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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 sal