UNITED STATES
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, 1999
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
Common Stock.................................. New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES X NO
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein and will not be contained, to the best
of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. X
Aggregate market value of the voting stock held by non-affiliates
of the Registrant as of February 28, 2000..................... $721,125,899
Number of shares of Common Stock outstanding as of
February 28, 2000............................................. 100,016,779
Documents Incorporated by Reference:
(1) Proxy Statement for Annual Meeting of Shareholders to be held May 18, 2000 -
Referenced in Part III of this report.
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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
- ------------------------------ --------------------------------
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 Condition
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 10. Directors and Executive Officers
of the Registrant
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 annual report on Form 10-K (the "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.
Definitions of Oil and Gas Terms and Conventions Used Herein
Within this Annual Report on Form 10-K, the following oil and gas terms
and conventions have specific meanings: "Bbl" means a standard barrel containing
42 United States gallons; "Bcf" means one billion cubic feet; "Bcfe" means a
billion cubic feet equivalent and is a standard convention used to express oil
and gas volumes on a comparable gas equivalent basis; "BOE" means a
barrel-of-oil equivalent and is a standard convention used to express oil and
gas volumes on a comparable oil equivalent basis; "Btu" means British thermal
unit and is an energy equivalent measure of natural gas; "MBbl" means one
thousand Bbls; "MBOE" means one thousand BOE; "Mcf" means one thousand cubic
feet and is a measure of natural gas volume; "MMcf" means one million cubic
feet; "NGL" means natural gas liquid; "NYMEX" means The New York Mercantile
Exchange; "proved reserves" mean the estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions (i.e., prices and
costs as of the date the estimate is made), where prices include consideration
of changes in existing prices only to the extent that price changes are provided
for under existing contractual arrangements, but not escalations based on future
conditions; and, "PV 10 Value" means the present value of estimated future net
revenues, before income taxes, of proved reserves, determined in accordance with
the rules and regulations of the United States Securities and Exchange
Commission (the "SEC"), using prices and costs in effect at the specified date
and a 10 percent discount rate.
Natural gas equivalents are determined under the relative energy content
method by using the ratio of 6.0 Mcf of natural gas to 1.0 Bbl of oil or NGL.
With respect to information on the working interest in wells, drilling
locations and acreage, "net" wells, drilling locations and acres are determined
by multiplying "gross" wells, drilling locations and acres by Pioneer Natural
Resources Company's working interest in such wells, drilling locations or acres.
Unless otherwise specified, wells, drilling locations and acreage statistics
quoted herein represent gross wells, drilling locations or acres; and, all
dollar amounts are expressed in United States dollars.
PART I
ITEM 1. BUSINESS
General
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") during August 1997. The
Company subsequently acquired 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, during December 1997. 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, South Africa and
Gabon.
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
Spraberry oil field located in West Texas, the Hugoton gas field located in
Southwest Kansas and the West Panhandle gas field located in the Texas
Panhandle. The Spraberry, Hugoton and West Panhandle fields provide consistent
and dependable production, cash flow and ongoing development opportunities for
the Company. Complementing these areas are the exploration and development
opportunities and oil and gas production contributed by Pioneer's assets in the
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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 natural gas; and, between long- lived, dependable
production and exploration and development opportunities. Additionally, 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.
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 provides administrative, financial and management support to
United States and foreign subsidiaries that explore for, develop and produce
oil, NGL and natural gas reserves. Drilling and production operations are
principally located domestically in Texas, Kansas, Oklahoma, Louisiana, New
Mexico and offshore Gulf of Mexico, and internationally in Argentina, Canada and
South Africa.
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,
1999, the Company had 817 employees, 298 of whom 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 values. The strategies employed to achieve this mission are anchored
by the Company's long-lived Spraberry oil field and Hugoton and West Panhandle
gas fields' reserves and production. Underlying these fields are approximately
70 percent of the Company's proved oil and gas reserves which have a remaining
production life in excess of 40 years. The stable base of oil and gas production
from these fields generate operating cash flows that allow Pioneer the financial
flexibility to selectively reinvest capital in these areas to: (a) develop and
increase production from existing properties through low-risk development
drilling activities, (b) leverage cost containment opportunities to achieve
operating and technical efficiencies, and (c) pursue strategic acquisitions in
the Company's core areas that will complement the Company's existing asset base
and provide additional growth opportunities. The Company is also provided the
financial flexibility to use portions of its operating cash flows to: (a)
selectively expand into new geographic areas that feature producing properties
and provide exploration/exploitation opportunities, (b) invest in the personnel
and technology necessary to increase the Company's exploration opportunities,
and (c) enhance liquidity; allowing the Company to take advantage of future
exploration, development and acquisition opportunities. The Company is committed
to continuing to enhance shareholder investment returns through adherence to
these strategies.
Business Activities
The Company is an independent oil and gas exploration and development
company. Its purpose is to competitively and profitably explore for, develop and
produce proved oil, NGL and natural gas reserves. In so doing, the Company sells
homogenous oil, NGL and natural gas units which, except for geographic and
relatively minor qualitative differentials, cannot be significantly
differentiated from units offered for sale by the Company's competitors.
Competitive advantage is gained in the oil and gas exploration and development
industry through superior capital investment decisions, technological innovation
and managing costs.
Petroleum Industry. The petroleum industry has been characterized by
volatile oil, NGL and natural gas commodity prices and relatively stable
supplier costs during the three years ended December 31, 1999. During 1997 and
1998, weather patterns, regional economic recessions and political matters
combined to cause worldwide crude oil supplies to exceed demand. As a result,
crude oil prices declined substantially from the price levels of 1996. Also
during 1997 and 1998, but to a lesser extent, market prices for natural gas
declined. During the first quarter of 1999, the Organization of Petroleum
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Exporting Companies and certain other crude oil exporting nations announced
reductions in their planned export volumes. Those announcements, together with
the enactment of the announced reductions in export volumes, have had a positive
impact on world crude oil prices. No assurances can be given that the reductions
in export volumes or the positive trend in oil and gas commodity prices can be
sustained for an extended period of time. However, the improvements in the
commodity price environment have enhanced the Company's financial flexibility,
as compared to what existed at the end of 1998. The Company intends to monitor
closely the business environment and to continue its efforts to reduce debt and
create financial flexibility.
The Company. The Company intends to continue to reduce its outstanding
indebtedness in order to provide sufficient financial flexibility for future
exploration, development and acquisition opportunities. While the Company has
recently incurred higher levels of debt to take advantage of strategic
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 and to
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 levels during 1996 and 1995 through the application of
proceeds from the disposition of assets that the Company had identified as
non-core. 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
utilize debt to finance 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 Notes L and N 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
increased to 73 percent and 56 percent at December 31, 1998 and 1997,
respectively.
During 1998, the Company formulated and implemented measures to increase
its financial flexibility and to safeguard its net asset values. Those measures
included the enactment of an operating strategy focused on the enhancement of
core assets and the divestiture of non-core assets, the enactment of cost
containment measures and the reduction of outstanding indebtedness.
The Company's core assets are anchored by its United States investments
in the long-lived Spraberry oil field and the Hugoton and West Panhandle gas
fields (see "Mission and Strategies", above). As a result of the strategic
superiority of the Company's core assets, Pioneer was able to reduce its capital
expenditures to $179.7 million during 1999 in support of its debt reduction
efforts. The Company's budgeted 2000 capital expenditures are $250 million (see
"Drilling Activities" and "Exploratory Activities", below).
During 1999, the Company realized $420.5 million of net proceeds from the
divestiture of non-core assets and completed the asset divestiture phase of the
financial measures formulated in 1998. Net cash proceeds of $390.5 million
associated with the 1999 asset divestitures were used to reduce outstanding
indebtedness (see "Asset Divestitures" and Note K of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data").
During 1998, the Company implemented cost containment measures intended
to reduce future production and administrative costs. Those measures included
the centralization in Irving, Texas of certain operational and administrative
functions previously based in Midland, Texas; 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 $8.5
million and $33.2 million during 1999 and 1998, and realized reductions in per
BOE production costs from $3.56 in 1998 to $3.12 in 1999 and reductions in per
BOE administrative costs from $1.16 in 1998 to $.79 in 1999.
The strategic measures formulated and implemented as of December 31, 1998
have allowed the Company to reduce its outstanding indebtedness from $2.2
billion at December 31, 1998 to $1.7 billion at December 31, 1999 and realize
reductions in total costs and expenses from $959.6 million during 1998 (before
impairment of oil and gas properties and reorganization expense) to $706.8
million during 1999. The Company's debt as a percentage of total capitalization
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declined to 69 percent at December 31, 1999. During 2000, the Company intends to
improve its ratio of debt to total capitalization by limiting the Company's
capital expenditure budget to $250 million and using the excess funds generated
by operating activities to further reduce debt. The accomplishment of this
objective in 2000 will be dependent on, among other things, commodity price
levels and other factors that impact the Company's net cash provided by
operating activities.
Production. The Company focuses its efforts towards maximizing its
average daily production of oil, NGL and gas through development drilling,
production enhancement activities and acquisitions of producing properties.
Average daily oil, NGL and gas production have each increased every year since
1991, with the exception of 1999 and 1996, when average daily production
declined due to property dispositions. Comparing 1994 to 1999, average daily oil
and NGL production has increased 103 percent and average daily gas production
has increased 99 percent, while production costs per BOE have declined 38
percent. Production, price and cost information with respect to the Company's
properties for each of 1999, 1998 and 1997 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 1995 through the end of 1999, the Company
drilled 2,572 gross (1,782 net) wells, 92 percent of which were successfully
completed as productive wells, at a total cost (net to the Company's interest)
of $1.3 billion. During 1999, the Company drilled 304 gross (209 net) wells for
a total cost (net to the Company's interest) of approximately $142.0 million, 69
percent of which was spent on development wells and related facilities. The
Company's current 2000 capital expenditure budget is $250 million, which
represents a spending increase of approximately 25 percent over 1999 costs
incurred. The Company has allocated the budgeted 2000 capital expenditures as
follows: $200 million to exploitation activities, and $50 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, 1999 include proved
undeveloped and proved developed non-producing reserves of 63.2 million Bbls of
oil and NGLs and 365 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. Prior to 1999, the Company was dedicating
increasing percentages of its annual exploration/exploitation capital budgets 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 expenditures were limited to $179.7 million, of which amount $43.5
million was expended for exploration activities. The Company currently
anticipates that its 2000 exploration efforts, which comprise 20 percent of
total budgeted 2000 expenditures, will be concentrated domestically in the Gulf
of Mexico, the onshore Gulf Coast area, Argentina and South Africa. 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-core 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 reduced debt levels.
During 1999, 1998 and 1997, the Company's divestitures primarily
consisted of the sale of oil and gas properties for net proceeds of $420.5
million, $21.9 million and $115.7 million, respectively, which resulted in 1999
and 1998 net divestiture losses of $24.2 million and $445 thousand,
respectively, and a 1997 net divestiture gain of $5.0 million. The assets that
the Company divested during 1999 were comprised of non-core United States and
Canadian oil and gas properties, gas plants and other assets. United States
asset divestitures comprised 86 percent, or $361.2 million, of the total 1999
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proceeds from the divestiture of oil and gas properties; and, Canadian asset
divestitures comprised 14 percent, or $59.3 million of the total 1999 proceeds
from the divestiture of oil and gas properties. The net cash proceeds from the
1999 asset dispositions were used to reduce the Company's outstanding bank
indebtedness and, during 1998 and 1997, the net cash proceeds from asset
dispositions were used 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. See Note K of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for specific information
regarding the Company's asset divestitures.
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. The Company regularly seeks to acquire properties
that complement its operations, provide exploitation and development
opportunities and potentially provide superior returns on investment. In
addition, the Company pursues strategic acquisitions that will allow the Company
to expand into new geographical areas that feature producing properties and
provide exploration/exploitation opportunities. During 1999, the Company
acquired Argentine proved and unproved oil and gas properties that complement
its existing operations in Argentina. The Company paid $38.8 million of cash for
the Argentine assets during the fourth quarter of 1999, of which amount $2.5
million was cash consideration paid for unproved Argentine oil and gas
properties. (See "Item 2. Properties"). During 1998, the Company reduced its
emphasis on major acquisitions and 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 United States Mid Continent and offshore Gulf Coast areas, 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.
The Company regularly pursues and evaluates acquisition opportunities
(including opportunities to acquire particular oil and gas properties or related
assets; entities owning oil and gas properties or related assets; and,
opportunities to engage in mergers, consolidations or other business
combinations with such entities) and at any given time may be in various stages
of evaluating such opportunities. Such stages may take the form of internal
financial analysis, oil and gas reserve analysis, due diligence, the submission
of an indication of interest, preliminary negotiations, negotiation of a letter
of intent or negotiation of a definitive agreement.
Operations by Geographic Area
The Company operates in one industry segment. During 1999 and 1998, the
Company principally had oil and gas producing activities in the United States,
Argentina and Canada; and, had exploration activities in the United States Gulf
Coast area, Argentina, South Africa and Gabon. During 1997 and 1996, the Company
did not have significant operations in geographic areas other than the United
States. See Note O of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for geographic operating
segment information, including operating revenues, net income (loss) and assets.
Marketing of Production
General. Production from the Company's properties is marketed consistent
with industry practices. Sales prices for oil, NGL 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 1999, the Company's primary purchaser of
crude oil was Mobil Oil Corporation ("Mobil"), the Company's primary purchaser
of natural gas liquids was Williams Energy Services ("Williams") and the
Company's primary purchaser of natural gas was Anadarko Petroleum Corporation
("Anadarko"). Approximately seven percent, 11 percent and five percent of the
Company's 1999 combined oil, NGL and gas revenues were attributable to sales to
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Mobil, Williams and Anadarko, respectively. 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" and Note H 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, 1999 and related prices and
notional amounts.
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. 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, the prices
for any oil or gas that the Company produces should be equivalent to current
market prices in the geographic region.
Governmental Regulation. Oil and gas exploration and production
operations 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
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.
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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 emissions 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 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
9
<PAGE>
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.
The Company employs an environmental manager and environmental
specialists charged with monitoring environmental and 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 material 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.
Commodity Prices. 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 resumption of the significant downward
trend in oil and gas prices experienced in 1998, as compared to 1999, 1997 and
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<PAGE>
1996 would 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 borrowing base under its bank credit facility.
Drilling 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.
Unproved Properties. At December 31, 1999 and 1998, the Company had
unproved property costs of $257.6 million and $342.6 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 will be required to recognize non-cash charges in the
earnings of future periods. During 1999 and 1998, the Company recognized
non-cash impairment provisions of $17.9 million and $147.3 million,
respectively, to reduce the carrying values of its unproved properties (see Note
L of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data").
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 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.
Operation of Natural Gas Processing Plants. As of December 31, 1999, the
Company owns interests in eight natural gas processing plants and three treating
facilities. The Company operates five of the plants and all three treating
facilities. 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 or facility 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 Losses. 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,
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<PAGE>
it is not fully insured against certain of these risks, either because such
insurance is not available or because of high premium costs.
Environmental. 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 future environmental laws will not
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.
Debt Restrictions and Availability. The Company is a borrower under fixed
term senior notes and a line of credit. The terms of the Company's borrowings
under the senior notes and the line of credit specify scheduled debt repayments
and the Company's compliance with certain associated covenants and restrictions.
The Company's ability to comply with the debt repayment terms, associated
covenants and restrictions is dependent on, among other things, factors outside
the Company's direct control, such as commodity prices, interest rates and
competition for available debt financing. See Note D of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for information regarding the Company's outstanding debt and the terms
associated therewith.
Competition. The oil and gas industry is highly competitive. The Company
competes with other companies, producers and operators for acquisitions and in
the exploration, development, production and marketing of oil and gas. Some of
these competitors have substantially greater financial and other resources than
the Company. See "Item 1. Business - Competition, Markets and Regulation".
Government Regulation. The Company's business is regulated by a variety
of federal, state, local and foreign laws and regulations. There can be no
assurance that present or future regulations will not adversely affect the
Company's business and operations. See "Item 1. Business - Competition, Markets
and Regulation".
International Operations. At December 31, 1999, approximately 21 percent
of the Company's proved reserves of oil, NGLs and gas were located outside the
United States (16 percent in Argentina and five 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 United States 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.
ITEM 2. PROPERTIES
The information included in this Report about the Company's oil, NGL and
gas reserves at December 31, 1999, including PV 10 Value, are based on proved
reserves as determined 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
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<PAGE>
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 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 included
herein of future net revenues 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 1999 to any federal authority or agency, other than the SEC.
Proved Reserves
The Company's proved reserves totaled 605.5 million BOE at December 31,
1999, 676.8 million BOE at December 31, 1998 and 761.6 million BOE at December
31, 1997, representing $2.9 billion, $1.6 billion and $3.1 billion,
respectively, of PV 10 Value. The divestiture of oil and gas properties,
partially offset by upward revisions of reserve quantities as a result of
increases in commodity prices, was the primary reason for the decrease in
reserves during 1999. 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.
On a BOE basis, 81 percent of the Company's total proved reserves at
December 31, 1999 are proved developed reserves. Based on reserve information as
of December 31, 1999, and using the Company's reserve report production
information for 2000, the reserve-to-production ratio associated with the
Company's proved reserves is 13.2 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, 1999.
<TABLE>
PROVED OIL AND GAS RESERVES
1999 Average
Proved Reserves As of December 31, 1999 Daily Production (a)
-------------------------------------------- ------------------------------
Oil Natural PV 10 Oil Natural
& NGLs Gas Value & NGLs Gas
(MBbls) (MMcf) MBOE (000) (Bbls) (Mcf) BOE
-------- --------- -------- ---------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
United States.. 259,066 1,314,842 478,206 $2,337,769 55,241 290,670 103,686
Argentina...... 29,797 415,620 99,067 469,100 7,037 94,457 22,780
Canada......... 3,970 145,251 28,179 130,390 5,369 49,003 13,536
-------- --------- -------- ---------- -------- -------- --------
Total.......... 292,833 1,875,713 605,452 $2,937,259 67,647 434,130 140,002
======== ========= ======== ========= ======== ======== ========
- ----------------
</TABLE>
(a) The 1999 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
During 1999 and 1998, the Company's proved reserves declined 71.4 million
BOE and 84.8 million BOE, respectively. Proved reserve reductions during 1999
were comprised of 111.4 million BOE's from asset divestitures and 51.1 million
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BOE's of current year production.The Company added 91.1 million BOE of proved
reserves during 1999 from revisions of previous estimates (74.4 million BOE),
purchases of minerals-in-place (7.3 million BOE) and new discoveries and
extensions (9.4 million BOE). During 1998, the Company's decline in proved
reserves included 62.9 million BOE from production, 31.2 million BOE from
revisions of previous estimates and 2.5 million BOE from asset divestitures.
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 positive impact of revisions in 1999 primarily resulted from
improved commodity prices as compared to December 31, 1998 prices. The downward
revisions in 1998 relate primarily to the decline in commodity prices during
1998. The Company's reserves as of December 31, 1999 and 1998 were estimated
using NYMEX oil prices of $25.60 and $12.00 per Bbl, respectively, and NYMEX gas
prices of $2.33 and $2.00 per Mcf, respectively, resulting in realized prices of
$24.33 and $10.09 per Bbl of oil, respectively; $17.59 and $6.81 per Bbl of
NGLs, respectively; and $1.83 and $1.64 per Mcf of gas. As prices increase or
decrease in future periods, reserves will be revised upward or downward for
quantities which become economical or uneconomical to produce under the new
price assumptions.
During 1999, the Company replaced 178 percent of its annual production
(262 percent for oil and NGL's and 99 percent for gas), on a BOE basis. The
Company's 1999 reserve replacement was primarily impacted by the increase in
commodity prices. On a BOE basis, the Company's 1998 reserve replacement rate
was negative due to severe declines in commodity prices. The Company's 1997
reserve replacement rate was 1,450 percent (1,375 percent for oil and NGL's and
1,528 percent for gas). For the three-year period ended December 31, 1999, the
Company's average reserve replacement rate was 391 percent, as compared to
average replacement rates of 465 percent and 769 percent for the three year
periods ended December 31, 1998 and 1997, respectively. During 1997, the
Company's reserve replacement rate was primarily reflective of its acquisition
activities.
Finding Cost
The Company's acquisition and finding cost per BOE for 1999 and 1997 were
$2.21 and $8.23 per BOE, respectively. During 1998, the Company's acquisition
and finding costs were negative. 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 primarily impacted by 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 1997 to 1999 was
$8.36 per BOE, representing a three percent decline from the 1998 three-year
average rate of $8.65.
Description of Properties
As of December 31, 1999, the Company has operations in the United States,
Argentina and Canada, and exploration opportunities in Africa.
Domestic. The Company's domestic operations are located in the Permian
Basin, Mid-Continent and Gulf Coast regions of the United States. Approximately
70 percent of the Company's domestic proved reserves are located in the
Spraberry, Hugoton and West Panhandle fields. These mature fields generate
substantial operating cash flow and have a portfolio of low risk infill drilling
opportunities. The cash flows generated from these fields provide funding for
the Company's other development and exploration activities both domestically and
internationally. During 1999, the Company expended $81.7 million in domestic
exploration and development activities and has budgeted approximately $135
million of domestic expenditures for 2000.
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
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<PAGE>
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 that
continued into 1999, which has reduced operating expenses by 15 percent on a per
BOE basis. Average lifting costs for 1999, 1998 and 1997 were $1.70, $1.95 and
$2.01 per BOE, respectively. This cost reduction program will be continued in
the future.
During 1999, the Company placed on production 137 wells, drilled one
developmental dry hole and, at December 31, 1999, had 23 wells in progress. The
Company plans to drill approximately 75 wells in 2000.
Hugoton field. The Hugoton field in Southwest Kansas is one of the
largest producing gas fields in the continental United States. The gas is a
relatively dry gas produced from the Chase and Council Grove formations at
depths ranging from 2,700 feet to 3,000 feet. The Company's Hugoton properties
represent approximately 13 percent of the proved reserves in the field and are
located on approximately 257,000 gross acres (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 partial royalty interests in approximately 500 of those 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 1999. During 1999, the Company completed eight development
wells in the Hugoton field and, at December 31, 1999, had two development wells
in progress. The Company plans to drill approximately 35 development wells in
2000.
The Company is considering plans to submit an application to the Kansas
Corporation Commission 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.
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 has an average Btu
content of 1,300 Btu per Mcf and 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 (a subsidiary of Coastal
Corporation) 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.
During 1999, the Company placed 35 new wells on production and has
another 17 wells in progress at December 31, 1999. The Company plans to drill
approximately 45 wells in 2000.
Other domestic properties. 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 1999, the Company expended $39.2
million to drill nine development and ten exploratory wells in the Gulf Coast
area. The most significant of these wells was the Company's first deep-water
Gulf of Mexico venture at Mississippi Canyon Block 305, the Aconcagua prospect,
which was drilled to a depth of 14,000 feet. Associated therewith, the Company
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<PAGE>
announced a significant discovery during the first quarter of 1999, encountering
a hydrocarbon- bearing section of over 200 gross feet. The Company has a 25
percent working interest in the block. An appraisal well on the Aconcagua
prospect was spud during February 2000. The Company spudded its second
deep-water well during the second quarter of 1999 at Garden Banks 515, which was
unsuccessful. During the fourth quarter of 1999, the Company spud its third
deep-water exploratory well on the Devil's Tower prospect in Mississippi Canyon
block 773. The Company announced a discovery on the Devil's Tower prospect
during February 2000. The well was drilled to a total depth of 15,625 feet and
encountered a significant number of hydrocarbon-bearing sands. The Company has a
15.8 percent working interest in the discovery. An appraisal well is scheduled
to be spud on the Devil's Tower prospect during the second quarter of 2000. In
addition to the appraisal wells on the Aconcagua and Devil's Tower prospects,
the Company plans to drill four to six Gulf Coast area exploratory wells during
2000.
International. The Company's international operations are located in the
Tierra del Fuego and Neuquen Basin areas of Argentina; and the Chinchaga, Martin
Creek and Rycroft/Spirit River areas of Canada. Additionally, the Company has
entered into agreements to explore for oil and gas reserves in the African
nations of South Africa and Gabon. Approximately 16 percent and five percent of
the Company's proved reserves are located in Argentina and Canada, respectively.
Argentina. The Company's Argentine properties are primarily located in
the Austral and Neuquen basins. The Company's share of Argentine production
during 1999 averaged 22.8 MBOE's per day, or approximately 16 percent of the
Company's equivalent production. The production concession in the Austral basin
is located in Tierra del Fuego, which is the extreme southern portion of
Argentina, approximately 1,500 miles south of Buenos Aires. Crude oil, natural
gas and NGLs are produced from six separate fields in which the Company has a 35
percent working interest. Production increases are anticipated from the area
through exploitation and exploration and improving the oil and gas processing
facilities and infrastructure on the island. Currently, production is being sent
to the mainland through oil tankers and gas pipelines and exported to Chile
through pipelines.
The Company's operated production in Argentina is concentrated in the
Neuquen Basin which is located about 925 miles southwest of Buenos Aires 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 100 percent working
interests. During the fourth quarter of 1999, the Company acquired 100 percent
working interests in certain producing properties located in the core areas of
Al Sur de la Dorsal and Estacion Fernandez Oro. Both properties have significant
exploitation and exploration potential and infrastructure synergies with the
Company's current operations.
During 1999, the Company expended $75.1 million on Argentine exploration
and development activities and drilled 22 development wells and 33 exploratory
wells in Argentina. The Company plans to spend approximately $55 million on oil
and gas development and exploration opportunities in Argentina during 2000.
Canada. The Company's Canadian producing properties are located primarily
in Alberta and British Columbia, Canada. Production during 1999 averaged 13.5
MBOE's per day, or approximately 10 percent of the Company's equivalent
production. In the third quarter of 1999, the Company completed the process of
divesting 68 non-core Canadian oil and gas properties to focus efforts on its
core assets in northeast British Columbia and northwest Alberta. The core
Canadian assets are geographically concentrated, predominantly shallow gas and
more than 90 percent operated by the Company in the following areas: Chinchaga,
Martin Creek and Rycroft/Spirit River. Following the property divestitures,
fourth quarter production averaged 7.6 MBOE's per day from the core properties.
Production from the Chinchaga areas is relatively dry gas from formation
depths averaging 3,400 feet. In the Martin Creek area, production is relatively
dry gas from various reservoirs ranging from 3,700 feet to 4,300 feet. The
Rycroft/Spirit River area produces primarily oil and consists of four unitized
waterfloods producing from reservoir depths ranging from 4,400 feet to 5,000
feet. In 1999, recompletion activity in this area resulted in increased gas
production from shallow reservoirs ranging from 4,000 feet to 4,300 feet.
During 1999, the Company expended $18.9 million on Canadian exploration
and development activities and drilled 34 development wells and one successful
exploratory well primarily in the Chinchaga and Martin Creek areas. The Company
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<PAGE>
plans to drill approximately 26 development wells and one exploratory well
during 2000. The Company expects to participate in an additional nine wells
operated by other companies in the same areas. The Company plans to spend $35
million on oil and gas development and exploration opportunities in Canada
during 2000.
Africa. The Company has entered into agreements to explore in the African
nations of South Africa and Gabon. The South African agreements covers over 13
million acres along the southern coast of South Africa, generally in water
depths less than 650 feet. During 1998, five wells were drilled by the Company
in South Africa, of which two discovered reserves. During 1999, the Company
performed and analyzed seismic studies necessary for the analysis, ranking and
timing of prospects in South Africa and Gabon. In doing so, the Company incurred
$3.7 million of seismic costs in South Africa and Gabon during 1999. During
2000, the Company plans to spend approximately $25 million on exploration
opportunities in South Africa and Gabon. The Company expects to spud an
appraisal well in the Sable field of South Africa during March 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, 1999, 1998 and 1997.
Because of normal production declines, increased or decreased drilling
activities and the effects of past and future acquisitions or divestitures, the
historical information presented below should not be interpreted as indicative
of future results.
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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, 1999, 1998 and 1997.
<TABLE>
PRODUCTION, PRICE AND COST DATA (a)
Year Ended December 31,
---------------------------------------------------------------------------------------------------------------
1999 1998 1997
--------------------------------------- -------------------------------------- ----------------------------
United United United
States Argentina Canada Total States Argentina Canada Total States Argentina Total
------- --------- ------ ------- ------- --------- ------ ------- ------- --------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Production information:
Annual production:
Oil (MBbls).... 11,448 2,352 1,654 15,454 15,167 3,072 3,315 21,554 13,470 148 13,618
NGLs (MBbls)... 8,714 217 306 9,237 10,160 228 281 10,669 4,267 - 4,267
Gas (MMcf)..... 106,094 34,477 17,886 158,457 137,741 26,801 19,371 183,913 104,868 - 104,868
Total (MBOE)... 37,845 8,315 4,941 51,101 48,284 7,767 6,824 62,875 35,215 148 35,363
Average daily
production:
Oil (Bbls)..... 31,366 6,443 4,530 42,339 41,555 8,415 9,082 59,052 36,903 406 37,309
NGLs (Bbls).... 23,875 594 839 25,308 27,835 626 770 29,231 11,691 - 11,691
Gas (Mcf)...... 290,670 94,457 49,003 434,130 377,373 73,427 53,072 503,872 287,309 - 287,309
Total (BOE).... 103,686 22,780 13,536 140,002 132,285 21,279 18,697 172,261 96,479 406 96,885
Average prices:
Oil (per Bbl).. $ 15.03 $ 18.41 $ 13.28 $ 15.36 $ 13.96 $ 11.00 $ 10.96 $ 13.08 $ 18.50 $ 19.68 $ 18.51
NGLs (per Bbl). $ 11.61 $ 11.30 $ 12.62 $ 11.64 $ 8.86 $ 9.83 $ 9.54 $ 8.90 $ 12.59 $ - $ 12.59
Gas (per Mcf).. $ 2.17 $ 1.10 $ 1.82 $ 1.90 $ 2.01 $ 1.09 $ 1.45 $ 1.82 $ 2.20 $ - $ 2.20
Revenue (per BOE)$ 13.28 $ 10.07 $ 11.81 $ 12.62 $ 11.99 $ 8.40 $ 9.83 $ 11.32 $ 15.16 $ 19.68 $ 15.18
Average costs:
Production costs
(per BOE):
Lease operating
expense....... $ 2.71 $ 2.04 $ 3.02 $ 2.63 $ 3.04 $ 2.57 $ 3.56 $ 3.04 $ 3.01 $ 5.47 $ 3.02
Production taxes. .49 .16 - .39 .50 .15 - .40 .81 .19 .81
Workover....... .09 - .34 .10 .14 - .10 .12 .25 - .25
------ ------ ------ ------ ------ ------ ------ ------ ------ ------ ------
Total......... $ 3.29 $ 2.20 $ 3.36 $ 3.12 $ 3.68 $ 2.72 $ 3.66 $ 3.56 $ 4.07 $ 5.66 $ 4.08
Depletion expense
(per BOE)..... $ 4.06 $ 4.68 $ 5.18 $ 4.27 $ 4.96 $ 5.42 $ 5.95 $ 5.13 $ 5.77 $ 8.70 $ 5.78
- ---------------
</TABLE>
(a) These amounts represent the Company's historical results from operations
without making pro forma adjustments for any acquisitions, divestitures or
drilling activity that occurred during the respective years.
18
<PAGE>
Productive Wells. The following table sets forth the number of productive
oil and gas wells attributable to the Company's properties as of December 31,
1999, 1998 and 1997.
<TABLE>
PRODUCTIVE WELLS(a)
Gross Productive Wells Net Productive Wells
------------------------- -------------------------
Oil Gas Total Oil Gas Total
------ ------ ------- ------ ------ -------
<S> <C> <C> <C> <C> <C> <C>
Year ended December 31, 1999:
United States................... 3,835 2,244 6,079 2,558 1,736 4,294
Argentina....................... 514 199 713 376 142 518
Canada.......................... 157 196 353 66 135 201
------ ------ ------- ------ ------ -------
Total........................ 4,506 2,639 7,145 3,000 2,013 5,013
====== ====== ======= ====== ====== =======
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
====== ====== ======= ====== ====== =======
- ---------------
</TABLE>
(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, 1999, the Company owned interests in 24 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, 1999.
LEASEHOLD ACREAGE
<TABLE>
Developed Acreage Undeveloped Acreage
----------------------- ------------------------ Royalty
Gross Acres Net Acres Gross Acres Net Acres Acreage
----------- --------- ----------- ---------- --------
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1999:
United States.................. 1,063,660 686,571 727,417 546,192 303,598
Argentina...................... 676,000 278,000 1,350,000 952,000 -
Canada......................... 135,000 88,000 701,000 575,000 -
South Africa and Gabon......... - - 13,813,937 13,513,937 -
----------- --------- ----------- ---------- --------
Total.......................... 1,874,660 1,052,571 16,592,354 15,587,129 303,598
=========== ========= =========== ========== ========
</TABLE>
Drilling Activities. The following table sets forth the number of gross
and net productive and dry wells in which the Company had an interest that were
drilled and completed during the years ended December 31, 1999, 1998, and 1997.
