SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996
Commission File Number: 1-10695
Parker & Parsley Petroleum Company
(Exact name of registrant as specified in its charter)
Delaware 74-2570602
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
303 West Wall, Suite 101, Midland, Texas 79701
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(915) 683-4768
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Common Stock.................................... New York Stock Exchange
Rights to Acquire Shares of
Common Stock.................................. New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES X NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Aggregate market value of the voting stock held by
non-affiliates of the Registrant as of February 3, 1997..... $1,174,357,828
Number of shares of Common Stock outstanding as of
February 3, 1997............................................ 35,085,247
Documents Incorporated by Reference:
(1) Proxy Statement for Annual Meeting of Shareholders to be held May 20, 1997
- Referenced in Part III of this report.
Page 1 of 76 pages.
- Exhibit index on page 67-
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Parts I and II of this Report contain forward looking statements that
involve risks and uncertainties. Accordingly, no assurances can be given that
the actual events and results will not be materially different than the
anticipated results described in the forward looking statements. See "Item 1.
Business - Competition, Markets and Regulation" and "Item 1. Business - Risks
Associated with Business Activities" for a description of various factors that
could materially affect the ability of the Company to achieve the anticipated
results described in the forward looking statements.
PART I
Unless otherwise specified, all dollar amounts are expressed in United
States dollars. Certain oil and gas terms used in this Report are defined under
"Item 1. Business - Definition of Certain Oil and Gas Terms".
ITEM 1. BUSINESS
General
Parker & Parsley Petroleum Company (the "Company") is one of the largest
public independent oil and gas exploration and production companies in the
United States. The Company's domestic oil and gas properties are located
principally in the Permian Basin of West Texas, the onshore Gulf Coast region of
South Texas and Louisiana and the Mid-Continent region. The Company also owns
interests in oil and gas properties in Argentina.
The Company's executive offices and operating headquarters are located at
303 West Wall, Suite 101, Midland, Texas 79701, and its telephone number at
those offices is (915) 683-4768. The Company maintains division offices in
Midland and Corpus Christi, Texas, Oklahoma City, Oklahoma and Buenos Aires,
Argentina. At December 31, 1996, the Company had 659 employees, 241 of which
were employed in field and plant operations.
The Company was formed in May 1990 as a Delaware corporation and began
operations on February 19, 1991. The Company's business activities are conducted
through wholly-owned subsidiaries. Prior to 1991, the Company conducted its
business activities through two partnerships that were under common control.
Unless otherwise noted, references herein to the activities and properties of
the Company are references to the collective activities and properties of the
Company's subsidiaries and predecessors.
Mission and Strategies
The Company's mission is to provide its shareholders with superior
long-term profitability and value. The strategies to be employed to achieve this
mission will include: (a) developing and increasing production from existing
properties through low-risk development drilling and other activities, (b)
concentrating on defined geographic areas to achieve operating and technical
efficiencies, (c) pursuing strategic acquisitions in the Company's core areas
that will complement the Company's existing asset base and that will provide
additional growth opportunities, (d) utilizing or acquiring technological and
operating efficiencies to selectively expand into new geographic areas that
feature producing properties and provide exploration/exploitation opportunities,
(e) allocating the personnel and technology necessary to increase the Company's
exploration opportunities, (f) maintaining financial flexibility to take
advantage of additional exploration, development and acquisition opportunities
and (g) encouraging high levels of equity ownership among senior managers and
the Company's Board of Directors to further align the interests of management
and shareholders. The Company is committed to continuing to enhance shareholder
value through adherence to these strategies.
Business Activities
Production
Since it began operations, the Company has focused its efforts toward
increasing its average daily production of oil and gas through development
drilling and production enhancement activities and acquisitions of producing
properties. Average daily oil and gas production have each increased every year
since the Company's inception with the exception of 1996 when average daily
production declined due to significant property dispositions. In spite of
production decreases due to property sales, the Company's efforts towards
production growth have been largely successful as illustrated by the five-year
average daily production growth rates. Comparing 1992 to 1996, average daily oil
production has increased 138% and average daily gas production has increased
208%, while production costs per BOE have declined 21%. Production, price and
cost information with respect to the Company's properties for
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each of 1996, 1995 and 1994 is set forth under "Item 2. Properties - Selected
Oil and Gas Information - Production, Price and Cost Data".
Drilling Activities
The Company seeks to increase its oil and gas reserves, production and
cash flow by concentrating on drilling low-risk development wells and by
conducting additional development activities such as recompletions. From the
beginning of 1992 through the end of 1996, the Company drilled 2,006 gross
(1,327 net) wells, 96% of which were successfully completed as productive wells,
at a total cost (net to the Company's interest) of $658 million. During 1996,
the Company drilled 599 gross wells for a total cost (net to the Company's
interest) of approximately $212 million, 82% of which was spent on development
wells and related facilities. The Company's current 1997 capital expenditure
budget is $270 million which the Company has allocated as follows: $170 million
to exploitation activities, $67 million to exploration activities and $33
million to oil and gas property acquisitions. This capital expenditure budget
reflects the Company's plans to drill approximately 500 development wells and
100 exploratory wells and to perform recompletions on over 150 wells.
The Company believes that its current property base, which has been
significantly enhanced and expanded by the development of properties acquired in
prior years, provides a substantial inventory of prospects for continued
reserve, production and cash flow growth. The Company currently has a portfolio
of over 800 domestic drilling locations to which proved reserves have been
assigned. The Company's domestic reserves as of December 31, 1996 include proved
undeveloped and proved developed nonproducing reserves of 43 million Bbls of oil
and 239.6 Bcf of gas. Development of these reserves is anticipated to occur
principally in 1997 and 1998. The Company believes that its current portfolio of
undeveloped prospects provides attractive development and exploration
opportunities for at least the next three to five years.
Exploratory Activities
Prior to the acquisition of Bridge Oil Limited in July 1994, the Company
spent a small percentage of its annual capital budget on exploratory projects.
However, the acquisition of Bridge Oil Limited provided the Company with a
significant inventory of exploratory projects in the United States, Australia
and Argentina. As a result, since 1994, the Company has spent an increasing
percentage of its annual capital budget to exploratory projects, 2.8% in 1994,
13.3% in 1995 and 16.7% in 1996. The Company has determined that it will
continue to allocate resources to increasing its exploration opportunities with
a focus on generating a portfolio of short to medium term impact projects. The
Company currently anticipates that approximately 25% of its 1997 capital budget
will be spent on exploratory projects. The majority of the 1997 exploratory
budget is allocated to domestic activities within the onshore Gulf Coast and
Permian Basin areas. The Company's international exploration efforts will
primarily be devoted to Central and South America. Exploratory drilling involves
greater risks of dry holes or failure to find commercial quantities of
hydrocarbons than development drilling or enhanced recovery activities. See
"Item 1. Business - Risks Associated with Business Activities - Risks of
Drilling Activities" below.
The Company is currently involved in 47 3-D seismic projects, covering
approximately 900 square miles. These projects are located in the following
areas: 22 in the Gulf Coast region, 13 in the Permian Basin, seven in other
domestic locations and five in international locations. Over the past four
years, the Company participated in the drilling of 75 wells as a result of 3-D
seismic interpretation, 62 of which were successfully completed as productive
wells. Most of the Company's 3-D seismic projects are related to exploration
activity.
Asset Divestitures
General. The Company regularly reviews its property base for the purpose
of identifying nonstrategic assets, the disposition of which would create
organizational and operational efficiencies. While the Company generally does
not dispose of assets solely for the purpose of reducing debt, such dispositions
can have the result of furthering the Company's objective of financial
flexibility through decreased debt levels.
Disposition of Australasian Assets. On March 28, 1996, the Company
completed the sale of certain wholly-owned Australian subsidiaries to Santos
Ltd., and on June 20, 1996, the Company completed the sale of another
wholly-owned subsidiary, Bridge Oil Timor Sea, Inc., to Phillips Petroleum
International Investment Company. The Company received aggregate consideration
of $237.5 million for these combined sales which consisted of $186.6 million of
proceeds for the equity of such entities, $21.8 million for reimbursement of
certain intercompany cash advances, and the assumption of such subsidiaries' net
liabilities, exclusive of oil and gas properties, of $29.1 million. The
proceeds,
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after payment of certain costs and expenses, were utilized to reduce the
Company's outstanding bank indebtedness and for general working capital
purposes. The Company recognized an after-tax gain of $67.3 million from the
disposition of these subsidiaries. For additional information, see Note Q of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data".
Domestic Asset Dispositions. During 1996, the Company also realized
proceeds of approximately $58.4 million from the divestiture of nonstrategic
domestic assets comprised of $55.2 million from the disposition of oil and gas
properties and $3.2 million from the disposition of gas processing facilities
and other nonstrategic assets. Similarly, during 1995, the Company realized
proceeds of approximately $175.1 million from the divestiture of nonstrategic
assets comprised of $152.4 million from the disposition of oil and gas
properties and $22.7 million from the disposition of gas processing facilities
and other nonstrategic assets. The proceeds from the asset dispositions were
used to reduce the Company's outstanding bank indebtedness and to provide
funding for a portion of the Company's capital expenditures, including purchases
of oil and gas properties in the Company's core areas. Although the Company has
no formal divestiture plan for 1997, it will continue to perform ongoing reviews
of its asset base in order to identify nonstrategic assets for disposition.
Acquisition Activities
General. The Company regularly seeks to acquire properties that complement
its operations and provide exploitation and development opportunities and
cost-reduction potential. In addition, the Company pursues strategic
acquisitions that will allow the Company to expand into new geographical areas
that feature producing properties and provide exploration/exploitation
opportunities. During 1994, the Company completed two major acquisitions: the
acquisition of Bridge Oil Limited for total cash consideration of $290.6 million
and the acquisition of certain oil and gas properties from PG&E Resources for
$115.7 million. These acquisitions added significantly to the Company's
development drilling opportunities, balanced the Company's reserve mix between
oil and natural gas, increased the scale of its operations in the Permian Basin
and the onshore Gulf Coast areas and provided the Company with a significant
base of operations and experienced personnel for its areas of geographic focus,
including international areas. During 1995 and 1996, the Company reduced its
previous emphasis on major acquisitions and, instead, concentrated its efforts
on maximizing the value from its existing properties. However, the Company
continued its program of smaller acquisitions of properties that exhibit one or
more of the following characteristics: properties that are near or otherwise
complement the Company's existing properties, properties that represent
additional working interests in Company-operated properties or properties that
provide the Company with strategic exploitation or exploration opportunities. In
1995 and 1996, aggregate expenditures to acquire such interests and properties
amounted to approximately $48.5 million and $21 million, respectively.
Future Acquisition Opportunities. The Company regularly pursues and
evaluates acquisition opportunities (including opportunities to acquire
particular oil and gas properties or related assets or entities owning oil and
gas properties or related assets and opportunities to engage in mergers,
consolidations or other business combinations with such entities) and at any
given time may be in various stages of evaluating such opportunities. Such
stages may take the form of internal financial analysis, oil and gas reserve
analysis, due diligence, the submission of an indication of interest,
preliminary negotiations, negotiation of a letter of intent or negotiation of a
definitive agreement.
Financial Management
The Company strives to maintain its outstanding indebtedness at a moderate
level in order to provide sufficient financial flexibility for future
exploration, development and acquisition opportunities. While the Company may
occasionally incur higher levels of debt to take advantage of opportunities,
management's objective is to maintain a flexible capital structure and to
strengthen the Company's financial position by reducing debt through an increase
in equity capital or through the divestiture of nonstrategic assets. In order to
achieve this objective, the Company attempts to maintain a debt to total
capitalization ratio of 40% to 45%.
As with any organization, the Company has experienced various debt levels
in recent years as it has responded to strategic opportunities. In 1994, the
Company's debt level increased as a result of borrowing the funds necessary to
complete the acquisition of Bridge Oil Limited and the acquisition of oil and
gas properties from PG&E Resources (see "Acquisition Activities" above).
Beginning in 1995 and continuing through 1996, the Company took deliberate
actions to reduce its debt levels or extend its debt maturities in order to
improve its financial flexibility and enable it to take advantage of future
strategic opportunities.
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During 1996, the Company reduced its debt level significantly through the
application of proceeds from dispositions of assets which the Company had
identified as nonstrategic. In 1996, the Company received total cash proceeds of
$241.6 million related to the disposition of the Company's Australasian assets
and the disposition of certain other domestic nonstrategic assets (see "Asset
Divestitures" above). Application of these proceeds to the Company's outstanding
bank indebtedness reduced such indebtedness to $9 million at December 31, 1996,
and, correspondingly, reduced the Company's interest expense significantly, from
$65.4 million in 1995 to $46.2 million in 1996. As a result, the Company's debt
as a percentage of total capitalization was 31% at December 31, 1996, down from
49% at December 31, 1995.
During 1995, the Company utilized a portion of the $175.1 million of
proceeds from the disposition of nonstrategic assets to reduce its outstanding
bank indebtedness. In addition, during 1995, the Company refinanced a portion of
the outstanding principle of its bank indebtedness with the proceeds, totaling
approximately $295.9 million, of two public issuances of senior notes. The
senior note issuances had the result of extending the average maturity of the
Company's outstanding indebtedness. See Note E of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data".
Marketing of Production
General. Production from the Company's properties is marketed consistent
with industry practices, which include the sale of oil at the wellhead to third
parties and the sale of gas to third parties. Sales prices for both oil and gas
production are negotiated based on factors normally considered in the industry
such as the spot price for gas or the posted price for oil, price regulations,
distance from the well to the pipeline, well pressure, estimated reserves,
quality of gas and prevailing supply conditions.
Gas Marketing. Effective January 1, 1996, the Company, along with Apache
Corporation and Oryx Energy Company, formed Producers Energy Marketing, LLC
("ProEnergy"), a natural gas marketing company organized to create a direct link
between gas producers and purchasers. The venture is structured to flow through
the benefits arising out of the expanded services and the economies of scale
from the aggregation of substantial volumes of gas. For a period of five years,
the Company is obligated to sell to ProEnergy all gas production (subject to
certain exclusions relative to immaterial volumes) that is owned or controlled
by the Company, or any affiliate, in North America (onshore and offshore), which
is not subject to a binding and enforceable gas sales contract in effect on July
1, 1996. The Company currently owns 9.59% of ProEnergy which markets
approximately 1.8 MMBtu per day. As a result, as of January 1, 1996, the Company
no longer has any revenues or expenses associated with third party gas marketing
activities.
Significant Purchasers. The Company's two primary purchasers of crude oil
are Mobil Oil Corporation ("Mobil") and Genesis Crude Oil, L.P. ("Genesis"),
both of which purchase oil pursuant to contracts that provide for prices that
are based on prevailing market prices. For a description of these contracts, see
Note J of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data". Approximately 22% and 28% of the
Company's 1996 oil and gas revenues were attributable to sales to Mobil and
Genesis, respectively. During 1996, the Company marketed its natural gas,
including natural gas products, to a variety of purchasers, none of which
accounted for 10% or more of the Company's oil and gas revenues. The Company is
of the opinion that the loss of any one purchaser would not have an adverse
effect on its ability to sell its oil and gas production or natural gas
products.
Hedging Activities. The Company periodically enters into commodity
derivative contracts (swaps, futures and options) in order to (i) reduce the
effect of the volatility of price changes on the commodities the Company
produces and sells, (ii) support the Company's annual capital budgeting and
expenditure plans and (iii) lock in prices to protect the economics related to
certain capital projects. During 1996, the Company's hedging activities reduced
the average price received for oil and gas sales 6% and 5%, respectively, as
discussed below.
Natural Gas. The Company employs a policy of hedging gas production based
on the index price upon which the gas is actually sold in order to mitigate the
basis risk between NYMEX prices and actual index prices. The average gas prices
per Mcf that the Company reports includes the effects of Btu content, gathering
and transportation costs, gas processing and shrinkage and the net effect of the
gas hedges. The Company reported an average gas price of $2.27 per Mcf for the
year ended December 31, 1996. The Company's average realized price for physical
gas sales (excluding hedge results) for the same period was $2.39 per Mcf. The
comparable average NYMEX prompt month closing for the year ended December 31,
1996 was $2.50 per Mcf. At December 31, 1996, the Company had 28.9 Bcf of future
gas
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production hedged at a weighted average NYMEX price of $2.17 per Mcf for the
period from January 1997 through April 1999.
Crude Oil. All material purchase contracts governing the Company's oil
production are tied directly or indirectly to NYMEX prices. The average oil
prices per Bbl that the Company reports includes the effects of oil quality,
gathering and transportation costs and the net effect of the oil hedges. The
Company reported an average oil price of $19.96 per Bbl for the year ended
December 31, 1996. The Company's average realized price for physical oil sales
(excluding hedge results) for the same period was $21.33 per Bbl. The comparable
average NYMEX prompt month closing for the year ended December 31, 1996 was
$22.03 per Bbl. At December 31, 1996, the Company had 6.2 million barrels of
future oil production hedged at a weighted average NYMEX price of $19.39 per Bbl
for the period from January 1997 through December 1998.
See Note N of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for more detail concerning the
Company's swap contracts in effect at December 31, 1996.
Operations by Geographic Area
The Company operates in one industry segment. During 1996, the Company did
not have significant operations in geographic areas other than the United
States. For financial information with respect to the Company's 1994 and 1995
operations by geographic area, see Note T of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data".
Competition, Markets and Regulation
Competition. The oil and gas industry is highly competitive. A large number
of companies and individuals engage in the exploration for and development of
oil and gas properties, and there is a high degree of competition for oil and
gas properties suitable for development or exploration. Acquisitions of oil and
gas properties have been an important element of the Company's growth, and the
Company intends to continue to acquire oil and gas properties. The principal
competitive factors in the acquisition of oil and gas properties include the
staff and data necessary to identify, investigate and purchase such properties
and the financial resources necessary to acquire and develop them. Many of the
Company's competitors are substantially larger and have greater financial and
other resources than the Company.
Markets. The Company's ability to produce and market oil and gas profitably
depends on numerous factors beyond the Company's control. The effect of these
factors cannot be accurately predicted or anticipated. In recent years,
worldwide oil production capacity and gas production capacity in certain areas
of the United States have exceeded demand, with resulting declines in the price
of oil and gas. Although the Company cannot predict the occurrence of events
that may affect oil and gas prices or the degree to which oil and gas prices
will be affected, it is possible that prices for any oil or gas the Company
produces will be lower than those currently available. Any significant decline
in the price of oil or gas would adversely affect the Company's revenues,
profitability and cash flow and could, under certain circumstances, result in a
reduction in the carrying value of the Company's oil and gas properties.
Governmental Regulation. Oil and gas exploration and production are subject
to various types of regulation by local, state and federal agencies. The
Company's operations are also subject to state conservation laws and
regulations, including provisions for the unitization or pooling of oil and gas
properties, the establishment of maximum rates of production from wells and the
regulation of spacing, plugging and abandonment of wells. Each state generally
imposes a production or severance tax with respect to production and sale of oil
and gas within their respective jurisdictions. The regulatory burden on the oil
and gas industry increases the Company's cost of doing business and,
consequently, affects its profitability.
The Outer Continental Shelf Lands Act (the "OCSLA") requires that all
pipelines operating on or across the Outer Continental Shelf (the "OCS") provide
open-access, nondiscriminatory service. Although the Federal Energy Regulatory
Commission ("FERC") has chosen not to impose the regulations of Order No. 509,
which implements the OCSLA, on gatherers and other nonjurisdictional entities,
FERC has retained the authority to exercise jurisdiction over those entities if
necessary to permit nondiscriminatory access to service on the OCS. In addition,
gathering lines are currently exempt from FERC's jurisdiction, regardless of
whether they are on the OCS, but FERC could eliminate this exception. Commencing
May 1994, FERC issued a series of orders in individual cases that delineate its
current gathering policy. FERC's gathering policy was retained and clarified
with regard to deep water offshore facilities
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in a statement of policy issued in February 1996. FERC's new gathering policy
does not address its jurisdiction over pipelines operating on or across the OCS
pursuant to the OCSLA. If FERC were to apply Order No. 509 to gatherers on the
OCS, eliminate the exemption of gathering lines and redefine its jurisdiction
over gathering lines, these acts could result in a reduction in available
pipeline space for existing shippers in the Gulf of Mexico and elsewhere, such
as the Company.
The United States Minerals Management Service (the "MMS") is conducting an
inquiry into certain contract settlement agreements from which producers on
federal oil and gas leases have received settlement proceeds that the MMS claims
are royalty-bearing and into the extent to which producers have paid appropriate
royalty on those proceeds.
Additional proposals and proceedings that might affect the oil and gas
industry are considered from time to time by Congress, FERC, state regulatory
bodies and the courts. The Company cannot predict when or if any such proposals
might become effective or their effect, if any, on the Company's operations.
Environmental and Health Controls. The Company's operations are subject to
numerous federal, state and local laws and regulations relating to environmental
and health protection. These laws and regulations may require the acquisition of
a permit before drilling commences, restrict the type, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas and impose substantial liabilities for pollution resulting from
oil and gas operations. These laws and regulations may also restrict air or
other discharges resulting from the operation of natural gas processing plants,
pipeline systems and other facilities that the Company owns. Although the
Company believes that compliance with environmental laws and regulations will
not have a material adverse effect on operations or earnings, risks of
substantial costs and liabilities are inherent in oil and gas operations, and
there can be no assurance that significant costs and liabilities, including
potential criminal penalties, will not be incurred. Moreover, it is possible
that other developments, such as stricter environmental laws and regulations or
claims for damages to property or persons resulting from the Company's
operations, could result in substantial costs and liabilities.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
with respect to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of the disposal site or sites where
the release occurred and companies that disposed or arranged for the disposal of
hazardous substances released at the site. Persons who are or were responsible
for releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment.
The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The U.S. Environmental Protection Agency and various state
agencies have limited the approved methods of disposal for certain hazardous and
nonhazardous wastes. Furthermore, certain wastes generated by the Company's oil
and natural gas operations that are currently exempt from treatment as
"hazardous wastes" may in the future be designated as "hazardous wastes," and
therefore be subject to more rigorous and costly operating and disposal
requirements.
The Company currently owns or leases, and has in the past owned or leased,
properties that for many years have been used for the exploration and production
of oil and gas. Although the Company has used operating and disposal practices
that were standard in the industry at the time, hydrocarbons or other wastes may
have been disposed of or released on or under the properties owned or leased by
the Company or on or under other locations where such wastes have been taken for
disposal. In addition, some of these properties have been operated by third
parties whose treatment and disposal or release of hydrocarbons or other wastes
was not under the Company's control. These properties and the wastes disposed
thereon may be subject to CERCLA, RCRA and analogous state laws. Under such
laws, the Company could be required to remove or remediate previously disposed
wastes or property contamination or to perform remedial plugging operations to
prevent future contamination. For instance, until the past few years, it has
been customary within the oil industry to dispose of tank bottoms in close
proximity to the crude oil storage tanks in which they are accumulated. However,
at least two separate federal courts have recently ruled that the sludges that
accumulate at the bottom of crude oil storage tanks (commonly called "tank
bottoms") may be classified as hazardous substances subject to regulation and
liability under CERCLA. Consequently, wastes subject to
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classification as hazardous substances may have been disposed of or released on
or under the Company's properties or on or under other properties in connection
with the operation of the Company's properties.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention control plans, countermeasure plans, and facility response
plans relating to the possible discharge of oil into surface waters. The Oil
Pollution Prevention Act of 1990 ("OPA") amends certain provisions of the
federal Water Pollution Control Act of 1972, commonly referred to as the Clean
Water Act ("CWA") and other statutes as they pertain to the prevention of and
response to oil spills into navigable waters. The OPA subjects owners of
facilities to strict joint and several liability for all containment and cleanup
costs and certain other damages arising from a spill, including, but not limited
to, the costs of responding to a release of oil to surface waters. The CWA
provides penalties for any discharges of petroleum products in reportable
quantities and imposes substantial liability for the costs of removing a spill.
State laws for the control of water pollution also provide varying civil and
criminal penalties and liabilities in the case of releases of petroleum or its
derivatives into surface waters or into the ground.
OPA requires responsible parties to establish and maintain evidence of
financial responsibility to cover removal costs and damages resulting from an
oil spill. OPA calls for a financial responsibility increase from $35 million to
$150 million to cover pollution cleanup for offshore facilities. In August 1993,
MMS, which has been charged with implementing certain segments of OPA, issued
its advanced notice of proposed rulemaking that would increase financial
responsibility requirements for offshore lessees and permittees to $150 million
as required by OPA. Due to the OPA's broad definition of "offshore facility,"
the Company could become subject to the financial responsibility rule if it is
proposed and adopted; to date, however, the MMS has not formally proposed the
financial responsibility regulations. On May 9, 1995, the U.S. House of
Representatives passed a bill that would lower the financial responsibility
requirements applicable to offshore facilities to $35 million (the current
requirement under the federal Outer Continental Shelf Lands Act). The bill
allows the limit to be increased to $150 million if a formal risk assessment
indicates the increase to be warranted. It would also define "offshore facility"
to include only coastal oil and gas properties. A U.S. Senate bill that would
also lower the financial responsibility requirements for offshore facilities was
passed in late 1995. The Senate bill would reduce the scope of "offshore
facilities" subject to this financial assurance requirement to those facilities
seaward of the U.S. coastline that are engaged in drilling for, producing or
processing oil or that have the capacity to transport, store, transfer, or
handle more than 1,000 barrels of oil at a time. Currently, the House and Senate
bills are being reconciled in Conference Committee. The Clinton Administration
has indicated support for these changes to the OPA financial responsibility
requirements. The Company cannot predict the final form of the financial
responsibility requirements that will be ultimately established, but any role
that requires the Company to establish evidence of financial responsibility in
the amount of $150 million has the potential to have a material adverse effect
on Company operations and earnings. The Company does not believe that the rule
to be proposed by the MMS will be any more burdensome to it than it will be to
other similarly situated oil and gas companies.
Many states in which the Company operates have recently begun to regulate
naturally occurring radioactive materials ("NORM") and NORM wastes that are
generated in connection with oil and gas exploration and production activities.
NORM wastes typically consist of very low-level radioactive substances that
become concentrated in pipe scale and in production equipment. State regulations
may require the testing of pipes and production equipment for the presence of
NORM, the licensing of NORM-contaminated facilities and the careful handling and
disposal of NORM wastes. The Company believes that the growing regulation of
NORM will have a minimal effect on the Company's operations because the Company
generates only a very small quantity of NORM on an annual basis.
The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, no assurance can be given that environmental laws will not, in the
future, result in a curtailment of production or processing or a material
increase in the costs of production, development, exploration or processing or
otherwise adversely affect the Company's operations and financial condition.
The Company employs an environmental specialist charged with monitoring
regulatory compliance. Historically, the Company has performed an environmental
review as part of the due diligence work on potential acquisitions, including
acquisitions of oil and gas properties. The Company is not aware of any material
environmental legal proceedings pending against it or any significant
environmental liabilities to which it may be subject.
8
<PAGE>
Risks Associated with Business Activities
The nature of the business activities conducted subjects the Company to
certain hazards and risks. The following is a summary of some of the material
risks relating to the Company's business activities.
Oil and Gas Prices and General Market Risks. The Company's revenues,
profitability, cash flow and future rate of growth are highly dependent on the
prevailing prices of oil and gas, which are affected by numerous factors beyond
the Company's control. Oil and gas prices historically have been very volatile.
A substantial or extended decline in the prices of oil or gas could have a
material adverse effect on the Company's revenues, profitability and cash flow
and could, under certain circumstances, result in a reduction in the carrying
value of the Company's oil and gas properties and a reduction in the Company's
borrowing base under its bank credit facility.
