<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, 1995
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 29, 1996, was approximately $28 million.
The number of Depositary Units outstanding as of February 29, 1996, was
7,543,100.
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<PAGE>
CERTAIN ABBREVIATIONS AND OTHER MATTERS
As used herein, the following terms have specific meanings:
<TABLE>
<C> <S>
m thousand
bbl barrel
mmb million barrels
mmcf million cubic feet
eb equivalent barrel
b/d barrels per day
WTI West Texas Intermediate spot
price
ED&A exploration, development and
acquisition
mm million
mb thousand barrels
mcf thousand cubic feet
bcf billion cubic feet
meb thousand equivalent barrels
mmeb million equivalent barrels
mmcf/d million cubic feet per day
HH Henry Hub spot price
FD&A finding, development and
acquisition
</TABLE>
Natural gas equivalents are determined under the relative energy content
method by using the ratio of 6 mcf of natural gas to 1 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 the whole numbers by Sun Energy Partners, L.P.'s
working interest.
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
GENERAL
Sun Energy Partners, L.P. (Sun Energy Partners) engages in the oil and gas
exploration and production business 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, 1995, 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 that 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 or 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, 1995, 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
economic impact.
RESERVES
As of December 31, 1995, the Partnership's proved reserves were an estimated
204 mmb of liquids and an estimated 1,285 bcf of natural gas which represents an
aggregate of 418 mmeb of reserves. More information on the estimated quantities
of proved oil and gas reserves and information on
<PAGE>
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 and Operating
Information." The Partnership files oil and gas reserve estimates with various
governmental regulatory authorities and agencies, the variability of which does
not exceed five percent.
The Partnership's production is exclusively in the United States and in
1995, the Partnership produced 47 mmeb. The Partnership seeks production
replacement through a balanced approach that combines exploration, development
and acquisition. In 1995, the Partnership replaced 99 percent of its production
at a finding, development and acquisition cost of $4.65 per eb.
OFFSHORE
The Partnership emphasizes projects that generate near term cash flow. The
Partnership has identified the Gulf of Mexico as the cornerstone of its growth
strategy.
The Partnership has significant presence in the Gulf of Mexico with an
interest in 115 blocks in various stages of exploration, development and
production. The Partnership has an interest in 36 producing platforms, 17 of
which it operates. The Partnership also holds interests in various offshore
pipelines and facilities.
EXPLORATION
As of December 31, 1995, the Partnership held 272 thousand net undeveloped
acres offshore, as compared to 341 thousand as of December 31, 1994. Of the 115
Gulf of Mexico blocks in which the Partnership owns an interest, 71 are
undeveloped. In 1995, the Partnership spent $5 million to acquire interests in 7
blocks.
As of December 31, 1995, one exploratory well was being drilled. The
Partnership drilled 6 gross (3 net) exploratory wells offshore in 1995 and 4
gross (3 net) in 1994. Of the wells drilled in 1995, 2 gross (1 net) wells were
successful.
PRODUCTION AND DEVELOPMENT
Average daily production of crude oil and condensate offshore was 16, 10 and
9 mbbls in 1995, 1994 and 1993. Average daily production of natural gas offshore
was 178, 201 and 191 mmcf in 1995, 1994 and 1993.
The Partnership owns a 99 percent interest in the High Island A-576 block.
In 1994, 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 discoveries at
High Island 379 and 385. This development, which has been named the Sherman
Project, began production in December 1995. Peak production was 7 meb per day.
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 360 feet. In 1993, the Partnership announced an oil discovery in High
Island 379 which encountered 179 feet of oil pay. 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. This new development, which
has been named the Patton Project, began production in January 1995 and in
September achieved the expected peak production of 20 meb per day.
Late in 1995, the Partnership confirmed the presence of natural gas reserves
in a previously untested area of the High Island 384 Unit. The High Island 385
#3 well encountered 158 feet of net gas pay. Two subsequent delineation wells
found the same pay interval in nearby fault blocks. In the second phase of
Patton, the Partnership will install a platform in 360 feet of water and develop
the new gas reservoir.
2
<PAGE>
In early 1995, the Partnership confirmed the presence of hydrocarbons in a
previously untested fault block on the Garden Banks 260 discovery in the Gulf of
Mexico. The Garden Banks (GB) 215 #2 well, which drilled a new fault block about
two miles north of the original discovery well on GB 260, encountered
approximately 170 feet of net pay. The GB 259 #2 well was then drilled as a
side-track, and encountered over 115 feet of new pay in the same reservoir
sands. A total of nine successful wells have been drilled in the GB 260 area.
The most recent well, GB 216 #2, encountered 150 feet of net pay. This
development, which has been named the Baldpate Project, is in federal waters
offshore Louisiana in water depths of approximately 1,700 feet. In 1995, the
Partnership entered into a plan of development to install a compliant tower
platform and processing facility. The Partnership owns a 50 percent interest in
a four-block area.
In 1995, the Partnership approved a plan 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 the Neptune Project. First production is
anticipated in 1997 with a gross peak rate of 24-30 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.
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 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, 1995, the Partnership was drilling 12 gross (7 net)
offshore development wells. The Partnership drilled 14 gross (11 net)
development wells offshore in 1995 and 16 gross (6 net) in 1994. All of the 14
gross (11 net) development wells drilled in 1995 were successful.
ONSHORE
The onshore area continues to be a major contributor of production volumes
and cash flow with relatively modest investment needs. The Partnership has
interests in 60 major onshore fields in five states and operates about 75
percent of its production. In addition, the Partnership has increased its
drilling activity to more rapidly exploit its onshore asset portfolio.
The Partnership is applying 3-D technology creating opportunities in new
fault blocks and deeper pool horizons which provide new volumes. To optimize
cash flow, the Partnership will continue to exploit its waterflood operations.
Onshore will be managed for maximum cash flow generation.
EXPLORATION
The Partnership drilled no exploratory wells onshore in 1995, and at
December 31, 1995, none were being drilled.
PRODUCTION AND DEVELOPMENT
Average daily production of crude oil and condensate onshore was 29, 37 and
47 mb in 1995, 1994 and 1993. The decrease in 1995 crude oil and condensate
production compared to 1994 and in 1994 compared to 1993 was due primarily to
asset sales and normal declines. Average daily net production of natural gas
onshore was 286, 332 and 326 mmcf in 1995, 1994 and 1993.
As of December 31, 1995, the Partnership was drilling or participating in
the drilling of 34 gross (29 net) development wells onshore. Of the 132 gross
(89 net) development wells drilled onshore during 1995, 121 gross (80 net) were
successful.
