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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, 1998
Commission File Number: 1-13245
PIONEER NATURAL RESOURCES COMPANY
(Exact name of registrant as specified in its charter)
DELAWARE 75-2702753
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1400 WILLIAMS SQUARE WEST, 5205 N. O'CONNOR BLVD., IRVING,
TEXAS 75039
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:
(972) 444-9001
Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock, par value $.01...................... 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. [ ]
AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY
NON-AFFILIATES OF THE REGISTRANT AS OF FEBRUARY 26,
1999...................................................... $ 485,536,206
NUMBER OF SHARES OF COMMON STOCK OUTSTANDING AS OF FEBRUARY
26, 1999.................................................. 100,300,023
DOCUMENTS INCORPORATED BY REFERENCE:
None
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PIONEER NATURAL RESOURCES COMPANY
CROSS REFERENCE SHEET
Pursuant to National Policy Statement No. 47 (Canada)
(Annual Information Form ("AIF"))
ITEM NUMBER AND CAPTION OF AIF HEADING OR LOCATION IN FORM 10-K
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1. Incorporation Item 1. Business
2. General Development of the Business Item 1. Business
3. Narrative Description of the Business Item 1. Business
Item 2. Properties
4. Selected Consolidated Financial Information Item 6. Selected Financial Data
Item 8. Financial Statements and
Supplementary Data
5. Management's Discussion and Analysis Item 7. Management's Discussion and Analysis
of Financial Conditions and Results of
Operations
Item 7A. Quantitative and Qualitative
Disclosures About Market Risk
6. Market for Securities Item 5. Market for Registrant's Common Stock
and Related Stockholder Matters
7. Directors and Officers Item 10. Directors and Executive Officers of
the Registrant
8. Additional Information Item 11. Executive Compensation
Item 12. Security Ownership of Certain
Beneficial Owners and Management
Item 13. Certain Relationships and Related
Transactions
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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
Pioneer Natural Resources Company ("Pioneer," or the "Company") was formed
in April 1997 as a Delaware corporation and, prior to August 7, 1997, had not
conducted any significant activities. Effective as of August 7, 1997, Parker &
Parsley Petroleum Company ("Parker & Parsley"), formerly a Delaware corporation,
and MESA Inc. ("Mesa"), formerly a Texas corporation, completed their business
combination pursuant to an Amended and Restated Agreement and Plan of Merger
dated as of April 6, 1997 (the "Merger Agreement"). On December 18, 1997, the
Company's asset base was significantly expanded by the acquisition of the
Canadian and Argentine oil and gas business of Chauvco Resources Ltd.
("Chauvco"), a publicly traded independent oil and gas company based in Calgary,
Canada.
Both the merger with Mesa and the acquisition of Chauvco were accounted for
as purchases by the Company (formerly Parker & Parsley). As a result, the
historical financial, reserve and other statistical information for the Company
are those of Parker & Parsley prior to August 1997. The Company's financial,
reserve and other statistical information present the addition of Mesa's and
Chauvco's assets and liabilities as acquisitions in August and December 1997,
respectively.
The Company's proved reserves at December 31, 1998 totaled 677 million BOE,
representing $1.6 billion in PV 10 Value. Of the total, United States reserves
represent 78 percent of the BOEs and 74 percent of the PV 10 Value.
The Company's business activities are conducted through wholly-owned
subsidiaries and are comprised of the business activities formerly conducted by
Parker & Parsley, Mesa and Chauvco. Drilling and production operations are
principally located domestically in Texas, Kansas, Oklahoma, Louisiana, New
Mexico and offshore Gulf of Mexico and internationally in Argentina and Canada.
The Company's executive offices are located at 1400 Williams Square West,
5205 N. O'Connor Blvd., Irving, Texas 75039; the Company's telephone number is
(972) 444-9001. The Company maintains other offices in Midland, Texas; Buenos
Aires, Argentina; Calgary, Canada; and Capetown, South Africa. At December 31,
1998, the Company had 1,016 employees, 475 of which were employed in field and
plant operations.
MISSION AND STRATEGIES
The Company's mission is to provide shareholders with superior investment
returns through strategies that maximize Pioneer's long-term profitability and
net asset value. The strategies employed to achieve this mission are anchored by
the Company's long-lived Hugoton and West Panhandle gas fields and Spraberry oil
field reserves and production. Underlying these fields are approximately sixty
percent of the Company's proved oil and gas reserves which have a remaining
production life of approximately forty years. The stable base of oil and gas
production from these fields generate operating cash flows that allow Pioneer
the financial flexibility to protect long-term net asset values during cycles of
depressed oil or gas prices and, during favorable oil and gas price
environments, more aggressively pursue capital investment strategies of: (a)
developing and increasing
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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 and (f)
maintaining financial flexibility to take advantage of additional exploration,
development and acquisition opportunities. Additionally, to further align the
interests of management and shareholders, Pioneer encourages high levels of
equity ownership among senior managers and the Company's Board of Directors. The
Company is committed to continuing to enhance shareholder investment returns
through adherence to these strategies.
BUSINESS ACTIVITIES
BUSINESS ENVIRONMENT
The Company is an independent oil and gas exploration and production
company whose operating cash flows are primarily impacted by production volumes,
realized oil and gas prices, production costs, interest expense and general and
administrative expense.
Approximately sixty percent of Pioneer's proved oil and gas reserves
underlie the Hugoton and West Panhandle gas fields and the Spraberry oil field,
which are characterized by long-lived, relatively stable oil and gas production.
These fields serve to reduce volatility in the Company's short-term production
volumes.
The realized oil and gas prices that Pioneer reports are based on the
market price received for the commodity adjusted by the results of the Company's
hedging activities. See "Marketing of Production" below. Historically, worldwide
oil and gas prices have been volatile and subject to significant changes in
response to real and perceived conditions in world politics, weather patterns
and other fundamental supply and demand variables. Since the third quarter of
1997, there has been a declining trend in world oil prices and, more recently
but to a lesser extent, natural gas prices. During cycles of depressed commodity
prices, such as the current cycle, the Company has the ability to reduce its
capital investments, without a significant impact to production volumes, which
allows the Company to control long-term debt levels and to protect its net asset
values. See "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations".
During 1998, the Company implemented cost containment measures intended to
reduce future production and administrative costs. These measures included the
closings of the Company's regional offices in Oklahoma City, Oklahoma, Corpus
Christi, Texas, and Houston, Texas and the elimination of approximately 350
employee positions. Associated with these measures, the Company recognized
reorganization charges of $33.2 million during 1998. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
Note N to Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data".
The Company's interest expense is essentially dependent upon debt levels
and prevailing interest rates. Pioneer intends to reduce its capital
expenditures during 1999 to approximately $100 million and to divest certain oil
and gas assets in 1999 or 2000 for approximately $500 million to $600 million of
divestment proceeds. See "Asset Divestitures" below. The liquidity provided by
these actions is expected to allow the Company to reduce outstanding
indebtedness during 1999. Although the Company anticipates that these
divestments will occur in 1999 or in 2000, the finalization of the transactions
are contingent upon the Company's ability to find one or more purchasers willing
to purchase the non-strategic assets at prices acceptable to the Company and the
purchasers' ability to complete the transaction. There can be no assurances that
the Company will be successful in completing the divestitures in 1999 or in
2000. See "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations".
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PRODUCTION
The Company focuses its efforts towards maximizing its average daily
production of oil and gas through development and exploratory drilling,
production enhancement activities and acquisitions of producing properties.
Average daily oil and gas production have each increased every year since 1991
with the exception of 1996 when average daily production declined due to
significant property dispositions. Comparing 1993 to 1998, average daily oil and
NGL production has increased 327 percent and average daily gas production has
increased 352 percent, while production costs per BOE have declined 35 percent.
Production, price and cost information with respect to the Company's properties
for each of 1998, 1997 and 1996 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
1994 through the end of 1998, the Company drilled 2,567 gross (1,777 net) wells,
93 percent of which were successfully completed as productive wells, at a total
cost (net to the Company's interest) of $1.3 billion. During 1998, the Company
drilled 568 gross (431 net) wells for a total cost (net to the Company's
interest) of approximately $430 million, 70 percent of which was spent on
development wells and related facilities. The Company's current 1999 capital
expenditure budget is $100 million, which the Company has allocated as follows:
$75 million to exploitation activities, and $25 million to exploration
activities.
The Company believes that its current property base provides a substantial
inventory of prospects for future reserve, production and cash flow growth. The
Company's reserves as of December 31, 1998 include proved undeveloped and proved
developed non-producing reserves of 43.3 million Bbls of oil and NGLs and 369
Bcf of gas. The timing of the development of these reserves will be dependent
upon the commodity price environment, the Company's expected operating cash
flows and the Company's financial condition. 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
Over the past three years, the Company has dedicated an increasing
percentage of its annual exploration/exploitation capital budget to exploratory
projects: 18 percent in 1996, 28 percent in 1997 and 30 percent in 1998. As a
result of the downturn in commodity prices, the Company's 1999 capital budget
has been limited to $100 million and the portion of the budget dedicated to
exploration activities is targeted at approximately $25 million. The Company
currently anticipates that its 1999 exploration efforts, although curtailed,
will be concentrated domestically in the Gulf of Mexico and onshore Gulf Coast
region. The Company will participate in one or two wells in the Gulf of Mexico
deep-water Mississippi Canyon Block 305 and in two wells in either the onshore
Gulf Coast area or in East Texas where several shallower exploration prospects
have been defined from Pioneer's 3-D database. The Company's exploration
programs in South Africa, Gabon, and the Gulf Coast transition zone are targeted
for comprehensive studies that will focus on analysis, ranking and timing of
prospects during 1999. 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.
ASSET DIVESTITURES
The Company regularly reviews its property base for the purpose of
identifying non-strategic assets, the disposition of which would increase
capital resources available for other activities and 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.
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During 1998 and 1997, the Company's asset disposition activity primarily
consisted of the sale of oil and gas properties for proceeds of $21.9 million
and $115.7 million, respectively, which resulted in a 1998 pre-tax net loss of
$445 thousand and a 1997 pre-tax net gain of $5.0 million. During the year ended
December 31, 1996, the Company sold certain wholly-owned subsidiaries for
proceeds of $183.2 million resulting in a pre-tax gain of $83.3 million and
certain non-strategic domestic assets for proceeds of $58.4 million that
resulted in the recognition of a pre-tax net gain of $13.8 million. 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.
The Company has announced its intentions to sell non-strategic oil and gas
assets for gross proceeds of $500 million to $600 million in 1999 and 2000. In
February 1998, the Company announced its intentions to sell domestic
non-strategic properties and subsequently signed a purchase and sale agreement
(the "Agreement") to sell certain oil and gas properties representing
approximately 10 percent of the Company's proved reserves. In December 1998,
Pioneer announced the re-negotiation of the Agreement and the sale of an
exclusive and irrevocable option to the counter-parties to purchase the same
properties on or before March 31, 1999. The proceeds associated with the
re-negotiated terms total $335 million, of which $41 million represents an
irrevocable option fee that has been paid to the Company as of December 31,
1998. The Company's realization of the remaining $294 million of proceeds, which
would be used to reduce outstanding indebtedness, is primarily dependent upon
the buyer's ability to finance the purchase and certain other contingencies
defined in the Agreement. As a result, there can be no assurance that the
divestiture of any or all of the properties will be completed or that the
remaining proceeds will be realized. The Company is continuing to review its
portfolio of oil and gas properties to identify other non-strategic properties
for divestiture. The realization of the Company's plans to divest of the other
non-strategic oil and gas properties in 1999 or in 2000 is contingent upon,
among other things, the Company's ability to find one or more purchasers'
willing to purchase the non-strategic assets at prices acceptable to the Company
and the purchasers' ability to complete the transaction. There can be no
assurances that the Company will be successful in completing the divestitures in
1999 or in 2000.
The Company anticipates that it will continue to sell non-strategic
properties from time to time to increase capital resources available for other
activities, to achieve operating and administrative efficiencies and to improve
profitability.
ACQUISITION ACTIVITIES
GENERAL. The Company regularly seeks to acquire properties that complement
its operations and provide further 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 development or exploration opportunities. During 1998,
the Company reduced its emphasis on major acquisitions and, instead,
concentrated its efforts on maximizing the value of the properties acquired in
1997. During 1997, the Company completed three major transactions: the merger
with Mesa for total consideration of $991.0 million, the acquisition of Chauvco
for total consideration of $721.4 million and the acquisition of assets from
America Cometra for total consideration of $130 million. These acquisitions
added significantly to the Company's exploratory and development drilling
opportunities, balanced the Company's reserve mix between oil and natural gas,
increased the scale of its operations in the Mid Continent region, the offshore
Gulf Coast region, Argentina and Canada and provided the Company with a
significant base of operations and experienced personnel for its areas of
geographic focus, including international areas. During 1996, the Company
focused on smaller acquisitions of properties that exhibited one or more of the
following characteristics: properties that were near or otherwise complemented
the Company's existing properties, properties that represented additional
working interests in Company-operated properties or properties that provided the
Company with strategic exploitation or exploration opportunities. In 1996,
aggregate expenditures to acquire such interests and properties amounted to
approximately $21 million.
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
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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 through debt management.
As with any organization, the Company has experienced various debt levels
in recent years as it has responded to strategic opportunities. During 1996 and
1995, 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. The Company was able to
reduce its debt level significantly each year through the application of
proceeds from the dispositions of assets that the Company had identified as
non-strategic (see "Asset Divestitures" above). In 1997, the Company's debt
level increased as a result of the assumption of the debt of Mesa and Chauvco.
In 1998, severe commodity price declines reduced cash flows from operating
activities, causing the Company to increase debt to finance committed capital
investments. As a result of the increases in debt and reductions in
shareholders' equity primarily resulting from 1998 and 1997 non-cash asset
impairment provisions (see Note M and Note O of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data"),
the Company's debt as a percentage of total capitalization has increased to 73
percent and 56 percent at December 31, 1998 and 1997, respectively. In 1999, the
Company intends, as it did in 1996 and 1995, to take deliberate actions to
reduce debt through reductions in capital investments and the use of operating
cash flows and net proceeds from the divestiture of non-strategic assets.
MARKETING OF PRODUCTION
GENERAL. Production from the Company's properties is marketed consistent
with industry practices. 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, commodity quality and
prevailing supply conditions.
SIGNIFICANT PURCHASERS. During 1998, the Company's primary purchaser of
crude oil was Genesis Crude Oil L.P. ("Genesis") and the Company's primary
purchaser of natural gas liquids was Williams Energy Services ("Williams").
Approximately 10 percent and 10 percent of the Company's 1998 oil and gas
revenues were attributable to sales to Genesis and Williams, respectively.
During 1998, the Company marketed its natural gas to a variety of purchasers,
none of which accounted for 10 percent 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.
See "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations" for a description of the Company's results of its
hedging activities; "Item 7A. Quantitative and Qualitative Disclosures About
Market Risk" for discussions regarding the hedging strategies used by the
Company to mitigate commodity price risks associated with crude oil, natural gas
liquids and natural gas sales; and Note J of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for
a description of the Company's open hedge positions at December 31, 1998 and the
related prices to be realized.
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OPERATIONS BY GEOGRAPHIC AREA
The Company operates in one industry segment. During 1998, the Company
principally had oil and gas producing activities in the United States, Canada
and Argentina and had exploration activities primarily in the United States,
Canada, Argentina and South Africa. During 1997 and 1996, prior to the
acquisition of Chauvco, the Company did not have significant operations in
geographic areas other than the United States. See Note P of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for geographic operating segment information.
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 financial and other
resources greater than those of 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 and gas production capacities 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 equivalent to or lower than those currently available. A continuation of
the current commodity price environment or a further decline in the price of oil
or gas will continue to adversely affect the Company's revenues, profitability
and cash flow.
During most of 1996 and 1997, the Company benefited from higher oil prices
as compared to previous years. However, during the fourth quarter of 1997, oil
prices began a downward trend that has continued through March 1999. A
continuation of the present oil price environment will prolong the associated
adverse effect on the Company's revenues and operating cash flow, and may result
in further downward adjustments to the Company's current 1999 capital budget of
$100 million. Additionally, declines in the outlook for future price levels have
contributed to 1998 and 1997 non-cash impairment provisions to reduce the
carrying values of oil and gas properties and in a non-cash valuation adjustment
to the Company's deferred tax assets. See Note M and Note O of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for specific disclosures relative to the impairments and
valuation provisions. Continued declines in commodity prices could result in
additional impairment or valuation provisions in the future.
GOVERNMENTAL REGULATION. Oil and gas exploration and production are subject
to various types of regulation by local, state, federal and foreign 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 non-jurisdictional 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
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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 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.
Additional proposals and proceedings that might affect the oil and gas
industry are considered from time to time by Congress, FERC, state regulatory
bodies, the courts and foreign governments. 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, local and foreign 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 its results of operations
or financial condition, 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
non-hazardous 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
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remediate previously disposed wastes or property contamination or to perform
remedial plugging operations to prevent future contamination.
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,
the United States Mineral Management Service (the "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
OCSLA). 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 the Company's results of operations and financial
condition. 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 results of operations and financial
condition.
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The Company employs an environmental specialist charged with monitoring
regulatory compliance. The Company performs 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.
RISKS ASSOCIATED WITH BUSINESS ACTIVITIES
The nature of the business activities conducted by the Company subjects it
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
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
continuation of the significantly lower oil and gas prices experienced in 1998,
as compared to prior years, or a further decline in the prices of oil or gas
will 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, a valuation adjustment
to the Company's deferred tax assets and a reduction in the Company's
commitments under its bank credit facilities.
RISKS OF DRILLING ACTIVITIES. As noted under "Item 1. Business -- Business
Activities," of the total 1999 capital budget of $100 million, the Company
anticipates spending approximately $75 million on development activities and $25
million on exploration activities. 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.
RISKS ASSOCIATED WITH UNPROVED PROPERTIES. At December 31, 1998 and 1997,
the Company had unproved property costs of $342.6 million and $545.1 million,
respectively. United States generally accepted accounting principles require
periodic evaluation of these costs on a project-by-project basis in comparison
to their estimated value. These evaluations will be affected by results of
exploration activities, commodity price outlooks, planned future sales or
expiration of all or a portion of such projects. If the quantity of potential
reserves determined by such evaluations are not sufficient to fully recover the
cost invested in each project, the Company may be required to recognize
significant non-cash charges in the earnings of future periods. There can be no
assurance that economic reserves will be determined to exist for such projects.
ACQUISITIONS. Acquisitions of producing oil and gas properties have been a
key element of the Company's growth. The Company's growth following the full
development of its existing 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 non-strategic assets, the disposition of which would
increase capital resources available for other activities and create
organizational and operational efficiencies. Various factors could materially
affect the ability of the
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Company to dispose of non-strategic assets, including the availability of
purchasers willing to purchase the non-strategic assets at prices acceptable to
the Company.
RISKS ASSOCIATED WITH OPERATION OF NATURAL GAS PROCESSING PLANTS. The
Company owns interests in seven natural gas processing plants and operates three
of those plants, although the net revenues derived from natural gas processing
during 1998 and 1997 represented only one percent 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.
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,
state and foreign 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".
RISKS ASSOCIATED WITH DEBT. At December 31, 1998 and 1997, the Company had
total debt outstanding of $2.2 billion and $1.9 billion, respectively. As of
December 31, 1998, approximately 55 percent of the Company's total debt was
comprised of variable rate debt that is sensitive to changes in market interest
rates. Such variable rate debt is primarily comprised of borrowings under credit
facilities. During 1999, the Company must reduce its borrowings by $306.5
million to comply with commitment reduction provisions specified in the credit
facilities and other current debt obligations. The Company is also subject to
certain debt covenants that are defined in the credit facilities. See "Interest
rate sensitivity" included in "Item 7A. Quantitative and Qualitative Disclosures
About Market Risk" for additional information regarding the Company's risks
associated interest rate sensitivity. Also, see "1999 Outlook -- Credit
facilities" included in "Item 7. Managements' Discussion and Analysis of
Financial Condition and Results of Operations" and Note E of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for discussions relative to the Company's credit facilities.
GOVERNMENT REGULATION. The Company's business is regulated by a variety of
federal, state, local and foreign laws and regulations. There can be no
assurance that present or future regulations will not adversely
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affect the Company's business and operations. See "Item 1.
Business -- Competition, Markets and Regulation".
RISKS OF INTERNATIONAL OPERATIONS. At December 31, 1998, approximately 22
percent of the Company's proved reserves of oil and gas were located outside the
United States (14 percent in Argentina and 8 percent in Canada). 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, natural gas liquids and
condensate.
"Bcf" means one billion cubic feet.
"Bcfe" means a billion cubic feet 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 oil to
natural gas, being approximately one barrel of oil per six Mcf of gas.
"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 six Mcf of natural gas per Bbl of oil.
"Btu" means British thermal unit and represents the amount of heat needed
to raise the temperature of one pound of water one degree Fahrenheit.
"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.
"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
wells.
"NGLs" means natural gas liquids.
"NYMEX" means The New York Mercantile Exchange.
"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.
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"PV 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 United States Securities and
Exchange Commission ("SEC") (generally using prices and costs in effect at the
specified date and a 10 percent discount rate). The reserve estimates for 1998
utilize an oil price of $10.09 per Bbl (reflecting adjustments for oil quality
and gathering and transportation costs), an NGL price of $6.81 per Bbl and a gas
price of $1.64 per Mcf (reflecting adjustments for Btu content, gathering and
transportation costs and gas processing and shrinkage).
ITEM 2. PROPERTIES
The information included in this Report about the Company's proved oil and
gas reserves at December 31, 1998, including estimated quantities and PV 10
value, is based on reserve reports 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, which are based on various assumptions, including those
prescribed by the SEC. 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
PV 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 PV 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.
PV 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 SEC.
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. PV 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 1998 to any federal authority or agency, other than the SEC.
PROVED RESERVES
The Company's proved reserves totaled 676.8 million BOE at December 31,
1998, 761.6 million BOE at December 31, 1997 and 302.2 million BOE at December
31, 1996, representing $1.6 billion, $3.1 billion and $2.3 billion,
respectively, in PV 10 value. Downward revisions of reserve quantities as a
result of the decline in commodity prices was the primary reason for the
decrease in reserves and PV 10 value during 1998.
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On a BOE basis, 90 percent of the Company's total proved reserves at
December 31, 1998 are proved developed reserves. Based on reserve information as
of December 31, 1998 and using the Company's reserve report production
information for 1999, the reserve-to-production ratio associated with the
Company's proved reserves is 11 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, 1998.
PROVED OIL AND GAS RESERVES
1998 AVERAGE
PROVED RESERVES AS OF DECEMBER 31, 1998 DAILY PRODUCTION(a)
------------------------------------------ --------------------------
OIL NATURAL PV 10 OIL NATURAL
& NGLS GAS VALUE & NGLS GAS
(MBbls) (MMcf) MBOE (000) (BBls) (Mcf) BOE
------- --------- ------- ---------- ------ ------- -------
United States.......... 269,638 1,545,644 527,246 $1,226,869 69,390 377,373 132,285
Argentina.............. 24,219 428,334 95,608 232,799 9,041 73,427 21,279
Canada................. 12,447 249,230 53,985 189,140 9,852 53,072 18,697
------- --------- ------- ---------- ------ ------- -------
Total............. 306,304 2,223,208 676,839 $1,648,808 88,283 503,872 172,261
======= ========= ======= ========== ====== ======= =======
- ---------------
(a) The 1998 average daily production is calculated using a 365-day year and
without making pro forma adjustments for any acquisitions, divestitures or
drilling activity that occurred during the year.
RESERVE REPLACEMENT
For the first time in almost a decade, the Company was unable to replace
its annual production volumes with proved reserves of crude oil, NGLs and
natural gas, stated on an energy equivalent basis. During 1998, the Company's
proved reserves declined 84.8 million BOE including 62.9 million BOE related to
production, 31.2 million BOE related to downward reserve revisions and 2.5
million BOE related to asset sales. Discoveries and extensions of 11.8 million
BOE partially offset these reductions. 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 downward revisions in 1998 relate
primarily to the decline in commodity prices during 1998. The Company's reserves
as of December 31, 1998 were estimated using a price of $10.09 per Bbl of oil,
$6.81 per Bbl of NGLs and $1.64 per Mcf of gas. Should prices increase or
decline in future periods, reserves may be revised upward or downward for
quantities which may be economical or uneconomical to produce at higher or lower
prices, respectively.
The Company's 1998 reserve replacement rate on a BOE basis was negative due
to the severe decline in commodity prices during 1998. Previous reserve
replacement performance rates were 1,450 percent in 1997 (1,375 percent for oil
and 1,528 percent for gas) and 314 percent in 1996 (398 percent for oil and 239
percent for gas). For the three-year period ended December 31, 1998, the average
reserve replacement rate was 465 percent, as compared to a three-year average
replacement rate of 769 percent in 1997 and 377 percent in 1996. During 1998,
the reserve replacement rate was primarily influenced by the decline in
commodity prices which resulted in significant downward reserve revisions.
During 1997, the Company's reserve replacement rate was primarily the product of
its acquisition activities. In 1996, the reserve replacement rate was influenced
primarily by exploration and development activities.
FINDING COST
The Company's acquisition and finding cost per BOE for 1998 was negative as
compared to the 1997 and 1996 acquisition and finding costs of $8.23 and $3.10
per BOE, respectively. The negative rate in 1998 was a result of downward
reserve revisions related to the decline in commodity prices during 1998. The
rate in 1997 was a result of the fair value associated with Mesa's and Chauvco's
long-lived, low production cost reserves. The average acquisition and finding
cost for the three-year period from 1996 to 1998 was $8.65 per BOE representing
a 23 percent increase from the 1997 three-year average rate of $7.04.
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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 percent oil and NGLs and 50
percent natural gas is in the best long-term interests of the Company and its
stockholders. The Company's reserve mix was 45 percent oil and NGLs and 55
percent gas at December 31, 1998, and its production mix was 51 percent oil and
NGLs and 49 percent gas during 1998.
DESCRIPTION OF PROPERTIES
As of December 31, 1998, the Company has operations in the United States,
Argentina and Canada, and to a lesser extent, exploration opportunities in
Africa.
DOMESTIC. The Company's domestic operations are principally located in the
Gulf Coast, Mid Continent and Permian Basin areas. In the Gulf Coast area, the
Company is focused on reserve and production growth through a balanced portfolio
of development and exploration activities. To accomplish this, the Company has
devoted most of its domestic exploration efforts to this area, as well as its
investment in and utilization of 3-D seismic technology. During 1998, the
Company expended $167 million to drill 38 development and eight exploratory
wells and more importantly, significantly enhanced its library of seismic data
for future exploration activities.
During 1999, the Company's exploration drilling will be concentrated in the
Gulf of Mexico and the onshore Gulf Coast area. The Company will participate in
the drilling of one or two wells in its deep-water Mississippi Canyon Block 305.
The Company has a 25 percent working interest (21.875 percent net revenue
interest) in the block; however, Pioneer is responsible for 50 percent of the
before casing point drilling costs in the first exploratory well drilled.
Drilling began on the first well in this block during January 1999. The well is
scheduled for preliminary evaluations in March. Two additional wells are planned
for 1999 onshore in the Gulf Coast area or in East Texas where several shallower
exploration prospects have been defined by the Company's 3-D database.
The Mid Continent area includes properties located in Kansas, the Texas
Panhandle, Oklahoma and Arkansas. By far, the largest of these assets is the
Company's Hugoton field followed by the West Panhandle field, both acquired from
Mesa in August 1997. These two fields combined account for approximately $548
million of the Company's $1.6 billion of PV 10 reserve value at December 31,
1998. During 1998, the Company spent approximately $26 million on exploratory
and development drilling in the Mid Continent area. This activity included the
drilling of 89 development wells and two exploratory wells.
Hugoton field. The Hugoton field in southwest Kansas is one of the largest
producing gas fields in the continental United States. The Company's Hugoton
properties represent approximately 13 percent of the proved reserves in the
field and are located on over 237,000 net acres, covering approximately 400
square miles. The Company has working interest in approximately 1,200 wells in
the Hugoton field, almost 1,000 of which it operates, and royalty interest in
approximately 750 wells. The Company owns substantially all of the gathering and
processing facilities, primarily the Satanta plant, that service its production
from the Hugoton field. Such ownership allows the Company to control the
production, gathering, processing and sale of its gas and associated NGLs.
Production in the Hugoton field is subject to allowables set by state
regulators, but the Company's Hugoton operated properties are capable of
producing approximately 150 MMcf of wet gas per day (i.e., gas production at the
wellhead before processing and before reduction for royalties). The Company
estimates that it and other major producers in the Hugoton field produced at or
near capacity in 1998.
The Company is considering plans to submit an application to the Kansas
Corporation Commission (the "KCC") to allow infill drilling into the Council
Grove Formation. The Company believes that such infill drilling could increase
production from its Hugoton properties. There can be no assurance that the
application will be approved or as to the timing of receipt of such approval if
such approval is obtained.
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West Panhandle field. The West Panhandle properties are located in the
panhandle region of Texas where initial production commenced in 1918. These
stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite,
Granite Wash and fractured Granite formations at depths no greater than 3,500
feet. The Company's natural gas in the West Panhandle field is produced from
approximately 600 wells on more than 241,000 gross (185,000 net) acres covering
over 375 square miles. The Company's wellhead gas produced from the West
Panhandle field contains a high quantity of NGLs, yielding relatively greater
NGL volumes than realized from many other natural gas fields. The Company
operates the wells and production equipment and Colorado Interstate Gas Company
owns and operates the gathering system.
The production from the West Panhandle field is processed through the
Company-owned Fain natural gas processing plant. In February 1997, the Company
initiated a project to add nitrogen rejection capabilities at the Fain Plant.
This project, which was completed in mid-1998, allows the Company to recover a
greater percentage of the helium in the processed gas; increase NGL recoveries;
and upgrade residue quality improving marketing flexibility.
As of December 31, 1998, the Company's West Panhandle properties
represented approximately 13 percent of the Company's equivalent proved reserves
and approximately nine percent of the present value of estimated future net cash
flows, determined in accordance with SEC guidelines. The Company has identified
over 70 locations that have additional production potential that the Company
plans to redrill in the next few years.
Since the early 1960's, the Company has been involved in acquisition and
development activities in fields in the Permian Basin area which includes all of
West Texas and Southeastern New Mexico. Of the $411 million of PV 10 value
contained in the properties in the Permian Basin area, the Spraberry field
accounts for $294 million. Along with the Spraberry field, the Iatan field in
Mitchell County, Texas, the Dagger Draw field in Eddy County, New Mexico and the
Ozona field in Crockett and Sutton Counties of Texas are significant to the
Company's Permian Basin area's operations in terms of existing production,
production and reserve growth, and identification of additional drilling
locations.
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 (CO(2)) flood implementation. During 1998, the Company
expended $113 million to drill 271 development and 13 exploratory wells. Wells
being drilled at the end of 1998 are being shut-in temporarily in anticipation
of future increases in oil prices. When this takes place, the Company will be in
a position to increase its oil production rather quickly. In addition, the
Company anticipates spending $9 million in 1999 in the Permian Basin area to
drill approximately 50 wells which will also be shut-in temporarily pending
future increases in oil prices. Development activities will account for the
majority of these planned expenditures.
Spraberry field. 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; however, until the late 1980's there
was very limited development activity in the field. 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. The Company initiated an aggressive
optimization and automation cost cutting program in 1998, which reduced
operating expenses. This program will continue in 1999 and the Company believes
that an additional 10 percent reduction can be achieved. In February 1997, the
Texas Railroad Commission (which regulates oil and gas production) entered a
favorable order on the
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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 per 40 acres.
INTERNATIONAL. The acquisition of Chauvco provided the Company with a
significant presence in Argentina and Canada, representing 14 percent and 11
percent, respectively, of the Company's PV 10 value at December 31, 1998. The
Company's Argentine properties are primarily located in the Tierra del Fuego and
Neuquen basins. The Company's share of Argentine production during 1998 averaged
21.3 MBOE's per day. The Tierra del Fuego production concession is located in
the extreme southern portion of Argentina, approximately 1,500 miles south of
the country's capital, Buenos Aires. Crude oil, natural gas, condensate and NGLs
are produced from six separate fields in which the Company has a 35 percent
working interest. Recent expansion of gas processing facilities and completed
pipeline connections at Tierra del Fuego will allow handling of increased
production volumes committed for delivery under a gas contract to a
petrochemical plant in Chile. Natural gas deliveries under the contract to the
methanol plant in Chile averaged 50 MMcf per day during 1998.
The Company's operated production in Argentina is concentrated in the
Neuquen Basin which is located about 925 miles southwest of the country's
capital city and just to the east of the Andes Mountains. Crude oil and natural
gas are produced from the Loma Negra/NI Block, the Dadin Block, the Al Norte de
la Dorsal Block and the Neuquen del Medio Block in which the Company has a 100
percent working interest. A commercial discovery was made in the newly acquired
Bajo Baguales Block in which the Company has a 65 percent interest.
During 1998, the Company drilled 46 development wells and 22 exploratory
wells in Argentina. The Company plans to spend $24 million on gas development
opportunities in Argentina during 1999.
The Company's Canadian producing properties are primarily located in
Alberta and British Columbia, Canada in the following areas: Chinchaga, Martin
Creek, Thompson Lake/Alliance, Rycroft, Lookout Butte and David. During 1998,
these properties produced an average of 18.7 MBOE's per day, net to the
Company's interest. In addition, during 1998 the Company drilled 60 development
wells and 14 exploratory wells primarily in Chinchaga and Martin Creek areas.
These properties currently include 29 new development well locations that are
scheduled to be drilled in 1999.
In addition to the proved producing assets of Chauvco and Mesa, the Company
acquired a substantial inventory of unproved oil and gas properties during 1997
which will provide the Company with many exploration opportunities with the
potential for significant reserve additions. Although the acquisition of a
portfolio of unproved properties represents an exciting challenge to the
Company's team of engineers, geologists and geophysicists, such opportunities
are not without risk. United States generally accepted accounting principles
require periodic evaluation of these costs on a project-by-project basis in
comparison to their estimated value. During 1998, the Company reduced the
carrying value of its unproved oil and gas properties by $147.3 million. See
Note M of Notes to Consolidated Financial Statements in "Item 8. Financial
Statements and Supplementary Data". An unproved property may be impaired if the
Company does not intend to drill the prospect as a result of downward revisions
to potential proved reserves, if the results of exploration or the Company's
outlook for future commodity prices indicate that the potential reserves are not
sufficient to generate net cash flows to recover the investment required by the
project, or if the Company intends to sell the property for less than its
carrying value. There can be no assurance that economic reserves will be
determined to exist for such projects in the future.
On a smaller scale, the Company has entered into agreements to explore in
the African nations of South Africa and Gabon. The South African agreements
cover over 13 million acres along the southern coast of South Africa, generally
in water depths less than 650 feet. During 1998, the Company participated in the
drilling of five wells in South Africa. Of the five wells drilled, two
discovered hydrocarbons; however, future activities associated with these
discoveries is under evaluation given the current economic environment of the
oil and gas industry. In 1998, the Company incurred $16.0 million of drilling
and seismic costs in South Africa. During 1999, the Company has targeted both
South Africa and Gabon for comprehensive studies that will focus on analysis,
ranking and timing of prospects. No new wells are planned during 1999 in South
Africa
18
19
while the Company evaluates farmout and other risk sharing opportunities.
Seismic studies are currently planned to commence in Gabon during late 1999 or
early 2000.
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, 1998, 1997 and 1996.
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, 1998, 1997 and 1996.
PRODUCTION, PRICE AND COST DATA(a)
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------
1998 1997
----------------------------------------- -------------------------------
UNITED UNITED
STATES ARGENTINA CANADA TOTAL STATES ARGENTINA TOTAL
-------- --------- ------- -------- -------- --------- --------
Production information:
Annual production:
Oil (MBbls).................. 15,167 3,072 3,315 21,554 13,470 148 13,618
NGLs (MBbls)................. 10,160 228 281 10,669 4,267 -- 4,267
Gas (MMcf)................... 137,741 26,801 19,371 183,913 104,868 -- 104,868
Total (MBOE)................. 48,284 7,767 6,824 62,875 35,215 148 35,363
Average daily production:
Oil (Bbls)................... 41,555 8,415 9,082 59,052 36,903 406 37,309
NGLs (Bbls).................. 27,835 626 770 29,231 11,691 -- 11,691
Gas (Mcf).................... 377,373 73,427 53,072 503,872 287,309 -- 287,309
Total (BOE).................. 132,285 21,279 18,697 172,261 96,479 406 96,885
Average prices:
Oil (per Bbl)................ $ 13.96 $ 11.00 $ 10.96 $ 13.08 $ 18.50 $19.68 $ 18.51
NGLs (per Bbl)............... $ 8.86 $ 9.83 $ 9.54 $ 8.90 $ 12.59 $ -- $ 12.59
Gas (per Mcf)................ $ 2.01 $ 1.09 $ 1.45 $ 1.82 $ 2.20 $ -- $ 2.20
Revenue (per BOE)............ $ 11.99 $ 8.40 $ 9.83 $ 11.32 $ 15.16 $19.68 $ 15.18
Average costs:
Production costs (per BOE):
Lease operating expense.... $ 3.04 $ 2.57 $ 3.56 $ 3.04 $ 3.01 $ 5.47 $ 3.02
Production taxes........... .50 .15 -- .40 .81 .19 .81
Workovers.................. .14 -- .10 .12 .25 -- .25
-------- ------- ------- -------- -------- ------ --------
Total.................... $ 3.68 $ 2.72 $ 3.66 $ 3.56 $ 4.07 $ 5.66 $ 4.08
Depletion expense (per BOE).. $ 4.96 $ 5.42 $ 5.95 $ 5.13 $ 5.77 $ 8.70 $ 5.78
YEAR ENDED DECEMBER 31,
----------------------------------
1996
----------------------------------
AUSTRALIA(b)
UNITED AND
STATES ARGENTINA TOTAL
-------- ------------ --------
Production information:
Annual production:
Oil (MBbls).................. 10,872 403 11,275
NGLs (MBbls)................. -- -- --
Gas (MMcf)................... 73,924 1,927 75,851
Total (MBOE)................. 23,193 723 23,916
Average daily production:
Oil (Bbls)................... 29,705 1,100 30,805
NGLs (Bbls).................. -- -- --
Gas (Mcf).................... 201,979 5,265 207,244
Total (BOE).................. 63,368 1,978 65,346
Average prices:
Oil (per Bbl)................ $ 19.96 $ 19.81 $ 19.96
NGLs (per Bbl)............... $ -- $ -- $ --
Gas (per Mcf)................ $ 2.27 $ 1.95 $ 2.27
Revenue (per BOE)............ $ 16.61 $ 16.21 $ 16.60
Average costs:
Production costs (per BOE):
Lease operating expense.... $ 3.39 $ 4.75 $ 3.43
Production taxes........... .94 -- .91
Workovers.................. .28 -- .27
-------- ------- --------
Total.................... $ 4.61 $ 4.75 $ 4.61
Depletion expense (per BOE).. $ 4.25 $ 5.73 $ 4.30
- ---------------
(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.
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20
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,
1998, 1997 and 1996.
PRODUCTIVE WELLS(A)
GROSS PRODUCTIVE WELLS NET PRODUCTIVE WELLS
---------------------- ---------------------
OIL GAS TOTAL OIL GAS TOTAL
----- ----- ------ ----- ----- -----
Year ended December 31, 1998:
United States................................ 6,280 4,130 10,410 3,578 2,443 6,021
Argentina.................................... 443 158 601 298 103 401
Canada....................................... 1,719 454 2,173 715 241 956
----- ----- ------ ----- ----- -----
Total........................................ 8,442 4,742 13,184 4,591 2,787 7,378
===== ===== ====== ===== ===== =====
Year ended December 31, 1997:
United States................................ 6,075 3,931 10,006 3,399 2,326 5,725
Argentina.................................... 342 122 464 228 84 312
Canada....................................... 1,666 428 2,094 667 202 869
----- ----- ------ ----- ----- -----
Total........................................ 8,083 4,481 12,564 4,294 2,612 6,906
===== ===== ====== ===== ===== =====
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
===== ===== ====== ===== ===== =====
- ---------------
(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, 1998, the Company owned interests in 181 wells containing
multiple completions.