Risks of Drilling Activities. As noted under "Item 1. Business - Business
Activities," of the total 1997 capital budget of $270 million, the Company
anticipates spending approximately $170 million on exploitation activities and
$67 million on exploration activities. This capital expenditure budget reflects
the Company's plans to drill approximately 500 development wells and 100
exploratory wells and to perform recompletions on over 150 wells. Drilling
involves numerous risks, including the risk that no commercially productive
natural gas or oil reservoirs will be encountered. The cost of drilling,
completing and operating wells is often uncertain and drilling operations may be
curtailed, delayed or canceled as a result of a variety of factors, including
unexpected drilling conditions, pressure or irregularities in formations,
equipment failures or accidents, adverse weather conditions and shortages or
delays in the delivery of equipment. The Company's future drilling activities
may not be successful and, if unsuccessful, such failure could have an adverse
effect on the Company's future results of operations and financial condition.
While all drilling, whether developmental or exploratory, involves these risks,
exploratory drilling involves greater risks of dry holes or failure to find
commercial quantities of hydrocarbons. Because of the percentage of the
Company's capital budget devoted to exploratory projects, it is likely that the
Company will continue to experience exploration and abandonment expense.
Acquisitions. Acquisitions of producing oil and gas properties have been a
key element of the Company's growth. In implementing its strategic plan, the
Company reduced its emphasis on acquisition activities during 1995 and 1996 and
focused on the development of its property base which was built largely through
acquisitions. The Company's growth following the full development of that
property base could be impeded if it is unable to acquire additional oil and gas
properties on a profitable basis. The success of any acquisition will depend on
a number of factors, including the ability to estimate accurately the
recoverable volumes of reserves, rates of future production and future net
revenues attributable to reserves and to assess possible environmental
liabilities. All of these factors affect whether an acquisition will ultimately
generate cash flows sufficient to provide a suitable return on investment. Even
though the Company performs a review of the properties it seeks to acquire that
it believes is consistent with industry practices, such reviews are often
limited in scope.
Divestitures. The Company regularly reviews its property base for the
purpose of identifying nonstrategic assets, the disposition of which would
create organizational and operational efficiencies. Various factors could
materially affect the ability of the Company to dispose of nonstrategic assets,
including the availability of purchasers willing to purchase the nonstrategic
assets at prices acceptable to the Company.
Risks Associated with Operation of Natural Gas Processing Plants. The
Company owns interests in three natural gas processing plants and operates one
of those plants, although the net revenues derived from natural gas processing
during 1996 represented only 4% of the total net revenues from oil and gas
activities. There are significant risks associated with the operation of natural
gas processing plants. Natural gas and natural gas liquids are volatile and
explosive and may include carcinogens. Damage to or misoperation of a natural
gas processing plant could result in an explosion or the discharge of toxic
gases, which could result in significant damage claims in addition to
interrupting a revenue source.
Operating Hazards and Uninsured Risks. The Company's operations are subject
to all the risks normally incident to the oil and gas exploration and production
business, including blowouts, cratering, explosions and pollution and other
environmental damage, any of which could result in substantial losses to the
Company due to injury or loss of life, damage to or destruction of wells,
production facilities or other property, clean-up responsibilities, regulatory
investigations and penalties and suspension of operations. Although the Company
currently maintains insurance coverage that it considers reasonable and that is
similar to that maintained by comparable companies in the oil and gas industry,
it is not fully insured against certain of these risks, either because such
insurance is not available or because of high premium costs.
9
<PAGE>
Environmental Risks. The oil and gas business is also subject to
environmental hazards, such as oil spills, gas leaks and ruptures and discharges
of toxic substances or gases that could expose the Company to substantial
liability due to pollution and other environmental damage. A variety of federal
and state laws and regulations govern the environmental aspects of the oil and
gas business. Noncompliance with these laws and regulations may subject the
Company to penalties, damages or other liabilities, and compliance may increase
the cost of the Company's operations. Such laws and regulations may also affect
the costs of acquisitions. See "Item 1. Business - Competition, Markets and
Regulation - Environmental and Health Controls".
The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, no assurance can be given that environmental laws will not, in the
future, result in a curtailment of production or processing or a material
increase in the costs of production, development, exploration or processing or
otherwise adversely affect the Company's operations and financial condition.
Pollution and similar environmental risks generally are not fully insurable.
Competition. The oil and gas industry is highly competitive. The Company
competes with other companies, producers and operators for acquisitions and in
the exploration, development, production and marketing of oil and gas. Some of
these competitors have substantially greater financial and other resources than
the Company. See "Item 1. Business - Competition, Markets and Regulation".
Government Regulation. The Company's business is regulated by a variety of
federal, state and local laws and regulations. There can be no assurance that
present or future regulations will not adversely affect the Company's business
and operations. See "Item 1. Business - Competition, Markets and Regulation".
Risks of International Operations. At December 31, 1996, less than 1% of
the Company's proved reserves of oil and gas were located outside the United
States. The success and profitability of international operations may be
adversely affected by risks associated with international activities, including
economic and labor conditions, political instability, tax laws (including U.S.
taxes on foreign subsidiaries) and changes in the value of the United States
dollar versus the local currency in which oil and gas are sold. To the extent
that the Company is involved in international activities, changes in exchange
rates may adversely affect the Company's consolidated revenues and expenses (as
expressed in United States dollars).
Estimates of Reserves and Future Net Revenues. Numerous uncertainties exist
in estimating quantities of proved reserves and future net revenues therefrom.
The estimates of proved reserves and related future net revenues set forth in
this Report are based on various assumptions, which may ultimately prove to be
inaccurate. Therefore, such estimates should not be construed as estimates of
the current market value of the Company's proved reserves.
Definition of Certain Oil and Gas Terms
When used in this Report, the following terms have the meanings indicated
below.
"Bbl" means a standard barrel of 42 U.S. gallons and represents the basic
unit for measuring the production of crude oil and condensate.
"Bcf" means one billion cubic feet.
"BOE" means a barrel-of-oil-equivalent and is a customary convention used
in the United States to express oil and gas volumes on a comparable basis. It is
determined on the basis of the estimated relative energy content of natural gas
to oil, being approximately 6 Mcf of natural gas per Bbl of oil.
"gross" acre or well means an acre or well in which a working interest is
owned.
"MBbl" means one thousand Bbls.
"MBOE" means one thousand BOEs.
"Mcf" means one thousand cubic feet under prescribed conditions of pressure
and temperature and represents the basic unit for measuring the production of
natural gas.
"MMcf" means one million cubic feet.
10
<PAGE>
"net" acres or wells is determined by multiplying the gross acres or wells,
as the case may be, by the applicable working interest in those gross acres or
well.
"NGLs" means natural gas liquids.
"proved reserves" means those estimated quantities of crude oil and natural
gas that geological and engineering data demonstrate with reasonable certainty
to be recoverable in future years from known oil and gas reservoirs under
existing economic and operating conditions. Proved reserves are limited to those
quantities of oil and gas that can be expected to be recoverable commercially at
current prices and costs, under existing regulatory practices and with existing
conventional equipment and operating methods.
"SEC 10 value" means the present value of estimated future net revenues,
before income taxes, of proved reserves, determined in all material respects in
accordance with the rules and regulations of the Securities and Exchange
Commission (generally using prices and costs in effect at the specified date and
a 10% discount rate). The prices in effect at December 31, 1996 used in
calculating SEC 10 value as of such date for purposes of this Report were $24.55
per Bbl (reflecting adjustments for oil quality and gathering and transportation
costs) for domestic oil reserves and $3.97 per Mcf (reflecting adjustments for
BTU content, gathering and transportation costs and gas processing and
shrinkage) for domestic gas reserves.
ITEM 2. PROPERTIES
The information included in this Report about the Company's proved oil and
gas reserves at December 31, 1996, including estimated quantities and SEC 10
value, is based on reserve reports audited by Netherland, Sewell & Associates,
Inc. for the Company's major domestic properties (representing approximately 52%
of the total SEC 10 value of the Company's domestic proved reserves at December
31, 1996) and reserve reports prepared by the Company's engineers for all other
domestic properties and the Company's Argentine properties. The estimate of the
reserves related to the Company's interests in natural gas processing rights for
proved reserves contractually or economically dedicated to the Company's natural
gas processing plants is based on evaluations prepared by the Company's
engineers.
Numerous uncertainties exist in estimating quantities of proved reserves
and in projecting future rates of production and timing of development
expenditures, including many factors beyond the Company's control. This Report
contains estimates of the Company's proved oil and gas reserves and the related
future net revenues therefrom, which are based on various assumptions, including
those prescribed by the Securities and Exchange Commission. Actual future
production, oil and gas prices, revenues, taxes, capital expenditures, operating
expenses, geologic success and quantities of recoverable oil and gas reserves
may vary substantially from those assumed in the estimates and could materially
affect the estimated quantities and related SEC 10 value of proved reserves set
forth in this Report. In addition, the Company's reserves may be subject to
downward or upward revisions based on production performance, purchases or sales
of properties, results of future development, prevailing oil and gas prices and
other factors. Therefore, estimates of the SEC 10 value of proved reserves
contained in this Report should not be construed as estimates of the current
market value of the Company's proved reserves.
SEC 10 value is a reporting convention that provides a common basis for
comparing oil and gas companies subject to the rules and regulations of the
Securities and Exchange Commission. It requires the use of oil and gas prices
prevailing as of the date of computation. Consequently, it may not reflect the
prices ordinarily received or that will be received for oil and gas because of
seasonal price fluctuations or other varying market conditions. SEC 10 values as
of any date are not necessarily indicative of future results of operations.
Accordingly, estimates of future net revenues in this Report may be materially
different from the net revenues that are ultimately received.
The Company did not provide estimates of total proved oil and gas reserves
during 1996 to any federal authority or agency, other than the Securities and
Exchange Commission.
Proved Reserves
The Company's proved reserves totaled 302.2 million BOE at December 31,
1996, 296.8 million BOE at December 31, 1995 and 282.5 million BOE at December
31, 1994, representing $2.3 billion, $1.4 billion and $1.1 billion,
respectively, in SEC 10 value. The Company achieved these annual increases in
reserves despite having sold reserves of 45.8 million BOE in 1996 and 34.8
million BOE in 1995. Excluding these sold reserves, total proved reserves
increased 21% in 1996 and 28% in 1995. Oil reserves at year-end 1996 were 163.9
million Bbls compared
11
<PAGE>
to 147.3 million Bbls at year-end 1995 and 144.5 million Bbls at year-end 1994
(an 11% increase from 1995 to 1996 and a 2% increase from 1994 to 1995). Natural
gas reserves at year-end 1996 were 829.4 Bcf, compared to 896.9 Bcf at year-end
1995 and 827.5 Bcf at year-end 1994 (an 8% decrease from 1995 to 1996 and an 8%
increase from 1994 to 1995).
On a BOE basis, 78% of the Company's total proved reserves at December 31,
1996 are proved developed reserves. The Company operates 86% of its total proved
reserves based on the December 31, 1996 SEC 10 value. Based on reserve
information as of December 31, 1996 and using the Company's reserve report
production information for 1997, the reserve-to-production ratio associated with
the Company's proved reserves is 12.1 years on a BOE basis. The following table
provides information regarding the Company's proved reserves by geographic area
as of and for the year ended December 31, 1996.
<TABLE>
PROVED OIL AND GAS RESERVES
<CAPTION>
1996 Average
Proved Reserves as of December 31, 1996 Daily Production (a)
------------------------------------------ ---------------------------
Natural SEC 10 Natural
Oil Gas Value Oil Gas
(MBbls) (MMcf) MBOE (000) (Bbls) (Mcf) BOE
------- ------- ------- ---------- ------ ------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
United States:
Spraberry......... 112,301 284,576 159,730 $1,119,950 17,638 42,182 24,668
Permian........... 41,391 119,710 61,343 515,461 8,606 35,481 14,520
Gulf Coast........ 4,345 252,335 46,401 445,337 2,166 92,309 17,551
Mid-Continent..... 2,769 167,120 30,622 238,400 1,294 31,813 6,596
Other............. 2,030 4,527 2,785 18,180 1 194 33
------- ------- ------- --------- ------ ------- ------
162,836 828,268 300,881 2,337,328 29,705 201,979 63,368
Australia (b)...... - - - - 955 5,265 1,833
Argentina.......... 1,105 1,108 1,290 8,041 145 - 145
------- ------- ------- --------- ------ ------- ------
Total............ 163,941 829,376 302,171 $2,345,369 30,805 207,244 65,346
======= ======= ======= ========= ====== ======= ======
<FN>
- ---------------
(a) The 1996 average daily production is calculated using a 366-day year and
without making pro forma adjustments for any acquisitions, divestitures or
drilling activity that occurred during the year.
(b) Represents production associated with the Company's Australian subsidiaries
prior to their divestiture in 1996. See Note Q of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data".
</FN>
</TABLE>
In addition, proved NGLs of 12.6 million Bbls were attributable to the
Company's interests in gas processing rights in reserves contractually or
economically dedicated to the Company's natural gas processing plants at
December 31, 1996. The present value of estimated future net revenues from those
dedicated proved reserves was $44.3 million at December 31, 1996 (using a
constant weighted average price of $11.46 per Bbl and a 10% discount rate). For
the year ended December 31, 1996, average daily production from the Company's
interests in natural gas processing plants was 2,327 NGLs per day.
Reserve Replacement
For the eighth consecutive year, the Company was able to replace its annual
production volumes with proved reserves of crude oil and natural gas, stated on
an energy equivalent basis. During 1996, the Company added 75 million BOE
resulting in reserve replacement of 314% of total production. Of the 75 million
BOE reserve additions, 71.1 million BOE were added through exploration and
development drilling activities, 2.2 million BOE were added through acquisitions
of proved properties and 1.7 million BOE were the net result of revisions.
Reserves added by development drilling are primarily from the identification of
additional infill drilling locations and new secondary recovery projects.
Reserve revisions result from several factors including changes in existing
estimates of quantities available for production and changes in estimates of
quantities which are economical to produce under current pricing conditions. The
Company's reserves as of December 31, 1996 were estimated using a price of
$24.55 per Bbl and $3.97 per Mcf. Should prices decline in future years,
reserves may be revised downward for quantities which may be uneconomical to
produce at lower prices.
The Company's 1996 reserve replacement rate on a barrel of oil equivalent
basis was 314%, which included reserve replacement rates for oil and natural gas
of 398% and 239%, respectively. Previous reserve replacement performance
12
<PAGE>
rates were 281% in 1995 (263% for oil and 297% for gas) and 537% in 1994 (549%
for oil and 526% for gas). For the three year period ended December 31, 1996,
the three year average reserve replacement rate was 377%, as compared to a three
year average replacement rate of 412% in 1995 and 496% in 1994. Through 1994,
the Company's reserve replacement rate was primarily the product of its
acquisition activities. Beginning in 1995, and to a greater extent in 1996, the
reserve replacement rates have been influenced more by exploration and
development activities and less by acquisition activities. The Company seeks to
achieve an annual reserve replacement rate of at least 150% through the emphasis
on its exploration and development activities.
Finding Cost
The Company's acquisition and finding cost for 1996 was $3.10 per BOE as
compared to the 1995 and 1994 acquisition and finding costs of $2.87 and $5.11
per BOE, respectively. The average acquisition and finding cost for the
three-year period from 1994 to 1996 was $3.99 per BOE representing an 18%
decrease from the 1995 three-year average rate of $4.84.
Oil and Gas Mix
The Company seeks to maintain a strategic balance between oil and natural
gas reserves and production. While the Company's reserve and production mix may
vary somewhat on a short-term basis as the Company takes advantage of market
conditions and specific acquisition and development opportunities, management
believes that a relative mix of approximately 50% oil and 50% natural gas is in
the best long-term interests of the Company and its stockholders. The Company's
reserve mix was 54% oil and 46% gas at December 31, 1996, and its production mix
was 47% oil and 53% gas during 1996.
Description of Properties
The Company manages its domestic oil and gas properties based upon their
geographic area, and, as a result, the Company has divided its domestic
operations into four operating divisions: the Spraberry Division, the Permian
Division, the Gulf Coast Division, and the MidContinent Division. In addition,
the Company has an international division that manages the Company's ownership
in oil and gas properties outside the United States. At December 31, 1996, the
Company's only properties outside the U.S. are located in Argentina.
Spraberry Division. The Spraberry field was discovered in 1949 and
encompasses eight counties in West Texas. The field is approximately 150 miles
long and 75 miles wide at its widest point. The oil produced is West Texas
Intermediate Sweet, and the gas produced is casinghead gas with an average Btu
content of 1,400 Btu per Mcf. The oil and gas is produced from three formations,
the upper and lower Spraberry and the Dean, at depths ranging from 6,700 feet to
9,200 feet. The center of the Spraberry field was unitized in the late 1950's
and early 1960's by the major oil companies but until the late 1980's
experienced very limited development activity. Since 1989, the Company has
focused acquisition and development drilling activities in the unitized portion
of the Spraberry field due to the dormant condition of the properties and the
high net revenue interests available. The Company believes the area offers
excellent opportunities to enhance oil and gas reserves because of the hundreds
of undeveloped infill drilling locations and the ability to reduce operating
expenses through economies of scale. In February 1997, the Texas Railroad
Commission (which regulates oil and gas production) entered a favorable order on
the Company's application to allow administrative approval of uncontested
applications to increase the density of drilling in the Spraberry field from one
well per 80 acres to one well in 40. The Company believes such reduced spacing
may provide in excess of 1,000 additional drilling locations which have the
potential to add 70 million equivalent barrels to the Company's reserve base.
The Company continues to realize the benefits of its focus on the Spraberry
field through significant reserve additions due to development drilling and
identification of a large number of new drilling locations each year. As a
result, the Company plans to continue to devote a great deal of its capital
budget and operating resources to the ongoing development of the Spraberry
field. Specifically, the Company has allocated $88 million, or 37%, of its 1997
exploration and development budget to drill approximately 225 development wells
and to perform approximately 50 recompletions in the Spraberry field.
Permian Division. Since the early 1960's, the Company has been involved in
acquisition and development activities in the Permian Division which includes
all of West Texas and Southeastern New Mexico except for the Spraberry field.
The Iatan field in Mitchell County, Texas, the Lusk and Dagger Draw fields in
Eddy County, New Mexico, the Abell (Devonian) field in Crane and Pecos Counties
of Texas and the Ozona field in Crockett and Sutton
13
<PAGE>
Counties of Texas are core areas for the Company's Permian Division operations
in terms of existing production, production and reserve growth, and
identification of additional drilling locations. During 1996, the Permian
Division expanded its growth strategy to include significant emphasis on
exploration activities in order to produce a more balanced portfolio. In
November 1996, the Company announced a significant oil discovery in the War-Wink
West Field in the Delaware Basin of West Texas. This Company operated well, the
University 18-34 #1, tested at rates of up to 720 barrels of oil per day and is
currently producing at its expected allowable rate of approximately 270 barrels
of oil per day and 374 thousand cubic feet of gas per day. The Company and
Enserch Exploration, Inc. ("Enserch") each own a 50% working interest in this
well, which is the first in their joint exploration and development of the 4,500
acre War-Wink prospect. In addition, during 1996, the Company experienced
successful results from its exploratory efforts in the Permian reef play of the
Southeastern Shelf of the Midland Basin.
The Company will continue to focus on the development of the existing
properties utilizing waterflood procedures and secondary recovery technologies
as these efforts have consistently resulted in increased production, reserve
additions due to development drilling, and new drilling locations. In addition,
all of the fields in this operational group have been screened for feasibility
for carbon dioxide (CO2) flood implementation, and the Company plans to move
forward in utilizing this technology in 1997. During 1997, the Company plans to
continue its development of the War- Wink prospect by drilling two confirmation
wells and an additional two to four development wells. Parker & Parsley and
Enserch also control approximately 30,000 additional acres in the Delaware Basin
play in Southeastern New Mexico and West Texas where they intend to drill eight
exploratory wells in 1997. Also during 1997, the Company plans to perform
additional 3-D seismic data interpretation in order to exploit the Midland Basin
successes.
In total, the Company anticipates spending $45 million in 1997 in this
area to drill approximately 220 wells and to perform recompletions on
approximately 90 targeted wells. Eighty percent of these planned expenditures
are devoted to development activities.
Gulf Coast Division. The Gulf Coast Division includes onshore oil and gas
properties located in South and East Texas, Louisiana, Mississippi and Alabama.
The primary producing formations in this region include the Wilcox, Frio and
Yegua formations in Texas and the Cretaceous formation in Mississippi. The
addition of the domestic properties acquired as a part of the Bridge Oil Limited
acquisition (primarily in South Texas and Louisiana), positioned the Company to
be better able to pursue and realize future economic growth in this area.
The strategy for the Gulf Coast Division has been to emphasize the growth
of natural gas reserves. To accomplish this, the Company has devoted most of its
domestic exploration efforts to this region as well as its investment in and
utilization of 3-D seismic technology. In addition, the Company is successfully
employing newer drilling techniques such as drilling horizontal wells.
Utilization of 3-D seismic technology during 1996 yielded substantial results in
the Company's Lopeno field which produces from the Wilcox formation. Gross gas
production increased from 14 MMcf per day to 38 MMcf per day in 1996 in this
area as a result of drilling six development wells, most of which were
identified through the 3-D project, and the Company has identified several
additional drilling locations after interpreting 3-D seismic data. In addition,
the Company experienced successful results in its Central Texas Pawnee field
which produces from the Edwards formation after drilling a successful horizontal
well in late 1996. This well, the S.E. Turner Gas Unit #2, in which the Company
owns a 100% working interest, is currently flowing at a rate of 3.1 MMcf per
day. The Company plans to drill two additional horizontal wells and to initiate
a 3-D project in this field during 1997 in order to exploit the 1996 successes.
Overall, the Company plans to continue its emphasis on exploration
activities in the Gulf Coast Division with a total budget of $45 million being
devoted to drilling approximately 25 exploratory wells and 40 development wells.
MidContinent Division. The Mid-Continent Division includes properties
located in the Texas Panhandle and Oklahoma. In past years, the Company has
aggressively engaged in both acquisitions and divestitures of oil and gas
properties in order to position this portfolio of properties for significant
growth through development and exploratory drilling opportunities. During 1997,
the Company plans to spend approximately $23 million in the MidContinent
Division on exploitation and exploration activities. This activity includes
drilling approximately 45 development wells and performing recompletions on
approximately 20 targeted wells.
International. The Company owns interests in Argentina consisting of a
14.42% interest in the Confluencia block and a 15% interest in the China Muerta
block, both in the Neuquen Basin of Central Argentina. During 1996, the Company
participated in several discoveries in the Confluencia Sur field in the
Confluencia block. In early 1996, the Company announced the successful
completion of two exploratory wells (the Naco x-1 and the Sierra de Reyes x-1),
and, in January 1997, the Company announced the successful completion of three
development wells, also in the
14
<PAGE>
Confluencia Sur field. The three wells, the Sierra de Reyes 2, 3 and 4, operated
by Petrolera Argentina San Jorge S.A., collectively tested 3,727 barrels of oil
per day, and current gross production for the field is at a facility-
constrained rate of 2,520 Bbls of oil per day. The Company expects to drill an
additional two to three development wells in the Confluencia Sur field during
the first six months of 1997 in order to increase daily oil production to 6,000
barrels (865 barrels net to the Company's interest).
Selected Oil and Gas Information
The following tables set forth selected oil and gas information for the
Company as of and for each of the years ended December 31, 1996, 1995 and 1994.
Because of normal production declines, increased or decreased drilling
activities and the effects of future acquisitions or divestitures, the
historical information presented below should not be interpreted as indicative
of future results.
Production, Price and Cost Data. The following table sets forth production,
price and cost data with respect to the Company's properties for the years ended
December 31, 1996, 1995 and 1994.
<TABLE>
PRODUCTION, PRICE AND COST DATA (a)
<CAPTION>
Year ended December 31,
--------------------------------------------------------------------------------------
1996 1995 1994
-------------------------- ------------------------- --------------------------
Australia(b)
United and United United
States Argentina Total States Australia Total States Australia Total
------ --------- ----- ------ --------- ----- ------ --------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Production information:
Annual production:
Oil (MBbls)..... 10,872 403 11,275 11,328 1,574 12,902 11,267 880 12,147
Gas (MMcf)...... 73,924 1,927 75,851 76,669 8,626 85,295 75,040 4,634 79,674
Total (MBOE).... 23,193 723 23,916 24,106 3,012 27,118 23,774 1,652 25,426
Average daily
production:
Oil (Bbls).... 29,705 1,100 30,805 31,036 4,312 35,348 30,868 2,411 33,279
Gas (Mcf)..... 201,979 5,265 207,244 210,052 23,633 233,685 205,589 12,696 218,285
Total (BOE)... 63,368 1,978 65,346 66,045 8,251 74,296 65,133 4,527 69,660
Average prices:
Oil (per Bbl).... $ 19.96 $ 19.81 $ 19.96 $ 16.70 $ 18.78 $ 16.96 $ 15.26 $ 17.12 $ 15.40
Gas (per Mcf).... $ 2.27 $ 1.95 $ 2.27 $ 1.84 $ 1.88 $ 1.84 $ 1.89 $ 1.89 $ 1.89
Revenue (per BOE) $ 16.61 $ 16.21 $ 16.60 $ 13.69 $ 15.21 $ 13.85 $ 13.20 $ 14.43 $ 13.28
Average costs:
Production costs
(per BOE):
Lease operating
expense....... $ 3.39 $ 4.75 $ 3.43 $ 3.97 $ 4.12 $ 3.99 $ 4.11 $ 3.89 $ 4.10
Production taxes .94 - .91 .70 - .62 .72 - .67
Workover....... .28 - .27 .25 - .22 .25 - .23
------ ------ ------ ------ ------ ------ ------ --- ------
Total........ $ 4.61 $ 4.75 $ 4.61 $ 4.92 $ 4.12 $ 4.83 $ 5.08 $ 3.89 $ 5.00
Depletion expense
(per BOE)...... $ 4.25 $ 5.73 $ 4.30 $ 5.19 $ 6.74 $ 5.36 $ 5.07 $ 6.77 $ 5.18
<FN>
- ---------------
(a) These amounts are calculated without making pro forma adjustments for any
acquisitions, divestitures or drilling activity that occurred during the
respective years.
(b) Represents production associated with the Company's Australian subsidiaries
prior to their divestiture in 1996. See Note Q of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data".
</FN>
</TABLE>
15
<PAGE>
Productive Wells. The following table sets forth the number of productive
oil and gas wells attributable to the Company's properties as of December 31,
1996, 1995 and 1994.
<TABLE>
<CAPTION>
PRODUCTIVE WELLS(a)
Gross Productive Wells Net Productive Wells
---------------------- ---------------------
Oil Gas Total Oil Gas Total
----- ----- ------ ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Year ended December 31, 1996:
United States............... 5,572 1,393 6,965 3,119 650 3,769
Argentina................... 5 - 5 1 - 1
----- ----- ------ ----- ----- -----
Total....................... 5,577 1,393 6,970 3,120 650 3,770
===== ===== ====== ===== ===== =====
Year ended December 31, 1995:
United States............... 6,138 2,137 8,275 3,198 680 3,878
Australia and Other
Foreign.................... 112 450 562 27 54 81
----- ----- ------ ----- ----- -----
Total....................... 6,250 2,587 8,837 3,225 734 3,959
===== ===== ====== ===== ===== =====
Year ended December 31, 1994:
United States............... 8,096 3,225 11,321 4,423 1,652 6,075
Australia and Other
Foreign.................... 83 542 625 19 70 89
----- ----- ------ ----- ----- -----
Total....................... 8,179 3,767 11,946 4,442 1,722 6,164
===== ===== ====== ===== ===== =====
<FN>
- ---------------
(a) Productive wells consist of producing wells and wells capable of
production, including shut-in wells. One or more completions in the same
well bore are counted as one well. Any well in which one of the multiple
completions is an oil completion is classified as an oil well. As of
December 31, 1996, the Company owned interests in 73 wells containing
multiple completions.