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, 1995 and 1994:
<TABLE>
<CAPTION>
GROSS NET
-------------------- --------------------
1995 1994 1995 1994
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
UNDEVELOPED ACREAGE
Onshore............................................................... 983 1,142 528 566
Offshore.............................................................. 380 511 272 341
--------- --------- --- ---
Total............................................................... 1,363 1,653 800 907
--------- --------- --- ---
--------- --------- --- ---
<CAPTION>
GROSS NET
-------------------- --------------------
1995 1994 1995 1994
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
DEVELOPED ACREAGE
Onshore............................................................... 982 1,137 545 625
Offshore.............................................................. 231 244 101 96
--------- --------- --- ---
Total............................................................... 1,213 1,381 646 721
--------- --------- --- ---
--------- --------- --- ---
</TABLE>
The following table sets forth the Partnership's net exploratory and
development oil and gas wells drilled in 1995, 1994 and 1993:
<TABLE>
<CAPTION>
EXPLORATORY WELLS DEVELOPMENT WELLS
------------------------------- -------------------------------
1995 1994 1993 1995 1994 1993
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Oil
Onshore..................................................... -- -- -- 41 11 29
Offshore.................................................... 1 -- 1 7 2 2
--- --- --- --- --- ---
1 -- 1 48 13 31
--- --- --- --- --- ---
Gas
Onshore..................................................... -- -- -- 39 23 15
Offshore.................................................... -- 1 1 4 3 3
--- --- --- --- --- ---
-- 1 1 43 26 18
--- --- --- --- --- ---
Dry
Onshore..................................................... -- -- 2 9 4 1
Offshore.................................................... 2 2 2 -- 1 3
--- --- --- --- --- ---
2 2 4 9 5 4
--- --- --- --- --- ---
Total..................................................... 3 3 6 100 44 53
--- --- --- --- --- ---
--- --- --- --- --- ---
</TABLE>
The following table sets forth the Partnership's gross and net producing oil
and gas wells at December 31, 1995:
<TABLE>
<CAPTION>
GROSS* NET*
-------------------- --------------------
OIL GAS OIL GAS
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
Onshore................................................................. 3,031 812 1,679 503
Offshore................................................................ 51 110 31 62
--------- --- --------- ---
Total............................................................... 3,082 922 1,710 565
--------- --- --------- ---
--------- --- --------- ---
</TABLE>
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*Gross producing wells include 136 multiple completion wells (more than one
formation producing into the same well bore).
4
<PAGE>
The following table sets forth the Partnership's average daily net
production for 1995, 1994 and 1993:
<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
Crude & Condensate (mb):
Onshore.......................................................................... 29 37 46
Offshore......................................................................... 16 10 9
--- --- ---
45 47 55
Processed Natural Gas (mb): 6 6 7
--- --- ---
51 53 62
--- --- ---
--- --- ---
Natural Gas (mmcf):
Onshore.......................................................................... 286 332 326
Offshore......................................................................... 178 201 191
--- --- ---
464 533 517
--- --- ---
--- --- ---
</TABLE>
The following table sets forth the Partnership's average revenues and
production costs per unit of oil and gas production for 1995, 1994 and 1993:
<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
Revenues:
Crude oil & condensate (per barrel).................................... $ 16.44 $ 14.69 $ 15.96
Natural gas (per mcf).................................................. $ 1.73 $ 1.87 $ 1.96
Average production cost per unit of oil and gas production (per
equivalent barrel)
Operating cost....................................................... $ 3.63 $ 3.95 $ 3.79
Production taxes..................................................... .67 .83 .93
--------- --------- ---------
Total production costs............................................. $ 4.30 $ 4.78 $ 4.72
--------- --------- ---------
--------- --------- ---------
</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 1995, the Partnership obtained 62, 37, and 1 percent of its crude
production from primary, secondary and tertiary recovery methods. This compares
to 55, 38 and 7 percent of its crude oil production in 1994. At December 31,
1995, the Partnership participated in no major tertiary oil recovery programs.
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.
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.
5
<PAGE>
CRUDE OIL AND CONDENSATE
During 1995, sales of crude oil and condensate to the Partnership's top
purchaser totaled approximately 5 percent of crude oil and condensate revenue.
No other customer purchased more than 3 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 1995, the ten largest
customers accounted for approximately 20 percent of such sales.
Currently, approximately 63 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 nine years in length.
NATURAL GAS
During 1995 the Partnership marketed its natural gas production. Sales of
natural gas into short-term markets averaged 46 percent of total sales. At
year-end over 50 percent of total sales were contracted to end-users of natural
gas on a term basis. Contract length of these term sales agreements ranges from
three months to ten years.
During the fourth quarter of 1995, the Company, Apache Corporation and
Parker & Parsley Petroleum Company formed Producers Energy Marketing, LLC
(ProEnergy). Upon commencement of full operations, which is expected to occur in
the second quarter of 1996, ProEnergy will purchase substantially all of the
Partnership's gas production at index prices.
During 1995, no individual customer accounted for more than five percent of
the Partnership's natural gas sales. The ten largest customers accounted for
approximately 15 percent of total gas sales during 1995.
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.
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.
6
<PAGE>
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 27 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 $8
million, $11 million and $15 million for the years 1995, 1994 and 1993,
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.
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.
7
<PAGE>
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>
1995 1994
------------------ ------------------
HIGH LOW HIGH LOW
------- ------- ------- -------
<S> <C> <C> <C> <C>
First Quarter........................... $ 4 1/2 $ 3 7/8 $ 7 3/8 $ 6
Second Quarter.......................... $ 4 3/4 $ 4 1/8 $ 6 1/8 $ 5 3/8
Third Quarter........................... $ 4 3/4 $ 4 1/8 $ 5 7/8 $ 4 1/8
Fourth Quarter.......................... $ 4 5/8 $ 3 5/8 $ 4 7/8 $ 3 3/4
</TABLE>
The Partnership had approximately 2,239 holders of record of depositary
units as of March 5, 1996.
During 1995 and 1994, the quarterly cash distributions per unit paid to
unitholders were as follows:
<TABLE>
<CAPTION>
1995 1994
--------- ---------
<S> <C> <C>
First Quarter............................................................................ $ .14 $ .08
Second Quarter........................................................................... $ .14 $ .07
Third Quarter............................................................................ $ .16 $ .07
Fourth Quarter........................................................................... $ .02 $ .05
</TABLE>
The first quarterly cash distribution for 1996 in the amount of $.02 per
unit was paid in March 1996. Cash distributions in 1995 and 1994 included $.27
and $.06 per unit related to proceeds from asset sales. 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.")