LEASEHOLD ACREAGE. The following table sets forth information about the
Company's developed, undeveloped and royalty leasehold acreage as of December
31, 1998.
LEASEHOLD ACREAGE
DEVELOPED ACREAGE UNDEVELOPED ACREAGE
----------------------- ------------------------ ROYALTY
GROSS ACRES NET ACRES GROSS ACRES NET ACRES ACREAGE
----------- --------- ----------- ---------- -------
United States...................... 1,505,137 958,845 1,230,934 705,543 422,246
Canada............................. 332,000 151,000 620,000 397,000 --
Argentina.......................... 655,000 256,000 1,152,000 737,000 --
South Africa and Gabon............. -- -- 13,813,937 13,513,937 --
--------- --------- ---------- ---------- -------
Total.............................. 2,492,137 1,365,845 16,816,871 15,353,480 422,246
========= ========= ========== ========== =======
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21
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, 1998, 1997 and 1996.
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.
DRILLING ACTIVITIES
GROSS WELLS NET WELLS
------------------------ ------------------------
YEAR ENDED DECEMBER 31, YEAR ENDED DECEMBER 31,
------------------------ ------------------------
1998 1997 1996(b) 1998 1997 1996(b)
----- ----- -------- ----- ------ -------
United States:
Productive wells:
Development............................... 385 483 535 285.9 341.2 362.9
Exploratory............................... 18 38 37 13.4 23.8 24.2
Dry holes:
Development............................... 13 18 7 8.8 8.8 4.4
Exploratory............................... 5 46 10 3.0 30.3 6.0
--- --- --- ----- ------ -----
421 585 589 311.1 404.1 397.5
--- --- --- ----- ------ -----
Argentina:
Productive wells:
Development............................... 41 4 3 39.1 .6 .4
Exploratory............................... 11 1 -- 10.6 .1 --
Dry holes:
Development............................... 5 -- -- 5.0 -- --
Exploratory............................... 11 1 3 9.7 .1 .4
--- --- --- ----- ------ -----
68 6 6 64.4 .8 .8
--- --- --- ----- ------ -----
Canada:
Productive wells:
Development............................... 54 -- -- 37.1 -- --
Exploratory............................... 10 -- -- 7.2 -- --
Dry holes:
Development............................... 6 -- -- 5.4 -- --
Exploratory............................... 4 -- -- 3.0 -- --
--- --- --- ----- ------ -----
74 -- -- 52.7 -- --
--- --- --- ----- ------ -----
Other foreign:
Productive wells:
Development............................... -- -- 2 -- -- .3
Exploratory............................... 2 -- -- .7 -- --
Dry holes:
Development............................... -- -- 1 -- -- .2
Exploratory............................... 3 1 1 1.7 .4 .2
--- --- --- ----- ------ -----
5 1 4 2.4 .4 .7
--- --- --- ----- ------ -----
Total................................ 568 592 599 430.6 405.3 399.0
=== === === ===== ====== =====
Success ratio(a)............................... 92% 89% 96% 92% 90% 97%
- ---------------
(a) Represents those wells that were successfully completed as productive
wells.
(b) The 1996 Australian amounts include only three months of activity related
to the Company's Australian properties prior to their sale in March 1996.
21
22
The following table sets forth information about the Company's wells that
were in progress at December 31, 1998.
GROSS WELLS NET WELLS
----------- ---------
United States:
Development............................................... 58 43.7
Exploratory............................................... 8 3.8
-- ----
66 47.5
-- ----
Argentina:
Development............................................... 3 3.0
Exploratory............................................... 4 3.4
-- ----
7 6.4
-- ----
Canada:
Development............................................... 2 1.7
Exploratory............................................... 1 .3
-- ----
3 2.0
-- ----
Total............................................. 76 55.9
== ====
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings, which are described
under "Legal actions" in Note H of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data". The Company
is also party to other litigation incidental to its business. The claims for
damages from such other legal actions are not in excess of 10 percent of the
Company's current assets and the Company believes none of these actions to be
material.
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 and the Toronto Stock Exchange under the symbol "PXD". 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
----- ---- --------------
1998
Fourth quarter............................................ $16 $ 7 3/4 --
Third quarter............................................. $24 11/16 $13 1/4 $.05
Second quarter............................................ $25 15/16 $21 3/8 --
First quarter............................................. $30 $20 5/8 $.05
1997
Fourth quarter............................................ $43 13/16 $25 5/8 --
Third quarter............................................. $44 3/8 $34 3/4 $.05
Second quarter............................................ $36 3/16 $28 1/2 --
First quarter............................................. $37 5/8 $28 7/8 $.05
On February 26, 1999, the last reported sales price of the Company's Common
Stock, as reported in the New York Stock Exchange composite transactions, was
$5 3/16 per share.
22
23
As of February 26, 1999, the Company's Common Stock was held by
approximately 35,000 holders of record, representing approximately 80,000 total
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; however, due to the current trend of declining commodity prices, the
Company's Board of Directors has elected to discontinue the declaration of cash
dividends in 1999 and future years.
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".
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1998 1997(a) 1996 1995 1994(b)
-------- --------- -------- -------- --------
(IN MILLIONS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas.......................... $ 711.5 $ 536.8 $ 396.9 $ 375.7 $ 337.6
Natural gas processing............... -- -- 23.8 33.2 39.2
Gas marketing........................ -- -- -- 76.8 103.0
Interest and other................... 10.4 4.3 17.5 11.4 6.9
Gain (loss) on disposition of assets,
net(c)............................. (.4) 4.9 97.1 16.6 9.5
-------- --------- -------- -------- --------
721.5 546.0 535.3 513.7 496.2
-------- --------- -------- -------- --------
Costs and expenses:
Oil and gas production............... 223.5 144.2 110.3 130.9 127.1
Natural gas processing............... -- -- 12.5 25.9 33.6
Gas marketing........................ -- -- -- 75.7 101.5
Depletion, depreciation and
amortization....................... 337.3 212.4 112.1 159.1 145.4
Impairment of oil and gas properties
and natural gas processing
facilities......................... 459.5 1,356.4 -- 130.5 --
Exploration and abandonments......... 121.9 77.2 23.0 27.5 25.2
General and administrative........... 73.0 48.8 28.4 37.4 29.0
Reorganization....................... 33.2 -- -- -- --
Interest............................. 164.3 77.5 46.2 65.4 50.6
Other................................ 39.6 7.1 2.5 11.3 4.3
-------- --------- -------- -------- --------
1,452.3 1,923.6 335.0 663.7 516.7
-------- --------- -------- -------- --------
Income (loss) before income taxes and
extraordinary item................... (730.8) (1,377.6) 200.3 (150.0) (20.5)
Income tax benefit (provision).......... (15.6) 500.3 (60.1) 45.9 6.5
-------- --------- -------- -------- --------
Income (loss) before extraordinary
item................................. (746.4) (877.3) 140.2 (104.1) (14.0)
Extraordinary item...................... -- (13.4) -- 4.3 (.6)
-------- --------- -------- -------- --------
Net income (loss)......................... $ (746.4) $ (890.7) $ 140.2 $ (99.8) $ (14.6)
======== ========= ======== ======== ========
Income (loss) before extraordinary item
per share:
Basic................................ $ (7.46) $ (16.88) $ 3.95 $ (2.96) $ (.47)
======== ========= ======== ======== ========
Diluted.............................. $ (7.46) $ (16.88) $ 3.47 $ (2.96) $ (.47)
======== ========= ======== ======== ========
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24
YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1998 1997(A) 1996 1995 1994(B)
-------- --------- -------- -------- --------
(IN MILLIONS, EXCEPT PER SHARE DATA)
Net Income (loss) per share:
Basic................................ $ (7.46) $ (17.14) $ 3.95 $ (2.84) $ (.49)
======== ========= ======== ======== ========
Diluted.............................. $ (7.46) $ (17.14) $ 3.47 $ (2.84) $ (.49)
======== ========= ======== ======== ========
Dividends per share..................... $ .10 $ .10 $ .10 $ .10 $ .10
======== ========= ======== ======== ========
Weighted average shares outstanding..... 100.1 52.0 35.5 35.1 29.9
OTHER FINANCIAL DATA:
Cash flows from operating activities.... $ 314.1 $ 228.2 $ 230.1 $ 156.6 $ 129.8
Cash flows from investing activities.... $ (517.0) $ (341.2) $ 13.7 $ (52.6) $ (446.0)
Cash flows from financing activities.... $ 190.9 $ 166.0 $ (245.4) $ (107.9) $ 331.4
BALANCE SHEET DATA:
Working capital (deficit)(d)............ $ (324.8) $ 46.6 $ 26.1 $ 31.5 $ 43.7
Property, plant and equipment, net...... $3,034.1 $ 3,515.8 $1,040.4 $1,121.7 $1,349.9
Total assets............................ $3,481.3 $ 4,153.0 $1,199.9 $1,319.2 $1,604.9
Long-term obligations................... $2,101.2 $ 2,124.0 $ 329.0 $ 603.2 $ 727.2
Preferred stock of subsidiary........... $ -- $ -- $ 188.8 $ 188.8 $ 188.8
Total stockholders' equity.............. $ 789.1 $ 1,548.8 $ 530.3 $ 411.0 $ 509.6
- ---------------
(a) Includes amounts relating to the acquisition of Mesa beginning in August
1997 and the acquisition of Chauvco as of December 18, 1997.
(b) 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.
(c) Includes a gain of $83.3 million in 1996 related to the disposition of
certain wholly-owned subsidiaries.
(d) The 1998 working capital deficit includes $306.5 million of current
maturities of long-term debt, including required reductions in borrowings
under the Company's credit facilities and other current debt obligations.
See "1999 Outlook -- Credit facilities" included in "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations"
and Note E of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data".
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
FORMATION OF PIONEER
Pioneer Natural Resources Company ("Pioneer", or the "Company"), a Delaware
corporation, was formed by the merger of Parker & Parsley Petroleum Company
("Parker & Parsley") and MESA Inc. ("Mesa") on August 7, 1997. On December 18,
1997, the Company was significantly expanded by the acquisition of the Canadian
and Argentine oil and gas business of Chauvco Resources Ltd. ("Chauvco"), a
publicly traded, independent oil and gas company based in Calgary, Canada.
Pioneer is an oil and gas exploration and production company with ownership
interests in oil and gas properties located in the United States, Argentina,
Canada and South Africa.
The combined physical assets and management resources of Parker & Parsley,
Mesa and Chauvco have created a company with a solid foundation of complementary
assets and industry expertise. This foundation is anchored by the Hugoton gas
field located in Southwest Kansas, the West Panhandle gas field located in the
Texas Panhandle, and the Spraberry oil and gas field in West Texas. Each of
these fields provides consistent and dependable production, cash flow and
ongoing development opportunities. These three areas are complemented by the
exploration and development opportunities and oil and gas production contributed
by Pioneer's assets in the United States Gulf Coast area, Argentina and Canada.
These assets create a portfolio of resources and opportunities that are well
balanced between oil, natural gas liquids and gas; and, that are balanced
between long-lived, dependable production and exploration and development
opportunities. Along
24
25
with these assets, the Company has a team of dedicated employees that represent
the professional disciplines and sciences that will allow Pioneer to maximize
the long-term profitability and net asset values inherent in its physical
assets.
In accordance with the provisions of Accounting Principles Board Opinion
No. 16, "Business Combinations", both the merger with Mesa and the acquisition
of Chauvco have been accounted for as purchases by the Company (formerly Parker
& Parsley). As a result, the historical financial statements of the Company are
those of Parker & Parsley prior to August 1997, and present the addition of
Mesa's and Chauvco's assets and liabilities as acquisitions by the Company in
August and December 1997, respectively.
FINANCIAL PERFORMANCE
The Company reported a net loss of $746.4 million ($7.46 per share) for the
year ended December 31, 1998 as compared to a net loss of $890.7 million ($17.14
per share) and net income of $140.2 million ($3.95 per share) for the years
ended December 31, 1997 and 1996, respectively. The 1998 results were
significantly impacted by declining commodity prices, a full year of production
volumes from the assets acquired from Mesa and Chauvco, provisions for the
impairment of proved and unproved oil and gas properties, increased interest and
general and administrative expenses, reorganization initiatives and a valuation
allowance recognized to reduce the carrying value of the Company's deferred tax
assets.
Crude oil and natural gas prices have declined substantially since 1996.
The average prices realized by the Company in 1998, including the effects of oil
and gas hedges, were $13.08 per Bbl of oil, $8.90 per Bbl of NGL and $1.82 per
Mcf of gas; as compared to average realized prices for oil, NGLs and gas of
$18.51 per Bbl, $12.59 per Bbl and $2.20 per Mcf, respectively, in 1997; and,
average realized prices for oil and gas of $19.96 per Bbl and $2.27 per Mcf,
respectively, in 1996. The effects of the declining prices on the Company's
results of operations and net cash generated by operating activities have been
mitigated by strategic oil and gas price hedges and increased production
volumes. Primarily as a result of the additions of the Mesa and Chauvco oil and
gas properties, 1998 oil, NGL and gas production increased to 62,875 MBOE as
compared to total production of 35,363 MBOE and 23,916 MBOE in 1997 and 1996,
respectively. Oil and gas production costs and depletion, depreciation and
amortization expense increased to $223.5 million and $337.3 million,
respectively, in 1998, primarily as a result of increased production volumes.
Oil and gas production costs and depletion, depreciation and amortization
expense were $144.2 million and $212.4 million, respectively, in 1997 and $110.3
and $112.1 million, respectively, in 1996.
The declining commodity price outlooks and performance issues prompted the
Company to review its oil and gas properties for impairment in 1998 and 1997,
resulting in non-cash, pre-tax impairment provisions of $459.5 million and $1.4
billion in 1998 and 1997, respectively. Exploration and abandonments expense for
1998 was $121.9 million as compared to $77.2 million and $23.0 million in 1997
and 1996, respectively, reflecting continued expansion of the Company's
exploration program into 1998. Interest and general and administrative expenses
were $164.3 million and $73.0 million in 1998, respectively, as compared to
respective expenses of $77.5 million and $48.8 million in 1997 and $46.2 million
and $28.4 million in 1996. The increase in interest expense is primarily
reflective of a full year of interest expense incurred on the debt that was
assumed in the Mesa and Chauvco acquisitions and increases in debt during 1998
to fund a portion of the Company's 1998 capital expenditures. The increase in
general and administrative expenses similarly reflects a full year of corporate
overhead and other costs incurred to manage a larger corporate entity.
During 1998, the Company implemented cost containment initiatives intended
to increase future operational and administrative efficiencies. Those
initiatives included the closings of the Company's regional offices in Oklahoma
City, Oklahoma, Corpus Christi, Texas, and Houston, Texas, the elimination of
approximately 350 employee positions and other initiatives. The $33.2 million
reorganization charge recognized during 1998 is a result of these initiatives.
Other expenses increased to $39.6 million in 1998, as compared to $7.1 million
and $2.5 million in 1997 and 1996, respectively. Other expense for 1998
included, and increased primarily as a result of, $20.5 million of
mark-to-market adjustments of non-hedge foreign currency and Btu swap agreements
previously owned by Chauvco and Mesa; a $9.6 million write-off of deferred
compensation arising from change of control features in the Company's incentive
plans; $4.4 million
25
26
of other expenses associated with the Company's operations in Argentina and
Canada; and, $3.3 million of bad debt expense.
The net loss for 1998 was also impacted by a $271.1 million valuation
allowance recognized to reduce the carrying value of the Company's deferred tax
assets. This charge, which significantly impacted the Company's 1998 net loss,
is a non-cash component of operating results and did not impact the Company's
net cash provided by operating activities. Net cash provided by operating
activities was $314.1 million for the year ended December 31, 1998, as compared
to $228.2 million for the year ended December 31, 1997 and to $230.1 million for
the year ended December 31, 1996. The additional cash flow generated by the
increased production realized from the acquired Mesa and Chauvco properties was
partially offset by the aforementioned declining commodity prices and increased
costs and expenses.
Total debt has increased to $2.2 billion at December 31, 1998 from $1.9
billion at December 31, 1997, due principally to capital expenditures in 1998
exceeding cash flow provided by operating activities. 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, 1998 was $3.0 billion, consisting of total
debt of $2.2 billion and stockholders' equity of $.8 billion. As a result of
increases in debt and reductions in shareholders' equity primarily resulting
from 1998 and 1997 non-cash impairment provisions (see Note M and Note O of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data"), the Company's debt to total capitalization
increased to 73 percent at December 31, 1998 from 56 percent at December 31,
1997.
See "Results of Operations", below, for more in-depth discussions of the
Company's oil and gas producing activities, including discussions pertaining to
oil and gas production volumes, prices, hedging activities, costs and expenses,
capital commitments, capital resources and liquidity.
1999 OUTLOOK
The Company's results of operations and financial condition in 1999 are
expected to be significantly affected by industry-wide conditions and Company
specific attributes and plans. The declining trend in commodity prices has
resulted from a combination of factors which have contributed to increased oil
and gas supplies and decreased demand for those commodities. The most
significant of those factors include increased crude oil exports by Iraq and
other members of the Organization of Petroleum Exporting Countries ("OPEC"),
mild weather patterns in heavy energy consuming areas during 1998 and 1997, and
declining demand for energy in the Asian and other formerly-high-growth areas of
the world due to regional recessions. During 1999, the Company anticipates a
continuation of the unfavorable commodity price environment presently impacting
the oil and gas industry. In response thereto, Pioneer plans to take deliberate
actions to reduce its outstanding indebtedness and to protect its operating cash
flows. The specific initiatives being taken include reductions in capital
expenditures, the divestment of non-strategic assets, the continuation of cost
containment measures and the maintenance of hedge positions designed to reduce
the volatility of 1999 realized natural gas prices.
Capital expenditures. During 1999, the Company plans to reduce capital
expended for oil and gas property additions to approximately $100 million, of
which $25 million has been budgeted for exploration expenditures and $75 million
has been budgeted for exploitation projects. Geographically, during 1999 the
Company expects capital expenditures of $60 million in the United States, $25
million in Argentina and $15 million in Canada. Pioneer's long-lived reserves
and dependable production in the Hugoton and West Panhandle gas fields and
Spraberry oil field allow it the flexibility necessary to make significant
changes in its capital allocation plans without significantly impacting near
term production volumes. During 1999, Pioneer's exploration and exploitation
programs will focus on natural gas projects. The Company's 1999 exploitation
program will focus on gas development in the Gulf Coast area and West Panhandle
field in the United States, the Chinchaga field in Canada, and in the Neuquen
Basin in Argentina. Exploration drilling will be concentrated in the Gulf of
Mexico and the onshore Gulf Coast area. The Company will participate in one or
two wells in the Gulf of Mexico deep-water Mississippi Canyon Block 305. The
first well was spudded in January and is scheduled for preliminary evaluations
in March. Two additional wells are planned for 1999
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onshore in the Gulf Coast area or in East Texas where several shallower
exploration prospects have been defined from Pioneer's 3-D database. The
Company's exploration programs in South Africa, Gabon, and the Gulf Coast
transition zone are targeted for comprehensive studies that will focus on
analysis, ranking and timing of prospects during 1999. Seismic studies are
currently planned to commence in Gabon during late 1999 or early 2000. No new
wells are planned during 1999 in South Africa, where the Company is evaluating
farmout and other risk sharing opportunities. In comparison, during 1999, the
Company intends to use the excess of cash provided by operating activities over
capital expenditures for oil and gas producing activities to reduce outstanding
indebtedness.
Asset divestitures. The Company has announced its intentions to sell
non-strategic oil and gas assets for gross proceeds of $500 million to $600
million in 1999 and 2000. As is discussed more fully below in "Trends and
Uncertainties -- Asset Dispositions", the Company has entered into a purchase
and sale agreement (the "Agreement") to sell certain non-strategic oil and gas
properties. The proceeds to be realized from the disposition, if the Agreement
is consummated, are $335 million, of which $41 million represents an irrevocable
option fee that has been paid to the Company as of December 31, 1998. If
consummated, the Agreement requires a final payment to Pioneer of $294 million
of proceeds on or before March 31, 1999. If the Agreement is not consummated,
the $41 million of irrevocable option fees would be recognized as 1999 earnings.
The Company is continuing to review its portfolio of oil and gas properties to
identify other non-strategic properties for divestiture. The realization of the
Company's plans to divest of the other non-strategic oil and gas properties in
1999 or in 2000 is contingent upon, among other things, the Company's ability to
find one or more purchasers willing to purchase the non-strategic assets at
prices acceptable to the Company and the purchasers' ability to complete the
transaction. There can be no assurances that the Company will be successful in
completing the divestitures in 1999 or in 2000. The Company intends to use
divestiture proceeds, if such proceeds are realized, to reduce outstanding
indebtedness during 1999 and 2000.
Cost containment. In 1998, the Company initiated a number of cost
containment measures. Such measures included centralizing its domestic
operations which resulted in the closing of its regional offices in Oklahoma
City, Oklahoma, Corpus Christi, Texas and Houston, Texas; the termination of 350
employees, including several officer positions; and the reduction of 1999
salaries among senior officers. These initiatives were designed to increase
operational and administrative efficiencies, thereby reducing future production
costs and general and administrative costs per BOE. Associated with these
initiatives, the Company anticipates that additional reorganization charges of
approximately $5 million will be recognized during the first quarter of 1999.
See Note N of Notes to Consolidated Financial Statement included in "Item 8.
Financial Statements and Supplementary Data" for specific discussion and
disclosures regarding the Company's reorganization provisions.
Hedging activities. The declines in commodity prices have had, and continue
to have, a significant impact on the Company's financial condition and results
of operations. To mitigate the impact of changing prices on the Company's
financial condition and results of operations, Pioneer, from time to time,
enters into commodity derivative contracts as hedges against oil and gas price
risk. As of December 31, 1998, the Company had entered into 1999 hedge contracts
for a combined notional volume of 284.7 MMcf of natural gas per day at a
weighted average floor price of $2.14 per MMBtu (the Company has sold 1999 put
options for a notional volume of 114.3 MMcf per day at an average index price of
$1.82 per MMBtu, thereby releasing the average hedge floor on 114.3 MMcf per day
of gas to the lesser of $2.12 per MMBtu or the index price plus $.30 per MMBtu).
See Notes B, C and J of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data".
Income taxes. The Company's ability to realize its deferred tax assets is
dependent upon generating sufficient taxable income prior to their expiration.
The Company believes that there is a risk, in light of the current economic
conditions in the oil and gas industry, that certain of its net operating loss
carryforwards and other credit carryforwards may expire unused. In accordance
with generally accepted accounting principles, the Company must reduce the
carrying value of its deferred tax assets if it cannot be determined that it is
more likely than not that it will be able to realize the deferred tax assets in
future operating periods. Accordingly, the Company has established a valuation
allowance of $271.1 million in 1998 to reduce the carrying value of the assets.
Although realization is not assured for the remaining deferred tax assets, the
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Company believes it is more likely than not that they will be realized through
future taxable earnings or alternative tax planning strategies. However, the net
deferred tax assets could be reduced further if the Company's estimate of
taxable income in future periods is significantly reduced or alternative tax
planning strategies are no longer viable. As a result of this situation, it is
likely that the Company's effective tax rate in 1999 will be minimal or nil if
the Company recognizes a loss before income taxes. If the Company recognizes
income before income taxes in 1999, its effective tax rate will be reduced to
the extent that taxable earnings are recognized in those tax jurisdictions
relative to which the Company established its 1998 valuation allowances.
Credit facilities. As of December 31, 1998, the Company was a borrower
under three separate credit facilities (the "Credit Facilities") that provided
for combined loan commitments of $1.4 billion, comprised of a $1.075 billion
primary credit facility (the "Primary Facility") that matures on August 7, 2002;
a $290 million Canadian Credit Facility, (the "Canadian Facility"), which
converted in the fourth quarter of 1998 to a $276 million term loan that matures
on December 19, 2003; and an $85 million credit facility (the "364-day
Facility") that matures on August 5, 1999. On December 31, 1998, the Company had
$993.6 million of outstanding borrowings under the Primary Facility, $276.0
million of outstanding borrowings under the Canadian Facility and no borrowings
under the 364-day Facility. As of December 31, 1998, advances on the Credit
Facilities bear interest at the option of the Company, based on (a) the prime
rate of NationsBank of Texas, N.A. ("Prime Rate") (7.75 percent at December 31,
1998), (b) a Eurodollar rate (substantially equal to the London Interbank
Offered Rate ("LIBOR")) 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) a competitive
bid rate as quoted by the lending banks electing to participate pursuant to a
request by the Borrower. The interest rates on the LIBOR Rate advances vary,
with the interest rate margin ranging from 18 basis points to 55 basis points,
including commitment utilization fees.
On March 19, 1999, the Company and the syndicate of banks participating in
the Credit Facilities executed amendments to the Credit Facilities that provide
for a $495 million reduction in the combined loan commitments under the Credit
Facilities by December 31, 1999; an increase in the maximum interest rate margin
on LIBOR Rate advances to 350 basis points, including facility and leverage
fees; provisions, under certain circumstances, for enhancing the participating
banks' collateral rights; and, amendment of certain associated debt covenants,
the most restrictive covenant requires the maintenance of a ratio of outstanding
Company senior debt to earnings before interest, depletion, depreciation,
amortization, income taxes, exploration and abandonment and other non-cash
expenses ("EBITDAX") not to exceed 5.75 to one through September 30, 1999, 4.25
to one through March 31, 2000, and 3.5 to one thereafter. Additionally, the
amendment provisions provide for the consolidation of the Primary Facility and
the Canadian Facility. The 1999 amendments to the Credit Facilities will
decrease the Company's liquidity and are expected to increase the Company's
weighted average rate of interest on outstanding indebtedness. To satisfy the
commitment reduction provisions of the amended Credit Facilities, the Company
intends to reduce its outstanding borrowings through the use of funds generated
by the individual or combined sources of operating activities, oil and gas
property divestitures, borrowings under subordinated debt agreements or
additional issuances of equity. The ultimate impact of the amendments on the
Company's results of operations and financial condition as of and for the year
ending December 31, 1999 is uncertain and will depend on the amount of debt
reduction that the Company is able to achieve in 1999. See "Results of
Operations -- Capital Commitments, Capital Resources and Liquidity", below, and
Note E to Notes to Consolidated Financial Statements in "Item 8. Financial
Statements and Supplementary Data" for further discussions relative to the
Company's Credit Facilities and outstanding borrowings.
TRENDS AND UNCERTAINTIES
COMMODITY PRICES
The realized oil and gas prices that Pioneer reports are based on the
market price received for the commodity adjusted by the results of the Company's
hedging activities. Historically, worldwide oil and gas prices have been
volatile and subject to significant changes in response to real and perceived
conditions in world politics, weather patterns and other fundamental supply and
demand variables.
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Since 1996, there has been a declining trend in world oil prices and, more
recently but to a lesser extent, natural gas prices. The benchmark daily average
NYMEX West Texas Intermediate crude oil closing price for the year ended
December 31, 1998 has declined 30 percent and 35 percent, respectively, as
compared with the same averages for 1997 and 1996; and, the benchmark daily
average NYMEX Henry Hub closing natural gas price for the year ended December
31, 1998 has declined 14 percent and 15 percent, respectively, as compared with
the same averages for 1997 and 1996.
ASSET DISPOSITIONS
As is discussed in "1999 Outlook", above, the Company has announced its
intentions to sell non-strategic oil and gas assets for gross proceeds of $500
million to $600 million in 1999 and 2000. In February 1998, the Company
announced its intentions to sell domestic non-strategic properties and
subsequently signed a purchase and sale agreement (the "Agreement") to sell
certain oil and gas properties representing approximately 10 percent of the
Company's proved reserves. In December 1998, Pioneer announced the re-
negotiation of the Agreement and the sale of an exclusive and irrevocable option
to the buyer to purchase the same properties on or before March 31, 1999. The
proceeds associated with the re-negotiated terms total $335 million, of which
$41 million represents an irrevocable option fee that has been paid to the
Company as of December 31, 1998. The Company's realization of the remaining $294
million of proceeds, which would be used to reduce outstanding indebtedness, is
primarily dependent upon the buyer's ability to finance the purchase and certain
other contingencies defined in the Agreement. As a result, there can be no
assurance that the divestiture of any or all of the properties will be completed
or that the remaining proceeds will be realized. The Company is continuing to
review its portfolio of oil and gas properties to identify other non-strategic
properties for divestiture. The realization of the Company's plans to divest of
the other non-strategic oil and gas properties in 1999 or in 2000 is contingent
upon, among other things, the Company's ability to find one or more purchasers
willing to purchase the non-strategic assets at prices acceptable to the Company
and the purchasers' ability to complete the transaction. There can be no
assurances that the Company will be successful in completing the divestitures in
1999 or in 2000.
ASSET IMPAIRMENTS AND VALUATION ALLOWANCES
Neither the longevity nor the extent of the current trend of declining
commodity prices can be assessed with any degree of certainty. A continuation of
the trend, or other relevant factors, could result in further impairment
provisions to the carrying value of the Company's proved and unproved properties
or additional valuation allowances to the Company's deferred tax assets in the
future, which could have a material adverse effect on the Company's financial
condition and results of operations. See Notes B, M and O of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information and disclosures regarding the
Company's accounting policies and attributes pertaining to asset impairments and
income tax valuation allowances.
FOREIGN CURRENCIES
The Company has oil and gas business dealings in Canada, Argentina, South
Africa and Gabon. Historically, crude oil sales contracts have been United
States dollar denominated, which significantly reduces foreign currency risks
associated with crude oil operations. Additionally, the Canadian dollar to
United States dollar exchange rate remains relatively stable. The functional
currency of the Company's Argentine operations is the Argentine peso. Presently,
the Argentine peso is valued on a one-to-one relationship with the United States
dollar. The functional currencies of the Company's South African and Gabon
operations are the United States dollar. The Company's operations in South
Africa and Gabon are not presently of a magnitude that would generate
significant foreign currency risk. Although the above described currency
relationships are not expected to change significantly in the near future,
economic and other factors can cause significant and sudden changes in foreign
currency exchange rates that could materially impact the Company's financial
position and future results of operations.
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YEAR 2000 PROJECT READINESS
Historically, many computer programs have been developed that use only the
last two digits in a date to refer to a year. As the year 2000 nears, the
inability of such computer programs and embedded technologies to distinguish
between "1900" and "2000" has given rise to the "Year 2000" problem.
Theoretically, such computer programs and related technology could fail outright
or communicate inaccurate data, if not remediated or replaced. With the
proliferation of electronic data interchange, the Year 2000 problem represents a
significant exposure to the entire global community, the full extent of which
cannot be accurately assessed.
In proactive response to the Year 2000 problem, the Company established a
"Year 2000" project to assess, to the extent possible, the Company's internal
Year 2000 problem; to take remedial actions necessary to minimize the Year 2000
risk exposure to the Company and significant third parties with whom it has data
interchange; and, to test its systems and processes once remedial actions have
been taken. The Company has contracted with IBM Global Services to perform the
assessment and remedial phases of its Year 2000 project.
The assessment phase of the Company's Year 2000 project is at varying
stages of completion as it pertains to information technology and
non-information technology applications and systems in the United States, Canada
and Argentina. As of December 31, 1998, the Company estimates that the
assessment phase is approximately 86 percent complete on a worldwide basis and
has included, but is not limited to, the following procedures:
- the identification of necessary remediation, upgrade and/or replacement
of existing information technology applications and systems;
- the assessment of non-information technology exposures, such as
telecommunications systems, security systems, elevators and process
control equipment;
- the initiation of inquiry and dialogue with significant third party
business partners, customers and suppliers in an effort to understand and
assess their Year 2000 problems, readiness and potential impact on the
Company and its Year 2000 problem;
- the implementation of processes designed to reduce the risk of
reintroduction of Year 2000 problems into the Company's systems and
business processes; and,
- the formulation of contingency plans for mission-critical information
technology systems.
The Company expects to complete the assessment phase of its Year 2000
project by the end of the first quarter of 1999 but is being delayed by limited
responses received on inquiries made of third party businesses. To date, the
Company has distributed Year 2000 problem inquiries to over 500 entities and has
received responses to approximately 37 percent of those inquiries.
The remedial phase of the Company's Year 2000 project is also at varying
stages of completion as it pertains to the remediation of information technology
and non-information technology applications and systems in the United States,
Canada and Argentina. As of December 31, 1998, the Company estimates that the
remedial phase is approximately 54 percent complete, on a worldwide basis,
subject to the continuing results of the third party inquiry assessments and the
testing phase. The remedial phase has included the upgrade and/or replacement of
certain application and hardware systems. The Company has upgraded its Artesia
general ledger accounting systems through remedial coding and is currently
testing this system for Year 2000 compliance. The remediation of non-information
technology is expected to be completed during July 1999. The Company's Year 2000
remedial actions have not significantly delayed other information technology
projects or upgrades.
The testing phase of the Company's Year 2000 project is on schedule. The
Company expects to complete the testing of the Artesia system upgrades by March
1999 and all other information technology systems and non-information technology
remediation by the end of the third quarter of 1999.
The Company expects that its total costs related to the Year 2000 problem
will approximate $3.6 million, of which approximately $500 thousand will have
been incurred to replace non-compliant information
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technology systems. The Company intends to use its working capital to pay for
the costs of the Year 2000 projects. As of December 31, 1998, the Company's
total costs incurred on the Year 2000 problem were $1.8 million, of which $200
thousand were incurred to replace non-compliant systems.
The risks associated with the Year 2000 problem are significant. A failure
to remedy a critical Year 2000 problem could have a materially adverse affect on
the Company's results of operations and financial condition. The most likely
worst case scenario which may be encountered as a result of a Year 2000 problem
could include information and non-information system failures, the receipt or
transmission of erroneous data, lost data or a combination of similar problems
of a magnitude that cannot be accurately assessed at this time.
In the assessment phase of the Company's Year 2000 project, contingency
plans are being designed to mitigate the exposures to mission critical
information technology systems, such as oil and gas sales receipts; vendor and
royalty cash distributions; debt compliance; accounting; and, employee
compensation. Such contingency plans anticipate the extensive utilization of
third-party data processing services, personal computer applications and the
substitution of courier and mail services in place of electronic data
interchange. Given the uncertainties regarding the scope of the Year 2000
problem and the compliance of significant third parties, there can be no
assurance that contingency plans will have anticipated all Year 2000 scenarios.
ACCOUNTING FOR DERIVATIVES
In June 1998, the Financial Accounting Standards Board issued Statement of
Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133"). SFAS 133 establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, (collectively referred to as derivatives) and for
hedging activities. It requires that an entity recognize all derivatives as
either assets or liabilities in the statement of financial position and measure
those instruments at fair value. If certain conditions are met, a derivative may
be specifically designated as (a) a hedge of the exposure to changes in the fair
value of a recognized asset or liability or an unrecognized firm commitment, (b)
a hedge of the exposure to variable cash flows of a forecasted transaction, or
(c) a hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated forecasted transaction.
SFAS 133 is effective for all fiscal quarters of fiscal years beginning
after June 15, 1999. The Company has not determined what effect, if any, SFAS
133 will have on its consolidated financial statements.
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RESULTS OF OPERATIONS
OIL AND GAS PRODUCTION
The following table describes the results of the Company's oil and gas
production activities during 1998, 1997 and 1996.
YEAR ENDED DECEMBER 31,
-------------------------------------
1998 1997 1996
---------- ----------- --------
(IN THOUSANDS, EXCEPT AVERAGE PRICE
AND COST DATA)
Revenues:
Oil and gas.......................................... $ 711,492 $ 536,782 $396,931
Gain on disposition of oil and gas properties,
net(a)............................................ 53 3,304 7,786
---------- ----------- --------
711,545 540,086 404,717
---------- ----------- --------
Costs and expenses:
Oil and gas production............................... 223,551 144,170 110,334
Depletion............................................ 322,294 204,450 102,803
Impairment of oil and gas properties................. 459,519 1,356,390 --
Exploration and abandonments......................... 51,008 37,603 12,653
Geological and geophysical........................... 70,850 39,557 9,054
---------- ----------- --------
1,127,222 1,782,170 234,844
---------- ----------- --------
Operating profit (loss) (excluding general and
administrative expense and income taxes).......... $ (415,677) $(1,242,084) $169,873
========== =========== ========
- ---------------
(a) The 1997 amount does not include the gain related to the disposition of the
Company's subsidiary that owned an interest in oil and gas properties in
Turkey. The 1996 amount does not include the gain related to the
disposition of the Company's Australasian assets. See Note L of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data".
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1997 1996
-------- -------- --------
(IN THOUSANDS, EXCEPT AVERAGE PRICE
AND COST DATA)
Production:
Oil (MBbls)............................................ 21,554 13,618 11,275
NGLs (MBbls)........................................... 10,669 4,267 --
Gas (MMcf)............................................. 183,913 104,868 75,851
Total (MBOE)........................................... 62,875 35,363 23,916
Average daily production:
Oil (Bbls)............................................. 59,052 37,309 30,805
NGLs (Bbls)............................................ 29,231 11,691 --
Gas (Mcf).............................................. 503,872 287,309 207,244
Average oil price (per Bbl).............................. $ 13.08 $ 18.51 $ 19.96
Average NGL price (per Bbl).............................. $ 8.90 $ 12.59 $ --
Average gas price (per Mcf).............................. $ 1.82 $ 2.20 $ 2.27
Costs:
Lease operating expense (per BOE)...................... $ 3.04 $ 3.02 $ 3.43
Production taxes (per BOE)............................. .40 .81 .91
Workover costs (per BOE)............................... .12 .25 .27
-------- -------- --------
Total production costs (per BOE).................... $ 3.56 $ 4.08 $ 4.61
======== ======== ========
Depletion (per BOE).................................... $ 5.13 $ 5.78 $ 4.30
OIL AND GAS REVENUES. Revenues from oil and gas operations totaled $711.5
million in 1998, $536.8 million in 1997 and $396.9 million in 1996, representing
a 33 percent increase from 1997 to 1998 and a 35 percent increase from 1996 to
1997. The revenue increase from 1997 to 1998 is reflective of a 78 percent
increase in BOE production, offset by a 29 percent, 29 percent and 17 percent
decline in prices for oil, NGLs and gas, respectively, from 1997 to 1998. The
increase in production during 1998 was primarily attributable to a full
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year of production realized from the Mesa and Chauvco properties acquired in
1997. The increase in revenue from 1996 to 1997 is primarily attributable to
increases in oil and gas production, offset by declines in commodity prices. The
majority of the increased production during 1997 was a direct result of the oil
and gas properties acquired from Mesa.
Parker & Parsley historically accounted for processed natural gas
production as wellhead production on a wet gas basis, while Mesa accounted for
processed natural gas production in two components: natural gas liquids and dry
residue gas. The combined entities own three major gas processing facilities,
and the majority of the gas processed by these facilities is owned by the
Company and produced by Company-operated properties. Consequently, the Company
now produces a higher proportion of processed gas relative to total natural gas
production and accounts for any processed natural gas production as natural gas
liquids and dry residue gas.
Production volumes for 1998 increased by 78 percent from 35,363 MBOE to
62,875 MBOE. This increase is primarily reflective of a full year of production
realized from the properties acquired from Mesa and Chauvco, but also was
impacted favorably by the Company's exploration and development projects. The
properties acquired from Mesa and Chauvco contributed 97 percent of the
production growth from 1997 to 1998. Excluding the production associated with
the Mesa and Chauvco properties and other properties sold during 1998 and 1997,
production increased nine percent during 1998, as compared to 1997, on a BOE
basis.
On a BOE basis, production increased by 48 percent for the year ended
December 31, 1997, as compared to the same period in 1996. The additional
production volumes from the Mesa properties contributed 85 percent of production
growth from 1996 to 1997. The remainder of the increase is a direct result of
the successes of the Company's exploration and exploitation efforts. Such
production growth was particularly evident in light of the fact that a portion
of the average daily oil and gas production for 1996 related to properties
included in the 1996 sale of the Company's Australasian subsidiaries and the
1996 sale of certain non-strategic domestic assets. Excluding production
associated with assets sold during 1996 and the Mesa properties acquired in
1997, on a BOE basis, production increased 14 percent for the year ended
December 31, 1997 as compared to the year ended 1996.