</FN>
</TABLE>
Leasehold Acreage. The following table sets forth information about the
Company's developed, undeveloped and royalty leasehold acreage as of December
31, 1996.
<TABLE>
<CAPTION>
LEASEHOLD ACREAGE
Developed Acreage Undeveloped Acreage
---------------------- ---------------------- Royalty
Gross Acres Net Acres Gross Acres Net Acres Acreage
----------- --------- ----------- --------- -------
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1996:
United States............. 1,174,911 517,385 1,029,883 597,210 435,618
Argentina (a)............. 5,718 825 1,816,429 262,111 -
--------- ------- --------- ------- -------
Total..................... 1,180,629 518,210 2,846,312 859,321 435,618
========= ======= ========= ======= =======
<FN>
- ---------------
(a) Effective February 22, 1997, the Company relinquished its interests in the
Laguna Blanca and Las Lajas blocks in the Neuquin Basin of Central
Argentina which represents 1,199,670 gross and 173,113 net undeveloped
acres at December 31, 1996.
</FN>
</TABLE>
Drilling Activities. The following table sets forth the number of gross and
net productive and dry wells in which the Company had an interest that were
drilled and completed during the years ended December 31, 1996, 1995 and 1994.
This information should not be considered indicative of future performance, nor
should it be assumed that there is necessarily any correlation between the
number of productive wells drilled and the oil and gas reserves generated
thereby or the costs to the Company of productive wells compared to the costs of
dry wells.
16
<PAGE>
<TABLE>
<CAPTION>
DRILLING ACTIVITIES
Gross Wells Net Wells
---------------------- -------------------------
Year Ended December 31, Year Ended December 31,
---------------------- -------------------------
1996(b) 1995 1994 1996(b) 1995 1994
------- ------ ------ ------- ------ ------
<S> <C> <C> <C> <C> <C> <C>
United States:
Productive wells:
Development........... 535 432 282 362.9 307.0 193.4
Exploratory........... 37 30 6 24.2 18.0 3.5
Dry holes:
Development........... 7 7 2 4.4 2.1 1.9
Exploratory........... 10 16 3 6.0 4.7 1.6
--- --- --- ----- ----- -----
589 485 293 397.5 331.8 200.4
--- --- --- ----- ----- -----
Australia:
Productive wells:
Development........... 2 6 1 .3 1.4 0.2
Exploratory........... - 1 2 - .3 0.5
Dry holes:
Development........... 1 - - .2 - -
Exploratory........... 1 9 3 .2 2.8 2.5
--- --- --- ----- ----- -----
4 16 6 .7 4.5 3.2
--- --- --- ----- ----- -----
Argentina:
Productive wells:
Development........... 3 - - .4 - -
Exploratory........... - 1 - - .1 -
Dry holes:
Development........... - - - - - -
Exploratory........... 3 7 - .4 1.0 -
--- --- --- ----- ----- -----
6 8 - .8 1.1 -
--- --- --- ----- ----- -----
Total............... 599 509 299 399.0 337.4 203.6
=== === === ===== ===== =====
Success ratio(a)........ 96% 92% 97% 97% 97% 97%
<FN>
- ---------------
(a) Represents those wells that were successfully completed as productive wells.
(b) The 1996 amounts include only three months of activity related to the
Company's Australian properties. The remaining foreign drilling activities
primarily relate to the Company's interests in Argentine oil and gas
properties.
</FN>
</TABLE>
The following table sets forth information about the Company's wells that
were in progress at December 31, 1996.
Gross Wells Net Wells
----------- ---------
United States:
Development............. 74 56.1
Exploratory............. 9 6.3
--- ----
Total................ 83 62.4
=== ====
Argentina:
Exploratory............. 2 0.3
=== ====
ITEM 3. LEGAL PROCEEDINGS
The Company is a party to various legal proceedings incidental to its
business involving claims in oil and gas leases or interests, other claims for
damages in amounts not in excess of 10% of its current assets and other matters,
none of which the Company believes to be material.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of the Company's stockholders
during the fourth quarter of 1996.
17
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
The Company's common stock is listed and traded on the New York Stock
Exchange under the symbol "PDP". The following table sets forth, for the periods
indicated, the high and low sales prices for the Company's common stock, as
reported in the New York Stock Exchange composite transactions, and the amount
of dividends paid.
Dividends
High Low Paid per share
-------- -------- --------------
1996
Fourth quarter................. $ 37 1/4 $ 26 1/8 -
Third quarter.................. $ 27 3/4 $ 22 1/4 $.05
Second quarter................. $ 27 7/8 $ 22 3/4 -
First quarter.................. $ 23 3/4 $ 19 3/8 $.05
1995
Fourth quarter................. $ 22 1/2 $ 18 1/2 -
Third quarter.................. $ 23 1/4 $ 17 3/8 $.05
Second quarter................. $ 22 3/4 $ 18 5/8 -
First quarter.................. $ 22 7/8 $16 5/16 $.05
On February 3, 1997, the last reported sales price of the Company's common
stock, as reported in the New York Stock Exchange composite transactions, was
$34-1/8 per share.
As of February 3, 1997, the Company's common stock was held by
approximately 39,000 holders of record and approximately 57,300 beneficial
owners.
Since the third quarter of 1991, the Company has paid a cash dividend of
$.05 per share of common stock in the first and third quarters of each calendar
year. Subject to the continuation of successful operations and the discretion of
the Company's Board of Directors, the Company intends to continue to declare a
$.05 per share dividend on a semi-annual basis to achieve an annual dividend
level of $.10 per share. The Company's Board of Directors may from time to time
reconsider the dividend policy and make any changes that it deems appropriate.
There can be no assurance that any future dividends or distributions will be
paid on the Company's common stock. The Company's current bank credit facility
agreement contains various restrictive covenants, which, among other things,
limit to $5 million per year the sum of annual dividends that the Company may
declare and pay and the amount of the Company's capital stock that the Company
may redeem or purchase.
18
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data for the Company should
be read in conjunction with "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Company's Consolidated
Financial Statements, related notes and other financial information included in
"Item 8. Financial Statements and Supplementary Data".
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994(a) 1993(b) 1992
---------- ---------- ---------- ---------- ---------
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Statement of Operations Data
Total operating revenues.................. $ 420,745 $ 485,762 $ 479,733 $ 328,467 $ 201,807
Total operating expenses(c)............... 286,389 586,947 461,804 280,473 163,071
--------- --------- --------- --------- --------
Operating income (loss)................... 134,356 (101,185) 17,929 47,994 38,736
--------- --------- --------- --------- --------
Other revenues and expenses:
Interest and other income............... 17,458 11,364 6,918 4,388 4,223
Gain on disposition of assets,
net (d)............................... 97,140 16,620 9,512 23,220 4,169
Interest expense........................ (46,155) (65,449) (50,552) (23,338) (14,708)
Other expenses.......................... (2,451) (11,357) (4,298) (3,861) (2,274)
--------- --------- --------- --------- --------
65,992 (48,822) (38,420) 409 (8,590)
--------- --------- --------- --------- --------
Income (loss) before income taxes,
extraordinary item and cumulative
effect of accounting change............. 200,348 (150,007) (20,491) 48,403 30,146
Income tax benefit (provision)............ (60,100) 45,900 6,500 (17,000) (3,000)
--------- --------- --------- --------- --------
Income (loss) before extraordinary item
and cumulative effect of accounting
change.................................. $ 140,248 $ (104,107) $ (13,991) $ 31,403 $ 27,146
========= ========= ========= ========= ========
Income (loss) before extraordinary item
and cumulative effect of accounting
change per share:
Primary............................... $ 3.92 $ (2.95) $ (.47) $ 1.13 $ 1.05
========= ========= ========= ========= ========
Fully diluted......................... $ 3.47 $ (2.95) $ (.47) $ 1.13 $ 1.05
========= ========= ========= ========= ========
Dividends per share ...................... $ .10 $ .10 $ .10 $ .10 $ .10
========= ========= ========= ========= ========
Weighted average shares outstanding....... 35,734 35,274 30,063 27,945 25,825
Cash Flow Data
Net cash provided by operating activities. $ 230,059 $ 157,256 $ 129,750 $ 112,152 $ 77,203
Net cash provided by (used in) investing
activities............................. 13,539 (53,806) (454,894) (386,816) (111,827)
Net cash provided by (used in) financing
activities.............................. (258,940) (107,541) 331,832 291,677 33,756
Balance Sheet Data
Working capital........................... $ 26,069 $ 31,501 $ 43,653 $ 39,475 $ 7,974
Property, plant and equipment, net........ 1,040,420 1,121,746 1,349,855 802,018 499,063
Total assets.............................. 1,199,865 1,319,229 1,604,904 1,016,854 576,714
Long-term obligations..................... 328,979 603,205 727,172 544,344 225,938
Preferred stock of subsidiary............. 188,820 188,820 188,820 - -
Total stockholders' equity................ 530,296 410,995 509,584 348,770 295,013
<FN>
- ---------------
(a) Includes amounts relating to the acquisition of Bridge Oil Limited in July
1994 and the acquisition of properties from PG&E Resources Company in
August 1994. See Note D of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data".
(b) Includes amounts relating to the acquisition of certain Prudential-Bache
Energy limited partnerships in July 1993. Also includes results of
operations related to the Company's interest in the Carthage gas processing
plant that had been deferred in 1992 and 1993 and the gain of $7.3 million
recognized on the sale of that interest on June 30, 1993.
(c) Includes noncash pre-tax charges of $130.5 million in 1995 associated with
the adoption of Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of". See Note R of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary
Data".
(d) Includes a gain of $83.3 million in 1996 related to the disposition of
certain wholly-owned subsidiaries. See Note Q of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data".
</FN>
</TABLE>
19
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
General
Operating Performance. The Company reported operating earnings for the year
ended December 31, 1996 of $58.9 million or $1.65 per share. The operating
earnings exclude certain items and their related tax effects described below
under "Financial Performance". Excluding production from the Company's
Australasian assets which were sold in 1996 and production from nonstrategic
domestic assets which were sold in 1995 and 1996, average daily oil production
increased 13% to 29,100 Bbls per day for the year ended December 31, 1996 from
25,718 Bbls per day for the year ended December 31, 1995, and average daily gas
production increased 13% to 193,246 Mcf per day from 170,979 Mcf per day for the
same period. In addition to increased production, the Company's operating
performance for the year ended December 31, 1996 was positively affected by the
following items: (i) improved oil and gas prices, (ii) decreases in production
costs due to certain cost reduction efforts initiated in 1995 and 1996, (iii) a
decrease in oil and gas property depletion expense as a result of significant
increases in the Company's oil and gas reserves during 1995 and 1996, (iv) a
decrease in general and administrative expenses primarily resulting from the
implementation of measures during 1995 intended to reduce overall general and
administrative expenses, and (v) a decrease in interest expense due to a
decrease in the Company's outstanding long-term indebtedness.
Net cash provided by operating activities, before changes in operating
assets and liabilities, increased 39% to $228.5 million for the year ended
December 31, 1996 as compared to $164.2 million for the year ended December 31,
1995. This increase was primarily attributable to improved commodity prices
during 1996, declining production costs due to the improvements made in the
overall cost structure of the Company during 1995 and 1996 and decreased
interest expense due to a decrease in long-term debt.
Long-term debt has been reduced by $265.6 million to $320.9 million at
December 31, 1996 from $586.5 million at December 31, 1995 due principally to
the application of substantially all of the proceeds from the disposition of the
Company's Australasian and certain domestic assets to the Company's outstanding
indebtedness, as described below. Consequently, the Company's long-term debt to
total capitalization has been reduced to 31% at December 31, 1996 from 49% at
December 31, 1995.
Financial Performance. The Company reported net income of $140.2 million
($3.92 per share) for the year ended December 31, 1996 as compared to a net loss
of $99.8 million ($2.83 per share) for the year ended December 31, 1995. Net
income for the year ended December 31, 1996 includes the following after-tax
nonoperating items: (i) aggregate gains of $76.3 million related to the
disposition of the Company's Australasian assets and certain nonstrategic
domestic assets (see "Disposition of Australasian Assets" and "Asset
Dispositions" below), (ii) income of $7.4 million related to the settlement of
several litigation matters involving the Company's Hooker Natural Gas Processing
Plant and related assets (see "Legal Actions" below), (iii) a loss of $2.8
million associated with the write-off of certain tax attributes related to
litigation contingencies that are no longer available and (iv) income of
$400,000 from the operations of the Australian assets and nonstrategic domestic
assets prior to their sale in 1996. Net income for December 31, 1995 includes
the following after-tax nonoperating items: (i) noncash charges of $84.8 million
associated with the adoption of SFAS 121 (as defined in "Depletion Expense"
below), (ii) charges of $6.9 million associated with the amortization of
deferred compensation awarded in 1993 and organizational changes designed to
reduce overall general and administrative expenses, (iii) charges of $4.4
million consisting of previously capitalized financing fees and expenses
associated with certain legal matters, and (iv) net gains of $10.8 million
associated with the disposition of nonstrategic assets (see "Asset Dispositions"
below).
Significant Activities in 1996
Exploration and Development Activities. The Company continues to realize
the benefits of its focused activities in the exploration and development of its
existing core areas. Since completing two major acquisitions in 1994 (see Note D
of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data"), the Company has devoted its efforts to
exploitation and exploration of its existing property base and the Company
believes that substantial additional opportunities remain.
Drilling Activities. As was the case in 1994 and 1995, the Company's 1996
development drilling activities focused primarily on the Company's Permian Basin
oil properties and Gulf Coast gas properties. During 1996, the Company
participated in the drilling and completion of 599 gross exploration and
development wells (482 of which were operated by the Company), including 326 in
the Spraberry Division, 177 in the Permian Division, 48 in the MidContinent
Division, 38
20
<PAGE>
in the Gulf Coast Division and 10 in other areas. The Company's total capital
expenditures during 1996 were $233 million, approximately $212 million of which
was spent on exploration and development activities.
During 1996, the Company announced several discoveries and developments in
domestic locations. In November 1996, the Company announced a significant oil
discovery in the War-Wink West field in the Delaware Basin of West Texas. This
Company operated well, the University 18-34 #1, tested at rates of up to 720
barrels of oil per day and is currently producing at its expected allowable rate
of approximately 270 barrels of oil per day and 374 thousand cubic feet of gas
per day. The Company and Enserch Exploration, Inc. each own a 50% working
interest in this well, which is the first in their joint exploration and
development of the 4,500 acre War-Wink prospect. During 1997, the Company plans
to continue its development of this prospect by drilling two confirmation wells
and an additional two to four development wells. Parker & Parsley and Enserch
also control approximately 30,000 additional acres in the Delaware Basin play in
southeastern New Mexico and West Texas where they intend to drill eight
exploratory wells in 1997. In addition, on November 25, 1996, the Company
announced the successful completion of three development wells in the South
Texas Lopeno field in which the Company owns a 50% working interest. The three
wells, operated by the Company, are currently producing a total of 20 MMcf of
natural gas per day. On December 19, 1996, the Company announced the successful
completion of the S.E. Turner Gas Unit #2 in its Central Texas Gulf Coast Pawnee
field in which the Company owns a 100% working interest. The dual lateral
horizontal unstimulated producer is currently flowing at a rate of 3.1 MMcf per
day. As a result of this successful activity, the Company has identified an
additional six horizontal prospects in the Pawnee field and plans to begin
developmental activity on these prospects in the first quarter of 1997.
During 1996, the Company participated in several discoveries in the
Confluencia Sur field in the Nuequen Basin of Central Argentina in which the
Company owns a 14.42% interest. In early 1996, the Company announced the
successful completion of two exploratory wells (the Naco x-1 and the Sierra de
Reyes x-1) and, in January 1997, the Company announced the successful completion
of three development wells, also in the Confluencia Sur field. The three wells,
the Sierra de Reyes 2, 3 and 4, operated by Petrolera Argentina San Jorge S.A.,
collectively tested 3,727 barrels of oil per day. The Company expects to drill
an additional two to three development wells in the Confluencia Sur field during
the first six months of 1997 in order to increase daily oil production to 6,000
barrels (865 barrels net to the Company's interest).
During 1997, the Company will continue with its emphasis on core
development, exploration and production activities, with a primary focus on the
exploitation of its current portfolio of drilling locations. This portfolio was
significantly enhanced and expanded by the major acquisitions completed in 1994
and the 1995 and 1996 drilling programs which have added a large number of new
locations to which proved reserves have been assigned. The Company believes that
its current portfolio of undeveloped prospects provides attractive development
and exploration opportunities for at least the next three to five years. Of the
total 1997 capital expenditure budget of $270 million, the Company has allocated
$170 million to exploitation activities, $67 million to exploration activities
and $33 million to oil and gas property acquisitions. The Company anticipates
that the $237 million exploration and development budget will be spent by its
operating divisions as follows: $88 million in the Spraberry Division, $45
million in the Permian Division, $45 million in the Gulf Coast Division, $23
million in the MidContinent Division and $36 million in Argentina and other
international areas. This capital expenditure budget reflects the Company's
plans to drill approximately 600 oil and gas wells, over 400 of which will be
drilled in the Spraberry and Permian Divisions. The Company currently expects to
fund its 1997 capital expenditure budget primarily with internally-generated
cash flow.
Proved Reserves. The Company's proved reserves totaled 302.2 million BOE at
December 31, 1996, 296.8 million BOE at December 31, 1995 and 282.5 million BOE
at December 31, 1994. The Company achieved these annual increases in reserves
despite having sold reserves of 45.8 million BOE in 1996 and 34.8 million BOE in
1995. Excluding these sold reserves, total proved reserves increased 21% in 1996
and 28% in 1995. Oil reserves at year-end 1996 were 163.9 million Bbls compared
to 147.3 million Bbls at year-end 1995 and 144.5 million Bbls at year-end 1994
(an 11% increase from 1995 to 1996 and a 2% increase from 1994 to 1995). Natural
gas reserves at year-end 1996 were 829.4 Bcf, compared to 896.9 Bcf at year-end
1995 and 827.5 Bcf at year-end 1994 (an 8% decrease from 1995 to 1996 and an 8%
increase from 1994 to 1995).
Reserve Replacement. For the eighth consecutive year, the Company was able
to replace its annual production volumes with proved reserves of crude oil and
natural gas, stated on an energy equivalent basis. During 1996, the Company
added 75 million BOE resulting in reserve replacement of 314% of total
production. Of the 75 million BOE reserve additions, 71.1 million BOE were added
through exploration and development drilling activities, 2.2 million BOE were
added through acquisitions of proved properties and 1.7 million BOE were the net
result of revisions. Reserves added by development drilling are primarily from
the identification of additional infill drilling locations and new secondary
recovery projects. Reserve revisions result from several factors including
changes in existing estimates of quantities available for production and changes
in estimates of quantities which are economical to produce under current pricing
conditions. The Company's
21
<PAGE>
reserves as of December 31, 1996 were estimated using a price of $24.55 per Bbl
and $3.97 per Mcf. Should prices decline in future years, reserves may be
revised downward for quantities which may be uneconomical to produce at lower
prices.
The Company's 1996 reserve replacement rate on a barrel of oil equivalent
basis was 314%, which included reserve replacement rates for oil and natural gas
of 398% and 239%, respectively. Previous reserve replacement performance rates
were 281% in 1995 (263% for oil and 297% for gas) and 537% in 1994 (549% for oil
and 526% for gas). For the three year period ended December 31, 1996, the three
year average reserve replacement rate was 377%. Through 1994, the Company's
reserve replacement rate was primarily the product of its acquisition
activities. Beginning in 1995, and to a greater extent in 1996, the reserve
replacement rates have been influenced more by exploration and development
activities and less by acquisition activities. The Company seeks to achieve an
annual reserve replacement rate of at least 150% through the emphasis on its
exploration and development activities.
Finding Cost. The Company's acquisition and finding cost for 1996 was $3.10
per BOE as compared to the 1995 and 1994 acquisition and finding costs of $2.87
and $5.11 per BOE, respectively. The average acquisition and finding cost for
the three-year period from 1994 to 1996 was $3.99 per BOE representing an 18%
decrease from the 1995 three-year average rate of $4.84.
Disposition of Australasian Assets. On March 28, 1996, the Company
completed the sale of certain wholly-owned Australian subsidiaries to Santos
Ltd., and on June 20, 1996, the Company completed the sale of another
wholly-owned subsidiary, Bridge Oil Timor Sea, Inc., to Phillips Petroleum
International Investment Company. During the year ended December 31, 1996, the
Company received aggregate consideration of $237.5 million for these combined
sales which consisted of $186.6 million of proceeds for the equity of such
entities, $21.8 million for reimbursement of certain intercompany cash advances,
and the assumption of such subsidiaries' net liabilities, exclusive of oil and
gas properties, of $29.1 million. The proceeds, after payment of certain costs
and expenses, were utilized to reduce the Company's outstanding bank
indebtedness and for general working capital purposes. The Company recognized an
after-tax gain of $67.3 million from the disposition of these subsidiaries. For
additional information, see Note Q of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data".
Cost Reductions. Production costs per BOE declined 5% (from $4.83 to $4.61)
for the year ended December 31, 1996 as compared to the year ended December 31,
1995. This decline is despite a 47% or $.29 per BOE increase in production taxes
resulting from oil and gas prices that were considerably higher in 1996 as
compared to 1995. The significant decline in the remaining components of
production costs, primarily lease operating expense, is the result of the
Company's emphasis on cost control efforts and the disposition of certain high
cost domestic nonstrategic oil and gas properties during 1995 and 1996. During
1995, the Company initiated programs to study specific opportunities for
significant future reductions in its entire cost structure. These programs have
continued in 1996, and the Company expects production costs per BOE to continue
to decline as specific programs for further cost reductions are implemented.
Asset Dispositions. From time to time, the Company disposes of nonstrategic
assets in order to raise capital for other activities, reduce debt or eliminate
costs associated with nonstrategic assets. During the year ended December 31,
1996, the Company sold certain domestic nonstrategic oil and gas properties, gas
plants and other related assets for aggregate proceeds of approximately $58.4
million. The proceeds from the asset dispositions were initially used to reduce
the Company's outstanding bank indebtedness and subsequently to provide funding
for a portion of the Company's 1996 capital expenditures, including purchases of
oil and gas properties in the Company's core areas.
Commodity Prices. The Company benefited from the significantly higher oil
and gas prices during 1996. In 1996, the Company received an average oil price
of $19.96 per Bbl and an average gas price of $2.27 per Mcf representing
increases of 18% and 23%, respectively, from 1995. The oil and gas prices that
the Company reports are based on the market price received for the commodities
adjusted by the results of the Company's hedging activities. The Company
periodically enters into commodity derivative contracts (swaps, futures and
options) in order to (i) reduce the effect of the volatility of price changes on
the commodities the Company produces and sells, (ii) support the Company's
annual capital budgeting and expenditure plans and (iii) lock in prices to
protect the economics related to certain capital projects. During 1996, the
Company's hedging activities reduced the average price received for oil and gas
sales 6% and 5%, respectively, as discussed below.
Natural Gas. The Company employs a policy of hedging gas production based
on the index price upon which the gas is actually sold in order to mitigate the
basis risk between NYMEX prices and actual index prices. The average gas prices
per Mcf that the Company reports includes the effects of Btu content, gathering
and transportation costs, gas processing and shrinkage and the net effect of the
gas hedges. The Company reported an average gas price of $2.27 per Mcf for the
year ended December 31, 1996. The Company's average realized price for physical
gas sales (excluding hedge results) for the
22
<PAGE>
same period was $2.39 per Mcf. The comparable average NYMEX prompt month closing
for the year ended December 31, 1996 was $2.50 per Mcf. At December 31, 1996,
the Company had 28.9 Bcf of future gas production hedged at a weighted average
NYMEX price of $2.17 per Mcf.
Crude Oil. All material purchase contracts governing the Company's oil
production are tied directly or indirectly to NYMEX prices. The average oil
prices per Bbl that the Company reports includes the effects of oil quality,
gathering and transportation costs and the net effect of the oil hedges. The
Company reported an average oil price of $19.96 per Bbl for the year ended
December 31, 1996. The Company's average realized price for physical oil sales
(excluding hedge results) for the same period was $21.33 per Bbl. The comparable
average NYMEX prompt month closing for the year ended December 31, 1996 was
$22.03 per Bbl. At December 31, 1996, the Company had 6.2 million barrels of
future oil production hedged at a weighted average NYMEX price of $19.39 per
Bbl.
See Note N of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for further discussion
concerning the Company's commodities hedging activities.
Capitalization. The Company strives to maintain its outstanding
indebtedness at a moderate level in order to provide sufficient financial
flexibility for future opportunities. The Company's total book capitalization at
December 31, 1996 was $1 billion, consisting of total long-term debt of $326
million, stockholders' equity of $530 million and preferred stock of subsidiary
of $189 million (see Note K of Notes to Consolidated Financial Statements
included in"Item 8. Financial Statements and Supplementary Data" for a
description of the Company's preferred stock of subsidiary). The Company
attempts to maintain a debt to total capitalization ratio of 40% to 45% in order
to achieve its goal of financial flexibility. Debt as a percentage of total
capitalization was 31% at December 31, 1996, down from 49% at December 31, 1995.
This decrease is primarily the result of the application of the net proceeds
from the disposition of the Company's Australian assets and the disposition of
certain other nonstrategic domestic assets described above to the Company's
outstanding indebtedness.
Legal Actions. On August 1, 1996, Dorchester Hugoton, Ltd. ("DHL"), Damson
Master Limited Partnership ("DMLP"), a wholly-owned subsidiary of the Company,
and their related entities entered into a settlement agreement resolving all
outstanding litigation between the parties that had arisen in connection with
DMLP's Hooker Plant, the Hooker Gathering System and certain other matters. The
Company recognized other income of $11.4 million ($7.0 million of which was
received in cash) associated with the settlement of these litigation matters.
Additionally, the Company will receive an annual formula-based production
payment with the first annual payment to begin in February 1997 and to continue
thereafter annually through February 2026. The Company estimates the total value
of the production payments to be at least $5.0 million, although such payments
are dependent on future gas prices and related transportation costs. The
production payments will be recognized as other income over the term of the
production payment contract.
23
<PAGE>
Results of Operations
Oil and Gas Production
The following table describes the results of the Company's oil and gas
production activities during 1996, 1995 and 1994.
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
--------- --------- ---------
(in thousands, except average
price and cost data)
<S> <C> <C> <C>
Revenues:
Oil and gas.............................. $ 396,931 $ 375,720 $ 337,602
Gain on disposition of oil and gas
properties, net (a).................... 7,786 16,847 9,175
-------- -------- --------
404,717 392,567 346,777
-------- -------- --------
Costs and expenses:
Oil and gas production................... 110,334 130,905 127,118
Depletion................................ 102,803 145,468 131,702
Impairment of oil and gas properties..... - 129,745 -
Exploration and abandonments............. 12,653 16,431 12,345
Geological and geophysical............... 9,054 11,121 8,402
-------- -------- --------
234,844 433,670 279,567
-------- -------- --------
Operating profit (loss) (excluding
general and administrative expense
and income taxes)...................... $ 169,873 $ (41,103) $ 67,210
======= ======== ========
- ---------------
(a) The 1996 amount does not include the gain related to the disposition of the
Company's Australasian assets.