8
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------------------------------------
1995 1994 1993 1992 1991
--------- --------- --------- --------- ---------
(MILLIONS OF DOLLARS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C> <C> <C>
For the Period
Revenues.................................................... $ 552 $ 613 $ 676 $ 937 $ 1,079
Income before cumulative effect of accounting change (1).... $ 99 $ 100 $ 44 $ 120 $ 114
Net income (loss) (1)....................................... $ 99 $ (477) $ 44 $ 120 $ 114
Net income per unit before cumulative effect of accounting
change (1)................................................. $ .24 $ .24 $ .11 $ .29 $ .28
Net income (loss) per unit (1).............................. $ .24 $ (1.13) $ .11 $ .29 $ .28
Cash distributions paid to unitholders (2).................. $ 194 $ 114 $ 340 $ 360 $ 535
Cash distributions paid per unit (2)........................ $ .46 $ .27 $ .82 $ .87 $ 1.33
Weighted average units outstanding (in thousands)........... 421.2 421.2 414.7 412.5 404.4
Capital expenditures........................................ $ 206 $ 166 $ 199 $ 100 $ 306
At End of Period
Total assets................................................ $ 1,143 $ 1,181 $ 1,822 $ 2,038 $ 2,592
Long-term debt (3).......................................... $ 62 $ 74 $ 86 $ 100 $ 319
Partners' capital........................................... $ 839 $ 934 $ 1,525 $ 1,751 $ 1,991
</TABLE>
- ------------------------
(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 and 1991 include gains from
sales of assets of $115 million and $75 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 $62 million, $72 million, $82 million, $91 million and $312 million
of long-term debt due to the Company. The Partnership prepaid $213 million
and $575 million of such debt in 1992 and 1991.
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 which follows should be read in conjunction with the
Consolidated Financial Statements and Selected Financial Data included in this
report.
BUSINESS CLIMATE
The Partnership's realized oil price in 1995 increased by $1.75 per barrel,
or 12 percent more than the 1994 price. The increase in 1995 followed an 8
percent decline in the Partnership's realized oil price in 1994 compared to
1993. The fundamentals in oil markets continue to reflect an excess of supply
over demand. Concerns regarding the reentry of Iraq into crude markets depress
prices.
The Partnership's realized gas price in 1995 was $.14 per mcf or 7 percent
lower than the $1.87 per mcf realized in 1994. The U.S. experienced mild weather
in early 1995 which resulted in high seasonal natural gas storage levels and low
prices. Storage capacity was not refilled to previous year levels and extremely
cold winter weather caused record high prices in late 1995 and early 1996.
The Partnership produced 45 million equivalent barrels of crude oil and
natural gas in 1995, 38 percent crude oil and 62 percent natural gas.
9
<PAGE>
RESULTS OF OPERATIONS
The Partnership's net income in 1995 was $99 million, or $.24 per unit, as
compared to net income of $100 million, excluding the cumulative effect of an
accounting change, or $.24 per unit, in 1994 and net income of $44 million, or
$.11 per unit in 1993. (See Note 7 to the Consolidated Financial Statements.)
Oil and gas revenue was $565 million or 9 percent lower in 1995 compared to
1994 due primarily to the sale of producing assets. Operating costs decreased 17
percent and production taxes decreased 27 percent in 1995 compared to 1994, also
due primarily to the sale of producing assets.
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.
Average net production of oil in 1995 was 45 thousand barrels daily, or 4
percent lower than the average net production in 1994 of 47 thousand barrels
daily. The average price received for the Partnership's oil production in 1995
was $16.44 per barrel, representing a 12 percent increase from the 1994 average
price of $14.69.
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 gas in 1995 was 464 million cubic feet daily, or
13 percent lower than average net production for 1994 of 533 million cubic feet
daily. The Partnership received an average price of $1.73 per thousand cubic
feet for its gas production in 1995 compared to an average price of $1.87 per
thousand cubic feet in 1994, representing a 7 percent decrease.
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.
LIQUIDITY AND CAPITAL RESOURCES
In 1995, cash flow from operating activities increased $57 million compared
to 1994 primarily due to favorable increases in cash flow working capital
components. Cash flow from investing activities used $144 million in 1995
compared to a use of $136 million in 1994. Capital expenditures were $40 million
higher in 1995 and proceeds from divestments were $33 million higher in 1995.
Cash flow from financing activities used $205 million in 1995 compared to a use
of $128 million in 1994. Cash distributions paid to unitholders were $80 million
higher in 1995 than 1994.
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
10
<PAGE>
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 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 December 1995, the Partnership adopted SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of."
Adoption did not impact results of operations.
During the fourth quarter of 1995, the Company, Apache Corporation and
Parker & Parsley Petroleum Company formed Producers Energy Marketing, LLC
(ProEnergy). Upon commencement of full operations, which is expected to occur in
the second quarter of 1996, ProEnergy will purchase substantially all of the
Partnership's gas production at index prices.
In 1996, ED&A expenditures are expected to increase approximately 40 percent
to about $305 million.
The Partnership's investing 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 1995
was 79 percent of liquids production and 112 percent of gas production. Reserve
replacement rates of liquids and gas were 35 and 109 percent in 1994 and 74 and
93 percent in 1993.
HEDGING ARRANGEMENTS
The Partnership, from time to time, enters into hedging arrangements for oil
and natural gas prices. The Partnership has entered into hedges for
approximately 7 percent of its estimated 1996 crude oil production under
agreements with an average price floor of $18.31 per barrel. Approximately 41
percent of its estimated 1996 gas production is under swap agreements with an
average price of $1.83 per mmbtu. The Partnership's hedging activities increased
oil and gas revenue by $20 million in 1995 and increased oil and gas revenue by
$3 million in 1994. (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
11
<PAGE>
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, including cash
proceeds from asset sales and makes distributions of only that cash remaining
after such outlays. The policy reduced the cash paid to unitholders in 1994 and
1995 and will reduce the cash paid to unitholders in the future but also ended
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, 1995, 1994 and 1993................... 14
Consolidated Balance Sheets at December 31, 1995 and 1994................................................ 15
Consolidated Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and 1993............... 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, 1995 and 1994 and the
related consolidated statements of income and cash flows for each of the three
years in the period ended December 31, 1995. 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, 1995 and 1994, and the
consolidated results of their operations and their cash flows for each of the
three years in the period ended December 31, 1995 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 asset
ceiling test in 1994.
COOPERS & LYBRAND L.L.P.