The average oil price received for the year ended December 31, 1998
decreased 29 percent (from $18.51 per Bbl in 1997 to $13.08 per Bbl in 1998);
the average NGL price received in 1998 decreased 29 percent (from $12.59 per Bbl
in 1997 to $8.90 per Bbl in 1998); and the average gas price received in 1998
decreased 17 percent (from $2.20 per Mcf in 1997 to $1.82 per Mcf in 1998). The
average oil price received for the year ended December 31, 1997 decreased seven
percent (from $19.96 per Bbl in 1996 to $18.51 per Bbl in 1997), and the average
gas price received decreased three percent (from $2.27 per Mcf in 1996 to $2.20
per Mcf in 1997). During 1997, the Company received an average of $12.59 per Bbl
for NGLs.
Hedging Activities
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 utilizes 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.
Crude Oil. All material purchase contracts governing the Company's oil
production are tied directly or indirectly to NYMEX prices. The average oil
price 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's average realized price for physical oil sales (excluding hedge
results) for the years ended December 31, 1998, 1997 and 1996 was $11.93 per
Bbl, $19.09 per Bbl and $21.33 per Bbl, respectively. During the year ended
December 31, 1998, the Company recorded a $24.8 million net increase to oil
revenues as a result of its oil price hedges. During the fourth quarter of 1998,
the Company terminated its 1999 crude oil hedge positions and recognized a
deferred gain of $14.0 million associated therewith. The deferred hedge gains
will be recognized as oil revenue during the year ended December 31, 1999 in the
amount of $3.5 million per calendar
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quarter. The Company recorded net reductions to oil revenues of $7.9 million and
$15.4 million for the years ended December 31, 1997 and 1996, respectively, as a
result of its oil price hedges.
Natural Gas Liquids. During 1998, the Company did not enter into natural
gas liquids price hedge contracts. During the year ended December 31, 1997, the
Company realized an average natural gas liquids price for physical sales
(excluding hedge results) of $12.61 per Bbl and recorded a net decrease to
natural gas liquids revenue of $77,600 as a result of hedging.
Natural Gas. The Company employs a policy of hedging a portion of its 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 price 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's average realized price for
physical gas sales (excluding hedge results) for the years ended December 31,
1998, 1997 and 1996 was $1.80 per Mcf, $2.41 per Mcf and $2.39 per Mcf,
respectively. For the year ended December 31, 1998, the Company recorded a net
increase to gas revenues of $3.6 million as a result of its gas price hedges.
The Company recorded net reductions to gas revenues of $21.9 million and $9.0
million for the years ended December 31, 1997 and 1996, respectively, as a
result of its gas price hedges.
See Note J of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for information concerning the
Company's open hedge positions at December 31, 1998 and the related prices to be
realized.
PRODUCTION COSTS. Total production costs per BOE decreased in 1998 and 1997
by approximately 13 percent and 11 percent, respectively (from $4.61 in 1996 to
$4.08 in 1997 to $3.56 in 1998). The primary component of production costs,
lease operating expense, remained constant in 1998 and decreased by 12 percent
in 1997. Workover costs declined by 52 percent in 1998 and seven percent in
1997. 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. Production taxes, which are correlated with
volumes and prices, declined 51 percent in 1998 and 11 percent in 1997
reflecting the decline in commodity prices over the past two years. As discussed
more fully in "Natural Gas Processing" below, the Company adopted a new method
of reporting the financial results of its natural gas processing facilities in
1997, and is now presenting these results as oil and gas production activities.
In 1998 and 1997, the operating margin from the Company's gas plants (i.e.,
third party processing revenues less processing costs and expenses) are included
in oil and gas production costs, specifically lease operating expense. The
additional reductions in lease operating expense during the three years ended
December 31, 1998 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 during 1996.
DEPLETION EXPENSE. Depletion expense per BOE decreased 11 percent in 1998
(to $5.13 in 1998 from $5.78 in 1997) and increased 34 percent in 1997 (from
$4.30 in 1996). The decrease in 1998 was primarily due to the 1997 provision for
impairment that reduced the per BOE carrying values of the Company's oil and gas
properties in accordance with SFAS 121 (see "Impairment of Oil and Gas
Properties" below). The increase in depletion expense per BOE in 1997 was
primarily associated with the fair value allocated to Mesa's long-lived, low
production cost natural gas reserves.
IMPAIRMENT OF OIL AND GAS PROPERTIES. 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"), the
Company reviews its oil and gas properties for impairment whenever events or
circumstances indicate a decline in the recoverability of the carrying value of
the Company's assets may have occurred. Declining commodity prices in 1998 and
1997, the Company's outlook for future commodity prices and 1998 performance
issues relative to certain oil and gas properties, prompted impairment reviews.
As a result of these reviews, the Company recognized non-cash pre-tax charges of
$312.2 million and $1.4 billion in 1998 and 1997, respectively, related to its
proved oil and gas properties.
In accordance with Statement of Financial Accounting Standards No. 19,
"Accounting and Reporting by Oil and Gas Producing Companies" ("SFAS 19"), the
Company periodically assesses its unproved properties
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35
to determine whether they have been impaired. An unproved property may be
impaired if the Company does not intend to drill the prospect as a result of
downward revisions to potential proved reserves, if the results of exploration
or the Company's outlook for future commodity prices indicate that the potential
proved reserves are not sufficient to generate net cash flows to recover the
investment required by the project, or if the Company intends to sell the
property for less than its carrying value. The Company has assessed its unproved
oil and gas properties for impairment and in 1998 recognized a non-cash pre-tax
impairment charge of $147.3 million to reduce the carrying value of its unproved
oil and gas properties.
EXPLORATION AND ABANDONMENTS/GEOLOGICAL AND GEOPHYSICAL COSTS. Exploration
and abandonments/ geological and geophysical costs totaled $121.9 million, $77.2
million and $21.7 million for the years ended December 31, 1998, 1997 and 1996,
respectively. The following table sets forth the components of the Company's
1998, 1997 and 1996 exploration and abandonments/geological and geophysical
costs:
YEAR ENDED DECEMBER 31,
----------------------------
1998 1997 1996
-------- ------- -------
(IN THOUSANDS)
Exploratory dry holes:
United States............................................. $ 15,737 $27,183 $ 6,256
Argentina................................................. 4,426 252 3,416
Canada.................................................... 1,949 -- --
Other foreign............................................. 9,486 5,442 15
Geological and geophysical costs:
United States............................................. 42,755 37,987 7,042
Argentina................................................. 9,999 1,570 592
Canada.................................................... 14,244 -- --
Other foreign............................................. 3,851 -- 1,420
Leasehold abandonments and other............................ 19,411 4,726 2,966
-------- ------- -------
$121,858 $77,160 $21,707
======== ======= =======
Approximately 30 percent of the Company's 1998 exploration/exploitation
capital budget was spent on exploratory projects as compared to 28 percent in
1997 and 18 percent in 1996. The increase in 1998 exploratory costs is primarily
due to the initial expenditures made to explore the Argentine and Canadian
properties acquired from Chauvco and the Company's exploration program in South
Africa. The increase in 1997 was primarily the result of increased domestic
exploratory drilling and geological and geophysical activity due to the
expansion of the Company's exploration program. The Company currently
anticipates that its 1999 exploration efforts, although curtailed to reduce
debt, will be concentrated domestically in the Gulf of Mexico and onshore Gulf
Coast region. The Company will participate in one or two wells in the Gulf of
Mexico deep-water Mississippi Canyon Block 305 and two wells in either the
onshore Gulf Coast area or in East Texas where several shallower exploration
prospects have been defined from Pioneer's 3-D database. The Company's
exploration programs in South Africa, Gabon, and the Gulf Coast transition zone
are targeted for comprehensive studies that will focus on analysis, ranking and
timing of prospects during 1999.
NATURAL GAS PROCESSING
The Company historically reflected its ownership interests in and revenues
and expenses related to its natural gas processing facilities as separate items
in the consolidated financial statements while Mesa reported revenues and
expenses from its natural gas processing facilities as oil and gas production
costs. During the last four years, the Company has sold its interests in 12
natural gas processing facilities and now owns interests in seven facilities.
The ownership interest in the remaining gas plant facilities and the related
results of operations from third party gas processed through such facilities are
not material to the Company's financial position. To report the results of gas
processing activities consistently within the financial statements, during 1997,
the Company reclassified the natural gas processing facilities into oil and gas
properties for financial statement purposes and will report all third party
revenues and expenses from its natural gas processing facilities in oil and gas
production costs.
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In 1996, natural gas processing revenues were $23.8 million and natural gas
processing costs were $12.5 million. The average price per Bbl of NGLs was
$15.10 in 1996, while the average price per Mcf of residue gas was $2.15. 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
pre-tax gain of $639 thousand. Additionally, the Company recognized non-cash
pre-tax charges of $1.3 million related to abandonments of certain of the
Company's gas processing facilities and the cancellation of certain gas
processing contracts.
GENERAL AND ADMINISTRATIVE EXPENSE
General and administrative expense was $73 million in 1998, $48.8 million
in 1997 and $28.4 million in 1996, representing a 50 percent increase from 1997
to 1998 and a 72 percent increase from 1996 to 1997. The increases from 1996 to
1997, and 1997 to 1998, resulted from the increased size of the Company and
relocation costs caused by the merger between Parker & Parsley and Mesa and the
acquisition of Chauvco.
REORGANIZATION
During 1998, the Company announced its plans to sell certain non-strategic
oil and gas fields, its intentions to reorganize its operations by combining its
six domestic operating regions and other cost reduction initiatives intended to
allow Pioneer to better adapt to declining oil and gas commodity price trends.
Specific cost reduction initiatives included the relocation of most of the
Company's administrative services from Midland, Texas to Irving, Texas; the
closings of the Company's regional offices in Oklahoma City, Oklahoma, Corpus
Christi, Texas and Houston, Texas; the termination of 350 employees including
several officer positions; and, further centralization of the Company's
organizational structure. Associated with these initiatives, the Company
recognized a pre-tax reorganization charge of $33.2 million in 1998. In
addition, the Company anticipates that another $5 million of reorganization
charges will be incurred during the first quarter of 1999. See Note N of Notes
to Consolidated Financial Statements in "Item 8. Financial Statements and
Supplementary Data" for specific information regarding reorganization costs paid
in 1998 and costs unpaid as of December 31, 1998.
INTEREST EXPENSE
Interest expense was $164.3 million in 1998, $77.6 million in 1997 and
$46.2 million in 1996. The increase in interest expense from 1997 to 1998
primarily reflects the increase in the weighted average outstanding balance of
Company indebtedness that resulted from a full year of debt assumed from Mesa
and Chauvco in 1997 and approximately $190 million of debt incurred to fund 1998
additions to oil and gas properties. The increase from 1996 to 1997 is primarily
the result of an increase in the weighted average outstanding balance of the
Company's indebtedness during 1997 as compared to 1996 due to the additional
debt assumed from Mesa. In addition, the 1997 and 1996 amounts included $6
million and $12 million of interest, respectively, associated with the preferred
stock of the Company's subsidiary, Parker & Parsley Capital LLC, which was
converted to common stock of the Company in July 1997 (see Note I of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data"). The 1998, 1997 and 1996 amounts also include $1.1 million,
$1.2 million and $1.3 million, respectively, of amortization of capitalized loan
fees.
During each of the years 1998, 1997 and 1996, the Company was a party to
various interest rate swap agreements. As a result, the Company recorded a
reduction in interest expense of $356 thousand, $847 thousand and $787 thousand
for the years ended December 31, 1998, 1997 and 1996, respectively. For a
description of the Company's interest rate swap agreements, see Note J of Notes
to the Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data".
OTHER EXPENSE
Other expense was $39.6 million, $7.1 million and $2.5 million for the
years ended December 31, 1998, 1997 and 1996, respectively. The $32.5 million
increase in other expense from 1997 to 1998 was comprised of several factors,
including a $14.7 million 1998 non-cash, pre-tax, mark-to-market adjustment of
Canadian
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dollar to United States dollar currency swaps which were acquired with Chauvco
in December 1997; a $9.6 million 1998 non-cash, pre-tax write-off of deferred
compensation that resulted from certain incentive plan change of control
provisions that were triggered by a 1998 increase in an investment fund's
beneficial ownership in the Company; $4.4 million of other expense items related
to the Company's operations in Argentina and Canada; and, a $2.3 million
increase in bad debt expense. The $4.6 million increase in other expense during
1997 as compared to 1996 primarily resulted from the $5.2 million non-cash,
pre-tax, mark-to-market adjustment of the December 31, 1997 carrying value of
the Company's BTU swap agreement that was originally entered into by Mesa.
During 1998, the Company recognized a $5.8 million non-cash, pre-tax,
mark-to-market adjustment of the carrying value of the BTU swap agreement.
Future mark-to-market adjustments of the Company's non-hedge derivatives
cannot be quantified with any degree of certainty. Such adjustments could
significantly impact the Company's future results of operations, financial
position and cash flows. See Notes F and J to the accompanying Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for further discussions pertaining to the incentive plan
change of control provisions and the Company's BTU swap agreement and other
mark-to-market derivatives.
INCOME TAXES
For the years ended December 31, 1998, 1997 and 1996, the Company
recognized, exclusive of the tax effect of the 1997 extraordinary loss, a
consolidated tax provision of $15.6 million, a tax benefit of $500.3 million and
a tax provision of $60.1 million, respectively. The tax provision for the year
ended December 31, 1998 includes a $271.1 million deferred tax valuation charge
to reduce the carrying value of the Company's deferred tax assets. During the
fourth quarter of 1998, the Company reviewed its deferred tax assets, and in
light of the current economic conditions in the oil and gas industry, and the
Company's outlook for future commodity prices, and the Company's performance
over the past two years; the Company believes that certain of its net operating
losses may expire unused, and accordingly, has established a valuation allowance
against them.
The Company's annual income tax provisions or benefits were determined from
the separate tax calculation prepared for each tax jurisdiction in which the
Company is subject to income taxes. For 1998, 1997 and 1996, the Company had
effective total tax rates of approximately two percent, 36 percent and 30
percent, respectively. See Note O 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
On December 18, 1997, the Company completed a cash tender offer for a
significant portion of the 11 5/8% senior subordinated discount notes due 2006
and the 10 5/8% senior subordinated notes due 2006 (the "10 5/8% Notes")
(collectively, the "Subordinated Notes") assumed from Mesa for a redemption
price of $829.90 and $1,171.40, respectively, per $1,000 tendered plus any
interest accrued on the 10 5/8% Notes (the "Tender Offer"). As a result of the
Tender Offer, the Company recognized an extraordinary loss on early
extinguishment of debt of $11.9 million (net of a related tax benefit of $6.4
million) during the fourth quarter of 1997. The Company financed the purchase
price of the Subordinated Notes tendered in the offer with borrowings under its
bank credit facility.
The accompanying Consolidated Statement of Operations and Comprehensive
Income (Loss) for the year ended December 31, 1997 also includes a $1.5 million
(net of a related tax benefit of $800 thousand) non-cash charge for an
extraordinary loss on early extinguishment of debt resulting from the mergers.
This extraordinary loss relates to capitalized issuance fees associated with
Parker & Parsley's previously existing bank credit facility, which was replaced
by a new credit facility agreement for the Company.
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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 1998, 1997 and 1996 for additions to
oil and gas properties (including individual property acquisitions, but not
including company acquisitions) totaled $507.3 million, $428.6 million and
$219.4 million, respectively. The 1998 amount includes $450.3 million of
development and exploratory drilling and seismic costs, of which $332.0 million,
or 74 percent, were development expenditures. During 1998, $308.2 million, or 68
percent, of the Company's drilling and seismic expenditures occurred in the
United States, of which $167.4 million, or 54 percent, was expended in the Gulf
Coast area and $112.6 million, or 37 percent, was expended in the Permian Basin
area. Also, during 1998, the Company expended $142.1 million, or 32 percent, of
its drilling and seismic capital in its international regions, located in Canada
($65.8 million, or 15 percent of worldwide drilling and seismic expenditures),
Argentina ($57.5 million, or 13 percent of worldwide drilling and seismic
expenditures) and other international areas ($18.8 million, or four percent of
worldwide drilling and seismic expenditures), including South Africa and Gabon.
The 1997 amount includes $292.6 million for development and exploratory drilling
when, as in 1996, the Company's drilling activities were focused primarily in
the Spraberry field of the Permian Basin. Significant drilling expenditures in
1997 included $99.0 million in the unitized portion of the Spraberry field of
the Permian Basin (including $47.6 million in the Driver unit, $12.7 million in
the Preston unit, $12.6 million in the Shackelford unit, $12.2 million in the
North Pembrook unit and $10.5 million in the Merchant unit), $14.9 million in
other portions of the Spraberry field, $46.5 million in other areas of the
Permian Basin, $91.3 million in the onshore and offshore Gulf Coast area, $29.9
million in the Mid Continent area and $11.0 million in Argentina and Guatemala.
The Company's 1999 capital expenditure budget has been set at $100 million,
reflecting planned expenditure reductions in support of the Company's intention
to reduce outstanding indebtedness and to increase financial flexibility.
Capital expenditures for 1999 are expected to include $75 million for
exploitation activities and $25 million for exploration activities. The Company
budgets its 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 and the Company's capital expenditure program may
be provided by any combination of internally-generated cash flow, proceeds from
the disposition of non-strategic assets or alternative financing sources as
discussed in "Capital Resources" below.
CAPITAL RESOURCES. The Company's primary capital resources are net cash
provided by operating activities, proceeds from financing activities and
proceeds from sales of non-strategic assets. The Company expects that these
resources will be sufficient to fund its capital commitments in 1999.
Operating Activities
Net cash provided by operating activities during 1998, 1997 and 1996 were
$314.1 million, $228.2 million and $230.1 million, respectively. Net cash
provided by operating activities in 1998 increased 38 percent over that of 1997
as a result of the increased production realized from the properties acquired
from Mesa and Chauvco, partially offset by declining commodity prices and
increased general and administrative expenses, reorganization expenditures, and
interest expense. Net cash provided by operating activities in 1997 was
comparable to that of 1996. Increased production in 1997 was offset by increased
general and administrative expenses and interest expenses and the payment of
certain liabilities assumed from Mesa, including severance payments made to
former Mesa employees.
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Financing Activities
As described more fully in Note E of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data", as
of December 31, 1998 the Company was a borrower under three credit facility
agreements with a syndicate of banks which provided for a total bank credit
facility of $1.4 billion as of December 31, 1998. The Company had an outstanding
balance under its Primary Facility at December 31, 1998 of $993.6 million
(including outstanding, undrawn letters of credit of $19.6 million), leaving
approximately $81 million of unused borrowing base available as of December 31,
1998. The Company had no outstanding borrowings under its 364-day Facility as of
December 31, 1998, leaving $85 million of borrowing capacity unused on that
date. At December 31, 1998, the Company also had $276.0 million of term loan
borrowings outstanding under its Canadian Facility, representing the total
borrowing capacity under the Canadian Facility. During the first quarter of
1999, the Company and the participating banks amended the Credit Facilities
whereby the Primary Facility and the Canadian Facility were consolidated; the
total loan commitments under the Credit Facilities were reduced by $495 million
by December 31, 1999; the interest rate on LIBOR Rate advances increased to a
maximum of 350 basis points; and, certain other Credit Facility amendments as
described in "1999 Outlook," above.
At December 31, 1998, the Company had four other outstanding significant
debt issuances. Such debt issuances consist of (i) $150 million aggregate
principal amount of 8 7/8% senior notes issued by Parker & Parsley in 1995 and
due in 2005 (carrying value of $150.0 million); (ii) $150 million aggregate
principal amount of 8 1/4% senior notes issued by Parker & Parsley in 1995 and
due in 2007 (carrying value of $149.4 million); (iii) $350 million aggregate
principal amount of 6 1/2% senior notes issued by Pioneer in 1998 and due in
2008 (carrying value of $348.4 million); and, (iv) $250 million aggregate
principal amount of 7 1/5% senior notes issued by Pioneer in 1998 and due in
2028 (carrying value of $249.9 million).
The weighted average interest rate for the year ended December 31, 1998 on
the Company's indebtedness was 7.16 percent as compared to 7.04 percent for the
year ended December 31, 1997 and 7.83 percent for the year ended December 31,
1996 (taking into account the effect of interest rate swaps).
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.
Sales of Non-strategic Assets
During 1998, 1997 and 1996, proceeds from the sale of non-strategic assets
totaled $21.9 million, $115.7 million and $58.4 million, respectively. In
addition, during 1996, the Company sold certain subsidiaries resulting in cash
proceeds of $183.2 million (see Note L of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data").
The proceeds from these sales were primarily utilized to reduce the Company's
outstanding bank indebtedness and for general working capital purposes.
As is more fully discussed in "1999 Outlook", above, the Company announced
its intentions to sell certain domestic non-strategic properties for gross
proceeds of $335 million. These properties represent approximately 10 percent of
the Company's reserves at December 31, 1998. Although the Company plans to
complete this sale during the first quarter of 1999, there can be no assurance
that the buyer will be able to consummate the transaction. The Company
anticipates that it will continue to sell non-strategic properties from time to
time to reduce outstanding indebtedness, increase capital resources available
for other activities and to achieve operating and administrative efficiencies
and improved profitability.
In January 1999, the Company announced its intentions to divest, during
1999 and 2000, non-strategic properties for gross divestment proceeds, including
the currently pending divestiture, of $500 million to $600 million. There can be
no assurances that the Company will be successful negotiating or completing such
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divestitures within the 1999 to 2000 time frame. The consummation of the
Company's 1999 and 2000 divestiture plan is entirely dependent on finding one or
more willing purchasers who have the financial wherewithal to complete such
purchases. Until such purchasers are found, the Company may reevaluate its
portfolio of properties and at any time may adjust its plans concerning
divestitures. As a result, there can be no assurance that the divestiture of any
or all of these properties will be completed or that the estimated proceeds will
be realized.
LIQUIDITY. At December 31, 1998, the Company had $59.2 million of cash and
cash equivalents on hand, compared to $71.7 million at December 31, 1997. The
Company's ratio of current assets to current liabilities was .38 at December 31,
1998 and 1.18 at December 31, 1997. The decline in the ratio is primarily
reflective of $306.5 million of current maturities of long-term debt as of
December 31, 1998, including required reductions in borrowings under the
Company's Credit Facilities and other current debt obligations. See "1999
Outlook -- Credit facilities," above, and Note E of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for further discussions regarding amendments to the Company's Credit
Facilities.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about
financial instruments to which the Company is a party as of December 31, 1998,
and from which the Company may incur future earnings gains or losses from
changes in market interest rates, foreign exchange rates, commodity prices or
common stock prices. Although certain derivative contracts that the Company is a
party to do not qualify as hedges, the Company does not enter into derivative or
other financial instruments for trading purposes.
QUANTITATIVE DISCLOSURES
INTEREST RATE SENSITIVITY. The following table provides information, in
United States dollar equivalent amounts, about the Company's derivative
financial instruments and other financial instruments that the Company is a
party to as of December 31, 1998 which are sensitive to changes in interest
rates. For debt obligations, the table presents maturities by expected maturity
dates together with the weighted average interest rates expected to be paid on
the debt, given current contractual terms and market conditions. For fixed rate
debt, the weighted average interest rate represents the contractual fixed rates
that the Company is obligated to periodically pay on the debt; for variable rate
debt, the average interest rate represents the average rates being paid on the
debt projected forward proportionate to the forward yield curve for United
States treasury securities. For the Canadian dollar denominated financial
instruments, the most recent average forward United States dollar to Canadian
dollar exchange rate is presented for the readers' information. For interest
rate derivatives that the Company is a party to and that are related to the
Company's total debt, the notional contractual amounts are presented together
with the average rates paid and received by the Company.
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PIONEER NATURAL RESOURCES COMPANY
INTEREST RATE SENSITIVITY
DERIVATIVE AND OTHER FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 1998
1999 2000 2001 2002 2003 THEREAFTER TOTAL FAIR VALUE
-------- ------- ------- -------- -------- ---------- ---------- ----------
(IN THOUSANDS EXCEPT INTEREST AND FOREIGN EXCHANGE RATES)
Total Debt:
U.S. dollar denominated
maturities:
Fixed rate debt.......... $ 330 $ -- $ -- $ 1,508 $ 1,447 $932,948 $ 936,233 $ 743,701(1)
Weighted average interest
rate................... 7.50% 7.50% 7.50% 7.50% 7.50% 7.50%
Variable rate debt....... $306,191 $ -- $ -- $932,841 $1,239,032 $1,239,032
Average interest rate.... 5.85% 5.87% 5.89% 5.92%
Interest Rate Derivatives
Related to Total Debt:
U.S. dollar denominated
hedge derivatives:
Notional amount of
interest rate
swaps(2)............... $150,000 $ 1,046
Average variable rate
paid................... 5.18%
Average fixed rate
received............... 6.62%
Canadian dollar denominated
non-hedge derivatives:
Notional amount of
interest rate cap(3)... $122,436 $ (80)
Rate paid when index is
below 8%............... 0.28%
Average forward U.S.
dollar to Canadian
dollar exchange rate... 0.6671
- ---------------
(1) Excludes $6.8 million of 10 5/8% notes due 2006 and $22.5 million of 11 5/8%
notes due 2006 for which fair values were not practicable to derive.
(2) $75 million notional amount of the interest rate swaps mature May 7, 1999;
$50 million notional amount of the interest rate swaps mature June 4, 1999;
and, $25 million notional amount of the interest rate swaps mature June 11,
1999.
(3) The Canadian dollar denominated interest rate cap matures August, 1999.
FOREIGN EXCHANGE RATE SENSITIVITY. The following table provides
information, in United States dollar equivalent amounts, about the Company's
derivative financial instruments and other financial instruments that the
Company is a party to as of December 31, 1998 and that are sensitive to changes
in foreign exchange rates. The table provides information regarding the notional
amounts of the Company's Canadian dollar denominated interest rate cap and
foreign currency swap derivative contracts, including rates paid and received by
the Company and forward currency exchange rates.
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PIONEER NATURAL RESOURCES COMPANY
FOREIGN EXCHANGE RATE SENSITIVITY
DERIVATIVE AND OTHER FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 1998
1999 2000 2001 2002 2003 THEREAFTER TOTAL FAIR VALUE
-------- ------- ------- ------- -------- ---------- -------- ----------
(IN THOUSANDS EXCEPT INTEREST AND FOREIGN EXCHANGE RATES)
Non-hedge Interest Rate Derivatives
Related to Total Debt:
Canadian dollar denominated
derivatives:
Notional amount of interest
rate cap(1).................. $122,436 $122,436 $ (80)
Rate paid when index is below
8%........................... 0.28%
Average forward U.S. dollar to
Canadian dollar exchange
rate......................... 0.6671
Non-hedge Foreign Exchange Rate
Derivatives:
Notional amount of foreign
currency swaps(2).............. $ 72,000 $72,000 $144,000 $(15,350)
Fixed Canadian to U.S. dollar
rate paid...................... 1.3670 1.3606
Average forward Canadian dollar
to U.S. dollar exchange rate
payable........................ 1.4990 1.4963
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(1) The Canadian dollar denominated interest rate cap matures August 1999.
(2) The foreign exchange rate swaps mature in October and December 2000.
COMMODITY PRICE SENSITIVITY. The following table provides information, in
United States dollar equivalent amounts, about the Company's derivative
financial instruments that the Company is a party to as of December 31, 1998 and
that are sensitive to changes in natural gas and crude oil commodity prices. The
table segregates hedge derivative contracts from those that do not qualify as
hedges. As shown in the table, the Company has entered into swap contracts
whereby a fixed price is established for a notional amount of sales volumes.
Additionally, the Company has entered into collar contracts that provide a floor
price for the Company on a notional amount of sales volumes while allowing some
additional price participation for the Company if the relevant index prices
close above the floor price. The Company also has entered into collar contracts
with short put options that differ from other collar contracts by virtue of the
short put option price, below which the Company's realized price will exceed
variable market prices by approximately $.30 per MMBtu. The Company's agreement
to swap the NYMEX gas price for 10 percent of the NYMEX oil price (the "BTU
Swap") was acquired through the merger with Mesa. Under the terms of the BTU
Swap, the Company receives 10 percent of the NYMEX oil price and pays the NYMEX
gas price on 13,036 notional MMBtu daily volume. See Notes B, C and J of Notes
to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for a description of the accounting procedures followed
by the Company relative to hedge and non-hedge derivative financial instruments
and for specific information regarding the terms of the Company's derivative
financial instruments that are sensitive to changes in natural gas and crude oil
commodity prices.
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PIONEER NATURAL RESOURCES COMPANY
COMMODITY PRICE SENSITIVITY
DERIVATIVE AND OTHER FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 1998
1999 2000 2001 2002 2003 THEREAFTER TOTAL FAIR VALUE
-------- ------- ------- ------- ------- ---------- ------- ----------
(IN THOUSANDS EXCEPT VOLUMES AND PRICES)
Natural Gas Hedge Derivatives(1):
Average daily notional MMBtu
volumes(2):
Swap contracts(3)............. 137,044 35,000 172,044 $ 17,827
Weighted average MMBtu fixed
price....................... $ 2.21 $ 2.35
Collar option contracts....... 33,400 33,400 $ 323
Weighted average short call
MMBtu ceiling price......... $ 2.56
Weighted average long put
MMBtu floor price........... $ 1.91
Collar option contracts with
short puts(4)............... 114,286 93,074 207,360 $ 8,398
Weighted average short call
MMBtu ceiling price......... $ 2.64 $ 2.75
Weighted average long put
MMBtu contingent floor
price....................... $ 2.12 $ 2.14
Weighted average short put
MMBtu price below which
floor becomes variable...... $ 1.82 $ 1.84
Natural Gas non-hedge Derivatives:
Daily notional MMBtu volumes
under agreement to swap NYMEX
gas price for 10 percent of
NYMEX WTI price............... 13,036 13,036 13,036 13,036 13,036 13,036 78,216 $(15,172)
Average forward NYMEX gas
prices...................... $ 1.97 $ 2.17 $ 2.25 $ 2.34 $ 2.39 $ 2.45
Average forward NYMEX oil
prices...................... $ 13.00 $ 14.75 $ 16.00 $ 16.75 $ 17.45 $ 17.88
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(1) When necessary, to minimize basis risk the Company enters into basis swaps
to connect the index price of the hedging instrument from a NYMEX index to
an index which reflects the geographic area of production. The Company
considers these basis swaps as part of the associated swap and option
contracts and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(2) See Note J of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for hedge volumes and
weighted average prices by calendar quarter for 1999 and 2000.
(3) Certain counterparties to the 1999 and 2000 swap contracts have the
contractual right to extend 35,000 MMBtu per day for one additional year at
prices of $2.40 and $2.41 per MMBtu, respectively.
(4) 65,000 MMBtu per day of the 1999 collar option contracts with short puts are
extendable at the option of the counterparties for a period of one year at
average per MMBtu prices of $2.79, $2.18 and $1.88 for the short call, long
put and short put, respectively. 75,000 MMBtu per day of the 2000 collar
option contracts with short puts are extendable at the option of the
counterparties at average per MMBtu prices of $2.90, $2.20 and $1.90 for the
short call, long put and short put, respectively.
OTHER PRICE SENSITIVITY. The following table provides information about the
Company's investment in common stock of Costilla Energy Inc. ("Costilla"). The
Company acquired three million shares of Costilla in partial payment of the
option fees associated with the irrevocable option sold to Costilla in December
1998, the terms of which allow Costilla to acquire certain assets of the
Company. Costilla has the option of repurchasing its common shares from the
Company, prior to May 31, 1999, for an aggregate purchase price of $13 million.
See Trends and Uncertainties -- Asset Dispositions included in "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" for a discussion with specific information regarding the irrevocable
option agreement sold to Costilla.
43
44
PIONEER NATURAL RESOURCES COMPANY
OTHER PRICE SENSITIVITY
DERIVATIVE AND OTHER FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 1998
1999 2000 2001 2002 2003 THEREAFTER TOTAL FAIR VALUE
------ ------ ------ ------ ------ ---------- ----- ----------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
Total Marketable Securities:
Common shares of Costilla Energy Inc.... 3,000 3,000 $12,000
Market value per share of Costilla
Energy Inc. common stock on December
31, 1998.............................. $ 4.00
Option Sold:
Option to purchase 3 million shares of
Costilla Energy Inc. common stock from
the Company for $13 million:
Total option shares................. 3,000 3,000 (1)
Option price per share.............. $ 4.25
Market value per share of Costilla
Energy Inc. common stock on
December 31, 1998................. $ 4.00
- ---------------
(1) Determination of fair value not practicable.
QUALITATIVE DISCLOSURES
NON-DERIVATIVE FINANCIAL INSTRUMENTS. The Company is a borrower under fixed
rate and variable rate debt instruments that give rise to interest rate and
foreign exchange rate risk. The Company's objective in borrowing under fixed or
variable rate debt is to satisfy capital requirements while minimizing the
Company's costs of capital. To realize its objectives, the Company borrows under
fixed and variable rate debt instruments, based on the availability of capital,
market conditions and hedge opportunities. See Note E of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for a discussion relative to the Company's debt instruments.
The Company received three million shares of Costilla common stock in
partial payment of the fees associated with an irrevocable option sold to
Costilla to purchase certain oil and gas properties of the Company prior to
April 1, 1999. The Company purchased the Costilla common shares as an
accommodation of the larger transaction with Costilla involving the contemplated
sale of certain of the Company's oil and gas properties. The Company did not
purchase the Costilla shares for trading purposes, although the Company has the
option of selling the shares to a third party if Costilla does not repurchase
them. Costilla has the contractual right to repurchase the shares prior to May
31, 1999, for an aggregate purchase price of $13 million, or $4.25 per share.
The Company does not normally, nor does it contemplate, investing in marketable
securities for trading purposes.
DERIVATIVE FINANCIAL INSTRUMENTS. The Company has entered into interest
rate, foreign exchange rate and commodity price derivative contracts to hedge
interest rate, foreign exchange rate and commodity price risks. Although the
Company has succeeded Mesa and Chauvco as a party to interest rate, foreign
exchange rate and commodity price derivative contracts that do not qualify as
hedges, the Company's policy is not to enter into derivative contracts for
trading purposes.
Crude oil hedge derivatives
All material purchase contracts governing the Company's oil production are
tied directly or indirectly to NYMEX prices. As a result, from time to time the
Company hedges its oil production using contracts tied to the NYMEX prices. The
average oil prices per Bbl that the Company reports include the effects of oil
quality, gathering and transportation costs and the net effect of the oil
hedges. As of December 31, 1998, the Company was not a party to any crude oil
hedge derivatives.
44
45
Natural gas liquids hedge derivatives
The Company from time to time hedges natural gas liquids based on actual
production prices in order to mitigate some of the volatility associated with
NYMEX pricing. As of December 31, 1998, the Company was not a party to natural
gas liquids derivatives.
Natural gas hedge derivatives
The Company employs a policy of hedging a portion of its 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. As of
December 31, 1998, the Company has hedged a portion of its gas price risk with
swap contracts that establish a fixed floor price for a notional amount of sales
volume; collar contracts that provide a fixed floor price but allow the Company
to participation, within a contractual range, in index prices if they close
above the contractual floor price; and, collar contracts with short put options,
the terms of which are similar to collar contracts except that the Company's
floor price on a notional sales volume becomes variable, at an above market
differential, if market prices fall below the short put index price. 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.
Non-hedge derivatives
As of December 31, 1998, the Company, through its merger with Mesa and
acquisition of Chauvco, is a party to the Canadian denominated interest rate cap
agreement, foreign exchange rate swaps and the BTU Swap that are described more
fully in Quantitative Disclosures, above, and Note J of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data". These financial instruments do not qualify as hedges of interest rate,
foreign exchange rate or commodity price risk.
The Company has a policy and strategy, as of December 31, 1998, to only
enter into interest rate, foreign exchange rate or commodity price derivative
instruments that qualify as hedges of its existing interest rate, foreign
exchange rate or commodity price risks. The Company's derivative instruments
that were initiated by Mesa and Chauvco will be allowed to mature by their terms
unless the Company encounters an opportunity, under terms more favorable than
are presently available, to terminate the contracts prior to their contractual
maturities. See Notes B, C and J of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for further
discussions relative to the Company's objectives and general strategies
associated with its hedge instruments.
As of December 31, 1998, the Company's primary risk exposures associated
with financial instruments to which it is a party include natural gas and crude
oil price volatility, interest rate volatility and Canadian dollar to United
States dollar foreign exchange rate volatility. The Company's primary risk
exposures associated with financial instruments have not changed significantly
since December 31, 1997.
45
46
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Consolidated Financial Statements of Pioneer Natural
Resources Company:
Independent Auditors' Reports............................. 47
Consolidated Balance Sheets as of December 31, 1998 and
1997................................................... 49
Consolidated Statements of Operations and Comprehensive
Income (Loss) for the Years Ended December 31,1998,
1997 and 1996.......................................... 50
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1998, 1997 and 1996........... 51
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996....................... 52
Notes to Consolidated Financial Statements................ 53
Unaudited Supplementary Information....................... 88
46
47
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders
Pioneer Natural Resources Company:
We have audited the accompanying consolidated balance sheet of Pioneer
Natural Resources Company and subsidiaries as of December 31, 1998, and the
related consolidated statements of operations and comprehensive income (loss),
stockholders' equity, and cash flows for the year then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Pioneer Natural Resources Company and subsidiaries at December 31, 1998, and the
consolidated results of its operations and its cash flows for the year then
ended in conformity with generally accepted accounting principles.
Ernst & Young LLP
Dallas, Texas
February 2, 1999, except for Note E
as to which the date is March 19, 1999
47
48
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Pioneer Natural Resources Company:
We have audited the consolidated balance sheet of Pioneer Natural Resources
Company and subsidiaries as of December 31, 1997, and the related consolidated
statements of income and comprehensive income, shareholders' equity, and cash
flows for the years ended December 31, 1997 and 1996. 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 Pioneer
Natural Resources Company and subsidiaries as of December 31, 1997, and the
results of their operations and their cash flows for each of the years in the
two-year period ended December 31, 1997, in conformity with generally accepted
accounting principles.
KPMG LLP
Midland, Texas
February 13, 1998
48
49
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
ASSETS
DECEMBER 31,
------------------------
1998 1997
----------- ----------
Current assets:
Cash and cash equivalents................................. $ 59,221 $ 71,713
Accounts receivable:
Trade, net............................................. 33,384 75,432
Affiliates............................................. 3,657 --
Oil and gas sales...................................... 73,479 116,500
Inventories............................................... 15,221 13,576
Deferred income taxes..................................... 7,100 16,900
Other current assets...................................... 9,926 14,067
----------- ----------
Total current assets.............................. 201,988 308,188
----------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts
methods of accounting:
Proved properties...................................... 3,621,630 3,575,971
Unproved properties.................................... 342,589 545,074
Accumulated depletion, depreciation and amortization...... (930,111) (605,203)
----------- ----------
3,034,108 3,515,842
----------- ----------
Deferred income taxes....................................... 96,800 206,400
Other property and equipment, net........................... 55,010 44,017
Other assets, net........................................... 93,408 78,543
----------- ----------
$ 3,481,314 $4,152,990
=========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt...................... $ 306,521 $ 5,791
Accounts payable:
Trade.................................................. 94,937 176,697
Affiliates............................................. 4,492 9,994
Accrued interest payable.................................. 33,194 13,697
Other current liabilities................................. 87,688 55,373
----------- ----------
Total current liabilities......................... 526,832 261,552
----------- ----------
Long-term debt, less current maturities..................... 1,868,744 1,943,718
Other noncurrent liabilities................................ 232,461 180,275
Deferred income taxes....................................... 64,200 218,600
Stockholders' equity:
Preferred stock, $.01 par value; 100,000,000 shares
authorized; one share issued and outstanding........... -- --
Common stock, $.01 par value; 500,000,000 shares
authorized; 100,833,615 and 101,037,562 shares issued
at December 31, 1998 and 1997, respectively............ 1,008 1,010
Additional paid-in capital................................ 2,347,996 2,359,992
Treasury stock, at cost; 537,392 and 591 shares at
December 31, 1998 and 1997, respectively............... (10,388) (21)
Unearned compensation..................................... -- (16,196)
Retained deficit.......................................... (1,552,442) (795,940)
Accumulated other comprehensive income (loss):
Cumulative translation adjustment...................... 2,903 --
----------- ----------
Total stockholders' equity........................ 789,077 1,548,845
Commitments and contingencies
----------- ----------
$ 3,481,314 $4,152,990
=========== ==========
The accompanying notes are an integral part of these consolidated financial
statements.