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.
19
<PAGE>
DRILLING ACTIVITIES
Gross Wells Net Wells
------------------------ ------------------------
Year Ended December 31, Year Ended December 31,
------------------------ ------------------------
1999 1998 1997 1999 1998 1997
------ ------ ------ ------ ------ ------
United States:
Productive wells:
Development............ 199 385 483 131.3 285.9 341.2
Exploratory............ 7 18 38 4.6 13.4 23.8
Dry holes:
Development............ 1 13 18 .8 8.8 8.8
Exploratory............ 7 5 46 2.7 3.0 30.3
------ ----- ----- ------ ------ ------
214 421 585 139.4 311.1 404.1
------ ----- ----- ------ ------ ------
Argentina:
Productive wells:
Development............ 19 41 4 16.6 39.1 .6
Exploratory............ 25 11 1 24.1 10.6 .1
Dry holes:
Development............ 3 5 - 3.0 5.0 -
Exploratory............ 8 11 1 6.5 9.7 .1
------ ----- ----- ------ ------ ------
55 68 6 50.2 64.4 .8
------ ----- ----- ------ ------ ------
Canada:
Productive wells:
Development............ 34 54 - 18.8 37.1 -
Exploratory............ - 10 - - 7.2 -
Dry holes:
Development............ - 6 - - 5.4 -
Exploratory............ 1 4 - .3 3.0 -
------ ----- ----- ------ ------ ------
35 74 - 19.1 52.7 -
------ ----- ----- ------ ------ ------
Other foreign:
Productive wells:
Development............ - - - - - -
Exploratory............ - 2 - - .7 -
Dry holes:
Development............ - - - - - -
Exploratory............ - 3 1 - 1.7 .4
------ ----- ----- ------ ------ ------
- 5 1 - 2.4 .4
------ ----- ----- ------ ------ ------
Total................ 304 568 592 208.7 430.6 405.3
====== ===== ===== ====== ====== ======
Success ratio(a)......... 93% 92% 89% 94% 92% 90%
- ---------------
(a) Represents those wells that were successfully completed as productive
wells.
The following table sets forth information about the Company's wells
that were in progress at December 31, 1999.
Gross Wells Net Wells
----------- ---------
United States:
Development.................... 45 26.9
Exploratory.................... 1 .1
------ ------
46 27.0
------ ------
Argentina:
Development.................... 2 2.0
Exploratory.................... 4 3.6
------ ------
6 5.6
------ ------
Canada:
Development.................... 3 2.6
Exploratory.................... - -
------ ------
3 2.6
------ ------
Total....................... 55 35.2
====== ======
20
<PAGE>
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings, which are described
under "Legal actions" in Note G 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not submit any matters to a vote of security holders
during the fourth quarter of 1999.
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
--------- --------- --------------
1999
Fourth quarter.................... $11 1/2 $ 7 5/8 -
Third quarter..................... $12 13/16 $ 9 3/8 -
Second quarter.................... $13 3/16 $ 7 1/16 -
First quarter..................... $ 9 3/4 $ 5 -
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
On February 28, 2000, the last reported sales price of the Company's
common stock, as reported in the New York Stock Exchange composite transactions,
was $7-11/16 per share.
As of February 28, 2000, the Company's common stock was held by
approximately 33,100 holders of record.
The Company's Board of Directors elected to discontinue cash dividends in
1999 and future years.
21
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data for the Company should
be read in conjunction with "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Company's Consolidated
Financial Statements, related notes and other financial information included in
"Item 8. Financial Statements and Supplementary Data".
<TABLE>
Year Ended December 31,
----------------------------------------------------
1999 1998 1997(a) 1996 1995
-------- -------- -------- -------- --------
(in millions, except per share data)
<S> <C> <C> <C> <C> <C>
Statement of Operations Data:
Revenues:
Oil and gas.............................. $ 644.6 $ 711.5 $ 536.8 $ 396.9 $ 375.7
Natural gas processing................... - - - 23.8 33.2
Gas marketing............................ - - - - 76.8
Interest and other (b)................... 89.7 10.4 4.3 17.5 11.4
Gain (loss) on disposition of assets, net (24.2) (.4) 4.9 97.1 16.6
------- ------- ------- ------- -------
710.1 721.5 546.0 535.3 513.7
------- ------- ------- ------- -------
Costs and expenses:
Oil and gas production................... 159.5 223.5 144.2 110.3 130.9
Natural gas processing................... - - - 12.5 25.9
Gas marketing............................ - - - - 75.7
Depletion, depreciation and amortization. 236.1 337.3 212.4 112.1 159.1
Impairment of properties and facilities.. 17.9 459.5 1,356.4 - 130.5
Exploration and abandonments............. 66.0 121.9 77.2 23.0 27.5
General and administrative............... 40.2 73.0 48.8 28.4 37.4
Reorganization........................... 8.5 33.2 - - -
Interest................................. 170.3 164.3 77.5 46.2 65.4
Other (c)................................ 34.7 39.6 7.1 2.5 11.3
------- ------- ------- ------- -------
733.2 1,452.3 1,923.6 335.0 663.7
------- ------- ------- ------- -------
Income (loss) before income taxes and
extraordinary item....................... (23.1) (730.8) 1,377.6) 200.3 (150.0)
Income tax benefit (provision)............. .6 (15.6) 500.3 (60.1) 45.9
------- ------- ------- ------- -------
Income (loss) before extraordinary item.... (22.5) (746.4) (877.3) 140.2 (104.1)
Extraordinary item......................... - - (13.4) - 4.3
------- ------- ------- ------- -------
Net income (loss).......................... $ (22.5) $ (746.4) $ (890.7) $ 140.2 $ (99.8)
======= ======= ======= ======= =======
Income (loss) before extraordinary item
per share:
Basic.................................. $ (.22) $ (7.46) $ (16.88) $ 3.95 $ (2.96)
======= ======= ======= ======= =======
Diluted................................ $ (.22) $ (7.46) $ (16.88) $ 3.47 $ (2.96)
======= ======= ======= ======= =======
Net income (loss) per share:
Basic.................................... $ (.22) $ (7.46) $ (17.14) $ 3.95 $ (2.84)
======= ======= ======= ======= =======
Diluted.................................. $ (.22) $ (7.46) $ (17.14) $ 3.47 $ (2.84)
======= ======= ======= ======= =======
Dividends per share ....................... $ - $ .10 $ .10 $ .10 $ .10
======= ======= ======= ======= =======
Weighted average shares outstanding........ 100.3 100.1 52.0 35.5 35.1
Statement of Cash Flows Data:
Cash flows from operating activities....... $ 255.2 $ 314.1 $ 228.2 $ 230.1 $ 156.6
Cash flows from investing activities....... $ 199.0 $ (517.0) $ (341.2) $ 13.7 $ (52.6)
Cash flows from financing activities....... $ (479.1) $ 190.9 $ 166.0 $ (245.4) $ (107.9)
Balance Sheet Data (as of December 31):
Working capital (deficit) (d).............. $ (13.7) $ (324.8) $ 46.6 $ 26.1 $ 31.5
Property, plant and equipment, net......... $2,503.0 $3,034.1 $3,515.8 $1,040.4 $1,121.7
Total assets............................... $2,929.5 $3,481.3 $4,153.0 $1,199.9 $1,319.2
Long-term obligations...................... $1,914.5 $2,101.2 $2,124.0 $ 329.0 $ 603.2
Preferred stock of subsidiary.............. $ - $ - $ - $ 188.8 $ 188.8
Total stockholders' equity................. $ 774.6 $ 789.1 $1,548.8 $ 530.3 $ 411.0
</TABLE>
- ---------------
(a) Includes amounts relating to the acquisition of Mesa and Chauvco in August
and December 1997, respectively.
(b) 1999 includes $41.3 million of option fees and $30.2 million of income
associated with an excise tax refund (see Note J of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and
Supplementary Data").
(c) 1999 and 1998 include non-cash mark-to-market charges for changes in the
fair values of non-hedge financial instruments of $27.0 million and $21.2
million, respectively (see Notes C and H of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary
Data").
(d) The 1998 working capital deficit includes $306.5 million of current
maturities of long-term debt (see Note D of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary
Data").
22
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
1999 Performance
The Company's performance during 1999 was highlighted by significant
improvements in oil, NGL and natural gas commodity prices; by its successful
execution of operating measures focused on the enhancement of core assets and
the divestiture of non-core assets, the continuation of cost containment
measures implemented during 1998 and the reduction of outstanding indebtedness,
and, by favorable test results from the Company's deep-water Gulf of Mexico
exploration drilling program.
During 1999, the Company reduced its capital expended on oil and gas
property additions to $179.7 million, as compared to 1998 and 1997 oil and gas
property expenditures of $507.3 million and $428.6 million, respectively (see
"Capital Commitments, Capital Resources and Liquidity", below). The Company also
realized $420.5 million of proceeds from the divestiture of non-core United
States and Canadian oil and gas properties, gas plants and other assets during
1999 (see "Asset Divestitures", below and Note K of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data"). The net cash proceeds from the asset divestitures were used, together
with net cash provided from operating activities, to reduce outstanding
indebtedness by $429.3 million during 1999 (see "Liquidity", below and Note D of
Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data").
The Company reported a net loss of $22.5 million ($.22 per share) for the
year ended December 31, 1999, as compared to net losses of $746.4 million ($7.46
per share) and $890.7 million ($17.14 per share) for the years ended December
31, 1998 and 1997, respectively. In comparison to 1998, the Company's 1999
results were positively impacted by improved commodity prices, a $79.2 million
increase in interest and other income, the results of cost containment measures,
reductions in outstanding indebtedness and significant reductions in provisions
for the impairment of oil and gas properties; and, were negatively impacted by
declines in production volumes due to asset divestitures, net losses recognized
on asset divestitures and non-cash mark-to-market charges recognized on
non-hedge derivative contracts.
Commodity prices and production volumes. During 1999, crude oil, NGL and
natural gas prices increased substantially from their depressed 1998 levels. The
average prices realized by the Company during 1999, including the effects of oil
and gas price hedges, were $15.36 per Bbl of oil, $11.64 per Bbl of NGL's and
$1.90 per Mcf of natural gas; as compared to average realized prices for oil,
NGL's and natural gas of $13.08 per Bbl, $8.90 per Bbl and $1.82 per Mcf,
respectively, during 1998; and, $18.51 per Bbl, $12.59 per Bbl and $2.20 per
Mcf, respectively, during 1997. The effects of price volatility on the Company's
results of operations and net cash generated by operating activities during 1999
and 1998 were mitigated by the results of oil and gas price hedges and changes
in production volumes. Primarily as a result of asset divestitures, the
Company's 1999 total production of oil, NGL and natural gas declined to 51,101
MBOE, as compared to total production of 62,875 MBOE and 35,363 MBOE, during
1998 and 1997, respectively.
Asset divestitures. During 1999, 1998 and 1997, the Company's asset
divestitures generated net proceeds to the Company of $420.5 million, $21.9
million and $115.7 million, respectively, which resulted in 1999 and 1998 net
losses of $24.2 million and $445 thousand, respectively, and a 1997 net gain of
$5.0 million. The Company's 1999 asset divestitures were comprised of non-core
United States and Canadian oil and gas properties, gas plants and other assets.
The net cash proceeds from the 1999 asset divestitures were used to reduce the
Company's outstanding indebtedness, while the net cash proceeds from the 1998
and 1997 asset divestitures were used to provide funding for a portion of the
Company's capital expenditures. See Note K of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" and
"Results of Operations", below, for additional information regarding the
Company's asset divestitures.
Cost containment. During 1999 and 1998, the Company executed a number of
cost containment measures. Such measures included the centralization of certain
operating and administrative functions in Irving, Texas that were previously
based in Midland, Texas, the closings of its regional offices in Oklahoma City,
Oklahoma, Corpus Christi, Texas and Houston, Texas; the termination of 350
23
<PAGE>
employees, including several officer positions; and reductions in salaries among
senior officers. Those initiatives increased operational and administrative
efficiencies by reducing production costs and general and administrative costs
per BOE during 1999 to $3.12 and $.79, respectively, from $3.56 and $1.16,
respectively, during 1998. The Company intends to sustain these initiatives
during 2000 and the foreseeable future. See Note M of Notes to Consolidated
Financial Statement included in "Item 8. Financial Statements and Supplementary
Data" for specific discussions and disclosures regarding the Company's
reorganization provisions.
Net cash provided by operating activities. Net cash provided by operating
activities was $255.2 million for the year ended December 31, 1999, as compared
to $314.1 million for the year ended December 31, 1998 and $228.2 million for
the year ended December 31, 1997. The decrease in net cash provided by operating
activities during 1999 as compared to 1998 is primarily attributable to declines
in production volumes, increases in operating receivables and repayments of
operating payables, partially offset by increases in oil, NGL and natural gas
commodity prices and reductions in operating costs. During 1998, additional cash
flow was generated due to the increased production realized from the acquired
Mesa and Chauvco properties, offset partially by declining commodity prices and
increased costs and expenses.
Total debt and book capitalization. Total debt was reduced to $1.7
billion as of December 31, 1999, as compared to total debt of $2.2 billion and
$1.9 billion, respectively, at December 31, 1998 and 1997. The Company strives
to maintain its outstanding indebtedness at a moderate level in order to provide
sufficient financial flexibility to react to future opportunities. The Company's
total book capitalization at December 31, 1999 was $2.5 billion, consisting of
total debt of $1.7 billion and stockholders' equity of $.8 billion.
Consequently, the Company's debt to total capitalization decreased to 69 percent
at December 31, 1999 from 73 percent at December 31, 1998.
Exploration and drilling results. During 1999, the Company completed
drilling 304 gross wells (209 net wells), of which 284 gross wells (195 net
wells) were successfully placed on production, representing a 93 percent success
rate. See "Item 2. Properties" for information regarding the Company's reserve
replacement, finding costs, property descriptions and drilling activities.
The Company's 1999 exploratory drilling was focused in the United States
Gulf of Mexico, Argentina and Canada. The Company completed drilling 48 gross
exploratory wells (38 net wells) during 1999, of which 32 gross exploratory
wells (29 net wells) successfully discovered proved oil, NGL and gas reserves,
representing a 67 percent success rate. The Company's most significant discovery
during 1999 was its first deep-water Gulf of Mexico venture at Mississippi
Canyon Block 305, the Aconcagua prospect, that was drilled to a total depth of
14,000 feet and encountered a hydrocarbon-bearing section of over 200 gross
feet. The Company has a 25 percent working interest in the block. An appraisal
well on the Aconcagua prospect was spud during February 2000. The Company
spudded its second deep-water Gulf of Mexico well during the second quarter of
1999, which was unsuccessful. During the fourth quarter of 1999, the Company
spud its third deep-water exploratory well on the Devil's Tower prospect in
Mississippi Canyon block 773. The Company announced a discovery on the Devil's
Tower prospect during February 2000. The well was drilled to a total depth of
15,625 feet and encountered a significant number of hydrocarbon-bearing sands.
The Company has a 15.8 percent working interest in the discovery. An appraisal
well is scheduled to be spud on the Devil's Tower prospect during the second
quarter of 2000. In addition to the appraisal wells on the Aconcagua and Devil's
Tower prospects, the Company plans to drill four to six Gulf Coast area
exploratory wells during 2000.
The Company also plans to drill exploratory wells in Argentina, Canada
and South Africa during 2000. During 1999, the Company drilled 33 gross
exploratory wells (31 net wells) in Argentina, with a 76 percent success rate.
In South Africa, the Company has scheduled three exploratory wells to be spud
during 2000, of which one is an appraisal well on the Company's Sable oil
discovery.
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.
24
<PAGE>
2000 Outlook
Commodity prices. The Company's results of operations and financial
condition in 2000 are expected to be significantly affected by the rising trend
in commodity prices that has occurred as a result of decreases in oil and gas
supplies relative to demand for those commodities. The most significant of those
factors has been the decrease in crude oil exports during 1999 by members of the
Organization of Petroleum Exporting Countries ("OPEC") and other crude oil
exporting nations. During 2000, the favorable commodity price environment
presently impacting the oil and gas industry may continue; however the Company
is continuing its debt reduction and cost containment measures to protect its
net asset values from a return to a less favorable commodity price environment.
If OPEC and the other crude oil exporting nations were to increase crude oil
supplies relative to demand, crude oil prices could again begin to decline,
which could have a significant negative impact on the Company's results of
operations and net cash provided or used by operating activities, and could
result in additional impairment of the carrying values of the Company's oil and
gas properties and deferred tax assets.
Capital expenditures. During 2000, the Company plans to limit capital
expended for oil and gas property additions to approximately $250 million, of
which approximately $50 million has been budgeted for exploration expenditures
and $200 million has been budgeted for exploitation projects. Pioneer's
long-lived reserves and dependable production in the Hugoton and West Panhandle
gas fields and Spraberry oil field allow the Company the flexibility necessary
to make significant changes in its capital allocation plans without
significantly impacting near term production volumes. The Company's 2000
exploitation budget is allocated approximately 55 percent to the United States,
25 percent to Argentina and 20 percent to Canada. Exploration drilling will be
concentrated in the Gulf of Mexico, the onshore Gulf Coast area, Argentina and
South Africa. The Company has budgeted exploratory expenditures of approximately
$25 million each for the United States Gulf Coast area and international areas
during 2000. During 2000, the Company will continue to use the excess of cash
provided by operating activities over capital expenditures for oil and gas
producing activities to reduce outstanding indebtedness.
Results of Operations
Oil and gas revenues. Revenues from oil and gas operations totaled $644.6
million in 1999, $711.5 million in 1998 and $536.8 million in 1997, representing
a nine percent decrease from 1998 to 1999 and a 33 percent increase from 1997 to
1998. The revenue decrease from 1998 to 1999 is reflective of a 19 percent
decrease in BOE production, partially offset by price increases of 17 percent,
31 percent and four percent, respectively, for oil, NGL and natural gas. The
revenue increase from 1997 to 1998 is reflective of a 78 percent increase in BOE
production, offset by a 29 percent, 29 percent and 17 percent decline in prices
for oil, NGLs and gas, respectively, from 1997 to 1998.
Year Ended December 31,
------------------------------
1999 1998 1997
-------- -------- --------
Total production:
Oil (MBbls)................................ 15,454 21,554 13,618
NGLs (MBbls)............................... 9,237 10,669 4,267
Gas (MMcf)................................. 158,457 183,913 104,868
Total (MBOE)............................... 51,101 62,875 35,363
Average daily production:
Oil (Bbls)................................. 42,339 59,052 37,309
NGLs (Bbls)................................ 25,308 29,231 11,691
Gas (Mcf).................................. 434,130 503,872 287,309
Average prices:
Oil (per Bbl).............................. $ 15.36 $ 13.08 $ 18.51
NGL (per Bbl).............................. $ 11.64 $ 8.90 $ 12.59
Gas (per Mcf).............................. $ 1.90 $ 1.82 $ 2.20
Percentage annual price increase (decrease):
Oil........................................ 17 (29) (7)
NGL........................................ 31 (29) N/A
Gas........................................ 4 (17) (3)
On a BOE basis, production declined by 19 percent for the year ended
December 31, 1999, as compared to the same period in 1998. The decline in
production was primarily attributable to asset divestitures, but also reflects
25
<PAGE>
the deferral of oil well completions at the end of 1998 and beginning of 1999
until oil prices recovered, and normal well production declines. Excluding the
production associated with 1999 and 1998 asset divestitures, production declined
by nine percent during the year ended December 31, 1999, as compared to the same
period in 1998.
Production volumes for 1998 increased by 78 percent from 35,363 MBOE to
62,875 MBOE. This increase was primarily reflective of a full year of production
realized from the properties acquired from Mesa and Chauvco, but also was
impacted favorably by the Company's exploration and exploitation projects. The
properties acquired from Mesa and Chauvco contributed 97 percent of the
production growth from 1997 to 1998. Excluding the production associated with
the Mesa and Chauvco properties and other properties sold during 1998 and 1997,
production increased nine percent during 1998, as compared to 1997, on a BOE
basis.
Hedging activities
The oil and gas prices that the Company reports are based on the market
price received for the commodities adjusted by the results of the Company's
hedging activities. The Company utilizes commodity derivative contracts (swaps,
futures and options) in order to (i) reduce the effect of the volatility of
price changes on the commodities the Company produces and sells, (ii) support
the Company's annual capital budgeting and expenditure plans and (iii) lock in
prices to protect the economics related to certain capital projects.
Crude oil. All material purchase contracts governing the Company's oil
production are tied directly or indirectly to NYMEX prices. The average oil
price per Bbl that the Company reports includes the effects of oil quality,
gathering and transportation costs and the net effect of the oil hedges. The
Company's average realized prices for physical oil sales (excluding hedge
results) for the years ended December 31, 1999, 1998 and 1997 were $16.23 per
Bbl, $11.93 per Bbl and $19.09 per Bbl, respectively. During the year ended
December 31, 1999, the Company recorded a $13.4 million net decrease to oil
revenues as a result of its oil price hedges. The Company recorded a net
increase to oil revenues of $24.8 million and a net decrease to oil revenues of
$7.9 million for the years ended December 31, 1998 and 1997, respectively, as a
result of its oil price hedges.
Natural gas liquids. During 1999 and 1998, the Company did not enter into
natural gas liquids price hedge contracts. During 1997, the Company employed a
policy of hedging natural gas liquids based on actual product prices in order to
mitigate some of the volatility associated with NYMEX pricing. The Company's
average realized prices for physical natural gas liquids sales (excluding hedge
results) for the years ended December 31, 1999, 1998 and 1997 were $11.64 per
Bbl, $8.90 per Bbl and $12.61 per Bbl, respectively. During 1997, the Company
recorded a net decrease to natural gas liquids revenue of $77,600 as a result of
natural gas liquids hedges.
Natural gas. The Company employs a policy of hedging gas production based
on the index price upon which the gas is actually sold in order to mitigate the
basis risk between NYMEX prices and actual index prices. The average gas price
per Mcf that the Company reports includes the effects of Btu content, gathering
and transportation costs, gas processing and shrinkage and the net effect of the
gas hedges. The Company's average realized prices for physical gas sales
(excluding hedge results) for the years ended December 31, 1999, 1998 and 1997
were $1.84 per Mcf, $1.80 per Mcf and $2.41 per Mcf, respectively. For the year
ended December 31, 1999, the Company recorded a net increase to gas revenues of
$9.4 million as a result of its gas price hedges. The Company recorded a net
increase to gas revenues of $3.6 million and a net decrease of $21.9 million for
the years ended December 31, 1998 and 1997, respectively, as a result of its gas
price hedges.
See Note H of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for information concerning
the Company's open hedge positions at December 31, 1999 and the related prices
to be realized.
Interest and other revenue. The Company recorded interest and other
income totaling $89.7 million, $10.5 million and $4.3 during 1999, 1998 and
1997, respectively. The significant increase in interest and other income during
1999 is primarily attributable to non-recurring option fees and excise tax
refunds recognized by the Company during 1999. In December 1998, the Company
announced the sale of an exclusive and irrevocable option to a third party to
purchase certain oil and gas properties and other assets of the Company. In
consideration for the option, the third party paid an option fee of $41.3
million to the Company, consisting of $29.3 million of cash and the third
party's common stock that was then valued at $12.0 million. The third party's
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option lapsed by its terms during the first quarter of 1999. During the second
quarter of 1999, the Company entered into a purchase and sale agreement with the
third party that was not completed as specified by the terms of the agreement
and, as a result thereof, the Company received liquidated damages of additional
shares of the third party's common stock valued at $.5 million. During 1999, the
Company recognized other revenue of $41.8 million as a result of the
transactions with the third party. The Company also received a $30.2 million
refund of excise taxes during 1999. Due to the uncertainty surrounding the
collectability of this refund, the Company was not carrying it as an asset.
Accordingly, the Company recognized the tax refund as other revenue during 1999.
Gain (loss) on disposition of assets. During 1998, the Company announced
measures to increase its financial flexibility and to safeguard net asset
values. Those measures included the enactment of an operating strategy focused
on the enhancement of core assets and the divestiture of non-core assets,
continuation of cost containment measures and the reduction of outstanding
indebtedness. During 1999, the Company completed the asset divestiture phase of
the measures referred to above. As a result, the Company realized net divestment
proceeds from asset divestitures of $420.5 million during 1999 and recorded an
associated net loss on disposition of assets of $24.2 million. The net cash
proceeds from the 1999 asset divestitures were used to reduce outstanding
indebtedness (see Note K of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data").
Production costs. Total production costs per BOE decreased in 1999 and
1998 by approximately 12 percent and 13 percent, respectively. The primary
component of production costs, lease operating expense, declined by 13 percent
in 1999 and remained constant in 1998. Workover costs declined by 20 percent and
52 percent, respectively, in 1999 and 1998. These costs represent the majority
of the oil and gas property operating expenses over which the Company has
control and the costs on which the Company has focused its reduction efforts.
Production taxes, which are correlated with volumes and prices, declined three
percent in 1999 and 51 percent in 1998, reflecting the declines in volumes
during 1999 and commodity prices during 1998. The operating margins from the
Company's gas plants (i.e., third party processing revenues less processing
costs and expenses) are included in oil and gas production costs, specifically
lease operating expense, which resulted in decreases in lease operating expense
per BOE during 1999 and 1997 of $.11 and $.07, respectively, and an increase in
lease operating expense per BOE of $.05 during 1998. The reductions in lease
operating expense during the years ended December 31, 1999 and 1998 are
primarily due to the cost containment measures initiated by the Company during
1998, and to the divestment of high operating cost properties during 1999 (see
"1999 Performance", above, and Note K of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data").
Year Ended December 31,
---------------------------
1999 1998 1997
------- ------- -------
(per BOE)
Lease operating expense................... $ 2.63 $ 3.04 $ 3.02
Production taxes.......................... .39 .40 .81
Workover costs............................ .10 .12 .25
------ ------ ------
Total production costs.................. $ 3.12 $ 3.56 $ 4.08
====== ====== ======
Depletion expense. Depletion expense per BOE decreased 17 percent during
1999 (to $4.27 in 1999 from $5.13 in 1998) and 11 percent in 1998 (from $5.78 in
1997). The decrease in 1999 depletion expense per BOE is primarily attributable
to the impact on proved reserves of improving commodity price outlooks and to
the impairment of the per BOE carrying values of the Company's proved oil and
gas properties during the years ended December 31, 1998 and 1997. The decrease
in 1998 depletion expense per BOE was primarily due to the 1997 impairment of
the per BOE carrying values of the Company's proved oil and gas properties (see
"Impairment of Oil and Gas Properties" below).
Impairment of oil and gas properties. The Company reviews its oil and gas
producing properties for impairment whenever events or circumstances indicate a
decline in the recoverability of the carrying value of the Company's assets may
have occurred. Declining commodity prices in 1998 and 1997, the Company's
outlook for future commodity prices and 1998 performance issues relative to
certain oil and gas properties, prompted impairment reviews. As a result of
these reviews, the Company recognized non-cash charges of $312.2 million and
$1.4 billion in 1998 and 1997, respectively, related to its proved oil and gas
properties.
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The Company periodically assesses its unproved properties to determine
whether they have been impaired. An unproved property may be impaired if the
Company does not intend to drill the prospect as a result of downward revisions
to potential 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. The Company has assessed its unproved oil and gas properties for
impairment and, during the years ended December 31, 1999 and 1998, recognized
non-cash impairment charges of $17.9 million and $147.3 million, respectively,
to reduce the carrying value of its unproved oil and gas properties.
Neither the longevity nor the extent of the current trend of increasing
commodity prices can be assessed with any degree of certainty. A resumption of
the 1998 trend towards declining commodity prices, or other relevant factors,
could result in further impairment provisions to the carrying value of the
Company's proved and unproved properties, which could have a material adverse
effect on the Company's financial condition and results of operations. See Notes
B and L of Notes to Consolidated Financial Statements included in "Item 8.
Financial Statements and Supplementary Data" for additional information and
disclosures regarding the Company's accounting policies and attributes
pertaining to asset impairments.
Exploration and abandonments/geological and geophysical costs. Exploration
and abandonments/geological and geophysical costs totaled $66.0 million, $121.9
million and $77.2 million for the years ended December 31, 1999, 1998 and 1997,
respectively. The following table sets forth the components of the Company's
1999, 1998 and 1997 exploration and abandonments/geological and geophysical
costs:
Year Ended December 31,
-------------------------------
1999 1998 1997
-------- --------- --------
(in thousands)
Exploratory dry holes:
United States............................. $ 15,591 $ 15,737 $ 27,183
Argentina................................. 3,441 4,426 252
Canada.................................... 978 1,949 -
Other foreign............................. (275) 9,486 5,442
Geological and geophysical costs:
United States............................. 17,207 42,755 37,987
Argentina................................. 3,399 9,999 1,570
Canada.................................... 315 14,244 -
Other foreign............................. 7,498 3,851 -
Leasehold abandonments and other........... 17,820 19,411 4,726
------- -------- -------
$ 65,974 $ 121,858 $ 77,160
======= ======== =======
Approximately 31 percent of the Company's 1999 exploration/exploitation
capital was spent on exploratory projects as compared to 30 percent in 1998 and
28 percent in 1997. The decrease in 1999 exploratory costs is primarily
attributable to the Company's curtailed 1999 capital program, as evidenced by
reductions in all categories of exploration, abandonments, geological and
geophysical costs as compared to 1998. The increase in 1998 exploratory costs
was primarily due to the initial expenditures made to explore the Argentine and
Canadian properties acquired from Chauvco and the Company's exploration program
in South Africa. The Company currently anticipates that its 2000 exploration
efforts will be concentrated in the Gulf of Mexico, onshore Gulf Coast area,
Argentina and South Africa.
Interest and administrative expenses. Interest and general and
administrative expenses were $170.3 million and $40.2 million, respectively,
during 1999, as compared to $164.3 million and $73.0 million, respectively,
during 1998, and $77.5 million and $48.8 million, respectively, during 1997. On
a per BOE basis, interest and general and administrative expenses were $3.33 and
$.79, respectively, during 1999, as compared to $2.61 and $1.16, respectively,
during 1998, and $2.19 and $1.38, respectively, during 1997. The increase in
interest expense during 1999 is due to the higher debt levels carried over from
1998. Interest expense is expected to decline in 2000 from the expense levels
incurred during 1999 and 1998. The decline in administrative expense during
1999, and the anticipated decline in interest expense during 2000, are a direct
result of the financial measures enacted to contain costs and reduce outstanding
indebtedness. The increases in total interest and administrative expenses during
1998 were due to the Company having incurred a full year of interest on the debt
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incurred as a result of the Mesa and Chauvco acquisitions and to fund the
capital expenditures of 1998, and to administer the larger Company
infrastructure immediately after the Mesa and Chauvco acquisitions and before
the effects of the reorganization measures enacted in 1998 could be realized. On
a per BOE basis, interest expense increased in 1999, after having declined in
1998, primarily due to production variances associated with the 1999 asset
divestitures and to the postponement of oil well completions at the end of 1998
due to low oil commodity prices. The decline in per BOE administrative expense
is due to the reorganization measures initiated by the Company during 1998.
Those reorganization measures included the centralization in Irving, Texas of
certain operational and administrative functions previously based in Midland,
Texas; 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. As a direct result
of those measures, the Company recognized reorganization charges of $8.5 million
and $33.2 million, respectively, during 1999 and 1998 (see Note M of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for specific information regarding reorganization costs paid
during 1999 and 1998, and unpaid reorganization costs as of December 31, 1999
and 1998).
Other expenses. Other expenses were $34.7 million during 1999, as
compared to $39.6 million during 1998 and $7.1 million during 1997. Other
expenses recognized during 1999 were primarily attributable to fluctuations in
mark-to- market provisions on derivative financial instruments. Mark-to-market
provisions in 1999 included $21.2 million associated with non-hedge commodity
derivatives and $11.9 million associated with four million shares of common
stock of a closely held, non-affiliated, public entity, the investment in which
the Company divested during the second quarter of 1999; partially offset by $5.9
million of mark-to-market income recognized on a series of forward foreign
exchange swap agreements and income of $.2 million associated with the Company's
Btu swap agreements. 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; a $9.6 million write-off of deferred
compensation arising from change of control features in the Company's incentive
plans; $4.4 million of other expenses associated with the Company's operations
in Argentina and Canada; and, $2.3 million of bad debt expense. Other expense
for 1997 included a $5.2 million mark-to-market charge associated with the Btu
swap agreements. See "Item 7A. Quantitative and Qualitative Disclosures About
Market Risk" and Notes C and H of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for specific
disclosures pertaining to the Company's investments in derivative financial
instruments.