Worldwide:
Production:
Oil (MBbls).......................... 11,275 12,902 12,147
Gas (MMcf)........................... 75,851 85,295 79,674
Total (MBOE)......................... 23,916 27,118 25,426
Average daily production:
Oil (Bbls)........................... 30,805 35,348 33,279
Gas (Mcf)............................ 207,244 233,685 218,285
Average oil price (per Bbl)............ $ 19.96 $ 16.96 $ 15.40
Average gas price (per Mcf)............ $ 2.27 $ 1.84 $ 1.89
Costs:
Lease operating expense (per BOE).... $ 3.43 $ 3.99 $ 4.10
Production taxes (per BOE)........... $ .91 $ .62 $ .67
Workover costs (per BOE)............. $ .27 $ .22 $ .23
-------- -------- --------
Total production costs (per BOE)... $ 4.61 $ 4.83 $ 5.00
======== ======== ========
Depletion (per BOE).................. $ 4.30 $ 5.36 $ 5.18
Domestic:
Production:
Oil (MBbls).......................... 10,872 11,328 11,267
Gas (MMcf)........................... 73,924 76,669 75,040
Total (MBOE)......................... 23,193 24,106 23,774
Average daily production:
Oil (Bbls)........................... 29,705 31,036 30,868
Gas (Mcf)............................ 201,979 210,052 205,589
Average oil price (per Bbl)............ $ 19.96 $ 16.70 $ 15.26
Average gas price (per Mcf)............ $ 2.27 $ 1.84 $ 1.89
Costs:
Lease operating expense (per BOE).... $ 3.39 $ 3.97 $ 4.11
Production taxes (per BOE)........... $ .94 $ .70 $ .72
Workover costs (per BOE)............. $ .28 $ .25 $ .25
-------- -------- --------
Total production costs (per BOE)... $ 4.61 $ 4.92 $ 5.08
======== ======== ========
Depletion (per BOE).................. $ 4.25 $ 5.19 $ 5.07
</TABLE>
Oil and Gas Revenues. Revenues from oil and gas operations totaled $396.9
million in 1996, $375.7 million in 1995 and $337.6 million in 1994, representing
a 6% increase from 1995 to 1996 and an 11% increase from 1994 to 1995. The
increase from 1995 to 1996 is primarily attributable to the higher average
prices being received for both oil and gas production and increases in
production due to the Company's successful exploitation and exploration
activities in 1995 and 1996, offset by the decreased production resulting from
the 1996 sale of the Company's Australasian assets and the 1995 and 1996 sales
of certain domestic assets. The average oil price received for the year ended
December 31, 1996 increased 18% (from $16.96 in 1995 to $19.96 in 1996), while
the average gas price received increased 23% (from $1.84 in 1995 to $2.27
24
<PAGE>
in 1996). The increase from 1994 to 1995 is primarily due to (i) a full year of
production in 1995 from properties purchased in 1994 offset by the production
lost from those properties sold in 1995, (ii) an increase in the average oil
price received of 10% (from $15.40 per Bbl in 1994 to $16.96 per Bbl in 1995),
and (iii) the Company's successful development drilling activities during 1994
and 1995, which resulted in increased production in 1995.
Excluding production from the Company's Australasian assets which were sold
in 1996 and production from the nonstrategic domestic assets which were sold in
1995 and 1996, average daily oil production increased 13% from 25,718 Bbls for
the year ended December 31, 1995 to 29,100 Bbls for the year ended December 31,
1996 and average daily gas production increased 13% from 170,979 Mcf to 193,246
Mcf for the same period.
Production Costs. Production costs per BOE decreased in 1996 and 1995 by
approximately 5% and 3%, respectively (from $5.00 in 1994 to $4.83 in 1995 to
$4.61 in 1996). These reductions are primarily due to the Company's concentrated
efforts to evaluate and reduce all operating costs and the sale of certain high
operating cost properties (see "Asset Dispositions" above). The success of these
cost reduction efforts is particularly evident in light of the fact that
production costs per BOE declined in 1996 despite a 47% or $.29 per BOE increase
in average production taxes per BOE resulting from higher commodity prices. The
primary component of production costs, lease operating expense, decreased 14%
from $3.99 per BOE in 1995 to $3.43 per BOE in 1996. These costs represent the
majority of the oil and gas property operating expenses over which the Company
has control and the costs on which the Company has focused its reduction
efforts.
Depletion Expense. Depletion expense per BOE decreased 20% in 1996 and
increased 3% in 1995. The decrease in depletion expense per BOE in 1996 is
primarily the result of the following factors: (i) the significant increase in
oil and gas reserves during 1995 and 1996 resulting from the Company's
exploration and development drilling activities, including revisions, and (ii) a
reduction in the Company's net depletable basis from charges taken in 1995 in
accordance with Statement of Financial Accounting Standards No. 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of" ("SFAS 121") (see "Impairment of Oil and Gas Properties" below). The
increase in depletion expense per BOE during 1995 is primarily the result of
increased depletion rates resulting from the relatively short lives of the
properties acquired as part of the Bridge Oil Limited acquisition, when compared
to the Company's other properties, and the application of such increased rates
to the book basis allocated to the proved oil and gas properties acquired. The
increase in depletion expense from 1994 to 1995 was mitigated by the Company's
adoption of SFAS 121 in 1995 and the significant increase in oil and gas
reserves at December 31, 1995.
Impairment of Oil and Gas Properties. The Company adopted SFAS 121
effective as of April 1, 1995, and, as a result of the review and evaluation of
its long-lived assets for impairment, the Company recognized noncash pre-tax
charges of $129.7 million ($84.3 million after-tax) related to its oil and gas
properties during 1995. See Note B and Note R of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
further explanation of the Company's policies concerning SFAS 121 and its 1995
charge for impairment.
Exploration and Abandonments/Geological and Geophysical Costs. Exploration
and abandonments/geological and geophysical costs increased from $20.7 million
in 1994 to $27.6 million in 1995 and decreased to $21.7 in 1996. The decrease in
1996 is largely the result of decreased activity, both in exploratory drilling
and geological and geophysical activity, resulting from the sale in March 1996
of the Company's Australasian assets (see "Disposition of Australasian Assets"
above and Note Q of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data"), offset by increases in
geological and geophysical activity in the United States as a result of the
Company's increased focus on exploitation and exploration activities. The
increase from 1994 to 1995 is largely the result of increased expenses, both in
exploratory drilling and geological and geophysical costs, brought about by the
Company's continued evaluation of certain domestic and international exploratory
projects acquired as part of the Bridge Oil Limited acquisition. The following
table sets forth the components of the Company's 1996, 1995 and 1994 exploration
and abandonments/geological and geophysical costs:
Year ended December 31,
1996 1995 1994
-------- -------- --------
(in thousands)
Exploratory dry holes:
United States....................... $ 6,256 $ 2,491 $ 523
Australia and other foreign......... 3,431 9,636 3,571
Geological and geophysical costs:
United States....................... 7,042 2,302 3,834
Australia and other foreign......... 2,012 8,819 4,568
Leasehold abandonments and other..... 2,966 4,304 8,251
------- ------- -------
$ 21,707 $ 27,552 $ 20,747
======= ======= =======
25
<PAGE>
Approximately 25% of the Company's 1997 capital budget will be spent on
exploratory projects (compared to 16.7% in 1996 and 13.3% in 1995). The Company
currently anticipates that its 1997 exploration efforts will be concentrated in
the Gulf Coast Division, the Permian Division and its interests in Argentina.
The Company continues to review opportunities involving exploration joint
ventures in domestic or international areas outside the Company's existing core
operating areas.
Natural Gas Processing
Natural gas processing revenues were $23.8 million in 1996, $33.3 million
in 1995 and $39.1 million in 1994; and natural gas processing costs were $12.5
million in 1996, $25.9 million in 1995 and $33.6 million in 1994. The 1996
natural gas processing revenues and costs decreased 29% and 52%, respectively,
when compared to the 1995 amounts primarily due to the sale of four gas plants
during 1995 and the sale of one gas plant during 1996. The 1995 natural gas
processing revenues and costs decreased 15% and 23%, respectively, when compared
to the 1994 amounts primarily as a result of the cancellation of certain gas
processing contracts related to four gas plants during 1994 and the sale of four
plants during 1995. The average price per Bbl of NGLs increased each year, by
30% in 1996 and 6% in 1995 (from $10.97 in 1994 to $11.59 in 1995 to $15.10 in
1996), while the average price per Mcf of residue gas increased by 55% in 1996
and declined by 16% in 1995 (from $1.66 in 1994 to $1.39 in 1995 to $2.15 in
1996).
During January 1996, the Company realized proceeds of $2.1 million from
sales of gas plants and related assets which resulted in the Company recognizing
a net gain of $639 thousand. In addition, in October 1995, the Company sold its
interests in the Cargray and Schafer plants located in Carson County, Texas. The
Company received net proceeds of $9.5 million from the disposition of such
plants which resulted in the Company recognizing a net gain of $4.6 million.
During 1996 and 1994, the Company recognized noncash pre-tax charges of
$1.3 million and $4.5 million, respectively, related to abandonments of certain
of the Company's gas processing facilities and the cancellation of certain gas
processing contracts. Additionally, during 1995, the Company recognized a
noncash pre-tax impairment charge of $748,000 related to a natural gas
processing facility.
General and Administrative Expense
General and administrative expense was $28.4 million in 1996, $37.4 million
in 1995 and $28.9 million in 1994, representing a 24% decrease from 1995 to 1996
and a 29% increase from 1994 to 1995. The decrease from 1995 to 1996 is
primarily due to 1995 including pre-tax charges of $10.6 million associated with
the amortization of deferred compensation awarded in 1993 and organizational
changes implemented by the Company that were designed to reduce overall general
and administrative expenses and 1996 reflecting the benefits of those
organizational changes as well as additional cost reduction efforts in 1996. The
significant increase in general and administrative expense from 1994 to 1995 is
partially attributable to significant nonrecurring general and administrative
expenses included in each year. The 1995 amount includes the nonrecurring items
noted above while the 1994 amount includes $6 million of nonrecurring general
and administrative expenses resulting from the acquisition of Bridge Oil
Limited, some of which were eliminated as the Company consolidated Bridge Oil
Limited's United States operations with its own during the latter part of 1994.
Not only did total general and administrative expense decrease for the year
ended December 31, 1996 as compared to the year ended December 31, 1995, general
and administrative costs per BOE declined significantly as well, from $1.38 per
BOE in 1995 to $1.19 per BOE in 1996, a 14% reduction. This decrease results
from the Company's improvements in operating efficiencies and increases in its
oil and gas production.
Interest Expense
Interest expense was $46.2 million in 1996, $65.4 million in 1995 and $50.6
million in 1994. The decrease from 1995 to 1996 is due to a decrease of $226.3
million in the weighted average outstanding balance of the Company's
indebtedness for the year ended December 31, 1996 as compared to the year ended
December 31, 1995, resulting primarily from the application of proceeds from the
sale of the Company's Australasian assets and the sales of certain domestic
assets during 1995 and 1996, and a decrease in the weighted average interest
rate on the Company's indebtedness from 8.02% in 1995 to 7.83% in 1996. The
increase from 1994 to 1995 was due primarily to (i) an increase of $109.2
million in the weighted average outstanding balance of the Company's
indebtedness due to the additional borrowings required to finance the
acquisition of Bridge Oil Limited and the properties acquired from PG&E
Resources in 1994, (ii) an increase in the weighted average interest rate from
7.15% in 1994 to 8.02% in 1995 and (iii) a full year of interest expense in 1995
versus six months in 1994 associated with certain pre-acquisition obligations of
Bridge Oil Limited. In addition, the 1996, 1995 and 1994 amounts include $12
million, $12 million and $9.1 million of interest, respectively, associated with
the preferred stock of the Company's subsidiary, Parker & Parsley Capital LLC
(see Note K of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data"). The 1996, 1995 and 1994 amounts
also include $1.3 million, $2 million and $2.3 million, respectively, of
amortization of capitalized loan fees.
26
<PAGE>
During each of the years 1996, 1995 and 1994, the Company was a party to
various interest rate swap agreements. As a result, the Company recorded a
reduction in interest expense of $787 thousand for the year ended December 31,
1996 and additional interest expense of $532 thousand and $2.2 million for the
years ended December 31, 1995 and 1994, respectively. For a description of the
Company's interest rate swap agreements, see Note N of the Notes to the
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data".
Income Taxes
The Company's income tax provision of $60.1 million for 1996 and its income
tax benefit of $45.9 million and $6.5 million (both of which exclude the tax
effects related to extraordinary items) for 1995 and 1994, respectively, reflect
the net provision or benefit, resulting from the separate tax calculation
prepared for each tax jurisdiction in which the Company is subject to income
taxes. For 1996, 1995 and 1994 the Company had effective total tax rates of
approximately 30%, 31% and 32%, respectively. In 1996, the effective tax rate is
lower than the applicable tax rate as a result of the tax effects of the 1996
sale of certain of the Company's subsidiaries. The effective tax rates in 1995
and 1994 are lower than the applicable tax rate for each year because the
effective rates reflect the amortization of foreign permanent differences. See
Note S of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for further discussion of the
Company's income tax provision and benefits.
Extraordinary Items
In October 1995, the Company transferred cash and certain oil and gas
properties with an aggregate estimated value of $1.1 million in full
satisfaction of a non-recourse note secured by the properties, the balance of
which was approximately $7.7 million. As a result, the Company recognized an
extraordinary gain on the early extinguishment of debt of $4.3 million (net of
related tax expense of $2.3 million).
In 1994, the Company acquired Bridge Oil Limited (see Note D of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data"), and as a result of this acquisition, the Company assumed
the obligations of certain indentures issued by that company. Upon a change in
control of Bridge Oil Limited, those indentures were redeemable for cash at the
option of the holder at a one percent premium. The majority of the holders chose
to exercise their call option which resulted in the recognizition of an
after-tax loss on early extinguishment of debt of $628 thousand.
Capital Commitments, Capital Resources and Liquidity
Capital Commitments. The Company's primary needs for cash are for
exploration, development and acquisitions of oil and gas properties, repayment
of principal and interest on outstanding indebtedness and working capital
obligations.
The Company's cash expenditures during 1996, 1995 and 1994 for additions to
oil and gas properties (including individual property acquisitions, but not
including company acquisitions) totaled $219.4 million, $215.7 million and
$247.1 million, respectively. The 1996 amount includes $198.4 million for
development and exploratory drilling, and, as in 1994 and 1995, the Company's
drilling activities were focused primarily in the Spraberry field of the Permian
Basin. Significant drilling expenditures in 1996 included $87.1 million in the
unitized portion of the Spraberry field of the Permian Basin (including $46.2
million in the Driver unit, $16.1 million in the Shackelford unit, $7.9 million
in the North Pembrook unit, $4.4 million in the Preston unit and $4.1 million in
the Merchant unit), $18.2 million in other portions of the Spraberry field,
$35.4 million in other areas of the Permian Basin, $31.7 million in the onshore
Gulf Coast region, $14.1 million in the MidContinent region and $11.9 million in
Argentina and Australia (prior to its sale in March 1996). Additions to natural
gas processing facilities during 1996, 1995 and 1994 primarily represented costs
associated with the Company's Spraberry natural gas processing facilities.
The Company's 1997 capital expenditure budget has been set at $270 million,
reflecting planned expenditures of $170 million for exploitation activities, $67
million for exploration activities and $33 million for oil and gas property
acquisitions in the Company's core areas of Texas, Oklahoma, New Mexico and
Louisiana. The Company budgets it capital expenditures based on projected
internally-generated cash flows and routinely adjusts the level of its capital
expenditures in response to anticipated changes in cash flows.
Funding for the Company's working capital obligations is provided by
internally-generated cash flow. Funding for the repayment of principal and
interest on outstanding debt may be provided by any combination of
internally-generated cash flow, proceeds from the disposition of nonstrategic
assets or alternative financing sources as discussed in "Capital Resources"
below.
27
<PAGE>
Capital Resources. The Company's primary capital resources are net cash
provided by operating activities, proceeds from financing activities and
proceeds from sales of nonstrategic assets. The Company expects that these
resources will be sufficient to fund its capital commitments in 1997.
Operating Activities. Net cash provided by operating activities increased
46% in 1996 and 21% in 1995 (from $129.8 million in 1994 to $157.3 million in
1995 to $230.1 million in 1996). These increases are primarily attributable to
stronger oil and gas prices combined with declining production costs due to
improvements in the Company's overall cost structure in 1995 and 1996.
Financing Activities. On July 31, 1996, the Company entered into an Amended
and Restated Credit Agreement, which has a current borrowing base of $350
million. Interest rates on the facility vary depending on the amount
outstanding. The outstanding balance under such Credit Agreement at December 31,
1996 was $9 million leaving approximately $340.1 million of unused borrowing
base immediately available, net of outstanding letters of credit of $872
thousand. The Company, through its subsidiaries, has other long-term
indebtedness, consisting primarily of a $10 million fixed-rate building loan.
The weighted average interest rate for the year ended December 31, 1996 on the
Company's indebtedness was 7.83% as compared to 8.02% for the year ended
December 31, 1995 and 7.15% for the year ended December 31, 1994 (taking into
account the effect of interest rate swaps). See Note E of the Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data".
In October 1996, the Company announced an odd-lot repurchase program for
shareholders who, as of October 7, 1996, individually owned 99 or fewer shares
of Parker & Parsley Petroleum Company Common Stock. The Company purchased a
total of 772,986 shares for $23.3 million which were added to the Company's
shares held in treasury. See Note L of the Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data".
During 1995, the Company completed two public issuances of senior notes.
The aggregate net proceeds from the two senior note issuances of approximately
$295.9 million were utilized to repay a portion of the Company's outstanding
U.S. bank indebtedness. At December 31, 1996, the outstanding balances on the
notes totaled $299.3 million. See Note E of the Notes to the Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data".
During 1994, the Company accessed the capital markets on three occasions:
the issuance of 3,776,400 6 1/4% Cumulative Guaranteed Monthly Income
Convertible Preferred Shares by the Company's wholly-owned special purpose
finance subsidiary in March 1994, which resulted in net proceeds of $182.2
million; the issuance of 2,360,000 shares of common stock in June 1994, which
resulted in net proceeds of approximately $57.6 million; and the issuance of
4,500,000 shares of common stock in November 1994, which resulted in net
proceeds of approximately $107 million. The net proceeds of each of these
offerings were used by the Company to reduce the outstanding balance of its bank
indebtedness.
As the Company continues to pursue its strategy, it may utilize alternative
financing sources, including the issuance for cash of fixed rate long-term
public debt, convertible securities or preferred stock. The Company may also
issue securities in exchange for oil and gas properties, stock or other
interests in other oil and gas companies or related assets. Additional
securities may be of a class preferred to common stock with respect to such
matters as dividends and liquidation rights and may also have other rights and
preferences as determined by the Company's Board of Directors.
On February 12, 1997, the Company completed a shelf registration statement
with the Securities and Exchange Commission, which provides for the issuance of
up to $400 million of common stock, preferred stock, warrants to acquire
preferred stock, depository shares representing fractional interests in
preferred stock, debt securities and warrants to acquire debt securities, or any
combination thereof which the Company may offer from time to time. The $400
million includes $127.9 million which remained unused from a 1994 shelf
registration statement. The net proceeds for any such offering will be used for
general corporate purposes, which may include repayment of indebtedness,
redemption or repurchase of securities of the Company or any subsidiary,
additions to working capital and capital expenditures, including acquisitions
and drilling.
Sales of Nonstrategic Assets. During 1996, 1995 and 1994, proceeds from the
sale of domestic nonstrategic assets totaled $58.4 million, $175.1 million and
$109 million, respectively. In addition, during 1996, the Company sold certain
subsidiaries resulting in cash proceeds of $183.2 million (see Note Q of Notes
to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data"). The proceeds from these sales have primarily been
utilized to reduce the Company's outstanding bank indebtedness and for general
working capital purposes. The Company anticipates that it will continue to sell
nonstrategic properties from time to time to increase capital resources
available for other activities and to achieve administrative efficiencies.
Liquidity. At December 31, 1996, the Company had $18.7 million of cash and
cash equivalents on hand, compared to $19.9 million at December 31, 1995. The
Company's ratio of current assets to current liabilities was 1.29 at December
31, 1996 and 1.28 at December 31, 1995.
28
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Page
Consolidated Financial Statements of Parker & Parsley
Petroleum Company:
Independent Auditors' Report............................... 30
Consolidated Balance Sheets as of December 31, 1996
and 1995................................................. 31
Consolidated Statements of Operations for the Years
Ended December 31, 1996, 1995 and 1994................... 32
Consolidated Statements of Stockholders' Equity for
the Years Ended December 31, 1996, 1995 and 1994......... 33
Consolidated Statements of Cash Flows for the Years
Ended December 31, 1996, 1995 and 1994................... 34
Notes to Consolidated Financial Statements................. 35
Unaudited Supplementary Information........................ 53
29
<PAGE>
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Parker & Parsley Petroleum Company:
We have audited the consolidated financial statements of Parker & Parsley
Petroleum Company and subsidiaries as listed in the accompanying index. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Parker &
Parsley Petroleum Company and subsidiaries as of December 31, 1996 and 1995, and
the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 1996, in conformity with generally
accepted accounting principles.
As discussed in Notes B and R to the consolidated financial statements, the
Company changed its method of accounting for the impairment of long-lived assets
and for long-lived assets to be disposed of in 1995 to adopt the provisions of
the Financial Accounting Standards Board's Statement of Financial Accounting
Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of".
KPMG Peat Marwick LLP
Midland, Texas
January 29, 1997
30
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
<TABLE>
<CAPTION>
ASSETS
December 31,
-------------------------
1996 1995
----------- -----------
<S> <C> <C>
Current assets:
Cash and cash equivalents...................... $ 18,711 $ 19,940
Restricted cash................................ 1,749 15,572
Accounts receivable:
Trade, net................................... 34,075 49,257
Affiliates................................... 434 2,369
Oil and gas sales............................ 48,459 37,358
Assets held for resale......................... - 3,677
Inventories.................................... 3,644 9,880
Deferred income taxes.......................... 7,400 1,600
Other current assets........................... 2,567 2,757
---------- ----------
Total current assets....................... 117,039 142,410
---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful
efforts method of accounting:
Proved properties.......................... 1,419,051 1,450,290
Unproved properties........................ 7,331 14,574
Natural gas processing facilities.............. 59,276 63,395
Accumulated depletion, depreciation and
amortization................................. (445,238) (406,513)
---------- ----------
1,040,420 1,121,746
Restricted investments........................... - 5,345
Other property and equipment, net................ 27,779 31,755
Other assets, net................................ 14,627 17,973
---------- ----------
$ 1,199,865 $ 1,319,229
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt........... $ 5,381 $ 2,608
Distributable litigation settlement............ - 13,633
Undistributed unit purchases................... 1,749 1,939
Accounts payable:
Trade ....................................... 56,713 58,263
Affiliates................................... 7,528 574
Domestic and foreign income taxes.............. 1,743 2,875
Other current liabilities...................... 17,856 31,017
---------- ----------
Total current liabilities.................. 90,970 110,909
---------- ----------
Long-term debt, less current maturities.......... 320,908 586,549
Other noncurrent liabilities..................... 8,071 16,656
Deferred income taxes............................ 60,800 5,300
Preferred stock of subsidiary.................... 188,820 188,820
Stockholders' equity:
Preferred stock, $.01 par value; 20,000,000
shares authorized; none issued and
outstanding.................................. - -
Common stock, $.01 par value; 180,000,000
shares authorized; 36,899,618 and
36,387,960 shares issued at December 31,
1996 and 1995, respectively.................. 369 364
Additional paid-in capital..................... 462,873 452,718
Treasury stock, at cost; 1,833,383 and
1,004,684 shares at December 31, 1996 and
1995, respectively........................... (31,528) (6,844)
Unearned compensation.......................... (1,625) (2,055)
Retained earnings (deficit) ................... 100,207 (36,491)
Cumulative translation adjustment.............. - 3,303
---------- ----------
Total stockholders' equity................. 530,296 410,995
Commitments and contingencies (Note J)
$ 1,199,865 $ 1,319,229
========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
</TABLE>
31
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except share and per share data)
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
---------- ---------- ----------
<S> <C> <C> <C>
Revenues:
Oil and gas................................ $ 396,931 $ 375,720 $ 337,602
Natural gas processing..................... 23,814 33,258 39,149
Gas marketing.............................. - 76,784 102,982
Interest and other......................... 17,458 11,364 6,918
Gain on disposition of assets, net......... 97,140 16,620 9,512
--------- --------- ---------
535,343 513,746 496,163
--------- --------- ---------
Costs and expenses:
Oil and gas production..................... 110,334 130,905 127,118
Natural gas processing..................... 12,528 25,865 33,626
Gas marketing.............................. - 75,664 101,499
Depletion, depreciation and amortization... 112,134 159,058 145,374
Impairment of oil and gas properties and
natural gas processing facilities........ - 130,494 -
Exploration and abandonments............... 23,030 27,552 25,239
General and administrative................. 28,363 37,409 28,948
Interest................................... 46,155 65,449 50,552
Other...................................... 2,451 11,357 4,298
--------- --------- ---------
334,995 663,753 516,654
--------- --------- ---------
Income (loss) before income taxes and
extraordinary item......................... 200,348 (150,007) (20,491)
Income tax benefit (provision)............... (60,100) 45,900 6,500
--------- --------- ---------
Income (loss) before extraordinary item...... 140,248 (104,107) (13,991)
Extraordinary item - gain (loss) on early
extinguishment of debt, net of tax......... - 4,338 (628)
--------- --------- ---------
Net income (loss)............................ $ 140,248 $ (99,769) $ (14,619)
========= ========= =========
Income (loss) per share:
Primary:
Income (loss) before extraordinary item.. $ 3.92 $ (2.95) $ (.47)
Extraordinary item....................... - .12 (.02)
--------- --------- ---------
Net income (loss)........................ $ 3.92 $ (2.83) $ (.49)
========= ========= =========
Fully diluted:
Income (loss) before extraordinary item.. $ 3.47 $ (2.95) $ (.47)
Extraordinary item....................... - .12 (.02)
--------- ---------- ---------
Net income (loss)........................ $ 3.47 $ (2.83) $ (.49)
========= ========== =========
Dividends declared per share................. $ .10 $ .10 $ .10
========= ========= =========
Weighted average shares outstanding......... 35,733,991 35,274,214 30,063,435
========== ========== ==========
The accompanying notes are an integral part of these
consolidated financial statements.