49
50
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1997 1996
---------- ----------- --------
Revenues:
Oil and gas............................................ $ 711,492 $ 536,782 $396,931
Natural gas processing................................. -- -- 23,814
Interest and other..................................... 10,452 4,278 17,458
Gain (loss) on disposition of assets, net.............. (445) 4,969 97,140
---------- ----------- --------
721,499 546,029 535,343
---------- ----------- --------
Costs and expenses:
Oil and gas production................................. 223,551 144,170 110,334
Natural gas processing................................. -- -- 12,528
Depletion, depreciation and amortization............... 337,308 212,435 112,134
Impairment of oil and gas properties................... 459,519 1,356,390 --
Exploration and abandonments........................... 121,858 77,160 23,030
General and administrative............................. 73,000 48,763 28,363
Reorganization......................................... 33,199 -- --
Interest............................................... 164,285 77,550 46,155
Other.................................................. 39,605 7,124 2,451
---------- ----------- --------
1,452,325 1,923,592 334,995
---------- ----------- --------
Income (loss) before income taxes and extraordinary
item................................................... (730,826) (1,377,563) 200,348
Income tax benefit (provision)........................... (15,600) 500,300 (60,100)
---------- ----------- --------
Income (loss) before extraordinary item.................. (746,426) (877,263) 140,248
Extraordinary item -- loss on early extinguishment of
debt, net of tax....................................... -- (13,408) --
---------- ----------- --------
Net income (loss)........................................ (746,426) (890,671) 140,248
Other comprehensive income (loss):
Currency translation adjustment........................ 2,903 -- (3,303)
---------- ----------- --------
Comprehensive income (loss).............................. $ (743,523) $ (890,671) $136,945
========== =========== ========
Income (loss) per share:
Basic:
Income (loss) before extraordinary item............. $ (7.46) $ (16.88) $ 3.95
Extraordinary item.................................. -- (.26) --
---------- ----------- --------
Net income (loss)................................... $ (7.46) $ (17.14) $ 3.95
========== =========== ========
Diluted:
Income (loss) before extraordinary item............. $ (7.46) $ (16.88) $ 3.47
Extraordinary item.................................. -- (.26) --
---------- ----------- --------
Net income (loss)................................... $ (7.46) $ (17.14) $ 3.47
========== =========== ========
Dividends declared per share............................. $ .10 $ .10 $ .10
========== =========== ========
Weighted average shares outstanding...................... 100,055 51,973 35,475
========== =========== ========
The accompanying notes are an integral part of these consolidated financial
statements.
50
51
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(IN THOUSANDS)
ACCUM. OTHER
ADDITIONAL UNEARNED RETAINED COMPREHENSIVE TOTAL
COMMON PAID-IN TREASURY COMPEN- EARNINGS INCOME STOCKHOLDERS'
STOCK CAPITAL STOCK SATION (DEFICIT) (LOSS) EQUITY
------ ---------- -------- -------- ----------- ------------- -------------
Balance at January 1, 1996...... $ 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
and option awards............. -- 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 ($.10 per share)...... -- -- -- -- (3,550) -- (3,550)
Other comprehensive income
(loss):
Currency translation
adjustment.................. -- -- -- -- -- (3,303) (3,303)
------ ---------- -------- -------- ----------- ------- ----------
Balance at December 31, 1996.... 369 462,873 (31,528) (1,625) 100,207 -- 530,296
------ ---------- -------- -------- ----------- ------- ----------
Common stock issued:
Acquisition of MESA, Inc...... 318 982,248 -- -- -- -- 982,566
Acquisition of Chauvco
Resources, Ltd.............. 249 688,081 -- -- -- -- 688,330
Acquisition of properties..... 16 44,857 -- -- -- -- 44,873
Exercise of long-term incentive
plan stock options............ 5 11,591 -- -- -- -- 11,596
Cancellation of treasury
shares........................ (19) (34,441) 34,460 -- -- -- --
Exchange of preferred shares for
common shares................. 67 182,909 -- -- -- -- 182,976
Restricted shares awarded....... 5 18,974 -- (18,079) -- -- 900
Tax benefits related to stock
and option awards............. -- 2,900 -- -- -- -- 2,900
Purchase of treasury stock...... -- -- (2,953) -- -- -- (2,953)
Amortization of unearned
compensation.................. -- -- -- 3,508 -- -- 3,508
Net loss........................ -- -- -- -- (890,671) -- (890,671)
Dividends ($.10 per share)...... -- -- -- -- (5,476) -- (5,476)
------ ---------- -------- -------- ----------- ------- ----------
Balance at December 31, 1997.... 1,010 2,359,992 (21) (16,196) (795,940) -- 1,548,845
------ ---------- -------- -------- ----------- ------- ----------
Common stock issued in
settlement of litigation...... -- 342 -- -- -- -- 342
Reduction in common stock issued
for acquisition of Chauvco
Resources Ltd................. (4) (11,094) -- -- -- -- (11,098)
Exercise of long-term incentive
plan stock options............ -- 3 -- -- -- -- 3
Restricted shares awarded....... 2 3,053 -- (493) -- -- 2,562
Tax provision related to stock
and option awards............. -- (4,300) -- -- -- -- (4,300)
Purchase of treasury stock...... -- -- (10,367) -- -- -- (10,367)
Amortization of unearned
compensation.................. -- -- -- 16,689 -- -- 16,689
Net loss........................ -- -- -- -- (746,426) -- (746,426)
Dividends ($.10 per share)...... -- -- -- -- (10,076) -- (10,076)
Other comprehensive income
(loss):
Currency translation
adjustment.................. -- -- -- -- -- 2,903 2,903
------ ---------- -------- -------- ----------- ------- ----------
Balance at December 31, 1998.... $1,008 $2,347,996 $(10,388) $ -- $(1,552,442) $ 2,903 $ 789,077
====== ========== ======== ======== =========== ======= ==========
The accompanying notes are an integral part of these consolidated financial
statements.
51
52
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
--------- ---------- ---------
Cash flows from operating activities:
Net income (loss)....................................... $(746,426) $ (890,671) $ 140,248
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depletion, depreciation and amortization............. 337,308 212,435 112,134
Impairment of oil and gas properties................. 459,519 1,356,390 --
Exploration expenses, including dry holes............ 92,311 63,288 17,262
Deferred income taxes................................ 18,600 (501,300) 57,400
Gain (loss) on disposition of assets, net............ 445 (4,969) (97,140)
Loss on early extinguishment of debt, net of tax..... -- 13,408 --
Other noncash items.................................. 66,300 18,886 (1,360)
Change in operating assets and liabilities, net of
effects from acquisitions and dispositions:
Accounts receivable.................................. 85,413 (39,774) (2,674)
Inventories.......................................... 2,714 (5,941) 1,842
Other current assets................................. 30 (1,913) (32)
Accounts payable..................................... (29,800) 27,138 (656)
Other current liabilities............................ 27,662 (18,768) 3,082
--------- ---------- ---------
Net cash provided by operating activities....... 314,076 228,209 230,106
--------- ---------- ---------
Cash flows from investing activities:
Payment for acquisitions, net of cash acquired.......... -- (15,490) --
Proceeds from disposition of wholly-owned subsidiaries,
net of cash disposed................................. -- -- 183,181
Proceeds from disposition of assets..................... 21,876 115,735 58,370
Additions to oil and gas properties..................... (507,337) (428,640) (219,394)
Other property additions, net........................... (31,546) (12,783) (8,428)
--------- ---------- ---------
Net cash provided by (used in) investing
activities.................................... (517,007) (341,178) 13,729
--------- ---------- ---------
Cash flows from financing activities:
Borrowings under long-term debt......................... 947,180 821,148 782
Principal payments on long-term debt.................... (711,524) (648,208) (222,157)
Payments of other noncurrent liabilities................ (17,091) (7,740) (2,642)
Deferred loan fees/issuance costs....................... (7,189) (2,396) (20)
Dividends............................................... (10,076) (5,476) (3,550)
Purchase of treasury stock.............................. (10,367) (2,953) (24,671)
Exercise of long-term incentive plan stock options...... -- 11,596 6,904
--------- ---------- ---------
Net cash provided by (used in) financing
activities.................................... 190,933 165,971 (245,354)
--------- ---------- ---------
Net increase (decrease) in cash and cash equivalents...... (11,998) 53,002 (1,519)
Effect of exchange rate changes on cash and cash
equivalents............................................. (494) -- 290
Cash and cash equivalents, beginning of year.............. 71,713 18,711 19,940
--------- ---------- ---------
Cash and cash equivalents, end of year.................... $ 59,221 $ 71,713 $ 18,711
========= ========== =========
The accompanying notes are an integral part of these consolidated financial
statements.
52
53
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
NOTE A. ORGANIZATION AND NATURE OF OPERATIONS
Pioneer Natural Resources Company (the "Company") is a Delaware Corporation
whose common stock is listed and traded on the New York Stock Exchange and the
Toronto Stock Exchange. The Company was formed by the merger of Parker & Parsley
Petroleum Company ("Parker & Parsley") and MESA Inc. ("Mesa") on August 7, 1997.
The Company was significantly expanded by the subsequent acquisition of the
Canadian and Argentine oil and gas business of Chauvco Resources Ltd.
("Chauvco"), a publicly traded independent oil and gas company based in Calgary,
Canada, on December 18, 1997. The Company is an oil and gas exploration and
production company with ownership interests in oil and gas properties located
principally in the Mid Continent, Southwestern and onshore and offshore Gulf
Coast regions of the United States and in Argentina, Canada and South Africa.
In accordance with the provisions of Accounting Principles Board Opinion
No. 16, "Business Combinations" ("APB 16"), both the merger with Mesa and the
acquisition of Chauvco have been accounted for as purchases by the Company
(formerly Parker & Parsley). As a result, the historical financial statements
for the Company are those of Parker & Parsley prior to August 1997; for the
period from August 1997 through December 31, 1997, the historical financial
statements for the Company reflect the above described merger of Parker &
Parsley and Mesa; and, as of December 31, 1997, the financial statements for the
Company include the addition of the acquired assets and liabilities of Chauvco.
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 percent-owned oil and gas partnerships in accordance with industry practice.
The Company owns less than a 20 percent interest in the oil and gas partnerships
that it proportionately consolidates. 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, the
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.
INVENTORIES. Inventories consist of lease and well equipment which are
carried at the lower of cost or market, on a first-in first-out basis.
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" ("SFAS 19"). Under this method, all costs
associated with productive wells and nonproductive development wells are
capitalized while nonproductive exploration costs are expensed. The Company
capitalizes interest on expenditures for significant development projects until
such time as operations commence.
53
54
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
Capitalized costs relating to proved properties are depleted using the
unit-of-production method based on proved reserves as estimated by the Company's
engineers. 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.
Capitalized costs of individual properties sold or abandoned 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.
If significant, the Company accrues the estimated future costs to plug and
abandon wells under the unit-of-production method. The charge, if any, is
reflected in the accompanying Consolidated Statements of Operations and
Comprehensive Income (Loss) as abandonment expense while the liability is
reflected in the accompanying Consolidated Balance Sheets as other liabilities.
Plugging and abandonment liabilities assumed in a business combination accounted
for as a purchase are recorded at fair value. At December 31, 1998, and 1997,
the Company has plugging and abandonment liabilities of $44.5 million and $35.9
million, respectively.
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment by comparing their cost to their estimated
value on a project-by-project basis. The estimated value is affected by the
results of exploration activities, commodity price outlooks, planned future
sales or expiration of all or a portion of such projects. If the quantity of
potential reserves determined by such evaluations are not sufficient to fully
recover the cost invested in each project, the Company will recognize a loss 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.
IMPAIRMENT OF LONG-LIVED ASSETS. 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"), 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 estimated fair value of the
asset.
NATURAL GAS PROCESSING FACILITIES. Through December 31, 1996, the Company
depreciated its gas processing, gathering and transmission facilities and
equipment on a straight-line basis over the estimated useful lives of the
assets, which ranged from 14 to 21 years. Capitalized costs relating to gas
contracts, representing the right to extract liquids and gas, were 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 estimated by the
Company's engineers. Upon disposition of a natural gas processing facility, the
cost and related accumulated depreciation and amortization was eliminated from
the accounts and any gain or loss was included in results of operations.
In 1997, the Company began accounting for its natural gas processing
facilities activities as part of its oil and gas properties for financial
reporting purposes. During 1998 and 1997, all revenues and expenses derived from
third party gas volumes processed through the Company's natural gas processing
facilities are reported as components of oil and gas production costs, and the
capitalized costs of natural gas processing facilities are included in proved
oil and gas properties and depleted using the unit-of-production method.
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.
54
55
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
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
basis. 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. 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. Additionally, in accordance with SFAS
109, the Company assesses the likelihood of whether some portion or all of its
recognized deferred tax assets will not be realized in future operating periods.
If such assessments determine that it is more likely than not that some portion
of deferred tax assets will not ultimately be realized, the Company establishes
a deferred tax asset valuation allowance to reduce the carrying value of its
deferred tax assets. Such allowances are recognized in the Company's
Consolidated Balance Sheets as reductions to deferred tax assets and, during the
operating periods in which the allowances are established, in the accompanying
Consolidated Statements of Operations and Comprehensive Income (Loss) as
components of income tax benefit (provision).
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. In accordance with the provisions of Statement of
Financial Accounting Standards No. 128, "Earnings per Share" ("SFAS 128"), basic
net income (loss) per share is computed by dividing income available to common
stockholders by the weighted average number of common shares outstanding for the
period. The computation of diluted net income (loss) per share reflects the
potential dilution that could occur if securities or other contracts to issue
common stock were exercised or converted into common stock or resulted in the
issuance of common stock that then shared in the earnings of the entity. For
1998 and 1997, the computation of diluted net loss per share was antidilutive;
therefore, the amounts reported for basic and diluted net loss per share were
the same. The computation of 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 ("Preferred Shares")
which increased the weighted average number of shares outstanding to 42.6
million.
COMPREHENSIVE INCOME (LOSS). In June 1997, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standards No.
130, "Reporting Comprehensive Income" (SFAS 130"). SFAS 130 established
standards for the reporting and display of comprehensive income or loss and its
components in a full set of financial statements. Comprehensive income or loss
is determined as net income or loss plus "other comprehensive income or loss"
items that under generally accepted accounting principles are excluded from net
income or loss. The Company's only item of other comprehensive income or loss
are translation adjustments arising from the translation of the financial
statements of non-United States subsidiary entities, whose functional currency
is not United States dollars, to United States dollars. Accordingly, the
accompanying Consolidated Statements of Operations and Comprehensive Income
(Loss) report and display comprehensive income or loss for each period
presented.
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
55
56
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
of a noncapital nature are recorded when environmental assessment and/or
remediation is probable and the costs can be reasonably estimated. Such
liabilities are generally undiscounted unless the timing of cash payments for
the liability are fixed or reliably determinable. The Company believes that the
costs for compliance with current environmental laws and regulations have not
had and will not have a material effect on the Company's financial position or
results of operations.
REVENUE RECOGNITION. The Company uses the entitlements method of accounting
for crude oil and natural gas revenues. 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. As of December 31, 1998 and 1997, such entitlement
assets totaled $38.2 million and $49.2 million, respectively. Entitlement
liabilities totaled $20.6 million and $20.2 million at December 31, 1998 and
1997, respectively.
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 hedging contract must be an
asset, liability or forecasted transaction that exposes the Company to price,
interest rate or foreign exchange rate risk that is not offset in another asset
or liability, the hedging contract must reduce that price, interest rate or
foreign exchange 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 hedged asset,
liability or forecasted transaction, such that changes in the market value of
the financial instrument will be offset by the effect of price, interest rate or
foreign exchange rate changes on the exposed items.
Gains or losses realized from financial instruments that qualify as hedges
are deferred as assets or liabilities in the accompanying Consolidated Balance
Sheets until the underlying hedged asset, liability or transaction monetizes,
matures or is otherwise recognized under generally accepted accounting
principles. Hedge gains or losses that are recognized in the accompanying
Consolidated Statements of Operations and Comprehensive Income (Loss) are
classified as components of the commodity prices, interest or foreign exchange
rates that the financial instruments hedge. Derivative financial instruments
that do not qualify as hedges are marked-to-market and recorded as assets or
liabilities in the accompanying Consolidated Balance Sheets. Changes in the fair
values of such instruments are recognized as other income or other expense in
the accompanying Consolidated Statements of Operations and Comprehensive Income
(Loss) during the periods in which their fair values change. See Note J for a
description of the specific types of derivative transactions in which the
Company participates.
FOREIGN CURRENCY TRANSLATION. The financial statements of non-United States
entities, whose functional currency is not United States dollars, are translated
to United States 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-United States balances are recorded directly in
stockholders' equity. Foreign currency transaction gains and losses are included
in net income (loss).
56
57
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
A summary of the exchange rates used in the preparation of these
consolidated financial statements appear below:
DECEMBER 31,
---------------------
1998 1997 1996
----- ----- -----
Canadian Dollar conversion to U.S. Dollar -- Balance
sheet..................................................... .6534.. .6997 N/A
Canadian Dollar conversion to U.S. Dollar -- Statement of
operations................................................ .6740 N/A N/A
Australian Dollar conversion to U.S. Dollar -- Statement of
operations................................................ N/A N/A.. .7562
RECLASSIFICATIONS. Certain reclassifications have been made to the 1997 and
1996 amounts to conform to the 1998 presentations.
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, 1998 and 1997:
1998 1997
----------------------- -----------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
---------- ---------- ---------- ----------
(IN THOUSANDS)
Financial assets:
Cash and cash equivalents.................. $ 59,221 $ 59,221 $ 71,713 $ 71,713
Investments in a non-affiliated entity..... 12,000 12,000 -- --
Financial liabilities:
Long-term debt:
Practicable to estimate fair value:
Lines of credit and term note......... 1,239,032 1,239,032 1,608,980 1,608,980
8 7/8% senior notes due 2005.......... 150,000 144,108 150,000 170,025
8 1/4% senior notes due 2007.......... 149,414 137,826 149,345 166,950
6 1/2% senior notes due 2008.......... 348,418 284,442 -- --
7 1/5% senior notes due 2028.......... 249,908 177,325 -- --
Not practicable to estimate fair value:
Other long term debt.................. 38,493 -- 41,184 --
Derivative financial instruments, including
off balance sheet instruments (see Note
J):
Interest rate agreements................ (80) 966 2,100 2,704
Foreign currency agreements............. (15,350) (15,350) (7,438) (7,438)
Commodity price hedges.................. (41) 26,548 (689) 12,061
BTU swap agreement...................... (15,172) (15,172) (6,893) (6,893)
CASH AND CASH EQUIVALENTS, 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.
INVESTMENT IN A NON-AFFILIATED ENTITY. At December 31, 1998, the Company
had an equity investment in a closely-held non-affiliated entity. The fair value
of this investment was estimated using quoted market prices.
LONG-TERM DEBT. The carrying amount of borrowings outstanding under the
Company's line of credit (see Note E for definitions and descriptions of each)
approximates fair value because these instruments bear
57
58
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
interest at rates tied to current market rates. The fair values of each of the
senior note issuances were based on quoted market prices for each of 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, 1998 and 1997, the Company
had outstanding five interest rate swap agreements with an aggregate notional
amount of $150 million and one interest rate cap agreement denominated in
Canadian dollars with a notional amount of $80 million Canadian dollars. In
addition to the agreements above, at December 31, 1997, the Company had
outstanding one interest rate swap agreement with a notional amount of $250
million and one cross-currency interest swap with a notional amount of $60
million. These are more fully described in Note J. The fair values of each of
the open interest rate swap agreements were obtained from quotes by the
respective counterparties and represent the estimated net amount the Company
would receive or pay upon termination of the agreements as of December 31 of
each of the respective years, taking into consideration interest rates at that
time.
FOREIGN CURRENCY AGREEMENTS. At December 31, 1998 and 1997, the Company had
two foreign exchange swap agreements with an aggregate remaining notional amount
of $144 million and $216 million as of December 31, 1998 and 1997, respectively.
These are more fully described in Note J. The fair values of these agreements
were obtained from quotes from the counterparty and represent the amounts that
the Company would have paid upon termination of the agreements at December 31,
of the respective years, based upon the spot and forward foreign currency
exchange rates existing in the market at those times.
COMMODITY PRICE HEDGES. The fair values of commodity price hedges
outstanding at December 31, 1998 and 1997 were obtained from quotes provided by
the individual counterparties for each agreement and represent the amount the
Company would be able to receive or required to pay to liquidate the hedges as
of December 31 of each of the respective years.
BTU SWAP AGREEMENTS. The fair value of the Btu swap agreements outstanding
at December 31, 1998 and 1997 were obtained from quotes provided by the
counterparty to these agreements and represent the amount the Company would have
been required to pay to liquidate the agreements as of December 31, for each of
the respective years, based upon the market price for oil and gas as specified
in the agreements.
58
59
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
NOTE D. ACQUISITIONS
During August 1997, Parker & Parsley completed a merger with Mesa that
resulted in the creation of the Company. The transaction was accounted for as a
purchase of Mesa by Parker & Parsley in accordance with APB 16. In December
1997, the Company acquired the Canadian and Argentine oil and gas business of
Chauvco, which was also accounted for as a purchase by the Company. These
transactions were accomplished through the issuance of common stock of the
Company to Mesa and Chauvco shareholders (31,782,263 shares and 24,515,179
shares, respectively). The aggregate purchase consideration for assets acquired
and liabilities assumed from Mesa and Chauvco was $991.0 million and $721.4
million, respectively. The following table represents the allocation of the
total purchase price of Mesa and Chauvco to the acquired assets and liabilities
based upon the fair values assigned to each of the significant assets acquired
and liabilities assumed.
ALLOCATION OF AGGREGATE
PURCHASE CONSIDERATION
------------------------
MESA CHAUVCO
----------- ----------
(IN THOUSANDS)
Net working capital......................................... $ 4,438 $ (20,191)
Property, plant and equipment............................... 2,530,114 1,125,256
Other assets................................................ 40,821 65,922
Long-term debt.............................................. (1,191,038) (234,709)
Other non-current liabilities, including deferred taxes..... (393,365) (214,919)
----------- ----------
$ 990,970 $ 721,359
=========== ==========
Common Stock consideration.................................. $ 982,566 $ 677,232
Transaction costs........................................... 8,404 7,890
Notes payable............................................... -- 36,237
----------- ----------
Aggregate purchase consideration............................ $ 990,970 $ 721,359
=========== ==========
The liabilities assumed include amounts recorded for litigation and certain
other pre-acquisition contingencies of Mesa and Chauvco.
In December 1997, the Company completed an acquisition of assets in the
East Texas Basin from American Cometra, Inc. ("ACI") and Rockland Pipeline Co.
("Rockland"), both subsidiaries of Electrafina S.A. of Belgium ("America Cometra
Acquisition"). The total consideration paid was approximately $130 million,
consisting of $85 million in cash and 1.6 million shares of the Company's common
stock. The Company acquired ACI's producing wells, acreage, seismic data,
royalties and mineral interests, and Rockland's gathering system pipeline and
gas processing plant in the East Texas Basin.
PRO FORMA RESULTS OF OPERATIONS. The following table reflects the pro forma
results of operations as though the merger with Mesa, the acquisition of
Chauvco, the 1996 sale of certain wholly-owned subsidiaries and the 1996 sale of
certain non-strategic domestic assets occurred on January 1, 1996. The pro forma
results of operations of the America Cometra Acquisition are not presented as
they are not material to the consolidated financial statements of the Company.
YEAR ENDED DECEMBER 31,
------------------------
1997 1996
----------- ----------
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
(UNAUDITED)
Revenues.................................................... $ 909,564 $959,208
Income (loss) before extraordinary item..................... $(931,784) $ 48,717
Income (loss) per share before extraordinary item........... $ (9.42) $ .49
59
60
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
NOTE E. LONG-TERM DEBT
Long-term debt consists of the following:
DECEMBER 31,
-----------------------
1998 1997
---------- ----------
(IN THOUSANDS)
Lines of credit and term note............................... $1,249,984 $1,608,980
8 7/8% senior notes due 2005................................ 150,000 150,000
8 1/4% senior notes due 2007 (net of discount).............. 149,414 149,345
6 1/2% senior notes due 2008 (net of discount).............. 348,418 --
7 1/5% senior notes due 2028 (net of discount).............. 249,908 --
Other....................................................... 27,541 41,184
---------- ----------
2,175,265 1,949,509
Less current maturities..................................... 306,521 5,791
---------- ----------
$1,868,744 $1,943,718
========== ==========
Maturities of long-term debt at December 31, 1998 are as follows (in
thousands):
1999........................................................ $306,521
2000........................................................ $ --
2001........................................................ $ --
2002........................................................ $934,349
2003........................................................ $ 1,447
Thereafter.................................................. $932,948
LINES OF CREDIT AND TERM NOTE. On August 7, 1997, the successor to Parker &
Parsley and Mesa Operating Company, Pioneer Natural Resources USA, Inc.
("Pioneer USA") (the "Borrower"), entered into two credit facility agreements
("Credit Facility Agreements") with a syndicate of banks (the "Banks") that
refinanced the credit facilities of Parker & Parsley and Mesa. On December 18,
1997, the Company amended and restated the Credit Facility Agreements to
substitute the Company as the Borrower in place of Pioneer USA. One Credit
Facility Agreement (the "Primary Facility") provides for a $1.075 billion credit
facility. On December 31, 1998, the Company had $993.6 million of outstanding
borrowings under the Primary Facility. The maturity date for the Primary
Facility is August 7, 2002. The second Credit Facility Agreement (the "364-day
Facility") provided for a $300 million credit facility with a current maturity
date of August 5, 1999. On June 29, 1998, the Company and the Banks executed an
amendment that reduced the commitment under the 364-day Facility to $85 million.
At December 31, 1998, the Company did not have any borrowings outstanding on the
364-day Facility. Also, on December 18, 1997, the Company refinanced all of
Chauvco's outstanding debt by establishing a $290 million Canadian credit
facility ("Canadian Facility"). During the fourth quarter of 1998, the
outstanding borrowings under the Canadian Facility converted to a $276.0 million
term loan that matures on December 19, 2003, under which the borrower is Pioneer
Natural Resources Canada Inc., and the Company and certain of its subsidiaries
(not including Pioneer USA) provide guarantees. On December 31, 1998, the
Company had $276.0 million of outstanding term loan borrowings under the
Canadian Facility.
Advances on both Credit Facility Agreements bear interest, at the
Borrower's option, based on (a) the prime rate of NationsBank of Texas, N.A.
("Prime Rate") (7.75 percent at December 31, 1998), (b) a Eurodollar rate
(substantially equal to the London Interbank Offered Rate ("LIBOR")), 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) a competitive bid rate as quoted by the
60
61
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
lending banks electing to participate pursuant to a request by the Borrower.
Advances that are LIBOR Rate have periodic maturities, at the Borrower's option,
of one, two, three, six, nine or twelve months. Advances that are competitive
bid rate have periodic maturities, at the Borrower's option, of not less than 15
days nor more than 360 days. The interest rates on the LIBOR Rate advances vary,
with the interest rate margin ranging from 18 basis points to 55 basis points,
including commitment utilization fees. The interest rate margin is determined by
a grid based upon the Company's senior unsecured long-term public debt rating.
The Company's obligations are guaranteed by Pioneer USA and certain other United
States subsidiaries, and are secured by a pledge of a portion of the capital
stock of certain non-United States subsidiaries.
The Credit Facility Agreements contain various restrictive covenants and
compliance requirements, which include (a) limits on the incurrence of
additional indebtedness and certain types of liens and (b) restrictions as to
merger, sale or transfer of assets and transactions without the Banks' consent.
On March 19, 1999, the Company and the Banks executed amendments to the
Credit Facilities that provide for a $495 million reduction in the combined loan
commitments under the Credit Facilities by December 31, 1999; an increase in the
maximum interest rate margin on LIBOR Rate advances to 350 basis points,
including facility and leverage fees; provisions, under certain circumstances,
for enhancing the Banks' collateral rights; and, amendment of certain associated
debt covenants, the most restrictive of which being the maintenance of a ratio
of outstanding Company senior debt to earnings before interest, depletion,
depreciation, amortization, income taxes, exploration and abandonment and other
non-cash expenses ("EBITDAX") not to exceed 5.75 to one through September 30,
1999, 4.25 to one through March 31, 2000, and 3.5 to one thereafter.
Additionally, the amendment provisions provide for the consolidation of the
Primary Facility and the Canadian Facility. To satisfy the commitment reduction
provisions of the amended Credit Facilities, the Company intends to reduce its
outstanding borrowings through the use of funds generated by the individual or
combined sources of operating activities, oil and gas property divestitures,
borrowings under subordinated debt agreements or additional issuances of equity.
The Company also executed a $100 million note (the "Term Note"), dated as
of December 22, 1997, payable to NationsBank of Texas, N.A. to fund short-term
working capital needs. At the request of the Company, the Term Note was canceled
on January 20, 1998.
SENIOR NOTES. During 1998, the Company completed the issuance of $350
million of 6 1/2% senior notes due 2008 and $250 million of 7 1/5% senior notes
due 2028 for combined net proceeds of $593 million. The proceeds were used
primarily to repay the Company's bank indebtedness.
At December 31, 1998, the Company has the following four issuances of
senior indebtedness 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.
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. Interest on the
8 1/4% senior notes is payable semi-annually on February 15 and August 15 of
each year.
6 1/2% senior notes due 2008. $350 million aggregate principal amount
6 1/2% senior notes dated January 13, 1998, due January 15, 2008. Interest on
the 6 1/2% senior notes is payable semi-annually on January 15 and July 15 of
each year.
7 1/5% senior notes due 2028. $250 million aggregate principal amount
7 1/5% senior notes dated January 13, 1998, due July 15, 2028. Interest on the
7 1/5% senior notes is payable semi-annually on January 15 and July 15 of each
year.
61
62
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
The 8 7/8% senior notes due 2005 and the 8 1/4% senior notes due 2007 are
governed by an Indenture between the Company and The Chase Manhattan Bank
(National Association) dated April 12, 1995. The 6 1/2% senior notes due 2008
and the 7 1/5% senior notes due 2028 are governed by an Indenture between the
Company and the Bank of New York dated January 15, 1998. The Company's senior
notes are general unsecured obligations 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. Pioneer USA has fully and
unconditionally guaranteed the senior note issuances.
TENDER OFFER FOR SENIOR SUBORDINATED NOTES. On December 18, 1997, the
Company completed a cash tender offer for two senior subordinated note issuances
(the "Subordinated Notes") assumed as part of the merger with Mesa. The Company
redeemed approximately 91 percent of the 11 5/8% senior subordinated discount
notes due 2006 and approximately 98 percent of the 10 5/8% senior subordinated
notes due 2006 (the "10 5/8% Notes") for a purchase price of $829.90 and
$1,171.40, respectively, per $1,000 tendered plus any interest accrued on the
10 5/8% Notes (the "Tender Offer"). As a result, the Company paid $574.5 million
for the principal amount tendered on the Subordinated Notes, including related
fees, and $15.7 million of accrued interest on the 10 5/8% Notes. As a result of
the Tender Offer, the Company recognized an extraordinary loss on early
extinguishment of debt of $11.9 million (net of a related tax benefit of $6.4
million) during the fourth quarter of 1997. The Company financed the purchase
price of the Subordinated Notes tendered in the offer with borrowings under its
Credit Facility Agreements.
EXTRAORDINARY ITEM. In addition to the extraordinary loss resulting from
the Tender Offer described above, the accompanying Consolidated Statement of
Operations and Comprehensive Income (Loss) for the year ended December 31, 1997
includes a $1.5 million (net of a related tax benefit of $800 thousand) non-
cash charge for an extraordinary loss on early extinguishment of debt resulting
from the merger of Parker & Parsley and Mesa. This extraordinary loss relates to
capitalized issuance fees associated with Parker & Parsley's previously existing
bank credit facility which was replaced by the new Credit Facility Agreements
for the Company.
INTEREST EXPENSE. The following amounts have been charged to interest
expense for the years ended December 31, 1998, 1997 and 1996:
1998 1997 1996
-------- ------- -------
(IN THOUSANDS)
Cash payments for interest............................. $135,811 $64,667 $44,405
Cash payments for commitment and agency fees........... -- 1,073 804
Accretion of discounts on loans........................ 11,787 7,348 261
Amortization of capitalized loan fees.................. 1,142 1,177 1,286
Net change in accruals................................. 15,545 3,285 (601)
-------- ------- -------
$164,285 $77,550 $46,155
======== ======= =======
The above amounts include $6 million in 1997 and $12 million in 1996
associated with the Preferred Shares of the Company's wholly-owned finance
subsidiary (see Note I).
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 35 public and nine private drilling partnerships and
three public income partnerships, all of which were formed primarily for the
purpose of drilling and
62
63
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
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 percent, 1.5375 percent and 1.865 percent,
respectively, of the costs and revenues attributable to the Company's interest
in the wells that such Direct Investment Partnership participates. The Company
discontinued the formation of Direct Investment Partnerships in 1995.
The Company, through a wholly-owned subsidiary, 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.
The activities with affiliated partnerships are summarized for the
following related party transactions for the years ended December 31, 1998, 1997
and 1996:
1998 1997 1996
------ ------ ------
(IN THOUSANDS)
Receipt of lease operating and supervision charges in
accordance with standard industry operating agreements... $9,021 $8,547 $8,484
Reimbursement of general and administrative expenses....... $ 739 $1,476 $1,246
RETIREMENT PLANS. Effective August 8, 1997, the Compensation Committee of
the Board of Directors approved a deferred compensation retirement plan for the
officers and certain key employees of the Company. Each officer and key employee
is allowed to contribute up to 25 percent of their base salary. The Company will
then provide a matching contribution of 100 percent of the officer's and key
employee's contribution limited to the first 10 percent of the officer's base
salary and eight percent of the key employee'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.
In December 1998, the Company received notification that an investment fund
group had acquired beneficial ownership of greater than 20 percent of the
Company's Common Stock. Pursuant to the provisions within the Company's deferred
compensation retirement plan, if a third party acquires 20 percent or more of
the Company's Common Stock certain change of control provisions contained within
the plan are triggered. Accordingly, in December 1998, the Compensation
Committee of the Board of Directors determined that a change of control had
occurred, effective September 30, 1998, under the deferred compensation
retirement plan. Consequently, all of the contributions to the deferred
compensation retirement plan from August 1997 to December 15, 1998 were
immediately distributed (December 15, 1998 was the earliest practicable date for
the trust fund, once notified of a change of control, to determine contributions
and investment earnings or losses related thereto for distribution).
During 1996 and prior to August 1997, the officers of Parker & Parsley
participated in a similar deferred compensation retirement plan as noted above.
As part of the merger with Mesa, the plan's change of control provision was
triggered and all funds contributed through August 1997 were immediately vested
and distributed.
CONSULTING FEE. Effective January 1, 1999, the Company entered into an
amended and restated agreement with Rainwater, Inc. for a five year term,
whereby the Company will pay Rainwater, Inc.
63
64
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
$300,000 per year and reimburse Rainwater, Inc. for certain expenses in
consideration for consulting and financial analysis services provided to the
Company by Rainwater, Inc. and its representatives. During 1998, the Company
paid Rainwater, Inc. $400,000 plus expenses for consulting and financial
analysis services under a similar agreement. Richard E. Rainwater, who serves on
the Company's Board of Directors, is the sole shareholder of Rainwater, Inc.
NOTE G. INCENTIVE PLANS
LONG-TERM INCENTIVE PLAN
In August 1997, the Company's stockholders approved a new 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 and restricted stock to directors, officers and 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 percent of the total number of
shares of Common Stock equivalents outstanding minus the total number of shares
of Common Stock subject to outstanding awards on the date of calculation under
any stock-based plan for the directors, officers or employees of the Company.
As previously noted in Note F, in December 1998, the Company received
notification that an investment fund group had acquired beneficial ownership of
greater than 20 percent of the Company's Common Stock. Pursuant to the
provisions within the Company's Long-Term Incentive Plan, if a third party
acquires 20 percent or more of the Company's Common Stock, certain change of
control provisions contained within the plan are triggered. In December 1998,
the Compensation Committee of the Board of Directors determined that a change of
control had occurred, effective September 30, 1998, under the Long-Term
Incentive Plan. Consequently, all awards granted under the Long-Term Incentive
Plan since its inception in August 1997 through September 30, 1998 were
immediately vested and any restrictions were canceled. Accordingly, in 1998, the
Company recognized $9.6 million in other expense related to restricted stock
awards that were vested.
The following table summarizes the cumulative stock and option awards
granted, forfeited, exercised, in the case of options, and the lapse of
restrictions, in the case of shares, under the Company's Long-Term Incentive
Plan during 1998 and 1997:
FOR THE YEAR ENDED DECEMBER 31,
------------------------------------------------------------------
1998 1997
-------------------------------- -------------------------------
SHARES OPTIONS TOTAL SHARES OPTIONS TOTAL
-------- --------- --------- ------- --------- ---------
Outstanding, beginning of
year......................... 476,914 1,716,625 2,193,539 -- -- --
Granted........................ 137,086 2,146,553 2,283,639 476,914 1,716,625 2,193,539
Forfeited...................... (12,585) (923,995) (936,580) -- -- --
Options exercised.............. -- -- -- -- -- --
Shares with lapse of
restrictions................. (601,415) -- (601,415) -- -- --
-------- --------- --------- ------- --------- ---------
Outstanding, end of year....... -- 2,939,183 2,939,183 476,914 1,716,625 2,193,539
======== ========= ========= ======= ========= =========
64
65
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
The following table calculates the number of shares or options available
for grant under the Company's Long-Term Incentive Plan as of December 31, 1998
and 1997:
DECEMBER 31,
-------------------------
1998 1997
----------- -----------
Shares outstanding.......................................... 100,296,223 101,036,971
Options outstanding......................................... 2,939,183 1,716,625
----------- -----------
103,235,406 102,753,596
=========== ===========
Maximum shares/options allowed under the Long-Term Incentive
Plan...................................................... 10,323,541 10,275,360
Less: Outstanding awards under Long-Term Incentive Plan..... (2,939,183) (2,193,539)
Outstanding options under Mesa 1991 stock option
plan.................................................. (407,284) (418,478)
Outstanding options under Mesa 1996 incentive plan.... (422,854) (510,000)
Outstanding options under Parker & Parsley long-term
incentive plan...................................... (810,709) (896,042)
----------- -----------
Shares/options available for future grant................... 5,743,511 6,257,301
=========== ===========
RESTRICTED STOCK AWARDS
NON-EMPLOYEE DIRECTORS. Pursuant to the Long-Term Incentive 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 percent of the then current annual retainer
fee. This award is made in lieu of an amount of cash equal to 50 percent of the
annual retainer fee. In May 1998 and August 1997, the Company issued an
aggregate 17,306 shares and 5,939 shares, respectively, to non-employee
directors pursuant to this arrangement.
When issued, the shares of common stock awarded pursuant to the Long-Term
Incentive 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.
OFFICERS AND KEY EMPLOYEES. The Company, at its sole discretion, may pay
annual bonuses awarded to selected officers and key employees either 100 percent
in cash or partially in cash and partially in the form of restricted stock
awards under the Long-Term Incentive Plan. The Company has established target
bonus levels 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. The bonus awards
are determined in the quarter following the Company's December 31 year-end. Any
restricted 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 one year 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 9, 1998, the
Company awarded an aggregate of 81,300 shares of restricted stock at a price of
$22.375 pursuant to the 1997 annual bonus program. The Company has elected not
to award any restricted stock in conjunction with the 1998 annual bonus program.
65
66
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
During 1998 and 1997, the Company made other Long-Term Incentive Plan
awards of 38,480 and 470,975 shares, respectively, to certain officers and key
employees. The shares awarded are subject to a vesting period and transfer
restrictions.