Dallas, Texas
February 19, 1996
13
<PAGE>
SUN ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF INCOME
(MILLIONS OF DOLLARS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
Revenues
Oil and gas..................................................................... $ 565 $ 618 $ 693
Other -- net (Notes 3 and 5).................................................... (13) (5) (17)
--------- --------- ---------
552 613 676
--------- --------- ---------
Costs and Expenses
Operating costs................................................................. 162 195 195
Production taxes (Note 6)....................................................... 30 41 48
Exploration costs............................................................... 42 50 53
Depreciation, depletion and amortization........................................ 163 163 256
General and administrative expense (Note 3)..................................... 53 52 67
Interest and debt expense (Note 3).............................................. 13 17 13
Interest capitalized............................................................ (10) (5) --
--------- --------- ---------
453 513 632
--------- --------- ---------
Income Before Cumulative Effect of Accounting Change.............................. 99 100 44
Cumulative Effect of Accounting Change (Note 7)................................... -- (577) --
--------- --------- ---------
Net Income (Loss)................................................................. $ 99 $ (477) $ 44
--------- --------- ---------
--------- --------- ---------
Net Income (Loss) Per Unit:
Before cumulative effect of accounting change................................... $ .24 $ .24 $ .11
Cumulative effect of accounting change.......................................... -- (1.37) --
--------- --------- ---------
Net income (loss)............................................................... $ .24 $ (1.13) $ .11
--------- --------- ---------
--------- --------- ---------
Cash Distributions Paid to Unitholders............................................ $ 194 $ 114 $ 340
--------- --------- ---------
--------- --------- ---------
Cash Distributions Per Unit....................................................... $ .46 $ .27 $ .82
--------- --------- ---------
--------- --------- ---------
Weighted Average Units Outstanding (In Millions).................................. 421.2 421.2 414.7
--------- --------- ---------
--------- --------- ---------
</TABLE>
(See Accompanying Notes)
14
<PAGE>
SUN ENERGY PARTNERS, L.P.
CONSOLIDATED BALANCE SHEETS
(MILLIONS OF DOLLARS)
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31
--------------------
1995 1994
--------- ---------
<S> <C> <C>
Current Assets
Cash and short-term investments............................................................. $ 8 $ 11
Advances to affiliate (Note 3).............................................................. -- 9
Accounts receivable and other current assets................................................ 97 88
--------- ---------
Total Current Assets.......................................................................... 105 108
Properties, Plants and Equipment (Note 8)..................................................... 955 993
Investment in Affiliate (Note 1).............................................................. 83 80
--------- ---------
Total Assets.................................................................................. $ 1,143 $ 1,181
--------- ---------
--------- ---------
LIABILITIES AND PARTNERS' CAPITAL
Current Liabilities
Advances from affiliate (Note 3)............................................................ $ 45 $ --
Accounts payable............................................................................ 73 62
Accrued liabilities (Note 9)................................................................ 79 72
Current portion of long-term debt due affiliate (Note 10)................................... 11 10
Current portion of long-term debt (Note 10)................................................. 2 2
--------- ---------
Total Current Liabilities..................................................................... 210 146
Long-Term Debt Due Affiliate (Note 10)........................................................ 62 72
Long-Term Debt (Note 10)...................................................................... -- 2
Deferred Credits and Other Liabilities (Note 14).............................................. 32 27
Commitments and Contingent Liabilities (Note 11)..............................................
Partners' Capital (Notes 12 and 13)...........................................................
Limited partnership interests............................................................... 257 286
General partnership interests............................................................... 582 648
--------- ---------
Partners' Capital............................................................................. 839 934
--------- ---------
Total Liabilities and Partners' Capital....................................................... $ 1,143 $ 1,181
--------- ---------
--------- ---------
</TABLE>
- ------------------------
The successful efforts method of accounting is followed.
(See Accompanying Notes)
15
<PAGE>
SUN ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
Cash and Cash Equivalents From Operating Activities
Net Income (Loss)..................................................................... $ 99 $ (477) $ 44
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization.......................................... 163 163 256
Dry hole costs and leasehold impairment........................................... 21 27 24
Loss on sale of assets............................................................ 1 -- 7
Cumulative effect of accounting change............................................ -- 577 --
Other............................................................................. 6 6 10
--------- --------- ---------
290 296 341
Changes in working capital:
Accounts receivable and other current assets...................................... (15) 25 46
Accounts payable, accrued liabilities and advances from affiliates................ 62 (41) 22
--------- --------- ---------
Net Cash Flow Provided From Operating Activities...................................... 337 280 409
--------- --------- ---------
Cash and Cash Equivalents From Investing Activities
Capital expenditures................................................................ (206) (166) (199)
Proceeds from divestments........................................................... 75 42 59
Other............................................................................... (13) (12) (8)
--------- --------- ---------
Net Cash Flow Used For Investing Activities........................................... (144) (136) (148)
--------- --------- ---------
Cash and Cash Equivalents From Financing Activities
Proceeds from borrowings............................................................ -- -- 5
Repayments of long-term debt........................................................ (11) (14) (19)
Cash distributions paid to unitholders.............................................. (194) (114) (340)
Sale of limited partnership units................................................... -- -- 70
--------- --------- ---------
Net Cash Flow Used For Financing Activities........................................... (205) (128) (284)
--------- --------- ---------
Changes in Cash and Cash Equivalents.................................................. (12) 16 (23)
Cash and Cash Equivalents at Beginning of Year........................................ 20 4 27
--------- --------- ---------
Cash and Cash Equivalents at End of Year.............................................. $ 8 $ 20 $ 4
--------- --------- ---------
--------- --------- ---------
</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, 1995, 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 added. Exploration costs, including geological and geophysical
costs and costs of carrying unproved properties, are charged against income as
incurred. Exploratory drilling costs are capitalized initially; however, if it
is determined that an exploratory well did not find 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
17
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
proved properties are depleted by the unit-of-production method based on proved
reserves by field. Capitalized exploratory drilling costs which result in the
addition of proved reserves and development costs are amortized by the
unit-of-production method based on proved developed reserves by field.
CEILING TEST. Effective January 1, 1994, the Partnership changed its policy
for performing ceiling test comparisons to an individual field basis. Prior to
1994, the Partnership performed its ceiling test comparisons on a total
partnership basis. Prior to December 1995, the Partnership impaired the net book
value of its proved properties to the extent that they exceeded the estimated
undiscounted future cash flows calculated by using current realized prices and
costs held constant. In December 1995, the Partnership adopted the provisions of
Statement of Financial Standards (SFAS) No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Under SFAS
No. 121, whenever events or changes in circumstances indicate that the carrying
amount of a long-lived asset may not be recoverable, the Partnership reviews for
impairment by comparing estimated future cash flows expected to result from the
use of an asset and its eventual disposition to the carrying amount of the asset
(Note 7).