Income tax provisions (benefits). Due to uncertainties regarding the
Company's ability to realize net operating loss carryovers and tax credit
carryovers prior to their scheduled expirations, the Company did not recognize
deferred income tax benefits associated with its operating results for 1999 and
1998. Additionally, during 1998, the Company's net loss was impacted by a $271.1
million valuation allowance recognized to reduce the carrying value of the
Company's deferred tax assets. Although realization is not assured for the
remaining deferred tax asset, the Company believes it is more likely than not
that they will be realized through future taxable earnings or alternative tax
planning strategies. However, the net deferred tax assets could be reduced
further if the Company's estimate of taxable income in future periods is
significantly reduced or alternative tax planning strategies are no longer
viable. As a result of this situation, it is likely that the Company's effective
tax rate in 2000 will be minimal. If the Company recognizes income before income
taxes in 2000, its effective tax rate will be reduced to the extent that taxable
earnings are recognized in those tax jurisdictions relative to which the Company
has established its valuation allowance. See Note N of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for information regarding the Company's income taxes and deferred tax
asset valuation reserves.
Extraordinary items. On December 18, 1997, the Company completed a cash
tender offer for a significant portion of the 11-5/8% senior subordinated
discount notes due 2006 and the 10-5/8% senior subordinated notes due 2006 (the
"10-5/8% Notes") (collectively, the "Subordinated Notes") assumed from Mesa for
a redemption price of $829.90 and $1,171.40, respectively, per $1,000 tendered
plus any interest accrued on the 10 5/8% Notes (the "Tender Offer"). As a result
of the Tender Offer, the Company recognized an extraordinary loss on early
extinguishment of debt of $11.9 million (net of a related tax benefit of $6.4
million) during the fourth quarter of 1997. The Company financed the purchase
price of the Subordinated Notes tendered in the offer with borrowings under its
bank credit facility.
The year ended December 31, 1997 also includes a $1.5 million (net of a
related tax benefit of $800 thousand) non-cash charge for an extraordinary loss
on early extinguishment of debt resulting from the Parker & Parsley and Mesa
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merger. This extraordinary loss relates to capitalized issuance fees associated
with Parker & Parsley's previously existing bank credit facility which was
replaced by a new credit facility agreement for the Company.
Capital Commitments, Capital Resources and Liquidity
Capital commitments. The Company's primary needs for cash are for
exploration, development and acquisitions of oil and gas properties, repayment
of principal and interest on outstanding indebtedness and working capital
obligations.
The Company's cash expenditures for additions to oil and gas properties
(including individual property acquisitions, but not including company
acquisitions) during 1999, 1998 and 1997 totaled $179.7 million, $507.3 million
and $428.6 million, respectively. The $327.6 million, or 65 percent, decline in
1999 capital expenditures as compared to the expenditures of 1998 resulted from
the 1999 capital expenditures budget curtailments announced by the Company at
the end of 1998. The 1999 expenditures include $142.0 million of development and
exploratory drilling and seismic costs, of which $98.6 million, or 69 percent,
were development expenditures. During 1999, $77.6 million, or 55 percent, of the
Company's drilling and seismic expenditures occurred in the United States, of
which amount $39.2 million, or 51 percent, were expended in the Gulf Coast area;
$33.3 million, or 43 percent, were expended in the Permian Basin area; and, $4.9
million, or six percent, were expended in the Mid Continent area. Also during
1999, the Company expended $64.4 million, or 45 percent, of its drilling and
seismic capital internationally in Argentina ($34.6 million, or 54 percent of
international drilling and seismic expenditures), Canada ($26.1 million, or 41
percent of international drilling and seismic expenditures) and other
international areas ($3.7 million, or five percent of international drilling and
seismic expenditures), including South Africa and Gabon. The 1998 amount
includes $450.3 million of development and exploratory drilling and seismic
costs, of which $332.0 million, or 74 percent, were development expenditures.
During 1998, $308.2 million, or 68 percent, of the Company's drilling and
seismic expenditures occurred in the United States, of which $167.4 million, or
54 percent, were expended in the Gulf Coast area and $112.6 million, or 37
percent, was expended in the Permian Basin area. Also, during 1998, the Company
expended $142.1 million, or 32 percent, of its drilling and seismic capital in
its international regions, located in Argentina ($57.5 million, or 13 percent of
worldwide drilling and seismic expenditures), Canada ($65.8 million, or 15
percent of worldwide drilling and seismic expenditures) and other international
areas ($18.8 million, or four percent of worldwide drilling and seismic
expenditures), including South Africa and Gabon. The 1997 amount includes $292.6
million for development and exploratory drilling when the Company's drilling
activities were focused primarily in the Spraberry field of the Permian Basin.
Significant drilling expenditures in 1997 included $99.0 million in the unitized
portion of the Spraberry field of the Permian Basin (including $47.6 million in
the Driver unit, $12.7 million in the Preston unit, $12.6 million in the
Shackelford unit, $12.2 million in the North Pembrook unit and $10.5 million in
the Merchant unit), $14.9 million in other portions of the Spraberry field,
$46.5 million in other areas of the Permian Basin, $91.3 million in the onshore
and offshore Gulf Coast region, $29.9 million in the Mid Continent region and
$11.0 million in Argentina and Guatemala.
The Company's 2000 capital expenditure budget has been set at $250
million. Capital expenditures for 2000 are expected to include $200 million for
exploitation activities and $50 million for exploration activities. The Company
expects that cash provided by operating activities during 2000 will exceed the
2000 capital expenditure budget. To the extent that cash provided by operating
activities exceed capital expenditures during 2000, the Company intends to
further reduce its outstanding debt. The Company budgets its capital
expenditures based on projected internally- generated cash flows and routinely
adjusts the level of its capital expenditures in response to anticipated changes
in cash flows.
Funding for the Company's working capital obligations is provided by
internally-generated cash flow. Funding for the repayment of principal and
interest on outstanding debt and the Company's capital expenditure program may
be provided by any combination of internally-generated cash flow, proceeds from
the disposition of non-strategic assets or alternative financing sources as
discussed in "Capital Resources" below.
Capital resources. The Company's primary capital resources are net cash
provided by operating activities, proceeds from financing activities and
proceeds from sales of non-strategic assets. The Company expects that these
resources will be sufficient to fund its capital commitments and allow further
reductions in debt in 2000.
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Operating activities. Net cash provided by operating activities during
1999, 1998 and 1997 were $255.2 million, $314.1 million and $228.2 million,
respectively. Net cash provided by operating activities during 1999 decreased 19
percent from that of 1998 primarily as a result of declines in production
volumes due to oil and gas property divestitures, partially offset by increases
in commodity prices and decreases in production and administrative costs. Net
cash provided by operating activities during 1999, as compared to that of 1998,
also declined as a result of increases in working capital associated with
operating activities. Net cash provided by operating activities in 1998
increased 38 percent over that of 1997 as a result of the increased production
realized from the properties acquired from Mesa and Chauvco, partially offset by
declining commodity prices and increased general and administrative expenses,
reorganization expenditures, and interest expense. Net cash provided by
operating activities in 1997 was comparable to that of 1996. Increased
production in 1997 was offset by increased general and administrative expenses
and interest expenses and the payment of certain liabilities assumed from Mesa,
including severance payments made to former Mesa employees.
Financing Activities. As described more fully in Note D of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data", the Company was a borrower under three credit facility
agreements with a syndicate of banks which provided for a total bank credit
facility of $1.4 billion as of December 31, 1998. During the first quarter of
1999, the Company and the participating banks amended the existing credit
facilities by consolidating them into the Credit Facility. Under the terms of
the Credit Facility, the Company agreed to reduce the total loan commitments
under the Credit Facility by $410 million by December 31, 1999; the interest
rate on LIBOR Rate advances was increased to 250 basis points; and, certain
other Credit Facility amendments. The Credit Facility contains various debt
convenants, the most restrictive being the maintenance of a ratio of outstanding
Company debt to earnings before interest, depletion, depreciation, amortization,
income tax, exploration and abandonment and other non-cash expenses ("EBITDAX")
not to exceed 4.25 to one through March 31, 2000, and 3.5 to one thereafter.
Other restrictive compliance requirements include limits on the incurrence of
additional indebtedness and certain types of liens and restrictions as to
merger, sale or transfer of assets and transactions without the Banks' consent.
During 1999, the Company reduced its loan commitments under the Credit Facility
to $939.6 million in early compliance with the loan commitment reduction
requirement. As a result of the loan commitment reduction and the Company's
compliance with other Credit Facility debt covenants, the future interest rate
margin on LIBOR Rate advances under the Credit Facility has been reduced to
187.5 basis points.
At December 31, 1999, the Company has four other outstanding senior debt
issuances. Such debt issuances consist of (i) $150 million aggregate principal
amount of 8-7/8% senior notes due in 2005; (ii) $150 million aggregate principal
amount of 8-1/4% senior notes due in 2007; (iii) $350 million aggregate
principal amount of 6-1/2% senior notes due in 2008; and, (iv) $250 million
aggregate principal amount of 7-1/5% senior notes due in 2028. The weighted
average interest rate for the year ended December 31, 1999 on the Company's
indebtedness was 7.81 percent as compared to 7.16 percent for the year ended
December 31, 1998 and 7.04 percent for the year ended December 31, 1997 (taking
into account the effect of interest rate swaps).
As the Company continues to pursue its strategy, it may utilize
alternative financing sources, including the issuance for cash of fixed rate
long-term public debt, convertible securities or preferred stock. The Company
may also issue securities in exchange for oil and gas properties, stock or other
interests in other oil and gas companies or related assets. Additional
securities may be of a class preferred to common stock with respect to such
matters as dividends and liquidation rights and may also have other rights and
preferences as determined by the Company's Board of Directors.
Sales of non-strategic Assets. During 1999, 1998 and 1997, proceeds from
the sale of non-strategic assets totaled $420.5 million, $21.9 million and
$115.7 million, respectively. The Company's 1999 asset divestitures were
comprised of non-strategic United States and Canadian oil and gas properties,
gas plants and other assets. The net cash proceeds from the 1999 asset
divestitures were used to reduce the Company's outstanding indebtedness (see
"Results of Operations", above, and Note K of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data").
The proceeds from the 1998 and 1997 asset divestitures were primarily utilized
to provide funding for a portion of the Company's capital expenditures during
those years.
Liquidity. At December 31, 1999, the Company had $34.8 million of cash
and cash equivalents on hand, compared to $59.2 million at December 31, 1998.
The Company's ratio of current assets to current liabilities was .93 at December
31, 1999 and .38 at December 31, 1998.
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Other Items
Year 2000 project readiness. As the year 2000 was approaching, the
inability of some computer programs and embedded technologies to distinguish
between "1900" and "2000" gave rise to the "Year 2000" problem. Such computer
programs and related technology were at risk to fail outright or communicate
inaccurate data, if not remediated or replaced. With the proliferation of
electronic data interchange, the Year 2000 problem represented a significant
exposure to the entire global community, the full extent of which could not be
accurately assessed prior to the year 2000.
In proactive response to the Year 2000 problem, the Company established a
"Year 2000" project that assessed, to the extent possible, the Company's
internal Year 2000 problem; took remedial actions necessary to minimize the Year
2000 risk exposure to the Company and significant third parties with whom it has
data interchange; and, tested the Company's systems and processes once remedial
actions were taken. The Company contracted with IBM Global Services to perform
the assessment and remedial phases of its Year 2000 project. The Company's total
costs related to the Year 2000 problem were $2.5 million, which was funded from
working capital.
The Company has closely monitored its information and non-information
technology systems since the beginning of 2000 and has identified no significant
Year 2000 failures or problems. The Company will continue to monitor Year 2000
risks and issues. There can be no assurances that unforeseen problems will not
be encountered in the future.
Proposal to acquire partnerships. On September 8, 1999, Pioneer Natural
Resources USA, Inc. ("Pioneer USA") filed a preliminary proxy statement with the
SEC proposing an agreement and plan of merger to the limited partners of 25
publicly-held Parker & Parsley limited partnerships. Pioneer USA is the managing
partner of the Parker & Parsley limited partnerships. The preliminary proxy
statement is non-binding and is subject to, among other things, consideration of
offers from third parties to purchase any partnership or its assets, the
majority approval of the limited partners in each partnership and the resolution
of SEC review comments. The Company is continuing to evaluate the feasibility of
the proposed agreement and plan of merger; however, the current commodity price
outlook has diminished the likelihood that the proposed agreement and plan of
merger will be consummated.
Accounting for derivatives. In June 1998, the Financial Accounting
Standards Board ("FASB") issued Statement of Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133").
SFAS 133 establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, (collectively referred to as derivatives) and for hedging activities.
It requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position and measure those instruments
at fair value. If certain conditions are met, a derivative may be specifically
designated as (a) a hedge of the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm commitment, (b) a hedge of
the exposure to variable cash flows of a forecasted transaction, or (c) a hedge
of the foreign currency exposure of a net investment in a foreign operation, an
unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated forecasted transaction.
In June 1999, the FASB issued Statement of Accounting Standards No. 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133 - and amendment of FASB Statement 133"
("SFAS 137"). SFAS 137 defers the effective date for SFAS 133 to fiscal years
beginning after June 15, 2000. The Company has not determined what effect, if
any, SFAS 133 will have on its consolidated financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about
financial instruments to which the Company is a party as of December 31, 1999
and 1998, and from which the Company may incur future gains or losses from
changes in market interest rates, foreign exchange rates, commodity prices or
common and preferred stock prices. Although certain derivative contracts that
the Company is a party to do not qualify as hedges, the Company does not enter
into derivative or other financial instruments for trading purposes.
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Quantitative Disclosures
Interest rate sensitivity. The following tables provide information, in
United States dollar equivalent amounts, about the Company's derivative
financial instruments and other financial instruments that the Company was a
party to as of December 31, 1999 and 1998, which are sensitive to changes in
interest rates. For debt obligations, the tables present maturities by expected
maturity dates together with the weighted average interest rates expected to be
paid on the debt, given current contractual terms and market conditions. For
fixed rate debt, the weighted average interest rate represents the contractual
fixed rates that the Company is obligated to periodically pay on the debt; for
variable rate debt, the average interest rate represents the average rates being
paid on the debt projected forward proportionate to the forward yield curve for
United States treasury securities. As of December 31, 1998, the Company was a
party to a series of interest rate swap agreements whereby the Company paid a
variable rate on a $150 million notional amount and received a fixed annual rate
of 6.62 percent of the notional amount. The fair value of the swap agreements to
the Company represented an asset of $1.046 million as of December 31, 1998. The
swap agreements were accounted for as hedges by the Company until their maturity
during May and June 1999. The Company was also a party to a non- hedge interest
rate cap as of December 31, 1998. Under the terms of the cap agreement, the
Company paid the counterparties a .28 percent annual rate on an $80 million
notional amount, so long as the Canadian bankers' acceptance reference rate did
not exceed 8.00 percent per year. The fair value of the interest rate cap
represented a liability of the Company of $80 thousand on December 31, 1998. The
interest rate cap matured in August 1999.
33
<PAGE>
Pioneer Natural Resources Company
Interest Rate Sensitivity
Derivative And Other Financial Instruments As of December 31, 1999
<TABLE>
2000 2001 2002 2003 2004 Thereafter Total Fair Value
------ ------ -------- ------ ------ ---------- -------- ----------
(in thousands except interest rates)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Debt:
U.S. dollar denominated
maturities:
Fixed rate debt....... $ 828 $ - $ - $ 518 $ 571 $ 919,019 $920,936 $776,230(1)
Weighted average
interest rate...... 7.50% 7.50% 7.50% 7.50% 7.50% 7.50%
Variable rate debt... $ - $ - $825,000 $825,000 $825,000
Average interest rates 7.65% 7.70% 7.65%
</TABLE>
Pioneer Natural Resources Company
Interest Rate Sensitivity
Derivative And Other Financial Instruments As of December 31, 1998
<TABLE>
1999 2000 2001 2002 2003 Thereafter Total Fair Value
-------- ------ ------ -------- ------- ---------- ---------- ------------
(in thousands except interest rates)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Total Debt:
U.S. dollar denominated
maturities:
Fixed rate debt....... $ 330 $ - $ - $ 1,508 $ 1,447 $ 932,948 $ 936,233 $ 743,701(1)
Weighted average
interest rate....... 7.50% 7.50% 7.50% 7.50% 7.50% 7.50%
Variable rate debt.... $306,191 $ - $ - $932,841 $1,239,032 $1,239,032
Average interest rates 5.85% 5.87% 5.89% 5.92%
- ---------------
</TABLE>
(1) Excludes $23.0 million and $38.5 million of debt instruments for which
fair values were not practicable to derive as of December 31, 1999
and 1998, respectively.
Foreign exchange rate sensitivity. The following tables provide
information, in United States dollar equivalent amounts, about the Company's
derivative financial instruments that the Company was a party to as of December
31, 1999 and 1998 and that are sensitive to changes in foreign exchange rates.
The tables provide information regarding the notional amounts of the Company's
Canadian dollar denominated foreign currency swap derivative contracts,
including rates paid and received by the Company and forward currency exchange
rates. See "Interest rate sensitivity", above, for information regarding the
Company's Canadian dollar denominated interest rate cap that matured during
August 1999.
Pioneer Natural Resources Company
Foreign Exchange Rate Sensitivity
Derivative And Other Financial Instruments As of December 31, 1999
<TABLE>
2000 2001 2002 2003 2004 Thereafter Total Fair Value
------- ------ ------ ------ ------ ---------- --------- ----------
(in thousands except foreign exchange rates)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Non-hedge Foreign Exchange
Rate Derivatives:
Notional amount of foreign
currency swaps (1)..... $72,000 $ 72,000 $ (4,168)
Fixed Canadian to U.S.
dollar rate paid....... 1.3606
Average forward Canadian
dollar to U.S. dollar
exchange rate......... 1.4455
</TABLE>
34
<PAGE>
Pioneer Natural Resources Company
Foreign Exchange Rate Sensitivity
Derivative And Other Financial Instruments As of December 31, 1998
<TABLE>
1999 2000 2001 2002 2003 Thereafter Total Fair Value
------- ------- ------- ------- ------- ---------- -------- ----------
(in thousands except foreign exchange rates)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Non-hedge Foreign Exchange
Rate Derivatives:
Notional amount of foreign
currency swaps (1)...... $72,000 $72,000 $144,000 $ (15,350)
Fixed Canadian to U.S.
dollar rate paid........ 1.3670 1.3606
Average forward Canadian
dollar to U.S. dollar
exchange rate.......... 1.4990 1.4963
- ---------------
</TABLE>
(1) The foreign exchange rate swaps mature in October and December 2000.
Commodity price sensitivity. The following tables provide information, in
United States dollar equivalent amounts, about the Company's derivative
financial instruments that the Company was a party to as of December 31, 1999
and 1998 and that are sensitive to changes in crude oil and natural gas
commodity prices. The tables segregate hedge derivative contracts from those
that do not qualify as hedges.
Commodity hedge instruments. The Company hedges commodity price risk with
swap contracts, put contracts, collar contracts and collar contracts with short
put options. Swap contracts provide a fixed price for a notional amount of sales
volumes. Put contracts provide a fixed floor price on a notional amount of sales
volumes while allowing full price participation if the relevant index price
closes above the floor price. Collar contracts provide a floor price for the
Company on a notional amount of sales volumes while allowing some additional
price participation if the relevant index price closes above the floor price.
Collar contracts with short put options differ from other collar contracts by
virtue of the short put option price below which the Company's realized price
will exceed variable market prices by the long put-to-short put price
differential.
Commodity non-hedge instruments. The Company has entered into BTU swap
contracts and optional call contracts that do not qualify for hedge accounting.
Under the terms of the BTU swap contracts, the Company receives 10 percent of
the NYMEX oil price and pays the NYMEX gas price on a 13,036 notional MMBtu
daily gas volume. As of December 31, 1998, this derivative instrument was the
only financial instrument that the Company was a party to that was sensitive to
changes in crude oil prices. The relevant information is included in the
Company's natural gas price sensitivity table as of December 31, 1998.
The terms of the optional call contracts provide the counterparties with
the option to elect to call either notional crude oil volumes or natural gas
volumes at specific index prices. Accordingly, these derivative instruments are
presented in both the accompanying crude oil and natural gas tables.
See Notes B, C and H of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a
description of the accounting procedures followed by the Company relative to
hedge and non-hedge derivative financial instruments and for specific
information regarding the terms of the Company's derivative financial
instruments that are sensitive to changes in natural gas and crude oil commodity
prices.
35
<PAGE>
Pioneer Natural Resources Company
Crude Oil Price Sensitivity
Derivative Financial Instruments As of December 31, 1999
<TABLE>
2000 2001 2002 2003 2004 Fair Value
-------- -------- -------- -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C>
Crude Oil Hedge Derivatives (1):
Average daily notional Bbl
volumes:
Swap contracts (2)................ 9,519 $ (5,714)
Weighted average per Bbl
fixed price.................... $ 16.51
Collar contracts.................. 826 $ (189)
Weighted average short call
per Bbl ceiling price.......... $ 23.00
Weighted average long
put per Bbl floor price........ $ 19.00
Collar contracts with short
put (2) (3)...................... 7,000 8,000 $ (9,407)
Weighted average short call
per Bbl ceiling price.......... $ 20.42 $ 21.57
Weighted average long put
per Bbl floor price............ $ 17.29 $ 18.44
Weighted average short put
per Bbl price below which
floor becomes variable......... $ 14.29 $ 15.44
Crude Oil Non-hedge Derivatives:
Daily notional crude oil Bbl
volumes under optional calls
sold.............................. 10,000 $ (13,259)
Weighted average short call
per Bbl ceiling price.......... $ 20.00
Average forward NYMEX
crude oil price per Bbl (4).... $ 24.03
Daily notional MMBtu volumes
under swap of NYMEX
gas price for 10 percent of
NYMEX WTI price................ 13,036 13,036 13,036 13,036 13,036 $ (13,218)
Average forward NYMEX
gas prices (4)................... $ 2.65 $ 2.58 $ 2.57 $ 2.62 $ 2.67
Average forward NYMEX
oil prices (4)................... $ 24.03 $ 20.33 $ 18.83 $ 18.27 $ 18.12
</TABLE>
- ---------------
(1) See Note H of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for hedge volumes and
weighted average prices by calendar quarter for years 2000 and 2001.
(2) During the first quarter of 2000, the Company terminated June 2000 through
December 2000 swap contracts for notional volumes of 9,000 Bbls per day and
the 2001 collar contracts with short puts for notional volumes of 8,000
Bbls per day, at a total cost of $16.1 million.
(3) The counterparties to the year 2000 collar contracts with short puts have
the contractual right to extend contracts for notional contract volumes of
5,000 Bbls per day through year 2001 at weighted average per Bbl strike
prices of $20.09 for the short call ceiling price, $17.00 for the long put
floor price and $14.00 for the short put price below which the floor
becomes variable.
(4) The average forward NYMEX oil and gas prices are based on February 2, 2000
market quotes.
36
<PAGE>
Pioneer Natural Resources Company
Natural Gas Price Sensitivity
Derivative Financial Instruments As of December 31, 1999
<TABLE>
2000 2001 2002 2003 2004 Fair Value
-------- -------- -------- -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C>
Natural Gas Hedge Derivatives (1):
Average daily notional MMBtu
volumes (2):
Swap contracts (3)........................ 328 - 10,000 $ (5,385)
Weighted average per
MMBtu fixed price...................... $ 3.00 $ - $ 2.42
Collar contracts with short puts (4) (5).. 93,814 60,000 $ (5,518)
Weighted average short call
MMBtu ceiling price................... $ 2.62 $ 2.64
Weighted average long put
MMBtu contingent floor price.......... $ 2.07 $ 2.25
Weighted average short put
MMBtu price below which
floor becomes variable................ $ 1.78 $ 1.95
Natural Gas Non-hedge
Derivatives:
Daily notional gas MMBtu volumes
under optional calls sold.................. 100,000 $ (13,259)
Weighted average short call
per MMBtu ceiling price.................. $ 2.75
Average forward NYMEX
gas price per MMBtu (6).................. $ 2.65
Daily notional MMBtu volumes
under agreement to swap
NYMEX gas price for 10 percent
of NYMEX WTI price...................... 13,036 13,036 13,036 13,036 13,036 $ (13,218)
Average forward NYMEX
gas prices (6)........................... $ 2.65 $ 2.58 $ 2.57 $ 2.62 $ 2.67
Average forward NYMEX
oil prices (6)........................... $ 24.03 $ 20.33 $ 18.83 $ 18.27 $ 18.12
- --------------
</TABLE>
(1) To minimize basis risks, the Company enters into basis swaps for a portion
of its gas hedges to connect the index price of the hedging instrument from
a NYMEX index to an index which reflects the geographic area of production.
The Company considers these basis swaps as part of the associated swap and
option contracts and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(2) See Note H of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for hedge volumes and
weighted average prices by calendar quarter for years 2000, 2001 and 2002.
(3) Certain counterparties to the swap contracts have the contractual right to
sell year 2001, 2002 and 2003 swap contracts to the Company for notional
daily contract volumes of 49,223, 12,500 and 10,000 MMBtu per day
respectively, at prices of $2.21, $2.52 and $2.58 per MMBtu, respectively.
(4) During the first quarter of 2000, the Company terminated collar contracts
with short puts for notional contract volumes of 45,000 MMBtu per day for
the period from April 2000 through December 2000 and the 2001 collar
contracts with short puts for notional contract volumes of 60,000 MMBtu per
day, at a cost of $4.6 million.
(5) 54,582 MMBtu per day of year 2000 collar option contracts with short puts
are extendable at the option of the counterparties for a period of one year
at average per MMBtu prices of $2.71, $2.09 and $1.80 for the short call,
long put and short put, respectively, 60,000 MMBtu per day of the year 2000
collar option contracts with short puts are extendable at the option of the
counterparties at average per MMBtu prices of $2.64, $2.25 and $1.95 for
the short call, long put and short put, respectively.
(6) The average forward NYMEX oil and gas prices are based on February 2, 2000
market quotes.
37
<PAGE>
Pioneer Natural Resources Company
Natural Gas Price Sensitivity
Derivative Financial Instruments As of December 31, 1998
<TABLE>
1999 2000 2001 2002 2003 Thereafter Fair Value
-------- -------- -------- -------- -------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Natural Gas Hedge Derivatives:
Average daily notional MMBtu
volumes:
Swap contracts................ 137,044 35,000 $ 17,827
Weighted average MMBtu
fixed price................ $ 2.21 $ 1.35
Collar option contracts....... 33,400 $ 323
Weighted average short call
MMBtu ceiling price........ $ 2.56
Weighted average long put
MMBtu floor price.......... $ 1.91
Collar option contracts with
short puts................... 114,286 93,074 $ 8,398
Weighted average short call
MMBtu ceiling price........ $ 2.64 $ 2.75
Weighted average long put
MMBtu contingent floor
price...................... $ 2.12 $ 2.14
Weighted average short put
MMBtu price below which
floor becomes variable..... $ 1.82 $ 1.84
Natural Gas Non-hedge
Derivatives:
Daily notional MMBtu volumes
under agreement to swap
NYMEX gas price for 10
percent of NYMEX WTI
price........................ 13,036 13,036 13,036 13,036 13,036 13,036 $ (15,172)
Average forward NYMEX
gas prices................. $ 1.97 $ 2.17 $ 2.25 $ 2.34 $ 2.39 $ 2.45
Average forward NYMEX oil
prices..................... $ 13.00 $ 14.75 $ 16.00 $ 16.75 $ 17.45 $ 17.88
</TABLE>
Other price sensitivity. During 1998, the Company acquired three million
shares of Costilla Energy Inc. ("Costilla") common stock in partial payment of
option fees associated with an irrevocable option sold to Costilla in December
1998, the terms of which allowed Costilla the option to acquire certain assets
of the Company. The fair value of the Costilla common stock owned by the Company
was $12 million as of December 31, 1998. The Company sold its investment in
common stock of Costilla during 1999. See Note C of Notes to Consolidated
Financial Statements included in"Item 8. Financial Statements and Supplemental
Data".
As of December 31, 1999, the Company owned 2,376.923 shares of Prize
Energy Corp. ("Prize") six percent convertible preferred stock ("Prize
Preferred") that had a liquidation preference and estimated fair value of $30.0
million when acquired on June 29, 1999. As of December 31, 1999, Prize was a
closely held, non-public entity and the fair value of the Prize Preferred was
not readily determinable.
On February 9, 2000, Prize announced a merger with Vista Energy Resources
Inc., whereby the common stock of the merged Prize entity began to publicly
trade on the American Stock Exchange. Associated therewith, the Company's Prize
Preferred was exchanged for 3,984,197 shares of Prize Series A 6% Convertible
Preferred Stock ("Prize Senior A Preferred") having a liquidation preference and
stated value of $7.81 per share, plus cumulative dividends accrued and unpaid.
Each share of Prize Series A Preferred is convertible, at the option of the
holder, into one share of Prize common stock. Under certain circumstances, Prize
38
<PAGE>
may redeem the Prize Series A Preferred at the stated value per share, unless
the Company exercises its conversion rights. The fair value of the Prize Series
A Preferred is not readily determinable.
Qualitative Disclosures
Non-derivative financial instruments. The Company is a borrower under
fixed rate and variable rate debt instruments that give rise to interest rate
risk. The Company's objective in borrowing under fixed or variable rate debt is
to satisfy capital requirements while minimizing the Company's costs of capital.
To realize its objectives, the Company borrows under fixed and variable rate
debt instruments, based on the availability of capital, market conditions and
hedge opportunities. See Note D of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a
discussion relative to the Company's debt instruments.
Derivative financial instruments. The Company has entered into interest
rate, foreign exchange rate and commodity price derivative contracts to hedge
interest rate, foreign exchange rate and commodity price risks. Although the
Company is a party to certain foreign exchange rate and commodity price
derivative contracts that do not qualify for hedge accounting treatment, the
Company's policy is to only enter into derivative contracts that, in the opinion
of management, reduce the Company's overall economic risk.
As of December 31, 1999 and 1998, the Company was a party to the Canadian
denominated foreign exchange rate swap, optional commodity calls and the BTU
swap that are described more fully in Quantitative Disclosures, above, and Note
H of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data". These financial instruments do not qualify
as hedges of foreign exchange rate or commodity price risk under generally
accepted accounting standards.
The Company intends to only enter into interest rate, foreign exchange
rate or commodity price derivative instruments that, in the opinion of
management, reduce the Company's interest rate, foreign exchange rate or
commodity price risk profiles. Occasionally, the Company may enter into
derivative financial instruments that reduce the Company's risk profiles, but do
not qualify for hedge accounting treatment. See Notes B, C and H of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for further discussions relative to the Company's objectives
and general strategies associated with its hedge instruments.
As of December 31, 1999, the Company's primary risk exposure associated
with financial instruments to which it is a party include crude oil and natural
gas price volatility, interest rate volatility and Canadian dollar to United
States dollar foreign exchange rate volatility. The Company's primary risk
exposures associated with financial instruments have not changed significantly
since December 31, 1999.
39
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Page
Consolidated Financial Statements of Pioneer Natural Resources Company:
Independent Auditors' Reports......................................... 41
Consolidated Balance Sheets as of December 31, 1999 and 1998.......... 42
Consolidated Statements of Operations and Comprehensive Loss for
the Years Ended December 31, 1999, 1998 and 1997.................. 43
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1999, 1998 and 1997................................... 44
Consolidated Statements of Cash Flows for the Years Ended December 31,
1999, 1998, and 1997............................................... 45
Notes to Consolidated Financial Statements............................ 46
Unaudited Supplementary Information................................... 76
40
<PAGE>
INDEPENDENT AUDITORS' REPORTS
The Board of Directors and Shareholders
Pioneer Natural Resources Company:
We have audited the accompanying consolidated balance sheets of Pioneer
Natural Resources Company and subsidiaries as of December 31, 1999 and 1998, and
the related consolidated statements of operations and comprehensive loss,
stockholders' equity, and cash flows for the years ended December 31, 1999 and
1998. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
Pioneer Natural Resources Company and subsidiaries at December 31, 1999 and
1998, and the consolidated results of its operations and its cash flows for the
years ended December 31, 1999 and 1998 in conformity with accounting principles
generally accepted in the United States.
Ernst & Young LLP
Dallas, Texas
January 24, 2000
The Board of Directors and Stockholders
Pioneer Natural Resources Company:
We have audited the consolidated statements of operations and
comprehensive loss, stockholders' equity, and cash flows of Pioneer Natural
Resources Company and subsidiaries for the year ended December 31, 1997. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provided a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the results of operations and cash
flows of Pioneer Natural Resources Company and subsidiaries for the year ended
December 31, 1997, in conformity with generally accepted accounting principles.