STOCK OPTIONS AWARDS
The Company has a program of awarding semi-annual stock options to its
officers and employees as part of their annual compensation package. This
program provides for semi-annual awards at an exercise price based upon the
closing sales price of the Company's common stock on the day preceding the date
of grant, a three year vesting schedule and a five year exercise period from
each vesting date. The Company granted 2,146,553 and 1,716,625 options under the
Long-Term Incentive Plan during 1998 and 1997, respectively.
OTHER STOCK BASED PLANS
Prior to the merger with Mesa, both Parker & Parsley and Mesa had long-term
incentive plans (Parker & Parsley Long-Term Incentive Plan, 1991 Stock Option
Plan of Mesa and the 1996 Incentive Plan of Mesa) in place that allowed Parker &
Parsley and Mesa to grant incentive awards similar to the provisions of the
Long-Term Incentive Plan. Upon consummation of the merger between Parker &
Parsley and Mesa, all awards under these plans were assumed by the Company with
the provision that no additional awards be granted under these plans.
The information presented in the remainder of this footnote represents the
awards granted under the Long-Term Incentive Plan since its approval in August
1997, the awards granted in 1997, and 1996 under the Parker & Parsley Long-Term
Incentive Plan, and the assumption in August 1997 of the outstanding option
awards granted under the 1991 Stock Option Plan of Mesa and the 1996 Incentive
Plan of Mesa.
RESTRICTED STOCK AWARDS. The following table reflects the outstanding
restricted stock awards and activity related thereto for 1998, 1997 and 1996:
FOR THE YEAR ENDED FOR THE YEAR ENDED FOR THE YEAR ENDED
DECEMBER 31, 1998 DECEMBER 31, 1997 DECEMBER 31, 1996
-------------------- -------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
NUMBER AVERAGE NUMBER AVERAGE NUMBER AVERAGE
OF SHARES PRICE OF SHARES PRICE OF SHARES PRICE
--------- -------- --------- -------- --------- --------
Restricted stock awards:
Outstanding, beginning of year.................. 476,914 $37.88 79,819 $23.35 225,244 $23.90
Shares granted.................................. 137,086 $21.13 506,786 $37.43 35,080 $26.54
Shares forfeited................................ (12,585) $35.67 -- -- (1,980) $25.13
Lapse of restrictions........................... (601,415) $34.11 (109,691) $25.66 (178,525) $24.65
-------- -------- --------
Outstanding, end of year........................ -- -- 476,914 $37.88 79,819 $23.35
======== ======== ========
STOCK OPTION AWARDS. 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,
----------------------------------
1998 1997 1996
--------- --------- --------
(IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS)
Net income (loss)................................ $(775,349) $(893,729) $139,297
Basic net income (loss) per share................ $ (7.75) $ (17.20) $ 3.90
Diluted net income (loss) per share.............. $ (7.75) $ (17.20) $ 3.43
66
67
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
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 1998, 1997 and 1996:
1998 1997 1996
------- ------- -------
Risk-free interest rate................................. 5.45% 5.72% 6.18%
Expected life........................................... 6 years 7 years 4 years
Expected volatility..................................... 36% 36% 32%
Expected dividend yield................................. .56% .30% .34%
A summary of the Company's stock option plans as of December 31, 1998, 1997
and 1996, and changes during the years ended on those dates is presented below:
FOR THE YEAR ENDED FOR THE YEAR ENDED FOR THE YEAR ENDED
DECEMBER 31, 1998 DECEMBER 31, 1997 DECEMBER 31, 1996
--------------------- --------------------- ---------------------
WEIGHTED WEIGHTED WEIGHTED
NUMBER AVERAGE NUMBER AVERAGE NUMBER AVERAGE
OF OPTIONS PRICE OF OPTIONS PRICE OF OPTIONS PRICE
---------- -------- ---------- -------- ---------- --------
Non-statutory stock options:
Outstanding, beginning of year.............. 3,541,145 $31.63 1,362,629 $24.04 1,230,411 $17.51
Options granted........................... 2,146,553 $19.22 1,744,704 $34.00 637,300 $29.52
Options assumed........................... -- -- 928,478 $33.97 -- --
Options forfeited......................... (1,106,835) $35.75 (1,500) $21.33 (35,000) $23.81
Options exercised......................... (833) $14.25 (493,166) $23.45 (470,082) $14.55
---------- --------- ---------
Outstanding, end of year.................... 4,580,030 $24.83 3,541,145 $31.63 1,362,629 $24.04
========== ========= =========
Exercisable at end of year.................. 3,937,113 $26.60 1,824,520 $29.37 358,177 $18.79
========== ========= =========
Weighted average fair value of options granted
during the year............................. $ 8.21 $ 16.10 $ 10.03
========== ========= =========
The following table summarizes information about the Company's stock
options outstanding at December 31, 1998:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------------------- ----------------------------------
NUMBER WEIGHTED AVERAGE WEIGHTED NUMBER WEIGHTED
RANGE OF OUTSTANDING AT REMAINING AVERAGE EXERCISABLE AT AVERAGE
EXERCISE PRICES DECEMBER 31, 1998 CONTRACTUAL LIFE EXERCISE PRICE DECEMBER 31, 1998 EXERCISE PRICE
--------------- ----------------- ---------------- -------------- ----------------- --------------
$ 6 - 18 1,569,319 5.4 years $15.62 926,402 $16.75
$19 - 28 1,209,377 5.4 years $24.16 1,209,377 $24.16
$29 - 38 1,485,482 4.3 years $30.01 1,485,482 $30.01
$39 - 52 298,638 1.8 years $46.84 298,638 $46.84
$80 - 82 17,214 3.1 years $81.81 17,214 $81.81
--------- ---------
4,580,030 3,937,113
========= =========
In addition to the expense associated with the accelerated vesting of
awards under the Company's Long-Term Incentive Plan that occurred as a result of
the change of control, the Company recognized $3.9 million, $3.3 million and
$1.9 million in general and administrative compensation expense related to its
Incentive Plans during 1998, 1997 and 1996, respectively. Additionally, $3.1
million of the Company's 1998 reorganization costs are compensation expenses
related to its Incentive Plans.
67
68
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
NOTE H. COMMITMENTS AND CONTINGENCIES
SEVERANCE AGREEMENTS. The Company has entered into severance agreements
with its parent company officers, subsidiary company officers and certain key
employees. Salaries and bonuses for the Company's officers are set independent
of this agreement by the Compensation Committee for the parent company officers
and the Management Committee for subsidiary company officers and key employees.
These committees can grant increases or reductions to base salary at their
discretion. The current annual salaries for the parent company officers, the
subsidiary company officers and key employees covered under such agreements
total approximately $7.8 million.
Either the Company or the officer/key employee may terminate the officer's
or key employee's employment under the severance agreement at any time. The
Company must pay the officer or key employee 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 or key employee an amount equal to
one year's base salary and continue health insurance for the officer or key
employee and his or her immediate family for one year if the Company terminates
employment without cause or if the officer or key employee terminates employment
with good reason, which occurs when reductions in the officer's or key
employee's base annual salary exceed specified limits or if, in the case of
officers, the officer is demoted to an officer position junior to their current
officer position or to a non-officer position. If within one year after a change
in control of the Company, the Company terminates the officer or key employee
without cause or if the officer or key employee terminates employment with good
reason, the Company must pay parent company officers an amount equal to 2.99
times the sum of the officer's base salary plus target bonus for the year and
subsidiary company officers and key employees an amount equal to two times the
officer's or key employee's base salary and continue health insurance for the
officer or key employee and his immediate family for one year. If the officer or
key employee 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 or key employee is required to
move, then the Company must pay the officer or key employee one year's base
salary and continue health insurance for the officer or key employee and his or
her immediate family for one year. Officers and key employees are also entitled
to additional payments for certain tax liabilities that may apply to severance
payments following a change in 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, including, but not limited to, the proceedings described below.
The majority of 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.
Masterson. In February 1992, the current lessors of an oil and gas lease
(the "Gas Lease") dated April 30, 1955, between R.B. Masterson et al., as
lessor, and Colorado Interstate Gas Company ("CIG"), as lessee, sued CIG in
Federal District Court in Amarillo, Texas, claiming that CIG had underpaid
royalties due under the Gas Lease. Under the agreements with CIG, the Company,
as successor to Mesa, has an entitlement to gas produced from the Gas Lease. In
August 1992, CIG filed a third-party complaint against the Company for any such
royalty underpayment which may be allocable to the Company. Plaintiffs alleged
that the underpayment was the result of CIG's use of an improper gas sales price
upon which to calculate royalties and that the proper price should have been
determined pursuant to a "favored-nations" clause in a
68
69
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
July 1, 1967, amendment to the Gas Lease. The plaintiffs also sought a
declaration by the court as to the proper price to be used for calculating
future royalties.
The plaintiffs alleged royalty underpayments of approximately $500 million
(including interest at 10 percent) dating from July 1, 1967. In March 1995, the
court made certain pretrial rulings that eliminated approximately $400 million
of the plaintiff's claims (which related to periods prior to October 1, 1989),
but which also reduced a number of the Company's defenses. The Company and CIG
filed stipulations with the court whereby the Company would have been liable for
between 50 percent and 60 percent, depending on the time period covered, of an
adverse judgment against CIG or post-February 1988 underpayments of royalties.
On March 22, 1995, a jury trial began and on May 4, 1995, the jury returned
its verdict. Among its findings, the jury determined that CIG had underpaid
royalties for the period after September 30, 1989, in the amount of
approximately $140,000. Although the plaintiffs argued that the
"favored-nations" clause entitled them to be paid for all of their gas at the
highest price voluntarily paid by CIG to any other lessor, the jury determined
that the plaintiffs were estopped from claiming that the "favored-nations"
clause provides for other than a pricing-scheme to pricing-scheme comparison. In
light of this determination, and the plaintiff's stipulation that a
pricing-scheme to pricing-scheme comparison would not result in any "trigger
prices" or damages, defendants asked the court for a judgment that plaintiffs
take nothing. The court, on June 7, 1995, entered final judgment that plaintiffs
recover no monetary damages. The plaintiffs filed a motion for new trial on June
22, 1995. The court, on July 18, 1997, denied plaintiffs' motion. The plaintiffs
have appealed to the Fifth Circuit Court of Appeals, where oral arguments were
heard in December 1998 and a decision could be announced by the end of the first
quarter of 1999.
On June 7, 1996, the plaintiffs filed a separate suit against CIG and the
Company in state court in Amarillo, Texas, similarly claiming underpayment of
royalties under the "favored-nations" clause, but based upon the above-described
pricing-scheme to pricing-scheme comparison on a well-by-well monthly basis. The
plaintiffs also claim underpayment of royalties since June 7, 1995, under the
"favored-nations" clause based upon either the pricing-scheme to pricing-scheme
method or their previously alleged higher price method. The Company believes it
has several defenses to this action and intends to contest it vigorously. The
Company has not yet determined the amount of damages, if any, that would be
payable if such action was determined adversely to the Company.
The federal court in the above-referenced first suit issued an order on
July 29, 1996, which stayed the state suit pending the plaintiffs' resolution of
the first suit.
Based on the jury verdict and final judgment, the Company does not
currently expect the ultimate resolution of either of these lawsuits to have a
material adverse effect on its financial position or results of operations.
Kansas ad valorem tax.
The Natural Gas Policy Act of 1978 ("NGPA") allows a "severance, production
or similar" tax to be included as an add-on, over and above the maximum lawful
price for natural gas. Based on a Federal Energy Regulatory Commission ("FERC")
ruling that Kansas ad valorem tax was such a tax, Mesa collected the Kansas ad
valorem tax in addition to the otherwise maximum lawful price. The FERC's ruling
was appealed to the United States Court of Appeals for the District of Columbia
("D.C. Circuit"), which held in June 1988 that the FERC failed to provide a
reasoned basis for its findings and remanded the case to the FERC for further
consideration.
On December 1, 1993, the FERC issued an order reversing its prior ruling,
but limiting the effect of its decision to Kansas ad valorem taxes for sales
made on or after June 28, 1988. The FERC clarified the effective date of its
decision by an order dated May 18, 1994. The order clarified that the effective
date applies to tax
69
70
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
bills rendered after June 28, 1988, not sales made on or after that date.
Numerous parties filed appeals on the FERC's action in the D.C. Circuit. Various
natural gas producers challenged the FERC's orders on two grounds: (1) that the
Kansas ad valorem tax, properly understood, does qualify for reimbursement under
the NGPA; and (2) the FERC's ruling should, in any event, have been applied
prospectively. Other parties challenged the FERC's orders on the grounds that
the FERC's ruling should have been applied retroactively to December 1, 1978,
the date of the enactment of the NGPA and producers should have been required to
pay refunds accordingly.
The D.C. Circuit issued its decision on August 2, 1996, which holds that
producers must make refunds of all Kansas ad valorem tax collected with respect
to production since October 4, 1983 as opposed to June 28, 1988. Petitions for
rehearing were denied on November 6, 1996. Various natural gas producers
subsequently filed a petition for writ of certiori with the United States
Supreme Court seeking to limit the scope of the potential refunds to tax bills
rendered on or after June 28, 1988 (the effective date originally selected by
the FERC). Williams Natural Gas Company filed a cross-petition for certiori
seeking to impose refund liability back to December 1, 1978. Both petitions were
denied on May 12, 1997.
The Company and other producers filed petitions for adjustment with the
FERC on June 24, 1997. The Company is seeking waiver or set-off from FERC with
respect to that portion of the refund associated with (i) non-recoupable
royalties, (ii) non-recoupable Kansas property taxes based, in part, upon the
higher prices collected, and (iii) interest for all periods. On September 10,
1997, FERC denied this request, and on October 10, 1997, the Company and other
producers filed a request for rehearing. Pipelines were given until November 10,
1997 to file claims on refunds sought from producers and refunds totaling
approximately $30 million were made against the Company. The Company is unable
at this time to predict the final outcome of this matter or the amount, if any,
that will ultimately be refunded. As of December 31, 1998, the Company has set
aside $29.7 million, including accrued interest, in an escrow account and has a
corresponding obligation for this litigation recorded in other current
liabilities in the accompanying Consolidated Balance Sheet. In addition, during
1998, the Company paid $1.4 million to a pipeline in settlement of the
pipeline's share of the total initial obligation.
LEASE AGREEMENTS. The Company leases equipment and office facilities under
noncancellable operating leases on which rental expense for the years ended
December 31, 1998, 1997 and 1996 was approximately $8.9 million, $3.7 million
and $2.9 million, respectively. Future minimum lease commitments under
noncancellable operating leases at December 31, 1998 are as follows (in
thousands):
1999........................................................ $7,846
2000........................................................ $5,933
2001........................................................ $2,029
2002........................................................ $1,685
2003........................................................ $1,234
Thereafter.................................................. $4,206
NOTE I. PREFERRED STOCK OF SUBSIDIARY
On July 28, 1997, the Company issued 6.7 million shares of common stock in
exchange for the 3,776,400 Preferred Shares outstanding. These Preferred Shares
were originally issued by Parker & Parsley Capital LLC, a wholly-owned finance
subsidiary of the Company, in 1994. During 1997 and 1996, the Company recorded
$6 million and $12 million, respectively, of interest expense associated with
the Preferred Shares.
70
71
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
NOTE J. DERIVATIVE FINANCIAL INSTRUMENTS
The Company has only limited involvement with derivative financial
instruments and generally 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.
As part of the acquisitions of Mesa and Chauvco, the Company became the
successor to certain derivative financial instruments entered into by Mesa or
Chauvco that do not qualify for hedge accounting treatment. Such instruments
will be marked-to-market at the end of each reporting period during their
respective lives and the effects on the Company's results of operations in
future periods could be significant. Those instruments not qualifying for hedge
accounting are designated under the heading "Mark-to-Market Derivatives" below.
HEDGE DERIVATIVES
INTEREST RATE SWAP AGREEMENTS. During the second quarter of 1996, the
Company entered into 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 percent while
the weighted average variable rate paid by the Company for the years ended
December 31, 1998, 1997 and 1996 was 5.75 percent, 5.78 percent and 5.56
percent, respectively. The variable rate will be redetermined approximately
every six months based upon the London interbank offered rate at that point in
time. The Company was also party to an interest rate swap agreement for an
aggregate amount of $250 million with one counterparty. This agreement, which
expired in August 1998, effectively converted a portion of the Company's
floating-rate borrowings into fixed-rate obligations. The effect of this
agreement was to provide the Company with an interest rate of 6.23 percent on
$250 million in nominal principal amount for the term of the agreement. The
accompanying Consolidated Statements of Operations and Comprehensive Income
(Loss) for the years ended December 31, 1998, 1997 and 1996 include a reduction
in interest expense of $356 thousand, $847 thousand and $787 thousand,
respectively, to account for the settlement of these rate swap agreements.
During 1997, the Company entered into two agreements with a counterparty
that obligated the Company to sell United States Treasury securities at a
designated point in the future. The face amount of the United States Treasury
securities was $300 million at interest rates ranging from 6.05 percent to 6.33
percent. These agreements effectively converted a portion of the Company's
floating-rate borrowings into fixed-rate obligations. In January 1998, the
Company terminated these agreements at a cost of $16.8 million. This amount is
being amortized over the life of the Company's Primary Facility.
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.
Crude oil. All material purchase contracts governing the Company's oil
production have been tied directly or indirectly to NYMEX prices. During the
fourth quarter of 1998, the Company terminated its 1999 crude oil hedge
contracts. As a result, the Company has deferred in other current liabilities in
the accompanying Consolidated Balance Sheet $14.0 million of hedge gains that
will be recognized in 1999 as
71
72
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
additions to crude oil revenue. The recognition of these hedge gains will
increase 1999 crude oil revenue by $3.5 million per calendar quarter.
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 following table sets forth the Company's oil prices, both realized
(excluding hedge results) and reported, and the net effects of settlements of
oil price hedges to revenue:
YEAR ENDED DECEMBER 31,
------------------------
1998 1997 1996
------ ------ ------
Average price reported per Bbl............................. $13.08 $18.51 $19.96
Average price realized per Bbl............................. $11.93 $19.09 $21.33
Addition (reduction) to revenue (in millions).............. $ 24.8 $ (7.9) $(15.4)
Natural Gas Liquids. The Company, from time to time, hedges natural gas
liquids based on actual product prices in order to mitigate some of the
volatility associated with NYMEX pricing. At December 31, 1998, the Company had
no outstanding NGL hedge contracts.
During the year ended December 31, 1998, the Company did not enter into any
natural gas liquids hedge contracts. The Company reported and realized an
average natural gas liquids price of $8.90 per Bbl during the year ended
December 31, 1998. During the year ended December 31, 1997, the Company reported
average natural gas liquids prices of $12.59 per Bbl while realizing an average
price for physical sales (excluding hedging results) of $12.61 per Bbl and
recorded a net decrease to natural gas liquids revenue of $77,600.
Natural Gas. The Company employs a policy of hedging a portion of its 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.
72
73
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
The Company was a party to contracts that hedged a portion of its January
1999 gas production. The January hedge contracts expired in December 1998.
Related thereto, the Company has deferred $2.5 million of hedge gains that will
be recognized in January 1999. The following table sets forth the Company's
outstanding gas hedge contracts as of December 31, 1998. 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 YEARLY
QUARTER QUARTER QUARTER QUARTER AVERAGE
----------- ----------- ----------- ----------- -----------
Daily gas production:
1999-Swap Contracts*
Volume (Mcf)............ 93,417 163,445 156,800 133,851 137,044
Index price per MMBtu... $2.17 $2.20 $2.21 $2.24 $2.21
NYMEX price per MMBtu... $2.39 $2.39 $2.39 $2.39 $2.39
1999-Collar Options**
Volume (Mcf)............ 107,398 163,827 163,827 154,991 147,686
Index price per MMBtu... $2.06-$2.61 $2.06-$2.61 $2.06-$2.61 $2.09-$2.65 $2.07-$2.62
2000-Swap Contracts*
Volume (Mcf)............ 35,000 35,000 35,000 35,000 35,000
Index price per MMBtu... $2.35 $2.35 $2.35 $2.35 $2.35
2000-Collar Options***
Volume (Mcf)............ 93,741 93,741 93,741 91,089 93,074
Index price per MMBtu... $2.14-$2.75 $2.14-$2.75 $2.14-$2.75 $2.15-$2.77 $2.14-$2.75
- ---------------
* Certain counterparties to the 1999 and 2000 Swap Contracts have the
contractual right to extend 35,000 Mcf per day for one additional year at
prices of $2.40 and $2.41 per MMBtu, respectively.
** Concurrent with the Company's purchase of certain of the 1999 Collar
Options, the Company sold 1999 put options to the counterparties for an
average volume of 114,286 Mcf per day at an average index price of $1.82 per
MMBtu. Consequently, if the weighted average 1999 index price falls below
$1.82 per MMBtu, the Company will receive a price for the notional contract
volumes that exceeds the weighted average index price by approximately $.30
per MMBtu. 65,000 Mcf per day of the 1999 Collar Options and associated put
options sold are extendable at the option of the counterparties for a period
of one year at average per MMBtu prices of $2.18-$2.79 for the collar
options and $1.88 for the put options.
*** Concurrent with the Company's purchase of the 2000 Collar Options, the
Company sold 2000 put options to the counterparties for an equal volume at
an average index price of $1.84 per MMBtu. Consequently, if the weighted
average 2000 index price falls below $1.84 per MMBtu, the Company will
receive a price for the notional contract volumes that exceeds the weighted
average index price by approximately $.30 per MMBtu. 75,000 Mcf per day of
the 2000 Collar Options and associated put options are extendable for one
year at the option of the counterparties at average per MMBtu prices of
$2.20-$2.90 for the collar options and $1.90 for the put options.
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 following table sets
73
74
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
forth the Company's gas prices, both realized (excluding hedge results) and
reported, and the net effects of settlements of gas price hedges to revenue:
YEAR ENDED DECEMBER 31,
-------------------------
1998 1997 1996
------ ------- ------
Average price reported per Mcf.............................. $1.82 $ 2.20 $2.27
Average price realized per Mcf.............................. $1.80 $ 2.41 $2.39
Addition (reduction) to revenue (in millions)............... $ 3.6 $(21.9) $(9.0)
MARK-TO-MARKET DERIVATIVES
INTEREST RATE SWAP/CURRENCY SWAP. At December 31, 1997, the Company was
party to a swap agreement with a counterparty in which the Company paid a
fixed-rate of interest in Canadian dollars and received a fixed-rate of interest
in United States dollars. In July 1998, the Company terminated this agreement
and recognized a $3.5 million pre-tax gain associated therewith.
INTEREST RATE CAP. At December 31, 1998 and 1997, the Company was party to
an interest rate cap agreement with a counterparty which caps the Canadian
dollar banker's acceptance rate at 8.00 percent on a notional amount of $80
million Canadian dollars. The agreement was entered into in 1997 and expires in
September 1999. Under the agreement, the Company pays the counterparty a fixed
amount in Canadian dollars on a quarterly basis. The counterparty has no payment
obligation to the Company until such time as the Canadian banker's acceptance
reference rate exceeds 8.00 percent. The effect of this agreement, in periods in
which the reference rate is below 8.00 percent, is to increase the interest rate
on $80 million Canadian dollars of floating-rate debt by 28 basis points.
FOREIGN CURRENCY AGREEMENTS. The Company has a series of forward foreign
exchange swap agreements to exchange Canadian dollars for United States dollars
at future dates for a fixed amount of the first currency. As of December 31,
1998 and 1997, the United States dollar equivalent of foreign currency exchange
swap agreements approximated $144 million and $216 million, respectively. These
contracts originated with the Company's acquisition of Chauvco in December 1997.
As these contracts do not qualify as hedges, the Company recorded a $14.7
million non-cash pre-tax mark-to-market increase to the recognized liabilities
associated with these agreements in 1998. These contracts will continue to be
marked-to-market until they mature at various dates in the fourth quarter of
2000 and the effects on the Company's results of operations in future periods
could be significant.
BTU SWAP AGREEMENTS. During 1996, Mesa entered into BTU swap agreements
covering 13,036 MMBtu per day from January 1, 1997 through December 31, 2004.
Under the terms of these agreements, the Company received a premium of $.52 per
MMBtu over market natural gas prices from January 1, 1997 through December 31,
1998. Additionally, the Company will receive 10 percent of the NYMEX oil price
for the volumes covered for a six-year period beginning January 1, 1999 and
ending December 31, 2004. As these derivative contracts do not qualify as
hedges, the Company recorded non-cash pre-tax mark-to-market increases to the
liabilities recognized for the BTU swap agreements of $5.8 million and $5.2
million in 1998 and 1997, respectively. These contracts will continue to be
marked-to-market at the end of each reporting period during their respective
lives and the effects on the Company's results of operations in future periods
could be significant.
NOTE K. 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.
74
75
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
The following domestic customers individually accounted for 10 percent or
more of the consolidated oil and gas revenues of the Company during the years
ended December 31, 1998, 1997 or 1996:
PERCENTAGE OF CONSOLIDATED
OIL AND GAS REVENUES
---------------------------
CUSTOMER 1998 1997 1996
-------- ----- ----- -----
Williams Energy Services.................................... 10 -- --
Genesis Crude Oil, L.P...................................... 10 23 28
Mobil Oil Corporation....................................... 7 16 22
Western Gas Resources....................................... 5 10 9
Producers Energy Marketing, L.L.C.(a)....................... 3 11 6
- ---------------
(a) Producers Energy Marketing, LLC ("ProEnergy") is a natural gas marketing
company in which the Company owned a noncontrolling member interest of
approximately 10 percent during 1997 and 1996. Effective January 1, 1998,
the Company withdrew as a member of ProEnergy.
At December 31, 1998, the amounts receivable from Williams Energy Services,
Genesis Crude Oil, L.P., Mobil Oil Corporation and Western Gas Resources were
$9.1 million, $3.8 million, $2.8 million and $1.5 million, respectively, which
are included in the caption "Accounts receivable -- oil and gas sales" in the
accompanying Consolidated Balance Sheet.
NOTE L. 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
accompanying Consolidated Statement of Operations and Comprehensive Income
(Loss) 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 for the year ended December 31, 1996, 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.
NOTE M. IMPAIRMENT OF LONG-LIVED ASSETS
In accordance with SFAS 121, the Company reviews its proved oil and gas
properties for impairment whenever events and circumstances indicate a decline
in the recoverability of the carrying value of the Company's oil and gas
properties. The Company estimates the expected future net cash flows of its oil
and gas properties and compares such estimated future net cash flows to the
respective carrying amounts of the oil and gas properties to determine if the
carrying amounts are likely to be recoverable. For those proved oil and gas
properties for which the carrying amount exceeds the estimated future net cash
flows, an impairment is determined to exist and the Company adjusts the carrying
amount of those proved oil and gas properties to their fair value as determined
by discounting their expected future net cash flows at a discount rate
commensurate with the risks involved in the industry.
Subsequent to the Mesa purchase in August 1997, crude oil prices began to
decline. Based on the decline in the fourth quarter of 1997, the Company
adjusted its outlook for future commodity prices downward and
75
76
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
recognized a $1.4 billion impairment provision in 1997, primarily related to
Mesa properties which were acquired in August 1997.
In 1998 crude oil prices continued to decline. The Company believed the
continued decline would be short-lived, however, after stabilizing somewhat in
the second and third quarters of 1998, crude oil prices fell sharply again in
the fourth quarter of 1998. As a result, the Company now believes it may take
several years for crude oil prices to recover and, accordingly, it again
adjusted its outlook for future commodity prices downward in the fourth quarter
of 1998. This coupled with the Company's assessment of performance issues
related to certain oil and gas properties resulted in an impairment provision of
$312.2 million in 1998.
As discussed above, using the Company's revised outlook for commodity
prices, the Company reassessed its unproved properties on a project-by-project
basis in 1998, and the Company recognized non-cash, pre-tax unproved property
impairment provisions of $147.3 million.
See Note P for disclosure of these impairment charges by geographic
operating segment.
NOTE N. REORGANIZATION
During 1998, the Company announced its plans to sell certain non-strategic
oil and gas fields, its intentions to reorganize its operations by combining its
six domestic operating regions, and other cost reduction initiatives intended to
allow Pioneer to better adapt to declining oil and gas commodity price trends.
Specific cost reduction initiatives included the relocation of most of the
Company's administrative services from Midland, Texas to Irving, Texas; the
closings of the Company's regional offices in Oklahoma City, Oklahoma, Corpus
Christi, Texas and Houston, Texas; the termination of 350 employees, including
several officer positions; and, further centralization of the Company's
organization structure. The consolidation of administrative services to Irving
is complete and the Corpus Christi, Texas office is closed. The Company
anticipates the Houston, Texas and Oklahoma City, Oklahoma offices to be closed
in February 1999. The unpaid employee termination costs as of December 31, 1998
relates to employees who were notified of their pending termination prior to
December 31, 1998, but were still employed with the Company as of December 31,
1998. The unpaid office closing amounts primarily relate to remaining lease
commitments on the office buildings in Oklahoma City, Oklahoma, Corpus Christi,
Texas, and Houston, Texas. As a result of the 1998 reorganization initiatives,
the Company has recognized pre-tax reorganization charges of $33.2 million
during 1998.
The following table provides a description of the components of the 1998
reorganization charges and the remaining unpaid portions of the charges as of
December 31, 1998:
TOTAL
CHARGES PAYMENTS UNPAID PORTION
------- -------- --------------
(IN THOUSANDS)
Employee terminations............................... $22,525 $17,845 $4,680
Relocation.......................................... 6,677 6,677 --
Office closings..................................... 3,873 343 3,530
Other............................................... 124 124 --
------- ------- ------
$33,199 $24,989 $8,210
======= ======= ======
76
77
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
NOTE O. INCOME TAXES
Income tax provision (benefit) and amounts separately allocated were as
follows:
YEAR ENDED DECEMBER 31,
-----------------------------
1998 1997 1996
------- --------- -------
(IN THOUSANDS)
Income (loss) before extraordinary item............... $15,600 $(500,300) $60,100
Extraordinary gain (loss)............................. -- > (7,200) --
Stockholders' equity provision (benefit).............. 4,300 (2,900) (2,200)
Change in cumulative translation adjustment........... (6,000) -- --
------- --------- -------
$13,900 $(510,400) $57,900
======= ========= =======
Income tax provision (benefit) attributable to income (loss) before
extraordinary item consists of the following:
YEAR ENDED DECEMBER 31,
-------------------------------
1998 1997 1996
--------- --------- -------
(IN THOUSANDS)
Current:
U.S. federal...................................... $ (3,300) $ 900 $ 300
State and local................................... 300 100 --
--------- --------- -------
(3,000) 1,000 300
--------- --------- -------
Deferred:
U.S. Federal...................................... $ 123,500 (470,000) 51,700
State and local................................... (300) (28,500) --
Foreign........................................... (104,600) (2,800) 8,100
--------- --------- -------
18,600 (501,300) 59,800
--------- --------- -------
Total............................................... $ 15,600 $(500,300) $60,100
========= ========= =======
Income (loss) before income taxes and extraordinary item consists of the
following:
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
--------- ----------- --------
(IN THOUSANDS)
Income (loss) before income taxes and
extraordinary item:
U.S. federal.................................... $(393,602) $(1,369,582) $121,680
Foreign......................................... (337,224) (7,981) 78,668
--------- ----------- --------
$(730,826) $(1,377,563) $200,348
========= =========== ========
77
78
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
Reconciliations of the U.S. federal statutory tax rate to the Company's
effective tax rate for income (loss) before extraordinary items are as follows:
1998 1997 1996
----- ----- ----
(IN PERCENTAGES)
U.S. federal statutory tax rate............................. (35.0) (35.0) 35.0
Disposition of foreign subsidiaries......................... -- -- (6.9)
Valuation allowance......................................... 37.1 -- --
Other....................................................... -- (1.3) 1.9
----- ----- ----
Consolidated effective tax rate............................. 2.1 (36.3) 30.0
===== ===== ====
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,
--------------------
1998 1997
--------- --------
(IN THOUSANDS)
Deferred tax assets:
Net operating loss carryforwards.......................... $ 291,678 $184,438
Alternative minimum tax credit carryforwards.............. 1,565 4,903
Other..................................................... 73,260 57,248
--------- --------
Total deferred tax assets......................... 366,503 246,589
Valuation allowance....................................... (271,100) --
--------- --------
Net deferred tax assets........................... 95,403 246,589
--------- --------
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........................ 44,058 206,721
Other..................................................... 11,645 35,168
--------- --------
Total deferred tax liabilities.................... 55,703 241,889
--------- --------
Net deferred tax asset............................ $ 39,700 $ 4,700
========= ========
Realization of deferred tax assets associated with net operating loss
carryforwards ("NOLs") and other credit carryforwards is dependent upon
generating sufficient taxable income prior to their expiration. The Company
believes that there is a risk, in light of the Company's revised outlook for
future commodity prices as discussed in Note M, that certain of these NOLs and
other credit carryforwards may expire unused and, accordingly, has established a
valuation allowance of $271.1 million in 1998 against them. Although realization
is not assured for the remaining deferred tax asset, the Company believes it is
more likely than not that they will be realized through future taxable earnings
or alternative tax planning strategies. However, the net deferred tax assets
could be reduced further if the Company's estimate of taxable income in future
periods is significantly reduced or alternative tax planning strategies are no
longer viable.
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. At December
31, 1998, the Company had NOLs for U.S. federal, Argentine, Canadian, and South
African income tax purposes of $712.6 million, $47.3 million, $52.8 million and
$7.7 million, respectively, which are available to offset future regular taxable
income in each respective tax jurisdiction, if any. Additionally, at December
31, 1998, the
78
79
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
Company has alternative minimum tax net operating loss carryforwards ("AMT
NOLs") in the U.S. of $617.7 million, which are available to reduce future
alternative minimum taxable income, if any. These carryforwards expire as
follows:
U.S.
------------------- ARGENTINA CANADA SOUTH AFRICA
EXPIRATION DATE NOL AMT NOL NOL NOL NOL
--------------- -------- -------- --------- ------- ------------
(IN THOUSANDS)
December 31, 1999....................... $ -- $ -- $ 2,161 $ -- $ --
December 31, 2000....................... -- -- 8,788 -- --
December 31, 2001....................... 689 593 10,385 -- --
December 31, 2002....................... 6,066 6,034 6,216 -- --
December 31, 2003....................... 838 -- 19,703 -- --
December 31, 2005....................... 11,049 10,762 -- 52,767 --
December 31, 2006....................... 30,834 12,254 -- -- --
December 31, 2007....................... 104,107 101,151 -- -- --
December 31, 2008....................... 112,508 106,558 -- -- --
December 31, 2009....................... 129,484 102,727 -- -- --
December 31, 2010....................... 125,111 110,961 -- -- --
December 31, 2011....................... 6,521 4,045 -- -- --
December 31, 2012....................... 68,609 58,890 -- -- --
December 31, 2018....................... 116,823 103,755 -- -- --
Indefinite.............................. -- -- -- -- 7,706
-------- -------- ------- ------- ------
Total.............................. $712,639 $617,730 $47,253 $52,767 $7,706
======== ======== ======= ======= ======
The NOLs and AMT NOLs from certain of the U.S. subsidiaries are subject to
various utilization limitations. In total, approximately $36.7 million of the
NOLs and $16.3 million of the AMT NOLs are limited in use to specific U.S.
subsidiaries. Section 382 of the Internal Revenue Code provides another
limitation to $592.1 million of the Company's U.S. NOLs and $503.8 million of
its AMT NOLS. The Company believes the utilization of $352.1 million of the NOLs
and $263.8 million of the AMT NOLs subject to the Section 382 limitation are
limited in each taxable year to approximately $104.2 million and the remaining
$240.0 million of the NOLs and AMT NOLs subject to the Section 382 limitation
are limited in each taxable year to approximately $20.0 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 $300,000, $2.7 million and $970,000 were made in 1998,
1997 and 1996, respectively. In addition, the Company received a refund of $3.3
million in 1998.
NOTE P. GEOGRAPHIC OPERATING SEGMENT INFORMATION
In June 1997, the FASB issued Statement of Financial Accounting Standards
No. 131, "Disclosure about Segments of an Enterprise and Related Information"
("SFAS 131"). SFAS 131 establishes guidelines for reporting selected information
about operating segments. The Company has operations in only one industry
segment, that being the oil and gas exploration and production industry;
however, the Company is organizationally structured along geographic operating
segments, or regions. Since the merger with Mesa and the acquisition of Chauvco,
the Company has had reportable operations in the U.S., Argentina and Canada.
During 1997 and 1996, the Company had only minor operations outside the U.S.
79
80
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
The following table provides the geographic operating segment data required
by SFAS 131, as well as results of operations of oil and gas producing
activities required by Statement of Financial Accounting Standards No. 69,
"Disclosures about Oil and Gas Producing Activities" ("SFAS 69"). Geographic
operating segment income tax benefits (provisions) have been determined based on
statutory rates existing in the various tax jurisdictions where the Company has
oil and gas producing activities. The "Headquarters and other" table column
includes revenues, expenses, additions to properties, plants and equipment, and
assets that are not related to oil and gas producing activities, and that are
not routinely included in the earnings measures or attributes internally
reported to management on a geographic operating segment basis.