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, 1995, 1994 and 1993, the Partnership's financial reporting
bases of assets and liabilities exceeded the tax bases of its assets and
liabilities (net temporary differences) by $537 million, $544 million and $1,049
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.
18
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Interest paid totaled $13 million, $17 million and $13 million in 1995, 1994
and 1993.
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 1995 and 1994, no individual customer accounted for more than 10
percent of the Partnership's oil or natural gas revenue. During 1993, sales of
oil to the Partnership's top two purchasers totaled approximately 21 and 16
percent. During 1993, no individual customer accounted for more than 5 percent
of the Partnership's natural 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
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Certain items in years prior to 1995 have been reclassified to conform to
the 1995 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, 1995, the Partnership was a party to crude oil and natural
gas hedging contracts to hedge about 5 percent of its estimated 1996 crude oil
production at an average price of $18.27 per barrel. Approximately 40 percent of
its estimated 1996 natural gas production was hedged at $1.81 per mmbtu. At
December 31, 1994, the Partnership was a party to crude oil and natural gas
hedging contracts to hedge about 11 percent of its 1995 crude oil production at
$17.80 per barrel and 40 percent of its 1995 natural gas production at $1.95 per
mmbtu. These arrangements serve to reduce the volatility associated with prices
of crude oil and natural gas. The aggregate carrying values of
19
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2) FINANCIAL INSTRUMENTS (CONTINUED)
these assets at December 31, 1995 and 1994 were $5 million and nil, and the
aggregate fair values, subject to daily fluctuation, based on quotes from
brokers, were approximately $(20) million and $13 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.
OTHER FINANCIAL INSTRUMENTS
At December 31, 1995 and 1994, the carrying values of the Partnership's
long-term debt, including amounts due within one year, were $75 million and $86
million (Note 10). At December 31, 1995 and 1994, the aggregate fair values of
the Partnership's long-term debt were approximately $117 million and $93
million, estimated primarily based on current rates offered 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 1996-2001.
DIRECT AND INDIRECT COST
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 $68 million, $73 million and $104 million
for the years 1995, 1994 and 1993. 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 $2 million, $3 million and $5 million during the years 1995,
1994 and 1993.
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 and advances due the Company and totaled $12 million, $16 million
and $12 million during the years 1995, 1994 and 1993 (Note 10).
4) CHANGES IN BUSINESS
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>
1995 1994 1993
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Interest income............................................................. $ 2 $ 3 $ 5
Loss on sale of assets...................................................... (1) -- (7)
Miscellaneous............................................................... (14) (8) (15)
--- --- ---------
$ (13) $ (5) $ (17)
--- --- ---------
--- --- ---------
</TABLE>
6) PRODUCTION TAXES
Production taxes consisted of the following:
<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Severance...................................................................... $ 20 $ 26 $ 31
Property taxes................................................................. 10 15 17
--- --- ---
$ 30 $ 41 $ 48
--- --- ---
--- --- ---
</TABLE>
7) ACCOUNTING CHANGE
In December 1995, the Partnership adopted SFAS No. 121 resulting in no
material impact.
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. Prior to this change, the Partnership
compared its total undiscounted standardized measure of future net cash flows
from estimated production of proved oil and gas reserves to its net proved
property, plant and equipment. 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's reported net
earnings for 1993 would have been a net loss of $198 million ($.47 per unit) if
this accounting change had been enacted prior to 1993.
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>
1995 1994
---------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Gross Investment
Proved properties.......................................................... $ 3,615 $ 3,914
Unproved properties........................................................ 37 42
Other...................................................................... 58 59
---------- ----------
3,710 4,015
---------- ----------
Less Accumulated Depreciation, Depletion and Amortization
Proved properties*......................................................... 2,701 2,969**
Other...................................................................... 54 53
---------- ----------
2,755 3,022
---------- ----------
Net Investment............................................................... $ 955 $ 993
---------- ----------
---------- ----------
</TABLE>
- ------------------------
* Includes $29 million for dismantlement, restoration and abandonment at
December 31, 1995 and 1994.
** Includes $577 million of impairment of proved oil and gas properties in 1994
(Note 7).
9) ACCRUED LIABILITIES
At December 31, the Partnership's accrued liabilities were comprised of the
following:
<TABLE>
<CAPTION>
1995 1994
---- ----
(MILLIONS
OF DOLLARS)
<S> <C> <C>
Drilling and operating costs.................................................... $ 48 $ 37
Taxes payable................................................................... 11 19
Other........................................................................... 20 16
---- ----
$ 79 $ 72
---- ----
---- ----
</TABLE>
10) LONG-TERM DEBT
At December 31, the Partnership's long-term debt consisted of the following:
<TABLE>
<CAPTION>
1995 1994
---- ----
(MILLIONS
OF DOLLARS)
<S> <C> <C>
9.75% note payable to affiliate, due 1996-2001, payable in quarterly
installments................................................................... $ 73 $ 82
Capitalized lease obligation due 1996........................................... 2 4
---- ----
75 86
Less: Current portion of note payable to affiliate.............................. 11 10
Current portion of capitalized lease obligations and other long-term
debt...................................................................... 2 2
---- ----
$ 62 $ 74
---- ----
---- ----
</TABLE>
Repayment obligations under the Partnership's long-term debt due affiliate
are $11 million, $12 million, $13 million, $14 million and $16 million in 1996,
1997, 1998, 1999 and 2000.