KPMG LLP
Midland, Texas
February 13, 1998
41
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
ASSETS
<TABLE>
December 31,
-------------------------
1999 1998
----------- -----------
<S> <C> <C>
Current assets:
Cash and cash equivalents...................................... $ 34,788 $ 59,221
Accounts receivable:
Trade, net................................................... 116,456 106,863
Affiliates................................................... 2,119 3,657
Inventories.................................................... 13,721 15,221
Deferred income taxes.......................................... 5,800 7,100
Other current assets........................................... 10,252 9,926
---------- ----------
Total current assets....................................... 183,136 201,988
---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts
method of accounting:
Proved properties............................................ 2,997,335 3,621,630
Unproved properties.......................................... 257,583 342,589
Accumulated depletion, depreciation and amortization........... (751,956) (930,111)
---------- ----------
2,502,962 3,034,108
Deferred income taxes............................................ 83,400 96,800
Other property and equipment, net................................ 43,006 55,010
Other assets, net................................................ 116,969 93,408
---------- ----------
$ 2,929,473 $ 3,481,314
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt........................... $ 828 $ 306,521
Accounts payable:
Trade ....................................................... 86,442 94,937
Affiliates................................................... 426 4,492
Interest payable............................................... 36,045 33,194
Other current liabilities...................................... 73,072 87,688
---------- ----------
Total current liabilities.................................. 196,813 526,832
---------- ----------
Long-term debt, less current maturities.......................... 1,745,108 1,868,744
Other noncurrent liabilities..................................... 169,438 232,461
Deferred income taxes............................................ 43,500 64,200
Stockholders' equity:
Preferred stock, $.01 par value; 100,000,000 shares
authorized; one share issued and outstanding................. - -
Common stock, $.01 par value; 500,000,000 shares authorized;
100,876,789 shares issued at December 31, 1999; and
100,833,615 shares issued at December 31, 1998............... 1,009 1,008
Additional paid-in capital..................................... 2,348,448 2,347,996
Treasury stock, at cost; 537,206 shares at December 31, 1999
and 537,392 shares at December 31, 1998...................... (10,384) (10,388)
Accumulated deficit............................................ (1,574,884) (1,552,442)
Accumulated other comprehensive income:
Cumulative translation adjustment............................ 10,425 2,903
---------- ----------
Total stockholders' equity................................. 774,614 789,077
---------- ----------
Commitments and contingencies
$ 2,929,473 $ 3,481,314
========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
42
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
AND COMPREHENSIVE LOSS
(in thousands, except per share data)
<TABLE>
Year Ended December 31,
------------------------------------
1999 1998 1997
--------- ---------- -----------
<S> <C> <C> <C>
Revenues:
Oil and gas...................................... $ 644,646 $ 711,492 $ 536,782
Interest and other............................... 89,657 10,452 4,278
Gain (loss) on disposition of assets, net........ (24,168) (445) 4,969
-------- --------- ----------
710,135 721,499 546,029
-------- --------- ----------
Costs and expenses:
Oil and gas production........................... 159,530 223,551 144,170
Depletion, depreciation and amortization......... 236,047 337,308 212,435
Impairment of oil and gas properties............. 17,894 459,519 1,356,390
Exploration and abandonments..................... 65,974 121,858 77,160
General and administrative....................... 40,241 73,000 48,763
Reorganization................................... 8,534 33,199 -
Interest......................................... 170,344 164,285 77,550
Other............................................ 34,631 39,605 7,124
-------- --------- ----------
733,195 1,452,325 1,923,592
-------- --------- ----------
Loss before income taxes and extraordinary item..... (23,060) (730,826) (1,377,563)
Income tax benefit (provision)...................... 600 (15,600) 500,300
-------- --------- ----------
Loss before extraordinary item...................... (22,460) (746,426) (877,263)
Extraordinary item - loss on early extinguishment
of debt, net of tax.............................. - - (13,408)
-------- --------- ----------
Net loss............................................ (22,460) (746,426) (890,671)
Other comprehensive income:
Currency translation adjustment.................. 8,358 2,903 -
-------- --------- ----------
Comprehensive loss.................................. $ (14,102) $ (743,523) $ (890,671)
======== ========= ==========
Loss per share:
Basic:
Loss before extraordinary item................. $ (.22) $ (7.46) $ (16.88)
Extraordinary item............................. - - (.26)
-------- --------- ----------
Net loss....................................... $ (.22) $ (7.46) $ (17.14)
======== ========= ==========
Diluted:
Loss before extraordinary item................. $ (.22) $ (7.46) $ (16.88)
Extraordinary item............................. - - (.26)
-------- --------- ----------
Net loss....................................... $ (.22) $ (7.46) $ (17.14)
======== ========= ==========
Dividends declared per share........................ $ - $ .10 $ .10
======== ========= ==========
Weighted average shares outstanding................. 100,307 100,055 51,973
======== ========= ==========
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
43
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(in thousands, except dividends per share)
<TABLE>
Additional Unearned Accumulated Accum. Other Total
Common Paid-in Treasury Compen- Earnings Comprehensive Stockholders'
Stock Capital Stock sation (Deficit) Income Equity
------- ---------- --------- --------- ----------- ------------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1997....... $ 369 $ 462,873 $ (31,528) $ (1,625) $ 100,207 $ - $ 530,296
Common stock issued:
Acquisition of MESA, Inc....... 318 982,248 - - - - 982,566
Acquisition of Chauvco
Resources, Ltd............... 249 688,081 - - - - 688,330
Acquisition of properties...... 16 44,857 - - - - 44,873
Exercise of stock options........ 5 11,591 - - - - 11,596
Cancellation of treasury shares.. (19) (34,441) 34,460 - - - -
Exchange of preferred shares
for common shares.............. 67 182,909 - - - - 182,976
Restricted shares awarded........ 5 18,974 - (18,079) - - 900
Tax benefits related to
stock options.................. - 2,900 - - - - 2,900
Purchase of treasury stock....... - - (2,953) - - - (2,953)
Amortization of unearned
compensation................... - - - 3,508 - - 3,508
Net loss......................... - - - - (890,671) - (890,671)
Dividends ($.10 per share)....... - - - - (5,476) - (5,476)
------ --------- -------- -------- ---------- --------- -----------
Balance at December 31, 1997..... 1,010 2,359,992 (21) (16,196) (795,940) - 1,548,845
------ --------- -------- -------- ---------- --------- -----------
Common stock issued in settlement
of litigation.................. - 342 - - - - 342
Reduction in common stock
issued for acquisition of
Chauvco Resources Ltd.......... (4) (11,094) - - - - (11,098)
Exercise of stock options........ - 3 - - - - 3
Restricted shares awarded........ 2 3,053 - (493) - - 2,562
Tax provision related to
stock and option awards........ - (4,300) - - - - (4,300)
Purchase of treasury stock....... - - (10,367) - - - (10,367)
Amortization of unearned
compensation................... - - - 16,689 - - 16,689
Net loss......................... - - - - (746,426) - (746,426)
Dividends ($.10 per share)....... - - - - (10,076) - (10,076)
Other comprehensive income:
Currency translation adjustment - - - - - 2,903 2,903
------ --------- -------- -------- ---------- --------- -----------
Balance at December 31, 1998..... 1,008 2,347,996 (10,388) - (1,552,442) 2,903 789,077
------ --------- -------- -------- ---------- --------- -----------
Exercise of stock options and
employee stock purchases....... 1 249 - - - - 250
Issuance of stock options under
long-term incentive plan....... - 25 - - - - 25
Restricted shares awarded........ - 178 4 - - - 182
Adjustment to dividends.......... - - - - 18 - 18
Realized translation adjustment.. - - - - - (836) (836)
Net loss......................... - - - - (22,460) - (22,460)
Other comprehensive income:
Currency translation adjustment - - - - - 8,358 8,358
------ --------- -------- -------- ---------- --------- -----------
Balance at December 31, 1999..... $ 1,009 $2,348,448 $ (10,384) $ - $(1,574,884) $ 10,425 $ 774,614
====== ========= ======== ======== ========== ========= ===========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
44
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
Year Ended December 31,
------------------------------------
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Cash flows from operating activities:
Net loss.................................................... $ (22,460) $ (746,426) $ (890,671)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depletion, depreciation and amortization............... 236,047 337,308 212,435
Impairment of oil and gas properties................... 17,894 459,519 1,356,390
Exploration expenses, including dry holes.............. 50,030 92,311 63,288
Deferred income taxes.................................. - 18,600 (501,300)
(Gain) loss on disposition of assets, net.............. 24,168 445 (4,969)
Loss on early extinguishment of debt, net of tax....... - - 13,408
Other noncash items.................................... (866) 66,300 18,886
Change in operating assets and liabilities, net of effects
from acquisitions and dispositions:
Accounts receivable.................................... (7,393) 85,413 (39,774)
Inventory.............................................. (952) 2,714 (5,941)
Other current assets................................... (2,335) 30 (1,913)
Accounts payable....................................... (18,683) (29,800) 27,138
Interest payable....................................... 2,851 15,545 3,285
Other current liabilities.............................. (23,067) 12,117 (22,053)
--------- --------- ---------
Net cash provided by operating activities............ 255,234 314,076 228,209
--------- --------- ---------
Cash flows from investing activities:
Payment for acquisitions, net of cash acquired.............. - - (15,490)
Proceeds from disposition of assets......................... 390,531 21,876 115,735
Additions to oil and gas properties......................... (179,669) (507,337) (428,640)
Other property additions, net............................... (11,867) (31,546) (12,783)
--------- --------- ---------
Net cash provided by (used in) investing activities.. 198,995 (517,007) (341,178)
--------- --------- ---------
Cash flows from financing activities:
Borrowings under long-term debt............................. 355,493 947,180 821,148
Principal payments on long-term debt........................ (793,919) (711,524) (648,208)
Payments of other noncurrent liabilities.................... (34,002) (17,091) (7,740)
Deferred loan fees/issuance costs........................... (6,891) (7,189) (2,396)
Dividends................................................... - (10,076) (5,476)
Purchase of treasury stock.................................. - (10,367) (2,953)
Exercise of stock options and employee stock purchases...... 250 - 11,596
--------- --------- ---------
Net cash provided by (used in) financing activities.. (479,069) 190,933 165,971
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents .......... (24,840) (11,998) 53,002
Effect of exchange rate changes on cash and cash equivalents... 407 (494) -
Cash and cash equivalents, beginning of year................... 59,221 71,713 18,711
--------- --------- ---------
Cash and cash equivalents, end of year......................... $ 34,788 $ 59,221 $ 71,713
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these
consolidated financial statements.
45
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
NOTE A. Organization and Nature of Operations
Pioneer Natural Resources Company (the "Company") is a Delaware
Corporation whose common stock is listed and traded on the New York Stock
Exchange and the Toronto Stock Exchange. The Company was formed by the merger of
Parker & Parsley Petroleum Company ("Parker & Parsley") and MESA Inc. ("Mesa")
in August 1997. The Company subsequently acquired 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 , during December 1997.
The Company is an oil and gas exploration and production company with ownership
interests in oil and gas properties located principally in the Mid Continent,
Southwestern and onshore and offshore Gulf Coast regions of the United States
and in Argentina, Canada and South Africa.
In accordance with the provisions of Accounting Principles Board Opinion
No. 16, "Business Combinations" ("APB 16"), both the merger with Mesa and the
acquisition of Chauvco were accounted for as purchases by the Company (formerly
Parker & Parsley). As a result, the historical financial statements for the
Company are those of Parker & Parsley prior to August 1997.
NOTE B. Summary of Significant Accounting Policies
Principles of consolidation. The consolidated financial statements
include the accounts of the Company and its majority-owned subsidiaries since
their acquisition or formation, and the Company's interest in the affiliated oil
and gas partnerships for which it serves as general partner through certain of
its wholly-owned subsidiaries. Investments in less than majority-owned
subsidiaries where the Company has the ability to exercise significant influence
over the investee's operations are accounted for by the equity method. The
Company proportionately consolidates less than 100 percent-owned oil and gas
partnerships in accordance with industry practice. The Company owns less than a
20 percent interest in the oil and gas partnerships that it proportionately
consolidates. All material intercompany balances and transactions have been
eliminated.
The Company determines the appropriate classification of investments in
non-affiliated equity securities at the time of purchase and re-evaluates such
determinations at each balance sheet date.
Investments in non-affiliated equity securities that have a readily
determinable fair value are classified as "trading securities" if management's
current intent is to hold them for only a short period of time; otherwise, they
are accounted for as "available-for-sale" securities. The carrying value of
trading securities and available-for-sale securities are adjusted to fair value
as of each balance sheet date. Unrealized holding gains and losses are
recognized for trading securities in interest and other revenue, in the case of
unrealized holding gains, or other expense, in the case of unrealized holding
losses, during the periods in which changes in fair value occur. Unrealized
holding gains and losses would be recognized for available-for-sale securities
as credits or charges to stockholders' equity during the periods in which
changes in fair value occur, and would also be included as items of other
comprehensive income (loss). The Company did not have any investments in
available-for-sale securities during the years ended December 31, 1999, 1998 or
1997.
Investments in non-affiliated equity securities that do not have a
readily determinable fair value are measured in the accompanying Consolidated
Balance Sheet as of December 31, 1999 at the lower of their original cost less
associated cash dividends received, or the net realizable value of the
investment.
Use of estimates in the preparation of financial statements. Preparation
of the accompanying consolidated financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities, the
46
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting periods. Actual results could differ from those estimates.
Cash equivalents. Cash and cash equivalents include cash on hand and
depository accounts held by banks.
Inventories. Inventories consist of lease and well equipment which are
carried at the lower of cost or market, on a first-in first-out basis.
Oil and gas properties. The Company utilizes the successful efforts
method of accounting for its oil and gas properties. Under this method, all
costs associated with productive wells and nonproductive development wells are
capitalized while nonproductive exploration costs are expensed. The Company
capitalizes interest on expenditures for significant development projects until
such time as operations commence.
The Company accounts for its natural gas processing facilities activities
as part of its oil and gas properties for financial reporting purposes. All
revenues and expenses derived from third party gas volumes processed through the
Company's natural gas processing facilities have been reported as components of
oil and gas production costs. The capitalized costs of natural gas processing
facilities are included in proved oil and gas properties and are depleted using
the unit-of-production method.
Capitalized costs relating to proved properties are depleted using the
unit-of-production method based on proved reserves as determined by the
Company's engineers. Costs of significant nonproducing properties, wells in the
process of being drilled and development projects are excluded from depletion
until such time as the related project is developed and proved reserves are
established or impairment is determined.
Generally, capitalized costs of individual properties sold or abandoned
are charged to accumulated depletion, depreciation and amortization with the
proceeds from the sales of individual properties credited to property costs; no
gain or loss is recognized until the entire amortization base is sold. However,
gain or loss is recognized from the sale of less than an entire amortization
base if the property costs are significant enough to materially impact the
depletion rate of the remaining properties in the amortization base.
If significant, the Company accrues the estimated future costs to plug
and abandon wells under the unit-of- production method. The charge, if any, is
reflected in the accompanying Consolidated Statements of Operations and
Comprehensive Loss as abandonment expense while the liability is reflected in
the accompanying Consolidated Balance Sheets as other liabilities. Plugging and
abandonment liabilities assumed in a business combination accounted for as a
purchase are recorded at fair value. At December 31, 1999 and 1998, the Company
has recognized plugging and abandonment liabilities of $44.2 million and $44.5
million, respectively.
In accordance with Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of", the Company reviews its long-lived assets to be held and used,
including proved oil and gas properties accounted for under the successful
efforts method of accounting, whenever events or circumstances indicate that the
carrying value of those assets may not be recoverable. An impairment loss is
indicated if the sum of the expected future cash flows is less than the carrying
amount of the assets. In this circumstance, the Company recognizes an impairment
loss for the amount by which the carrying amount of the asset exceeds the
estimated fair value of the asset.
Unproved oil and gas properties that are individually significant are
periodically assessed for impairment by comparing their cost to their estimated
value on a project-by-project basis. The estimated value is affected by the
results of exploration activities, commodity price outlooks, planned future
sales or expiration of all or a portion of such projects. If the quantity of
potential reserves determined by such evaluations are not sufficient to fully
47
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
recover the cost invested in each project, the Company will recognize a loss at
the time of impairment by providing an impairment allowance. The remaining
unproved oil and gas properties are aggregated and an overall impairment
allowance is provided based on the Company's historical experience.
Treasury stock. Treasury stock purchases are recorded at cost. Upon
reissuance, the cost of treasury shares held is reduced by the average purchase
price per share of the aggregate treasury shares held.
Environmental. The Company's environmental expenditures are expensed or
capitalized depending on their future economic benefit. Expenditures that relate
to an existing condition caused by past operations and that have no future
economic benefits are expensed. Liabilities for expenditures of a noncapital
nature are recorded when environmental assessment and/or remediation is probable
and the costs can be reasonably estimated. Such liabilities are generally
undiscounted unless the timing of cash payments for the liability are fixed or
reliably determinable. The Company believes that the costs for compliance with
current environmental laws and regulations have not had and will not have a
material effect on the Company's financial position or results of operations.
Revenue recognition. The Company uses the entitlements method of
accounting for crude oil, natural gas liquids ("NGL") and natural gas revenues.
Sales proceeds in excess of the Company's entitlement are included in other
liabilities and the Company's share of sales taken by others is included in
other assets in the accompanying Consolidated Balance Sheets. As of December 31,
1999 and 1998, entitlement liabilities totaled $15.5 million and $20.6 million,
respectively, and entitlement assets totaled $33.0 million and $38.2 million,
respectively.
Stock-based compensation. The Company accounts for employee stock-based
compensation using the intrinsic value method prescribed by Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees"
("APB 25"). Accordingly, the Company has only adopted the disclosure provisions
of Statement of Financial Accounting Standards No.123, "Accounting for
Stock-Based Compensation" ("SFAS 123"). See Note F for the pro forma disclosures
of compensation expense determined under the fair-value provisions of SFAS 123.
Hedging. The following criteria must be met in order for the Company to
account for a financial instrument as a hedge of an existing asset, liability or
forecasted transaction: an asset, liability or forecasted transaction must exist
that exposes the Company to price, interest rate or foreign exchange rate risk
that is not offset in another asset or liability; the hedging contract must
reduce that price, interest rate or foreign exchange rate risk; and, the
instrument must be designated as a hedge at the inception of the contract and
throughout the hedge period. In order to qualify as a hedge, there must be clear
correlation between changes in the fair value of the financial instrument and
the fair value of the hedged asset, liability or forecasted transaction, such
that changes in the market value of the financial instrument will be offset by
the effect of price, interest rate or foreign exchange rate changes on the
exposed items.
Gains or losses realized from financial instruments that qualify as
hedges are deferred as assets or liabilities until the underlying hedged asset,
liability or transaction monetizes, matures or is otherwise recognized under
generally accepted accounting principles. When recognized, hedge gains and
losses are classified as components of the commodity prices, interest or foreign
exchange rates that the financial instruments hedge. Derivative financial
instruments that do not qualify as hedges are marked-to-market and recorded as
assets or liabilities. Changes in the fair values of such instruments are
recognized as other income or other expense during the periods in which their
fair values change. See Note H for a description of the specific types of
derivative transactions in which the Company participates.
Foreign currency translation. The financial statements of subsidiary
entities whose functional currency is not the United States dollar are
translated to United States dollars as follows: all assets and liabilities at
year-end exchange rates; revenues, costs and expenses at average exchange rates.
Gains and losses from translating non-United States dollar denominated balances
are recorded directly in stockholders' equity. Foreign currency transaction
gains and losses are included in net loss.
48
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
The exchange rates used in the preparation of these consolidated
financial statements appear below:
<TABLE>
December 31,
------------------------
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
U.S. Dollar from Canadian Dollar - Balance sheet............... .6915 .6534 .6997
U.S. Dollar from Canadian Dollar - Statements of operations.... .6700 .6740 N/A
</TABLE>
Reclassifications. Certain reclassifications have been made to the 1998
and 1997 amounts to conform to the 1999 presentation.
NOTE C. Disclosures About Fair Value of Financial Instruments
The following table presents the carrying amounts and estimated fair
values of the Company's financial instruments as of December 31, 1999 and 1998:
<TABLE>
1999 1998
------------------- -----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- ---------- ----------
(in thousands)
<S> <C> <C> <C> <C>
Financial assets:
Cash and cash equivalents................................. $ 34,788 $ 34,788 $ 59,221 $ 59,221
Investment in non-affiliated entity - trading securities.. $ - $ - $ 12,000 $ 12,000
Investment in non-affiliated entity - fair value not
readily determinable.................................... $ 30,000 $ - $ - $ -
Financial liabilities:
Long-term debt:
Practicable to estimate fair value:
Lines of credit...................................... $825,000 $825,000 $1,239,032 $1,239,032
8-7/8% senior notes due 2005......................... $150,000 $149,189 $ 150,000 $ 144,108
8-1/4% senior notes due 2007......................... $149,482 $141,903 $ 149,414 $ 137,826
6-1/2% senior notes due 2008......................... $348,550 $297,313 $ 348,418 $ 284,442
7-1/5% senior notes due 2028......................... $249,909 $187,825 $ 249,908 $ 177,325
Not practicable to estimate fair value:
Other long-term debt................................. $ 22,995 $ - $ 38,493 $ -
Derivative financial instruments, including off-balance
sheet instruments (see Note H):
Interest rate swaps.................................. $ - $ - $ (80) $ 966
Foreign currency agreements.......................... $ (4,168) $ (4,168) $ (15,350) $ (15,350)
Commodity price hedges............................... $ 1,672 $(26,213) $ (41) $ 26,548
BTU swap agreements.................................. $(13,218) $(13,218) $ (15,172) $ (15,172)
Other non-hedge commodity derivatives ............... $(13,259) $(13,259) $ - $ -
</TABLE>
Cash and cash equivalents, accounts receivable, other current assets,
accounts payable and other current liabilities. The carrying amounts approximate
fair value due to the short maturity of these instruments.
Investments in non-affiliated entities. During 1999, the Company received
2,307.693 shares of Prize Energy Corp. ("Prize") six percent convertible
preferred stock ("Prize Preferred"), having a liquidation preference and
estimated fair value of $30.0 million on the date acquired, in partial
consideration for oil and gas properties, gas plants and other assets sold to
Prize (see Note K for information specific to the assets sold to, and the
investment in, Prize). As of December 31, 1999, Prize was a closely held,
non-public entity. As such, the fair value of the Prize Preferred was not
readily determinable. During 1999, the Company earned dividends of 69.23
additional shares of Prize Preferred.
49
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
On February 9, 2000, Prize announced a merger with Vista Energy Resources
Inc., whereby the common stock of the merged Prize entity began to publicly
trade on the American Stock Exchange. Associated therewith, the Company's Prize
Preferred was exchanged for 3,984,197 shares of Prize Series A 6% Convertible
Preferred Stock ("Prize Senior A Preferred") having a liquidation preference and
stated value of $7.81 per share, plus cumulative dividends accrued and unpaid.
Each share of Prize Series A Preferred is convertible, at the option of the
holder, into one share of Prize common stock. Under certain circumstances, Prize
may redeem the Prize Series A Preferred at the stated value per share, unless
the Company exercises its conversion rights. The fair value of the Prize Series
A Preferred is not readily determinable.
As of December 31, 1998, the Company owned three million shares of common
stock of a closely held, non- affiliated, public entity having a fair value of
$12.0 million. The three million shares of common stock were received by the
Company as partial consideration for the sale of an exclusive and irrevocable
option to purchase certain oil and gas properties and other assets of the
Company. During 1999, the Company's investment in the entity was increased to
four million shares of common stock as a result of liquidation damages received
by the Company from the non- affiliated entity (see Note K for information
pertaining to the Company's transactions with the entity). This investment was
classified by the Company as an investment in trading securities. As a result of
declines in the fair value of this investment, other expenses in the
accompanying Consolidated Statements of Operations and Comprehensive Loss for
the years ended December 31, 1999 and 1998, include non-cash mark-to-market
charges of $11.9 million and $.8 million, respectively. The Company sold its
investment in the common stock during 1999.
Long-term debt. The carrying amount of borrowings outstanding under the
Company's line of credit (see Note D for definitions and descriptions of each)
approximates fair value because these instruments bear interest at rates tied to
current market rates. The fair values of each of the senior note issuances were
based on quoted market prices for each of these issues.
It was not practicable to estimate the fair value of certain of the
long-term debt obligations because quoted market prices are not available and
the Company does not have a current borrowing rate which could be used as a
comparable rate for the stated maturities of the obligations.
Interest rate swaps, interest rate cap agreements, foreign currency swap
contracts and commodity price swap and option contracts. The fair value of
interest rate swaps, interest rate cap agreements, foreign currency contracts
and commodity price swap and option contracts are estimated from quotes provided
by the counterparties to these instruments and represent the estimated amounts
that the Company would expect to receive or pay to terminate the agreements. See
Note H for a description of each of these instruments, including whether the
derivative contract qualifies for hedge accounting treatment or is considered a
speculative derivative instrument.
NOTE D. Long-term Debt
December 31,
-----------------------
1999 1998
---------- ----------
(in thousands)
Lines of credit..................................... $ 825,000 $1,249,984
8-7/8% senior notes due 2005........................ 150,000 150,000
8-1/4% senior notes due 2007 (net of discount)...... 149,482 149,414
6-1/2% senior notes due 2008 (net of discount)...... 348,550 348,418
7-1/5% senior notes due 2028 (net of discount)...... 249,909 249,908
Other............................................... 22,995 27,541
--------- ---------
1,745,936 2,175,265
Less current maturities............................. 828 306,521
--------- ---------
$1,745,108 $1,868,744
========= =========
50
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
Maturities of long-term debt at December 31, 1999 are as follows (in
thousands):
2000............................................ $ 828
2001............................................ $ -
2002............................................ $825,000
2003............................................ $ 518
2004............................................ $ 571
Thereafter...................................... $919,019
Lines of credit. As of December 31, 1999, the Company has a credit
facility (the "Credit Facility") with a syndicate of banks (the "Banks") with
commitments aggregating $939.6 million and outstanding borrowings of $825
million. Advances under the Credit Facility are required to be paid no later
than August 7, 2002.
Advances on the Credit Facility bear interest at the option of the
Company, based on (a) the prime rate of NationsBank of Texas, N.A. (8.50 percent
at December 31, 1999), (b) a Eurodollar rate (substantially equal to the London
Interbank Offered Rate ("LIBOR")) adjusted for the reserve requirement as
determined by the Board of Governors of the Federal Reserve System with respect
to transactions in Eurocurrency liabilities ("LIBOR Rate"), or (c) a competitive
bid rate as quoted by the lending banks electing to participate pursuant to a
request by the Company. The interest rate on LIBOR Rate advances includes an
interest rate margin component that is determined by a grid that is based on the
Company's senior unsecured long-term public debt rating. As of December 31,
1999, the future maximum interest rate margin on LIBOR Rate advances is 187.5
basis points.
The Credit Facility contains various debt convenants, the most
restrictive being the maintenance of a ratio of outstanding Company debt to
earnings before interest, depletion, depreciation, amortization, income tax,
exploration and abandonment and other non-cash expenses ("EBITDAX") not to
exceed 4.25 to one through March 31, 2000, and 3.5 to one thereafter. Other
restrictive compliance requirements include limits on the incurrence of
additional indebtedness and certain types of liens and restrictions as to
merger, sale or transfer of assets and transactions without the Banks' consent.
The Company's obligations under the Credit Facility are also guaranteed by
Pioneer Natural Resources USA, Inc. ("Pioneer USA") and certain other United
States subsidiaries, and are secured by a pledge of a portion of the capital
stock of certain non-United States subsidiaries.
During the first quarter of 1999, the Company and the Banks executed
amendments to the Credit Facility that provided for the consolidation of the
Company's $276 million Canadian subsidiary term loan with and into the Credit
Facility. The amendments also provided for a $410 million reduction in loan
commitments by December 31, 1999, an increase in the maximum interest rate
margin on LIBOR Rate advances to 250 basis points including commitment
utilization fees and the debt covenants outlined above. The Company met each of
the requirements of the amended Credit Facility during 1999.
Senior notes. The Company's senior notes are general unsecured
obligations ranking equally in right of payment with all other senior unsecured
indebtedness of the Company and are senior in right of payment to all existing
and future subordinated indebtedness of the Company. In addition, the Company is
a holding company that conducts all of its operations through subsidiaries;
consequently, the senior notes issuances are structurally subordinated to all
obligations of its subsidiaries. Pioneer USA has fully and unconditionally
guaranteed the senior note issuances. Interest on the Company's senior notes is
payable semi-annually.
Extraordinary items. On December 18, 1997, the Company completed a cash
tender offer for two senior subordinated note issuances (the "Subordinated
Notes") assumed as part of the merger with Mesa. During 1997, the Company
redeemed approximately 91 percent of the 11-5/8% senior subordinated discount
notes due 2006 and approximately 98 percent of the 10-5/8% senior subordinated
notes due 2006 (the "10-5/8% Notes") for a purchase price of $829.90 and
51
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
$1,171.40, respectively, per $1,000 tendered plus any interest accrued on the
10-5/8% Notes (the "Tender Offer"). As a result, the Company paid $574.5 million
for the principal amount tendered on the Subordinated Notes, including related
fees, and $15.7 million of accrued interest on the 10-5/8% Notes. As a result of
the Tender Offer, the Company recognized an extraordinary loss on early
extinguishment of debt of $11.9 million (net of a related tax benefit of $6.4
million) during the fourth quarter of 1997. The Company financed the purchase
price of the Subordinated Notes tendered in the offer with borrowings under its
Credit Facility Agreements.
In addition to the extraordinary loss resulting from the Tender Offer,
the accompanying Consolidated Statement of Operations and Comprehensive Loss for
the year ended December 31, 1997 includes a $1.5 million (net of a related tax
benefit of $800 thousand) non-cash charge for an extraordinary loss on the early
extinguishment of debt resulting from the merger of Parker & Parsley and Mesa.
This extraordinary loss relates to capitalized issuance fees associated with
Parker & Parsley's previously existing bank credit facility which was replaced
by the Credit Facility .
Interest expense. The following amounts have been charged to interest
expense for the years ended December 31, 1999, 1998 and 1997:
<TABLE>
1999 1998 1997
-------- -------- ---------
(in thousands)
<S> <C> <C> <C>
Cash payments for interest................................ $150,929 $135,811 $ 65,740
Accretion/amortization of discounts or premiums on loans.. 8,401 10,688 7,348
Amortization of capitalized loan fees..................... 2,686 1,142 1,177
Net change in accruals.................................... 8,328 16,644 3,285
------- ------- -------
$170,344 $164,285 $ 77,550
======= ======= ========
</TABLE>
NOTE E. Related Party Transactions
Activities with affiliated partnerships. The Company, through its
wholly-owned subsidiaries, has in the past sponsored certain affiliated
partnerships, including 35 public and nine private drilling partnerships and
three public income partnerships, all of which were formed primarily for the
purpose of drilling and completing wells or acquiring producing properties. In
accordance with the terms of the partnership agreements and the related tax
partnership agreements of the affiliated partnerships, the Company participated
in the activities of the sponsored partnerships on a promoted basis. In 1992,
the Company discontinued sponsoring public and private oil and gas development
drilling and income partnerships.
During each of 1994, 1993 and 1992, the Company formed a Direct
Investment Partnership for the purpose of permitting selected key employees to
invest directly, on an unpromoted basis, in wells that the Company drills. The
partners in the Direct Investment Partnerships formed in 1994, 1993 and 1992 pay
and receive approximately .337 percent, 1.5375 percent and 1.865 percent,
respectively, of the costs and revenues attributable to the Company's interest
in the wells that such Direct Investment Partnership participates. The Company
discontinued the formation of Direct Investment Partnerships in 1995.
The Company, through a wholly-owned subsidiary, serves as operator of
properties in which it and its affiliated partnerships have an interest.
Accordingly, the Company receives producing well overhead, drilling well
overhead and other fees related to the operation of the properties. The
affiliated partnerships also reimburse the Company for their allocated share of
general and administrative charges.
The activities with affiliated partnerships are summarized for the
following related party transactions for the years ended December 31, 1999, 1998
and 1997:
52
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
<TABLE>
1999 1998 1997
------ ------ ------
(in thousands)
<S> <C> <C> <C>
Receipt of lease operating and supervision charges in accordance
with standard industry operating agreements........................ $9,059 $9,021 $8,547
Reimbursement of general and administrative expenses................. $ 744 $ 739 $1,476
</TABLE>
Prize divestiture. As further disclosed in Note K, the Company sold certain
oil and gas properties, gas plants and other assets to Prize during 1999.