OTHER HEADQUARTERS CONSOLIDATED
U.S. ARGENTINA CANADA FOREIGN AND OTHER TOTAL
----------- --------- --------- -------- ------------ ------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1998:
Oil and gas revenue..................... $ 579,156 $ 65,256 $ 67,080 $ -- $ -- $ 711,492
Interest and other...................... -- -- -- -- 10,452 10,452
Loss on disposition of assets........... (52) -- -- -- (393) (445)
----------- --------- --------- -------- --------- -----------
579,104 65,256 67,080 -- 10,059 721,499
----------- --------- --------- -------- --------- -----------
Production costs........................ 177,371 21,158 25,022 -- -- 223,551
Depletion, depreciation and
amortization.......................... 239,561 42,115 40,617 -- 15,015 337,308
Impairment of oil and gas properties.... 237,528 136,751 85,240 -- -- 459,519
Exploration and abandonments............ 69,263 18,245 20,613 13,737 -- 121,858
General and administrative.............. -- -- -- -- 73,000 73,000
Reorganization.......................... -- -- -- -- 33,199 33,199
Interest................................ -- -- -- -- 164,285 164,285
Other................................... -- -- -- -- 39,605 39,605
----------- --------- --------- -------- --------- -----------
723,723 218,269 171,492 13,737 325,104 1,452,325
----------- --------- --------- -------- --------- -----------
Loss before income taxes................ (144,619) (153,013) (104,412) (13,737) (315,045) (730,826)
Income tax benefit (provision).......... 53,075 50,494 45,628 4,808 (169,605) (15,600)
----------- --------- --------- -------- --------- -----------
Net loss................................ $ (91,544) $(102,519) $ (58,784) $ (8,929) $(484,650) $ (746,426)
=========== ========= ========= ======== ========= ===========
Additions to properties, plant and
equipment............................. $ 346,368 $ 69,082 $ 73,096 $ 18,791 $ 31,546 $ 538,883
=========== ========= ========= ======== ========= ===========
Segment assets.......................... $ 2,259,746 $ 692,271 $ 308,025 $103,702 $ 117,570 $ 3,481,314
=========== ========= ========= ======== ========= ===========
YEAR ENDED DECEMBER 31, 1997:
Oil and gas revenue..................... $ 533,865 $ 2,917 $ -- $ -- $ -- $ 536,782
Interest and other...................... -- -- -- -- 4,278 4,278
Gain on disposition of assets........... 3,305 -- -- -- 1,664 4,969
----------- --------- --------- -------- --------- -----------
537,170 2,917 -- -- 5,942 546,029
----------- --------- --------- -------- --------- -----------
Production costs........................ 143,332 838 -- -- -- 144,170
Depletion, depreciation and
amortization.......................... 203,160 1,290 -- -- 7,985 212,435
Impairment of oil and gas properties.... 1,356,390 -- -- -- -- 1,356,390
Exploration and abandonments............ 69,896 1,822 -- 5,442 -- 77,160
General and administrative.............. -- -- -- -- 48,763 48,763
Interest................................ -- -- -- -- 77,550 77,550
Other................................... -- -- -- -- 7,124 7,124
----------- --------- --------- -------- --------- -----------
1,772,778 3,950 -- 5,442 141,422 1,923,592
----------- --------- --------- -------- --------- -----------
Loss before income taxes and
extraordinary item.................... (1,235,608) (1,033) -- (5,442) (135,480) (1,377,563)
Income tax benefit...................... 453,468 341 -- 1,905 44,586 500,300
----------- --------- --------- -------- --------- -----------
Loss before extraordinary items......... $ (782,140) $ (692) $ -- $ (3,537) $ (90,894) $ (877,263)
=========== ========= ========= ======== ========= ===========
Additions to properties, plant and
equipment............................. $ 417,269 $ 4,446 $ -- $ 6,925 $ 12,783 $ 441,423
=========== ========= ========= ======== ========= ===========
Segment assets.......................... $ 2,684,091 $ 734,569 $ 505,483 $ 1,085 $ 227,762 $ 4,152,990
=========== ========= ========= ======== ========= ===========
80
81
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
OTHER HEADQUARTERS CONSOLIDATED
U.S. ARGENTINA CANADA FOREIGN AND OTHER TOTAL
----------- --------- --------- -------- ------------ ------------
(IN THOUSANDS)
YEAR ENDED DECEMBER 31, 1996:
Oil and gas revenue..................... $ 385,198 $ 1,142 $ -- $ 10,591 $ -- $ 396,931
Natural gas processing.................. -- -- -- -- 23,814 23,814
Interest and other...................... -- -- -- -- 17,458 17,458
Gain on disposition of assets........... 7,784 -- -- 83,262 6,094 97,140
----------- --------- --------- -------- --------- -----------
392,982 1,142 -- 93,853 47,366 535,343
----------- --------- --------- -------- --------- -----------
Production costs........................ 106,898 136 -- 3,300 -- 110,334
Natural gas processing.................. -- -- -- -- 12,528 12,528
Depletion, depreciation and
amortization.......................... 98,655 231 -- 3,917 9,331 112,134
Exploration and abandonments............ 16,264 4,008 -- 1,435 1,323 23,030
General and administrative.............. -- -- -- -- 28,363 28,363
Interest................................ -- -- -- -- 46,155 46,155
Other................................... -- -- -- -- 2,451 2,451
----------- --------- --------- -------- --------- -----------
221,817 4,375 -- 8,652 100,151 334,995
----------- --------- --------- -------- --------- -----------
Income (loss) before income taxes....... 171,165 (3,233) -- 85,201 (52,785) 200,348
Income tax benefit (provision).......... (62,818) 1,067 -- (29,820) 31,471 (60,100)
----------- --------- --------- -------- --------- -----------
Net income (loss)....................... $ 108,347 $ (2,166) $ -- $ 55,381 $ (21,314) $ 140,248
=========== ========= ========= ======== ========= ===========
Additions to properties, plant and
equipment............................. $ 207,495 $ 4,541 $ -- $ 7,358 $ 8,428 $ 227,822
=========== ========= ========= ======== ========= ===========
Segment assets.......................... $ 1,143,282 $ 3,543 $ 2 $ 2,321 $ 50,717 $ 1,199,865
=========== ========= ========= ======== ========= ===========
NOTE Q. EARNINGS PER SHARE
In accordance with the requirements of SFAS 128, the following table
provides a reconciliation between basic and diluted earnings per share for the
year ended December 31, 1996. For 1998 and 1997, the computation of diluted net
loss per share was antidilutive; therefore, the amounts reported for basic and
diluted net loss per share were the same.
PER SHARE
INCOME SHARES AMOUNT
-------- ------ ---------
(IN THOUSANDS)
Basic EPS
Income available to common stockholders............. $140,248 35,475 $3.95
=====
Effect of Dilutive Securities
Options/restricted stock............................ -- 394
Preferred shares.................................... 7,683 6,714
-------- ------
Diluted EPS:
Income available to common stockholders plus assumed
conversions...................................... $147,931 42,583 $3.47
======== ====== =====
NOTE R. PIONEER USA
Pioneer USA is a wholly-owned subsidiary of the Company that has fully and
unconditionally guaranteed certain debt securities of the Company (see Note E
above). The Company has not prepared financial statements and related
disclosures for Pioneer USA under separate cover because management of the
Company has determined that such information is not material to investors. In
accordance with practices accepted by the U.S. Securities and Exchange
Commission ("SEC"), the Company has prepared Consolidating Financial Statements
in order to quantify the assets of Pioneer USA as a subsidiary guarantor. The
81
82
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
following Consolidating Balance Sheets as of December 31, 1998 and 1997 and
Consolidating Statements of Operations for the Years Ended December 31, 1998 and
1997 present financial information for Pioneer Natural Resources Company as the
Parent on a stand-alone basis (carrying any investments in subsidiaries under
the equity method), financial information for Pioneer USA on a stand-alone basis
(carrying any investment in non-guarantor subsidiaries under the equity method),
financial information for the non-guarantor subsidiaries of the Company on a
consolidated basis, the consolidation and elimination entries necessary to
arrive at the information for the Company on a consolidated basis, and the
financial information for the Company on a consolidated basis. Pioneer USA is
not restricted from making distributions to the Company.
Pioneer USA's guarantees of the Company's debt securities were executed as
a result of the merger with Mesa in August 1997. Consequently, a Consolidating
Statement of Operations for the year ended December 31, 1996 has not been
presented.
82
83
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1998
(IN THOUSANDS)
ASSETS
PIONEER
NATURAL
RESOURCES NON-
COMPANY PIONEER GUARANTOR THE
(PARENT) USA SUBSIDIARIES ELIMINATIONS COMPANY
----------- ----------- ------------ ------------ -----------
Current assets:
Cash and cash equivalents............ $ 3,161 $ 37,932 $ 18,128 $ $ 59,221
Accounts receivable, trade........... 636 75,236 30,991 106,863
Affiliate receivables................ 2,240,421 (1,828,672) (408,092) 3,657
Inventories.......................... -- 8,930 6,291 15,221
Deferred income taxes................ 7,100 -- -- 7,100
Other current assets................. 87 8,868 971 9,926
----------- ----------- ---------- -----------
Total current assets.......... 2,251,405 (1,697,706) (351,711) 201,988
----------- ----------- ---------- -----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of
accounting:
Proved properties.................. -- 2,678,637 942,993 3,621,630
Unproved properties................ -- 58,989 283,600 342,589
Accumulated depletion, depreciation
and amortization................... -- (753,570) (176,541) (930,111)
----------- ----------- ---------- -----------
-- 1,984,056 1,050,052 3,034,108
----------- ----------- ---------- -----------
Deferred income taxes.................. 96,800 -- -- 96,800
Other property and equipment, net...... -- 38,229 16,781 55,010
Other assets, net...................... 9,787 43,557 40,064 93,408
Investment in subsidiaries............. 135,204 148,257 -- (283,461) --
----------- ----------- ---------- -----------
$ 2,493,196 $ 516,393 $ 755,186 $ 3,481,314
=========== =========== ========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term
debt............................... $ 212,302 $ 1,189 $ 93,030 $ $ 306,521
Accounts payable:
Trade.............................. 697 56,723 37,517 94,937
Affiliates......................... 29 4,463 -- 4,492
Other current liabilities............ 21,001 84,759 15,122 120,882
----------- ----------- ---------- -----------
Total current liabilities..... 234,029 147,134 145,669 526,832
----------- ----------- ---------- -----------
Long-term debt, less current
maturities........................... 1,676,933 830 190,981 1,868,744
Other noncurrent liabilities........... -- 189,325 43,136 232,461
Deferred income taxes.................. -- -- 64,200 64,200
Stockholders' equity:
Partners' capital.................... -- -- 22 (22) --
Common stock......................... 934 1 76 (3) 1,008
Additional paid-in capital........... 2,143,214 2,022,076 589,511 (2,406,805) 2,347,996
Treasury stock, at cost.............. (10,388) -- -- (10,388)
Retained deficit..................... (1,551,526) (1,842,973) (281,312) 2,123,369 (1,552,442)
Cumulative translation adjustment.... -- -- 2,903 2,903
----------- ----------- ---------- -----------
Total stockholders' equity.... 582,234 179,104 311,200 789,077
----------- ----------- ---------- -----------
Commitments and contingencies.......... $ 2,493,196 $ 516,393 $ 755,186 $ 3,481,314
=========== =========== ========== ===========
83
84
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 1997
(IN THOUSANDS)
ASSETS
PIONEER
NATURAL
RESOURCES NON-
COMPANY PIONEER GUARANTOR THE
(PARENT) USA SUBSIDIARIES ELIMINATIONS COMPANY
---------- ----------- ------------ ------------ ----------
Current assets:
Cash and cash equivalents.............. $ 41 $ 49,033 $ 22,639 $ $ 71,713
Accounts receivable, trade............. 5 138,569 53,358 191,932
Affiliate receivables.................. 2,088,082 (1,673,443) (414,639) --
Inventories............................ -- 11,677 1,899 13,576
Deferred income taxes.................. 16,700 -- 200 16,900
Other current assets................... -- 10,988 3,079 14,067
---------- ----------- ---------- ----------
Total current assets............ 2,104,828 (1,463,176) (333,464) 308,188
---------- ----------- ---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of
accounting:
Proved properties.................... -- 2,453,750 1,122,221 3,575,971
Unproved properties.................. -- 98,664 446,410 545,074
Accumulated depletion, depreciation and
amortization......................... -- (504,628) (100,575) (605,203)
---------- ----------- ---------- ----------
-- 2,047,786 1,468,056 3,515,842
---------- ----------- ---------- ----------
Deferred income taxes.................... 206,400 -- -- 206,400
Other property and equipment, net........ -- 26,096 17,921 44,017
Other assets, net........................ 4,705 68,715 28,098 (22,975) 78,543
Investment in subsidiaries............... 645,113 284,046 -- (929,159) --
---------- ----------- ---------- ----------
$2,961,046 $ 963,467 $1,180,611 $4,152,990
========== =========== ========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt... $ -- $ 538 $ 28,228 $ (22,975) $ 5,791
Accounts payable:
Trade................................ 663 113,432 62,602 176,697
Affiliates........................... 90 9,904 -- 9,994
Other current liabilities.............. 5,771 61,648 1,651 69,070
---------- ----------- ---------- ----------
Total current liabilities....... 6,524 185,522 92,481 261,552
---------- ----------- ---------- ----------
Long-term debt, less current
maturities............................. 1,700,500 565 242,653 1,943,718
Other noncurrent liabilities............. -- 140,668 39,607 180,275
Deferred income taxes.................... (9,853) -- 228,453 218,600
Stockholders' equity:
Partners' capital...................... -- -- 401 (401) --
Common stock........................... 901 1 110 (2) 1,010
Additional paid-in capital............. 2,058,935 2,049,072 739,518 (2,487,533) 2,359,992
Treasury stock, at cost................ (21) -- -- (21)
Unearned compensation.................. -- (16,196) -- (16,196)
Retained deficit....................... (795,940) (1,396,165) (162,612) 1,558,777 (795,940)
---------- ----------- ---------- ----------
Total stockholders' equity...... 1,263,875 636,712 577,417 1,548,845
---------- ----------- ---------- ----------
Commitments and contingencies............ $2,961,046 $ 963,467 $1,180,611 $4,152,990
========== =========== ========== ==========
84
85
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1998
(IN THOUSANDS)
PIONEER
NATURAL
RESOURCES NON- CONSOLIDATED
COMPANY PIONEER GUARANTOR INCOME THE
(PARENT) USA SUBSIDIARIES TAX BENEFIT ELIMINATIONS COMPANY
--------- --------- ------------ ------------ ------------ ----------
Revenue
Oil and gas.......................... $ -- $ 523,736 $ 187,756 $ $ $ 711,492
Interest and other................... 38 7,937 2,477 10,452
Loss on disposition of assets, net... -- (477) 32 (445)
--------- --------- --------- ----------
38 531,196 190,265 721,499
--------- --------- --------- ----------
Costs and expenses:
Oil and gas production............... -- 164,964 58,587 223,551
Depletion, depreciation and
amortization....................... -- 225,127 112,181 337,308
Impairment of oil and gas
properties......................... -- 237,529 221,990 459,519
Exploration and abandonments......... -- 71,851 50,007 121,858
General and administrative........... 2,042 57,158 13,800 73,000
Reorganization....................... -- 31,756 1,443 33,199
Interest............................. (54,237) 159,863 58,659 164,285
Equity loss from subsidiary.......... 675,142 4,358 -- (679,500) --
Other................................ 722 22,732 16,151 39,605
--------- --------- --------- ----------
623,669 975,338 532,818 1,452,325
--------- --------- --------- ----------
Loss before income taxes............... (623,631) (444,142) (342,553) (730,826)
Income tax provision................... -- (174) 107,369 (122,795) (15,600)
--------- --------- --------- ----------
Net loss........................... $(623,631) $(444,316) $(235,184) $ (746,426)
========= ========= ========= ==========
85
86
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
CONSOLIDATING STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 1997
(IN THOUSANDS)
PIONEER
NATURAL
RESOURCES NON- CONSOLIDATED
COMPANY PIONEER GUARANTOR INCOME THE
(PARENT) USA SUBSIDIARIES TAX BENEFIT ELIMINATIONS COMPANY
----------- ----------- ------------ ------------ ------------ -----------
Revenue
Oil and gas...................... $ -- $ 453,771 $ 83,011 $ $ $ 536,782
Interest and other............... -- 5,357 873 (1,952) 4,278
Gain on disposition of assets,
net............................ -- 6,062 (402) (691) 4,969
----------- ----------- --------- -----------
-- 465,190 83,482 546,029
----------- ----------- --------- -----------
Costs and expenses:
Oil and gas production........... -- 128,644 15,526 144,170
Depletion, depreciation and
amortization................... -- 166,495 45,940 212,435
Impairment of oil and gas
properties..................... -- 1,220,920 135,470 1,356,390
Exploration and abandonments..... -- 67,679 9,481 77,160
General and administrative....... 613 44,766 3,384 48,763
Interest......................... 5,910 67,969 5,623 (1,952) 77,550
Equity loss from subsidiary...... 1,407,844 124,874 -- (1,532,718) --
Other............................ -- 7,065 59 7,124
----------- ----------- --------- -----------
1,414,367 1,828,412 215,483 1,923,592
----------- ----------- --------- -----------
Loss before income taxes and
extraordinary item............... (1,414,367) (1,363,222) (132,001) (1,377,563)
Income tax benefit................. -- -- -- 500,300 500,300
----------- ----------- --------- -----------
Loss before extraordinary item..... (1,414,367) (1,363,222) (132,001) (877,263)
Extraordinary item -- loss on early
extinguishment of debt net of
tax.............................. -- (13,408) -- (13,408)
----------- ----------- --------- -----------
Net loss....................... $(1,414,367) $(1,376,630) $(132,001) $ (890,671)
=========== =========== ========= ===========
86
87
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
CONSOLIDATING STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 1998
(IN THOUSANDS)
PIONEER
NATURAL
RESOURCES NON- CONSOLIDATED
COMPANY PIONEER GUARANTOR INCOME TAX THE
(PARENT) USA SUBSIDIARIES PROVISION ELIMINATIONS COMPANY
--------- --------- ------------ ------------ ------------ ---------
Cash flows from operating activities:
Net loss............................... $(623,631) $(444,316) $(235,184) $(122,795) $ 679,500 $(746,426)
Adjustments to reconcile net loss to
net cash provided by operating
activities:
Depletion, depreciation and
amortization....................... -- 225,127 112,181 -- 337,308
Impairment of oil and gas
properties......................... -- 237,529 221,990 -- 459,519
Exploration expenses, including dry
holes.............................. -- 53,903 38,408 -- -- 92,311
Deferred income taxes................ -- 174 (107,369) 125,795 18,600
(Gain) loss on disposition of assets,
net................................ -- 477 (32) -- 445
Other noncash items.................. 685,032 44,181 16,587 -- (679,500) 66,300
Changes in working capital............... (212,716) 196,284 105,451 (3,000) 86,019
--------- --------- --------- --------- ---------
Net cash provided by (used in)
operating activities........... (151,315) 313,359 152,032 -- 314,076
--------- --------- --------- --------- ---------
Cash flows from investing activities:
Proceeds from disposition of assets.... -- 13,791 8,085 -- 21,876
Additions to oil and gas properties.... -- (309,639) (197,698) -- (507,337)
Other property additions, net.......... -- (15,862) (15,684) -- (31,546)
--------- --------- --------- --------- ---------
Net cash used in investing
activities..................... -- (311,710) (205,297) -- (517,007)
--------- --------- --------- --------- ---------
Cash flows from financing activities:
Borrowings under long-term debt........ 886,008 -- 61,172 -- 947,180
Principal payments on long-term debt... (704,857) (1,326) (5,341) -- (711,524)
Payment of noncurrent liabilities...... -- (11,424) (5,667) -- (17,091)
Dividends.............................. (9,160) -- (916) -- (10,076)
Purchase of treasury stock............. (10,367) -- -- -- (10,367)
Deferred loan fees/issuance costs...... (7,189) -- -- -- (7,189)
--------- --------- --------- --------- ---------
Net cash provided by (used in)
financing activities........... 154,435 (12,750) 49,248 -- 190,933
--------- --------- --------- --------- ---------
Net increase (decrease) in cash and cash
equivalents............................ 3,120 (11,101) (4,017) -- (11,998)
Effect of exchange rate changes on cash
and cash equivalents................... -- -- (494) -- (494)
Cash and cash equivalents, beginning of
period................................. 41 49,033 22,639 -- 71,713
--------- --------- --------- --------- ---------
Cash and cash equivalents, end of
period................................. $ 3,161 $ 37,932 $ 18,128 $ -- $ 59,221
========= ========= ========= ========= =========
87
88
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
CAPITALIZED COSTS
DECEMBER 31,
------------------------
1998 1997
---------- ----------
(IN THOUSANDS)
Oil and Gas Properties:
Proved.................................................... $3,621,630 $3,575,971
Unproved.................................................. 342,589 545,074
---------- ----------
3,964,219 4,121,045
Less accumulated depletion................................ (930,111) (605,203)
---------- ----------
Net capitalized costs for oil and gas properties.......... $3,034,108 $3,515,842
========== ==========
COSTS INCURRED FOR OIL AND GAS PRODUCING ACTIVITIES
PROPERTY
ACQUISITION COST TOTAL
------------------------ EXPLORATION DEVELOPMENT COSTS
PROVED UNPROVED(a) COSTS COSTS INCURRED
---------- ----------- ----------- ----------- ----------
(IN THOUSANDS)
Year ended December 31, 1998:
United States................... $ 19,658 $ 34,092 $ 62,747 $213,943 $ 330,440
Argentina....................... 4,504 67,010 22,521 39,049 133,084
Canada.......................... 1,185 (93,349) 21,871 47,550 (22,743)
Other foreign(b)................ (136) -- 21,706 412 21,982
---------- -------- -------- -------- ----------
Total costs incurred.... $ 25,211 $ 7,753 $128,845 $300,954 $ 462,763
========== ======== ======== ======== ==========
Year ended December 31, 1997:
United States................... $2,623,993 $ 91,373 $ 88,710 $243,119 $3,047,195
Argentina....................... 430,607 252,343 1,822 3,927 688,699
Canada.......................... 287,787 194,067 -- -- 481,854
Other foreign(c)................ -- 332 5,442 -- 5,774
---------- -------- -------- -------- ----------
Total costs incurred.... $3,342,387 $538,115 $ 95,974 $247,046 $4,223,522
========== ======== ======== ======== ==========
Year ended December 31, 1996:
United States................... $ 15,699 $ 5,255 $ 31,568 $168,553 $ 221,075
Foreign(d)...................... 18 -- 7,240 4,659 11,917
---------- -------- -------- -------- ----------
Total costs incurred.... $ 15,717 $ 5,255 $ 38,808 $173,212 $ 232,992
========== ======== ======== ======== ==========
- ---------------
(a) Includes 1998 Chauvco purchase price adjustments of $59.9 million for
Argentina and $(99.4) million for Canada.
(b) Primarily relates to the drilling of five wells in South Africa.
(c) Primarily relates to an unsuccessful well in Guatemala.
(d) 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.
88
89
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
RESULTS OF OPERATIONS
Information about the Company's results of operations for oil and gas
producing operations is presented in accordance with SFAS 69 and SFAS 131 in
Note P to the accompanying Notes to Consolidated Financial Statements.
RESERVE QUANTITY INFORMATION
The estimates of the Company's proved oil and gas reserves, which are
located principally in the United States, Argentina and Canada are prepared by
the Company's engineers. Reserves were estimated in accordance with guidelines
established by the SEC 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 reserve estimates for 1998, 1997 and 1996 utilize
respective oil prices of $10.09, $16.89 and $24.55 per Bbl (reflecting
adjustments for oil quality and gathering and transportation costs), and gas
prices of $1.64, $2.06 and $3.97 per Mcf (reflecting adjustments for BTU
content, gathering and transportation costs and gas processing and shrinkage).
The reserve estimates for 1998 and 1997 utilize respective NGL prices of $6.81
and $12.79 per Bbl.
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.
89
90
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
OIL AND GAS PRODUCING ACTIVITIES
1998 1997 1996
------------------------------ ----------------------------- ----------------------------
OIL OIL OIL
& NGLS GAS & NGLS GAS & NGLS GAS
(MBbls) (MMcf) MBOE (MBBls) (MMcf) MBOE (MBbls) (MMCF) MBOE
------- --------- -------- ------- --------- ------- ------- -------- -------
TOTAL PROVED RESERVES:
UNITED STATES
Balance, January 1............... 329,316 1,719,130 615,838 162,836 828,268 300,881 134,891 778,609 264,659
Revisions of previous
estimates...................... (34,211) (32,113) (39,563) 70,063 (100,755) 53,271 42,614 151,095 67,797
Purchases of minerals in place... -- -- -- 121,286 1,147,921 312,606 300 11,494 2,216
New discoveries and extensions... 183 3,438 756 1,109 7,659 2,385 760 17,607 3,694
Production....................... (25,327) (137,741) (48,284) (17,737) (104,868) (35,215) (10,872) (73,924) (23,193)
Sales of minerals-in-place....... (323) (7,070) (1,501) (8,241) (59,095) (18,090) (4,857) (56,613) (14,292)
------- --------- -------- ------- --------- ------- ------- -------- -------
Balance, December 31............. 269,638 1,545,644 527,246 329,316 1,719,130 615,838 162,836 828,268 300,881
CANADA
Balance, January 1............... 22,796 207,868 57,441 -- -- -- -- -- --
Revisions of previous
estimates...................... (6,905) 60,247 3,135 -- -- -- -- -- --
Purchases of minerals-in-place... 2 -- 2 22,796 207,868 57,441 -- -- --
New discoveries and extensions... 261 5,951 1,253 -- -- -- -- -- --
Production....................... (3,596) (19,371) (6,824) -- -- -- -- -- --
Sales of minerals-in-place....... (111) (5,465) (1,022) -- -- -- -- -- --
------- --------- -------- ------- --------- ------- ------- -------- -------
Balance, December 31............. 12,447 249,230 53,985 22,796 207,868 57,441 -- -- --
AUSTRALIA
Balance, January 1............... -- -- -- -- -- -- 12,443 118,297 32,159
Revisions of previous
estimates...................... -- -- -- -- -- -- -- -- --
Purchases of minerals-in-place... -- -- -- -- -- -- -- -- --
New discoveries and extensions... -- -- -- -- -- -- -- -- --
Production....................... -- -- -- -- -- -- (349) (1,927) (669)
Sales of minerals-in-place....... -- -- -- -- -- -- (12,094) (116,370) (31,490)
------- --------- -------- ------- --------- ------- ------- -------- -------
Balance, December 31............. -- -- -- -- -- -- -- -- --
ARGENTINA
Balance, January 1............... 31,612 340,392 88,344 1,105 1,108 1,290 -- -- --
Revisions of previous
estimates...................... (7,615) 76,843 5,192 (259) (1,108) (444) -- -- --
Purchases of minerals-in-place... -- -- -- 30,914 340,392 87,646 -- -- --
New discoveries and extensions... 3,522 37,900 9,839 -- -- -- 1,159 1,108 1,344
Production....................... (3,300) (26,801) (7,767) (148) -- (148) (54) -- (54)
Sales of minerals-in-place....... -- -- -- -- -- -- -- -- --
------- --------- -------- ------- --------- ------- ------- -------- -------
Balance, December 31............. 24,219 428,334 95,608 31,612 340,392 88,344 1,105 1,108 1,290
TOTAL
Balance, January 1............... 383,724 2,267,390 761,623 163,941 829,376 302,171 147,334 896,906 296,818
Revisions of previous
estimates...................... (48,731) 104,977 (31,236) 69,804 (101,863) 52,827 42,614 151,095 67,797
Purchases of minerals-in-place... 2 -- 2 174,996 1,696,181 457,693 300 11,494 2,216
New discoveries and extensions... 3,966 47,289 11,848 1,109 7,659 2,385 1,919 18,715 5,038
Production....................... (32,223) (183,913) (62,875) (17,885) (104,868) (35,363) (11,275) (75,851) (23,916)
Sales of minerals-in-place....... (434) (12,535) (2,523) (8,241) (59,095) (18,090) (16,951) (172,983) (45,782)
------- --------- -------- ------- --------- ------- ------- -------- -------
Balance, December 31............. 306,304 2,223,208 676,839 383,724 2,267,390 761,623 163,941 829,376 302,171
======= ========= ======== ======= ========= ======= ======= ======== =======
PROVED DEVELOPED RESERVES:
January 1...................... 329,920 1,956,658 656,030 126,370 660,174 236,399 108,920 646,066 216,598
======= ========= ======== ======= ========= ======= ======= ======== =======
December 31.................... 274,953 2,001,775 608,582 329,920 1,956,658 656,030 126,370 660,174 236,399
======= ========= ======== ======= ========= ======= ======= ======== =======
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PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
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.
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PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------
1998 1997 1996
----------- ----------- -----------
(IN THOUSANDS)
UNITED STATES
Oil and gas producing activities:
Future cash inflows................................. $ 5,050,473 $ 8,936,044 $ 7,280,710
Future production costs............................. (2,281,406) (3,185,357) (2,325,274)
Future development costs............................ (227,727) (325,659) (196,410)
Future income tax expense........................... -- (860,632) (1,385,399)
----------- ----------- -----------
2,541,340 4,564,396 3,373,627
10% annual discount factor.......................... (1,314,471) (2,067,371) (1,574,103)
----------- ----------- -----------
Standardized measure of discounted future net cash
flows............................................ $ 1,226,869 $ 2,497,025 $ 1,799,524
=========== =========== ===========
ARGENTINA
Oil and gas producing activities:
Future cash inflows................................. $ 686,911 $ 912,688 $ 28,211
Future production costs............................. (196,446) (168,105) (8,099)
Future development costs............................ (45,710) (137,060) (4,456)
Future income tax expense........................... -- (60,069) --
----------- ----------- -----------
444,755 547,454 15,656
10% annual discount factor.......................... (211,956) (201,732) (7,615)
----------- ----------- -----------
Standardized measure of discounted future net cash
flows............................................ $ 232,799 $ 345,722 $ 8,041
=========== =========== ===========
CANADA
Oil and gas producing activities:
Future cash inflows................................. $ 526,844 $ 662,104 $ --
Future production costs............................. (163,414) (223,325) --
Future development costs............................ (49,380) (48,323) --
Future income tax expense........................... (30,797) (79,044) --
----------- ----------- -----------
283,253 311,412 --
10% annual discount factor.......................... (94,113) (102,395) --
----------- ----------- -----------
Standardized measure of discounted future net cash
flows............................................ $ 189,140 $ 209,017 $ --
=========== =========== ===========
TOTAL
Oil and gas producing activities:
Future cash inflows................................. $ 6,264,228 $10,510,836 $ 7,308,921
Future production costs............................. (2,641,266) (3,576,787) (2,333,373)
Future development costs............................ (322,817) (511,042) (200,866)
Future income tax expense........................... (30,797) (999,745) (1,385,399)
----------- ----------- -----------
3,269,348 5,423,262 3,389,283
10% annual discount factor.......................... (1,620,540) (2,371,498) (1,581,718)
----------- ----------- -----------
Standardized measure of discounted future net cash
flows............................................ $ 1,648,808 $ 3,051,764 $ 1,807,565
=========== =========== ===========
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PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
OIL AND GAS PRODUCING ACTIVITIES
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------
1998 1997 1996
----------- ----------- ----------
(IN THOUSANDS)
Oil and gas sales, net of production costs............ $ (487,942) $ (392,612) $ (286,597)
Net changes in prices and production costs............ (1,281,944) (1,034,678) 866,196
Extensions and discoveries............................ 44,018 19,993 53,314
Sales of minerals-in-place............................ (12,748) (126,879) (185,859)
Purchases of minerals-in-place........................ 3 1,880,570 20,606
Revisions of estimated future development costs....... (2,777) (15,158) (73,587)
Revisions of previous quantity estimates.............. (68,086) 240,375 569,529
Accretion of discount................................. 307,567 234,537 123,174
Changes in production rates, timing and other......... 75,045 (99,753) (106,896)
----------- ----------- ----------
Change in present value of future net reserves........ (1,426,864) 706,395 979,880
Net change in present value of future income taxes.... 23,908 537,804 (376,104)
----------- ----------- ----------
(1,402,956) 1,244,199 603,776
Balance, beginning of year............................ 3,051,764 1,807,565 1,203,789
----------- ----------- ----------
Balance, end of year.................................. $ 1,648,808 $ 3,051,764 $1,807,565
=========== =========== ==========
SELECTED QUARTERLY FINANCIAL RESULTS
QUARTER
-------------------------------------------
FIRST SECOND THIRD FOURTH
-------- -------- -------- ----------
(IN THOUSANDS EXCEPT PER SHARE DATA)
1998
Operating revenues............................. $197,369 $183,647 $173,462 $ 157,014
Total revenues................................. $198,557 $185,107 $178,869 $ 158,966
Costs and expenses............................. $238,801 $235,616 $247,071 $ 730,837
Net loss....................................... $(26,844) $(32,809) $(43,902) $ (642,871)
Net loss per share............................. $ (.27) $ (.33) $ (.44) $ (6.41)
1997
Operating revenues............................. $103,779 $ 94,847 $150,354 $ 187,802
Total revenues................................. $106,707 $ 97,389 $151,278 $ 190,655
Costs and expenses............................. $ 77,994 $ 85,576 $168,326 $1,591,696
Income (loss) before extraordinary item........ $ 18,613 $ 7,413 $(11,048) $ (892,241)
Net income (loss).............................. $ 18,613 $ 7,413 $(12,566) $ (904,131)
Income (loss) before extraordinary item per
share....................................... $ .53 $ .21 $ (.18) $ (11.43)
Net income (loss) per share.................... $ .53 $ .21 $ (.21) $ (11.58)
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
At a meeting held on December 5, 1997, the Board of Directors of the
Company approved the engagement of Ernst & Young LLP as the Company's
independent auditors for the fiscal year ending December 31, 1998 to replace the
firm of KPMG LLP, who were dismissed as auditors of the Company after completing
the audit of the Company for the fiscal year ending December 31, 1997. The audit
committee of the Board of Directors approved the change in auditors on December
5, 1997, subject to ratification by the Company's stockholders.
The reports of KPMG LLP on the Company's financial statements for the past
two fiscal years did not contain an adverse opinion or a disclaimer of opinion
and were not qualified or modified as to uncertainty, audit scope, or accounting
principles.
In connection with the audits of the Company's financial statements for
each of the two fiscal years ended December 31, 1997 and 1996, there were no
disagreements with KPMG LLP on any matters of accounting principles or
practices, financial statement disclosure, or auditing scope and procedures
which, if not resolved to the satisfaction of KPMG LLP would have caused KPMG
LLP to make reference to the matter in their report.
The Company received from KPMG LLP a letter addressed to the Securities and
Exchange Commission stating that KPMG LLP agrees with the above statements. A
copy of the letter was included as Exhibit 16.1 to the Company's annual report
on Form 10-K for the fiscal year ended December 31, 1997.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Set forth below are the names, ages, and positions of the Company's
directors and executive officers as of February 26, 1999.
NAME AGE POSITION
- ---- --- --------
I. Jon Brumley.......................... 60 Chairman of the Board of Directors and
Director
Scott D. Sheffield...................... 46 President, Chief Executive Officer and
Director
Timothy L. Dove......................... 42 Executive Vice President -- Business
Development
Dennis E. Fagerstone.................... 50 Executive Vice President
Lon C. Kile............................. 43 Executive Vice President
M. Garrett Smith........................ 37 Executive Vice President and Chief
Financial Officer
Mark L. Withrow......................... 51 Executive Vice President, General
Counsel and Secretary
James R. Baroffio....................... 67 Director
R. Hartwell Gardner..................... 64 Director
Kenneth A. Hersh........................ 36 Director
James L. Houghton....................... 68 Director
Jerry P. Jones.......................... 67 Director
Richard E. Rainwater.................... 54 Director
Charles E. Ramsey, Jr................... 62 Director
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NAME AGE POSITION
- ---- --- --------
Philip B. Smith......................... 47 Director
Robert L. Stillwell..................... 62 Director
The Company has classified its Board of Directors into three classes.
Directors in each class are elected to serve for three-year terms and until
their successors are elected and qualified. Each year, the directors of one
class stand for re-election as their terms of office expire. Messrs. Baroffio,
Hersh, Sheffield and Stillwell are designated as Class II directors, and their
terms of office expire at the Annual Meeting. Messrs. Gardner, Houghton and
Philip Smith are designated as Class I directors, and their terms of office
expire at the annual meeting of stockholders in 2001. Messrs. Brumley, Jones,
Rainwater and Ramsey are designated as Class III directors, and their terms of
office expire at the annual meeting of stockholders in 2000. Effective March 18,
1999, Mr. Jones resigned as a Class II director and was re-appointed as a Class
III director. Since the last annual meeting of stockholders, three directors of
the Company, T. Boone Pickens, Arthur L. Smith and Guy J. Turcotte, voluntarily
resigned as directors of the Company. None of such resignations was the result
of a disagreement with the Company on any matter relating to the Company's
operations, policies or practices.
Members of the current Board of Directors (other than Mr. Baroffio) were
appointed under the terms of the merger agreement between Parker & Parsley and
Mesa. Mr. Baroffio became a director in December 1997 under the terms of the
combination agreement between the Company and Chauvco.
Executive officers serve at the discretion of the Board of Directors.
Set forth below is biographical information about each of the Company's
directors and executive officers.
I. Jon Brumley. Mr. Brumley, a graduate of the University of Texas with a
B.A. and of the Wharton School of Finance and Commerce with an M.B.A., has
served as Chairman of the Board of Directors of the Company since August 1997.
Mr. Brumley was also an employee of the Company from August 1997 until May 1998.
Mr. Brumley currently serves as Chairman of the Board of Directors of Encore
Acquisition Partners Inc., an independent oil and gas company that he founded in
April 1998. Mr. Brumley served as Chairman of the Board of Directors and Chief
Executive Officer of Mesa from August 1996 until August 1997. He also co-founded
Cross Timbers Oil Company and served as its Chairman of the Board from 1986 to
mid-1996. Mr. Brumley served as President and Chief Executive Officer of
Southland Royalty Company from 1974 until 1985.
Scott D. Sheffield. Mr. Sheffield, a graduate of the University of Texas
with a Bachelor of Science degree in Petroleum Engineering, has been the
President and Chief Executive Officer of the Company since August 1997. He was
the President and a director of Parker & Parsley since May 1990 and was the
Chairman of the Board and Chief Executive Officer of Parker & Parsley since
October 1990. Mr. Sheffield was the sole director of Parker & Parsley from May
1990 until October 1990. Mr. Sheffield joined Parker & Parsley Development
Company ("PPDC"), a predecessor of Parker & Parsley, as a petroleum engineer in
1979. Mr. Sheffield served as Vice President -- Engineering of PPDC from
September 1981 until April 1985, when he was elected President and a director.
In March 1989, Mr. Sheffield was elected Chairman of the Board and Chief
Executive Officer of PPDC. Before joining PPDC's predecessor, Mr. Sheffield was
employed as a production and reservoir engineer for Amoco Production Company.
Timothy L. Dove. Mr. Dove became Executive Vice President -- Business
Development of the Company in August 1997. Mr. Dove joined Parker & Parsley in
May 1994 as Vice President -- International and was promoted to Senior Vice
President -- Business Development in October 1996, in which position he served
until August 1997. Before joining Parker & Parsley, Mr. Dove was employed with
Diamond Shamrock Corp., and its successor, Maxus Energy Corp, in various
capacities in international exploration and production, marketing, refining, and
planning and development. Mr. Dove earned a Bachelor of Science degree in
Mechanical Engineering from Massachusetts Institute of Technology in 1979 and
received his M.B.A. in 1981 from the University of Chicago.
Dennis E. Fagerstone. Mr. Fagerstone, a graduate of the Colorado School of
Mines with a B.S. in Petroleum Engineering, became an Executive Vice President
of the Company in August 1997. Mr. Fagerstone
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served as Executive Vice President and Chief Operating Officer of Mesa from
March 1997, until August 1997. Mr. Fagerstone served as Senior Vice President
and Chief Operating Officer of Mesa from October 1996 to February 1997, and
served as Vice President -- Exploration and Production of Mesa from May 1991 to
October 1996. Mr. Fagerstone served as Vice President -- Operations of Mesa from
June 1988 until May 1991.
Lon C. Kile. Mr. Kile, a graduate of Oklahoma State University with a
Bachelor of Business Administration degree in Accounting, became Executive Vice
President of the Company in August 1997. Mr. Kile joined Parker & Parsley in
1985 and was promoted to Senior Vice President -- Investor Relations in October
1996. Previously, he was Vice President and Manager of the Mid-Continent
Division. Prior to that he held the positions of Vice President -- Equity
Finance & Analysis and Vice President -- Marketing and Program Administration.
Before joining Parker & Parsley, he was employed as Supervisor -- Senior, Audit,
in charge of Parker & Parsley's audit, with Arthur & Young.
M. Garrett Smith. Mr. Smith, a graduate of the University of Texas with a
Bachelor of Science degree in Electrical Engineering and Southern Methodist
University with an M.B.A., became Executive Vice President and Chief Financial
Officer of the Company in December 1997. Prior to that he was Senior Vice
President -- Finance of the Company since August 1997. Mr. Smith served as Vice
President -- Corporate Acquisitions of Mesa from January 1997 until August 1997.
From October 1996 to December 1996, Mr. Smith served as Vice President
-- Finance of Mesa and from 1994 to 1996, he served as Director of Financial
Planning of Mesa. Mr. Smith was employed by BTC Partners, Inc. (a former
financial advisor to Mesa) from 1989 to 1994.
Mark L. Withrow. Mr. Withrow, a graduate of Abilene Christian University
with a Bachelor of Science degree in Accounting and Texas Tech University with a
Juris Doctorate degree, has been the Executive Vice President, General Counsel
and Secretary of the Company since August 1997. He served as Vice President --
General Counsel of Parker & Parsley from February 1991 until January 1995, and
served as Senior Vice President, General Counsel of Parker & Parsley from
January 1995 until August 1997. He was Parker & Parsley's Secretary from August
1992 until August 1997. Mr. Withrow joined PPDC in January 1991. Before joining
PPDC, Mr. Withrow was the managing partner of the law firm of Turpin, Smith,
Dyer, Saxe & MacDonald, Midland, Texas.
James R. Baroffio. Dr. Baroffio received a B.A. in Geology at the College
of Wooster, Ohio, an M.S. in Geology at Ohio State University, and a Ph.D. in
Geology at the University of Illinois. Before becoming a director of the Company
in December 1997, Dr. Baroffio enjoyed a long career with Standard Oil Company
of California, the predecessor of Chevron Corporation, eventually retiring as
President of Chevron Canada Resources in 1994. Dr. Baroffio was President-elect
of the Colorado Petroleum Association, a member of the Board of Directors of the
Rocky Mountain Oil & Gas Association, and Chairman of the U.S. National
Committee of the World Petroleum Congress. His community leadership positions
included membership on the Board of Directors of Glenbow Museum and the Nature
Conservancy of Canada, as well as serving as President of the Alberta Nature
Conservancy.