22
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 1995, 1994 and
1993 was $38 million, $33 million and $28 million. Under contracts existing as
of December 31, 1995, 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:
1996............................................................... $ 24
1997............................................................... 5
1998............................................................... 3
1999............................................................... 3
2000............................................................... 1
Later years........................................................ --
---------
Total minimum payments required.................................. $ 36
---------
---------
</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
ORYX ENERGY COMPANY ENERGY
PUBLIC TOTAL COMPANY
---------------------- ---------------------- ---------------------- ---------
UNITS DOLLARS UNITS DOLLARS UNITS DOLLARS UNITS
--------- ----------- --------- ----------- --------- ----------- ---------
(DOLLARS IN MILLIONS, UNITS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
December 31, 1992...................... 7,543 $ 33 112,912 $ 477 120,455 $ 510 292,000
Sale of limited partnership units.... -- 1 8,716 48 8,716 49 --
Cash distributions................... -- (7) -- (94) -- (101) --
Net income........................... -- -- -- 10 -- 10 --
--------- ----- --------- ----------- --------- ----------- ---------
December 31, 1993...................... 7,543 27 121,628 441 129,171 468 292,000
Cash distributions................... -- (2) -- (33) -- (35) --
Net loss............................. -- (9) -- (138) -- (147) --
--------- ----- --------- ----------- --------- ----------- ---------
December 31, 1994...................... 7,543 16 121,628 270 129,171 286 292,000
Cash distributions................... -- (3) -- (56) -- (59) --
Net income........................... -- 1 -- 29 -- 30 --
--------- ----- --------- ----------- --------- ----------- ---------
December 31, 1995...................... 7,543 $ 14 121,628 $ 243 129,171 $ 257 292,000
--------- ----- --------- ----------- --------- ----------- ---------
--------- ----- --------- ----------- --------- ----------- ---------
<CAPTION>
TOTAL
----------------------
DOLLARS UNITS DOLLARS
----------- --------- -----------
<S> <C> <C> <C>
December 31, 1992...................... $ 1,241 412,455 $ 1,751
Sale of limited partnership units.... 21 8,716 70
Cash distributions................... (239) -- (340)
Net income........................... 34 -- 44
----------- --------- -----------
December 31, 1993...................... 1,057 421,171 1,525
Cash distributions................... (79) -- (114)
Net loss............................. (330) -- (477)
----------- --------- -----------
December 31, 1994...................... 648 421,171 934
Cash distributions................... (135) -- (194)
Net income........................... 69 -- 99
----------- --------- -----------
December 31, 1995...................... $ 582 421,171 $ 839
----------- --------- -----------
----------- --------- -----------
</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 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.
23
<PAGE>
SUN ENERGY PARTNERS, L.P.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
13) CASH DISTRIBUTIONS (CONTINUED)
Sun Energy Partners' quarterly cash distributions per unit for the years
1995, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
First Quarter................................................................ $ .14 $ .08 $ .25
Second Quarter............................................................... .14 .07 .16
Third Quarter................................................................ .16 .07 .23
Fourth Quarter............................................................... .02 .05 .18
</TABLE>
Cash distributions included $.27 and $.06 per unit related to proceeds from
asset sales in 1995 and 1994.
14) DEFERRED CREDITS AND OTHER LIABILITIES
At December 31, the Partnership's deferred credits and other liabilities
were comprised of the following:
<TABLE>
<CAPTION>
1995 1994
--------- ---------
(MILLIONS OF
DOLLARS)
<S> <C> <C>
Accrued environmental cleanup costs............................................... $ 20 $ 21
Other............................................................................. 12 6
--------- ---------
$ 32 $ 27
--------- ---------
--------- ---------
</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 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
PRPs 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 $13 million. 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
--------------------
1995 1994
--------- ---------
(MILLIONS OF
DOLLARS)
<S> <C> <C>
Proved properties............................................................... $ 3,615 $ 3,914
Unproved properties............................................................. 37 42
--------- ---------
Total capitalized costs......................................................... 3,652 3,956
Less accumulated depreciation, depletion and amortization....................... 2,701 2,969
--------- ---------
Net capitalized costs........................................................... $ 951 $ 987
--------- ---------
--------- ---------
</TABLE>
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Property acquisition costs:
Proved....................................................................... $ 6 $ -- $ 9
Unproved..................................................................... 6 4 8
Exploration costs.............................................................. 39 38 58
Development costs.............................................................. 165 142 145
--------- --------- ---------
$ 216 $ 184 $ 220
--------- --------- ---------
--------- --------- ---------
</TABLE>
EXPLORATION COSTS
<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Dry hole costs................................................................. $ 12 $ 9 $ 21
Leasehold impairment........................................................... 9 18 3
Geological and geophysical..................................................... 20 21 27
Other.......................................................................... 1 2 2
--------- --------- ---------
$ 42 $ 50 $ 53
--------- --------- ---------
--------- --------- ---------
</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.
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,
1995. 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.
25
<PAGE>
<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, 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
Revisions of previous estimates................................... (6) 3 60
Improved recovery................................................. 5 -- 1
Purchases of minerals in place.................................... 1 -- 4
Sales of minerals in place........................................ (10) (4) (55)
Extensions and discoveries........................................ 12 -- 124
Production........................................................ (17) (2) (169)
--- --- -----
BALANCE AT DECEMBER 31, 1995...................................... 186 18 1,285
--- --- -----
--- --- -----
Proved Developed Reserves At:
December 31, 1992............................................... 173 20 1,058
December 31, 1993............................................... 154 16 1,000
December 31, 1994............................................... 128 16 898
December 31, 1995............................................... 115 13 872
</TABLE>
- ------------------------
*Natural gas volumes include liquefiable hydrocarbons approximating 5 percent
of total gas reserves which are recoverable downstream. Such recoverable
liquids also have been included in natural gas liquids reserve volumes.
26
<PAGE>
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 and production costs and a 10 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 Note 1 to the Consolidated Financial Statements.) The year-end
realized prices were $17.90 and $15.30 per barrel of oil and $2.28 and $1.75 per
mcf of gas for 1995 and 1994.
<TABLE>
<CAPTION>
1995 1994
---------- ----------
(MILLIONS OF DOLLARS)
<S> <C> <C>
Future cash inflows............................................................... $ 6,492 $ 5,672
Future production and development costs........................................... (2,592) (2,921)
---------- ----------
Future net cash flows............................................................. 3,900 2,751
Discount at 10 percent............................................................ (1,559) (1,062)
---------- ----------
Standardized measure.............................................................. $ 2,341 $ 1,689
---------- ----------
---------- ----------
</TABLE>
SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE
<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C>
Balance, beginning of year............................................... $ 1,689 $ 1,136 $ 1,992
Increase (decrease) in discounted future net cash flows:
Sales of oil and gas production net of related costs................... (375) (382) (440)
Revisions to estimates of proved reserves:
Prices............................................................... 578 370 (767)
Development costs.................................................... (4) 304 (30)
Production costs..................................................... 17 (116) (10)
Quantities........................................................... 62 10 (9)
Other................................................................ (228) (69) (11)
Extensions, discoveries and improved recovery, less related costs...... 339 216 96
Development costs incurred during the period........................... 165 147 168
Purchases of reserves in place......................................... 12 2 6
Sales of reserves in place............................................. (75) (43) (58)
Accretion of discount.................................................. 161 114 199
--------- --------- ---------
Balance, end of year..................................................... $ 2,341 $ 1,689 $ 1,136
--------- --------- ---------
--------- --------- ---------
</TABLE>
27
<PAGE>
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:
1995........................ $ 144 $ 153 $ 119 $ 136
-------- ------ ----- -----
-------- ------ ----- -----
1994
As reported............... $ 159 $ 154 $ 148
Restatement of other
revenues for accounting
change................... 2 1 2
-------- ------ -----
As restated............... $ 161 $ 155 $ 150 $ 147
-------- ------ ----- -----
-------- ------ ----- -----
Gross profit:*
1995........................ $ 42 $ 52 $ 32 $ 45
-------- ------ ----- -----
-------- ------ ----- -----
1994........................ $ 45 $ 41 $ 39 $ 47
-------- ------ ----- -----
-------- ------ ----- -----
Net income (loss):
1995........................ $ 23 $ 42 $ 7 $ 27
-------- ------ ----- -----
-------- ------ ----- -----
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
-------- ------ ----- -----
-------- ------ ----- -----
Net income (loss) per unit:
1995........................ $ .05 $ .10 $ .02 $ .07
-------- ------ ----- -----
-------- ------ ----- -----
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
-------- ------ ----- -----
-------- ------ ----- -----
</TABLE>
- ------------------------
*Gross profit equals oil and gas revenues plus gas plant margins less production
cost, exploration cost and depreciation, depletion and amortization.