Associated with these transactions, the Company received $245.0 million of
proceeds, including the 2,307.693 shares of Prize Preferred valued at $30.0
million. The board of directors of Prize is comprised of six directors, which
include Mr. Philip P. Smith, the Chief Executive Officer; Mr. Kenneth A. Hersh;
Mr. Lon C. Kile; two members of the Company's executive management committee;
and, a member who is unrelated to the Company. Messrs. Smith and Hersh were
members of the Board of Directors of the Company and resigned their positions
with the Company during the second quarter of 1999. Additionally, Mr. Lon C.
Kile resigned his position as Executive Vice President of the Company to accept
the position of President and Chief Operating Officer of Prize. The sale of the
assets to Prize was initiated through an auction process which, upon receipt of
Prize's initial offer, was placed under the supervision of a special independent
committee (comprised of outside directors unrelated to Prize) of the Company's
Board of Directors. The independent committee reviewed and considered all offers
presented to the Company for the purchase of the assets acquired by Prize. The
Prize offer was approved by the special independent committee as being the best
offer presented (see Notes C and K for information pertaining to the divestiture
of assets to Prize and the Company's investment in Prize).
Consulting fee. Effective January 1, 1999, the Company entered into an
amended and restated agreement with Rainwater, Inc., whereby the Company will
pay Rainwater, Inc. $300,000 per year and reimburse Rainwater, Inc. for certain
expenses in consideration for certain consulting and financial analysis services
provided to the Company by Rainwater, Inc. and its representatives. The term of
this agreement expires on December 31, 2003. During 1999, 1998 and 1997,
consulting and financial analysis services provided to the Company totaled
$325,000, $400,000 and $100,000; respectively, plus expenses. Richard E.
Rainwater, who serves on the Company's Board of Directors, is the sole
shareholder of Rainwater, Inc.
NOTE F. Incentive Plans
Retirement Plans
Deferred compensation retirement plan. Effective August 8, 1997, the
Compensation Committee of the Board of Directors approved a deferred
compensation retirement plan for the officers and certain key employees of the
Company. Each officer and key employee is allowed to contribute up to 25 percent
of their base salary. The Company will then provide a matching contribution of
100 percent of the officer's and key employee's contribution limited to the
first 10 percent of the officer's base salary and eight percent of the key
employee's base salary. The Company's matching contribution vests immediately. A
trust fund has been established by the Company to accumulate the contributions
made under this retirement plan.
In December 1998, the Company received notification that an investment
fund group had acquired beneficial ownership of greater than 20 percent of the
Company's common stock. Pursuant to the then existing provisions within the
Company's deferred compensation retirement plan, if a third party acquired 20
percent or more of the Company's common stock certain change of control
provisions contained within the plan were triggered. Accordingly, in December
1998, the Compensation Committee of the Board of Directors determined that a
change of control had occurred, effective September 30, 1998, under the deferred
compensation retirement plan. Consequently, all of the contributions to the
deferred compensation retirement plan from August 1997 to December 15, 1998 were
immediately vested and distributed.
53
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
401(k) plan. The Pioneer Natural Resources USA, Inc. 401(k) Plan (the
"401(k) Plan") is a defined contribution pension plan established under the
Internal Revenue Code Section 401. All regular full-time and part-time employees
of Pioneer USA are eligible to participate in the 401(k) Plan on the first day
of the month following their date of hire. Participants may contribute an amount
of not less than two percent nor more than 12 percent of their annual salary
into the 401(k) Plan. Each participant's account is credited with the
participant's contributions and an allocation of the 401(k) Plan's earnings.
Participants are immediately fully vested in their account balances.
Matching plan. The Pioneer Natural Resources USA, Inc. Matching Plan (the
"Matching Plan") is a money purchase pension plan which accumulates benefits to
participants. All regular full-time and part-time employees of Pioneer USA
become eligible to participate in the Matching Plan concurrent with their
eligibility to participate in the 401(k) Plan. All Matching Plan contributions
are made in cash by Pioneer USA in amounts equal to 200 percent of a
participant's contributions to the 401(k) Plan that are not in excess of five
percent of the participant's basic compensation (the "Matching Contribution").
Each participant's account is credited with their Matching Contribution and an
allocation of Matching Plan earnings. Participants proportionately vest in their
account balances over a four year period, at the end of which they are fully
vested in their account balances. During the years ended December 31, 1999, 1998
and 1997, the Company recognized compensation expense of $508 thousand, $742
thousand and $497 thousand, respectively, as a result of Matching Contributions.
Long-term incentive plan. In August 1997, the Company's stockholders
approved a new long-term incentive plan (the "Long-Term Incentive Plan"), which
provides for the granting of incentive awards in the form of stock options,
stock appreciation rights, performance units and restricted stock to directors,
officers and employees of the Company. The Long-Term Incentive Plan provides for
the issuance of a maximum number of shares of common stock equal to 10 percent
of the total number of shares of common stock equivalents outstanding minus the
total number of shares of common stock subject to outstanding awards on the date
of calculation under any stock-based plan for the directors, officers or
employees of the Company.
Pursuant to the provisions within the Company's Long-Term Incentive Plan,
if a third party acquires 40 percent or more of the Company's common stock,
certain change of control provisions contained within the plan are triggered. In
December 1998, the Compensation Committee of the Board of Directors determined
that a change of control had occurred, effective September 30, 1998, under the
Long-Term Incentive Plan. Consequently, all awards granted under the Long-Term
Incentive Plan since its inception in August 1997 through September 30, 1998
were immediately vested and any restrictions were canceled.
The following table calculates the number of shares or options available
for grant under the Company's Long- Term Incentive Plan as of December 31, 1999
and 1998:
<TABLE>
December 31,
1999 1998
----------- --------------
<S> <C> <C>
Shares outstanding.......................................................... 100,339,583 100,296,223
Options outstanding......................................................... 4,832,412 2,939,183
----------- -----------
105,171,995 103,235,406
=========== ===========
Maximum shares/options allowed under the Long-Term Incentive Plan........... 10,517,200 10,323,541
Less: Outstanding awards under Long-Term Incentive Plan.................... (4,832,412) (2,939,183)
Outstanding options under Mesa 1991 stock option plan................ (149,547) (407,284)
Outstanding options under Mesa 1996 incentive plan................... (372,855) (422,854)
Outstanding options under Parker & Parsley long-term incentive plan.. (887,075) (810,709)
----------- -----------
Shares/options available for future grant................................... 4,275,311 5,743,511
=========== ===========
</TABLE>
54
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
Restricted stock awards
Non-employee directors. On May 20, 1999, the Company's Long-Term
Incentive Plan was amended to eliminate the automatic award of restricted stock
to non-employee directors in payment of their annual retainer fees. The effect
of the amendment was to provide the Compensation Committee of the Board of
Directors with the authority to determine what awards, if any, non-employee
directors will receive and what the terms of those awards will be and,
alternatively, to award stock options to non-employee directors in payment of
their annual retainer fees. During 1999, the Company awarded stock options to
the non-employee directors in payment of their annual retainer fees. The options
awarded were determined by dividing the annual retainer fees by the value of one
option on the last business day of the month in which the fee was paid. The
option values were determined using the Black-Scholes method (see "Stock Option
Awards", below). Prior to this amendment, on the last business day of the month
in which the annual meeting of the stockholders of the Company was held, each
non-employee director automatically received an award of common stock equal to
50 percent of their annual retainer fee. These awards were made in lieu of an
amount of cash equal to 50 percent of the annual retainer fee. In May 1998 and
August 1997, the Company issued an aggregate 17,306 shares and 5,939 shares,
respectively, to non-employee directors pursuant to this arrangement.The shares
of common stock awarded pursuant to the Long-Term Incentive Plan are subject to
transfer restrictions that lapse on the first anniversary of the date of the
award.
Officers and key employees. The Company, at its sole discretion, may pay
annual bonuses awarded to selected officers and key employees either 100 percent
in cash or partially in cash and partially in the form of restricted stock
awards under the Long-Term Incentive Plan. The Company has established target
bonus levels for each officer and key employee. Based upon Company and
individual performance during the year, each officer or key employee has the
potential to earn more or less than their target bonus level. The bonus awards
are determined in the quarter following the Company's December 31 year-end.
During 1997, the Company awarded restricted stock pursuant to this program. The
1997 awards were limited to one-half of each officer's or key employee's target
bonus level, and the remainder of the officer's or key employee's annual bonus
was paid in cash. The number of shares of restricted stock that were awarded
pursuant to the annual bonus program were based on the closing sales price of
the Company's common stock on the day immediately preceding the date of the
award. Ownership of the restricted stock awarded vested one year after the date
it was issued, subject to transfer restrictions that lapsed on one-third of the
shares on each of the first, second and third anniversaries of the date of
grant. Each recipient of restricted stock also received an amount of cash equal
to the estimated federal income taxes payable as a result of the receipt of such
award. On February 9, 1998, the Company awarded an aggregate of 81,300 shares of
restricted stock at a price of $22.375 pursuant to the 1997 annual bonus
program. The Company elected not to award any restricted stock in conjunction
with the 1999 or 1998 annual bonus programs.
During 1998 and 1997, the Company made other Long-Term Incentive Plan
awards of 38,480 and 470,975 shares, respectively, to certain officers and key
employees. The shares awarded are subject to vesting period and transfer
restrictions.
Stock Option Awards
The Company has a program of awarding semi-annual stock options to its
officers and employees and annual stock options to its directors, as part of
their annual compensation. This program provides for annual awards at an
exercise price based upon the closing sales price of the Company's common stock
on the day prior to the date of grant. The awards vest over an 18 month or three
year schedule and provide a five year exercise period from each vesting date.
The Company granted 1,985,193; 2,146,553 and 1,716,625 options under the
Long-Term Incentive Plan during 1999, 1998 and 1997, respectively.
55
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
Other stock based plans. Prior to the merger with Mesa, both Parker &
Parsley and Mesa had long-term incentive plans (Parker & Parsley Long-Term
Incentive Plan, 1991 Stock Option Plan of Mesa and the 1996 Incentive Plan of
Mesa) in place that allowed Parker & Parsley and Mesa to grant incentive awards
similar to the provisions of the Long-Term Incentive Plan. Upon consummation of
the merger between Parker & Parsley and Mesa, all awards under these plans were
assumed by the Company with the provision that no additional awards be granted
under these plans.
The information presented in the remainder of this footnote represents
the awards granted under the Long-Term Incentive Plan since its approval in
August 1997, the awards granted in 1997 under the Parker & Parsley Long-Term
Incentive Plan, and the assumption in August 1997 of the outstanding option
awards granted under the 1991 Stock Option Plan of Mesa and the 1996 Incentive
Plan of Mesa.
Restricted stock awards. The following table reflects the outstanding
restricted stock awards and activity related thereto for 1999, 1998 and 1997:
<TABLE>
For the Year Ended For the Year Ended For the Year Ended
December 31, 1999 December 31, 1998 December 31, 1997
----------------------- ----------------------- --------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Shares Price of Shares Price of Shares Price
--------- --------- --------- --------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Restricted stock awards:
Outstanding, beginning of year.. - $ - 476,914 $ 37.88 79,819 $ 23.35
Shares granted.................. 6,200 $ 29.56 137,086 $ 21.13 506,786 $ 37.43
Shares forfeited................ - $ - (12,585) $ 35.67 - $ -
Lapse of restrictions........... (6,200) $ 29.56 (601,415) $ 34.11 (109,691) $ 25.66
--------- --------- ---------
Outstanding, end of year........ - $ - - $ - 476,914 $ 37.88
========= ========= =========
</TABLE>
Stock option awards. The Company applies APB 25 and related
interpretations in accounting for its stock option awards. Accordingly, no
compensation expense has been recognized for its stock option awards. If
compensation expense for the stock option awards had been determined consistent
with SFAS 123, the Company's net losses and net losses per share would have been
adjusted to the pro forma amounts indicated below:
For the Year Ended December 31,
---------------------------------
1999 1998 1997
--------- --------- ---------
(in thousands, except per share amounts)
Net loss................................ $(25,269) $(775,349) $(893,729)
Basic and diluted net loss per share.... $ (.25) $ (7.75) $ (17.20)
Under SFAS 123, the fair value of each stock option grant is estimated on
the date of grant using the Black- Scholes option pricing model with the
following weighted average assumptions used for grants in 1999, 1998 and 1997:
For the Year Ended December 31,
---------------------------
1999 1998 1997
------- ------- -------
Risk-free interest rate.................... 6.59% 5.45% 5.72%
Expected life.............................. 6 years 6 years 7 years
Expected volatility........................ 48% 36% 36%
Expected dividend yield.................... - .56% .30%
56
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
A summary of the Company's stock option plans as of December 31, 1999,
1998 and 1997, and changes during the years ended on those dates, are presented
below:
<TABLE>
For the Year Ended For the Year Ended For the Year Ended
December 31, 1999 December 31, 1998 December 31, 1997
----------------------- ------------------------ ---------------------
Weighted Weighted Weighted
Number Average Number Average Number Average
of Shares Price of Shares Price of Shares Price
---------- --------- ---------- --------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Non-statutory stock options:
Outstanding, beginning of year....... 4,580,030 $ 24.83 3,541,145 $ 31.63 1,362,629 $ 24.04
Options granted.................... 1,945,135 $ 9.10 2,146,553 $ 19.22 1,744,704 $ 34.00
Options assumed.................... - $ - - $ - 928,478 $ 33.97
Options forfeited.................. (256,576) $ 38.29 (1,106,835) $ 35.75 (1,500) $ 21.33
Options exercised.................. (26,700) $ 5.81 (833) $ 14.25 (493,166) $ 23.45
---------- ---------- ----------
Outstanding, end of year............. 6,241,889 $ 19.45 4,580,030 $ 24.83 3,541,145 $ 31.63
========== ========== ==========
Exercisable at end of year........... 4,038,341 $ 24.62 3,937,113 $ 26.60 1,824,520 $ 29.37
========== ========== ==========
Weighted average fair value of options
granted during the year.............. $ 5.14 $ 8.21 $ 16.10
========= ========= =========
</TABLE>
The following table summarizes information about the Company's stock
options outstanding at December 31, 1999:
<TABLE>
Options Outstanding Options Exercisable
----------------------------------------------------- -------------------------------------
Number Weighted Average Weighted Weighted
Range of Outstanding at Remaining Average Number Exercisable Average
Exercise Prices December 31, 1999 Contractual Life Exercise Price at December 31, 1999 Exercise Price
- --------------- ----------------- ---------------- -------------- -------------------- --------------
<S> <C> <C> <C> <C> <C>
$ 5-11 1,251,868 6.4 years $ 7.59 40,210 $ 10.82
$ 12-18 2,114,621 5.0 years $ 14.76 1,122,731 $ 16.28
$ 19-26 844,628 3.7 years $ 22.51 844,628 $ 22.51
$ 27-30 1,932,370 3.5 years $ 29.65 1,932,370 $ 29.65
$ 31-82 98,402 4.4 years $ 44.86 98,402 $ 44.86
----------- ----------
6,241,889 4,038,341
=========== ==========
</TABLE>
During 1999, the Company recognized $.2 million of costs related to its
incentive plans in other expense. The Company recognized $3.9 million and $3.3
million in general and administrative compensation expense related to its
Incentive Plans during 1998 and 1997, respectively. During 1998, the Company
also recognized $9.6 million in other expense related to restricted stock awards
that were immediately vested as a result of the Long-Term Incentive Plan change
in control provisions and $3.1 million of reorganization costs related to its
Incentive Plans.
NOTE G. Commitments and Contingencies
Severance agreements. The Company has entered into severance agreements
with its officers, subsidiary company officers and certain key employees.
Salaries and bonuses for the Company's officers are set independent of this
agreement by the Compensation Committee for the parent company officers and the
Management Committee for subsidiary company officers and key employees. These
committees can grant increases or reductions to base salary at their discretion.
The current annual salaries for the parent company officers, the subsidiary
company officers and key employees covered under such agreements total
approximately $8.2 million.
Either the Company or the officer/key employee may terminate the
officer's or key employee's employment under the severance agreement at any
time. The Company must pay the officer or key employee an amount equal to one
year's base salary if employment is terminated because of death, disability, or
normal retirement. The Company must pay the officer or key employee an amount
57
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
equal to one year's base salary and continue health insurance for the officer or
key employee and his or her immediate family for one year if the Company
terminates employment without cause or if the officer or key employee terminates
employment with good reason, which occurs when reductions in the officer's or
key employee's base annual salary exceed specified limits or if, in the case of
officers, the officer is demoted to an officer position junior to their current
officer position or to a non-officer position. If within one year after a change
in control of the Company, the Company terminates the officer or key employee
without cause or if the officer or key employee terminates employment with good
reason, the Company must pay parent company officers an amount equal to 2.99
times the sum of the officer's base salary plus target bonus for the year and
subsidiary company officers and key employees an amount equal to two times the
officer's or key employee's base salary and continue health insurance for the
officer or key employee and his immediate family for one year. If the officer or
key employee terminates employment with the Company without good reason between
six months and one year after a change in control, or at any time within one
year after a change in control if the officer or key employee is required to
move, then the Company must pay the officer or key employee one year's base
salary and continue health insurance for the officer or key employee and his or
her immediate family for one year. Officers and key employees are also entitled
to additional payments for certain tax liabilities that may apply to severance
payments following a change in control.
Indemnifications. The Company has indemnified its directors and certain
of its officers, employees and agents with respect to claims and damages arising
from acts or omissions taken in such capacity, as well as with respect to
certain litigation.
Legal actions. The Company is party to various legal actions incidental
to its business, including, but not limited to, the proceedings described below.
The majority of these lawsuits primarily involve claims for damages arising from
oil and gas leases and ownership interest disputes. The Company believes that
the ultimate disposition of these legal actions will not have a material adverse
effect on the Company's consolidated financial position, liquidity, capital
resources or future results of operations. The Company will continue to evaluate
its litigation matters on a quarter-by- quarter basis and will adjust the
litigation reserve as appropriate to reflect the then current status of its
litigation.
Masterson. In February 1992, the current lessors of an oil and gas lease
(the "Gas Lease") dated April 30, 1955, between R.B. Masterson et al., as
lessor, and Colorado Interstate Gas Company ("CIG"), as lessee, sued CIG in
Federal District Court in Amarillo, Texas, claiming that CIG had underpaid
royalties due under the Gas Lease. Under the agreements with CIG, the Company,
as successor to Mesa, has an entitlement to gas produced from the Gas Lease. In
August 1992, CIG filed a third-party complaint against the Company for any such
royalty underpayment which may be allocable to the Company. Plaintiffs alleged
that the underpayment was the result of CIG's use of an improper gas sales price
upon which to calculate royalties and that the proper price should have been
determined pursuant to a "favored-nations" clause in a July 1, 1967, amendment
to the Gas Lease. The plaintiffs also sought a declaration by the court as to
the proper price to be used for calculating future royalties.
The plaintiffs alleged royalty underpayments of approximately $500
million (including interest at 10 percent) dating from July 1, 1967. In March
1995, the court made certain pretrial rulings that eliminated approximately $400
million of the plaintiff's claims (which related to periods prior to October 1,
1989), but which also reduced a number of the Company's defenses. The Company
and CIG filed stipulations with the court whereby the Company would have been
liable for between 50 percent and 60 percent, depending on the time period
covered, of an adverse judgment against CIG or post-February 1988 underpayments
of royalties.
On March 22, 1995, a jury trial began and on May 4, 1995, the jury
returned its verdict. Among its findings, the jury determined that CIG had
underpaid royalties for the period after September 30, 1989, in the amount of
approximately $140,000. Although the plaintiffs argued that the
"favored-nations" clause entitled them to be paid for all of their gas at the
highest price voluntarily paid by CIG to any other lessor, the jury determined
that the plaintiffs were estopped from claiming that the "favored-nations"
58
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
clause provides for other than a pricing-scheme to pricing- scheme comparison.
In light of this determination, and the plaintiff's stipulation that a
pricing-scheme to pricing-scheme comparison would not result in any "trigger
prices" or damages, defendants asked the court for a judgment that plaintiffs
take nothing. The court, on June 7, 1995, entered final judgment that plaintiffs
recover no monetary damages. The plaintiffs filed a motion for new trial on June
22, 1995. The court, on July 18, 1997, denied plaintiffs' motion. The plaintiffs
have appealed to the Fifth Circuit Court of Appeals, where oral arguments were
heard in December 1998. The Court's decision regarding this litigation could be
announced at any time.
On June 7, 1996, the plaintiffs filed a separate suit against CIG and the
Company in state court in Amarillo, Texas, similarly claiming underpayment of
royalties under the "favored-nations" clause, but based upon the above-
described pricing-scheme to pricing-scheme comparison on a well-by-well monthly
basis. The plaintiffs also claim underpayment of royalties since June 7, 1995,
under the "favored-nations" clause based upon either the pricing-scheme to
pricing-scheme method or their previously alleged higher price method. The
Company believes it has several defenses to this action and intends to contest
it vigorously. The Company has not yet determined the amount of damages, if any,
that would be payable if such action was determined adversely to the Company.
The federal court in the above-referenced first suit issued an order on
July 29, 1996, which stayed the state suit pending the plaintiffs' resolution of
the first suit.
Based on the jury verdict and final judgment, the Company does not
currently expect the ultimate resolution of either of these lawsuits to have a
material adverse effect on its financial position or results of operations.
Kansas ad valorem tax. The Natural Gas Policy Act of 1978 ("NGPA") allows
a "severance, production or similar" tax to be included as an add-on, over and
above the maximum lawful price for natural gas. Based on a Federal Energy
Regulatory Commission ("FERC") ruling that Kansas ad valorem tax was such a tax,
Mesa collected the Kansas ad valorem tax in addition to the otherwise maximum
lawful price. The FERC's ruling was appealed to the United States Court of
Appeals for the District of Columbia ("D.C. Circuit"), which held in June 1988
that the FERC failed to provide a reasoned basis for its findings and remanded
the case to the FERC for further consideration.
On December 1, 1993, the FERC issued an order reversing its prior ruling,
but limiting the effect of its decision to Kansas ad valorem taxes for sales
made on or after June 28, 1988. The FERC clarified the effective date of its
decision by an order dated May 18, 1994. The order clarified that the effective
date applies to tax bills rendered after June 28, 1988, not sales made on or
after that date. Numerous parties filed appeals on the FERC's action in the D.C.
Circuit. Various natural gas producers challenged the FERC's orders on two
grounds: (1) that the Kansas ad valorem tax, properly understood, does qualify
for reimbursement under the NGPA; and (2) the FERC's ruling should, in any
event, have been applied prospectively. Other parties challenged the FERC's
orders on the grounds that the FERC's ruling should have been applied
retroactively to December 1, 1978, the date of the enactment of the NGPA and
producers should have been required to pay refunds accordingly.
The D.C. Circuit issued its decision on August 2, 1996, which holds that
producers must make refunds of all Kansas ad valorem tax collected with respect
to production since October 4, 1983 as opposed to June 28, 1988. Petitions for
rehearing were denied on November 6, 1996. Various natural gas producers
subsequently filed a petition for writ of certiori with the United States
Supreme Court seeking to limit the scope of the potential refunds to tax bills
rendered on or after June 28, 1988 (the effective date originally selected by
the FERC). Williams Natural Gas Company filed a cross-petition for certiori
seeking to impose refund liability back to December 1, 1978. Both petitions were
denied on May 12, 1997.
The Company and other producers filed petitions for adjustment with the
FERC on June 24, 1997. The Company is seeking waiver or set-off from FERC with
respect to that portion of the refund associated with (i) non- recoupable
royalties, (ii) non-recoupable Kansas property taxes based, in part, upon the
higher prices collected, and (iii)
59
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
interest for all periods. On September 10, 1997, FERC denied this request, and
on October 10, 1997, the Company and other producers filed a request for
rehearing. Pipelines were given until November 10, 1997 to file claims on
refunds sought from producers and refunds totaling approximately $30 million
were made against the Company. The Company is unable at this time to predict the
final outcome of this matter or the amount, if any, that will ultimately be
refunded. As of December 31, 1999 and 1998, the Company had set aside $31.3
million and $29.7 million, respectively, including accrued interest, in an
escrow account and had corresponding obligations for this litigation recorded in
other current liabilities in the accompanying Consolidated Balance Sheets. In
addition, during 1998, the Company paid $1.4 million to a pipeline in settlement
of the pipeline's share of the total initial obligation.
Lease agreements. The Company leases equipment and office facilities
under noncancellable operating leases on which rental expense for the years
ended December 31, 1999, 1998 and 1997 was approximately $6.9 million, $8.9
million and $3.7 million, respectively. Future minimum lease commitments under
noncancellable operating leases at December 31, 1999 are as follows (in
thousands):
2000......................................... $ 6,765
2001......................................... $ 5,684
2002......................................... $ 4,517
2003......................................... $ 4,070
2004......................................... $ 3,549
Thereafter................................... $ 3,388
NOTE H. Derivative Financial Instruments
The Company uses derivative financial instruments to manage interest
rate, foreign exchange rate and commodity price risks. The Company is exposed to
credit losses in the event of nonperformance by the counterparties. The Company
anticipates, however, that such counterparties will be able to fully satisfy
their obligations under the contracts. The Company does not obtain collateral or
other security to support financial instruments subject to credit risk but
monitors the credit standing of the counterparties.
The Company is a party to certain derivative financial instruments that
do not qualify for hedge accounting treatment. Such instruments are
marked-to-market at the end of each reporting period during their respective
lives. The associated effects on the Company's results of operations in future
periods could be significant. Those instruments not qualifying for hedge
accounting are designated under the heading "Mark-to-Market Derivatives" below.
Hedge Derivatives
Interest rate swap agreements. During 1996, the Company entered into a
series of interest rate swap agreements for an aggregate amount of $150 million
with four counterparties. These agreements, which had a term of three years,
effectively converted a portion of the Company's fixed-rate borrowings into
floating-rate obligations. The weighted average fixed rate received by the
Company over the term of these agreements was 6.62 percent, while the weighted
average variable rate paid by the Company for the years ended December 31, 1999,
1998 and 1997 was 5.16 percent, 5.75 percent and 5.78 percent, respectively. The
interest rate swap agreements expired in May and June, 1999. The Company was
also party to an interest rate swap agreement for an aggregate amount of $250
million with one counterparty. This agreement, which expired in August 1998,
effectively converted a portion of the Company's floating- rate borrowings into
fixed-rate obligations. The effect of this agreement was to provide the Company
with an interest rate of 6.23 percent on $250 million in nominal principal
amount for the term of the agreement. The accompanying Consolidated Statements
of Operations and Comprehensive Loss for the years ended December 31, 1999, 1998
and 1997 include a reduction in interest expense of $849 thousand, $356 thousand
and $847 thousand, respectively, associated with these rate swap agreements.
60
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
During 1997, the Company entered into two agreements with a counterparty
that obligated the Company to sell United States Treasury securities at a
designated point in the future. The face amount of the United States Treasury
securities was $300 million at interest rates ranging from 6.05 percent to 6.33
percent. These agreements effectively converted a portion of the Company's
floating-rate borrowings into fixed-rate obligations. In January 1998, the
Company terminated these agreements at a cost of $16.8 million. This amount is
being amortized over the life of the Company's Credit Facility.
Commodity hedges. The Company utilizes various swap and option contracts
to (i) reduce the effect of the volatility of price changes on the commodities
the Company produces and sells, (ii) support the Company's annual capital
budgeting and expenditure plans and (iii) lock in prices to protect the
economics related to certain capital projects.
Crude Oil. All material sales contracts governing the Company's oil
production have been tied directly or indirectly to the New York Mercantile
Exchange ("NYMEX") prices.
The following table sets forth the Company's outstanding oil hedge
contracts as of December 31, 1999. During the first quarter of 2000, the Company
terminated June 2000 through December 2000 swap contracts for notional volumes
of 9,000 Bbls per day and the 2001 collar contracts (and associated sold puts)
for notional volumes of 8,000 Bbls per day, at a total cost of $16.1 million.
Including these costs, the Company has deferred oil hedge losses of $14.3
million and $3.7 million that will be recognized during 2000 and 2001,
respectively.
<TABLE>
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
------------- ------------- ------------ -------------- -------------
<S> <C> <C> <C> <C> <C>
Daily oil production:
2000 - Swap Contracts
Volume (Bbl).................. 9,626 9,538 9,478 9,435 9,519
Price per Bbl................. $ 16.50 $ 16.51 $ 16.51 $ 16.52 $ 16.51
2000 - Collar Contracts *
Volume (Bbl).................. 7,713 7,714 7,898 7,977 7,826
Price per Bbl................. $17.45-$20.66 $17.44-$20.66 $17.48-$20.71 $17.50-$20.74 $17.47-$20.69
2001 - Collar Contracts**
Volume (Bbl).................. 8,000 8,000 8,000 8,000 8,000
Price per Bbl................. $18.44-$21.57 $18.44-$21.57 $18.44-$21.57 $18.44-$21.57 $18.44-$21.57
</TABLE>
- -------------
* Concurrent with the Company's purchase of the year 2000 collar contracts,
the Company sold year 2000 put contracts to the counterparties for average
notional contract volumes of 6,997 Bbls per day at a weighted average
index price of $14.29 per Bbl. Consequently, if the weighted average year
2000 index price falls below $14.29 per Bbl, the Company will receive the
weighted average index price for the notional contract volumes, plus $3.18
per Bbl. The counterparties have the contractual right to extend contracts
for notional volumes of 5,000 Bbls per day through year 2001 at weighted
average per Bbl strike prices of $17.00 - $20.09 for the collar contracts
and $14.00 for the put contracts.
** Concurrent with the Company's purchase of the year 2001 collar contracts,
the Company sold 2001 put contracts to the counterparties for equal
notional contract volumes at a weighted average index price of $15.44 per
Bbl. Consequently, if the weighted average year 2001 index price falls
below $15.44 per Bbl, the Company will receive the weighted average index
price for the notional contract volumes, plus $3.00 per Bbl.
61
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
The Company reports average oil prices per Bbl including the effects of
oil quality, gathering and transportation costs and the net effect of the oil
hedges. The following table sets forth the Company's oil prices, both realized
(excluding hedge results) and reported, and the net effects of settlements of
oil price hedges to revenue:
Year Ended December 31,
---------------------------
1999 1998 1997
------- ------- -------
Average price reported per Bbl.................. $ 15.36 $ 13.08 $ 18.51
Average price realized per Bbl.................. $ 16.23 $ 11.93 $ 19.09
Addition (reduction) to revenue (in millions)... $ (13.4) $ 24.8 $ (7.9)
Natural Gas Liquids. During the years ended December 31, 1999 and 1998,
the Company did not enter into any natural gas liquids hedge contracts. The
Company reported and realized an average natural gas liquids price of $11.64 per
Bbl during the year ended December 31, 1999. During the year ended December 31,
1998, the Company reported an average natural gas liquids price of $8.90 per
Bbl. During the year ended December 31, 1997, the Company reported average
natural gas liquids prices of $12.59 per Bbl while realizing an average price
for physical sales (excluding hedging results) of $12.61 per Bbl and recorded a
net decrease to natural gas liquids revenue of $77,600.
Natural Gas. The Company employs a policy of hedging a portion of its gas
production based on the index price upon which the gas is actually sold in order
to mitigate the basis risk between NYMEX prices and actual index prices.
The following table sets forth the Company's outstanding gas hedge
contracts as of December 31, 1999. Prices included herein represent the
Company's weighted average index price per MMBtu. During the first quarter of
2000, the Company terminated Collar Contracts (and associated sold puts) for
notional volumes of 45,000 MMBtu per day for the nine months ended December 31,
2000, and 60,000 MMBtu per day for the year 2001, at a cost of $4.6 million.
Including this cost, the Company has deferred gas hedge losses of $4.1 million
and $2.5 million that will be recognized during 2000 and 2001, respectively. In
addition to the hedge contracts shown below, certain counterparties have the
contractual right to sell year 2001, 2002, and 2003 swap contracts to the
Company for notional contract volumes of 49,223; 12,500; and 10,000 Mcf per day,
respectively, at weighted average strike prices of $2.21; $2.52; and $2.58 per
MMBtu, respectively.
<TABLE>
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Daily gas production:
2000 - Swap Contracts
Volume (Mcf).......................... 1,318 - - - 328
Index price per MMBtu................. $ 3.00 $ - $ - $ - $ 3.00
2000 - Collar Contracts*
Volume (Mcf).......................... 68,059 103,223 103,223 100,571 93,814
Index price per MMBtu................. $2.07-$2.61 $2.07-$2.61 $2.07-$2.61 $2.07-$2.63 $2.07-$2.62
2001 - Collar Contracts**
Volume (Mcf).......................... 60,000 60,000 60,000 60,000 60,000
Index price per MMBtu................. $2.25-$2.74 $2.24-$2.58 $2.24-$2.58 $2.25-$2.68 $2.25-$2.64
2002 - Swap Contracts
Volume (Mcf).......................... 10,000 10,000 10,000 10,000 10,000
Index price per MMBtu................. $ 2.42 $ 2.42 $ 2.42 $ 2.42 $ 2.42
</TABLE>
62
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
- -------------
* Concurrent with the Company's purchase of the year 2000 collar contracts,
the Company sold year 2000 put contracts to the counterparties for an
equal volume at a weighted average index price of $1.78 per MMBtu.