</TABLE>
32
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands)
<TABLE>
<CAPTION>
Additional Unearned Cumulative Total
Common Paid-in Treasury Compen- Retained Translation Stockholders'
Stock Capital Stock sation Earnings Adjustment Equity
------ --------- --------- --------- -------- ---------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1994..... $ 291 $ 278,521 $ (7,409) $ (6,946) $ 84,313 $ - $ 348,770
Common stock issued............ 68 164,546 - - - - 164,614
Exercise of long-term incentive
plan stock options........... - 462 480 - - - 942
Restricted shares awarded...... - 1,492 514 (832) - - 1,174
Tax benefits related to
stock options................ - 300 - - - - 300
Purchase of treasury stock..... - - (373) - - - (373)
Amortization of unearned
compensation................. - - - 2,052 - - 2,052
Net loss....................... - - - - (14,619) - (14,619)
Dividends ($.10 per share)..... - - - - (2,915) - (2,915)
Currency translation
adjustment................... - - - - - 9,639 9,639
----- -------- ------- ------- ------- ------ ---------
Balance at December 31, 1994... 359 445,321 (6,788) (5,726) 66,779 9,639 509,584
----- -------- ------- ------- ------- ------ ---------
Common stock issued............ 2 3,963 - - - - 3,965
Exercise of long-term incentive
plan stock options........... 2 2,065 223 (365) - - 1,925
Restricted shares awarded...... 1 769 - (1,387) - - (617)
Tax benefits related to
stock options................ - 600 - - - - 600
Purchase of treasury stock..... - - (279) - - - (279)
Amortization of unearned
compensation................. - - - 5,423 - - 5,423
Net loss....................... - - - - (99,769) - (99,769)
Dividends ($.10 per share)..... - - - - (3,501) - (3,501)
Currency translation
adjustment................... - - - - - (6,336) (6,336)
----- -------- ------- ------- ------- ------ ---------
Balance at December 31, 1995... 364 452,718 (6,844) (2,055) (36,491) 3,303 410,995
----- -------- ------- ------- ------- ------ ---------
Exercise of long-term incentive
plan stock options........... 5 6,899 - - - - 6,904
Restricted shares awarded...... - 1,091 - (1,199) - - (108)
Restricted shares forfeited.... - (35) (13) 48 - - -
Tax benefits related to
stock options................ - 2,200 - - - - 2,200
Purchase of treasury stock..... - - (24,671) - - - (24,671)
Amortization of unearned
compensation................. - - - 1,581 - - 1,581
Net income..................... - - - - 140,248 - 140,248
Dividends ($.10 per share)..... - - - - (3,550) - (3,550)
Currency translation
adjustment................... - - - - - (3,303) (3,303)
----- -------- ------- ------- ------- ------- ---------
Balance at December 31, 1996... $ 369 $ 462,873 $(31,528) $ (1,625) $100,207 $ - $ 530,296
===== ======== ======= ======= ======= ======= =========
The accompanying notes are an integral part of these
consolidated financial statements.
</TABLE>
33
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
--------- ---------- ----------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss)......................................... $ 140,248 $ (99,769) $ (14,619)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depletion, depreciation and amortization.............. 112,134 159,058 145,374
Impairment of oil and gas properties and natural
gas processing facilities.......................... - 130,494 -
Exploration and abandonments.......................... 17,262 23,500 22,852
Deferred income taxes................................. 57,400 (42,600) (7,150)
Gain on disposition of assets, net.................... (97,140) (16,620) (9,512)
Other noncash items................................... (1,360) 10,132 5,453
-------- -------- --------
228,544 164,195 142,398
Change in operating assets and liabilities,
net of effects from acquisitions and dispositions:
Accounts receivable................................... (2,674) 4,870 11,870
Inventory............................................. 1,842 682 -
Other current assets.................................. (32) 1,146 (2,018)
Accounts payable...................................... (656) (15,712) (5,137)
Accrued income taxes and other current liabilities.... 3,035 2,758 (17,363)
Other................................................... - (683) -
-------- -------- --------
Net cash provided by operating activities.......... 230,059 157,256 129,750
-------- -------- --------
Cash flows from investing activities:
Payment for acquisitions, net of cash acquired............ (190) (1,206) (278,528)
Proceeds from disposition of wholly-owned subsidiaries,
net of cash disposed.................................... 183,181 - -
Proceeds from disposition of assets....................... 58,370 175,085 108,984
Additions to oil and gas properties....................... (219,394) (215,731) (247,124)
Additions to natural gas processing facilities............ (3,407) (6,377) (11,582)
Additions to other property and equipment and other assets (5,021) (5,577) (26,644)
-------- -------- --------
Net cash provided by (used in) investing activities 13,539 (53,806) (454,894)
-------- -------- --------
Cash flows from financing activities:
Borrowings under long-term debt........................... 782 334,458 452,071
Principal payments on long-term debt...................... (222,157) (434,681) (451,176)
Payment of noncurrent liabilities......................... (2,534) (1,588) (10,260)
Issuance of common stock, net............................. - (23) 164,614
Issuance of preferred stock of subsidiary................. - - 188,820
Deferred loan fees/issuance costs......................... (20) (4,121) (10,354)
Dividends................................................. (3,550) (3,501) (2,915)
Purchase of treasury stock................................ (24,671) (279) (373)
Exercise of long-term incentive plan stock options........ 6,904 1,925 942
Distributable litigation settlement - receipts............ 5,290 383 463
Distributable litigation settlement - disbursements....... (18,876) - -
Other ................................................... (108) (114) -
-------- -------- --------
Net cash provided by (used in) financing activities (258,940) (107,541) 331,832
-------- -------- --------
Effect of exchange rate changes on cash and cash equivalents. 290 (299) 671
Net increase (decrease) in cash, cash equivalents
and restricted cash....................................... (15,342) (4,091) 6,688
Cash, cash equivalents and restricted cash, beginning of year 35,512 39,902 32,543
-------- -------- --------
Cash, cash equivalents and restricted cash, end of year...... $ 20,460 $ 35,512 $ 39,902
======== ======== ========
The accompanying notes are an integral part of these
consolidated financial statements.
</TABLE>
34
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
NOTE A. Organization and Nature of Operations
Parker & Parsley Petroleum Company (the "Company"), a Delaware
Corporation whose common stock is listed and traded on the New York Stock
Exchange, was formed in May 1990 and began operations on February 19, 1991, with
the combination and conversion to corporate structure of two partnerships that
were under common control with the Company.
The Company is an oil and gas exploration and production concern with oil
and gas properties principally in the Permian Basin of West Texas, the onshore
Gulf Coast region of South Texas and Louisiana and the Mid-Continent region.
The Company also owns interests in oil and gas properties in Argentina.
NOTE B. Summary of Significant Accounting Policies
Principles of consolidation. The consolidated financial statements
include the accounts of the Company and its majority-owned subsidiaries since
their acquisition or formation and the Company's interest in the affiliated oil
and gas partnerships for which it serves as general partner through certain of
its wholly-owned subsidiaries. Investments in less-than- majority-owned
subsidiaries where the Company has the ability to exercise significant influence
over the investee's operations are accounted for by the equity method;
otherwise, they are accounted for at cost. The Company proportionately
consolidates less-than-100%-owned oil and gas partnerships in accordance with
industry practice. All material intercompany balances and transactions have been
eliminated.
Use of estimates in the preparation of financial statements. Preparation
of the accompanying consolidated 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.
Cash equivalents. For purposes of the Consolidated Statements of Cash
Flows, cash and cash equivalents include cash on hand and depository accounts
held by banks.
Restricted cash at December 31, 1996 includes $1.7 million representing
the Company's remaining obligation to redeem for cash the unconverted limited
partner units in the acquired Prudential-Bache Energy limited partnerships.
Inventories. Inventories consist of lease and well equipment, natural gas
processing plant products and oil in tanks. Lease and well equipment is carried
at the lower of cost (first-in, first-out) or market. Natural gas processing
plant products and oil in tanks are carried at market.
Impairment of long-lived assets. In accordance with Financial Accounting
Standards Board Statement No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"), the Company
reviews its long-lived assets to be held and used, including oil and gas
properties accounted for under the successful efforts method of accounting,
whenever events or circumstances indicate that the carrying value of those
assets may not be recoverable. An impairment loss is indicated if the sum of the
expected future cash flows is less than the carrying amount of the assets. In
this circumstance, the Company recognizes an impairment loss for the amount by
which the carrying amount of the asset exceeds the fair value of the asset.
The Company accounts for long-lived assets to be disposed of at the lower
of their carrying amount or fair value less cost to sell once management has
committed to a plan to dispose of the assets.
Oil and gas properties. The Company utilizes the successful efforts
method of accounting for its oil and gas properties as promulgated by Statement
of Financial Accounting Standards No. 19, "Financial Accounting and Reporting by
Oil and Gas Producing Companies". Under this method, all costs associated with
productive wells and nonproductive development wells are capitalized while
nonproductive exploration costs are expensed. Capitalized costs relating to
proved properties are depleted using the unit-of-production method based on
proved reserves expressed as net equivalent barrels ("BOE") as audited by
independent petroleum engineers with respect to the Company's major properties
and as prepared by the Company's engineers with respect to all other properties.
35
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
Capitalized costs of individual properties abandoned or retired are
charged to accumulated depletion, depreciation and amortization. Proceeds from
sales of individual properties are credited to property costs. No gain or loss
is recognized until the entire amortization base is sold or abandoned.
Costs of significant nonproducing properties, wells in the process of
being drilled and development projects are excluded from depletion until such
time as the related project is developed and proved reserves are established or
impairment is determined. The Company capitalizes interest on expenditures for
significant development projects until such time as significant operations
commence.
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment. A loss is recognized at the time of
impairment by providing an impairment allowance. The remaining unproved oil and
gas properties are aggregated and an overall impairment allowance is provided
based on the Company's historical experience.
Natural gas processing facilities. The Company depreciates its gas
processing, gathering and transmission facilities and equipment on a
straight-line basis over the estimated useful lives of the assets, which range
from 14 to 21 years. Capitalized costs relating to gas contracts, representing
the right to extract liquids and gas, are amortized on a plant-by-plant basis
using the unit-of-production method over the lives of gas reserves expected to
be processed through the facility, as prepared by the Company's engineers. Upon
disposition of a natural gas processing facility, the cost and related
accumulated depreciation and amortization are eliminated from the accounts and
any gain or loss is included in operations.
Treasury stock. Treasury stock purchases are recorded at cost. Upon
reissuance, the cost of treasury shares held is reduced by the average purchase
price per share of the aggregate treasury shares held.
Income taxes. The Company accounts for income taxes in accordance with
the provisions of Statement of Financial Accounting Standards No. 109,
"Accounting for Income Taxes" ("SFAS 109"). Under the asset and liability method
of SFAS 109, deferred tax assets and liabilities are recognized for the future
tax consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Under SFAS 109, the effect
on deferred tax assets and liabilities of a change in tax rate is recognized in
income in the period that includes the enactment date.
The Company and its eligible subsidiaries file a consolidated U.S.
federal income tax return. Certain subsidiaries that are consolidated for
financial reporting purposes are not eligible to be included in the consolidated
U.S. federal income tax return and separate provisions for income taxes have
been determined for these entities or groups of entities.
Income (loss) per share. Primary net income (loss) per share is computed
based on the weighted average number of shares of common stock and common stock
equivalents outstanding during the period. The computation of fully diluted net
income per share for the year ended December 31, 1996 assumes conversion of the
Company's 6-1/4% Cumulative Guaranteed Monthly Income Convertible Preferred
Shares which increased the weighted average number of shares outstanding to 42.6
million. For 1995 and 1994, the computation of fully diluted net income (loss)
per share was antidilutive; therefore, the amounts reported for primary and
fully diluted net income (loss) per share were the same.
Environmental. The Company is subject to extensive federal, state, local
and foreign environmental laws and regulations. These laws, which are constantly
changing, regulate the discharge of materials into the environment and may
require the Company to remove or mitigate the environmental effects of the
disposal or release of petroleum or chemical substances at various sites.
Environmental expenditures are expensed or capitalized depending on their future
economic benefit. Expenditures that relate to an existing condition caused by
past operations and that have no future economic benefits are expensed.
Liabilities for expenditures of a noncapital nature are recorded when
environmental assessment and/or remediation is probable and the costs can be
reasonably estimated.
Revenue recognition. The Company uses the sales method of accounting for
crude oil revenues. To the extent that crude oil is produced but not sold, the
oil in tanks, if material, is recorded as inventory in the accompanying
consolidated financial statements.
36
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
Revenues from natural gas production are generally recorded using the
entitlements method. Sales proceeds in excess of the Company's entitlement are
included in Other liabilities and the Company's share of sales taken by others
is included in Other assets in the accompanying Consolidated Balance Sheets. The
Company did not have a material amount recorded in Other assets or Other
liabilities associated with gas balancing during 1996, 1995 or 1994.
Stock-based compensation. The Company accounts for employee stock-based
compensation using the intrinsic value method prescribed by Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
("APB 25"). Accordingly, the Company has only adopted the disclosure provisions
of Statement of Financial Accounting Standards No.123, "Accounting for
Stock-Based Compensation" ("SFAS 123"). See Note G for the pro forma disclosures
of compensation expense determined under the fair-value provisions of SFAS 123.
Hedging. The financial instruments that the Company accounts for as
hedging contracts must meet the following criteria: the underlying asset or
liability must expose the Company to price or interest rate risk that is not
offset in another asset or liability, the hedging contract must reduce that
price or interest rate risk, and the instrument must be designated as a hedge at
the inception of the contract and throughout the hedge period. In order to
qualify as a hedge, there must be clear correlation between changes in the fair
value of the financial instrument and the fair value of the underlying asset or
liability such that changes in the market value of the financial instrument will
be offset by the effect of price or interest rate changes on the exposed items.
The following is a description of the specific types of hedging transactions in
which the Company participates:
Commodity hedging. The Company periodically enters into commodity
derivative contracts (swaps, futures and options) in order to (i) reduce the
effect of the volatility of price changes on the commodities the Company
produces and sells, (ii) support the Company's annual capital budgeting and
expenditure plans and (iii) lock in prices to protect the economics related to
certain capital projects. Gains and losses on contracts that are designed to
hedge commodities are included in income recognized from the sale of those
commodities. Other commodity futures contracts are valued at market.
Interest rate hedging. The Company enters into interest rate swap
transactions and forward rate lock transactions to hedge its interest rate
exposure. Interest rate swap agreements, in general, involve the exchange of
fixed and floating interest payment obligations with no exchange of the
underlying principal amounts. The interest rate differential to be received or
paid is recognized over the lives of the agreements as an adjustment to interest
expense. Forward rate lock transactions involve selling certain U.S. Treasury
securities at a date certain in the future. The Company uses these transactions
to hedge the interest rates on issuances of obligations in the public bond
market since the obligations' interest rates are determined based on the rate of
the certain U.S. Treasury security at time of issuance of the obligation. The
interest rate differential to be received or paid is recognized in interest
expense over the life of the obligation under the effective interest rate
method.
Foreign currency translation. The financial statements of non-U.S.
entities are translated to U.S. dollars as follows: all assets and liabilities
at year-end exchange rates; revenues, costs and expenses at average exchange
rates. Gains and losses from translating non-U.S. balances are recorded directly
in stockholders' equity. Foreign currency transaction gains and losses are
included in net income (loss).
Reclassifications. Certain reclassifications have been made to the 1995
and 1994 amounts to conform to the 1996 presentation.
37
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
NOTE C. Disclosures About Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair
values of the Company's financial instruments at December 31, 1996 and 1995:
<TABLE>
<CAPTION>
1996 1995
-------------------- --------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
(in thousands)
<S> <C> <C> <C> <C>
Financial assets:
Cash, cash equivalents and restricted
cash $ 20,460 $ 20,460 $ 35,512 $ 35,512
Restricted investments - - 5,345 5,706
Financial liabilities:
Long-term debt:
Practicable to estimate fair value:
Line of credit and GRUF 9,000 9,000 267,000 267,000
8-7/8% senior notes due 2005 150,000 165,945 150,000 167,316
8-1/4% senior notes due 2007 149,277 160,965 149,209 161,995
Not practicable to estimate fair value:
Other long-term debt 18,012 - 22,948 -
Off-balance sheet financial instruments
(see Note N):
Interest rate swaps - 1,782 - -
Commodity price hedges - (35,560) - (2,500)
</TABLE>
Cash and cash equivalents, restricted cash, accounts receivable, other
current assets, accounts payable and other current liabilities. The carrying
amounts approximate fair value due to the short maturity of these instruments.
Restricted investments. The fair value of noncurrent investments is based
on quoted market prices.
Long-term debt. The carrying amount of borrowings outstanding under the
Company's Line of Credit and GRUF (see Note E for definition and description of
each) approximates fair value because these instruments bear interest at rates
tied to current market rates. The fair values of the 8-7/8% senior notes due
2005 and the 8-1/4% senior notes due 2007 were both based on quoted market
prices for these issues.
It was not practicable to estimate the fair value of certain of the
long-term debt obligations because quoted market prices are not available and
the Company does not have a current borrowing rate which could be used as a
comparable rate for the stated maturities of the obligations.
Interest rate swap agreements. At December 31, 1996, the Company had five
interest rate swap agreements outstanding with an aggregate notional amount of
$150 million. These are more fully described in Note N. The fair values of each
of the open interest rate swap agreements were obtained from bank quotes and
represent the estimated amount the Company would receive upon termination of the
agreements at December 31, 1996, taking into consideration interest rates at
that time.
Commodity price hedges. The fair values of commodity price hedges
outstanding at December 31, 1996 and 1995 were obtained from quotes provided by
the individual counterparties for each agreement and represent the amount which
the Company would be required to pay as of December 31 of each of the respective
years, based upon the differential between a fixed and a variable commodity
price as specified in the hedge contracts. As of March 3, 1997, the fair value
of the Company's obligation for commodity price hedges outstanding at December
31, 1996 was $13.1 million. This fair value consists of the following two
components: (i) payments made for swap contracts related to oil and gas
production for the months of January and February 1997 and (ii) the amount the
Company is obligated to pay for swap contracts related to oil and gas production
for the period from March 1997 through April 1999 based upon the differentials
as described above using quotes in effect at March 3, 1997.
38
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
NOTE D. Acquisitions
Acquisition of Bridge Oil Limited. During 1994, the Company completed an
acquisition of the issued and outstanding shares of Bridge Oil Limited. The
acquisition was the result of an unsolicited tender offer that commenced in May
and was completed in September with Bridge Oil Limited becoming a wholly-owned
subsidiary of the Company. The total consideration paid for all outstanding
shares in Bridge Oil Limited and related transaction costs was approximately
$290.6 million.
The acquisition of Bridge Oil Limited, accounted for using the purchase
method, resulted in the following noncash investing activities (in thousands):
Recorded amounts of assets acquired, including
cash acquired of $20,797......................... $ 579,190
Liabilities assumed, including $61,267 of
deferred income taxes............................ (288,555)
---------
Cash paid.......................................... $ 290,635
=========
The liabilities assumed include amounts recorded for litigation and
certain other preacquisition contingencies of Bridge Oil Limited.
Certain of the wholly-owned subsidiaries acquired as part of the Bridge
Oil Limited acquisition were sold in 1996. See Note Q for a description of the
subsidiaries sold.
Property acquisition from PG&E Resources Company. On August 1, 1994, the
Company completed the acquisition of certain oil and gas properties and related
assets from PG&E Resources Company, a subsidiary of Pacific Gas and Electric
Company, for $115.7 million after preliminary purchase price adjustments. The
Company funded the acquisition under the bank credit facility described in Note
E.
Pro forma results of operations. The following table reflects the pro
forma results of operations as though the acquisition of Bridge Oil Limited and
the acquisition of the properties from PG&E Resources Company occurred on
January 1, 1994.
Year ended
December 31,
1994
(in thousands, except
per share data)
(Unaudited)
Revenues........................................... $ 576,060
Loss before extraordinary item..................... $ (25,026)
Loss per share before extraordinary item........... $ (.72)
NOTE E. Long-term Debt
Long-term debt consists of the following:
December 31,
1996 1995
-------- --------
(in thousands)
Line of credit..................................... $ 9,000 $225,000
8-7/8% senior notes due 2005....................... 150,000 150,000
8-1/4% senior notes due 2007 (net of discount)..... 149,277 149,209
Project finance facility........................... - 42,000
Fixed rate building loan........................... 10,121 11,168
Other.............................................. 7,891 11,780
------- -------
326,289 589,157
Less current maturities............................ 5,381 2,608
------- -------
$320,908 $586,549
======= =======
39
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
Maturities of long-term debt at December 31, 1996 are as follows (in
thousands):
1997................................................. $ 5,381
1998................................................. 1,558
1999................................................. 1,315
2000................................................. 3,172
2001................................................. 1,109
Thereafter........................................... 313,754
Line of credit. At December 31, 1996, the Company is party to a Credit
Facility Agreement (as amended and restated, the "Credit Agreement") with a
syndicate of banks (the "Banks"). The Credit Agreement provides for a $350
million senior unsecured revolving line of credit (the "Line of Credit"),
comprised of one facility subject to a borrowing base. On May 15, 1998, the
facility converts to a four-year reducing revolving line of credit, at which
time each Bank's commitment as of that date is automatically and permanently
reduced by 1/16 on each August 15, November 15, February 15 and May 15 beginning
on August 15, 1998 and continuing until the earlier of May 15, 2002 or
termination by the Company pursuant to the Credit Agreement.
The Company's Line of Credit has a current borrowing base of $350
million. The borrowing base is determined by the Banks in their sole discretion
and is redetermined at least annually as of each April utilizing oil and gas
reserve information as of the immediately preceding December 31. In addition,
the Company or a 66-2/3% majority of the Banks can request one additional
redetermination at any time during the year and the Company can request
additional redeterminations upon the payment to the Banks of specified fees.
Advances under the Line of Credit bear interest, at the Company's option,
based on (a) the prime rate of NationsBank of Texas, N.A. ("Prime Rate") (8.25%
at December 31, 1996), (b) a Eurodollar rate (substantially equal to the London
Interbank Offered Rate), adjusted for the reserve requirement as determined by
the Board of Governors of the Federal Reserve System with respect to
transactions in Eurocurrency liabilities ("LIBOR Rate"), or (c) quoted rates
from participating banks under a competitive bid option. Advances that are based
on LIBOR Rate have periodic maturities, at the Company's option, of one, two,
three, six, nine or twelve months. Maturities of greater than three months are
subject to availability of such deposits in the relevant markets. Advances on
the competitive bid have periodic maturities, at the Company's option, of not
less than seven days nor more than 180 days. The interest rates on the LIBOR
Rate advances vary, with the interest rate margin ranging from 25 to 70 basis
points depending on the Company's senior unsecured long-term public debt rating.
The Credit Agreement contains various restrictive covenants and
compliance requirements, which include (a) limiting to $5 million per annum the
sum of annual dividends the Company may declare and pay and the amount of the
Company's capital stock the Company may redeem or purchase; (b) limiting the
incurrence of additional indebtedness; and (c) restrictions as to merger, sale
or transfer of assets and transactions with affiliates without the Banks'
consent.
Senior notes. At December 31, 1996, the following two issuances of senior
indebtedness are outstanding.
8-7/8% senior notes due 2005. $150 million aggregate principal amount
8-7/8% senior notes dated April 12, 1995, due April 15, 2005. Interest on the
8-7/8% senior notes is payable semi-annually on April 15 and October 15 of each
year, commencing October 15, 1995.
8-1/4% senior notes due 2007. $150 million aggregate principal amount
8-1/4% senior notes dated August 22, 1995, due August 15, 2007. These 8-1/4%
senior notes were sold at a discount aggregating $816,000. Interest on the
8-1/4% senior notes is payable semi-annually on February 15 and August 15 of
each year, commencing February 15, 1996.
Both senior note issuances are governed by an Indenture between the
Company and The Chase Manhattan Bank (National Association) dated April 12,
1995. Both senior note issuances are general unsecured obligations of the
Company ranking equally in right of payment with all other senior unsecured
indebtedness of the Company and are senior in right of payment to all existing
and future subordinated indebtedness of the Company. In addition, the Company is
a holding company that conducts all its operations through subsidiaries, and the
senior notes issuances are structurally subordinated to all obligations of its
subsidiaries.
40
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
Project finance facility. The Global Revolving Underwriting Facility (the
"GRUF"), as amended, was originally entered into by Bridge Oil International
Finance Limited as borrower and a syndicate of banks on December 19, 1986. The
GRUF was outstanding at December 31, 1995 and, at that time, had a scheduled
maturity date of June 30, 1997. As part of the sale of certain wholly-owned
Australian subsidiaries on March 28, 1996, the buyer of such subsidiaries
assumed the GRUF obligations.
Fixed rate building loan. In March 1994, the Company entered into a
12-year, $13 million fixed rate loan to finance the acquisitions of two office
buildings in Midland, Texas. One of the office buildings was acquired from an
affiliated partnership of which the Company was a 42.5% limited partner. This
building is also the Company's headquarters. The loan is payable in monthly
principal payments of $87,250 plus interest at the rate of 7.9% beginning April
7, 1994 and continuing until the final maturity of August 4, 2006. Security for
the loan consists of first lien deeds of trust on the two buildings, collateral
assignments of all rents and leases related to the two buildings and security
interests in all contracts and fixed assets of the borrower that are related to
the buildings.
Extraordinary item. In October 1995, the Company transferred cash and
certain oil and gas properties with an aggregate estimated value of $1.1 million
in full satisfaction of a non-recourse note secured by the properties, the
balance of which was approximately $7.7 million As a result, the Company
recognized an extraordinary gain on the early extinguishment of debt of $4.3
million (net of related tax expense of $2.3 million).
Interest expense. The following amounts have been charged to interest
expense for the years ended December 31, 1996, 1995 and 1994:
1996 1995 1994
-------- -------- --------
(in thousands)
Cash payments for interest.................... $ 44,405 $ 59,767 $ 41,933
Cash payments for commitment and agency fees.. 804 1,650 1,265
Accretion of discounts on loans............... 261 617 402
Amortization of capitalized loan fees......... 1,286 2,022 2,308
Net change in accruals........................ (601) 1,393 4,644
------- ------- -------
$ 46,155 $ 65,449 $ 50,552
======= ======= =======
The above amounts include $12 million in 1996, $12 million in 1995 and
$9.1 million in 1994 associated with the 6- 1/4% Cumulative Guaranteed Monthly
Income Convertible Preferred Shares of the Company's wholly-owned finance
subsidiary (see Note K).
NOTE F. Related Party Transactions
Activities with affiliated partnerships. The Company, through its
wholly-owned subsidiaries, has in the past sponsored certain affiliated
partnerships, including thirty-five public and nine private drilling
partnerships and three public income partnerships, all of which were formed
primarily for the purpose of drilling and completing wells or acquiring
producing properties. In accordance with the terms of the partnership agreements
and the related tax partnership agreements of the affiliated partnerships, the
Company participated in the activities of the sponsored partnerships on a
promoted basis. In 1992, the Company discontinued sponsoring public and private
oil and gas development drilling and income partnerships.
During each of 1994, 1993 and 1992, the Company formed a Direct
Investment Partnership for the purpose of permitting selected key employees to
invest directly, on an unpromoted basis, in wells that the Company drills. The
partners in the Direct Investment Partnerships formed in 1994, 1993 and 1992 pay
and receive approximately .337%, 1.5375% and 1.865%, respectively, of the costs
and revenues attributable to the Company's interest in the wells in which such
Direct Investment Partnership participates. The Company discontinued the
formation of Direct Investment Partnerships in 1995.
The Company, through certain wholly-owned subsidiaries, serves as
operator of properties in which it and its affiliated partnerships have an
interest. Accordingly, the Company receives producing well overhead, drilling
well overhead and other fees related to the operation of the properties. The
affiliated partnerships also reimburse the Company for their allocated share of
general and administrative charges.