28
<PAGE>
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):
1995............................................. 49 47 44 43 45
1994............................................. 50 48 47 44 47
Average price (per barrel):
1995............................................. $ 16.26 $ 17.10 $ 16.20 $ 16.15 $ 16.44
1994............................................. $ 12.72 $ 15.28 $ 15.34 $ 15.56 $ 14.69
Natural gas:
Net production (million cubic feet daily):
1995............................................. 504 480 439 437 464
1994............................................. 548 515 536 533 533
Average price (per thousand cubic feet):
1995............................................. $ 1.69 $ 1.70 $ 1.61 $ 1.92 $ 1.73
1994............................................. $ 2.12 $ 1.92 $ 1.71 $ 1.72 $ 1.87
</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 nine current
directors of the Company and the eight 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 1998) 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, 57 ......................... Mr. Box has been in this position since
Executive Vice President, Chief Operating December 7, 1995. From December 1994 through
Officer and Director November 1995 he served as Executive Vice
President, Exploration and Production. From
January 1992 through November 1994, he was
Senior Vice President, Exploration and
Production of the Company. From 1987 to 1991,
he was Vice President, Exploration.
William E. Bradford, 61 .................. Mr. Bradford has been President and Chief
Director Executive Officer of Dresser Industries Inc.
since November 1995 and a director of Dresser
Industries, Inc. since March 1992. He was
President and Chief Operating Officer of
Dresser Industries, Inc. from March 1992 to
November 1995. 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, 43 ................... Mr. Chavenson assumed this position in October
Treasurer 1993. For the five years previous thereto, he
was Assistant Treasurer and Manager, Corporate
Finance and Credit of the Company.
Sherri T. Durst, 46 ...................... Ms. Durst assumed this position in December
General Auditor 1993. From 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, 64 ....................... Mr. Gill served as Vice Chairman of the Board
Director of J.C. 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 served as Chairman of the Board
of the J.C. Penney National Bank and the J.C.
Penney Insurance Company. He was a director of
the National Junior Achievement, the 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 and a member
of the Business Advisory Committee of Lehigh
University.
Frances G. Heartwell, 49 ................. Ms. Heartwell assumed this position on December
Vice President, Human Resources 7, 1995. From February 1993 to December 1995,
and Administration she served the Company as Director, Human Re-
sources. From December 1991 to February 1993,
she was Director of Employee and Community Re-
lations. Prior to December 1991, she served as
Director of Administration.
David S. Hollingsworth, 67 ............... Mr. Hollingsworth served as Chairman of the
Director Board and Chief 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. 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. Mr.
Hollingsworth is a member of the board of
directors of the Delaware Trust Company.
Robert L. Keiser, 53 ..................... Mr. Keiser assumed this position in December
Chairman of the Board, Chief Executive 1994. From January 1992 through November 1994,
Officer, and President he was President and 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.
</TABLE>
31
<PAGE>
<TABLE>
<CAPTION>
NAME, AGE AND BUSINESS EXPERIENCE DURING
POSITION WITH THE COMPANY PAST FIVE YEARS
- ------------------------------------------ -----------------------------------------------
<S> <C>
William C. Lemmer, 51 .................... Mr. Lemmer assumed this position on February 2,
Vice President, General Counsel and 1995. From June 1994 until February 1995, he
Secretary served as Vice President and General Counsel
to the Company. For the five previous years,
he was Chief Counsel to the Company.
Edward W. Moneypenny, 54 ................. Mr. Moneypenny has been in this position since
Executive Vice President, Finance, Chief December 1994. From January 1992 through Novem-
Financial Officer, and Director ber 1994, he was Senior Vice President,
Finance and Chief Financial Officer of the
Company. From 1988 through 1991, he was Vice
President, Finance and Chief Financial Officer
of the Company.
Charles H. Pistor, Jr., 65 ............... Mr. Pistor was the Vice Chair of Southern
Director Methodist University from October 1991 to
September 1995. 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 member of the Executive
Board of the Cox School of Business at
Southern Methodist University.
Paul R. Seegers, 66 ...................... Mr. Seegers is President of Seegers
Director Enterprises. He was 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 Of-
ficer. He is a member of the board of
directors of Centex Corporation and is
Chairman of its Executive Committee. Mr.
Seegers is a member of the board of directors
of RAC Financial Group, Inc. He is also a
member of the Board of Methodist Hospitals of
Dallas and a trustee of Southwestern Medical
Foundation.
Robert L. Thompson, 49 ................... Mr. Thompson assumed this position on February
Comptroller and Corporate Planning 2, 1995. From February 1993 through January
Director 1995, he served the 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, 59 ................. Mr. White-Thomson has been President and Chief
Director Executive Officer of U.S. Borax Inc. since
1988 and since April 1, 1995, 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. During 1985 and 1986,
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 3 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 1995, the
Company received $68 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 in 1995 for the salaries of the Chief
Executive Officer of the Company, each of the four most highly compensated
executive officers of the Company other than the Chief Executive Officer and to
one other who served as an executive officer was approximately $1.7 million.
(See Note 3 to the Consolidated Financial Statements.)
33
<PAGE>
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, 1995.
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 (13)............................................ --
</TABLE>
- ------------------------
* Assumes that Oryx Energy Company's 292,000,000 general partnership units are
converted into limited partnership units of Sun Energy Partners, L.P.