Consequently, if the weighted average year 2000 index price falls below
$1.78 per MMBtu, the Company will receive the weighted average index price
for the notional contract volumes, plus approximately $.29 per MMBtu.
54,482 MMBtu per day of the year 2000 collar contracts and associated put
contracts are extendable for one year at the option of the counterparties
at weighted average per MMBtu prices of $2.09-$2.71 for the collar
contracts and $1.80 for the put contracts.
** Concurrent with the Company's purchase of the year 2001 collar contracts,
the Company sold year 2001 put contracts to the counterparties for an
equal volume at a weighted average index price of $1.95 per MMBtu.
Consequently, if the weighted average year 2001 index price falls below
$1.95 per MMBtu, the Company will receive the weighted average index price
for the notional contract volumes, plus approximately $.30 per MMBtu. The
year 2001 collar contracts and associated put contracts are extendable for
one year at the option of the counterparties for notional contract volumes
of 60,000 MMBtu per day at weighted average per MMBtu prices of
$2.25-$2.64 for the collar contracts and $1.95 for the put contracts.
The Company reports average gas prices per Mcf including the effects of
Btu content, gathering and transportation costs, gas processing and shrinkage
and the net effect of the gas hedges. The following table sets forth the
Company's gas prices, both realized (excluding hedge results) and reported, and
the net effects of settlements of gas price hedges to revenue:
Year Ended December 31,
------------------------
1999 1998 1997
------ ------ ------
Average price reported per Mcf................... $ 1.90 $ 1.82 $ 2.20
Average price realized per Mcf................... $ 1.84 $ 1.80 $ 2.41
Addition/(reduction) to revenue (in millions).... $ 9.4 $ 3.6 $(21.9)
Mark-to-Market Derivatives
As of December 31, 1999 and 1998, the Company has recognized other
current liabilities in the accompanying Consolidated Balance Sheets of $15.9
million and $3.4 million, respectively, associated with non-hedge mark-to-market
derivatives. The following descriptions provide information pertaining to
non-hedge mark-to-market derivatives that the Company was a party to as of
December 31, 1999 and 1998. See Note C. "Disclosures About Fair Value of
Financial Instruments" for information regarding the Company's determination of
the fair values of derivative financial instruments.
Interest rate cap. At December 31, 1998, the Company was party to an
interest rate cap agreement with a counterparty which capped the Canadian dollar
banker's acceptance rate at 8.00 percent on a notional amount of $80 million
Canadian dollars. The agreement expired in August 1999. Under the agreement, the
Company paid the counterparty a fixed amount in Canadian dollars on a quarterly
basis.
Foreign currency agreements. The Company has a series of forward foreign
exchange swap agreements to exchange Canadian dollars for United States dollars
at future dates for a fixed amount of the first currency. As of December 31,
1999 and 1998, the United States dollar equivalent of foreign currency exchange
swap agreements approximated $72 million and $144 million, respectively. These
contracts originated with the Company's acquisition of Chauvco in December 1997.
As these contracts do not qualify as hedges, the Company recorded non-cash
mark-to- market adjustments to decrease the associated contract liabilities by
$5.9 million during 1999 and to increase the associated liabilities by $14.7
million during 1998. These contracts will continue to be marked-to-market until
they mature at various dates in the fourth quarter of 2000. The related effects
on the Company's results of operations in future periods could be significant.
63
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
BTU swap agreements. During 1996, Mesa entered into BTU swap agreements
covering 13,036 MMBtu per day from January 1, 1997 through December 31, 2004.
Under the terms of these agreements, the Company received a premium of $.52 per
MMBtu over market natural gas prices from January 1, 1997 through December 31,
1998. Additionally, the Company receives 10 percent of the NYMEX oil price for
the volumes covered for a six-year period ending December 31, 2004. As these
derivative contracts do not qualify as hedges, the Company recorded non-cash
mark-to-market adjustments to reduce the carrying value of the BTU swap
liability by $.2 million during 1999 and, during 1998 and 1997, to increase the
BTU swap liability by $5.8 million and $5.2 million, respectively. These
contracts will continue to be marked-to-market at the end of each reporting
period during their respective lives. The related effects on the Company's
results of operations in future periods could be significant.
Other non-hedge commodity derivatives. During 1999, the Company sold call
options that provide the counterparties an option to exercise call provisions on
10,000 barrels per day of oil, at a strike price of $20.00 per barrel, for a
twenty-one month period that began on April 1, 1999 and ends on December 31,
2000, or to exercise call provisions over that same time period on 100,000 MMBtu
per day of natural gas, at a weighted average strike price of $2.75 per MMBtu.
These contracts do not qualify for hedge accounting treatment. Other expenses in
the accompanying Consolidated Statement of Operations and Comprehensive Loss for
the year ended December 31, 1999 includes $21.2 million of non-cash
mark-to-market charges associated with these call options.
NOTE I. Sales to Major Customers
The Company's share of oil and gas production is sold to various
purchasers. The Company is of the opinion that the loss of any one purchaser
would not have an adverse effect on the ability of the Company to sell its oil
and gas production.
The following customers individually accounted for 10 percent or more of
the consolidated oil, NGL and gas revenues of the Company during the years ended
December 31, 1999, 1998 or 1997:
Percentage of Consolidated
Customer Oil, NGL and Gas Revenues
-------- ---------------------------
1999 1998 1997
------ ------ -----
Williams Energy Services................... 11 10 -
Genesis Crude Oil, L.P..................... 2 10 23
Mobil Oil Corporation...................... 7 7 16
Western Gas Resources...................... 1 5 10
Producers Energy Marketing, LLC (a)........ - 3 11
- -------------
(a) Producers Energy Marketing, LLC ("ProEnergy") is a natural gas marketing
company in which the Company owned a noncontrolling member interest of
approximately 10 percent during 1997. Effective January 1, 1998, the
Company withdrew as a member of ProEnergy.
At December 31, 1999, the amounts receivable from Williams Energy
Services, Genesis Crude Oil, L.P., Mobil Oil Corporation and Western Gas
Resources were $15.4 million, $.1 million, $6.0 million and $.1 million,
respectively, which are included in the caption "Accounts receivable - trade" in
the accompanying Consolidated Balance Sheet.
NOTE J. Other Revenue
During December 1998, the Company announced the sale to a third party of
an exclusive and irrevocable option to purchase certain oil and gas properties
and other assets of the Company. In consideration for the option, the third
64
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
party paid a fee of $41.3 million to the Company, consisting of $29.3 million of
cash and the third party's common stock that was then valued at $12.0 million.
The third party's option lapsed by its terms during the first quarter of 1999.
During the second quarter of 1999, the Company entered into a purchase and sale
agreement with the third party that was not completed as specified by the terms
of the agreement and, as a result thereof, the Company received liquidated
damages of additional shares of the third party's common stock valued at $.5
million. During 1999, the Company recognized other revenue of $41. 8 million
associated with the transactions described above.
During 1999, the Company received an excise tax refund of $30.2 million.
Due to uncertainties surrounding the collectability of this refund, the Company
did not recognize it as an asset until it was realized. Accordingly, the Company
recognized the tax refund as other revenue during 1999.
NOTE K. Asset Divestitures
During 1999, the Company completed the divestiture of certain assets for
net divestment proceeds of $420.5 million (of which $390.5 million were cash
proceeds) and recorded an associated net loss on disposition of assets of $24.2
million. The net cash proceeds from the 1999 asset divestitures were used to
reduce outstanding indebtedness.
Prize divestiture. On June 29, 1999, the Company completed a sale of
certain United States oil and gas producing properties, gas plants and other
assets to Prize. The oil and gas producing assets sold to Prize include
properties located in the Gulf Coast, Mid Continent and Permian Basin areas of
the Company's United States region.
In accordance with the terms of the purchase and sale agreement (the
"Prize Divestiture"), the Company received net sales proceeds of $245.0 million,
comprised of $215.0 million of cash and 2,307.693 shares of six percent
convertible preferred stock having a liquidation preference and fair value of
$30.0 million. The convertible preferred stock provides for six percent annual
dividend payments, payable quarterly in additional equity shares of Prize
through 2001. Subsequent to 2001, Prize has the option of paying the quarterly
dividends on the convertible preferred stock in equity shares or cash. Each
share of the convertible preferred stock may, at the option of the Company, be
converted into one share of Prize common stock, subject to certain anti-dilution
adjustments. The Company recognized a loss of $46.4 million from the Prize
Divestiture during 1999.
Other United States divestitures. In addition to the Prize Divestiture,
the Company completed the divestitures of non-strategic United States oil and
gas properties located in the South Texas Gulf Coast, West Texas Permian Basin
and North Dakota areas, an East Texas gas facility and certain other assets for
net cash proceeds of $116.2 million during 1999. Associated with these
divestitures, the Company recorded net gains on divestitures of assets of $31.0
million during 1999.
Canadian divestitures. During 1999, the Company completed the
divestitures of certain non-strategic Canadian oil and gas properties, gas
plants and other related assets. In accordance with the terms of the Canadian
divestitures, the Company received net cash proceeds of $59.3 million, and
recognized a net loss of $8.8 million.
NOTE L. Impairment of Long-Lived Assets
Based upon the decline in oil prices that began in the fourth quarter of
1997 and continued through the first quarter of 1999, the Company's outlook for
future commodity prices and the Company's assessment of performance issues
relative to certain of its oil and gas properties, the Company estimated the
expected future cash flows of its oil and gas properties as of December 31, 1998
and 1997, and compared such estimated future cash flows to the respective
carrying amounts of the oil and gas properties to determine if the carrying
amounts were likely to be recoverable. For those proved oil and gas properties
for which the carrying amount exceeded the estimated future cash flows, an
impairment was determined to exist; therefore, the Company adjusted the carrying
65
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
amount of those proved oil and gas properties to their fair value as determined
by discounting their expected future cash flows at a discount rate commensurate
with the risks involved in the industry. As a result, the Company recognized
non-cash impairment provisions of $312.2 million and $1.4 billion related to its
proved oil and gas properties during 1998 and 1997, respectively.
Based on the Company's 1999 and 1998 assessments of its unproved
properties, the Company recognized non- cash unproved property impairment
provisions of $17.9 million and $147.3 million, respectively, during 1999 and
1998.
See Note O for disclosure of these impairment charges by geographic
operating segment.
NOTE M. Reorganization
During 1998, the Company announced its plans to sell certain
non-strategic oil and gas fields, its intentions to reorganize its operations by
combining its six domestic operating regions, and other cost reduction
initiatives intended to allow the Company to realize greater operational and
administrative efficiences. Specific cost reduction initiatives included the
relocation of most of the Company's administrative services from Midland, Texas
to Irving, Texas; the closings of the Company's regional offices in Oklahoma
City, Oklahoma, Corpus Christi, Texas and Houston, Texas; the termination of 350
employees, including several officer positions; and, further centralization of
the Company's organization structure. The consolidation of administrative
services to Irving and the closing of the Corpus Christi, Texas office were
completed in 1998. The Company completed the closings of the Houston, Texas and
Oklahoma City, Oklahoma offices during 1999 and further centralized certain
operational functions in Irving, Texas. The unpaid employee termination costs as
of December 31, 1998 related to employees who were notified of their pending
termination prior to December 31, 1998, but were still employed with the Company
as of December 31, 1998. The unpaid office closing amounts as of December 31,
1999 and 1998, primarily relate to lease commitments on the office buildings in
Oklahoma City, Oklahoma, Corpus Christi, Texas, and Houston, Texas. As a result
of the reorganization initiatives, the Company has recognized reorganization
charges of $8.5 million and $33.2 million during 1999 and 1998, respectively.
The following table provides a description of the components of the
reorganization charges and unpaid portions of the charges as of December 31,
1999 and 1998:
Unpaid
Total Portion as of
Charges Payments December 31,
-------- -------- -------------
(in thousands)
1999:
Employee terminations........... $ 3,125 $ 7,805 $ -
Relocation...................... 4,998 4,768 230
Office closings................. 340 2,233 1,637
Other........................... 71 71 -
------- ------- -------
$ 8,534 $ 14,877 $ 1,867
======= ======= =======
1998:
Employee terminations........... $ 22,525 $ 17,845 $ 4,680
Relocation...................... 6,677 6,677 -
Office closings................. 3,873 343 3,530
Other........................... 124 124 -
------- ------- -------
$ 33,199 $ 24,989 $ 8,210
======= ======= =======
NOTE N. Income Taxes
The Company accounts for income taxes in accordance with the provisions
of Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("SFAS 109"). The Company and its eligible subsidiaries file a
consolidated United States federal income tax return. Certain subsidiaries are
not eligible to be included in the
66
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
consolidated United States federal income tax return and separate provisions for
income taxes have been determined for these entities or groups of entities. The
tax returns and the amount of taxable income or loss are subject to examination
by United States federal, state and foreign taxing authorities. Current and
estimated tax payments of $800,000; $300,000 and $2.7 million were made in 1999,
1998 and 1997, respectively. In addition, the Company received income tax
refunds of $1.4 million and $3.3 million in 1999 and 1998, respectively. During
1999, 1998 and 1997, the Company's income tax provision (benefit) and amounts
separately allocated were as follows:
<TABLE>
Year Ended December 31,
-------------------------------
1999 1998 1997
-------- -------- ---------
(in thousands)
<S> <C> <C> <C>
Income (loss) before extraordinary item......... $ (600) $ 15,600 $(500,300)
Extraordinary loss.............................. - - (7,200)
Stockholders' equity provision (benefit)........ - 4,300 (2,900)
Change in cumulative translation adjustment..... 1,600 (6,000) -
------- ------- -----
$ 1,000 $ 13,900 $(510,400)
======= ======= ========
</TABLE>
Income tax provision (benefit) attributable to income (loss) before
extraordinary item consists of the following:
Year Ended December 31,
---------------------------------
1999 1998 1997
--------- --------- ---------
(in thousands)
Current:
U.S. federal............... $ - $ (3,300) $ 900
State and local............ 400 300 100
Foreign.................... (1,000) - -
-------- -------- --------
(600) (3,000) 1,000
-------- -------- --------
Deferred:
U.S. federal............... 14,700 123,500 (470,000)
State and local............ - (300) (28,500)
Foreign.................... (14,700) (104,600) (2,800)
-------- -------- --------
- 18,600 (501,300)
-------- -------- --------
Total........................ $ (600) $ 15,600 $(500,300)
======== ======== ========
Income (loss) before income taxes and extraordinary item consists of the
following:
Year Ended December 31,
-----------------------------------
1999 1998 1997
--------- --------- -----------
(in thousands)
Income (loss) before income taxes
and extraordinary item:
U.S. federal........................ $ (23,594) $(393,602) $(1,369,582)
Foreign............................. 534 (337,224) (7,981)
-------- -------- ---------
$ (23,060) $(730,826) $(1,377,563)
======== ======== ==========
Reconciliations of the United States federal statutory rate to the
Company's effective rate for income (loss) before extraordinary item are as
follows:
1999 1998 1997
------- ------- -------
U.S. federal statutory tax rate.............. (35.0) (35.0) (35.0)
Valuation allowance.......................... 102.0 37.1 -
Rate differential on foreign operations...... (68.1) (.5) -
Other........................................ (1.3) .5 (1.3)
------- ------ -------
Consolidated effective tax rate.............. (2.4) 2.1 (36.3)
======= ====== =======
67
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities were as
follows:
December 31,
---------------------
1999 1998
--------- ---------
(in thousands)
Deferred tax assets:
Net operating loss carryforwards................... $ 334,173 $ 291,678
Alternative minimum tax credit carryforwards....... 1,565 1,565
Other.............................................. 78,994 73,260
-------- --------
Total deferred tax assets........................ 414,732 366,503
Valuation allowance................................ (319,900) (271,100)
-------- --------
Net deferred tax assets.......................... 94,832 95,403
-------- --------
Deferred tax liabilities:
Oil and gas properties, principally due to
differences in basis and depletion and the
deduction of intangible drilling costs for
tax purposes..................................... 38,025 44,058
Other.............................................. 11,107 11,645
-------- --------
Total deferred tax liabilities................... 49,132 55,703
-------- --------
Net deferred tax asset........................... $ 45,700 $ 39,700
======== ========
Realization of deferred tax assets associated with net operating loss
carryforwards ("NOLs") and other credit carryforwards is dependent upon
generating sufficient taxable income prior to their expiration. The Company
believes that there is a risk that certain of these NOLs and other credit
carryforwards may expire unused and, accordingly, has established a valuation
allowance of $319.9 million against them. Although realization is not assured
for the remaining deferred tax asset, the Company believes it is more likely
than not that they will be realized through future taxable earnings or
alternative tax planning strategies. However, the net deferred tax assets could
be reduced further if the Company's estimate of taxable income in future periods
is significantly reduced or alternative tax planning strategies are no longer
viable.
Certain subsidiaries that are consolidated for financial reporting
purposes are not eligible to be included in the Company's consolidated United
States federal income tax return and separate provisions for income taxes have
been determined for these entities or groups of entities. At December 31, 1999,
the Company had NOLs for United States, Argentine, Canadian, and South African
income tax purposes of $831.4 million, $24.1 million, $69.6 million and $10.5
million, respectively, which are available to offset future regular taxable
income in each respective tax jurisdiction, if any. Additionally, at December
31, 1999, the Company has alternative minimum tax net operating loss
carryforwards ("AMT NOLs") in the United States of $748.1 million, which are
available to reduce future alternative minimum taxable income, if any. These
carryforwards expire as follows:
68
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
<TABLE>
U.S.
--------------------- Argentina Canada South Africa
Expiration Date NOL AMT NOL NOL NOL NOL
--------------- --------- --------- --------- --------- ------------
(in thousands)
<S> <C> <C> <C> <C> <C>
December 31, 2001.......... $ 689 $ 593 $ - $ - $ -
December 31, 2002.......... 6,066 6,034 4,416 - -
December 31, 2003.......... 838 - 19,703 - -
December 31, 2005.......... 11,049 10,762 - 61,776 -
December 31, 2006.......... 30,834 12,254 - 7,779 -
December 31, 2007.......... 104,107 101,151 - - -
December 31, 2008.......... 112,508 106,558 - - -
December 31, 2009.......... 129,227 102,727 - - -
December 31, 2010.......... 124,859 110,961 - - -
December 31, 2011.......... 6,521 4,045 - - -
December 31, 2012.......... 68,542 58,890 - - -
December 31, 2018.......... 127,925 126,780 - - -
December 31, 2019.......... 108,282 107,369 - - -
Indefinite................. - - - - 10,541
-------- -------- ------- ------- ----------
Total................... $ 831,447 $ 748,124 $ 24,119 $ 69,555 $ 10,541
======== ======== ======= ======= ==========
</TABLE>
The NOLs and AMT NOLs from certain of the United States subsidiaries are
subject to various utilization limitations. In total, approximately $34.3
million of the NOLs and $14.8 million of the AMT NOLs are limited in use to
specific United States subsidiaries. Section 382 of the Internal Revenue Code
provides another limitation to $466.7 million of the Company's United States
NOLs and $379.5 million of its AMT NOLS. The Company believes the utilization of
$246.7 million of the NOLs and $159.5 million of the AMT NOLs subject to the
Section 382 limitation are limited in each taxable year to approximately $104.2
million and the remaining $220 million of the NOLs and AMT NOLs subject to the
Section 382 limitation are limited in each taxable year to approximately $20
million.
NOTE O. Geographic Operating Segment Information
The Company has operations in only one industry segment, that being the
oil and gas exploration and production industry; however, the Company is
organizationally structured along geographic operating segments, or regions.
Since the merger with Mesa and the acquisition of Chauvco, the Company has had
reportable operations in the United States, Argentina and Canada. During 1997,
the Company had only minor operations outside the United States.
The following table provides the geographic operating segment data
required by Statement of Financial Accounting Standards No. 131, "Disclosure
about Segments of an Enterprise and Related Information" ("SFAS 131"), as well
as results of operations of oil and gas producing activities required by
Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and
Gas Producing Activities" ("SFAS 69"). Geographic operating segment income tax
benefits (provisions) have been determined based on statutory rates existing in
the various tax jurisdictions where the Company has oil and gas producing
activities. The "Headquarters and other" table column includes revenues,
expenses, additions to properties, plants and equipment, and assets that do not
represent revenues, expenses, additions to properties, plants and equipment, or
assets of oil and gas producing activities, and that are not routinely included
in the earnings measures or attributes internally reported to management on a
geographic operating segment basis.
69
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
<TABLE>
United Other Headquarters Consolidated
States Argentina Canada Foreign and Other Total
----------- --------- --------- --------- ------------ ------------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Year Ended December 31, 1999:
Oil and gas revenues...................... $ 502,585 $ 83,697 $ 58,364 $ - $ - $ 644,646
Interest and other........................ - - - - 89,657 89,657
Loss on disposition of assets............. (14,736) - (8,836) - (596) (24,168)
---------- -------- -------- -------- ---------- ---------
487,849 83,697 49,528 - 89,061 710,135
---------- -------- -------- -------- ---------- ----------
Production costs.......................... 124,654 18,268 16,608 - - 159,530
Depletion, depreciation and amortization.. 153,775 38,874 25,601 - 17,797 236,047
Impairment of oil and gas properties...... 17,894 - - - - 17,894
Exploration and abandonments.............. 41,225 14,009 3,509 7,231 - 65,974
General and administrative................ - - - - 40,241 40,241
Reorganization............................ - - - - 8,534 8,534
Interest.................................. - - - - 170,344 170,344
Other..................................... - - - - 34,631 34,631
---------- -------- -------- -------- ---------- ----------
337,548 71,151 45,718 7,231 271,547 733,195
---------- -------- -------- -------- ---------- ----------
Loss before income taxes.................. 150,301 12,546 3,810 (7,231) (182,486) (23,060)
Income tax benefit (provision)............ (52,605) (4,140) (1,699) 2,531 56,513 600
---------- -------- -------- -------- ---------- ----------
Net loss.................................. $ 97,696 $ 8,406 $ 2,111 $ (4,700) $ (125,973) $ (22,460)
========== ======== ======== ======== ========== ==========
Additions to properties, plant and
equipment.............................. $ 81,739 $ 75,137 $ 18,893 $ 3,899 $ 7,756 $ 187,424
========== ======== ======== ======== ========== ==========
Segment assets (as of December 31)........ $ 1,865,441 $ 734,382 $ 218,526 $ 8,289 $ 102,835 $ 2,929,473
========== ======== ======== ======== ========== ==========
Year Ended December 31, 1998:
Oil and gas revenues...................... $ 579,156 $ 65,256 $ 67,080 $ - $ - $ 711,492
Interest and other........................ - - - - 10,452 10,452
Loss on disposition of assets............ (52) - - - (393) (445)
---------- -------- -------- -------- ---------- ----------
579,104 65,256 67,080 - 10,059 721,499
---------- -------- -------- -------- ---------- ----------
Production costs.......................... 177,371 21,158 25,022 - - 223,551
Depletion, depreciation and amortization.. 239,561 42,115 40,617 - 15,015 337,308
Impairment of oil and gas properties...... 237,528 136,751 85,240 - - 459,519
Exploration and abandonments.............. 69,263 18,245 20,613 13,737 - 121,858
General and administrative................ - - - - 73,000 73,000
Reorganization............................ - - - - 33,199 33,199
Interest.................................. - - - - 164,285 164,285
Other..................................... - - - - 39,605 39,605
---------- -------- -------- -------- ---------- ----------
723,723 218,269 171,492 13,737 325,104 1,452,325
---------- -------- -------- -------- ---------- ----------
Loss before income taxes.................. (144,619) (153,013) (104,412) (13,737) (315,045) (730,826)
Income tax benefit (provision)............ 53,075 50,494 45,628 4,808 (169,605) (15,600)
---------- -------- -------- -------- ---------- ----------
Net loss.................................. $ (91,544) $(102,519) $ (58,784) $ (8,929) $ (484,650) $ (746,426)
========== ======== ======== ======== ========== ==========
Additions to properties, plant and
equipment.............................. $ 346,368 $ 69,082 $ 73,096 $ 18,791 $ 31,546 $ 538,883
========== ======== ======== ======== ========== ==========
Segment assets (as of December 31)........ $ 2,259,746 $ 692,271 $ 308,025 $ 103,702 $ 117,570 $ 3,481,314
========== ======== ======== ======== ========== ==========
Year Ended December 31, 1997:
Oil and gas revenues...................... $ 533,865 $ 2,917 $ - $ - $ - $ 536,782
Interest and other........................ - - - - 4,278 4,278
Gain on disposition of assets............. 3,305 - - - 1,664 4,969
---------- -------- -------- -------- ---------- ----------
537,170 2,917 - - 5,942 546,029
---------- -------- -------- -------- ---------- ----------
Production costs.......................... 143,332 838 - - - 144,170
Depletion, depreciation and amortization.. 203,160 1,290 - - 7,985 212,435
Impairment of oil and gas properties...... 1,356,390 - - - - 1,356,390
Exploration and abandonments.............. 69,896 1,822 - 5,442 - 77,160
General and administrative................ - - - - 48,763 48,763
Interest.................................. - - - - 77,550 77,550
Other..................................... - - - - 7,124 7,124
---------- -------- -------- -------- ---------- ----------
1,772,778 3,950 - 5,442 141,422 1,923,592
---------- -------- -------- -------- ---------- ----------
Loss before income taxes and
extraordinary item..................... (1,235,608) (1,033) - (5,442) (135,480) (1,377,563)
Income tax benefit........................ 453,468 341 - 1,905 44,586 500,300
---------- -------- -------- -------- ---------- ----------
Loss before extraordinary items........... $ (782,140) $ (692) $ - $ (3,537) $ (90,894) $ (877,263)
========== ======== ======== ======== ========== ==========
Additions to properties, plant and
equipment.............................. $ 417,269 $ 4,446 $ - $ 6,925 $ 12,783 $ 441,423
========== ======== ======== ======== ========== ==========
Segment assets (as of December 31)........ $ 2,684,091 $ 734,569 $ 505,483 $ 1,085 $ 227,762 $ 4,152,990
========== ======== ======== ======== ========== ==========
</TABLE>
70
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
NOTE P. Loss Per Share
Basic net income (loss) per share is computed by dividing income
available to common stockholders by the weighted average number of common shares
outstanding for the period. The computation of diluted net income (loss) per
share reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock or
resulted in the issuance of common stock that would then share in the earnings
of the entity. For 1999, 1998 and 1997, the computation of diluted net loss per
share was antidilutive; therefore, the amounts reported for basic and diluted
net loss per share were the same.
NOTE Q. Pioneer USA
Pioneer USA is a wholly-owned subsidiary of the Company that has fully
and unconditionally guaranteed certain debt securities of the Company (see Note
D above). The Company has not prepared financial statements and related
disclosures for Pioneer USA under separate cover because management of the
Company has determined that such information is not material to investors. In
accordance with practices accepted by the United States Securities and Exchange
Commission (the "SEC"), the Company has prepared Consolidating Condensed
Financial Statements in order to quantify the assets of Pioneer USA as a
subsidiary guarantor. The following Consolidating Condensed Balance Sheets as of
December 31, 1999 and 1998, and Consolidating Statements of Operations and
Comprehensive Loss and Consolidating Condensed Statements of Cash Flows for the
years ended December 31, 1999, 1998 and 1997 present financial information for
Pioneer Natural Resources Company as the Parent on a stand-alone basis (carrying
any investments in subsidiaries under the equity method), financial information
for Pioneer USA on a stand-alone basis (carrying any investment in non-guarantor
subsidiaries under the equity method), financial information for the non-
guarantor subsidiaries of the Company on a consolidated basis, the consolidation
and elimination entries necessary to arrive at the information for the Company
on a consolidated basis, and the financial information for the Company on a
consolidated basis. Pioneer USA is not restricted from making distributions to
the Company.