R. Hartwell Gardner. Mr. Gardner became a director of the Company in August
1997. He served as a director of Parker & Parsley from November 1995 until
August 1997. Mr. Gardner graduated from Colgate University with a Bachelor of
Arts degree in Economics and then earned an M.B.A. from Harvard University.
Until October 1, 1995, Mr. Gardner was the Treasurer of Mobil Oil Corporation
and Mobil Corporation from 1974 and 1976, respectively. Mr. Gardner is a member
of the Financial Executives Institute of which he served as Chairman in
1986/1987 and is a Director of Oil Investment Corporation Ltd. and Oil Casualty
Investment Corporation Ltd., Pembroke, Bermuda.
Kenneth A. Hersh. Mr. Hersh, who became a director of the Company in August
1997, has been a Managing Director of Natural Gas Partners ("NGP") since 1989.
NGP is a family of investment funds organized to make equity investments in oil
and gas companies. Previously, he was employed by the investment banking
division of Morgan Stanley & Co. Incorporated where he was a member of the
firm's energy group specializing in oil and gas financing and acquisition
transactions. Mr. Hersh is a director of HS Resources, Inc., Petroglyph Energy,
Inc., Titan Exploration, Inc. and Vista Energy Resources, Inc.
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Mr. Hersh earned his M.B.A. from the Stanford University Graduate School of
Business, and his undergraduate degree from Princeton University.
James L. Houghton. Mr. Houghton is a certified public accountant and a
graduate of Kansas University with a Bachelor of Science degree in Accounting,
as well as a Bachelor of Laws degree. Mr. Houghton has served as a director of
the Company since August 1997, and as a director of Parker & Parsley from
October 1991 until August 1997. Until October 1, 1991, Mr. Houghton was the lead
oil and gas tax specialist for the accounting firm of Ernst & Young, was a
member of Ernst & Young's National Energy Group, and had served as its Southwest
Regional Director of Tax. Mr. Houghton is a member of the American Institute of
Certified Public Accountants, a member of the Oklahoma Society of Certified
Public Accountants and a former Chairman of its Federal and Oklahoma Taxation
Committee and past President of the Oklahoma Institute on Taxation. He has also
served as a Director for the Independent Petroleum Association of America and as
a member of its Tax Committee.
Jerry P. Jones. Mr. Jones earned a Bachelor of Science degree from West
Texas State College in 1953 and a Bachelor of Law degree from the University of
Texas School of Law in 1959. Mr. Jones has served as a director of the Company
since August 1997, and as a director of Parker & Parsley from May 1991 until
August 1997. Mr. Jones has been an attorney with the law firm of Thompson &
Knight, P.C., Dallas, Texas, since September 1959 and was a shareholder in that
firm until January 1998, when he retired and became of counsel to the firm. Mr.
Jones specialized in civil litigation, especially in the area of energy
disputes.
Richard E. Rainwater. Mr. Rainwater, a graduate of the University of Texas
with a B.A. and the Stanford University Graduate School of Business with an
M.B.A., became a director of the Company in August 1997. He served as a director
of Mesa from July 1996 until August 1997. Since 1986, Mr. Rainwater has been an
independent investor and the sole shareholder and Chairman of Rainwater, Inc.
Mr. Rainwater was the founder of Crescent Real Estate Equities, Inc. in 1994,
and since that time has served as its Chairman of the Board. He was the
co-founder of Mid Ocean Limited in 1991, the founder of Columbia Hospital
Corporation (predecessor to Columbia/HCA Healthcare Corporation) in 1987, and
the founder of ENSCO International, Inc. in 1986. From 1970 until 1986, Mr.
Rainwater served as the Chief Investment Advisor to the Bass Family of Texas.
Charles E. Ramsey, Jr. Mr. Ramsey is a graduate of the Colorado School of
Mines with a Petroleum Engineering degree and a graduate of the Smaller Company
Management program at the Harvard Graduate School of Business Administration.
Mr. Ramsey has served as a director of the Company since August 1997. Mr. Ramsey
served as a director of Parker & Parsley from October 1991 until August 1997.
Since October 1991, he has operated an independent management and financial
consulting firm. From June 1958 until June 1986, Mr. Ramsey held various
engineering and management positions in the oil and gas industry and, for six
years before October 1991, was a Senior Vice President in the Corporate Finance
Department of Dean Witter Reynolds Inc. (Dallas, Texas office). His industry
experience includes 12 years of senior management experience in the positions of
President, Chief Executive Officer and Executive Vice President of May Petroleum
Inc. Mr. Ramsey is also a former director of MBank Dallas, the Dallas Petroleum
Club and Lear Petroleum Corporation.
Philip B. Smith. Mr. Smith, a graduate of Oklahoma State University with a
B.S. in mechanical engineering and the University of Tulsa with an M.B.A., has
served as a director of the Company since August 1997. He served as a director
of Mesa from July 1996 until August 1997. In 1996, Mr. Smith founded PRIZE
Petroleum, L.L.C., an owner of Sunterra Petroleum, L.L.C. From 1991 until 1996,
Mr. Smith served as President, Chief Executive Officer and a director of Tide
West Oil Company. From 1986 until 1991, he served as Senior Vice President of
Mega Natural Gas Company, and from 1980 until 1986 he held executive positions
with two small exploration and production companies. From 1976 until 1980, Mr.
Smith held various positions with Samson Resources Company, and from 1974 until
1976 he was a production engineer with Texaco Inc. Mr. Smith is a director of HS
Resources, Inc.
Robert L. Stillwell. Mr. Stillwell, a graduate of the University of Texas
with a B.B.A. and the University of Texas School of Law with a J.D., has served
as a director of the Company since August 1997. He served as a director of Mesa
from January 1992 until August 1997, as a member of the Advisory Committee of
Mesa,
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L.P., a predecessor of Mesa, from December 1985 until December 1991, and as a
director of Mesa in its original corporate form from 1968 until January 1987.
Mr. Stillwell has been a partner in the law firm of Baker & Botts, L.L.P., for
more than five years.
In addition to the directors of the Company, Edward O. Vetter and John S.
Herrington will serve as Senior Advisors to the Board of Directors until May 31,
1999. Each of Messrs. Vetter and Herrington receives an annual fee of $20,000
cash for his services as Senior Advisor.
Mr. Vetter, a graduate of the Massachusetts Institute of Technology, served
as a director of Parker & Parsley from February 1992 until August 1997, and has
in the past served as director of AMR Corporation, American Airlines, Inc.,
Cabot Corporation, The Western Company of North America and Champion
International Corporation. Since 1977, Mr. Vetter has been President of Edward
O. Vetter & Associates, a management consulting firm in Dallas, Texas. Mr.
Vetter was the Energy Advisor to the Governor of Texas from 1979 to 1983, was
chairman of the Texas Department of Commerce from 1987 to 1991, and was a
Presidential appointee to the U.S. Competitiveness Policy Council. He is a life
trustee of the Massachusetts Institute of Technology and a former member of the
National Petroleum Council.
Mr. Herrington, a graduate of Stanford University with a B.A. in Economics,
and the University of California Hastings College of Law with a J.D. and L.L.B.,
was a director of the Company from August 1997 until May 1998. He served as a
director of Mesa from January 1992 until August 1997. Since December 1991, Mr.
Herrington has been involved in personal investments and real estate activities.
He was Chairman of the Board of Harcourt Brace Jovanovich, Inc. (publishing)
from May 1990 until November 1991, and served as a director from May 1989 until
May 1990. Mr. Herrington served as the Secretary of the Department of Energy of
the United States from February 1985 until May 1990.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
The executive officers and directors of the Company are required to file
reports with the Securities and Exchange Commission, and with the various
Canadian provincial securities commissions (the "Canadian Commissions"),
disclosing the amount and nature of their beneficial ownership in common stock,
as well as changes in that ownership. Pursuant to applicable Canadian policies,
the executive officers and directors of the Company are exempted from filing
reports with the Canadian Commissions, provided that they timely file all
reports required to be filed with the Securities and Exchange Commission.
Based solely on its review of reports and written representations that the
Company has received, the Company is aware that Scott D. Sheffield, the
President and Chief Executive Officer of the Company, did not timely file three
reports on Form 4 covering six transactions effected in 1998. Other than as
discussed above, the Company believes that all required reports were filed on
time for 1998.
ITEM 11. EXECUTIVE COMPENSATION
The Company began operations upon completion of the merger of Parker &
Parsley and Mesa on August 7, 1997. Information about management compensation
for periods before that date refers to compensation that either of the
predecessor companies paid.
COMPENSATION OF DIRECTORS
Currently, each non-employee director receives an annual retainer fee of
$50,000 if the director serves on a committee and $40,000 if he does not. In
addition, each non-employee director is reimbursed for travel expenses to attend
meetings of the Board of Directors or its committees and an additional $2,500
for services as chairman of a committee. No additional fees are paid for
attendance at board or committee meetings. Executive officers of the Company do
not receive additional compensation for serving on the Board of Directors.
Under the Plan, each non-employee director automatically receives 50
percent (and may elect to receive 100 percent) of the director's annual retainer
fee in the form of common stock instead of cash on the last
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business day of the month in which the annual meeting of stockholders is held.
The number of shares included in each award is determined by dividing the
applicable percentage of the annual retainer fee by the closing sale price of
common stock on the business day immediately preceding the date of the award.
When issued, the shares of common stock awarded are subject to transfer
restrictions that lapse on the earlier of the next annual meeting of
stockholders or the first anniversary date of the award if the person has
continued as a director through that date. If a non-employee director's services
as a director are terminated for any reason before the earlier of the next
annual meeting of stockholders or the first anniversary of the date of the
grant, transfer restrictions on some of the shares will lapse (and the rest of
the shares will be forfeited) based on the number of regularly scheduled
meetings of the Board of Directors that were held since the last annual meeting
and the number of regularly scheduled meetings remaining to be held before the
next annual meeting of stockholders. The vesting of ownership and the lapse of
transfer restrictions may be accelerated upon the death, disability or
retirement of the director or a change in control of the Company.
On May 29, 1998, each non-employee director received the following awards
of common stock in lieu of cash retainer fees (which were based on a closing
sale price of $22.8125 for the common stock): Messrs. Brumley, Gardner and Hersh
received awards of 2,191 shares; Messrs. Baroffio and Rainwater received awards
of 1,753 shares; Messrs. Houghton, Jones, Ramsey and Smith received awards of
1,095 shares; and Mr. Stillwell received an award of 876 shares. Messrs.
Brumley, Gardner and Hersh were the only directors who elected to receive 100
percent of their retainers in common stock.
COMPENSATION OF EXECUTIVE OFFICERS
The compensation paid to the Company's executive officers generally
consists of base salaries, annual bonuses, awards under the Plan, contributions
to the Company's 401(k) retirement plan, and miscellaneous perquisites. The
following table summarizes the total compensation for 1998, 1997, and 1996
awarded to, earned by or paid to the following persons:
SUMMARY COMPENSATION TABLE
LONG-TERM
COMPENSATION AWARDS
ANNUAL COMPENSATION -----------------------
------------------------------------- VALUE OF SHARES
OTHER ANNUAL RESTRICTED UNDERLYING ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS(a) COMPENSATION(b) STOCK(c) OPTIONS(d) COMPENSATION(e)
- --------------------------- ---- -------- -------- --------------- ---------- ---------- ---------------
I. Jon Brumley(f)............... 1998 $225,000 $ -- $ 60,285 $ -- -- $ 36,445
Chairman of the Board 1997 537,525 360,000 121,198 2,234,625 90,000 36,037
1996 180,142 -- -- -- 228,571 18,014
Scott D. Sheffield(g)........... 1998 600,000 216,000 16,734 -- 90,000 123,252
President and 1997 518,875 360,000 838,075 2,234,625 90,000 105,996
Chief Executive Officer 1996 390,000 375,375 47,770 -- 70,000 87,990
Dennis E. Fagerstone............ 1998 275,000 92,812 8,076 -- 35,000 37,757
Executive Vice President 1997 259,387 123,750 61,985 871,125 35,000 27,149
1996 212,490 90,000 -- -- 71,428 30,249
Mel Fischer(h).................. 1998 285,000 76,950 18,897 -- -- 44,500
Executive Vice President 1997 255,833 128,250 346,438 871,125 56,000 33,787
- -- World Wide Exploration 1996 -- -- -- -- -- --
Mark L. Withrow(g).............. 1998 250,000 84,376 60,882 -- 35,000 61,178
Executive Vice President 1997 228,000 112,500 382,020 871,125 35,000 51,835
and General Counsel 1996 175,000 201,737 33,021 59,500 21,000 43,103
M. Garrett Smith................ 1998 250,000 84,376 7,457 -- 35,000 36,559
Executive Vice President 1997 214,000 105,750 44,386 871,125 35,000 15,812
and Chief Financial Officer 1996 137,490 200,000 -- -- 50,000 33,749
- ---------------
(a) Represents the amount awarded under the Company's annual bonus program and
bonus awards related to specific events. The 1998 annual bonus was approved
on February 24, 1999, and paid fully in cash. The 1997 annual bonus was
paid one-half in cash and one-half in restricted common stock. Subject to
accelerated lapse in certain circumstances, the ownership of the stock
vests after one year, and transfer restrictions lapse on one-third of the
shares on each of the first, second and third anniversaries of the date of
grant. In 1996, Mr. Withrow received one-half of a previously established
target level bonus in
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100
restricted stock and the other one-half of target plus any excess above
target in cash. The number of shares of restricted stock awarded as annual
bonuses was calculated using the last closing sale price of the common
stock before the date of the award $(22.375 for 1997 and $30.125 for 1996).
Ownership of the restricted stock awarded in 1996 vested on August 13, 1997
and ownership of the restricted stock awarded for 1997 vested on September
30, 1998 due to the triggering of a vesting acceleration clause contained
in the Plan.
RESTRICTED STOCK AWARD
-----------------------
NUMBER VALUE
YEAR CASH AWARD OF SHARES OF SHARES
---- ---------- ---------- ----------
Mr. Brumley....................................... 1998 $ -- -- $ --
1997 179,993 8,045 180,007
1996 -- -- --
Mr. Sheffield..................................... 1998 216,000 -- --
1997 179,993 8,045 180,007
1996 375,375 -- --
Mr. Fagerstone.................................... 1998 92,812 -- --
1997 61,883 2,765 61,867
1996 90,000 -- --
Mr. Fischer....................................... 1998 76,950 -- --
1997 64,123 2,866 64,127
1996 -- -- --
Mr. Withrow....................................... 1998 84,376 -- --
1997 56,249 2,514 56,251
1996 102,377 1,307 39,373
Mr. Smith......................................... 1998 84,376 -- --
1997 52,878 2,363 52,872
1996 200,000 -- --
In 1996 Mr. Withrow also received a restricted stock bonus award of 2,436
shares valued at $59,987 on the date of grant for his role in the
divestiture of the Company's Australia and Asia subsidiaries. These shares
vested on April 17, 1997, and the transfer restrictions lapsed one-third on
April 17, 1997, and the remaining two-thirds lapsed on August 7, 1997.
(b) This column includes (i) gross-up payments in 1997 for taxes in connection
with the receipt of restricted stock awarded pursuant to the annual bonus
plan as follows: Mr. Brumley $118,805; Mr. Sheffield $118,805; Mr.
Fagerstone $40,832; Mr. Fischer $42,328; and Mr. Withrow $37,125; (ii)
relocation and housing cost of living adjustment related to moving
corporate headquarters from Midland, Texas to Irving, Texas as follows:
payment for 1998 -- Mr. Withrow $42,290; payments for 1997 -- Mr. Sheffield
$432,856; Mr. Fischer $151,777; and Mr. Withrow $204,000; (iii) tax
gross-up payments for relocation and cost of living adjustment: payment for
1998 -- Mr. Withrow $12,044; payments for 1997 -- Mr. Sheffield $283,781;
Mr. Fischer $94,889; and Mr. Withrow $133,742; (iv) temporary housing
payment to Mr. Fisher of $15,000 in 1998, and $55,000 in 1997, for housing
in Texas during Mr. Fischer's two year initial employment commitment; (v) a
1998 payment of $44,998 to Mr. Brumley for unused vacation; and 1997
payments to Mr. Fagerstone of $21,153 and Mr. Smith for $9,490 for unused
vacation; (vi) a cash payment to Mr. Sheffield in 1996 of $47,770, which
was equal to 50 percent of the federal income tax liability associated with
the cash bonus received in lieu of restricted stock under the annual bonus
program; and (vii) a 1996 gross-up payment to Mr. Withrow of $33,021
related to a restricted stock award he received as part of the annual bonus
plan. Amounts not shown represent miscellaneous perquisites.
(c) The restricted stock awarded in 1997 represents grants on August 8, 1997 of
59,000 shares of common stock to each of Messrs. Brumley and Sheffield and
23,000 shares of common stock to each of Messrs. Fagerstone, Fischer,
Withrow and Smith with vesting restrictions that were to lapse one-half on
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August 8, 2000, and one-half on August 8, 2001. Mr. Brumley's restricted
stock fully vested effective as of May 15, 1998, in connection with his
retirement as an employee of the Company. Messrs. Sheffield, Fischer,
Fagerstone, Withrow and Smith's restricted stock fully vested on September
30, 1998 due to the triggering of a vesting acceleration clause contained
in the Plan. In 1996 Mr. Withrow received a restricted stock award of 2,000
shares of common stock with vesting restrictions that were to lapse
November 19, 1999. The merger of Parker & Parsley and Mesa to form the
Company accelerated the lapse of these restrictions to August 7, 1997. The
values of the awards were calculated using the closing sale price of the
common stock of $37.875 on August 7, 1997, and of $29.75 on November 18,
1996. Because all vesting restrictions on all restricted stock heretofore
awarded to each executive officer have lapsed (either by their terms or
through acceleration upon the happening of certain events) no executive
officer held any shares of restricted stock on December 31, 1998.
(d) Stock options that Mesa awarded to Messrs. Brumley, Fagerstone and Smith
before the merger were converted to options to purchase common stock on a
1-for-7 basis.
(e) For 1998 this column includes (i) contributions to qualified retirement
plans for Messrs. Brumley, Sheffield, Fagerstone, Fischer, Withrow and
Smith of $7,916, $16,000, $9,728, $16,000, $16,000 and $11,222,
respectively; (ii) contributions to the Company's non-qualified deferred
compensation retirement plan for Messrs. Brumley, Sheffield, Fagerstone,
Fischer, Withrow and Smith of $28,529, $61,154, $28,029, $28,500, $25,481
and $25,337, respectively; (iii) deemed payment for one-third of the
principal and all accrued interest to Mr. Sheffield for $44,768 and Mr.
Withrow for $19,697 related to a 1995 stock acquisition loan program; and
(iv) a $1,330 premium with respect to a term life insurance policy for the
benefit of Mr. Sheffield.
(f) Mr. Brumley became an officer of Mesa in August 1996. He ceased to be an
employee of the Company effective May 15, 1998, but continues to serve as
Chairman of the Board of Directors.
(g) See "Compensation of Executive Officers -- Employee Investment
Partnerships" below for information about Parker & Parsley-sponsored
employee investment partnerships in which Mr. Sheffield and Mr. Withrow
invested their own funds.
(h) Mr. Fischer became an officer of Parker & Parsley in February 1997. Mr.
Fischer retired from the Company effective February 15, 1999.
Long-Term Incentive Plan. The Plan provides for employee awards in the form
of stock options, stock appreciation rights, restricted stock, and performance
units payable in stock or cash. The maximum number of shares of common stock
that may be issued under the Plan is equal to 10 percent of the total number of
shares of common stock outstanding from time to time minus the total number of
shares of stock subject to outstanding awards on the date of calculation under
any other stock-based plan for employees or directors of the Company and its
subsidiaries. The Plan had 5,743,511 shares available for additional awards at
December 31, 1998.
Information about restricted stock awards made under the Plan is set forth
in the Summary Compensation Table. No performance units or stock appreciation
rights have been awarded under the Plan.
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The following table sets forth information about stock option grants made
during 1998 to the named executive officers.
OPTION GRANTS IN LAST FISCAL YEAR
INDIVIDUAL GRANTS
------------------------------------------------
NUMBER OF % OF TOTAL
SECURITIES OPTIONS GRANTED EXERCISE OR
UNDERLYING TO EMPLOYEES BASE PRICE EXPIRATION GRANT DATE
NAME OPTIONS GRANTED IN FISCAL YEAR PER SHARE(c) DATE VALUE(d)
- ---- --------------- --------------- ------------ ---------- ----------
Mr. Brumley.............. -- -- -- -- --
Mr. Sheffield............ 45,000(a) 2.10 17.25 9/30/03 298,800
45,000(b) 2.10 14.00 11/23/04-05-06 279,000
Mr. Fagerstone........... 17,500(a) 0.81 17.25 9/30/03 116,200
17,500(b) 0.81 14.00 11/23/04-05-06 108,500
Mr. Fischer.............. 17,500(a) 0.81 17.25 9/30/03 116,200
17,500(b) 0.81 14.00 11/23/04-05-06 108,500
Mr. Withrow.............. 17,500(a) 0.81 17.25 9/30/03 116,200
17,500(b) 0.81 14.00 11/23/04-05-06 108,500
Mr. Smith................ 17,500(a) 0.81 17.25 9/30/03 116,200
17,500(b) 0.81 14.00 11/23/04-05-06 108,500
- ---------------
(a) These options were granted on August 19, 1998, fully vested on September
30, 1998 due to the triggering of a vesting acceleration clause contained
in the Plan, and expire September 30, 2003.
(b) These options were granted on November 23, 1998, vest at the rate of
one-third each year commencing on the first anniversary of the grant date,
and have a term of five years from the date of vesting. The Compensation
Committee retains discretion, subject to plan limits, to modify the terms
of the options. In the event of a change in control of the Company as
defined in the Plan, the options will immediately become fully vested and
exercisable in full.
(c) The exercise price per share is equal to the closing price of the common
stock on the New York Stock Exchange composite tape on the day before the
date of grant.
(d) The estimated grant date value of shares in footnotes (a) and (b) is
determined using the Black-Scholes model. The material assumptions and
adjustments incorporated in the Black-Scholes model in estimating the value
of the options include the following:
- An interest rate of 5.43 percent for footnote (a) and 5.5 percent for
footnote (b), which represents the interest rate on a U.S. Treasury
security with a maturity date corresponding to the option term.
- Volatility of .309 percent for footnote (a) and .398 percent for footnote
(b) calculated using daily stock prices for the 120-day period prior to
the grant date.
- Dividends at the rate of $.10 per share representing the annualized
dividends paid with respect to a share of common stock at the date of
grant.
No other adjustments were made to the model for non-transferability or risk
of forfeiture. The ultimate values of the options will depend on the future
market price of the common stock, which cannot be forecast with reasonable
accuracy. The actual value, if any, an optionee will realize upon exercise
of an option will depend on the excess of the market value of the common
stock over the exercise price on the date the option is exercised.
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103
The following table sets forth, for each named executive officer,
information concerning the exercise of stock options during 1998 and the value
of unexercised stock options as of December 31, 1998.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR END OPTION VALUES
NUMBER OF SECURITIES VALUE OF UNEXERCISED
NUMBER OF UNDERLYING UNEXERCISED IN-THE-MONEY
SHARES OPTIONS AT FISCAL YEAR END OPTIONS AT FISCAL YEAR END
ACQUIRED ON VALUE --------------------------- ---------------------------
EXERCISE REALIZED EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
----------- -------- ----------- ------------- ----------- -------------
Mr. Brumley............... -- -- 318,571 -- -- --
Mr. Sheffield............. -- -- 305,350 45,000 -- --
Mr. Fagerstone............ -- -- 132,498 17,500 -- --
Mr. Fischer............... -- -- 73,500 17,500 -- --
Mr. Withrow............... -- -- 94,500 17,500 -- --
Mr. Smith................. -- -- 106,071 17,500 -- --
Retirement Plan. The Company provides a non-qualified deferred compensation
retirement plan for officers and key employees of the Company. Each participant
is allowed to contribute up to 25 percent of base salary. The Company provides a
matching contribution of 100 percent of the participant's contribution limited
to the first 10 percent of the officer's base salary (or 8 percent of the key
employee's base salary). The Company matching contribution vests immediately.
In December 1998, the Company received information that an investment fund
group had acquired beneficial ownership of more than 20 percent of the common
stock. Pursuant to the provisions of the Company's deferred compensation
retirement plan, if a third party acquires 20 percent or more of the common
stock certain change in control provisions contained in the Plan are triggered.
Accordingly, in December 1998, the Compensation Committee determined that a
change in control had occurred, effective September 30, 1998, under the deferred
compensation retirement plan. Consequently, all of the contributions made to the
deferred compensation retirement plan from August 1997 to December 15, 1998 were
distributed to the respective officers and key employees.
Employee Investment Partnerships. From 1987 through 1991, Parker & Parsley
formed employee partnership programs in which Mr. Sheffield participated. In
1992 and 1993 Mr. Sheffield and Mr. Withrow participated in a Direct Investment
Partnership formed to invest in all wells drilled by Parker & Parsley during
those years (except in certain circumstances where its participation would
impose additional costs to Parker & Parsley). As of December 31, 1998, the
aggregate contributions that have been made to the employee partnerships and the
Direct Investment Partnerships by Mr. Sheffield and Mr. Withrow and the
aggregate distributions that have been received by them from those partnerships
were as follows: Mr. Sheffield contributed $734,955 and received $1,066,125
($111,542 of which was received during 1998); and Mr. Withrow contributed
$142,625 and received $138,231 ($18,416 of which was received during 1998).
Severance Agreements. On August 8, 1997, the Company entered into severance
agreements with its officers. Salaries and bonuses are set by the Compensation
Committee independent of these agreements, and the Compensation Committee can
increase or reduce base salaries at its discretion.
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 the officer's 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's family for one year if the Company terminates the officer's
employment without cause or if the officer terminates employment for good
reason, which is 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 in control of the Company, the
Company terminates the officer without cause or if the officer terminates
employment for good reason, the Company must pay the officer an amount equal to
2.99 times the sum of the
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officer's base salary plus target bonus for the year and continue health
insurance for the officer's family for one year. If the officer terminates
employment with the Company without 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's family for
one year. Officers are also entitled to additional payments for certain tax
liabilities that may apply to severance payments following a change in control.
Indemnification Agreements. The Company has entered into indemnification
agreements with each of its directors and officers, including the named
executive officers. Those agreements require the Company to indemnify the
directors and officers to the fullest extent permitted by the Delaware General
Corporation Law and to advance expenses in connection with certain claims
against directors and officers. The Company expects to enter into similar
agreements with persons selected to be directors and officers in the future.
Each indemnification agreement also provides that, upon a potential change in
control of the Company and if the indemnified director or officer so requests,
the Company will create a trust for the benefit of the indemnified director or
officer in an amount sufficient to satisfy payment of all liabilities and suits
against which the Company has indemnified the director or officer.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
Mr. Kenneth A. Hersh is a member of the Compensation Committee and is a
vice-president of Rainwater, Inc. Effective January 1, 1999, the Company entered
into an agreement with Rainwater, Inc., the former general partner of DNR-MESA
Holdings, L.P. ("DNR"), modifying certain terms of a prior agreement between DNR
and Mesa, which was assumed by the Company upon consummation of the merger
between Parker & Parsley and Mesa. Pursuant to the terms of this agreement, as
modified, the Company will pay Rainwater, Inc. $300,000 per year and reimburse
Rainwater, Inc. for certain expenses in consideration for consulting and
financial analysis services provided to the Company by Rainwater, Inc. and its
representatives.
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105
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information regarding the beneficial
ownership of common stock as of February 26, 1999, by (a) each person who is
known by the Company to own beneficially more than 5 percent of the outstanding
shares of common stock, (b) each director and nominee for director of the
Company, (c) each executive officer of the Company, and (d) all directors and
executive officers as a group.
NUMBER OF PERCENTAGE
NAME OF PERSON OR IDENTITY OF GROUP SHARES OF CLASS(1)
- ----------------------------------- ---------- -----------
Beneficial Owners:
Southeastern Asset Management, Inc.(2).................... 26,434,632 26.4
Longleaf Partners Fund
O. Mason Hawkins
6410 Poplar Avenue, Suite 900
Memphis, Tennessee 38119
The Prudential Insurance Company of America(3)............ 10,210,987 10.2
751 Broad Street
Newark, New Jersey 07102-3777
Management:
Richard E. Rainwater(4)................................... 5,518,267 5.9
777 Main Street, Suite 2700
Fort Worth, Texas 76102
I. Jon Brumley(5)......................................... 687,283 *
Scott D. Sheffield(5),(6)................................. 640,770 *
Timothy L. Dove(5),(7).................................... 141,795 *
Dennis E. Fagerstone(5)................................... 163,405 *
Lon C. Kile(5),(8)........................................ 172,965 *
M. Garrett Smith(5)....................................... 129,149 *
Mark L. Withrow(5),(9).................................... 155,719 *
James R. Baroffio......................................... 4,753 *
R. Hartwell Gardner....................................... 12,489 *
Kenneth A. Hersh.......................................... 10,671 *
James L. Houghton(10)..................................... 13,040 *
Jerry P. Jones............................................ 15,552 *
Charles E. Ramsey, Jr..................................... 17,086 *
Philip B. Smith........................................... 42,674 *
Robert L. Stillwell(11)................................... 6,649 *
All directors and executive officers as a group (16
persons)(12)........................................... 7,732,267 8.3
- ---------------
* Does not exceed 1 percent.
(1) Based on 100,300,023 shares of common stock consisting of 94,099,256
outstanding shares of common stock and 6,200,767 outstanding exchangeable
shares that are exchangeable for the same number of shares of common stock.
(2) The Schedule 13G/A filed with the SEC on February 10, 1999, which is a
joint statement on Schedule 13G/A filed by Southeastern Asset Management,
Inc. ("Southeastern"), Longleaf Partners Fund ("Longleaf") and O. Mason
Hawkins ("Hawkins"), states that the statement is being filed by
Southeastern as a registered investment adviser, and that all of the
securities covered by the statement are owned legally by Southeastern's
investment advisory clients and none are owned directly or indirectly by
Southeastern. The Schedule 13G/A further states that the statement is also
being filed by Hawkins, Chairman of the Board and C.E.O. of Southeastern,
in the event he could be deemed to be a controlling person of that firm as
the result of his official positions with or ownership of its voting
securities. The existence of such control is expressly disclaimed. Hawkins
does not own directly or indirectly any securities covered by the Schedule
13G/A for his own account.
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106
(3) The Schedule 13G/A filed with the SEC on January 27, 1999 states that The
Prudential Insurance Company of America may have direct or indirect voting
and/or investment discretion over 10,210,987 shares or 10.2 percent of the
outstanding common stock which are held for the benefit of its clients by
its separate accounts, externally managed accounts, registered investment
companies, subsidiaries and/or other affiliates.
(4) Includes 109,324 shares owned directly by Rainwater, Inc., of which Mr.
Rainwater is the sole shareholder, and 247,710 shares (of which Mr.
Rainwater disclaims beneficial ownership) owned by Mr. Rainwater's spouse.
(5) Includes the following number of shares subject to stock options that were
exercisable at or within 60 days after March 31, 1999: Mr. Brumley,
318,571; Mr. Sheffield, 305,350; Mr. Dove, 100,500; Mr. Fagerstone,
132,498; Mr. Kile, 101,500; Mr. Smith, 106,071; and Mr. Withrow, 94,500;
(6) Includes 1,270 shares held by a minor child of Mr. Sheffield and 766 shares
held in Mr. Sheffield's 401(k) account.
(7) Includes 370 shares held in Mr. Dove's 401(k) account.
(8) Includes 586 shares held in Mr. Kile's 401(k) account.
(9) Includes 4,328 shares held in Mr. Withrow's 401(k) account.
(10) Includes 10,945 shares held by two trusts of which Mr. Houghton is a
trustee and over which shares he has sole voting and investment power, and
1,000 shares held in Mr. Houghton's investment retirement account.
(11) Includes 758 shares held by Mr. Stillwell's wife.
(12) Includes 1,158,990 shares of common stock subject to stock options that
were exercisable at or within 60 days after February 26, 1999.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company, through its wholly-owned subsidiaries, has in the past
sponsored certain affiliated partnerships, including 35 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 percent, 1.5375 percent and 1.865 percent,
respectively, of the costs and revenues attributable to the Company's interest
in the wells in which each such Direct Investment Partnership participates. The
Company discontinued the formation of Direct Investment Partnerships in 1995.
The Company, through a wholly-owned subsidiary, 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.
Effective January 1, 1999, the Company entered into an agreement with
Rainwater, Inc., the former general partner of DNR that Mr. Rainwater wholly
owns, modifying certain terms of a prior agreement between DNR and Mesa, which
was assumed by the Company upon consummation of the merger between Parker &
Parsley and Mesa. Pursuant to the terms of this agreement, as modified, the
Company will pay Rainwater, Inc. $300,000 per year and reimburse Rainwater, Inc.
for certain expenses in consideration for consulting and financial analysis
services provided to the Company by Rainwater, Inc. and its representatives.
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107
Brumley Partners, a Texas general partnership consisting of I. Jon Brumley,
the Company's Chairman of the Board, and a family member, was admitted as a
limited partner with a profits interest in DNR pursuant to the Amended and
Restated Agreement of Limited Partnership of DNR dated November 8, 1996. Until
March 23, 1998, DNR was a major holder of shares of common stock. On March 23,
1998, DNR distributed to its partners most of its common stock holdings, which
resulted in a distribution to Brumley Partners of 310,344 shares of common stock
having a net value of $8,243,513 at the distribution date.
Robert L. Stillwell, a director of the Company, is a partner of Baker &
Botts, L.L.P., which provided various legal services to the Company during 1997.
Baker & Botts, L.L.P. was Mesa's primary outside corporate counsel. The dollar
amount of fees that the Company paid to Baker & Botts, L.L.P. during the most
recent fiscal year of that law firm did not exceed 5 percent of that firm's
gross revenues for that year.
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' Reports
Consolidated Balance Sheets as of December 31, 1998 and 1997
Consolidated Statements of Operations and Comprehensive Income
(Loss) for the years ended December 31, 1998, 1997 and 1996
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1998, 1997 and 1996
Consolidated Statements of Cash Flows for the years ended December 31,
1998, 1997 and 1996
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 SEC 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 -- Amended and Restated Agreement and Plan of Merger, dated
as of April 6, 1997, by and among MESA Inc. ("Mesa"),
Mesa Operating Co. ("MOC"), MXP Reincorporation Corp. and
Parker & Parsley Petroleum Company ("Parker & Parsley")
(incorporated by reference to Exhibit 2.1 to the
Company's Registration Statement on Form S-4, dated June
27, 1997, Registration No. 333-26951).
3.1 -- Amended and 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 June
27, 1997, Registration No. 333-26951).
3.2 -- Restated Bylaws of the Company (incorporated by reference
to Exhibit 3.2 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No.
333-26951).
3.3 -- Certificate of Designations of Special Preferred Voting
Stock (incorporated by reference to Exhibit 3.3 of the
Company's Registration Statement on Form S-3,
Registration No. 333-42315, filed with the SEC on
December 17, 1997).
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108
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3.4 -- Terms and Conditions of Exchangeable Shares (incorporated
by reference to Annex F to the Definitive Joint
Management Information Circular and Proxy Statement of
the Company and Chauvco Resources Ltd. ("Chauvco"), File
No. 001-13245, filed with the SEC on November 17, 1997).
4.1 -- Form of Certificate of Common Stock, par value $.01 per
share, of the Company (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No.
333-26951).
4.2 -- Form of Certificate of Special Preferred Voting Stock
(incorporated by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
4.3 -- Form of Certificate of Exchangeable Shares (incorporated
by reference to Exhibit 4.2 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
9.1 -- Voting and Exchange Trust Agreement, dated as of December
18, 1997, among the Company, Pioneer Natural Resources
(Canada) Ltd. ("Pioneer Canada") and Montreal Trust
Company of Canada, as Trustee (incorporated by reference
to Exhibit 2.4 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on January 2,
1998).
9.2 -- Amended and Restated Shareholders Agreement, dated as of
September 3, 1997, by and between the Company and Guy J.
Turcotte (incorporated by reference to Exhibit 2.6 to the
Company's Registration Statement on Form S-3,
Registration No. 333-42315, filed with the SEC on
December 15, 1997).
9.3 -- Shareholders Agreement, dated as of September 3, 1997, by
and among the Company, Trimac Corporation and Gendis Inc.
(incorporated by reference to Exhibit 2.4 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on October 2, 1997).
10.1 -- Indenture, dated July 2, 1996, among Pioneer USA
(formerly MOC), as Issuer, the Company, as Guarantor, and
Harris Trust and Savings Bank, as Trustee, relating to
the 11 5/8% Senior Subordinated Discount Notes Due 2006
(incorporated by reference to Exhibit 4.17 to Mesa's
Quarterly Report on Form 10-Q for the period ended June
30, 1996).
10.2 -- First Supplemental Indenture, dated as of April 15, 1997,
among Pioneer USA (formerly MOC), as Issuer, Mesa, the
subsidiary guarantors named therein, the Company, and
Harris Trust and Savings Bank, as Trustee, with respect
to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 001-13245).
10.3 -- Second Supplemental Indenture, dated as of August 7,
1997, among Pioneer USA (formerly MOC), as Issuer, Mesa,
the subsidiary guarantors named therein, the Company, and
Harris Trust and Savings Bank, as Trustee, with respect
to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 001-13245).
10.4 -- Third Supplemental Indenture, dated as of December 18,
1997, among Pioneer USA, the Subsidiary Guarantors named
therein, the Company, and Harris Trust and Savings Bank,
as Trustee, with respect to the indenture identified
above as Exhibit 10.1 (incorporated by reference to
Exhibit 10.12 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on January 2,
1998).
108
109
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.5 -- Fourth Supplemental Indenture, dated as of December 30,
1997, among Pioneer USA (formerly MOC), a Delaware
corporation, the Company, a Delaware corporation, Pioneer
NewSub1, Inc., a Texas corporation, and Harris Trust and
Savings Bank, an Illinois corporation, as Trustee, with
respect to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 10.13 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.6 -- Fifth Supplemental Indenture, dated as of December 30,
1997, among Pioneer NewSub1, Inc. (as successor to
Pioneer USA), a Texas corporation, the Company, a
Delaware corporation, Pioneer DebtCo., Inc., a Texas
corporation, and Harris Trust and Savings Bank, an
Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.1 (incorporated
by reference to Exhibit 10.14 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.7 -- Sixth Supplemental Indenture, dated as of December 30,
1997, among Pioneer DebtCo. Inc. (as successor to Pioneer
NewSub1, Inc.), a Texas corporation, the Company, a
Delaware corporation, and Harris Trust and Savings Bank,
an Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.1 (incorporated
by reference to Exhibit 10.15 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.8 -- Indenture, dated July 2, 1996, among Pioneer USA
(formerly MOC), as Issuer, the Company (Mesa's
successor), as Guarantor, and Harris Trust and Savings
Bank, as Trustee, relating to the 10 5/8% Senior
Subordinated Notes Due 2006 (incorporated by reference to
Exhibit 4.18 to Mesa's Quarterly Report on Form 10-Q for
the period ended June 30, 1996).
10.9 -- First Supplemental Indenture, dated as of April 15, 1997,
among Pioneer USA (formerly MOC), as Issuer, Mesa, the
Subsidiary Guarantors named therein, the Company, and
Harris Trust and Savings Bank, as Trustee, with respect
to the indenture identified above as Exhibit 10.8
(incorporated by reference to Exhibit 10.3 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 001-13245).
10.10 -- Second Supplemental Indenture, dated as of August 7,
1997, among Pioneer USA (formerly MOC), as Issuer, Mesa,
the Subsidiary Guarantors named therein, the Company, and
Harris Trust and Savings Bank, as Trustee, with respect
to the indenture identified above as Exhibit 10.8
(incorporated by reference to Exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 001-13245).
10.11 -- Third Supplemental Indenture, dated as of December 18,
1997, among Pioneer USA, the Subsidiary Guarantors named
therein, the Company, and Harris Trust and Savings Bank,
as Trustee, with respect to the indenture identified
above as Exhibit 10.8 (incorporated by reference to
Exhibit 10.6 to the Company's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 2,
1998).