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, 1995:
<TABLE>
<CAPTION>
BALANCE DUE BALANCE DUE
TO (FROM) TO (FROM)
PARTNERSHIP PARTNERSHIP
DECEMBER 31, 1994 ADDITIONS REPAYMENTS DECEMBER 31, 1995
------------------- ------------- ------------- -------------------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C>
Variable Rate Advances to (from) Oryx Energy
Company........................................... $ 9 $ 46 $ 100 $ (45)
--- --- ----- ---
--- --- ----- ---
9.75% Note Payable to Oryx Energy Company.......... $ (82) $ -- $ 9 $ (73)
--- --- ----- ---
--- --- ----- ---
</TABLE>
During 1995, the largest balance owed to the Partnership by the Company for
variable rate advances was $55 million. The largest balance owed to the Company
by the Partnership during 1995 resulting from advances from Oryx Energy Company
and amounts due under the 9.75% Note Payable was $58 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> <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, dated February 19, 1995 (incorporated by
reference to Exhibit 16 of the Partnership Annual Report on Form 10-K for the
fiscal year ended December 31, 1994, Commission File No. 1-9033, filed with the
Commission on March 24, 1995)
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.
27 -- Financial Data Schedule
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, 1995.
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 27, 1996
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,
- ----------------------------------- Chief Operating Officer,
Jerry W. Box 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,
- ----------------------------------- President, and Chief
Robert L. Keiser Executive Officer
(principal
executive officer) March 27, 1996
/s/ EDWARD W. MONEYPENNY Executive Vice President,
- ----------------------------------- Finance, Chief Financial
Edward W. Moneypenny 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>
PRINCIPAL OFFICERS AND DIRECTORS OF
ORYX ENERGY COMPANY
MANAGING GENERAL PARTNER
Jerry W. Box
Executive Vice President, Chief Operating Officer and Director
William E. Bradford
Director
David F. Chavenson
Treasurer
Sherri T. Durst
General Auditor
Robert B. Gill
Director
Frances G. Heartwell
Vice President, Human Resources and Administration
David S. Hollingsworth
Director
Robert L. Keiser
Chairman of the Board, Chief Executive Officer, and President
William C. Lemmer
Vice President, General Counsel and Secretary
Edward W. Moneypenny
Executive Vice President, Finance, Chief Financial Officer and Director
Charles H. Pistor, Jr.
Director
Paul R. Seegers
Director
Robert L. Thompson
Comptroller and Corporate Planning Director
Ian L. White-Thomson
Director
EXECUTIVE OFFICES
13155 Noel Road
Dallas, TX 75240-5067
Telephone (214) 715-4000
DEPOSITORY UNITS
The depositary units are traded on the New York Stock Exchange, Inc. under the
symbol SLP.
MARKET PRICE RANGES:
<TABLE>
<CAPTION>
1995 1994
---------------------- ----------------------
HIGH LOW HIGH LOW
<S> <C> <C> <C> <C>
1st Quarter............. $ 41/2 $ 37/8 $ 73/8 $ 6
2nd Quarter............. $ 43/4 $ 41/8 $ 61/8 $ 53/8
3rd Quarter............. $ 43/4 $ 41/8 $ 57/8 $ 41/8
4th Quarter............. $ 45/8 $ 35/8 $ 47/8 $ 33/4
</TABLE>
CASH DISTRIBUTIONS PAID PER UNIT:
<TABLE>
<CAPTION>
1995 1994
--------- ---------
<S> <C> <C>
1st Quarter............................ $ .14 $ .08
2nd Quarter............................ $ .14 $ .07
3rd Quarter............................ $ .16 $ .07
4th Quarter............................ $ .02 $ .05
</TABLE>
TRANSFER AGENT, DEPOSITARY AND REGISTRAR
Chemical Mellon Shareholder Services, LLC
Shareholder Relations Department
P.O. Box 3068
New York, NY 10116-3068
1-800-648-8393
FOR UNITHOLDER ASSISTANCE, PLEASE CONTACT:
Unitholder Relations
Sun Energy Partners, L.P
c/o Oryx Energy Company
Managing General Partner
P.O. Box 2880
Dallas, TX 75221-2880
1-800-846-ORYX
<PAGE>
SUN ENERGY PARTNERS, L.P.
C/O ORYX ENERGY COMPANY
MANAGING GENERAL PARTNER
P.O. BOX 2880
DALLAS, TEXAS 75221
<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 true and lawful
attorney-in-fact and agent, with full power of substitution and resubstitution,
for him and in his 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, 1995 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 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
- ----------------------------------- ------------------------- ----------------
ROBERT L. KEISER* Chairman of the Board,
- ----------------------------------- Chief Executive Officer,
Robert L. Keiser President, and Director
(principal executive
officer)
JERRY W. BOX* Executive Vice President,
- ----------------------------------- Chief Operating Officer,
Jerry W. Box and Director
/s/ EDWARD W. MONEYPENNY Executive Vice President,
- ----------------------------------- Finance, Chief Financial
Edward W. Moneypenny Officer, and Director
(principal financial
officer)
ROBERT L. THOMPSON* Comptroller and Corporate
- ----------------------------------- Planning Director
Robert L. Thompson (principal accounting
officer)
WILLIAM E. BRADFORD* Director
- -----------------------------------
William E. Bradford
March 7, 1996
ROBERT B. GILL* Director
- -----------------------------------
Robert B. Gill
DAVID S. HOLLINGSWORTH* Director
- -----------------------------------
David S. Hollingsworth
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.
<PAGE>
EXHIBIT 24(B)
CERTIFICATE
I, Linda L. O'Keefe, hereby certify that I am Assistant Secretary of ORYX
ENERGY COMPANY, a Delaware corporation and that the following is a true and
correct copy of a resolution adopted by the Board of Directors of Oryx Energy
Company on the 7th day of March, 1996:
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, 1995, 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 13th day of March, 1996.
By: /s/ LINDA L. O'KEEFE
-----------------------------------
Linda L. O'Keefe
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENTS INCLUDED IN THE 1995 SUN ENERGY PARTNERS, L.P.
ANNUAL REPORT AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<CASH> 8
<SECURITIES> 0
<RECEIVABLES> 77
<ALLOWANCES> 0
<INVENTORY> 7
<CURRENT-ASSETS> 105
<PP&E> 3,710
<DEPRECIATION> 2,755
<TOTAL-ASSETS> 1,143
<CURRENT-LIABILITIES> 210
<BONDS> 62
0
0
<COMMON> 0
<OTHER-SE> 839
<TOTAL-LIABILITY-AND-EQUITY> 1,143
<SALES> 565
<TOTAL-REVENUES> 552
<CGS> 355
<TOTAL-COSTS> 355
<OTHER-EXPENSES> 95
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 3
<INCOME-PRETAX> 99
<INCOME-TAX> 0
<INCOME-CONTINUING> 99
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 99
<EPS-PRIMARY> .24
<EPS-DILUTED> .24
</TABLE>