71
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
CONSOLIDATING CONDENSED BALANCE SHEET
As of December 31, 1999
(in thousands)
ASSETS
<TABLE>
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Eliminations Company
---------- ----------- ------------ ------------ -----------
<S> <C> <C> <C> <C> <C>
Current assets:
Cash and cash equivalents............. $ 5 $ 22,699 $ 12,084 $ $ 34,788
Other current assets.................. 2,160,134 (1,455,442) (556,344) 148,348
--------- ---------- ---------- ----------
Total current assets.............. 2,160,139 (1,432,743) (544,260) 183,136
--------- ---------- ---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of accounting:
Proved properties................... - 2,200,173 797,162 2,997,335
Unproved properties................. - 24,267 233,316 257,583
Accumulated depletion, depreciation and
amortization........................ - (614,402) (137,554) (751,956)
--------- ---------- ---------- ----------
- 1,610,038 892,924 2,502,962
--------- ---------- ---------- ----------
Deferred income taxes................... 83,400 - - 83,400
Other property and equipment, net....... - 28,144 14,862 43,006
Other assets, net....................... 13,293 58,117 45,559 116,969
Investment in subsidiaries.............. 190,293 161,061 - (351,354) -
--------- ---------- ---------- ----------
$2,447,125 $ 424,617 $ 409,085 $ 2,929,473
========= ========== ========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt.. $ - $ 828 $ - $ $ 828
Other current liabilities............. 36,115 120,857 39,013 195,985
--------- ---------- ---------- ----------
Total current liabilities......... 36,115 121,685 39,013 196,813
--------- ---------- ---------- ----------
Long-term debt, less current maturities. 1,745,108 - - 1,745,108
Other noncurrent liabilities............ - 137,848 31,590 169,438
Deferred income taxes................... - - 43,500 43,500
Stockholders' equity.................... 665,902 165,084 294,982 (351,354) 774,614
Commitments and contingencies........... --------- ---------- ---------- ----------
$2,447,125 $ 424,617 $ 409,085 $ 2,929,473
========= ========== ========== ==========
CONSOLIDATING CONDENSED BALANCE SHEET
As of December 31, 1998
(in thousands)
ASSETS
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Eliminations Company
---------- ----------- ------------ ------------ -----------
Current assets:
Cash and cash equivalents............. $ 3,161 $ 37,932 $ 18,128 $ $ 59,221
Other current assets.................. 2,248,244 (1,735,638) (369,839) 142,767
--------- ---------- ---------- ----------
Total current assets.............. 2,251,405 (1,697,706) (351,711) 201,988
--------- ---------- ---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of accounting:
Proved properties................... - 2,678,637 942,993 3,621,630
Unproved properties................. - 58,989 283,600 342,589
Accumulated depletion, depreciation and
amortization........................ - (753,570) (176,541) (930,111)
--------- ---------- ---------- ----------
- 1,984,056 1,050,052 3,034,108
--------- ---------- ---------- ----------
Deferred income taxes................... 96,800 - - 96,800
Other property and equipment, net....... - 38,229 16,781 55,010
Other assets, net....................... 9,787 43,557 40,064 93,408
Investment in subsidiaries.............. 135,204 148,257 - (283,461) -
--------- ---------- ---------- ----------
$2,493,196 $ 516,393 $ 755,186 $ 3,481,314
========= ========== ========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt.. $ 212,302 $ 1,189 $ 93,030 $ $ 306,521
Other current liabilities............. 21,727 145,945 52,639 220,311
--------- ---------- ---------- ----------
Total current liabilities......... 234,029 147,134 145,669 526,832
--------- ---------- ---------- ----------
Long-term debt, less current maturities. 1,676,933 830 190,981 1,868,744
Other noncurrent liabilities............ - 189,325 43,136 232,461
Deferred income taxes................... - - 64,200 64,200
Stockholders' equity.................... 582,234 179,104 311,200 (283,461) 789,077
Commitments and contingencies........... ---------- ----------- ---------- ----------
$2,493,196 $ 516,393 $ 755,186 $ 3,481,314
========= ========== ========== ==========
</TABLE>
72
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE LOSS
For the Year Ended December 31, 1999
(in thousands)
<TABLE>
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income The
(Parent) USA Subsidiaries Tax Provision Eliminations Company
--------- --------- ------------ ------------- ------------ ----------
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas.................. $ - $ 470,059 $ 174,587 $ - $ $ 644,646
Interest and other........... 406 52,232 37,019 - 89,657
Gain (loss) on disposition of
assets, net............... - 19,379 (43,547) - (24,168)
-------- -------- --------- ---------- ---------
406 541,670 168,059 - 710,135
-------- -------- --------- ---------- ---------
Costs and expenses:
Oil and gas production....... - 120,074 39,456 - 159,530
Depletion, depreciation and
amortization............... - 157,294 78,753 - 236,047
Impairment of oil and gas
properties................. - 17,894 - - 17,894
Exploration and abandonments. - 43,133 22,841 - 65,974
General and administrative... 1,051 27,260 11,930 - 40,241
Reorganization............... - 8,534 - - 8,534
Interest..................... (33,404) 145,184 58,564 - 170,344
Equity income (loss) from
subsidiary................. 39,672 (5,179) - - (34,493) -
Other........................ 799 38,166 (4,334) - 34,631
-------- -------- --------- ---------- ---------
8,118 552,360 207,210 - 733,195
-------- -------- --------- ---------- ---------
Loss before income taxes....... (7,712) (10,690) (39,151) - (23,060)
Income tax benefit (provision). - (444) 15,792 (14,748) 600
-------- -------- --------- ---------- ---------
Net loss....................... (7,712) (11,134) (23,359) (14,748) (22,460)
Other comprehensive income:
Translation adjustment....... - - 8,358 - 8,358
-------- -------- --------- ---------- ---------
Comprehensive loss............. $ (7,712) $ (11,134) $ (15,001) $ (14,748) $ (14,102)
======== ======== ========= ========== =========
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE LOSS
For the Year Ended December 31, 1998
(in thousands)
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income The
(Parent) USA Subsidiaries Tax Provision Eliminations Company
---------- --------- ------------ ------------- ------------ ----------
Revenues:
Oil and gas.................. $ - $ 523,736 $ 187,756 $ - $ $ 711,492
Interest and other........... 38 7,937 2,477 - 10,452
Loss on disposition of assets,
net - (477) 32 - (445)
-------- -------- --------- ---------- ---------
38 531,196 190,265 - 721,499
-------- -------- --------- ---------- ---------
Costs and expenses:
Oil and gas production....... - 164,964 58,587 - 223,551
Depletion, depreciation and
amortization............... - 225,127 112,181 - 337,308
Impairment of oil and gas
properties................. - 237,529 221,990 - 459,519
Exploration and abandonments. - 71,851 50,007 - 121,858
General and administrative... 2,042 57,158 13,800 - 73,000
Reorganization............... - 31,756 1,443 - 33,199
Interest..................... (54,237) 159,863 58,659 - 164,285
Equity loss from subsidiary.. 675,142 4,358 - - (679,500) -
Other........................ 722 22,732 16,151 - 39,605
-------- -------- --------- ---------- ---------
623,669 975,338 532,818 - 1,452,325
-------- -------- --------- ---------- ---------
Loss before income taxes....... (623,631) (444,142) (342,553) - (730,826)
Income tax provision........... - (174) 107,369 (122,795) (15,600)
-------- -------- --------- ---------- ---------
Net loss....................... (623,631) (444,316) (235,184) (122,795) (746,426)
Other comprehensive income:
Translation adjustment....... - - 2,903 - 2,903
-------- -------- --------- ---------- ---------
Comprehensive loss............. $(623,631) $(444,316) $ (232,281) $ (122,795) $ (743,523)
======== ======== ========= =========== =========
</TABLE>
73
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE LOSS
For the Year Ended December 31, 1997
(in thousands)
<TABLE>
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income The
(Parent) USA Subsidiaries Tax Benefit Eliminations Company
----------- ----------- ------------ ------------ ------------ ----------
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas.................. $ - $ 453,771 $ 83,011 $ - $ $ 536,782
Interest and other........... - 5,357 873 - (1,952) 4,278
Gain (loss) on disposition of
assets, net................ - 6,062 (402) - (691) 4,969
---------- ---------- --------- ---------- ----------
- 465,190 83,482 - 546,029
---------- ---------- --------- ---------- ----------
Costs and expenses:
Oil and gas production....... - 128,644 15,526 - 144,170
Depletion, depreciation and
amortization............... - 166,495 45,940 - 212,435
Impairment of oil and gas
properties................. - 1,220,920 135,470 - 1,356,390
Exploration and abandonments. - 67,679 9,481 - 77,160
General and administrative... 613 44,766 3,384 - 48,763
Interest..................... 5,910 67,969 5,623 - (1,952) 77,550
Equity loss from subsidiary.. 1,407,844 124,874 - - (1,532,718) -
Other........................ - 7,065 59 - 7,124
---------- ---------- --------- ---------- ----------
1,414,367 1,828,412 215,483 - 1,923,592
---------- ---------- --------- ---------- ----------
Loss before income taxes and
extraordinary item........... (1,414,367) (1,363,222) (132,001) - (1,377,563)
Income tax benefit............. - - - 500,300 500,300
---------- ---------- --------- ---------- ----------
Loss before extraordinary item. (1,414,367) (1,363,222) (132,001) 500,300 (877,263)
Extraordinary item - loss on
early extinguishment of debt,
net of tax................... - (13,408) - - (13,408)
---------- ---------- --------- ---------- ----------
Net loss....................... (1,414,367) (1,376,630) (132,001) 500,300 (890,671)
Other comprehensive income:
Translation adjustment....... - - - - -
---------- ---------- --------- ---------- --------
Comprehensive loss............. $(1,414,367) $(1,376,630) $ (132,001) $ 500,300 $ (890,671)
========== ========== ========= ========== ==========
</TABLE>
74
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1999, 1998 and 1997
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
For the Year Ended December 31, 1999
(in thousands)
<TABLE>
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Company
---------- --------- ------------ ----------
<S> <C> <C> <C> <C>
Cash flows from operating activities:
Net cash provided by (used in) operating activities.......... $ 152,485 $(230,625) $ 333,374 $ 255,234
--------- -------- -------- ---------
Cash flows from investing activities:
Proceeds from disposition of assets.......................... - 328,182 62,349 390,531
Additions to oil and gas properties.......................... - (74,257) (105,412) (179,669)
Other property additions, net................................ - (8,335) (3,532) (11,867)
--------- -------- -------- ---------
Net cash provided by (used in) investing activities... - 245,590 (46,595) 198,995
--------- -------- -------- ---------
Cash flows from financing activities:
Borrowings under long-term debt.............................. 355,493 - - 355,493
Principal payments on long-term debt......................... (504,493) (1,192) (288,234) (793,919)
Payment of noncurrent liabilities............................ - (29,006) (4,996) (34,002)
Deferred loan fees/issuance costs............................ (6,891) - - (6,891)
Exercise of stock options and employee stock purchases....... 250 - - 250
--------- -------- --------- ---------
Net cash used in financing activities................. (155,641) (30,198) (293,230) (479,069)
--------- -------- --------- ---------
Net decrease in cash and cash equivalents...................... (3,156) (15,233) (6,451) (24,840)
Effect of exchange rate changes on cash and cash equivalents... - - 407 407
Cash and cash equivalents, beginning of period................. 3,161 37,932 18,128 59,221
--------- -------- -------- ---------
Cash and cash equivalents, end of period................... $ 5 $ 22,699 $ 12,084 $ 34,788
========= ======== ======== =========
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
For the Year Ended December 31, 1998
(in thousands)
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Company
---------- --------- ------------ -----------
Cash flows from operating activities:
Net cash provided by (used in) operating activities.......... $ (151,315) $ 313,359 $ 152,032 $ 314,076
--------- -------- --------- ----------
Cash flows from investing activities:
Proceeds from disposition of assets.......................... - 13,791 8,085 21,876
Additions to oil and gas properties.......................... - (309,639) (197,698) (507,337)
Other property additions, net................................ - (15,862) (15,684) (31,546)
--------- -------- --------- ----------
Net cash used in investing activities................. - (311,710) (205,297) (517,007)
--------- -------- --------- ----------
Cash flows from financing activities:
Borrowings under long-term debt.............................. 886,008 - 61,172 947,180
Principal payments on long-term debt......................... (704,857) (1,326) (5,341) (711,524)
Payment of noncurrent liabilities............................ - (11,424) (5,667) (17,091)
Dividends.................................................... (9,160) - (916) (10,076)
Purchase of treasury stock................................... (10,367) - - (10,367)
Deferred loan fees/issuance costs............................ (7,189) - - (7,189)
--------- -------- --------- ----------
Net cash provided by (used in) financing activities... 154,435 (12,750) 49,248 190,933
--------- -------- --------- ----------
Net increase (decrease) in cash and cash equivalents........... 3,120 (11,101) (4,017) (11,998)
Effect of exchange rate changes on cash and cash equivalents... - - (494) (494)
Cash and cash equivalents, beginning of period................. 41 49,033 22,639 71,713
--------- -------- --------- ----------
Cash and cash equivalents, end of period................... $ 3,161 $ 37,932 $ 18,128 $ 59,221
========= ======== ========= ==========
</TABLE>
75
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 1999, 1998 and 1997
Capitalized Costs
- -----------------
December 31,
-----------------------
1999 1998
---------- ----------
(in thousands)
il and Gas Properties:
Proved.............................................. $2,997,335 $3,621,630
Unproved............................................ 257,583 342,589
--------- --------
3,254,918 3,964,219
Less accumulated depletion.......................... (751,956) (930,111)
--------- --------
Net capitalized costs for oil and gas properties.... $2,502,962 $3,034,108
========= =========
<TABLE>
Costs Incurred for Oil and Gas Producing Activities
- ---------------------------------------------------
Property
Acquisition Costs Total
--------------------- Exploration Development Costs
Proved Unproved(a) Costs Costs Incurred
---------- -------- ----------- ----------- -----------
(in thousands)
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1999:
United States.................. $ 937 $ 3,185 $ 42,337 $ 59,204 $ 105,663
Argentina...................... 36,312 2,517 12,597 25,228 76,654
Canada......................... 174 (7,375) 1,431 17,322 11,552
Other foreign (b).............. 151 - 7,106 - 7,257
--------- -------- ---------- ---------- ----------
Total costs incurred......... $ 37,574 $ (1,673) $ 63,471 $ 101,754 $ 201,126
========= ======== ========== ========== ==========
Year Ended December 31, 1998:
United States.................. $ 19,658 $ 34,092 $ 62,747 $ 213,943 $ 330,440
Argentina...................... 4,504 67,010 22,521 39,049 133,084
Canada......................... 1,185 (93,349) 21,871 47,550 (22,743)
Other foreign (c).............. (136) - 21,706 412 21,982
--------- -------- ---------- ---------- ----------
Total costs incurred......... $ 25,211 $ 7,753 $ 128,845 $ 300,954 $ 462,763
========= ======== ========== ========== ==========
Year Ended December 31, 1997:
United States.................. $2,623,993 $ 91,373 $ 88,710 $ 243,119 $ 3,047,195
Argentina...................... 430,607 252,343 1,822 3,927 688,699
Canada......................... 287,787 194,067 - - 481,854
Other foreign (d).............. - 332 5,442 - 5,774
--------- -------- ---------- ---------- ----------
Total costs incurred......... $3,342,387 $ 538,115 $ 95,974 $ 247,046 $ 4,223,522
========= ======== ========== ========== ==========
</TABLE>
- ---------------
(a) Includes 1998 Chauvco purchase price adjustments of $59.9 million for
Argentina and $(99.4) million for Canada.
(b) Primarily comprised of South Africa and Gabon geological and geophysical
costs.
(c) Primarily relates to the drilling of five wells in South Africa.
(d) Primarily relates to an unsuccessful well in Guatemala.
76
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 1999, 1998 and 1997
Results of Operations
Information about the Company's results of operations for oil and gas
producing activities is presented in Note O to the accompanying Notes to
Consolidated Financial Statements.
Reserve Quantity Information
The estimates of the Company's proved oil and gas reserves, which are
located principally in the United States, Argentina and Canada are prepared by
the Company's engineers. Reserves were estimated in accordance with guidelines
established by the SEC and the Financial Accounting Standards Board, which
require that reserve estimates be prepared under existing economic and operating
conditions with no provision for price and cost escalations except by
contractual arrangements. The reserve estimates for 1999, 1998 and 1997 utilize
respective oil prices of $24.33, $10.09 and $16.89 per Bbl (reflecting
adjustments for oil quality and gathering and transportation costs); respective
NGL prices of $17.59, $6.81 and $12.79 per Bbl; and, respective gas prices of
$1.83, $1.64 and $2.06 per Mcf (reflecting adjustments for Btu content,
gathering and transportation costs and gas processing and shrinkage).
Oil and gas reserve quantity estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revision of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of currently
producing oil and gas properties. Accordingly, these estimates are expected to
change as additional information becomes available in the future.
77
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 1999, 1998 and 1997
<TABLE>
Oil and Gas Producing Activities:
1999 1998 1997
------------------------------- ----------------------------- ------------------------------
Oil Oil Oil
& NGLs Gas & NGLs Gas & NGLs Gas
(MBbls) (MMcf) MBOE (MBbls) (MMcf) MBOE (MBbls) (MMcf) MBOE
Total Proved Reserves: -------- --------- -------- ------- --------- ------- ------- --------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
UNITED STATES
Balance, January 1............... 269,638 1,545,644 527,246 329,316 1,719,130 615,838 162,836 828,268 300,881
Revisions of previous estimates.. 51,649 196,833 84,455 (34,211) (32,113) (39,563) 70,063 (100,755) 53,271
Purchases of minerals-in-place... - - - - - - 121,286 1,147,921 312,606
New discoveries and extensions... 149 1,351 374 183 3,438 756 1,109 7,659 2,385
Production....................... (20,163) (106,095) (37,845) (25,327) (137,741) (48,284) (17,737) (104,868) (35,215)
Sales of minerals-in-place....... (42,207) (322,891) (96,024) (323) (7,070) (1,501) (8,241) (59,095) (18,090)
-------- ---------- -------- ------- --------- ------- ------- --------- -------
Balance, December 31............. 259,066 1,314,842 478,206 269,638 1,545,644 527,246 329,316 1,719,130 615,838
ARGENTINA
Balance, January 1............... 24,219 428,334 95,608 31,612 340,392 88,344 1,105 1,108 1,290
Revisions of previous estimates.. (2,441) (12,470) (4,520) (7,615) 76,843 5,192 (259) (1,108) (444)
Purchases of minerals-in-place... 4,406 17,483 7,320 - - - 30,914 340,392 87,646
New discoveries and extensions... 6,182 16,750 8,974 3,522 37,900 9,839 - - -
Production....................... (2,569) (34,477) (8,315) (3,300) (26,801) (7,767) (148) - (148)
Sales of minerals-in-place....... - - - - - - - - -
-------- ---------- -------- ------- --------- ------- ------- --------- -------
Balance, December 31............. 29,797 415,620 99,067 24,219 428,334 95,608 31,612 340,392 88,344
CANADA
Balance, January 1............... 12,447 249,230 53,985 22,796 207,868 57,441 - - -
Revisions of previous estimates.. 4,865 (62,356) (5,527) (6,905) 60,247 3,135 - - -
Purchases of minerals-in-place... - - - 2 - 2 22,796 207,868 57,441
New discoveries and extensions... - - - 261 5,951 1,253 - - -
Production....................... (1,960) (17,886) (4,941) (3,596) (19,371) (6,824) - - -
Sales of minerals-in-place....... (11,382) (23,737) (15,338) (111) (5,465) (1,022) - - -
-------- ---------- -------- ------- --------- ------- ------- --------- -------
Balance, December 31............. 3,970 145,251 28,179 12,447 249,230 53,985 22,796 207,868 57,441
TOTAL
Balance, January 1............... 306,304 2,223,208 676,839 383,724 2,267,390 761,623 163,941 829,376 302,171
Revisions of previous estimates.. 54,073 122,007 74,408 (48,731) 104,977 (31,236) 69,804 (101,863) 52,827
Purchases of minerals-in-place... 4,406 17,483 7,320 2 - 2 174,996 1,696,181 457,693
New discoveries and extensions... 6,331 18,101 9,348 3,966 47,289 11,848 1,109 7,659 2,385
Production....................... (24,692) (158,458) (51,101) (32,223) (183,913) (62,875) (17,885) (104,868) (35,363)
Sales of minerals-in-place....... (53,589) (346,628) (111,362) (434) (12,535) (2,523) (8,241) (59,095) (18,090)
-------- ---------- -------- ------- --------- ------- ------- --------- --------
Balance, December 31............. 292,833 1,875,713 605,452 306,304 2,223,208 676,839 383,724 2,267,390 761,623
======== ========== ======== ======= ========= ======= ======= ========= ========
Proved Developed Reserves:
January 1...................... 274,953 2,001,775 608,582 329,920 1,956,658 656,030 126,370 660,174 236,399
======== ========== ======== ======= ========= ======= ======= ========= ========
December 31.................... 235,165 1,538,310 491,551 274,953 2,001,775 608,582 329,920 1,956,658 656,030
======== ========== ======== ======= ========= ======= ======= ========= ========
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed
by applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves less estimated future expenditures
(based on year-end costs) to be incurred in developing and producing the proved
reserves, discounted using a rate of 10 percent per year to reflect the
estimated timing of the future cash flows. Future income taxes are calculated by
comparing discounted future cash flows to the tax basis of oil and gas
properties plus available carryforwards and credits and applying the current tax
rates to the difference.
78
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 1999, 1998 and 1997
Discounted future cash flow estimates like those shown below are not
intended to represent estimates of the fair value of oil and gas properties.
Estimates of fair value should also consider probable reserves, anticipated
future oil and gas prices, interest rates, changes in development and production
costs and risks associated with future production. Because of these and other
considerations, any estimate of fair value is necessarily subjective and
imprecise.
<TABLE>
For the Year Ended December 31,
---------------------------------------
1999 1998 1997
----------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
UNITED STATES Oil and gas producing activities:
Future cash inflows................................. $ 8,143,587 $ 5,050,473 $ 8,936,044
Future production costs............................. (2,823,316) (2,281,406) (3,185,357)
Future development costs............................ (288,801) (227,727) (325,659)
Future income tax expense........................... (855,875) - (860,632)
---------- ---------- ----------
4,175,595 2,541,340 4,564,396
10% annual discount factor............................. (1,837,826) (1,314,471) (2,067,371)
---------- ---------- ----------
Standardized measure of discounted future cash flows... $ 2,337,769 $ 1,226,869 $ 2,497,025
========== ========== ==========
ARGENTINA
Oil and gas producing activities:
Future cash inflows................................. $ 1,075,904 $ 686,911 $ 912,688
Future production costs............................. (199,513) (196,446) (168,105)
Future development costs............................ (79,336) (45,710) (137,060)
Future income tax expense........................... (87,274) - (60,069)
---------- ---------- ----------
709,781 444,755 547,454
10% annual discount factor............................. (240,681) (211,956) (201,732)
---------- ---------- ----------
Standardized measure of discounted future cash flows... $ 469,100 $ 232,799 $ 345,722
========== ========== ==========
CANADA
Oil and gas producing activities:
Future cash inflows................................. $ 354,662 $ 526,844 $ 662,104
Future production costs............................. (91,913) (163,414) (223,325)
Future development costs............................ (54,571) (49,380) (48,323)
Future income tax expense........................... (2,522) (30,797) (79,044)
---------- ---------- ----------
205,656 283,253 311,412
10% annual discount factor............................. (75,266) (94,113) (102,395)
---------- ---------- ----------
Standardized measure of discounted future cash flows... $ 130,390 $ 189,140 $ 209,017
========== ========== ==========
TOTAL
Oil and gas producing activities:
Future cash inflows................................. $ 9,574,153 $ 6,264,228 $10,510,836
Future production costs............................. (3,114,742) (2,641,266) (3,576,787)
Future development costs............................ (422,708) (322,817) (511,042)
Future income tax expense........................... (945,671) (30,797) (999,745)
---------- ---------- ----------
5,091,032 3,269,348 5,423,262
10% annual discount factor............................. (2,153,773) (1,620,540) (2,371,498)
---------- ---------- ----------
Standardized measure of discounted future cash flows... $ 2,937,259 $ 1,648,808 $ 3,051,764
========== ========== ==========
</TABLE>
79
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
Years Ended December 31, 1999, 1998 and 1997
<TABLE>
For the Year Ended December 31,
--------------------------------------
Oil and Gas Producing Activities 1999 1998 1997
---------- ----------- -----------
(in thousands)
<S> <C> <C> <C>
Oil and gas sales, net of production costs........... $ (485,116) $ (487,942) $ (392,612)
Net changes in prices and production costs........... 1,571,584 (1,281,944) (1,034,678)
Extensions and discoveries........................... 60,695 44,018 19,993
Sales of minerals-in-place........................... (468,376) (12,748) (126,879)
Purchases of minerals-in-place....................... 56,309 3 1,880,570
Revisions of estimated future development costs...... (115,043) (2,777) (15,158)
Revisions of previous quantity estimates............. 387,616 (68,086) 240,375
Accretion of discount................................ 164,881 307,567 234,537
Changes in production rates, timing and other........ 115,901 75,045 (99,753)
--------- ---------- ----------
Change in present value of future net revenues....... 1,288,451 (1,426,864) 706,395
Net change in present value of future income taxes... - 23,908 537,804
--------- ---------- ----------
1,288,451 (1,402,956) 1,244,199
Balance, beginning of year........................... 1,648,808 3,051,764 1,807,565
--------- ---------- ----------
Balance, end of year................................. $2,937,259 $ 1,648,808 $ 3,051,764
========= ========== ==========
</TABLE>
Selected Quarterly Financial Results
Quarter
------------------------------------------
First Second Third Fourth
-------- -------- -------- ---------
(in thousands, except per share data)
1999
Operating revenues............. $147,151 $174,231 $159,855 $ 163,409
Total revenues................. $193,191 $134,744 $213,165 $ 169,035
Costs and expenses............. $195,292 $209,860 $166,137 $ 161,906
Net income (loss).............. $ (2,501) $(74,616) $ 46,428 $ 8,229
Net income (loss) per share.... $ (.02) $ (.74) $ .46 $ .08
1998
Operating revenues............. $197,369 $183,647 $173,462 $ 157,014
Total revenues................. $198,557 $185,107 $178,869 $ 158,966
Costs and expenses............. $238,801 $235,616 $247,071 $ 730,837
Net loss ...................... $(26,844) $(32,809) $(43,902) $(642,871)
Net loss per share............. $ (.27) $ (.33) $ (.44) $ (6.41)
80
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 18, 2000 and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 18, 2000 and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 18, 2000 and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required in response to this item is set forth in the
Company's definitive proxy statement for the annual meeting of stockholders to
be held on May 18, 2000 and is incorporated herein by reference.
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Listing of Financial Statements and Exhibits
Financial Statements
The following consolidated financial statements of the Company are
included in "Item 8. Financial Statements and Supplementary Data":
Independent Auditors' Reports
Consolidated Balance Sheets as of December 31, 1999 and 1998
Consolidated Statements of Operations and Comprehensive Loss for the
years ended December 31, 1999, 1998 and 1997
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1999, 1998 and 1997
Consolidated Statements of Cash Flows for the years ended December 31,
1999, 1998 and 1997
Notes to Consolidated Financial Statements
Unaudited Supplementary Information
All other statements and schedules for which provision is made in the
applicable accounting regulations of the SEC have been omitted because they are
not required under related instructions or are inapplicable, or the information
is shown in the financial statements and related notes.
81
<PAGE>
Exhibits
--------
Exhibit
Number Description
- ------- -----------
2.1 - Amended and Restated Agreement and Plan of Merger, dated as of April 6,
1997, by and among MESA Inc. ("Mesa"), Mesa Operating Co. ("MOC"), MXP
Reincorporation Corp. and Parker & Parsley Petroleum Company ("Parker &
Parsley") (incorporated by reference to Exhibit 2.1 to the Company's
Registration Statement on Form S-4, dated June 27, 1997, Registration No.
333-26951).
3.1 - Amended and Restated Certificate of Incorporation of the Company
(incorporated by reference to Exhibit 3.1 to the Company's Registration
Statement on Form S-4, dated June 27, 1997, Registration No. 333- 26951).
3.2 - Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2
to the Company's Registration Statement on Form S-4, dated June 27, 1997,
Registration No. 333-26951).
3.3 - Certificate of Designations of Special Preferred Voting Stock
(incorporated by reference to Exhibit 3.3 of the Company's Registration
Statement on Form S-3, Registration No. 333-42315, filed with the SEC on
December 17, 1997).
3.4 - Terms and Conditions of Exchangeable Shares (incorporated by reference to
Annex F to the Definitive Joint Management Information Circular and Proxy
Statement of the Company and Chauvco Resources Ltd. ("Chauvco"), File No.
001-13245, filed with the SEC on November 17, 1997).
4.1 - Form of Certificate of Common Stock, par value $.01 per share, of the
Company (incorporated by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-4, dated June 27, 1997, Registration No.
333-26951).
4.2 - Form of Certificate of Special Preferred Voting Stock (incorporated by
reference to Exhibit 4.1 to the Company's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 2, 1998).
4.3 - Form of Certificate of Exchangeable Shares (incorporated by reference to
Exhibit 4.2 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
9.1 - Voting and Exchange Trust Agreement, dated as of December 18, 1997, among
the Company, Pioneer Natural Resources (Canada) Ltd. ("Pioneer Canada")
and Montreal Trust Company of Canada, as Trustee (incorporated by
reference to Exhibit 2.4 to the Company's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 2, 1998).
9.2 - Amended and Restated Shareholders Agreement, dated as of September 3,
1997, by and between the Company and Guy J. Turcotte (incorporated by
reference to Exhibit 2.6 to the Company's Registration Statement on Form
S-3, Registration No. 333-42315, filed with the SEC on December 15,
1997).
9.3 - Shareholders Agreement, dated as of September 3, 1997, by and among the
Company, Trimac Corporation and Gendis Inc. (incorporated by reference to
Exhibit 2.4 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on October 2, 1997).
10.1 - Indenture, dated July 2, 1996, among Pioneer USA (formerly MOC), as
Issuer, the Company, as Guarantor, and Harris Trust and Savings Bank, as
Trustee, relating to the 11-5/8% Senior Subordinated Discount Notes Due
2006 (incorporated by reference to Exhibit 4.17 to Mesa's Quarterly
Report on Form 10-Q for the period ended June 30, 1996).
82
<PAGE>
Exhibit
Number Description
- ------- -----------
10.2 - First Supplemental Indenture, dated as of April 15, 1997, among Pioneer
USA (formerly MOC), as Issuer, Mesa, the subsidiary guarantors named
therein, the Company, and Harris Trust and Savings Bank, as Trustee, with
respect to the indenture identified above as Exhibit 10.1 (incorporated
by reference to Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the period ended September 30, 1997, File No. 001-13245).
10.3 - Second Supplemental Indenture, dated as of August 7, 1997, among Pioneer
USA (formerly MOC), as Issuer, Mesa, the subsidiary guarantors named
therein, the Company, and Harris Trust and Savings Bank, as Trustee, with
respect to the indenture identified above as Exhibit 10.1 (incorporated
by reference to Exhibit 10.2 to the Company's Quarterly Report on Form
10-Q for the period ended September 30, 1997, File No. 001-13245).
10.4 - Third Supplemental Indenture, dated as of December 18, 1997, among
Pioneer USA, the Subsidiary Guarantors named therein, the Company, and
Harris Trust and Savings Bank, as Trustee, with respect to the indenture
identified above as Exhibit 10.1 (incorporated by reference to Exhibit
10.12 to the Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.5 - Fourth Supplemental Indenture, dated as of December 30, 1997, among
Pioneer USA (formerly MOC), a Delaware corporation, the Company, a
Delaware corporation, Pioneer NewSub1, Inc., a Texas corporation, and
Harris Trust and Savings Bank, an Illinois corporation, as Trustee, with
respect to the indenture identified above as Exhibit 10.1 (incorporated
by reference to Exhibit 10.13 to the Company's Current Report on Form
8-K, File No. 001-13245, filed with the SEC on January 2, 1998).
10.6 - Fifth Supplemental Indenture, dated as of December 30, 1997, among
Pioneer NewSub1, Inc. (as successor to Pioneer USA), a Texas corporation,
the Company, a Delaware corporation, Pioneer DebtCo., Inc., a Texas
corporation, and Harris Trust and Savings Bank, an Illinois corporation,
as Trustee, with respect to the indenture identified above as Exhibit
10.1 (incorporated by reference to Exhibit 10.14 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2,
1998).
10.7 - Sixth Supplemental Indenture, dated as of December 30, 1997, among
Pioneer DebtCo. Inc.(as successor to Pioneer NewSub1, Inc.), a Texas
corporation, the Company, a Delaware corporation, and Harris Trust and
Savings Bank, an Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.1 (incorporated by reference to
Exhibit 10.15 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
10.8 - Indenture, dated July 2, 1996, among Pioneer USA (formerly MOC), as
Issuer, the Company (Mesa's successor), as Guarantor, and Harris Trust
and Savings Bank, as Trustee, relating to the 10-5/8% Senior Subordinated
Notes Due 2006 (incorporated by reference to Exhibit 4.18 to Mesa's
Quarterly Report on Form 10-Q for the period ended June 30, 1996).
10.9 - First Supplemental Indenture, dated as of April 15, 1997, among Pioneer
USA (formerly MOC), as Issuer, Mesa, the Subsidiary Guarantors named
therein, the Company, and Harris Trust and Savings Bank, as Trustee, with
respect to the indenture identified above as Exhibit 10.8 (incorporated
by reference to Exhibit 10.3 to the Company's Quarterly Report on Form
10-Q for the period ended September 30, 1997, File No. 001-13245).
10.10- Second Supplemental Indenture, dated as of August 7, 1997, among Pioneer
USA (formerly MOC), as Issuer, Mesa, the Subsidiary Guarantors named
therein, the Company, and Harris Trust and Savings Bank, as Trustee, with
respect to the indenture identified above as Exhibit 10.8 (incorporated
by reference to Exhibit 10.4 to the Company's Quarterly Report on Form
10-Q for the period ended September 30, 1997, File No. 001-13245).
83
<PAGE>
Exhibit
Number Description
- ------- -----------
10.11- Third Supplemental Indenture, dated as of December 18, 1997, among
Pioneer USA, the Subsidiary Guarantors named therein, the Company, and
Harris Trust and Savings Bank, as Trustee, with respect to the indenture
identified above as Exhibit 10.8 (incorporated by reference to Exhibit
10.6 to the Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.12- Fourth Supplemental Indenture, dated as of December 30, 1997, among
Pioneer USA, a Delaware corporation, the Company, a Delaware corporation,
Pioneer NewSub1, Inc., a Texas corporation, and Harris Trust and Savings
Bank, an Illinois corporation, as Trustee, with respect to the indenture
identified above as Exhibit 10.8 (incorporated by reference to Exhibit
10.7 to the Company's Current Report on Form 8-K, File No. 001-13245,
filed with the SEC on January 2, 1998).
10.13- Fifth Supplemental Indenture, dated as of December 30, 1997, among
Pioneer NewSub 1, Inc.(as successor to Pioneer USA), a Texas corporation,
the Company, a Delaware corporation, Pioneer DebtCo, Inc, a Texas
corporation, and Harris Trust and Savings Bank, an Illinois corporation,
as Trustee, with respect to the indenture identified above as Exhibit
10.8 (incorporated by reference to Exhibit 10.8 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2,
1998).
10.14- Sixth Supplemental Indenture, dated as of December 30, 1997, among
Pioneer DebtCo, Inc. (as successor to Pioneer NewSub1, Inc.), a Texas
corporation, the Company, a Delaware corporation, and Harris Trust and
Savings Bank, an Illinois corporation, as Trustee, with respect to the
indenture identified above as Exhibit 10.8 (incorporated by reference to
Exhibit 10.9 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
10.15- Indenture, dated April 12, 1995, between Pioneer USA (successor to
Parker & Parsley), and The Chase Manhattan Bank (National Association),
as Trustee (incorporated by reference to Exhibit 4.1 to Parker &
Parsley's Current Report on Form 8-K, dated April 12, 1995, File No.
001-10695).
10.16- First Supplemental Indenture, dated as of August 7, 1997, among Parker &
Parsley, The Chase Manhattan Bank, as Trustee, and Pioneer USA, with
respect to the indenture identified above as Exhibit 10.15 (incorporated
by reference to Exhibit 10.5 to the Company's Quarterly Report on Form
10-Q for the period ended September 30, 1997, File No. 001-13245).
10.17- Second Supplemental Indenture, dated as of December 30, 1997, among
Pioneer USA, a Delaware corporation, Pioneer NewSub1, Inc., a Texas
corporation, and The Chase Manhattan Bank, a New York banking
association, as Trustee, with respect to the indenture identified above
as Exhibit 10.15 (incorporated by reference to Exhibit 10.17 to the
Company's Current Report on Form 8-K, File No. 001- 13245, filed with the
SEC on January 2, 1998).