41
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
The activities with affiliated partnerships are summarized for the
following related party transactions for the years ended December 31, 1996, 1995
and 1994:
1996 1995 1994
------ ------ ------
(in thousands)
Receipt of lease operating and supervision charges
in accordance with standard industry operating
agreements.......................................... $8,484 $8,458 $8,556
Reimbursement of general and administrative expenses.. 1,246 1,153 1,143
NOTE G. Long-term Incentive Plan
During 1991, the Company's stockholders approved a long-term incentive
plan (the "Long-term Incentive Plan"), which provides for the granting of
incentive awards in the form of stock options, stock appreciation rights,
performance units, restricted stock and cash to certain directors, officers and
key employees of the Company. The Long-term Incentive Plan provides for the
issuance of a maximum number of shares of common stock equal to 10% of the total
shares outstanding.
The following table summarizes the cumulative stock and option awards
granted by the Company and the shares or options available for future grant
under the Company's Long-term Incentive Plan at the end of 1996 and 1995:
For the year ended
December 31,
1996 1995
--------- ---------
Cumulative shares/options granted, beginning of year 2,766,069 2,234,616
Shares/options granted 672,380 548,117
Shares/options forfeited (36,980) (16,664)
--------- ---------
Cumulative shares/options granted, end of year 3,401,469 2,766,069
--------- ---------
Maximum shares/options allowed under Long-term
Incentive Plan 3,506,624 3,538,328
--------- ---------
Shares/options available for future grant at end of year 105,155 772,259
========= =========
Directors
Under the Company's Long-term Incentive Plan, each non-employee director,
upon commencement of service as a director, is eligible to receive $125,000 of
Company common stock. The price used to calculate the number of shares to be
awarded is generally equal to the average trading price of the Company's common
stock during the 60 days immediately preceding the award. The shares awarded are
subject to vesting and transfer restrictions that lapse with respect to
one-third of the shares six months after the award, another one-third of the
shares one year after the award and the remaining one-third of the shares two
years after the award. The vesting of ownership and lapse of the transfer
restrictions may be accelerated in the event of the death, disability or
retirement of the director or a change in control of the Company. The Long-term
Incentive Plan requires each non-employee director to make an election under the
Internal Revenue Code to include the value of the stock in his income in the
year of grant and provides for a cash award to the non-employee director in an
amount sufficient to pay the federal income taxes due with respect to the award
and such cash payment. During 1995, there were two new directors elected to the
Board of Directors each of whom received a grant of 6,528 shares of restricted
stock. No such awards were made during 1996 or 1994.
Officers and Key Employees
Restricted stock awards. The Company's policy is to pay any annual
bonuses awarded to selected officers and key employees partially in cash and
partially in the form of restricted stock awards under the Long-term Incentive
Plan. Prior to 1996, annual bonuses, if awarded, were paid one-half in cash and
one-half in the form of restricted stock awards. In 1996, target bonus levels
were established for each officer and key employee. Based upon Company and
individual performance during the year, each officer or key employee has the
potential to earn more or less than their target bonus level. Beginning in 1996,
the bonus awards are determined in the quarter following the Company's December
31 year-end. Any restricted
42
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
stock awarded pursuant to this program will be limited to one-half of each
officer's or key employee' s target bonus level, and the remainder of the
officer's or key employee's annual bonus will be paid in cash. The number of
shares of restricted stock that are awarded pursuant to the annual bonus program
is based on the closing sales price of the Company's common stock on the day
immediately preceding the date of the award. Ownership of the restricted stock
awarded vests six months after the date it is issued but is subject to transfer
restrictions that lapse on one-third of the shares on each of the first, second
and third anniversaries of the date of grant. Each recipient of restricted stock
also receives an amount of cash equal to the estimated federal income taxes
payable as a result of the receipt of such award. On February 13, 1997, the
Company awarded an aggregate of 29,872 shares of restricted stock at a price of
$30.125 pursuant to the 1996 annual bonus program. The Company did not award any
restricted stock under the annual bonus program in 1995. In 1994, the Company
awarded an aggregate of 46,776 shares of restricted stock pursuant to this
annual bonus program.
During 1996, 1995 and 1994, the Company has made other incentive awards
of 35,080 shares, 20,778 shares and 29,418 shares of restricted stock,
respectively, to certain officers and key employees. The shares awarded are
subject to a vesting period and transfer restrictions.
The following table reflects the outstanding restricted stock awards and
activity related thereto for 1996, 1995 and 1994:
<TABLE>
For the year ended For the year ended For the year ended
December 31, 1996 December 31, 1995 December 31, 1994
-------------------- -------------------- --------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Shares Price of Shares Price of Shares Price
--------- -------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Restricted stock awards:
Restricted shares outstanding
at beginning of year........ 225,244 $ 23.90 476,034 $ 24.46 424,018 $ 24.15
Shares granted.............. 35,080 $ 26.54 33,834 $ 19.21 78,259 $ 24.19
Shares forfeited............ (1,980) $ 25.13 - $ - - $ -
Lapse of restrictions....... (178,525) $ 24.65 (284,624) $ 24.28 (26,243) $ 18.58
--------- --------- ---------
Restricted shares outstanding
at end of year.............. 79,819 $ 23.35 225,244 $ 23.90 476,034 $ 24.46
========= ========= =========
</TABLE>
Stock options awards. The Company also has an annual stock option award
program for selected key employees and officers. This program provides for
annual awards at an exercise price based on the closing sales price of the
Company's common stock on the date of grant, a three-year vesting schedule and a
five-year exercise period.
The Company applies APB 25 and related Interpretations in accounting for
its stock option awards. Accordingly, no compensation expense has been
recognized for its stock option awards. If compensation expense for the stock
option awards had been determined consistent with SFAS 123, the Company's net
income (loss) and net income (loss) per share would have been adjusted to the
pro forma amounts indicated below:
For the year ended
December 31,
1996 1995
-------- --------
(in thousands, except per
share amounts)
Net income (loss): $139,301 $(99,891)
Primary net income (loss) per share: $ 3.90 $ (2.83)
Fully diluted net income (loss) per share: $ 3.43 $ (2.83)
The pro forma net income (loss) and pro forma net income (loss) per share
amounts noted above are not likely to be representative of the pro forma amounts
to be reported in future years. The pro forma amounts for 1996 and 1995 reflect
the initial phase-in of SFAS 123 and as a result do not reflect any compensation
expense for options granted prior to 1995. Pro forma adjustments in future years
will include compensation expense associated with the options granted in 1995
and 1996 plus compensation expense associated with any options awarded in future
years. As a result, such proforma compensation expense is likely to be higher
than the levels experienced in 1995 and 1996.
43
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
Under SFAS 123, the fair value of each stock option grant is estimated on
the date of grant using the Black-Scholes option pricing model with the
following weighted average assumptions used for grants in 1996 and 1995:
1996 1995
-------- --------
Risk-free interest rate 6.18% 6.06%
Expected life 4 years 4 years
Expected volatility 32% 35%
Expected dividend yield .34% .52%
A summary of the Company's stock option plan as of December 31, 1996,
1995 and 1994, and changes during the years ended on those dates is presented
below:
<TABLE>
For the year ended For the year ended For the year ended
December 31, 1996 December 31, 1995 December 31, 1994
-------------------- -------------------- --------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Shares Price of Shares Price of Shares Price
--------- -------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Non-statutory stock options:
Outstanding at beginning of year 1,230,411 $ 17.51 924,075 $ 15.39 859,627 $ 13.68
Options granted............... 637,300 $ 29.52 514,283 $ 19.23 144,000 $ 24.33
Options forfeited............. (35,000) $ 23.81 (16,664) $ 26.18 (4,833) $ 19.99
Options exercised............. (470,082) $ 14.55 (191,283) $ 10.97 (74,719) $ 12.42
--------- --------- ---------
Outstanding at end of year...... 1,362,629 $ 24.04 1,230,411 $ 17.51 924,075 $ 15.39
========= ========= =========
Exercisable at end of year...... 358,177 $ 18.79 616,591 $ 14.89 665,676 $ 12.65
========= ========= =========
Weighted average fair value of
options granted during the year. $ 10.03 $ 6.71
======== ========
</TABLE>
The following table summarizes information about the Company's stock
options outstanding at December 31, 1996:
<TABLE>
Options Outstanding Options Exercisable
--------------------------------------------------- ------------------------------------
Number Weighted Average Weighted Weighted
Range of Outstanding at Remaining Average Number Exercisable Average
Exercise Prices December 31, 1996 Contractual Life Exercise Price at December 31, 1996 Exercise Price
- --------------- ----------------- ---------------- -------------- -------------------- --------------
<S> <C> <C> <C> <C> <C>
$ 6 - 15 138,390 4.0 years $ 13.16 138,390 $ 13.16
$ 19 - 27 605,239 4.6 years $ 20.68 215,287 $ 22.17
$ 29 - 31 619,000 5.0 years $ 29.75 4,500 $ 30.17
--------- -------
1,362,629 358,177
========= =======
</TABLE>
Loans. During 1995, the Compensation Committee approved loans aggregating
$870,000 to certain officers of the Company and its subsidiaries to fund option
exercises for and open market purchases of Company common stock. Each loan
provides that one-third of the principal and all accrued interest will be deemed
paid on each of the first three anniversaries of the loan if the officer has
continued as an employee of the Company through that date.
Retirement plan. Effective January 1, 1996, the Compensation Committee
approved a deferred compensation retirement plan for the officers of the
Company. Each officer is allowed to contribute up to 25% of their base salary.
The Company will then provide a matching contribution of 100% of the officer's
contribution limited to the first 10% of the officer's base salary. The
Company's matching contribution vests immediately. A trust fund has been
established by the Company to accumulate the contributions made under this
retirement plan. The Company does not have a defined benefit retirement plan.
The Company recognized $1.9 million, $7.7 million and $4.1 million in
compensation expense related to its Long-term Incentive Plan during 1996, 1995
and 1994, respectively.
44
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
NOTE H. Non-Employee Director Equity Compensation Plan
During 1994, the Company authorized and adopted a Non-Employee Director
Equity Compensation Plan (the "Director Plan"), which was approved by the
Company's stockholders. Pursuant to the Director Plan, on the last business day
of the month in which the annual meeting of the stockholders of the Company is
held, each non-employee director will automatically receive an award of Common
Stock equal to 50% of the then current annual retainer fee (which was $40,000
for 1996, 1995 and 1994). This award is made in lieu of an amount of cash equal
to 50% of the annual retainer fee. The number of shares included in each such
award is determined by dividing 50% of the annual retainer fee by the closing
sales price of the Company's common stock on the business day immediately
preceding the date of the award. On May 31, 1996, each non-employee director
received an award of 812 shares of common stock (which number was calculated by
dividing $20,000 by $24.625, the closing sales price of the common stock on May
30, 1996). On June 30, 1995, each non-employee director received an award of
1,025 shares of common stock (which number was calculated by dividing $20,000 by
$19.50, the closing sales price of the common stock on June 29, 1995). On May
31, 1994, each non-employee director received an award of 816 shares of common
stock (which number was calculated by dividing $20,000 by $24.50, the closing
sales price of the common stock on May 27, 1994).
When issued, the shares of common stock awarded pursuant to the Director
Plan are subject to transfer restrictions that lapse on the first anniversary of
the date of the award. In addition, if a non-employee director's services as a
director of the Company are terminated for any reason before the next annual
meeting of the Company's stockholders, a portion of the shares are forfeited,
with the number of forfeited shares being based on the number of regularly
scheduled meetings of the Board of Directors remaining to be held before the
next annual meeting of the Company's stockholders.
NOTE I. Rights Agreement
During 1991, the Company distributed a dividend of one common share
purchase right ("Right") for each share of common stock then outstanding. A
Right was or will be distributed for each share of common stock that was or will
be issued subsequent to February 19, 1991 until the occurrence of the earlier of
the Distribution Date (herein defined), the redemption of the Rights or the
expiration of the Rights on February 19, 2001. Initially, each Right entitles
the registered holder to purchase from the Company one share of common stock at
a price per share of $52.50, subject to adjustment. The Rights are attached to
all certificates representing shares of common stock outstanding, and no
separate certificates representing the Rights will be distributed to
stockholders until the earlier of (a) 10 days following a public announcement
that (1) a person or group acquires 20% or more of the outstanding shares of
common stock or (2) a person or group holding 10% of the common stock is
determined to have intentions and actions adverse to the best interest of the
Company (an "Adverse Person") (persons in (1) or (2), an "Acquiring Person") or
(b) 10 business days following the commencement of a tender offer or exchange
offer that would result in a person or group beneficially owning 20% or more of
the outstanding shares of common stock (the "Distribution Date"). The Rights are
not exercisable until the Distribution Date and will expire on February 19,
2001, unless earlier redeemed by the Company. If at any time following the
Rights Distribution Date (a) the Company is a surviving corporation in a merger
or combination with an Acquiring Person and the shares of common stock remain
outstanding and are not changed or exchanged, (b) a person becomes the
beneficial owner of 20% or more of the then outstanding shares of common stock,
(c) an Acquiring Person engages in one or more "self-dealing" transactions as
set forth in the rights agreement governing the Rights or (d) a person is
determined to be an Adverse Person, each holder of a Right then will have the
right to receive, upon exercise, common stock (or, in certain circumstances,
cash, property or other securities of the Company or an acquiring company)
having a value equal to two times the exercise price of the Right. Thereafter,
in general, all Rights that are beneficially owned by an Acquiring Person will
be void. In the event that, at any time following the date that a person has
become an Acquiring Person, (i) the Company is acquired in a merger or other
combination transaction in which the Company is not the surviving entity, (ii)
the Company consolidates with or merges with or into any other person pursuant
to which the Company is the surviving entity but all or a part of the shares of
common stock are changed into or exchanged for stock of another person or cash
or other property or (iii) 50% or more of the Company's assets or earning power
is sold or transferred, each holder of a Right (except Rights that previously
have been voided as described above) shall thereafter have the right to receive,
upon exercise, common stock or other securities of the acquiring company having
a value equal to two times the exercise price of the Right. The Company may
redeem the Rights in certain circumstances. Until a Right is exercised, the
holder of the Right, as such, will have no rights as a stockholder of the
Company, including the right to vote or to receive dividends.
45
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
NOTE J. Commitments and Contingencies
Severance agreements. On January 1, 1996, the Company entered into
severance agreements with its officers to replace their employment agreements
that expired at the end of 1995. Salaries and bonuses for the Company's officers
are set by the Compensation Committee of the Company's Board of Directors (the
"Committee") independent of this severance agreement, and the Committee can
grant increases or reductions to base salary at its discretion. The current
annual salaries for the officers covered under such severance agreements total
approximately $3.5 million.
Either the Company or the officer may terminate the officer's employment
under the severance agreement at any time. The Company must pay the officer an
amount equal to one year's base salary if employment is terminated because of
death, disability, or normal retirement. The Company must pay the officer an
amount equal to one year's base salary and continue health insurance for the
officer and his immediate family for one year if the Company terminates
employment without cause or if the officer terminates employment with good
reason, which occurs when reductions in the officer's base annual salary exceed
specified limits or when the officer's responsibilities have been significantly
reduced. If within one year after a change of control of the Company, the
Company terminates the officer without cause or if the officer terminates
employment with good reason, the Company must pay the officer an amount equal to
2.99 times the sum of the officer's base salary plus target bonus for the year
and continue health insurance for the officer and his immediate family for one
year. If the officer terminates employment with the Company without good reason
between six months and one year after a change in control, or at any time within
one year after a change in control if the officer is required to move, then the
Company must pay the officer one year's base salary and continue health
insurance for the officer and his immediate family for one year. Officers are
also entitled to additional payments for certain tax liabilities that may apply
to severance payments following a change of control.
Indemnifications. The Company has indemnified its directors and certain
of its officers, employees and agents with respect to claims and damages arising
from acts or omissions taken in such capacity, as well as with respect to
certain litigation.
Legal actions. The Company is party to various legal actions incidental
to its business. These lawsuits primarily involve claims for damages arising
from oil and gas leases and ownership interest disputes. The Company believes
that the ultimate disposition of these legal actions will not have a material
adverse effect on the Company's consolidated financial position, liquidity,
capital resources or future results of operations. The Company will continue to
evaluate its litigation matters on a quarter-by-quarter basis and will adjust
the litigation reserve as appropriate to reflect the then current status of its
litigation.
Lease agreements. The Company leases equipment and office facilities
under noncancellable operating leases on which rental expense for the years
ended December 31, 1996, 1995 and 1994 was approximately $2.9 million, $3.6
million and $1.5 million, respectively. Future minimum lease commitments under
noncancellable operating leases at December 31, 1996 are as follows (in
thousands):
1997....................................................... $ 3,304
1998....................................................... 2,419
1999....................................................... 1,432
2000....................................................... 835
2001....................................................... 458
Thereafter................................................. 1,132
Crude oil purchase agreements. On September 23, 1996, the Company and
Basis Petroleum, Inc. (formerly Phibro Energy, Inc.) entered into an agreement
that supersedes the prior crude oil purchase agreement and memorandum of
agreement between the parties. On November 25, 1996, the Company consented to
the assignment of the agreement to Genesis Crude Oil, L.P. ("Genesis"), a
limited partnership formed by Basis Petroleum, Inc. and Howell Corporation. The
price to be paid by Genesis for oil purchased under the agreement ("Genesis
Agreement") is to be competitive with prices paid by other substantial
purchasers in the same areas who are significant competitors of Genesis. The
price to be paid for oil purchased under the Genesis Agreement includes a
market-related bonus that may vary from month to month based upon spot oil
prices at various commodity trade points. The term of the Genesis Agreement is
through June 30, 1998, and it may continue thereafter subject to termination
rights afforded each party. Salomon, Inc., the parent company of Basis
Petroleum,
46
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
Inc. and a subordinated limited partner in Genesis, secures the payment
obligations under the Genesis Agreement with a $25 million payment guarantee.
Certain properties acquired from Mobil Oil Corporation ("Mobil") are
subject to a call on crude oil production (the "Mobil Call Option"). The Mobil
Call Option provides a continuing option, but no obligation, for Mobil to
purchase all crude oil produced from those properties. The purchase price that
Mobil must pay for production purchased pursuant to the Mobil Call Option is the
average of the daily prices as posted by specified crude oil purchasers,
including Mobil, during the month of delivery without reduction for
transportation fees or other penalties. Regardless of these pricing provisions,
if the Company has a bona fide purchase offer from a third party under a
contract with at least a six-month term that the Company desires to accept, the
price Mobil must pay is the price under that offer for that term. If Mobil
elects not to match the third-party price for the term, the Company may sell the
production to the third party for that term.
NOTE K. Preferred Stock of Subsidiary
On March 29, 1994, Parker & Parsley Capital LLC ("P&P Capital"), a
limited life company organized under the laws of the Turks and Caicos Islands
and a wholly-owned finance subsidiary of the Company, issued 3,776,400 shares of
6-1/4% Cumulative Guaranteed Monthly Income Convertible Preferred Shares (the
"Preferred Shares") with a liquidation preference of $50 per share. The
proceeds, net of issuance costs, from the sale of the Preferred Shares was
approximately $182.2 million. During 1996, 1995 and 1994, the Company recorded
$12 million, $12 million and $9.1 million, respectively, of interest expense
associated with the Preferred Shares.
Dividends on the Preferred Shares are payable in United States dollars at
an annual rate of 6-1/4% of the liquidation preference and are payable monthly
in arrears on the last day of each calendar month. Each Preferred Share is
convertible at the option of the holder at any time, unless previously redeemed
or exchanged, into the Company's common stock at the rate of 1.7778 shares of
common stock for each Preferred Share, subject to adjustment in certain
circumstances. On or after April 1, 1997, the Preferred Shares are subject to
exchange in whole or in part at the Company's option, for the number of shares
of common stock into which the Preferred Shares are convertible, so long as the
closing price for the common stock equals or exceeds 125% of the then applicable
conversion price during certain periods and certain other conditions are
satisfied. The Preferred Shares are redeemable, at the option of P&P Capital, in
whole or in part, from time to time on or after April 1, 1997, at an initial
redemption price of $52.1875 per share and declining ratably thereafter to $50
per share on and after April 1, 2004, plus, in each case, accumulated and unpaid
dividends to the date fixed for redemption, but only if certain conditions are
satisfied. The Preferred Shares are subject to mandatory redemption on the 30th
anniversary of the date of original issuance. The Preferred Shares are also
subject to exchange, in whole but not in part, on a share-for-share basis, into
Series A Convertible Preferred Stock of the Company (the "Company Preferred
Stock") at the option of the holders of a majority of all outstanding Preferred
Shares upon the occurrence of certain events. The Company Preferred Stock will
have dividend, optional conversion, liquidation preference and optional
redemption features substantially identical to the Preferred Shares but will not
be subject to mandatory redemption.
NOTE L. Odd-Lot Repurchase Program
In October 1996, the Company announced an odd-lot repurchase program for
shareholders who, as of October 7, 1996, individually owned 99 or fewer shares
of Parker & Parsley Petroleum Company Common Stock. The Company purchased a
total of 772,986 shares, associated with approximately 25,000 shareholder
accounts, and such shares were added to the Company's shares held in treasury.
The shares were purchased at an average price of $30.17 per share which
represented the average of the five highest closing market prices as reported by
the New York Stock Exchange from October 8, 1996 through November 22, 1996, less
a processing fee of seventy-five cents per share. The accompanying Consolidated
Statements of Cash Flows for the year ended December 31, 1996, includes $23.3
million of treasury stock repurchases related to this program.
NOTE M. Equity Offerings
On November 7, 1994 and June 30, 1994, the Company completed public
offerings of 4.5 million and 2.36 million shares of common stock, respectively,
at a price of $25.00 per share and $25.25 per share, respectively. Aggregate net
proceeds of the offerings were $164.6 million.
47
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
NOTE N. Derivative Financial Instruments
The Company has only limited involvement with derivative financial
instruments and does not use them for trading purposes. They are used to manage
well-defined interest rate and commodity price risks. The Company is exposed to
credit losses in the event of nonperformance by the counterparties to its
interest rate swap agreements and its commodity hedges. The Company anticipates,
however, that such counterparties will be able to fully satisfy their
obligations under the contracts. The Company does not obtain collateral or other
security to support financial instruments subject to credit risk but monitors
the credit standing of the counterparties.
Interest rate swap agreements. At December 31, 1996, the Company was a
party to a series of interest rate swap agreements for an aggregate amount of
$150 million with four counterparties. These agreements, which have a term of
three years, effectively convert a portion of the Company's fixed-rate
borrowings into floating-rate obligations. The weighted average fixed rate being
received by the Company over the term of these agreements is 6.62% while the
weighted average variable rate being paid by the Company for the year ended
December 31, 1996 is 5.56%. The variable rate will be redetermined approximately
every six months based upon the London interbank offered rate at that point in
time. The accompanying Consolidated Statements of Operations for the year ended
December 31, 1996 includes a reduction in interest expense of $787 thousand to
account for the settlement of these interest rate swap agreements.
Commodity hedges. The Company utilizes various swap and option contracts
to (i) reduce the effect of the volatility of price changes on the commodities
the Company produces and sells, (ii) support the Company's annual capital
budgeting and expenditure plans and (iii) lock in prices to protect the
economics related to certain capital projects.
Natural Gas. The Company employs a policy of hedging gas production based
on the index price upon which the gas is actually sold in order to mitigate the
basis risk between NYMEX prices and actual index prices. The following table
sets forth the Company's outstanding gas swap contracts as of December 31, 1996.
Prices included herein represent the Company's weighted average index price per
MMBtu and, as an additional point of reference, the weighted average price for
the portion of the Company's gas which is hedged based on NYMEX.
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- -------
Gas production:
1997 - Swap Contracts
Volume (Bcf) 8.5 6.0 2.9 2.6 20.0
Index price per MMBtu $ 2.04 $ 2.01 $ 1.89 $ 1.86 $ 1.98
NYMEX price per MMBtu $ 2.29 $ 2.27 $ 2.15 $ 2.03 $ 2.23
1998 - Swap Contracts
Volume (Bcf) 2.5 1.8 1.4 1.4 7.1
Index price per MMBtu $ 1.86 $ 1.86 $ 1.86 $ 1.86 $ 1.86
NYMEX price per MMBtu $ 2.03 $ 2.03 $ 2.03 $ 2.03 $ 2.03
1999 - Swap Contracts
Volume (Bcf) 1.4 .4 - - 1.8
Index price per MMBtu $ 1.86 $ 1.86 $ - $ - $ 1.86
NYMEX price per MMBtu $ 2.03 $ 2.03 $ - $ - $ 2.03
The Company reports average gas prices per Mcf including the effects of
Btu content, gathering and transportation costs, gas processing and shrinkage
and the net effect of the gas hedges. The Company reported an average gas price
of $2.27 per Mcf for the year ended December 31, 1996. The Company's average
realized price for physical gas sales (excluding hedge results) for the same
period was $2.39 per Mcf. The comparable average NYMEX prompt month closing for
the year ended December 31, 1996 was $2.50 per Mcf.
48
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
Crude Oil. All material purchase contracts governing the Company's oil
production are tied directly or indirectly to NYMEX prices. The following table
sets forth the Company's outstanding oil swap contracts as of December 31, 1996.
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- -------
Oil production:
1997 - Swap Contracts
Volume (MMBbl) 1.9 1.5 1.2 .7 5.3
Price per Bbl $ 20.05 $19.56 $19.28 $18.56 $19.53
1998 - Swap Contracts
Volume (MMBbl) .2 .2 .3 .2 .9
Price per Bbl $ 18.53 $18.53 $18.53 $18.53 $18.53
The Company reports average oil prices per Bbl including the effects of
oil quality, gathering and transportation costs and the net effect of the oil
hedges. The Company reported an average oil price of $19.96 per Bbl for the year
ended December 31, 1996. The Company's average realized price for physical oil
sales (excluding hedge results) for the same period was $21.33 per Bbl. The
comparable average NYMEX prompt month closing for the year ended December 31,
1996 was $22.03 per Bbl.
NOTE O. Sales to Major Customers
The Company's share of oil and gas production is sold to various
purchasers. The Company is of the opinion that the loss of any one purchaser
would not have an adverse effect on the ability of the Company to sell its oil
and gas production.
The following customers individually accounted for more than 10% of the
consolidated oil and gas revenues of the Company:
Percentage of Consolidated
Customer Oil and Gas Revenues
-------- --------------------------
1996 1995 1994
---- ---- ----
Genesis Crude Oil, L.P.............. 28% 19% 17%
Mobil Oil Corporation............... 22% 17% 16%
At December 31, 1996, the amounts receivable from Genesis and Mobil were
$12.7 million and $9.4 million, respectively, which are included in the caption
"Accounts receivable - oil and gas sales" in the accompanying Consolidated
Balance Sheet.
NOTE P. Gas Marketing
Effective January 1, 1996, the Company, along with Apache Corporation and
Oryx Energy Company, formed Producers Energy Marketing, LLC ("ProEnergy"), a
natural gas marketing company organized to create a direct link between gas
producers and purchasers. The venture is structured to flow through the benefits
arising out of the expanded services and the economies of scale from the
aggregation of substantial volumes of gas. The Company is obligated to sell to
ProEnergy all gas production (subject to certain exclusions relative to
immaterial volumes) for a period of five years that is owned or controlled by
the Company, or any affiliate, in North America (onshore and offshore), which is
not subject to a binding and enforceable gas sales contract in effect on July 1,
1996. The Company currently owns approximately 9.59% of ProEnergy which markets
approximately 1.8 MMBtu per day. As a result, as of January 1, 1996, the Company
no longer reports revenues or expenses associated with third party gas marketing
activities.