10.12 -- Fourth Supplemental Indenture, dated as of December 30,
1997, among Pioneer USA, a Delaware corporation, the
Company, a Delaware corporation, Pioneer NewSub1, Inc., a
Texas corporation, and Harris Trust and Savings Bank, an
Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.8 (incorporated
by reference to Exhibit 10.7 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
109
110
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.13 -- Fifth Supplemental Indenture, dated as of December 30,
1997, among Pioneer NewSub 1, Inc. (as successor to
Pioneer USA), a Texas corporation, the Company, a
Delaware corporation, Pioneer DebtCo., Inc., a Texas
corporation, and Harris Trust and Savings Bank, an
Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.8 (incorporated
by reference to Exhibit 10.8 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.14 -- Sixth Supplemental Indenture, dated as of December 30,
1997, among Pioneer DebtCo, Inc. (as successor to Pioneer
NewSub1, Inc.), a Texas corporation, the Company, a
Delaware corporation, and Harris Trust and Savings Bank,
an Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.8 (incorporated
by reference to Exhibit 10.9 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.15 -- Indenture, dated April 12, 1995, between Pioneer USA
(successor to Parker & Parsley), and The Chase Manhattan
Bank (National Association), as Trustee (incorporated by
reference to Exhibit 4.1 to Parker & Parsley's Current
Report on Form 8-K, dated April 12, 1995, File No.
001-10695).
10.16 -- First Supplemental Indenture, dated as of August 7, 1997,
among Parker & Parsley, The Chase Manhattan Bank, as
Trustee, and Pioneer USA, with respect to the indenture
identified above as Exhibit 10.15 (incorporated by
reference to Exhibit 10.5 to the Company's Quarterly
Report on Form 10-Q for the period ended September 30,
1997, File No. 001-13245).
10.17 -- Second Supplemental Indenture, dated as of December 30,
1997, among Pioneer USA, a Delaware corporation, Pioneer
NewSub1, Inc., a Texas corporation, and The Chase
Manhattan Bank, a New York banking association, as
Trustee, with respect to the indenture identified above
as Exhibit 10.15 (incorporated by reference to Exhibit
10.17 to the Company's Current Report on Form 8-K, File
No. 001-13245, filed with the SEC on January 2, 1998).
10.18 -- Third Supplemental Indenture, dated as of December 30,
1997, among Pioneer New Sub1, Inc. (as successor to
Pioneer USA), a Texas corporation, Pioneer DebtCo, Inc.,
a Texas corporation, and The Chase Manhattan Bank, a New
York banking association, as Trustee, with respect to the
indenture identified above as Exhibit 10.15 (incorporated
by reference to Exhibit 10.18 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.19 -- Fourth Supplemental Indenture, dated as of December 30,
1997, among Pioneer DebtCo, Inc. (as successor to Pioneer
NewSub1, Inc., as successor to Pioneer USA), a Texas
corporation, the Company, a Delaware corporation, Pioneer
USA, a Delaware corporation, and The Chase Manhattan
Bank, a New York banking association, as trustee, with
respect to the indenture identified above as Exhibit
10.15 (incorporated by reference to Exhibit 10.19 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.20 -- Guarantee, dated as of December 30, 1997, by Pioneer USA
relating to the $150,000,000 in aggregate principal
amount of 8 7/8% Senior Notes due 2005 and $150,000,000
in aggregate principal amount of 8 1/4% Senior Notes due
2007 issued under the indenture identified above as
Exhibit 10.15 (incorporated by reference to Exhibit 10.20
to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
110
111
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.21 -- 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
identified above as Exhibit 10.15 (incorporated by
reference to Exhibit 4.2 to Parker & Parsley's Quarterly
Report on Form 10-Q for the period ended June 30, 1995,
File No. 001-10695).
10.22 -- 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
identified above as Exhibit 10.15 (incorporated by
reference to Exhibit 1.2 to Parker & Parsley's Current
Report on Form 8-K, dated August 17, 1995, File No.
001-10695).
10.23 -- Indenture, dated January 13, 1998, between the Company
and The Bank of New York, as Trustee (incorporated by
reference to Exhibit 99.1 to the Company's and Pioneer
USA's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 14, 1998).
10.24 -- First Supplemental Indenture, dated as of January 13,
1998, among the Company, Pioneer USA, as the Subsidiary
Guarantor, and The Bank of New York, as Trustee, with
respect to the indenture identified above as Exhibit
10.23 (incorporated by reference to Exhibit 99.2 to the
Company's and Pioneer USA's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 14,
1998).
10.25 -- Form of 6.50% Senior Notes due 2008 of the Company
(incorporated by reference to Exhibit 99.3 to the
Company's and Pioneer USA's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 14,
1998).
10.26 -- Form of 7.20% Senior Notes due 2028 of the Company
(incorporated by reference to Exhibit 99.4 to the
Company's and Pioneer USA's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 14,
1998).
10.27 -- Guarantee (2008 Notes), dated as of January 13, 1998,
entered into by Pioneer USA (incorporated by reference to
Exhibit 99.5 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 14, 1998).
10.28 -- Guarantee (2028 Notes), dated as of January 13, 1998,
entered into by Pioneer USA (incorporated by reference to
Exhibit 99.6 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 14, 1998).
10.29 -- Amended and Restated Credit Facility Agreement (Primary
Facility), dated as of December 18, 1997, between the
Company, as Borrower, and NationsBank of Texas, N.A., as
Administrative Agent, CIBC Inc., as Documentation Agent,
Morgan Guaranty Trust Company of New York, as
Documentation Agent, and The Chase Manhattan Bank, as
Syndication Agent; and the other Co-Agents and lenders
named therein (incorporated by reference to Exhibit 10.1
to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
111
112
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.30* -- First Amendment to Amended and Restated Credit Facility
Agreement (Primary Facility), dated as of June 29, 1998,
by and among the Company, as Borrower, NationsBank, N.A.,
as Administrative Agent, CIBC Inc., as Documentation
Agent, Morgan Guaranty Trust Company of New York, as
Documentation Agent, The Chase Manhattan Bank, as
Syndication Agent, and the Co-Agents and other lenders
signatory thereto.
10.31 -- Amended and Restated Credit Facility Agreement (364 Day
Facility), dated as of December 18, 1997, between the
Company, as Borrower, and NationsBank of Texas, N.A., as
Administrative Agent, CIBC Inc., as Documentation Agent,
Morgan Guaranty Trust Company of New York, as
Documentation Agent, and The Chase Manhattan Bank, as
Syndication Agent; and the other Co-Agents and lenders
named therein (incorporated by reference to Exhibit 10.2
to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
10.32* -- First Amendment to Amended and Restated Credit Facility
Agreement (364 Day Facility), dated as of June 29, 1998,
by and among the Company, as Borrower, NationsBank, N.A.,
as Administrative Agent, CIBC Inc., as Documentation
Agent, Morgan Guaranty Trust Company of New York, as
Documentation Agent, The Chase Manhattan Bank, as
Syndication Agent, and the Co-Agents and other lenders
signatory thereto.
10.33 -- Credit Agreement, dated as of December 18, 1997, among
Chauvco, Canadian Imperial Bank of Commerce, as Agent,
and the other lenders named therein (incorporated by
reference to Exhibit 10.3 to the Company's Current Report
on Form 8-K, File No. 001-13245, filed with the SEC on
January 2, 1998).
10.34* -- First Amending Agreement, dated June 29, 1998, among
Pioneer Natural Resources Canada Inc. (formerly Chauvco),
Canadian Imperial Bank of Commerce, and the lenders
thereto, with respect to the Credit Agreement identified
above as Exhibit 10.33.
10.35 -- Note, dated December 22, 1997, between the Company, as
Borrower, and NationsBank of Texas, N.A., as lender
(incorporated by reference to Exhibit 10.21 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.36+ -- 1991 Stock Option Plan of Mesa (incorporated by reference
to Exhibit 10(v) to Mesa's Annual Report on Form 10-K for
the period ended December 31, 1991).
10.37+ -- 1996 Incentive Plan of Mesa (incorporated by reference to
Exhibit 10.28 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No.
333-26951).
10.38+ -- Parker & Parsley Long-Term Incentive Plan, dated February
19, 1991 (incorporated by reference to Exhibit 4.1 to
Parker & Parsley's Registration Statement on Form S-8,
Registration No. 33-38971).
10.39+ -- First Amendment to the Parker & Parsley Long-Term
Incentive Plan, dated August 23, 1991 (incorporated by
reference to Exhibit 10.2 to Parker & Parsley's
Registration Statement on Form S-1, dated February 28,
1992, Registration No. 33-46082).
10.40+ -- The Company's Long-Term Incentive Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration
Statement on Form S-8, Registration No. 333-35087).
112
113
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.41+ -- The Company's Employee Stock Purchase Plan (incorporated
by reference to Exhibit 4.1 to the Company's Registration
Statement on Form S-8, Registration No. 333-35165).
10.42* -- Amendment No. 1 to the Company's Employee Stock Purchase
Plan, dated December 9, 1998.
10.43+ -- The Company's Deferred Compensation Retirement Plan
(incorporated by reference to Exhibit 4.1 to the
Company's Registration Statement on Form S-8,
Registration No. 333-39153).
10.44+ -- Pioneer USA 401(k) Plan (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on
Form S-8, Registration No. 333-39249).
10.45+ -- Pioneer USA Matching Plan (incorporated by reference to
Exhibit 10.42 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997, File No.
001-13245).
10.46+ -- Omnibus Amendment to Nonstatutory Stock Option
Agreements, included as part of the Parker & Parsley
Long-Term Incentive Plan, dated as of November 16, 1995,
between Parker & Parsley and Named Executive Officers
identified on Schedule 1 setting forth additional details
relating to the Parker & Parsley Long-Term Incentive Plan
(incorporated by reference to Parker & Parsley's Annual
Report on Form 10-K for the year ended December 31, 1995,
File No. 001-10695).
10.47+ -- Mesa Management Severance Plan, dated April 4, 1997,
including a Schedule of Participants on Schedule A 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
Exhibit 10.29 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No.
333-26951).
10.48+ -- Severance Agreement, dated as of August 8, 1997, 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 Exhibit 10.7
to the Company's Quarterly Report on Form 10-Q for the
period ended September 30, 1997, File No. 001-13245).
10.49+ -- Indemnification Agreement, dated as of August 8, 1997,
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 identified on
Schedule I (incorporated by reference to Exhibit 10.8 to
the Company's Quarterly Report on Form 10-Q for the
period ended September 30, 1997, File No. 001-13245).
10.50 -- Purchase and Sale Agreement, dated as of October 22,
1997, between Cometra Energy, L.P., and Pioneer USA
(incorporated by reference to Exhibit 10.22 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.51 -- Combination Agreement, dated September 3, 1997, between
the Company and Chauvco (incorporated by reference to
Exhibit 2.1 to the Company's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on October 2,
1997).
10.52 -- Plan of Arrangement, as amended, under Section 186 of the
Business Corporations Act (Alberta) (incorporated by
reference to Exhibit 2.2 to the Company's Current Report
on Form 8-K, File No. 001-13245, filed with the SEC on
January 2, 1998).
113
114
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.53 -- Support Agreement, dated as of December 18, 1997, between
the Company and Pioneer Canada (incorporated by reference
to Exhibit 2.3 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on January 2,
1998).
10.54 -- Stock Purchase Agreement, dated April 26, 1996, between
Mesa and DNR (incorporated by reference to Exhibit No. 10
to Mesa's Current Report on Form 8-K filed with the SEC
on April 29, 1996).
10.55 -- "B" Contract Production Allocation Agreement, dated July
29, 1991, and effective as of January 1, 1991, between
Colorado Interstate Gas Company and Mesa Operating
Limited Partnership (incorporated by reference to Exhibit
10(r) to Mesa's Annual Report on Form 10-K for the period
ended December 31, 1991).
10.56 -- Amendment to "B" Contract Production Allocation Agreement
effective as of January 1, 1993, between Colorado
Interstate Gas Company and Mesa Operating Limited
Partnership (incorporated by reference to Exhibit 10.24
to Mesa's Registration Statement on Form S-1,
Registration No. 33-51909).
10.57 -- Amarillo Supply Agreement between Mesa Operating Limited
Partnership, Seller, and Energas Company, a division of
Atmos Energy Corporation, Buyer, dated effective January
2, 1993 (incorporated by reference to Exhibit 10.14 to
Mesa's Annual Report on Form 10-K for the period ended
December 31, 1995).
10.58+ -- 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 Parker &
Parsley), 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 Parker & Parsley's Registration Statement on
Form S-4, dated December 31, 1990, Registration No.
33-38436).
10.59+ -- 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 executives
officers of Parker & Parsley), together with a schedule
identifying substantially identical documents and setting
forth the material details in which those documents
differ form the foregoing document (incorporated by
reference to Exhibit 10.51 to Parker & Parsley's
Registration Statement on Form S-4, dated December 31,
1990, Registration No. 33-38436).
10.60+ -- Schedule identifying additional documents substantially
identical to the Amendment to Agreement of Partnership of
P&P Employees 89-B GP included as Exhibit 10.59 and
setting forth the material details in which those
documents differ from that document (incorporated by
reference to Exhibit 10.52 to Parker & Parsley's
Registration Statement on Form S-1, dated February 28,
1992, Registration No. 33-46082).
114
115
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.61+ -- 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 Parker &
Parsley), 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 Parker & Parsley's Registration Statement on
Form S-4, dated December 31, 1990, Registration No.
33-38436).
10.62+ -- 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 Parker & Parsley), 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 Parker &
Parsley's Registration Statement on Form S-1, dated
February 28, 1992, Registration No. 33-46082).
10.63+ -- 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 Parker & Parsley),
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 Parker & Parsley's Registration Statement on
Form S-1, dated February 28, 1992, Registration No.
33-46082).
10.64+ -- 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
Parker & Parsley) (incorporated by reference to Exhibit
10.67 to Parker & Parsley's Registration Statement on
Form S-1, dated February 28, 1992, Registration No.
33-46082).
10.65 -- Share Purchase Agreement, dated February 13, 1998, among
the Company, Trimac Corporation and 761795 Alberta Ltd.
(incorporated by reference to Exhibit 99.1 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on February 23, 1998).
10.66 -- Share Purchase Agreement, dated February 13, 1998, among
the Company, 398215 Alberta Ltd. and Guy J. Turcotte
(incorporated by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on February 23, 1998).
10.67 -- Option to Purchase Agreement, dated December 16, 1998, by
and among Costilla Energy, Inc. ("Costilla"), Pioneer
USA, and Pioneer Resources Producing, L.P. (incorporated
by reference to Exhibit 1 to the Company's statement on
Schedule 13D relating to the common stock of Costilla,
filed with the SEC on December 22, 1998, File No.
0-21411).
10.68 -- Purchase and Sale Agreement, dated December 16, 1998, by
and among Costilla, Pioneer USA, and Pioneer Resources
Producing, L.P. (incorporated by reference to Exhibit 2
to the Company's statement on Schedule 13D relating to
the common stock of Costilla, filed with the SEC on
December 22, 1998, File No. 0-21411).
115
116
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.69* -- Second Amended and Restated Credit Facility Agreement
(Primary Facility) by and among Pioneer Natural Resources
Company, as Borrower, NationsBank, N.A., as
Administrative Agent, CIBC Inc., as Documentation Agent,
Morgan Guarantee Trust Company of New York, as
Documentation Agent, Chase Bank of Texas, National
Association, as Syndication Agent, The Co-Agents and
certain other lenders dated as of March 19, 1999.
10.70* -- Second Amended and Restated Credit Facility Agreement
(364 Day Facility) by and among Pioneer Natural Resources
Company, as Borrower, NationsBank, N.A., as
Administrative Agent, CIBC Inc., as Documentation Agent,
Morgan Guarantee Trust Company of New York, as
Documentation Agent, Chase Bank of Texas, National
Association, as Syndication Agent, The Co-Agents and
certain other lenders dated as of March 19, 1999.
11.1* -- Statement of Computation of Earnings per Share.
21.1* -- Subsidiaries of the registrant.
23.1* -- Consent of Ernst & Young LLP.
23.2* -- Consent of KPMG LLP.
27.1* -- Financial Data Schedule.
- ---------------
* Filed herewith.
+ Executive Compensation Plan or Arrangement previously filed pursuant to Item
14(c).
REPORTS ON FORM 8-K
No reports on Form 8-K were filed by the Company during the fourth quarter
of 1998.
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.
116
117
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.
PIONEER NATURAL RESOURCES COMPANY
Date: March 23, 1999 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 President, Chief Executive March 23, 1999
- ----------------------------------------------------- Officer and Director
Scott D. Sheffield (principal executive
officer)
/s/ M. GARRETT SMITH Executive Vice President and March 23, 1999
- ----------------------------------------------------- Chief Financial Officer
M. Garrett Smith
/s/ RICH DEALY Vice President and Chief March 23, 1999
- ----------------------------------------------------- Accounting Officer
Rich Dealy
/s/ I. JON BRUMLEY Chairman of the Board March 23, 1999
- -----------------------------------------------------
I. Jon Brumley
/s/ JAMES R. BAROFFIO Director March 23, 1999
- -----------------------------------------------------
James R. Baroffio
/s/ R. HARTWELL GARDNER Director March 23, 1999
- -----------------------------------------------------
R. Hartwell Gardner
/s/ KENNETH A. HERSH Director March 23, 1999
- -----------------------------------------------------
Kenneth A. Hersh
/s/ JAMES L. HOUGHTON Director March 23, 1999
- -----------------------------------------------------
James L. Houghton
/s/ JERRY P. JONES Director March 23, 1999
- -----------------------------------------------------
Jerry P. Jones
/s/ RICHARD E. RAINWATER Director March 23, 1999
- -----------------------------------------------------
Richard E. Rainwater
/s/ CHARLES E. RAMSEY, JR. Director March 23, 1999
- -----------------------------------------------------
Charles E. Ramsey, Jr.
/s/ PHILIP B. SMITH Director March 23, 1999
- -----------------------------------------------------
Philip B. Smith
/s/ ROBERT L. STILLWELL Director March 23, 1999
- -----------------------------------------------------
Robert L. Stillwell
117
118
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
2.1 -- Amended and Restated Agreement and Plan of Merger, dated
as of April 6, 1997, by and among MESA Inc. ("Mesa"),
Mesa Operating Co. ("MOC"), MXP Reincorporation Corp. and
Parker & Parsley Petroleum Company ("Parker & Parsley")
(incorporated by reference to Exhibit 2.1 to the
Company's Registration Statement on Form S-4, dated June
27, 1997, Registration No. 333-26951).
3.1 -- Amended and 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 June
27, 1997, Registration No. 333-26951).
3.2 -- Restated Bylaws of the Company (incorporated by reference
to Exhibit 3.2 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No.
333-26951).
3.3 -- Certificate of Designations of Special Preferred Voting
Stock (incorporated by reference to Exhibit 3.3 of the
Company's Registration Statement on Form S-3,
Registration No. 333-42315, filed with the SEC on
December 17, 1997).
3.4 -- Terms and Conditions of Exchangeable Shares (incorporated
by reference to Annex F to the Definitive Joint
Management Information Circular and Proxy Statement of
the Company and Chauvco Resources Ltd. ("Chauvco"), File
No. 001-13245, filed with the SEC on November 17, 1997).
4.1 -- Form of Certificate of Common Stock, par value $.01 per
share, of the Company (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No.
333-26951).
4.2 -- Form of Certificate of Special Preferred Voting Stock
(incorporated by reference to Exhibit 4.1 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
4.3 -- Form of Certificate of Exchangeable Shares (incorporated
by reference to Exhibit 4.2 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
9.1 -- Voting and Exchange Trust Agreement, dated as of December
18, 1997, among the Company, Pioneer Natural Resources
(Canada) Ltd. ("Pioneer Canada") and Montreal Trust
Company of Canada, as Trustee (incorporated by reference
to Exhibit 2.4 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on January 2,
1998).
9.2 -- Amended and Restated Shareholders Agreement, dated as of
September 3, 1997, by and between the Company and Guy J.
Turcotte (incorporated by reference to Exhibit 2.6 to the
Company's Registration Statement on Form S-3,
Registration No. 333-42315, filed with the SEC on
December 15, 1997).
9.3 -- Shareholders Agreement, dated as of September 3, 1997, by
and among the Company, Trimac Corporation and Gendis Inc.
(incorporated by reference to Exhibit 2.4 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on October 2, 1997).
10.1 -- Indenture, dated July 2, 1996, among Pioneer USA
(formerly MOC), as Issuer, the Company, as Guarantor, and
Harris Trust and Savings Bank, as Trustee, relating to
the 11 5/8% Senior Subordinated Discount Notes due 2006
(incorporated by reference to Exhibit 4.17 to Mesa's
Quarterly Report on Form 10-Q for the period ended June
30, 1996).
119
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.2 -- First Supplemental Indenture, dated as of April 15, 1997,
among Pioneer USA (formerly MOC), as Issuer, Mesa, the
subsidiary guarantors named therein, the Company, and
Harris Trust and Savings Bank, as Trustee, with respect
to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 10.1 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 001-13245).
10.3 -- Second Supplemental Indenture, dated as of August 7,
1997, among Pioneer USA (formerly MOC), as Issuer, Mesa,
the subsidiary guarantors named therein, the Company, and
Harris Trust and Savings Bank, as Trustee, with respect
to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 001-13245).
10.4 -- Third Supplemental Indenture, dated as of December 18,
1997, among Pioneer USA, the Subsidiary Guarantors named
therein, the Company, and Harris Trust and Savings Bank,
as Trustee, with respect to the indenture identified
above as Exhibit 10.1 (incorporated by reference to
Exhibit 10.12 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on January 2,
1998).
10.5 -- Fourth Supplemental Indenture, dated as of December 30,
1997, among Pioneer USA (formerly MOC), a Delaware
corporation, the Company, a Delaware corporation, Pioneer
NewSub1, Inc., a Texas corporation, and Harris Trust and
Savings Bank, an Illinois corporation, as Trustee, with
respect to the indenture identified above as Exhibit 10.1
(incorporated by reference to Exhibit 10.13 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.6 -- Fifth Supplemental Indenture, dated as of December 30,
1997, among Pioneer NewSub1, Inc. (as successor to
Pioneer USA), a Texas corporation, the Company, a
Delaware corporation, Pioneer DebtCo., Inc., a Texas
corporation, and Harris Trust and Savings Bank, an
Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.1 (incorporated
by reference to Exhibit 10.14 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.7 -- Sixth Supplemental Indenture, dated as of December 30,
1997, among Pioneer DebtCo. Inc. (as successor to Pioneer
NewSub1, Inc.), a Texas corporation, the Company, a
Delaware corporation, and Harris Trust and Savings Bank,
an Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.1 (incorporated
by reference to Exhibit 10.15 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.8 -- Indenture, dated July 2, 1996, among Pioneer USA
(formerly MOC), as Issuer, the Company (Mesa's
successor), as Guarantor, and Harris Trust and Savings
Bank, as Trustee, relating to the 10 5/8% Senior
Subordinated Notes due 2006 (incorporated by reference to
Exhibit 4.18 to Mesa's Quarterly Report on Form 10-Q for
the period ended June 30, 1996).
10.9 -- First Supplemental Indenture, dated as of April 15, 1997,
among Pioneer USA (formerly MOC), as Issuer, Mesa, the
Subsidiary Guarantors named therein, the Company, and
Harris Trust and Savings Bank, as Trustee, with respect
to the indenture identified above as Exhibit 10.8
(incorporated by reference to Exhibit 10.3 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 001-13245).
120
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.10 -- Second Supplemental Indenture, dated as of August 7,
1997, among Pioneer USA (formerly MOC), as Issuer, Mesa,
the Subsidiary Guarantors named therein, the Company, and
Harris Trust and Savings Bank, as Trustee, with respect
to the indenture identified above as Exhibit 10.8
(incorporated by reference to Exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 001-13245).
10.11 -- Third Supplemental Indenture, dated as of December 18,
1997, among Pioneer USA, the Subsidiary Guarantors named
therein, the Company, and Harris Trust and Savings Bank,
as Trustee, with respect to the indenture identified
above as Exhibit 10.8 (incorporated by reference to
Exhibit 10.6 to the Company's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 2,
1998).
10.12 -- Fourth Supplemental Indenture, dated as of December 30,
1997, among Pioneer USA, a Delaware corporation, the
Company, a Delaware corporation, Pioneer NewSub1, Inc., a
Texas corporation, and Harris Trust and Savings Bank, an
Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.8 (incorporated
by reference to Exhibit 10.7 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.13 -- Fifth Supplemental Indenture, dated as of December 30,
1997, among Pioneer NewSub1, Inc. (as successor to
Pioneer USA), a Texas corporation, the Company, a
Delaware corporation, Pioneer DebtCo., Inc., a Texas
corporation, and Harris Trust and Savings Bank, an
Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.8 (incorporated
by reference to Exhibit 10.8 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.14 -- Sixth Supplemental Indenture, dated as of December 30,
1997, among Pioneer DebtCo, Inc. (as successor to Pioneer
NewSub1, Inc.), a Texas corporation, the Company, a
Delaware corporation, and Harris Trust and Savings Bank,
an Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.8 (incorporated
by reference to Exhibit 10.9 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.15 -- Indenture, dated April 12, 1995, between Pioneer USA
(successor to Parker & Parsley), and The Chase Manhattan
Bank (National Association), as Trustee (incorporated by
reference to Exhibit 4.1 to Parker & Parsley's Current
Report on Form 8-K, dated April 12, 1995, File No.
001-10695).
10.16 -- First Supplemental Indenture, dated as of August 7, 1997,
among Parker & Parsley, The Chase Manhattan Bank, as
Trustee, and Pioneer USA, with respect to the indenture
identified above as Exhibit 10.15 (incorporated by
reference to Exhibit 10.5 to the Company's Quarterly
Report on Form 10-Q for the period ended September 30,
1997, File No. 001-13245).
10.17 -- Second Supplemental Indenture, dated as of December 30,
1997, among Pioneer USA, a Delaware corporation, Pioneer
NewSub1, Inc., a Texas corporation, and The Chase
Manhattan Bank, a New York banking association, as
Trustee, with respect to the indenture identified above
as Exhibit 10.15 (incorporated by reference to Exhibit
10.17 to the Company's Current Report on Form 8-K, File
No. 001-13245, filed with the SEC on January 2, 1998).
121
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.18 -- Third Supplemental Indenture, dated as of December 30,
1997, among Pioneer NewSub1, Inc. (as successor to
Pioneer USA), a Texas corporation, Pioneer DebtCo, Inc.,
a Texas corporation, and The Chase Manhattan Bank, a New
York banking association, as Trustee, with respect to the
indenture identified above as Exhibit 10.15 (incorporated
by reference to Exhibit 10.18 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 2, 1998).
10.19 -- Fourth Supplemental Indenture, dated as of December 30,
1997, among Pioneer DebtCo, Inc. (as successor to Pioneer
NewSub1, Inc., as successor to Pioneer USA), a Texas
corporation, the Company, a Delaware corporation, Pioneer
USA, a Delaware corporation, and The Chase Manhattan
Bank, a New York banking association, as Trustee, with
respect to the indenture identified above as Exhibit
10.15 (incorporated by reference to Exhibit 10.19 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.20 -- Guarantee, dated as of December 30, 1997, by Pioneer USA
relating to the $150,000,000 in aggregate principal
amount of 8 7/8% Senior Notes due 2005 and $150,000,000
in aggregate principal amount of 8 1/4% Senior Notes due
2007 issued under the indenture identified above as
Exhibit 10.15 (incorporated by reference to Exhibit 10.20
to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
10.21 -- 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
identified above as Exhibit 10.15 (incorporated by
reference to Exhibit 4.2 to Parker & Parsley's Quarterly
Report on Form 10-Q for the period ended June 30, 1995,
File No. 001-10695).
10.22 -- 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
identified above as Exhibit 10.15 (incorporated by
reference to Exhibit 1.2 to Parker & Parsley's Current
Report on Form 8-K, dated August 17, 1995, File No.
001-10695).
10.23 -- Indenture, dated January 13, 1998, between the Company
and The Bank of New York, as Trustee (incorporated by
reference to Exhibit 99.1 to the Company's and Pioneer
USA's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 14, 1998).
10.24 -- First Supplemental Indenture, dated as of January 13,
1998, among the Company, Pioneer USA, as the Subsidiary
Guarantor, and The Bank of New York, as Trustee, with
respect to the indenture identified above as Exhibit
10.23 (incorporated by reference to Exhibit 99.2 to the
Company's and Pioneer USA's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 14,
1998).
10.25 -- Form of 6.50% Senior Notes due 2008 of the Company
(incorporated by reference to Exhibit 99.3 to the
Company's and Pioneer USA's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 14,
1998).
10.26 -- Form of 7.20% Senior Notes due 2028 of the Company
(incorporated by reference to Exhibit 99.4 to the
Company's and Pioneer USA's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 14,
1998).
122
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.27 -- Guarantee (2008 Notes), dated as of January 13, 1998,
entered into by Pioneer USA (incorporated by reference to
Exhibit 99.5 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 14, 1998).
10.28 -- Guarantee (2028 Notes), dated as of January 13, 1998,
entered into by Pioneer USA (incorporated by reference to
Exhibit 99.6 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 001-13245, filed with the
SEC on January 14, 1998).
10.29 -- Amended and Restated Credit Facility Agreement (Primary
Facility), dated as of December 18, 1997, between the
Company, as Borrower, and NationsBank of Texas, N.A., as
Administrative Agent, CIBC Inc., as Documentation Agent,
Morgan Guaranty Trust Company of New York, as
Documentation Agent, and The Chase Manhattan Bank, as
Syndication Agent; and the other Co-Agents and lenders
named therein (incorporated by reference to Exhibit 10.1
to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
10.30* -- First Amendment to Amended and Restated Credit Facility
Agreement (Primary Facility), dated as of June 29, 1998,
by and among the Company, as Borrower, NationsBank, N.A.,
as Administrative Agent, CIBC Inc., as Documentation
Agent, Morgan Guaranty Trust Company of New York, as
Documentation Agent, The Chase Manhattan Bank, as
Syndication Agent, and the Co-Agents and other Lenders
signatory thereto.
10.31 -- Amended and Restated Credit Facility Agreement (364 Day
Facility), dated as of December 18, 1997, between the
Company, as Borrower, and NationsBank of Texas, N.A., as
Administrative Agent, CIBC Inc., as Documentation Agent,
Morgan Guaranty Trust Company of New York, as
Documentation Agent, and The Chase Manhattan Bank, as
Syndication Agent; and the other Co-Agents and lenders
named therein (incorporated by reference to Exhibit 10.2
to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
10.32* -- First Amendment to Amended and Restated Credit Facility
Agreement (364 Day Facility), dated as of June 29, 1998,
by and among the Company, as Borrower, NationsBank, N.A.,
as Administrative Agent, CIBC Inc., as Documentation
Agent, Morgan Guaranty Trust Company of New York, as
Documentation Agent, The Chase Manhattan Bank, as
Syndication Agent, and the Co-Agents and other lenders
signatory thereto.
10.33 -- Credit Agreement, dated as of December 18, 1997, among
Chauvco, Canadian Imperial Bank of Commerce, as Agent,
and the other lenders named therein (incorporated by
reference to Exhibit 10.3 to the Company's Current Report
on Form 8-K, File No. 001-13245, filed with the SEC on
January 2, 1998).
10.34* -- First Amending Agreement, dated June 29, 1998, among
Pioneer Natural Resources Canada Inc. (formerly Chauvco),
Canadian Imperial Bank of Commerce, and the lenders
thereto, with respect to the Credit Agreement identified
above as Exhibit 10.33.
10.35 -- Note, dated December 22, 1997, between the Company, as
Borrower, and NationsBank of Texas, N.A., as lender
(incorporated by reference to Exhibit 10.21 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
123
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.36+ -- 1991 Stock Option Plan of Mesa (incorporated by reference
to Exhibit 10(v) to Mesa's Annual Report on Form 10-K for
the period ended December 31, 1991).
10.37+ -- 1996 Incentive Plan of Mesa (incorporated by reference to
Exhibit 10.28 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No.
333-26951).
10.38+ -- Parker & Parsley Long-Term Incentive Plan, dated February
19, 1991 (incorporated by reference to Exhibit 4.1 to
Parker & Parsley's Registration Statement on Form S-8,
Registration No. 33-38971).
10.39+ -- First Amendment to the Parker & Parsley Long-Term
Incentive Plan, dated August 23, 1991 (incorporated by
reference to Exhibit 10.2 to Parker & Parsley's
Registration Statement on Form S-1, dated February 28,
1992, Registration No. 33-46082).
10.40+ -- The Company's Long-Term Incentive Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration
Statement on Form S-8, Registration No. 333-35087).
10.41+ -- The Company's Employee Stock Purchase Plan (incorporated
by reference to Exhibit 4.1 to the Company's Registration
Statement on Form S-8, Registration No. 333-35165).
10.42* -- Amendment No. 1 to the Company's Employee Stock Purchase
Plan, dated December 9, 1998.
10.43+ -- The Company's Deferred Compensation Retirement Plan
(incorporated by reference to Exhibit 4.1 to the
Company's Registration Statement on Form S-8,
Registration No. 333-39153).
10.44+ -- Pioneer USA 401(k) Plan (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on
Form S-8, Registration No. 333-39249).
10.45+ -- Pioneer USA Matching Plan (incorporated by reference to
Exhibit 10.42 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1997, File No.
001-13245).
10.46+ -- Omnibus Amendment to Nonstatutory Stock Option
Agreements, included as part of the Parker & Parsley
Long-Term Incentive Plan, dated as of November 16, 1995,
between Parker & Parsley and Named Executive Officers
identified on Schedule 1 setting forth additional details
relating to the Parker & Parsley Long-Term Incentive Plan
(incorporated by reference to Parker & Parsley's Annual
Report on Form 10-K for the year ended December 31, 1995,
File No. 001-10695).
10.47+ -- Mesa Management Severance Plan, dated April 4, 1997,
including a Schedule of Participants on Schedule A 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
Exhibit 10.29 to the Company's Registration Statement on
Form S-4, dated June 27, 1997, Registration No.
333-26951).
10.48+ -- Severance Agreement, dated as of August 8, 1997, 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 Exhibit 10.7
to the Company's Quarterly Report on Form 10-Q for the
period ended September 30, 1997, File No. 001-13245).
124
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.49+ -- Indemnification Agreement, dated as of August 8, 1997,
between the Company and Scott D. Sheffield, together with
a schedule identifying substantially identical agreements
the Company and each of the Company's other directors and
named executive officers identified on Schedule I
(incorporated by reference to Exhibit 10.8 to the
Company's Quarterly Report on Form 10-Q for the period
ended September 30, 1997, File No. 001-13245).
10.50 -- Purchase and Sale Agreement, dated as of October 22,
1997, between Cometra Energy, L.P., and Pioneer USA
(incorporated by reference to Exhibit 10.22 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.51 -- Combination Agreement, dated September 3, 1997, between
the Company and Chauvco (incorporated by reference to
Exhibit 2.1 to the Company's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on October 2,
1997).
10.52 -- Plan of Arrangement, as amended, under Section 186 of the
Business Corporations Act (Alberta) (incorporated by
reference to Exhibit 2.2 to the Company's Current Report
on Form 8-K, File No. 001-13245, filed with the SEC on
January 2, 1998).
10.53 -- Support Agreement, dated as of December 18, 1997, between
the Company and Pioneer Canada (incorporated by reference
to Exhibit 2.3 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on January 2,
1998).
10.54 -- Stock Purchase Agreement, dated April 26, 1996, between
Mesa and DNR (incorporated by reference to Exhibit No. 10
to Mesa's Current Report on Form 8-K filed with the SEC
on April 29, 1996).
10.55 -- "B" Contract Production Allocation Agreement, dated July
29, 1991, and effective as of January 1, 1991, between
Colorado Interstate Gas Company and Mesa Operating
Limited Partnership (incorporated by reference to Exhibit
10(r) to Mesa's Annual Report on Form 10-K for the period
ended December 31, 1991).
10.56 -- Amendment to "B" Contract Production Allocation Agreement
effective as of January 1, 1993, between Colorado
Interstate Gas Company and Mesa Operating Limited
Partnership (incorporated by reference to Exhibit 10.24
to Mesa's Registration Statement on Form S-1,
Registration No. 33-51909).
10.57 -- Amarillo Supply Agreement between Mesa Operating Limited
Partnership, Seller, and Energas Company, a division of
Atmos Energy Corporation, Buyer, dated effective January
2, 1993 (incorporated by reference to Exhibit 10.14 to
Mesa's Annual Report on Form 10-K for the period ended
December 31, 1995).
10.58+ -- 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 Parker &
Parsley), 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 Parker & Parsley's Registration Statement on
Form S-4, dated December 31, 1990, Registration No.
33-38436).
125
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.59+ -- 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 Parker & Parsley), 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 Parker & Parsley's
Registration Statement on Form S-4, dated December 31,
1990, Registration No. 33-38436).
10.60+ -- Schedule identifying additional documents substantially
identical to the Amendment to Agreement of Partnership of
P&P Employees 89-B GP included as Exhibit 10.59 and
setting forth the material details in which those
documents differ from that document (incorporated by
reference to Exhibit 10.52 to Parker & Parsley's
Registration Statement on Form S-1, dated February 28,
1992, Registration No. 33-46082).
10.61+ -- 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 Parker &
Parsley), 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 Parker & Parsley's Registration Statement on
Form S-4, dated December 31, 1990, Registration No.
33-38436).
10.62+ -- 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 Parker & Parsley), 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 Parker &
Parsley's Registration Statement on Form S-1, dated
February 28, 1992, Registration No. 33-46082).
10.63+ -- 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 Parker & Parsley),
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 Parker & Parsley's Registration Statement on
Form S-1, dated February 28, 1992, Registration No.
33-46082).
10.64+ -- 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
Parker & Parsley) (incorporated by reference to Exhibit
10.67 to Parker & Parsley's Registration Statement on
Form S-1, dated February 28, 1992, Registration No.
33-46082).
126
EXHIBIT
NUMBER DESCRIPTION
------- -----------
10.65 -- Share Purchase Agreement, dated February 13, 1998, among
the Company, Trimac Corporation and 761795 Alberta Ltd.
(incorporated by reference to Exhibit 99.1 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on February 23, 1998).
10.66 -- Share Purchase Agreement, dated February 13, 1998, among
the Company, 398215 Alberta Ltd. and Guy J. Turcotte
(incorporated by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on February 23, 1998).
10.67 -- Option to Purchase Agreement, dated December 16, 1998, by
and among Costilla Energy, Inc. ("Costilla"), Pioneer
USA, and Pioneer Resources Producing, L.P. (incorporated
by reference to Exhibit 1 to the Company's statement on
Schedule 13D relating to the common stock of Costilla,
filed with the SEC on December 22, 1998, File No.
0-21411).
10.68 -- Purchase and Sale Agreement, dated December 16, 1998, by
and among Costilla, Pioneer USA, and Pioneer Resources
Producing, L.P. (incorporated by reference to Exhibit 2
to the Company's statement on Schedule 13D relating to
the common stock of Costilla, filed with the SEC on
December 22, 1998, File No. 0-21411).
10.69* -- Second Amended and Restated Credit Facility Agreement
(Primary Facility) by and among Pioneer Natural Resources
Company, as Borrower, NationsBank, N.A., as
Administrative Agent, CIBC Inc., as Documentation Agent,
Morgan Guarantee Trust Company of New York, as
Documentation Agent, Chase Bank of Texas, National
Association, as Syndication Agent, The Co-Agents and
certain other lenders dated as of March 19, 1999.
10.70* -- Second Amended and Restated Credit Facility Agreement
(364 Day Facility) by and among Pioneer Natural Resources
Company, as Borrower, NationsBank, N.A., as
Administrative Agent, CIBC Inc., as Documentation Agent,
Morgan Guarantee Trust Company of New York, as
Documentation Agent, Chase Bank of Texas, National
Association, as Syndication Agent, The Co-Agents and
certain other lenders dated as of March 19, 1999.
11.1* -- Statement of Computation of Earnings per Share.
21.1* -- Subsidiaries of the registrant.
23.1* -- Consent of Ernst & Young LLP.
23.2* -- Consent of KPMG LLP.
27.1* -- Financial Data Schedule.
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* Filed herewith.
+ Executive Compensation Plan or Arrangement previously filed pursuant to Item
14(c).