10.18- Third Supplemental Indenture, dated as of December 30, 1997, among
Pioneer New Sub1, Inc.(as successor to Pioneer USA), a Texas corporation,
Pioneer DebtCo, Inc., a Texas corporation, and The Chase Manhattan Bank,
a New York banking association, as Trustee, with respect to the
indenture identified above as Exhibit 10.15 (incorporated by reference
to Exhibit 10.18 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
10.19- Fourth Supplemental Indenture, dated as of December 30, 1997, among
Pioneer DebtCo, Inc. (assuccessor to Pioneer NewSub1, Inc., as successor
to Pioneer USA), a Texas corporation, the Company, a Delaware
corporation, Pioneer USA, a Delaware corporation, and The Chase Manhattan
Bank, a New York banking association, as trustee, with respect to the
indenture identified above as Exhibit 10.15 (incorporated by reference
to Exhibit 10.19 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
84
<PAGE>
Exhibit
Number Description
- ------- -----------
10.20- Guarantee, dated as of December 30, 1997, by Pioneer USA relating to the
$150,000,000 in aggregate principal amount of 8-7/8% Senior Notes due
2005 and $150,000,000 in aggregate principal amount of 8-1/4% Senior
Notes due 2007 issued under the indenture identified above as Exhibit
10.15 (incorporated by reference to Exhibit 10.20 to the Company's
Current Report on Form 8-K, File No. 001-13245, filed with the SEC on
January 2, 1998).
10.21- Form of 8-7/8% Senior Notes Due 2005, dated as of April 12, 1995, in the
aggregate principal amount of $150,000,000, together with Officers'
Certificate dated April 12, 1995, establishing the terms of the 8- 7/8%
Senior Notes Due 2005 pursuant to the indenture identified above as
Exhibit 10.15 (incorporated by reference to Exhibit 4.2 to Parker &
Parsley's Quarterly Report on Form 10-Q for the period ended June 30,
1995, File No. 001-10695).
10.22- Form of 8-1/4% Senior Notes due 2007, dated as of August 22, 1995, in
the aggregate principal amount of $150,000,000, together with Officers'
Certificate dated August 22, 1995, establishing the terms of the 8-1/4%
Senior Notes due 2007 pursuant to the indenture identified above as
Exhibit 10.15 (incorporated by reference to Exhibit 1.2 to Parker &
Parsley's Current Report on Form 8-K, dated August 17, 1995, File No.
001-10695).
10.23- Indenture, dated January 13, 1998, between the Company and The Bank of
New York, as Trustee (incorporated by reference to Exhibit 99.1 to the
Company's and Pioneer USA's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 14, 1998).
10.24- First Supplemental Indenture, dated as of January 13, 1998, among the
Company, Pioneer USA, as the Subsidiary Guarantor, and The Bank of New
York, as Trustee, with respect to the indenture identified above as
Exhibit 10.23 (incorporated by reference to Exhibit 99.2 to the Company's
and Pioneer USA's Current Report on Form 8-K, File No. 001-13245, filed
with the SEC on January 14, 1998).
10.25- Form of 6.50% Senior Notes Due 2008 of the Company (incorporated by
reference to Exhibit 99.3 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14,
1998).
10.26- Form of 7.20% Senior Notes Due 2028 of the Company (incorporated by
reference to Exhibit 99.4 to the Company's and Pioneer USA's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC on January 14,
1998).
10.27- Guarantee (2008 Notes), dated as of January 13, 1998, entered into by
Pioneer USA (incorporated by reference to Exhibit 99.5 to the Company's
and Pioneer USA's Current Report on Form 8-K, File No. 001- 13245, filed
with the SEC on January 14, 1998).
10.28- Guarantee (2028 Notes), dated as of January 13, 1998, entered into by
Pioneer USA (incorporated by reference to Exhibit 99.6 to the Company's
and Pioneer USA's Current Report on Form 8-K, File No. 001- 13245, filed
with the SEC on January 14, 1998).
10.29- Amended and Restated Credit Facility Agreement (Primary Facility), dated
as of December 18, 1997, between the Company, as Borrower, and
NationsBank of Texas, N.A., as Administrative Agent, CIBC Inc., as
Documentation Agent, Morgan Guaranty Trust Company of New York, as
Documentation Agent, and The Chase Manhattan Bank, as Syndication Agent;
and the other Co-Agents and lenders named therein (incorporated by
reference to Exhibit 10.1 to the Company's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 2, 1998).
85
<PAGE>
Exhibit
Number Description
- ------- -----------
10.30 - First Amendment to Amended and Restated Credit Facility Agreement
(Primary Facility), dated as of June 29, 1998, by and among the Company,
as Borrower, NationsBank, N.A., as Administrative Agent, CIBC Inc., as
Documentation Agent, Morgan Guaranty Trust Company of New York, as
Documentation Agent, The Chase Manhattan Bank, as Syndication Agent, and
the Co-Agents and other Lenders signatory thereto (incorporated by
reference to the Company's Annual Report on Form 10-K for the year ended
December 31, 1998, File No. 001-13245).
10.31 - Amended and Restated Credit Facility Agreement (364 Day Facility), dated
as of December 18, 1997, between the Company, as Borrower, and
NationsBank of Texas, N.A., as Administrative Agent, CIBC Inc., as
Documentation Agent, Morgan Guaranty Trust Company of New York, as
Documentation Agent, and The Chase Manhattan Bank, as Syndication Agent;
and the other Co-Agents and lenders named therein (incorporated by
reference to Exhibit 10.2 to the Company's Current Report on Form 8-K,
File No. 001-13245, filed with the SEC on January 2, 1998).
10.32 - First Amendment to Amended and Restated Credit Facility Agreement (364
Day Facility), dated as of June 29, 1998, by and among the Company, as
Borrower, NationsBank, N.A., as Administrative Agent, CIBC Inc., as
Documentation Agent, Morgan Guaranty Trust Company of New York, as
Documentation Agent, The Chase Manhattan Bank, as Syndication Agent, and
the Co-Agents and other Lenders signatory thereto (incorporated by
reference to the Company's Annual Report on Form 10-K for the year ended
December 31, 1998, File No. 001-13245).
10.33 - Credit Agreement, dated as of December 18, 1997, among Chauvco, Canadian
Imperial Bank of Commerce, as Agent, and the other Lenders named therein
(incorporated by reference to Exhibit 10.3 to the Company's Current
Report on Form 8-K, File No. 001-13245, filed with the SEC on January 2,
1998).
10.34 - First Amending Agreement, dated June 29, 1998, among Pioneer Natural
Resources Canada Inc. (formerly Chauvco), Canadian Imperial Bank of
Commerce, and the Lenders thereto, with respect to the Credit Agreement
identified above as Exhibit 10.33 (incorporated by reference to the
Company's Annual Report on Form 10-K for the year ended December 31,
1998, File No. 001-13245).
10.35 - Note, dated December 22, 1997, between the Company, as Borrower, and
NationsBank of Texas, N.A., as Lender (incorporated by reference to
Exhibit 10.21 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
10.36H- 1991 Stock Option Plan of Mesa (incorporated by reference to Exhibit
10(v) to Mesa's Annual Report on Form 10-K for the period ended December
31, 1991).
10.37H- 1996 Incentive Plan of Mesa (incorporated by reference to Exhibit 10.28
to the Company's Registration Statement on Form S-4, dated June 27,
1997, Registration No. 333-26951).
10.38H- Parker & Parsley Long-Term Incentive Plan, dated February 19, 1991
(incorporated by reference to Exhibit 4.1 to Parker & Parsley's
Registration Statement on Form S-8, Registration No. 33-38971).
10.39H- First Amendment to the Parker & Parsley Long-Term Incentive Plan, dated
August 23, 1991 (incorporated by reference to Exhibit 10.2 to Parker &
Parsley's Registration Statement on Form S-1, dated February 28, 1992,
Registration No. 33-46082).
10.40H- The Company's Long-Term Incentive Plan (incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on Form S-8,
Registration No. 333-35087).
86
<PAGE>
Exhibit
Number Description
- ------- -----------
10.41H- The Company's Employee Stock Purchase Plan (incorporated by reference
to Exhibit 4.1 to the Company's Registration Statement on Form S-8,
Registration No. 333-35165).
10.42 - Amendment No. 1 to the Company's Employee Stock Purchase Plan, dated
December 9, 1998 (incorporated by reference to the Company's Annual
Report on Form 10-K for the year ended December 31, 1998, File No.
001-13245).
10.43H- The Company's Deferred Compensation Retirement Plan (incorporated by
reference to Exhibit 4.1 to the Company's Registration Statement on
Form S-8, Registration No. 333- 39153).
10.44H- Pioneer USA 401(k) Plan (incorporated by reference to Exhibit 4.1 to
the Company's Registration Statement on Form S-8, Registration No.
333-39249).
10.45H- Pioneer USA Matching Plan (incorporated by reference to Exhibit 10.42
to the Company's Annual Report on Form 10-K for the year ended December
31, 1997, File No. 001-13245).
10.46H- Omnibus Amendment to Nonstatutory Stock Option Agreements, included as
part of the Parker & Parsley Long-Term Incentive Plan, dated as of
November 16, 1995, between Parker & Parsley and Named Executive Officers
identified on Schedule 1 setting forth additional details relating to
the Parker & Parsley Long-Term Incentive Plan (incorporated by
reference to Parker & Parsley's Annual Report on Form 10-K for the year
ended December 31, 1995, File No. 001-10695).
10.47H- Mesa Management Severance Plan, dated April 4, 1997, including a
Schedule of Participants on Schedule A for the purpose of defining the
payment of certain benefits upon the termination of the officer's
employment under certain circumstances (incorporated by reference to
Exhibit 10.29 to the Company's Registration Statement on Form S-4, dated
June 27, 1997, Registration No. 333-26951).
10.48H- Severance Agreement, dated as of August 8, 1997, between the Company and
Scott D. Sheffield, together with a schedule identifying substantially
identical agreements between the Company and each of the other named
executive officers identified on Schedule I for the purpose of defining
the payment of certain benefits upon the termination of the officer's
employment under certain circumstances (incorporated by reference to
Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the
period ended September 30, 1997, File No. 001-13245).
10.49H- Indemnification Agreement, dated as of August 8, 1997, between the
Company and Scott D. Sheffield, together with a schedule identifying
substantially identical agreements the Company and each of the Company's
other directors and named executive officers identified on Schedule I
(incorporated by reference to Exhibit 10.8 to the Company's Quarterly
Report on Form 10-Q for the period ended September 30, 1997, File No.
001-13245).
10.50 - Purchase and Sale Agreement, dated as of October 22, 1997, between
Cometra Energy, L.P., and Pioneer USA (incorporated by reference to
Exhibit 10.22 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on January 2, 1998).
10.51 - Combination Agreement, dated September 3, 1997, between the Company and
Chauvco (incorporated by reference to Exhibit 2.1 to the Company's
Current Report on Form 8-K, File No. 001-13245, filed with the SEC on
October 2, 1997).
10.52 - Plan of Arrangement, as amended, under Section 186 of the Business
Corporations Act (Alberta) (incorporated by reference to Exhibit 2.2 to
the Company's Current Report on Form 8-K, File No. 001- 13245, filed
with the SEC on January 2, 1998).
87
<PAGE>
Exhibit
Number Description
- ------- -----------
10.53 - Support Agreement, dated as of December 18, 1997, between the Company
and Pioneer Canada (incorporated by reference to Exhibit 2.3 to the
Company's Current Report on Form 8-K, File No. 001- 13245, filed with
the SEC on January 2, 1998).
10.54 - Stock Purchase Agreement, dated April 26, 1996, between Mesa and DNR
(incorporated by reference to Exhibit No. 10 to Mesa's Current Report on
Form 8-K filed with the SEC on April 29, 1996).
10.55 - "B" Contract Production Allocation Agreement, dated July 29, 1991, and
effective as of January 1, 1991, between Colorado Interstate Gas Company
and Mesa Operating Limited Partnership (incorporated by reference to
Exhibit 10(r) to Mesa's Annual Report on Form 10-K for the period ended
December 31, 1991).
10.56 - Amendment to "B" Contract Production Allocation Agreement effective as
of January 1, 1993, between Colorado Interstate Gas Company and Mesa
Operating Limited Partnership (incorporated by reference to Exhibit
10.24 to Mesa's Registration Statement on Form S-1, Registration No.
33-51909).
10.57 - Amarillo Supply Agreement between Mesa Operating Limited Partnership,
Seller, and Energas Company, a division of Atmos Energy Corporation,
Buyer, dated effective January 2, 1993 (incorporated by reference to
Exhibit 10.14 to Mesa's Annual Report on Form 10-K for the period ended
December 31, 1995).
10.58H- Agreement of Partnership of P&P Employees 89-B Conv., L.P. (formerly P&P
Employees 89-B GP), dated October 31, 1989, among Parker & Parsley, Ltd.
and the Investor Partners (as defined therein, which includes
individuals who are directors and executive officers of Parker &
Parsley), together with a schedule identifying substantially identical
documents and setting forth the material details in which those
documents differ from the foregoing document (incorporated by reference
to Exhibit 10.50 to Parker & Parsley's Registration Statement on Form
S-4, dated December 31, 1990, Registration No. 33-38436).
10.59H- Amendment to Agreement of Partnership of P&P Employees 89-B GP, dated
May 31, 1990, among Parker & Parsley, Ltd. and the Investor Partners (as
defined therein, which includes individuals who are directors and
executives officers of Parker & Parsley), together with a schedule
identifying substantially identical documents and setting forth the
material details in which those documents differ form the foregoing
document (incorporated by reference to Exhibit 10.51 to Parker &
Parsley's Registration Statement on Form S-4, dated December 31, 1990,
Registration No. 33-38436).
10.60H- Schedule identifying additional documents substantially identical to
the Amendment to Agreement of Partnership of P&P Employees 89-B GP
included as Exhibit 10.59 and setting forth the material details in
which those documents differ from that document (incorporated by
reference to Exhibit 10.52 to Parker & Parsley's Registration Statement
on Form S-1, dated February 28, 1992, Registration No. 33-46082).
10.61H- Agreement of Partnership of P&P Employees 90 Spraberry Private
Development GP, dated October 16, 1990, among Parker & Parsley, Ltd.,
James D. Moring, and the General Partners (as defined therein, which
includes individuals who are directors and executive officers of Parker
& Parsley), and form of Amendment to Agreement of Partnership of P&P
Employees 90 Spraberry Private Development GP, together with a schedule
identifying substantially identical documents and setting forth the
material details in which those documents differ from the foregoing
document (incorporated by reference to Exhibit 10.52 to Parker &
Parsley's Registration Statement on Form S-4, dated December 31, 1990,
Registration No. 33- 38436).
88
<PAGE>
Exhibit
Number Description
- ------- -----------
10.62H- Amendment to Agreement of Partnership of Parker & Parsley 90-A GP, dated
February 19, 1991, among Parker & Parsley Development Company and the
Investor Partners (as defined therein, which includes individuals who
are directors and executive officers of Parker & Parsley), together with
a schedule identifying substantially identical documents and setting
forth the material details in which those documents differ from the
foregoing document (incorporated by reference to Exhibit 10.58 to Parker
& Parsley's Registration Statement on Form S-1, dated February 28, 1992,
Registration No. 33-46082).
10.63H- Agreement of Partnership of P&P Employees 91-A, GP, dated September 30,
1991, among Parker & Parsley Development Company, James D. Moring, and
the General Partners (as defined therein, which includes individuals who
are directors and executive officers of Parker & Parsley), together with
a schedule identifying substantially identical documents and setting
forth the material details in which those documents differ from the
foregoing document (incorporated by reference to Exhibit 10.61 to Parker
& Parsley's Registration Statement on Form S-1, dated February 28, 1992,
Registration No. 33-46082).
10.64H- Amendment to Agreement of Partnership of P&P Employees 90 Spraberry
Private Development GP, dated April 22, 1991, among the Partners (as
defined therein, which includes individuals who are directors and
executive officers of Parker & Parsley) (incorporated by reference to
Exhibit 10.67 to Parker & Parsley's Registration Statement on Form S-1,
dated February 28, 1992, Registration No. 33-46082).
10.65 - Share Purchase Agreement, dated February 13, 1998, among the Company,
Trimac Corporation and 761795 Alberta Ltd. (incorporated by reference to
Exhibit 99.1 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on February 23, 1998).
10.66 - Share Purchase Agreement, dated February 13, 1998, among the Company,
398215 Alberta Ltd. and Guy J. Turcotte (incorporated by reference to
Exhibit 99.2 to the Company's Current Report on Form 8-K, File No.
001-13245, filed with the SEC on February 23, 1998).
10.67 - Option to Purchase Agreement, dated December 16, 1998, by and among
Costilla Energy, Inc. ("Costilla"), Pioneer USA, and Pioneer Resources
Producing, L.P. (incorporated by reference to Exhibit 1 to the Company's
statement on Schedule 13D relating to the common stock of Costilla,
filed with the SEC on December 22, 1998, File No. 0-21411).
10.68 - Purchase and Sale Agreement, dated December 16, 1998, by and among
Costilla, Pioneer USA, and Pioneer Resources Producing, L.P.
(incorporated by reference to Exhibit 2 to the Company's statement on
Schedule 13D relating to the common stock of Costilla, filed with the
SEC on December 22, 1998, File No. 0-21411).
10.69 - Purchase and Sale Agreement, dated May 16, 1999, by and between Pioneer
USA and Pioneer Resources Producing, L.P., as Seller, and Prize Energy
Corp., as Purchaser (incorporated by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K filed with the SEC on July 13,
1999).
10.70 - Second Amended and Restated Credit Facility Agreement (Primary Facility)
by and among Pioneer Natural Resources Company, as borrower,
NationsBank, N.A., as Administrative Agent, CIBC Inc. as Documentation
Agent, Morgan Guarantee Trust Company of New York, as Documentation
Agent, Chase Bank of Texas, National Association, as Syndication Agent,
The Co-Agents and certain other lenders dated as of March 19, 1999
(incorporated by reference to Exhibit 10.69 to the Company's Annual
Report on Form 10-K for the period ended December 31, 1998, File No.
1-13245).
89
<PAGE>
Exhibit
Number Description
- ------- -----------
10.71 - Second Amended and Restated Credit Facility Agreement (364 Day Facility)
by and among Pioneer Natural Resources Company, as borrower,
NationsBank, N.A., as Administrative Agent, CIBC Inc. as Documentation
Agent, Morgan Guarantee Trust Company of New York, as Documentation
Agent, Chase Bank of Texas, National Association, as Syndication Agent,
The Co-Agents and certain other lenders dated as of March 19, 1999
(incorporated by reference to Exhibit 10.70 to the Company's Annual
Report on Form 10-K for the period ended December 31, 1998, File No.
1-13245).
10.72*- First Amendment to the Company's Long-Term Incentive Plan, effective as
of November 23, 1998.
10.73*- Amendment No. 2 to the Company's Long-Term Incentive Plan, effective as
of May 20, 1999.
10.74*- Amendment No. 2 to the Company's Employee Stock Purchase Plan, dated
December 14, 1999.
10.75 - Voting and Shareholders Agreement dated as of February 8, 2000 between
Prize Energy Corp. and its stockholders (incorporated by reference to
Exhibit 10.1 to the Company's statement on Schedule 13D relating to the
common stock of Prize Energy Corp., filed with the SEC on February 18,
2000, File No. 005-54797).
10.76*- Amendment No. 3 to the Company's Long-Term Incentive Plan, effective as
of February 17, 2000.
21.1* - Subsidiaries of the registrant.
23.1* - Consent of Ernst & Young LLP.
23.2* - Consent of KPMG LLP.
27.1* - Financial Data Schedule
- ---------------
*Filed herewith
H Executive Compensation Plan or Arrangement previously filed pursuant to Item
14(c).
(b) Reports on Form 8-K
On December 14, 1999, the Company filed a Current Report on Form 8-K to
report, under Items 5. and 7., supplemental information to the Current Report on
Form 8-K filed with the SECon July 13, 1999. Specifically, the Company's Current
Report on Form 8-K dated December 14, 1999 supplemented the information
regarding the disposition of assets and related proforma condensed financial
statements and supplemental data provided under Items 2. and 7. of the Company's
Current Report on Form 8-K filed with the SEC on July 13, 1999.
(c) Exhibits
The exhibits to this Report required to be filed pursuant to Item 14(c)
are listed under "Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K - Listing of Financial Statements and Exhibits - Exhibits" above and
in the "Index to Exhibits" attached hereto.
(d) Financial Statement Schedules
No financial statement schedules are required to be filed as part of
this Report or they are inapplicable.
90
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PIONEER NATURAL RESOURCES COMPANY
Date: February 29, 2000 By: /s/ Scott D. Sheffield
-----------------------------
Scott D. Sheffield, President
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Scott D. Sheffield Chairman of the Board, President February 29, 2000
- --------------------------- and Chief Executive Officer
Scott D. Sheffield (principal executive officer)
/s/ Timothy L. Dove Executive Vice President and February 29, 2000
- --------------------------- Chief Financial Officer
Timothy L. Dove
/s/ Rich Dealy Vice President and Chief February 29, 2000
- --------------------------- Accounting Officer
Rich Dealy
/s/ James R. Baroffio Director February 29, 2000
- ---------------------------
James R. Baroffio
/s/ R. Hartwell Gardner Director February 29, 2000
- ---------------------------
R. Hartwell Gardner
/s/ James L. Houghton Director February 29, 2000
- ---------------------------
James L. Houghton
/s/ Jerry P. Jones Director February 29, 2000
- ---------------------------
Jerry P. Jones
/s/ Richard E. Rainwater Director February 29, 2000
- ---------------------------
Richard E. Rainwater
/s/ Charles E. Ramsey, Jr. Director February 29, 2000
- ---------------------------
Charles E. Ramsey, Jr.
/s/ Robert L. Stillwell Director February 29, 2000
- ---------------------------
Robert L. Stillwell
91
<PAGE>
EXHIBIT 10.72
FIRST AMENDMENT
TO
PIONEER NATURAL RESOURCES COMPANY
LONG-TERM INCENTIVE PLAN
Pioneer Natural Resources Company, a Delaware corporation (the
"Company"), has adopted this First Amendment to Pioneer Natural Resources
Company Long-Term Incentive Plan (the "Plan") effective as of November 23, 1998.
"Section 1.7 of the Plan is hereby amended by replacing all references to
20% with 30%."
Except as to the extent modified by this amendment, the Plan is hereby
ratified and confirmed in all respects.
IN WITNESS WHEREOF, Pioneer Natural Resources Company, acting by and
through its officer hereunto duly authorized, has executed this instrument as of
the date first written above.
PIONEER NATURAL RESOURCES COMPANY
By: /s/ Scott D. Sheffield
----------------------------------
Scott D. Sheffield
President
<PAGE>
EXHIBIT 10.73
AMENDMENT NO. 2
TO
PIONEER NATURAL RESOURCES COMPANY
LONG-TERM INCENTIVE PLAN
AMENDMENT NO. 2 (this "Amendment", to that certain Long-Term Incentive
Plan (the "Plan", of Pioneer Natural Resources Company (the "Company") is
effective as of May 20, 1999.
RECITALS
WHEREAS, the Company has adopted the Plan; and
WHEREAS, the Board of Directors and the shareholders of the Company have
approved an amendment to the Plan, which amendment is memorialized below in this
Amendment.
NOW, THEREFORE, the Plan is hereby amended as follows:
1. Deletion of Section 5. Section 5 of the Plan and any cross-
references to that Section are hereby deleted in their entirety.
2. Confirmation of the Plan. Except as to the extent modified by this
Amendment, the Plan is hereby
ratified and confirmed in all respects.
IN WITNESS WHEREOF, the Company has caused this Amendment to be executed
by its duly authorized officer to be effective as of May 20, 1999.
PIONEER NATURAL RESOURCES COMPANY
By: /s/ Mark L. Withrow
---------------------------------
Name: Mark L. Withrow
Title: Executive Vice President and
General Counsel
<PAGE>
EXHIBIT 10.74
AMENDMENT NO. 2
TO THE
PIONEER NATURAL RESOURCES COMPANY
EMPLOYEE STOCK PURCHASE PLAN
Pursuant to the provisions of Paragraph 15 thereof, the Pioneer Natural
Resources Company Employee Stock Purchase Plan (the "Plan") is hereby amended in
the following respects only:
Effective as of January 1, 2000, the first sentence of Subparagraph (b)
of Paragraph 7 of the Plan is hereby amended as follows:
The option price per share of Stock to be paid by each Eligible Employee
on each exercise of his option shall be an amount equal to the lesser of
85% of the Fair Market Value of the Stock on the date of exercise or on
the date of grant.
IN WITNESS WHEREOF, this Amendment has been executed as of this 14th day
of December, 1999.
PIONEER NATURAL RESOURCES COMPANY
By: /s/ Mark L. Withrow
----------------------------------
Mark L. Withrow
Executive Vice President and
General Counsel
<PAGE>
EXHIBIT 10.76
Amendment No. 3
to
PIONEER NATURAL RESOURCES COMPANY
LONG-TERM INCENTIVE PLAN
AMENDMENT NO. 3 (this "Amendment") to that certain Long-Term Incentive Plan
(the "Plan") of Pioneer Natural Resources Company (the "Company") is effective
as of February 17, 2000.
RECITALS
WHEREAS, the Company has adopted the Plan; and
WHEREAS, the Board of Directors of the Company has approved an amendment to
the Plan, which amendment is memorialized below in this Amendment.
NOW, THEREFORE, the Plan is hereby amended as follows:
"Section 1.7 of the Plan is hereby amended by replacing all references to
30% with 40%."
IN WITNESS WHEREOF, the Company has caused this Amendment to be executed by
its duly authorized officer to be effective as of February 17, 2000.
PIONEER NATURAL RESOURCES COMPANY
By: /s/ Mark L. Withrow
-------------------------------
Name: Mark L. Withrow
Title: Executive Vice President and
General Counsel
<PAGE>
EXHIBIT 21.1
SUBSIDIARIES OF THE COMPANY
State or Jurisdiction
of Organization Subsidiaries
- ------------------------ ------------
Delaware Bridge Oil (U.S.A.) Inc.
Bermuda CR International Limited
Delaware DMLP Co.
Delaware Mesa Environmental Ventures Co.
Texas Mesa Offshore Royalty Partnership
Delaware P&PCanada LP Co.
Delaware Parker & Parsley Argentina, Inc.
Turks and Caicos Islands Parker & Parsley Capital LLC
Cayman Islands Parker & Parsley International Holdings, Ltd.
Australia Parker & Parsley Petroleum Australia Holdings Pty
Limited
Australia Parker & Parsley Petroleum Australia Pty Limited
Texas Pioneer Natural Resources Scholarship Foundation
New York Parker & Parsley Transfer Agent Corporation
Delaware Pioneer Holding Inc.
Delaware Pioneer International Resources Company
Texas Pioneer Natural Gas Company
Argentina Pioneer Natural Resources (Argentina) S.A.
Canada Pioneer Natural Resources Canada Inc.
Cayman Islands Pioneer Natural Resources (Cayman) Ltd.
Cayman Islands Pioneer Natural Resources Guatemala Ltd.
South Africa Pioneer Natural Resources South Africa (Pty) Limited
Argentina Pioneer Natural Resources (Tierra Del Fuego) S.A.
Delaware Pioneer Natural Resources USA, Inc.
Delaware Pioneer Resources Inc.
Bahamas Pioneer Resources Africa, Ltd.
Delaware Pioneer Resources China, Inc.
Bahamas Pioneer Resources Gabon - Olowi Ltd.
Delaware Pioneer Resources Producing L.P.
Texas Pioneer Uravan, Inc.
Delaware PNR Resources (USA) Inc.
Texas PNRC Properties L.P.
Delaware Westpan NGL Co.
<PAGE>
State or Jurisdiction
of Organization Subsidiaries
- ------------------------ ------------
Partnerships that Pioneer Natural Resources USA, Inc.
is the managing general partner
- -----------------------------------------------------
Texas Parker & Parsley 81-I, Ltd.
Texas Parker & Parsley 81-II, Ltd.
Texas Parker & Parsley 82-I, Ltd.
Texas Parker & Parsley 82-II, Ltd.
Texas Parker & Parsley 82-III, Ltd.
Texas Parker & Parsley 83-A, Ltd.
Texas Parker & Parsley 83-B, Ltd.
Texas Parker & Parsley 84-A, Ltd.
Texas Parker & Parsley 85-A, Ltd.
Texas Parker & Parsley 85-B, Ltd.
Texas Parker & Parsley Private Investment 85-A Ltd.
Texas Parker & Parsley Selected 85 Private Investment, Ltd.
Texas Parker & Parsley 86-A, Ltd.
Texas Parker & Parsley 86-B, Ltd.
Texas Parker & Parsley 86-C, Ltd.
Texas Parker & Parsley Private Investment 86, Ltd.
Delaware Parker & Parsley 87-A, Ltd.
Delaware Parker & Parsley 87-B, Ltd.
Delaware Parker & Parsley 87-A Conv., Ltd.
Delaware Parker & Parsley 87-B Conv., Ltd.
Delaware Parker & Parsley Private Investment 87, Ltd.
Delaware Parker & Parsley Producing Properties 87-A, Ltd.
Delaware Parker & Parsley Producing Properties 87-B, Ltd.
Delaware Parker & Parsley 88-A, L.P.
Delaware Parker & Parsley 88-B, L.P.
Delaware Parker & Parsley 88-C, L.P.
Delaware Parker & Parsley 88-A Conv., L.P.
Delaware Parker & Parsley 88-B Conv., L.P.
Delaware Parker & Parsley 88-C Conv., L.P.
Delaware Parker & Parsley Private Investment 88, L.P.
Delaware Parker & Parsley Producing Properties 88-A, L.P.
Delaware Parker & Parsley 89-A, L.P.
Delaware Parker & Parsley 89-B, L.P.
Texas Parker & Parsley 89-A Conv., L.P.
Texas Parker & Parsley 89-B Conv., L.P.
Texas P&P Employees 89-A Conv., L.P.
Texas P&P Employees 89-B Conv., L.P.
Delaware Parker & Parsley Private Investment 89, L.P.
Texas P&P Employees Private Investment 89, L.P.
Delaware Parker & Parsley 90-A Conv., L.P.
Delaware Parker & Parsley 90-B Conv., L.P.
Delaware Parker & Parsley 90-C Conv., L.P.
Delaware Parker & Parsley 90-A, L.P.
Delaware Parker & Parsley 90-B, L.P.
Delaware Parker & Parsley 90-C, L.P.
Texas P&P Employees 90-A Conv., L.P.
Texas P&P Employees 90-B Conv., L.P.
Texas P&P Employees 90-C Conv., L.P.
Delaware Parker & Parsley Private Investment 90 Conv., L.P.
Texas P&P Employees Private Investment 90 Conv., L.P.
Delaware Parker & Parsley 90 Spraberry Private Development
Conv., L.P.
Texas P&P Employees 90 Spraberry Private Development L.P.
<PAGE>
State or Jurisdiction
of Organization Subsidiaries
- ------------------------ ------------
Delaware Parker & Parsley 91-A, L.P.
Delaware Parker & Parsley 91-B, L.P.
Delaware Parker & Parsley 91-A Conv., L.P.
Delaware Parker & Parsley 91-B Conv., L.P.
Texas P&P Employees 91-A G.P.
Texas P&P Employees 91-B G.P.
Texas Parker & Parsley 1992 Direct Investment Program, Ltd.
Texas Parker & Parsley 1993 Direct Investment Program, Ltd.
Texas Parker & Parsley 1994 Direct Investment Program, Ltd.
Texas Midkiff Development Drilling Program, Ltd.
<PAGE>
EXHIBIT 23.1
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in the Registration Statements (No.
333-35087, No. 333-35165, No. 333- 39153, No. 333-39249, No. 33-44851, No.
333-35085 and No. 333-35175) on Form S-8 and (No. 333-42315, No. 333- 44439 and
No. 333-39381) on Form S-3 of Pioneer Natural Resources Company and subsidiaries
of our report dated January 24, 2000, with respect to the consolidated financial
statements of Pioneer Natural Resources Company included in this Annual Report
on Form 10-K for the year ended December 31, 1999.
Ernst & Young LLP
Dallas, Texas
February 25, 2000
<PAGE>
EXHIBIT 23.2
CONSENT OF INDEPENDENT AUDITORS
The Board of Directors and Stockholders
Pioneer Natural Resources Company:
We consent to the incorporation by reference in the Registration Statements
(No. 333-35087, No. 333-35165, No. 333-39153, No. 333-39249, No. 33-44851, No.
333-35085 and No. 333-35175) on Form S-8 and Registration Statements (No.
333-42315, No. 333-44439 and No. 333-39381) on Form S-3 of Pioneer Natural
Resources Company and subsidiaries and its predecessors of our report dated
February 13, 1998, related to the Pioneer Natural Resources Company and
subsidiaries consolidated statements of operations and comprehensive loss,
stockholders' equity, and cash flows for the year ended December 31, 1997, which
report appears in the December 31, 1999 annual report on Form 10-K of Pioneer
Natural Resources Company.
KPMG LLP
Midland, Texas
March 23, 1999
<PAGE>
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