NOTE Q. Disposition of Australasian Assets
On March 28, 1996, the Company completed the sale of certain wholly-owned
Australian subsidiaries to Santos Ltd., and on June 20, 1996, the Company
completed the sale of another wholly-owned subsidiary, Bridge Oil Timor Sea,
Inc., to Phillips Petroleum International Investment Company. During the year
ended December 31, 1996, the Company received
49
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
aggregate consideration of $237.5 million for these combined sales which
consisted of $186.6 million of proceeds for the equity of such entities, $21.8
million for reimbursement of certain intercompany cash advances, and the
assumption of such subsidiaries' net liabilities, exclusive of oil and gas
properties, of $29.1 million. The accompanying Consolidated Statements of
Operations for the year ended December 31, 1996 includes a pre-tax gain of $83.3
million from the disposition of these subsidiaries (net of transaction expenses
of $8.7 million) and an income tax provision of $16 million. The income tax
provision includes $6.4 million related to the write-off of certain net
operating loss carryforwards which, with the sale of the income producing assets
in the Australian tax jurisdiction, will not be utilized in the future.
The assets sold to Santos Ltd. consisted primarily of properties located
in the Cooper Basin in Central Australia, the Surat Basin in Northeast
Australia, the Carnarvon Basin on the Northwest Shelf off the coast of Western
Australia, the Otway Basin off the coast of Southeast Australia and the Central
Sumatra Basin in Indonesia. At December 31, 1995, the Company's interests in
these properties contained 32.1 million BOE of proved reserves (consisting of
12.4 million Bbls of oil and 118.3 Bcf of gas), representing $133.8 million of
SEC 10 value. The accompanying Consolidated Statements of Operations for the
year ended December 31, 1996 includes the results of operations from these
properties prior to their sale on March 28, 1996. During 1996, these properties
produced 349,500 Bbls of oil and 1,927,000 Mcf of gas. The Company received an
average price of $19.55 per Bbl and $1.95 per Mcf from such production or $10.6
million in total revenues. Total production costs associated with these
properties were $3.3 million ($4.92 per equivalent Bbl) and depletion expense
was $3.9 million ($5.84 per equivalent Bbl).
The wholly-owned subsidiary sold to Phillips Petroleum International
Investment Company, Bridge Oil Timor Sea, Inc. has a wholly owned subsidiary,
Bridge Oil Timor Sea Pty Ltd., which owns a 22.5% interest in the ZOCA 91-13
permit in the offshore Bonaparte Basin in the Zone of Cooperation between
Australia and Indonesia.
NOTE R. Impairment of Long-Lived Assets
The Company adopted SFAS 121 in 1995. The Company undertook to review its
oil and gas properties for impairment earlier than required by SFAS 121
(adoption was required for fiscal years beginning after December 15, 1995) as a
result of the continuation of depressed commodity prices and to eliminate any
uncertainty associated with the magnitude of the noncash charge for impairment
of its oil and gas properties under SFAS 121. In order to determine whether an
impairment had occurred, the Company estimated the expected future cash flows of
its oil and gas properties and compared such future cash flows to the carrying
amount of the oil and gas properties to determine if the carrying amount was
recoverable. For those oil and gas properties for which the carrying amount
exceeded the estimated future cash flows, an impairment was determined to exist;
therefore, the Company adjusted the carrying amount of those oil and gas
properties to their fair value as determined by discounting their expected
future cash flows at a discount rate commensurate with the risks involved in the
industry. As a result of this process and an evaluation of unproven oil and gas
properties, the Company recognized noncash pre-tax charges of $129.7 million
($84.3 million after tax) related to its oil and gas properties during 1995. The
Company also recognized a noncash pre-tax charge of $748,000 ($486,000 after
tax) related to a natural gas processing facility in 1995.
NOTE S. Income Taxes
Income tax provision (benefit) and amounts separately allocated were as
follows:
Year ended December 31,
1996 1995 1994
------- -------- -------
(in thousands)
Income (loss) before extraordinary item......... $60,100 $(45,900) $(6,500)
Extraordinary gain (loss)....................... - 2,300 (350)
Benefit arising from exercise of stock options.. (2,200) (600) (300)
Change in cumulative translation adjustment..... - (550) 500
------ ------- ------
$57,900 $(44,750) $(6,650)
====== ======= ======
50
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
Income tax provision (benefit) attributable to income (loss) before
extraordinary item consists of the following:
Year ended December 31,
1996 1995 1994
-------- -------- --------
(in thousands)
Current:
U.S. federal....................... $ 300 $ (1,000) $ 150
State and local.................... - - 150
------- ------- -------
300 (1,000) 300
------- -------- -------
Deferred:
U.S. federal....................... 51,700 (35,500) (1,650)
Foreign (primarily Australia)...... 8,100 (9,400) (5,150)
------- -------- -------
59,800 (44,900) (6,800)
------- -------- -------
Total................................ $ 60,100 $(45,900) $ (6,500)
======= ======= =======
Income (loss) before income taxes, extraordinary item consists of the
following:
Year ended December 31,
1996 1995 1994
-------- --------- --------
(in thousands)
Income (loss) before income taxes,
extraordinary item and cumulative
effect of accounting change:
U.S. federal............................ $121,680 $(118,871) $ (3,664)
Foreign (primarily Australia)........... 78,668 (31,136) (16,827)
------- -------- --------
$200,348 $(150,007) $ (20,491)
======= ======== ========
Reconciliations of the U.S. federal statutory rate to the Company's
effective rate for income (loss) before extraordinary item are as follows:
1996 1995 1994
------ ------- -------
U.S. federal statutory tax rate.................. 35.0% (35.0%) (35.0%)
Disposition of foreign subsidiaries.............. (6.9%) - -
Amortization of foreign permanent differences.... - 3.1% 1.8%
Rate differential on foreign operations.......... .4% (.1%) 1.3%
Other............................................ 1.5% 1.4% .2%
----- ------ ------
Consolidated effective tax rate.................. 30.0% (30.6%) (31.7%)
===== ====== ======
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities were as
follows:
December 31,
1996 1995
--------- ---------
(in thousands)
Deferred tax assets:
Net operating loss carryforwards................ $ 23,704 $ 70,882
Alternative minimum tax credit carryforwards.... 4,005 6,760
Other accrued liabilities....................... 3,306 7,485
Compensation, principally due to accrual for
financial reporting purposes.................. 2,579 -
Other, net...................................... 1,831 1,051
-------- --------
Total gross deferred tax assets............... 35,425 86,178
-------- --------
Deferred tax liabilities:
Oil and gas properties, principally due to
differences in basis and depletion and the
deduction of intangible drilling costs for
tax purposes................................... 88,790 86,530
Long-term debt, principally due to early
extinguishment for book purposes............... - 2,313
Other, net...................................... 35 1,035
-------- --------
Total gross deferred tax liabilities.......... 88,825 89,878
-------- --------
Net deferred tax liability.................... $ (53,400) $ (3,700)
======== ========
51
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1996, 1995 and 1994
A valuation allowance is provided when it is more likely than not that
some portion of the deferred tax assets will not be realized. Based on
expectations for the future and the availability of certain tax planning
strategies that would generate taxable income to realize the net tax benefits,
if implemented, management has determined that taxable income of the Company
will more likely than not be sufficient to fully utilize available carryforwards
prior to their ultimate expiration.
At December 31, 1996, the Company had net operating loss carryforwards
("NOLs") for U.S. federal income tax purposes of $67.7 million, which are
available to offset future regular taxable income, if any. Additionally, the
Company has alternative minimum tax net operating loss carryforwards ("AMT
NOLs") of $15.2 million, which are available to reduce future alternative
minimum taxable income, if any. These carryforwards expire as follows:
Expiration Date NOLs AMT NOLs
--------------- -------- --------
(in thousands)
December 31, 2006........................... $ 22,798 $ 4,195
December 31, 2009........................... 28,558 9,667
December 31, 2010........................... 16,368 1,364
------- -------
$ 67,724 $ 15,226
======= =======
As discussed in Note B, certain subsidiaries that are consolidated for
financial reporting purposes are not eligible to be included in the Company's
consolidated U.S. federal income tax return, and separate provisions for income
taxes have been determined for these entities or groups of entities. As a
result, approximately $35 million of the NOLs and all of the AMT NOLs are
limited in use to specific entities or groups of entities. In addition, $22.9
million and $4.2 million of the NOLs and AMT NOLs, respectively, are further
subject to limitations under Section 382 of the Internal Revenue Code. The
Company believes the utilization of its NOLs and AMT NOLs subject to the Section
382 limitations is limited in each taxable year to approximately $11.4 million.
The tax returns and the amount of taxable income or loss are subject to
examination by U.S. federal, state and foreign taxing authorities. Current and
estimated tax payments of $970,000, $93,000 and $5 million were made in 1996,
1995 and 1994, respectively.
NOTE T. Operations by Geographic Area
The Company operates in one industry segment. During 1996, the Company
did not have significant operations in geographic areas other than the United
States. Information about the Company's operations for the years ended December
31, 1995 and 1994 by different geographic areas is shown below. During these
years, the Company did not have any significant operations or separately
identifiable assets other than those from the United States and Australia.
<TABLE>
<CAPTION>
Year ended December 31,
1995 1994
----------------------------------- -----------------------------------
Australia Australia
United and Other United and Other
States Foreign Total States Foreign Total
---------- --------- ---------- ---------- --------- ----------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Operating revenue............ $ 439,957 $ 45,805 $ 485,762 $ 455,895 $ 23,838 $ 479,733
Loss before income taxes
and extraordinary item..... $ (118,871) $ (31,136) $ (150,007) $ (3,664) $ (16,827) $ (20,491)
Identifiable assets.......... $1,120,738 $ 198,491 $1,319,229 $1,395,253 $ 209,651 $1,604,904
</TABLE>
52
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years ended December 31, 1996, 1995 and 1994
Capitalized Costs
December 31,
1996 1995
---------- ----------
(in thousands)
Oil and Gas Properties:
Proved oil and gas properties $1,419,051 $1,450,290
Unproved property 7,331 14,574
--------- ---------
1,426,382 1,464,864
Less accumulated depletion (424,594) (383,825)
--------- ---------
Net capitalized costs for oil
and gas properties $1,001,788 $1,081,039
========= =========
Costs Incurred for Oil and Gas
Producing Activities
<TABLE>
Property
Acquisition Costs Total
-------------------- Exploration Development Costs
Proved Unproved Costs Costs Incurred
-------- -------- ----------- ----------- --------
(in thousands)
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1996:
United States $ 15,699 $ 5,255 $ 31,568 $ 168,553 $221,075
Foreign (a) 18 - 7,240 4,659 11,917
------- ------- --------- --------- -------
Total costs incurred $ 15,717 $ 5,255 $ 38,808 $ 173,212 $232,992
======= ======= ========= ========= =======
Year ended December 31, 1995:
United States $ 46,796 $ - $ 8,062 $ 130,461 $185,319
Australia and Other Foreign 1,698 - 21,129 10,877 33,704
------- ------- --------- --------- -------
Total costs incurred $ 48,494 $ - $ 29,191 $ 141,338 $219,023
======= ======= ========= ========= =======
Year ended December 31, 1994:
United States $401,826(b) $ 30,308 $ 8,370 $ 93,175 $533,679
Australia and Other Foreign 141,785 10,000 11,098 1,391 164,274
------- ------- --------- --------- -------
Total costs incurred $543,611(b) $ 40,308 $ 19,468 $ 94,566 $697,953
======= ======= ========= ========= =======
<FN>
- ---------------
(a) Includes $7.4 million of expenditures related to the Company's Australian
properties prior to their sale in 1996. The remainder relates to the
Company's interests in Argentine properties.
(b) Excludes approximately $1.9 million associated with properties held by
Bridge Oil Limited and $12.8 million associated with properties acquired
from PG&E Resources Company that were classified as assets held for resale.
</FN>
</TABLE>
53
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years ended December 31, 1996, 1995 and 1994
<TABLE>
<CAPTION>
Results of Operations
For the year ended December 31,
1996 1995 1994
--------- --------- ---------
(in thousands)
<S> <C> <C> <C>
UNITED STATES
Oil and gas revenues $ 385,198 $ 329,915 $ 313,764
Production costs (106,898) (118,487) (120,687)
Exploration and abandonments (9,222) (6,795) (8,774)
Geological and geophysical (7,042) (2,302) (3,834)
Depletion (98,655) (125,165) (120,520)
Impairment of oil and gas properties - (129,745) -
-------- -------- --------
163,381 (52,579) 59,949
Income tax benefit (provision) (a) (57,183) 18,403 (20,982)
-------- -------- --------
Results of operations for oil and gas
producing activities $ 106,198 $ (34,176) $ 38,967
======== ======== ========
AUSTRALIA
Oil and gas revenues $ 10,591 $ 45,805 $ 23,838
Production costs (3,300) (12,418) (6,431)
Exploration and abandonments (15) (6,779) (3,401)
Geological and geophysical (1,420) (6,874) (3,332)
Depletion (3,917) (20,303) (11,182)
-------- -------- --------
1,939 (569) (508)
Income tax benefit (provision) (a) (698) 205 168
-------- -------- --------
Results of operations for oil and gas
producing activities $ 1,241 $ (364) $ (340)
======== ======== ========
ARGENTINA
Oil and gas revenues $ 1,142 $ - $ -
Production costs (136) - -
Exploration and abandonments (3,416) (2,857) (170)
Geological and geophysical (592) (1,945) (1,236)
Depletion (231) - -
-------- -------- --------
(3,233) (4,802) (1,406)
Income tax benefit (a) 1,164 1,729 464
-------- -------- --------
Results of operations for oil and gas
producing activities $ (2,069) $ (3,073) $ (942)
======== ======== ========
TOTAL
Oil and gas revenues $ 396,931 $ 375,720 $ 337,602
Production costs (110,334) (130,905) (127,118)
Exploration and abandonments (12,653) (16,431) (12,345)
Geological and geophysical (9,054) (11,121) (8,402)
Depletion (102,803) (145,468) (131,702)
Impairment of oil and gas properties - (129,745) -
-------- -------- --------
162,087 (57,950) 58,035
Income tax benefit (provision) (a) (56,717) 20,337 (20,350)
-------- -------- --------
Results of operations for oil and gas
producing activities $ 105,370 $ (37,613) $ 37,685
======== ======== ========
<FN>
- ---------------
(a) The income tax benefit (provision) is calculated using the current statutory
tax rate for each jurisdiction.
</FN>
</TABLE>
54
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years ended December 31, 1996, 1995 and 1994
Reserve Quantity Information
The estimates of the Company's proved oil and gas reserves, which are
located principally in the United States, are based on evaluations audited by
independent petroleum engineers with respect to the Company's major properties
and prepared by the Company's engineers with respect to all other properties.
Reserves were estimated in accordance with guidelines established by the U.S.
Securities and Exchange Commission and the Financial Accounting Standards Board,
which require that reserve estimates be prepared under existing economic and
operating conditions with no provision for price and cost escalations except by
contractual arrangements. The United States reserve estimates for 1996 utilize
an oil price of $24.55 per Bbl (reflecting adjustments for oil quality and
gathering and transportation costs) and a gas price of $3.97 per Mcf (reflecting
adjustments for BTU content, gathering and transportation costs and gas
processing and shrinkage).
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revision of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of currently
producing oil and gas properties. Accordingly, these estimates are expected to
change as additional information becomes available in the future.
55
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years ended December 31, 1996, 1995 and 1994
<TABLE>
<CAPTION>
Oil (Bbls) Natural Gas (Mcf)
-------------------------------------- -------------------------------------
United United Total
States Australia Argentina Total States Australia Argentina Total BOE's
------- --------- --------- ------- ------- --------- --------- -------- -------
(in thousands)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Oil and Gas Producing
Activities:
Total Proved Reserves:
Balance, January 1, 1994 94,004 - - 94,004 527,752 - - 527,752 181,963
Revisions:
Revisions of previous
estimates 15,141 (199) - 14,942 10,318 184 - 10,502 16,692
Reserves added by
development drilling 11,935 - - 11,935 55,617 - - 55,617 21,205
Purchases of minerals-
in-place 25,822 13,884 - 39,706 243,719 108,880 - 352,599 98,472
New discoveries and
extensions 135 - - 135 452 - - 452 210
Production (11,267) (880) - (12,147) (75,040) (4,634) - (79,674) (25,426)
Sales of minerals-in-place (4,034) - - (4,034) (39,740) - - (39,740) (10,657)
------- ------- ----- ------- ------- -------- ----- -------- -------
Balance,
December 31, 1994 131,736 12,805 - 144,541 723,078 104,430 - 827,508 282,459
Revisions:
Revisions of previous
estimates 9,211 1,212 - 10,423 80,571 22,493 - 103,064 27,600
Reserves added by
development drilling 18,486 - - 18,486 61,945 - - 61,945 28,810
Purchases of minerals-
in-place 4,309 - - 4,309 82,713 - - 82,713 18,094
New discoveries and
extensions 761 - - 761 6,015 - - 6,015 1,764
Production (11,328) (1,574) - (12,902) (76,669) (8,626) - (85,295) (27,118)
Sales of minerals-in-place (18,284) - - (18,284) (99,044) - - (99,044) (34,791)
------- ------- ----- ------- ------- -------- ----- -------- -------
Balance,
December 31, 1995 134,891 12,443 - 147,334 778,609 118,297 - 896,906 296,818
Revisions:
Revisions of previous
estimates 3,652 - - 3,652 (11,790) - - (11,790) 1,687
Reserves added by
development drilling 38,962 - - 38,962 162,885 - - 162,885 66,110
Purchases of minerals-
in-place 300 - - 300 11,494 - - 11,494 2,216
New discoveries and
extensions 760 - 1,159 1,919 17,607 - 1,108 18,715 5,038
Production (10,872) (349) (54) (11,275) (73,924) (1,927) - (75,851) (23,916)
Sales of minerals-in-place (4,857) (12,094) - (16,951) (56,613) (116,370) - (172,983) (45,782)
------- ------- ----- ------- ------- -------- ----- -------- -------
Balance,
December 31, 1996 162,836 - 1,105 163,941 828,268 - 1,108 829,376 302,171
======= ======= ===== ======= ======= ======== ===== ======== =======
Proved Developed Reserves:
January 1, 1994 74,217 - - 74,217 442,270 - - 442,270 147,929
======= ======= ===== ======= ======= ======== ===== ======== =======
December 31, 1994 99,520 7,548 - 107,068 591,472 31,303 - 622,775 210,864
======= ======= ===== ======= ======= ======== ===== ======== =======
December 31, 1995 101,310 7,610 - 108,920 615,328 30,738 - 646,066 216,598
======= ======= ===== ======= ======= ======== ===== ======== =======
December 31, 1996 126,163 - 207 126,370 660,174 - - 660,174 236,399
======= ======= ===== ======= ======= ======== ===== ======== =======
</TABLE>
56
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years ended December 31, 1996, 1995 and 1994
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed
by applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves less estimated future expenditures
(based on year-end costs) to be incurred in developing and producing the proved
reserves, discounted using a rate of 10% per year to reflect the estimated
timing of the future cash flows. Future income taxes are calculated by comparing
discounted future cash flows to the tax basis of oil and gas properties plus
available carryforwards and credits and applying the current tax rates to the
difference.
Discounted future cash flow estimates like those shown below are not
intended to represent estimates of the fair value of oil and gas properties.
Estimates of fair value should also consider probable reserves, anticipated
future oil and gas prices, interest rates, changes in development and production
costs and risks associated with future production. Because of these and other
considerations, any estimate of fair value is necessarily subjective and
imprecise.
57
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years ended December 31, 1996, 1995 and 1994
<TABLE>
<CAPTION>
For the year ended December 31,
1996 1995 1994
----------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
UNITED STATES
Oil and gas producing activities:
Future cash inflows $ 7,280,710 $ 4,134,327 $ 3,447,519
Future production costs (2,325,274) (1,618,191) (1,513,188)
Future development costs (196,410) (164,794) (133,580)
---------- ---------- ----------
Future net cash flows before taxes 4,759,026 2,351,342 1,800,751
10% annual discount factor (2,421,698) (1,119,604) (801,575)
---------- ---------- ----------
Discounted future cash flows before taxes 2,337,328 1,231,738 999,176
Discounted future income taxes (537,804) (131,894) (22,436)
---------- ---------- ----------
Standardized measure of discounted future
net cash flows $ 1,799,524 $ 1,099,844 $ 976,740
========== ========== ==========
AUSTRALIA
Oil and gas producing activities:
Future cash inflows $ - $ 428,191 $ 358,903
Future production costs - (136,681) (88,630)
Future development costs - (47,085) (48,251)
---------- ---------- ----------
Future net cash flows before taxes - 244,425 222,022
10% annual discount factor - (110,674) (102,555)
---------- ---------- ----------
Discounted future cash flows before taxes - 133,751 119,467
Discounted future income taxes - (29,806) (24,550)
---------- ---------- ----------
Standardized measure of discounted future
net cash flows $ - $ 103,945 $ 94,917
========== ========== ==========
ARGENTINA
Oil and gas producing activities:
Future cash inflows $ 28,211 $ - $ -
Future production costs (8,099) - -
Future development costs (4,456) - -
---------- ---------- -
Future net cash flows before taxes 15,656 - -
10% annual discount factor (7,615) - -
---------- ---------- -
Discounted future cash flows before taxes 8,041 - -
Discounted future income taxes - - -
---------- ---------- ----------
Standardized measure of discounted future
net cash flows $ 8,041 $ - $ -
========== ========== ==========
TOTAL
Oil and gas producing activities:
Future cash inflows $ 7,308,921 $ 4,562,518 $ 3,806,422
Future production costs (2,333,373) (1,754,872) (1,601,818)
Future development costs (200,866) (211,879) (181,831)
---------- ---------- ----------
Future net cash flows before taxes 4,774,682 2,595,767 2,022,773
10% annual discount factor (2,429,313) (1,230,278) (904,130)
---------- ---------- ----------
Discounted future cash flows before taxes 2,345,369 1,365,489 1,118,643
Discounted future income taxes (537,804) (161,700) (46,986)
---------- ---------- ----------
Standardized measure of discounted future
net cash flows $ 1,807,565 $ 1,203,789 $ 1,071,657
========== ========== =========
</TABLE>
58
<PAGE>
PARKER & PARSLEY PETROLEUM COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years ended December 31, 1996, 1995 and 1994
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995 1994
---------- ---------- ----------
(in thousands)
<S> <C> <C> <C>
Oil and Gas Producing Activities:
Oil and gas sales, net of production costs $ (286,597) $ (244,815) $ (210,484)
Net changes in prices and production costs 866,196 221,581 (25,789)
Extensions and discoveries 53,314 12,321 1,781
Sales of minerals-in-place (185,859) (139,250) (63,581)
Purchases of minerals-in-place 20,606 53,628 451,127
Revisions of estimated future development costs (73,587) (47,459) (20,383)
Revisions of previous quantity estimates and
reserves added by development drilling 569,529 288,445 159,210
Accretion of discount 123,174 105,891 90,190
Changes in production rates, timing and other (106,896) (3,496) 1,504
--------- --------- ---------
Change in present value of future net revenues 979,880 246,846 383,575
Net change in present value of future income taxes (376,104) (114,714) (43,502)
--------- --------- ---------
603,776 132,132 340,073
Balance, beginning of year 1,203,789 1,071,657 731,584
--------- --------- ---------
Balance, end of year $1,807,565 $1,203,789 $1,071,657
========= ========= =========
Selected Quarterly Financial Results
Quarter
--------------------------------------------------
First Second(a) Third Fourth(a)
-------- --------- --------- ---------
(in thousands, except per share data)
1996
Operating revenues $103,444 $ 99,674 $ 97,019 $ 120,608
Total revenues 118,282 182,508 111,230 123,323
Costs and expenses 91,272 82,952 74,765 86,006
Net income 14,710 80,156 20,965 24,417
Net income per share .41 2.24 .58 .68
1995
Operating revenues $123,580 $ 126,760 $ 113,347 $ 122,075
Total revenues 122,341 152,449 115,329 123,627
Costs and expenses 143,919 244,453 124,836 150,545
Loss before extraordinary item (14,778) (62,403) (6,908) (20,018)
Loss before extraordinary item
per share (.42) (1.77) (.20) (.56)
Net loss (14,778) (62,403) (6,908) (15,680)
Net loss per share (.42) (1.77) (.20) (.44)
<FN>
- ----------
(a) The second and fourth quarter of 1995 include a SFAS 121 impairment
charge of $101.3 million and $29.2 million, respectively. See Note R of
the Notes to the Consolidated Financial Statements above.
</FN>
</TABLE>
59
<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 information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held in 1997 and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held in 1997 and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held in 1997 and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held in 1997 and is incorporated herein by reference.
60
<PAGE>
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Listing of Financial Statements and Exhibits
Financial Statements
The following consolidated financial statements of the Company are
included in "Item 8. Financial Statements and Supplementary Data":
Independent Auditors' Report
Consolidated Balance Sheets as of December 31, 1996 and 1995
Consolidated Statements of Operations for the years ended December 31,
1996, 1995 and 1994
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1996, 1995 and 1994
Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994
Notes to Consolidated Financial Statements
Unaudited Supplementary Information
All other statements and schedules for which provision is made in the
applicable accounting regulations of the Securities and Exchange Commission have
been omitted because they are not required under related instructions or are
inapplicable, or the information is shown in the financial statements and
related notes.
Exhibits
Exhibit
Number Description
2.1 - Agreement of Sale and Purchase dated June 6, 1994, between the
Company and PG&E Resources Company (incorporated by reference to
Exhibit 2.1 to the Company's Current Report on Form 8-K dated June
6, 1994, Commission File No. 1-10695).
2.2 - Offer by Parker & Parsley Petroleum Australia Pty Limited to
Acquire all of the Ordinary Shares in Bridge Oil Limited
(incorporated by reference to Exhibit 2.2 to the Company's Current
Report on Form 8-K dated June 6, 1994, Commission File No.
1-10695).
3.1 - Restated Certificate of Incorporation of the Company (incorporated
by reference to Exhibit 3.1 to the Company's Registration
Statement on Form S-4 dated December 31, 1990, Registration No.
33-38436).
3.2 - Restated By-laws of the Company (incorporated by reference to
Exhibit 3.2 to the Company's Registration Statement on Form S-4
dated December 31, 1990, Registration Statement No. 33-38436).
4.1 - Form of Certificate of Common Stock, par value $.01 per share, of
the Company (incorporated by reference to Exhibit 4.2 to the
Company's Registration Statement on Form S-4 dated December 31,
1990, Registration No. 33-38436).
4.2 - Rights Agreement of the Company (incorporated by reference to
Exhibit 4.1 to the Company's Current Report on Form 8-K dated
February 19, 1991, Commission File No. 1-10695).
4.3 - First Amendment to Rights Agreement of the Company, dated as of
March 18, 1994 (incorporated by reference to Exhibit 4.4A to the
Company's Registration Statement on Form S-3 dated June 24, 1994,
Registration No. 33-79920).
4.4 - Certificate of Designations of Series A Convertible Preferred
Stock of the Company, dated March 24, 1994 (incorporated by
references to Exhibit 4.4B to the Company's Registration Statement
on Form S-3 dated June 24, 1994, Registration No. 33-79920).
61
<PAGE>
Exhibit
Number Description
-- - Indentures relating to $50,000,000 principal amount of 8-1/2%
Convertible Subordinated Debentures due 2005 of Dorchester Master
Limited Partnership ($3,762,000 million principal amount of which
were outstanding and held by nonaffiliates at December 31, 1996)
and $100,000,000 principal amount of 9-1/2% Senior Notes due 2000
of Bridge Oil (U.S.A.) Inc. ($2,063,000 principal amount of which
were outstanding at December 31, 1996) have been omitted pursuant
to Item 601(b)(4)(iii)(A) of Regulation S-K. The Company hereby
agrees to furnish a copy of such indenture to the Securities and
Exchange Commission upon request.
-- - Indenture (the "Indenture") relating to $150,000,000 principal
amount of 8-7/8% Senior Notes Due 2005 of the Company and to
$150,000,000 principal amount of 8-1/4% Senior Notes Due 2007 of
the Company (incorporated by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K dated April 12, 1995,
Commission File No. 1-10695).
-- - Form of 8-7/8% Senior Notes Due 2005 dated as of April 12, 1995, in
the aggregate principal amount of $150,000,000, together with
Officers' Certificate dated April 12, 1995, establishing the terms
of the 8-7/8% Senior Notes Due 2005 pursuant to the Indenture
(incorporated by reference to Exhibit 4.2 to the Company's
Quarterly Report on Form 10-Q for the period ended June 30, 1995,
Commission File No. 1-10695).
-- - Form of 8-1/4% Senior Notes Due 2007 dated as of August 22, 1995,
in the aggregate principal amount of $150,000,000, together with
Officers' Certificate dated August 22, 1995, establishing the terms
of the 8-1/4% Senior Notes Due 2007 pursuant to the Indenture
(incorporated by reference to Exhibit 1.2 to the Company's Current
Report on Form 8-K dated August 17, 1995, Commission File No.
1-10695).
10.1+ - Parker & Parsley Petroleum Company Long-term Incentive Plan dated
February 19, 1991 (incorporated by reference to Exhibit 4.1 to the
Company's Registration Statement on Form S-8, Registration No.
33-38971).
10.2+ - First Amendment to the Parker & Parsley Petroleum Company Long-term
Incentive Plan dated August 23, 1991 (incorporated by reference to
Exhibit 10.2 to the Company's Registration Statement on Form S-1
dated February 28, 1992, Registration No. 33-46082).
10.3+ - Amended and Restated Indemnification Agreement, dated as of
February 15, 1995, between the Company and Scott D. Sheffield,
together with a schedule identifying substantially identical
agreements between the Company and each of the Company's other
directors and Named Executive Officers and setting forth the
material details in which those agreements differ from the Amended
and Restated Indemnification Agreement filed (incorporated by
reference to Exhibit 10.4 to the Company's Annual Report on Form
10-K for the year ended December 31, 1994, Commission File No.
1-10695).
10.4+ - Agreement of Partnership of P&P Employees 89-B Conv., L.P.
(formerly P&P Employees 89-B GP), dated October 31, 1989, among
Parker & Parsley, Ltd. and the Investor Partners (as defined
therein, which includes individuals who are directors and executive
officers of the Company), together with a schedule identifying
substantially identical documents and setting forth the material
details in which those documents differ from the foregoing document
(incorporated by reference to Exhibit 10.50 to the Company's
Registration Statement on Form S-4 dated December 31, 1990,
Registration No. 33-38436).
10.5+ - Amendment to Agreement of Partnership of P&P Employees 89-B GP,
dated May 31, 1990, among Parker & Parsley, Ltd. and the Investor
Partners (as defined therein, which includes individuals who are
directors and executive officers of the Company), together with a
schedule identifying substantially identical documents and setting
forth the material details in which those documents differ from the
foregoing document (incorporated by reference to Exhibit 10.51 to
the Company's Registration Statement on Form S-4 dated December 31,
1990, Registration No. 33-38436).
62
<PAGE>
Exhibit
Number Description
10.6+ - Schedule identifying additional documents substantially identical
to the Amendment to Agreement of Partnership of P&P Employees 89-B
GP included as Exhibit 10.5 and setting forth the material details
in which those documents differ from that document (incorporated by
reference to Exhibit 10.52 to the Company's Registration Statement
on Form S-1 dated February 28, 1992, Registration No. 33-46082).
10.7+ - Agreement of Partnership of P&P Employees 90 Spraberry Private
Development GP, dated October 16, 1990, among Parker & Parsley,
Ltd., James D. Moring, and the General Partners (as defined
therein, which includes individuals who are directors and executive
officers of the Company), and form of Amendment to Agreement of
Partnership of P&P Employees 90 Spraberry Private Development GP,
together with a schedule identifying substantially identical
documents and setting forth the material details in which those
documents differ from the foregoing document (incorporated by
reference to Exhibit 10.52 to the Company's Registration Statement
on Form S-4 dated December 31, 1990, Registration No. 33-38436).
10.8+ - Amendment to Agreement of Partnership of Parker & Parsley 90-A GP,
dated February 19, 1991, among Parker & Parsley Development Company
and the Investor Partners (as defined therein, which includes
individuals who are directors and executive officers of the
Company), together with a schedule identifying substantially
identical documents and setting forth the material details in which
those documents differ from the foregoing document (incorporated by
reference to Exhibit 10.58 to the Company's Registration Statement
on Form S-1 dated February 28, 1992, Registration No. 33-46082).
10.9+ - Agreement of Partnership of P&P Employees 91-A, GP, dated September
30, 1991, among Parker & Parsley Development Company, James D.
Moring and the General Partners (as defined therein, which includes
individuals who are directors and executive officers of the
Company), together with a schedule identifying substantially
identical documents and setting forth the material details in which
those documents differ from the foregoing document (incorporated by
reference to Exhibit 10.61 to the Company's Registration Statement
on Form S-1 dated February 28, 1992, Registration No. 33-46082).
10.10+ - Development Drilling Program Agreement of Parker & Parsley 91-A
Development Drilling Program, dated September 30, 1991, among
Parker & Parsley Development Company, the P&P Employee Participants
(as defined therein, which includes individuals who are directors
and executive officers of the Company), P&P Employees 91-A, GP, and
Parker & Parsley 91-A, L.P., together with a schedule identifying
substantially identical documents and setting forth the material
details in which those documents differ from the foregoing document
(incorporated by reference to Exhibit 10.63 to the Company's
Registration Statement on Form S-1 dated February 28, 1992,
Registration No. 33-46082).
10.11+ - Development Drilling Program Agreement dated August 1, 1989, among
Parker & Parsley, Ltd., Parker & Parsley Development Partners L.P.,
certain key employees of Parker & Parsley, Ltd. (which includes
individuals who are directors and executive officers of the
Company) and related persons, P&P Employees 89-A GP, Parker &
Parsley 89-A GP, and Parker & Parsley 89-A, L.P., together with a
schedule identifying substantially identical documents and setting
forth the material details in which those documents differ from the
foregoing document (incorporated by reference to Exhibit 10.56 to
the Company's Registration Statement on Form S-4 dated December 31,
1990, Registration No. 33-38436).
10.12+ - Amendment to Development Drilling Program Agreement, dated February
19, 1991, amending the Development Drilling Program Agreement
included as Exhibit 10.11, together with a schedule identifying
substantially identical documents and setting forth the material
details in which those documents differ from the foregoing document
(incorporated by reference to Exhibit 10.66 to the Company's
Registration Statement on Form S-1 dated February 28, 1992,
Registration No. 33-46082).
10.13+ - Amendment to Agreement of Partnership of P&P Employees 90 Spraberry
Private Development GP, dated April 22, 1991, among the Partners
(as defined therein, which includes individuals who are directors
and executive officers of the Company ) (incorporated by reference
to Exhibit 10.67 to the Company's Registration Statement on Form
S-1 dated February 28, 1992, Registration No. 33-46082).
63
<PAGE>
Exhibit
Number Description
10.14+ - Agreement of Limited Partnership of Parker & Parsley 1992 Direct
Investment Program, Ltd., dated as of July 24, 1992, among Parker &
Parsley Development Company, as managing general partner, and
certain key employees of the Company (including individuals who are
directors and executive officers of the Company), as non-managing
general partners and limited partners (incorporated by reference to
Exhibit 10.57 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993, Commission File No. 1-10695).
10.15+ - Agreement of Limited Partnership of Parker & Parsley 1993 Direct
Investment Program, Ltd., dated as of January 1, 1993, among Parker
& Parsley Development Company, as managing general partner, and
certain key employees of the Company (including individuals who are
directors and executive officers of the Company), as non-managing
general partners and limited partners (incorporated by reference to
Exhibit 10.49 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993, Commission File No. 1-10695).
10.16+ - Agreement of Limited Partnership of Parker & Parsley 1994 Direct
Investment Program, Ltd., dated as of January 1, 1994, among Parker
& Parsley Development Company, as managing general partner, and
certain key employees of the Company (including individuals who are
directors and executive officers of the Company), as non-managing
general partners and limited partners (incorporated by reference to
Exhibit 10.20 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1994, Commission File No. 1-10695).
10.17+ - Forms of Stock Acquisition Loan Agreements entered into as of June
15, 1995, between the Company and the officers identified on
Schedule I thereto, providing for the Company's loans to such
officers of the amounts respectively identified on Schedule I
thereto, for the purpose of acquiring the Company's Common Stock,
par value $0.01 per share (incorporated by reference to Exhibit
10.1 to the Company's Quarterly Report on Form 10-Q for the period
ended June 30, 1995, Commission File No. 1-10695).
10.18+ - Severance Agreement dated as of January 1, 1996 between the Company
and Scott D. Sheffield, together with a schedule identifying
substantially identical agreements between the Company and each of
the other Named Executive Officers identified on Schedule I for the
purpose of defining the payment of certain benefits upon the
termination of the officer's employment under certain circumstances
(incorporated by reference to the Company's Annual Report on Form
10-K for the year ended December 31, 1995, Commission File No.
1-10695).
10.19+ - Omnibus Amendment to Nonstatutory Stock Option Agreements, included
as part of the Long-term Incentive Plan, dated as of November 16,
1995, between the Company and Named Executive Officers identified
on Schedule I setting forth additional details relating to the
Long-term Incentive Plan (incorporated by reference to the
Company's Annual Report on Form 10-K for the year ended December
31, 1995, Commission File No. 1-10695).
10.20+ - Parker & Parsley Petroleum Company Annual Bonus Program for Key
Employees dated July 13, 1992 (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on Form S-8,
Registration No. 33-49612).
10.21+ - Registration of additional shares under Parker & Parsley Petroleum
Company's Long-term Incentive Plan dated April 14, 1992
(incorporated by reference to the Company's Registration Statement
on Form S-8, Registration No. 33-47168).
10.22+ - Parker & Parsley Petroleum Company Non-Employee Director Equity
Compensation Plan dated May 26, 1994 (incorporated by reference to
Exhibit 4.4 to the Company's Registration Statement on Form S-8,
Registration No. 33-79480).
64
<PAGE>
Exhibit
Number Description
10.23P - Credit Facility Agreement, dated as of July 31, 1996, between
Parker & Parsley Petroleum Company as Borrower and NationsBank of
Texas, N.A., as Administrative Agent, and CIBC Inc. as
Documentation Agent, and Bank of America National Trust and Savings
Association, The Chase Manhattan Bank, First Union National Bank of
North Carolina, Morgan Guaranty Trust Company of New York and Wells
Fargo Bank, N.A., as Co-Agents and the other lenders signatory
thereto (incorporated by reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the period ended September 30,
1996, Commission File No.1 -10695).
21.1* - Subsidiaries of the registrant.
23.1* - Consent of KPMG Peat Marwick LLP
23.2* - Consent of Netherland, Sewell & Associates, Inc.
- ---------------
* Filed herewith
+ Executive Compensation Plan or Arrangement previously filed pursuant to Item
14(c).
P In accordance with Rule 202 of Regulation S-T, this Exhibit was filed in
paper pursuant to a continuing hardship exemption.
Reports on Form 8-K
No current report on Form 8-K was filed by the Company during the fourth
quarter of 1996.
Exhibits
The exhibits to this Report required to be filed pursuant to Item 14(c)
are listed under "Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K - Listing of Financial Statements and Exhibits - Exhibits" above and
in the "Index to Exhibits" attached hereto.
Financial Statement Schedules
No financial statement schedules are required to be filed as part of this
Report or are inapplicable.
65
<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.
PARKER & PARSLEY PETROLEUM COMPANY
Date: March 10, 1997 By: /s/ Scott D. Sheffield
----------------------------------
Scott D. Sheffield, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Scott D. Sheffield Chairman of the Board, President, March 10, 1997
- --------------------------- Chief Executive Officer and
Scott D. Sheffield Director (principal executive
officer)
/s/ Mel Fischer Executive Vice President and March 10, 1997
- --------------------------- Director
Mel Fischer
/s/ R. Hartwell Gardner Director March 10, 1997
- ---------------------------
R. Hartwell Gardner
/s/ James L. Houghton Director March 10, 1997
- ---------------------------
James L. Houghton
/s/ Jerry P. Jones Director March 10, 1997
- ---------------------------
Jerry P. Jones
/s/ Charles E. Ramsey, Jr. Director March 10, 1997
- ---------------------------
Charles E. Ramsey, Jr.
/s/ Arthur L. Smith Director March 10, 1997
- ---------------------------
Arthur L. Smith
/s/ Edward O. Vetter Director March 10, 1997
- ---------------------------
Edward O. Vetter
/s/ Michael D. Wortley Director March 10, 1997
- ---------------------------
Michael D. Wortley
/s/ Steven L. Beal Senior Vice President and March 10, 1997
- --------------------------- Chief Financial Officer
Steven L. Beal (principal financial and
accounting officer)
66
<PAGE>
INDEX TO EXHIBITS
Exhibit
Number Description Page
2.1 - Agreement of Sale and Purchase dated June 6, 1994, between
the Company and PG&E Resources Company (incorporated by
reference to Exhibit 2.1 to the Company's Current Report on
Form 8-K dated June 6, 1994, Commission File No. 1-10695).
2.2 - Offer by Parker & Parsley Petroleum Australia Pty Limited
to Acquire all of the Ordinary Shares in Bridge Oil Limited
(incorporated by reference to Exhibit 2.2 to the Company's
Current Report on Form 8-K dated June 6, 1994, Commission
File No. 1-10695).
3.1 - Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3.1 to the Company's
Registration Statement on Form S-4 dated December 31, 1990,
Registration No. 33-38436).
3.2 - Restated By-laws of the Company (incorporated by reference
to Exhibit 3.2 to the Company's Registration Statement on
Form S-4 dated December 31, 1990, Registration Statement
No. 33-38436).
4.1 - Form of Certificate of Common Stock, par value $.01 per
share, of the Company (incorporated by reference to Exhibit
4.2 to the Company's Registration Statement on Form S-4
dated December 31, 1990, Registration No. 33-38436).
4.2 - Rights Agreement of the Company (incorporated by reference
to Exhibit 4.1 to the Company's Current Report on Form 8-K
dated February 19, 1991, Commission File No. 1-10695).
4.3 - First Amendment to Rights Agreement of the Company, dated
as of March 18, 1994 (incorporated by reference to Exhibit
4.4A to the Company's Registration Statement on Form S-3
dated June 24, 1994, Registration No. 33-79920).
4.4 - Certificate of Designations of Series A Convertible
Preferred Stock of the Company, dated March 24, 1994
(incorporated by reference to Exhibit 4.4B to the Company's
Registration Statement on Form S-3 dated June 24, 1994,
Registration No. 33-79920).
-- - Indentures relating to $50,000,000 principal amount of
8-1/2% Convertible Subordinated Debentures due 2005 of
Dorchester Master Limited Partnership ($3,762,000 million
principal amount of which were outstanding and held by
nonaffiliates at December 31, 1996) and $100,000,000
principal amount of 9-1/2% Senior Notes due 2000 of Bridge
Oil (U.S.A.) Inc. ($2,063,000 principal amount of which
were outstanding at December 31, 1996) have been omitted
pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K. The
Company hereby agrees to furnish a copy of such indenture
to the Securities and Exchange Commission upon request.
-- - Indenture (the "Indenture") relating to $150,000,000
principal amount of 8-7/8% Senior Notes Due 2005 of the
Company and to $150,000,000 principal amount of 8-1/4%
Senior Notes Due 2007 of the Company (incorporated by
reference to Exhibit 4.1 to the Company's Current Report on
Form 8-K dated April 12, 1995, Commission File No. 1-10695).
67
<PAGE>
Exhibit
Number Description Page
-- - Form of 8-7/8% Senior Notes Due 2005 dated as of April 12,
1995, in the aggregate principal amount of $150,000,000,
together with Officers' Certificate dated April 12, 1995,
establishing the terms of the 8-7/8% Senior Notes Due 2005
pursuant to the Indenture (incorporated by reference to
Exhibit 4.2 to the Company's Quarterly Report on Form 10-Q
for the period ended June 30, 1995, Commission File No.
1-10695).
-- - Form of 8-1/4% Senior Notes Due 2007 dated as of August 22,
1995, in the aggregate principal amount of $150,000,000,
together with Officers' Certificate dated August 22, 1995,
establishing the terms of the 8-1/4% Senior Notes Due 2007
pursuant to the Indenture (incorporated by reference to
Exhibit 1.2 to the Company's Current Report on Form 8-K
dated August 17, 1995, Commission File No. 1-10695).
10.1+ - Parker & Parsley Petroleum Company Long-term Incentive Plan
dated February 19, 1991 (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on Form
S-8, Registration No. 33-38971).
10.2+ - First Amendment to the Parker & Parsley Petroleum Company
Long-term Incentive Plan dated August 23, 1991 (incorporated
by reference to Exhibit 10.2 to the Company's Registration
Statement on Form S-1 dated February 28, 1992, Registration
No. 33-46082).
10.3+ - Amended and Restated Indemnification Agreement, dated as of
February 15, 1995, between the Company and Scott D.
Sheffield, together with a schedule identifying
substantially identical agreements between the Company and
each of the Company's other directors and Named Executive
Officers and setting forth the material details in which
those agreements differ from the Amended and Restated
Indemnification Agreement filed (incorporated by reference
to Exhibit 10.4 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1994, Commission File No.
1-10695).
10.4+ - Agreement of Partnership of P&P Employees 89-B Conv., L.P.
(formerly P&P Employees 89-B GP), dated October 31, 1989,
among Parker & Parsley, Ltd. and the Investor Partners (as
defined therein, which includes individuals who are
directors and executive officers of the Company), together
with a schedule identifying substantially identical
documents and setting forth the material details in which
those documents differ from the foregoing document
(incorporated by reference to Exhibit 10.50 to the Company's
Registration Statement on Form S-4 dated December 31, 1990,
Registration No. 33-38436).
10.5+ - Amendment to Agreement of Partnership of P&P Employees 89-B
GP, dated May 31, 1990, among Parker & Parsley, Ltd. and the
Investor Partners (as defined therein, which includes
individuals who are directors and executive officers of the
Company), together with a schedule identifying substantially
identical documents and setting forth the material details
in which those documents differ from the foregoing document
(incorporated by reference to Exhibit 10.51 to the Company's
Registration Statement on Form S-4 dated December 31, 1990,
Registration No. 33-38436).
68
<PAGE>
Exhibit
Number Description Page
10.6+ - Schedule identifying additional documents substantially
identical to the Amendment to Agreement of Partnership of
P&P Employees 89-B GP included as Exhibit 10.5 and setting
forth the material details in which those documents differ
from that document (incorporated by reference to Exhibit
10.52 to the Company's Registration Statement on Form S-1
dated February 28, 1992, Registration No. 33-46082).
10.7+ - Agreement of Partnership of P&P Employees 90 Spraberry
Private Development GP, dated October 16, 1990, among Parker
& Parsley, Ltd., James D. Moring, and the General Partners
(as defined therein, which includes individuals who are
directors and executive officers of the Company), and form
of Amendment to Agreement of Partnership of P&P Employees 90
Spraberry Private Development GP, together with a schedule
identifying substantially identical documents and setting
forth the material details in which those documents differ
from the foregoing document (incorporated by reference to
Exhibit 10.52 to the Company's Registration Statement on
Form S-4 dated December 31, 1990, Registration No.
33-38436).
10.8+ - Amendment to Agreement of Partnership of Parker & Parsley
90-A GP, dated February 19, 1991, among Parker & Parsley
Development Company and the Investor Partners (as defined
therein, which includes individuals who are directors and
executive officers of the Company), together with a schedule
identifying substantially identical documents and setting
forth the material details in which those documents differ
from the foregoing document (incorporated by reference to
Exhibit 10.58 to the Company's Registration Statement on
Form S-1 dated February 28, 1992, Registration No.
33-46082).
10.9+ - Agreement of Partnership of P&P Employees 91-A, GP, dated
September 30, 1991, among Parker & Parsley Development
Company, James D. Moring and the General Partners (as
defined therein, which includes individuals who are
directors and executive officers of the Company), together
with a schedule identifying substantially identical
documents and setting forth the material details in which
those documents differ from the foregoing document
(incorporated by reference to Exhibit 10.61 to the Company's
Registration Statement on Form S-1 dated February 28, 1992,
Registration No. 33-46082).
10.10+ - Development Drilling Program Agreement of Parker & Parsley
91-A Development Drilling Program, dated September 30, 1991,
among Parker & Parsley Development Company, the P&P Employee
Participants (as defined therein, which includes individuals
who are directors and executive officers of the Company),
P&P Employees 91-A, GP, and Parker & Parsley 91-A, L.P.,
together with a schedule identifying substantially identical
documents and setting forth the material details in which
those documents differ from the foregoing document
(incorporated by reference to Exhibit 10.63 to the Company's
Registration Statement on Form S-1 dated February 28, 1992,
Registration No. 33-46082).
69
<PAGE>
Exhibit
Number Description Page
10.11+ - Development Drilling Program Agreement dated August 1, 1989,
among Parker & Parsley, Ltd., Parker & Parsley Development
Partners L.P., certain key employees of Parker & Parsley,
Ltd. (which includes individuals who are directors and
executive officers of the Company) and related persons, P&P
Employees 89-A GP, Parker & Parsley 89-A GP, and Parker &
Parsley 89-A, L.P., together with a schedule identifying
substantially identical documents and setting forth the
material details in which those documents differ from the
foregoing document (incorporated by reference to Exhibit
10.56 to the Company's Registration Statement on Form S-4
dated December 31, 1990, Registration No. 33-38436).
10.12+ - Amendment to Development Drilling Program Agreement, dated
February 19, 1991, amending the Development Drilling Program
Agreement included as Exhibit 10.11, together with a
schedule identifying substantially identical documents and
setting forth the material details in which those documents
differ from the foregoing document (incorporated by
reference to Exhibit 10.66 to the Company's Registration
Statement on Form S-1 dated February 28, 1992, Registration
No. 33-46082).
10.13+ - Amendment to Agreement of Partnership of P&P Employees 90
Spraberry Private Development GP, dated Apri l 22, 1991,
among the Partners (as defined therein, which includes
individuals who are directors and executive officers of the
Company) (incorporated by reference to Exhibit 10.67 to the
Company's Registration Statement on Form S-1 dated February
28, 1992, Registration No. 33-46082).
10.14+ - Agreement of Limited Partnership of Parker & Parsley 1992
Direct Investment Program, Ltd., dated as of July 24, 1992,
among Parker & Parsley Development Company, as managing
general partner, and certain key employees of the Company
(including individuals who are directors and executive
officers of the Company), as non-managing general partners
and limited partners (incorporated by reference to Exhibit
10.57 to the Company's Annual Report on Form 10-K for the
year ended December 31, 1993, Commission File No. 1-10695).
10.15+ - Agreement of Limited Partnership of Parker & Parsley 1993
Direct Investment Program, Ltd., dated as of January 1,
1993, among Parker & Parsley Development Company, as
managing general partner, and certain key employees of the
Company (including individuals who are directors and
executive officers of the Company), as non-managing general
partners and limited partners (incorporated by reference to
Exhibit 10.49 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1993, Commission File No.
1-10695).
10.16+ - Agreement of Limited Partnership of Parker & Parsley 1994
Direct Investment Program, Ltd., dated as of January 1,
1994, among Parker & Parsley Development Company, as
managing general partner, and certain key employees of the
Company (including individuals who are directors and
executive officers of the Company), as non-managing general
partners and limited partners (incorporated by reference to
Exhibit 10.20 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1994, Commission File No.
1-10695).
70
<PAGE>
Exhibit
Number Description Page
10.17+ - Forms of Stock Acquisition Loan Agreements entered into as
of June 15, 1995, between the Company and the officers
identified on Schedule I thereto, providing for the
Company's loans to such officers of the amounts
respectively identified on Schedule I thereto, for the
purpose of acquiring the Company's Common Stock, par value
$0.01 per share (incorporated by reference to Exhibit 10.1
to the Company's Quarterly Report on Form 10-Q for the
period ended June 30, 1995, Commission File No. 1-10695).
10.18+ - Severance Agreement dated as of January 1, 1996 between
the Company and Scott D. Sheffield, together with a
schedule identifying substantially identical agreements
between the Company and each of the other Named Executive
Officers identified on Schedule I for the purpose of
defining the payment of certain benefits upon the
termination of the officer's employment under certain
circumstances (incorporated by reference to the Company's
Annual Report on Form 10-K for the year ended December 31,
1995, Commission File No. 1-10695).
10.19+ - Omnibus Amendment to Nonstatutory Stock Option Agreements,
included as part of the Long-term Incentive Plan, dated as
of November 16, 1995, between the Company and Named
Executive Officers identified on Schedule I setting forth
additional details relating to the Long-term Incentive
Plan (incorporated by reference to the Company's Annual
Report on Form 10-K for the year ended December 31, 1995,
Commission File No. 1-10695).
10.20+ - Parker & Parsley Petroleum Company Annual Bonus Program
for Key Employees dated July 13, 1992 (incorporated by
reference to Exhibit 4.1 to the Company's Registration
Statement on Form S-8, Registration No. 33-49612).
10.21+ - Registration of additional shares under Parker & Parsley
Petroleum Company's Long-term Incentive Plan dated April
14, 1992 (incorporated by reference to the Company's
Registration Statement on Form S-8, Registration No.
33-47168).
10.22+ - Parker & Parsley Petroleum Company Non-Employee Director
Equity Compensation Plan dated May 26, 1994 (incorporated
by reference to Exhibit 4.4 to the Company's Registration
Statement on Form S-8, Registration No. 33-79480).
10.23P - Credit Facility Agreement, dated as of July 31, 1996,
between Parker & Parsley Petroleum Company as Borrower and
NationsBank of Texas, N.A., as Administrative Agent, and
CIBC Inc. as Documentation Agent, and Bank of America
National Trust and Savings Association, The Chase
Manhattan Bank, First Union National Bank of North
Carolina, Morgan Guaranty Trust Company of New York and
Wells Fargo Bank. N.A., as Co-Agents and the other lenders
signatory thereto (incorporated by reference to Exhibit
10.1 to the Company's Quarterly Report on Form 10-Q for
the period ended September 30, 1996, Commission File
No.1 -10695).
71
<PAGE>
Exhibit
Number Description Page
21.1* - Subsidiaries of the registrant 73
23.1* - Consent of KPMG Peat Marwick LLP 75
23.2* - Consent of Netherland, Sewell & Associates, Inc. 76
- ---------------
* Filed herewith
+ Executive Compensation Plan or Arrangement filed herewith pursuant
to Item 14(c).
P In accordance with Rule 202 of Regulation S-T, this Exhibit was
filed in paper pursuant to a continuing hardship exemption.
Reports on Form 8-K
No current report on Form 8-K was filed by the Company during the fourth
quarter of 1996.
Exhibits
The exhibits to this Report required to be filed pursuant to Item 14(c)
are listed under "Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K - Listing of Financial Statements and Exhibits - Exhibits" above and
in the "Index to Exhibits" attached hereto.
Financial Statement Schedules
No financial statement schedules are required to be filed as part of this
Report or are inapplicable.
72
<PAGE>
