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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997
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. [ ]
Aggregate market value of the voting stock held by
non-affiliates of the Registrant as of February 27, 1998....... $2,377,781,760
Number of shares of Common Stock outstanding as of
February 27, 1998.............................................. 100,899,720
Documents Incorporated by Reference:
(1) Proxy Statement for Annual Meeting of Shareholders to be held May 21, 1998
- Referenced in Part III of this report.
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 Item 1. Business
Business
3. Narrative Description of the Item 1. Business
Business Item 2. Properties
4. Selected Consolidated Financial Item 6. Selected Financial Data
Information Item 8. Financial Statements and
Supplementary Data
5. Management's Discussion and Item 7. Management's Discussion and
Analysis Analysis of Financial Conditions
and Results of Operations
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 Report contain forward looking statements that
involve risks and uncertainties. Accordingly, no assurances can be given that
the actual events and results will not be materially different than the
anticipated results described in the forward looking statements. See "Item 1.
Business - Competition, Markets and Regulation" and "Item 1. Business - Risks
Associated with Business Activities" for a description of various factors that
could materially affect the ability of the Company to achieve the anticipated
results described in the forward looking statements.
PART I
Unless otherwise specified, all dollar amounts are expressed in United
States dollars. Certain oil and gas terms used in this Report are defined under
"Item 1. Business - Definition of Certain Oil and Gas Terms".
ITEM 1. BUSINESS
General
Pioneer Natural Resources Company (the "Company") was formed in April 1997
as a Delaware corporation and, prior to August 7, 1997, had not conducted any
significant activities. Effective as of August 7, 1997, Parker & Parsley
Petroleum Company ("Parker & Parsley"), formerly a Delaware corporation, and
MESA Inc. ("Mesa"), formerly a Texas corporation, completed their business
combination pursuant to an Amended and Restated Agreement and Plan of Merger
dated as of April 6, 1997 (the "Merger Agreement"), among Parker & Parsley, Mesa
and its wholly-owned subsidiaries, the Company and Mesa Operating Company
("MOC"). The Company was significantly expanded by the subsequent acquisition of
the Canadian and Argentine oil and gas business of Chauvco Resources Ltd.
("Chauvco"), a publicly traded independent oil and gas company based in Calgary,
Canada on December 18, 1997.
In accordance with the provisions of Accounting Principles Board No. 16,
"Business Combinations", both the merger with Mesa and the acquisition of
Chauvco have been accounted for as purchases by the Company (formerly Parker &
Parsley). As a result, the historical financial, reserve and other statistical
information for the Company are those of Parker & Parsley, and the Company's
financial, reserve and other statistical information present the addition of
Mesa's and Chauvco's assets and liabilities as an acquisition by Parker &
Parsley in August and December 1997, respectively.
The Company's proved reserves at December 31, 1997 totaled 761.6 million
BOE, representing $3.1 billion in SEC 10 Value. Of the total, domestic reserves
represent 81% of the BOEs and 82% of the SEC 10 Value.
The Company's business activities are conducted through wholly-owned
subsidiaries and are comprised of the business activities formerly conducted by
Parker & Parsley, Mesa and Chauvco. Domestic drilling and production operations
are principally located in Texas, Kansas, Oklahoma, Louisiana, New Mexico and
offshore Gulf of Mexico. The Company also owns interests in oil and gas
properties in Argentina and Canada.
The Company's executive offices are located at 1400 Williams Square West,
5205 N. O'Connor Blvd., Irving, Texas 75039, and its telephone number at those
offices is (972) 444-9001. The Company maintains division offices in Midland and
Houston, Texas, Oklahoma City, Oklahoma, Buenos Aires, Argentina and Calgary,
Canada. At December 31, 1997, the Company had 1,321 employees, 399 of which were
employed in field and plant operations.
Mission and Strategies
The Company's mission is to provide its shareholders with superior
long-term profitability and value. The "opportunity driven" strategies to be
employed to achieve this mission will include: (a) developing and increasing
production from existing properties through low-risk development drilling and
other activities, (b) concentrating on defined geographic areas to achieve
operating and technical efficiencies, (c) pursuing strategic acquisitions in the
Company's core areas that will complement the Company's existing asset base and
that will provide additional growth opportunities, (d) utilizing or acquiring
technological and operating efficiencies to selectively expand into new
geographic areas that feature producing properties and provide
exploration/exploitation opportunities, (e) allocating the personnel and
technology necessary to increase the Company's exploration opportunities, (f)
maintaining financial flexibility to take advantage of additional exploration,
development and acquisition opportunities and (g) encouraging high levels of
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equity ownership among senior managers and the Company's Board of Directors to
further align the interests of management and shareholders. The Company is
committed to continuing to enhance shareholder value through adherence to these
strategies.
Business Activities
Production
The Company focuses its efforts toward increasing its average daily
production of oil and gas through development drilling, production enhancement
activities and acquisitions of producing properties. Average daily oil and gas
production have each increased every year since 1991 with the exception of 1996
when average daily production declined due to significant property dispositions.
In spite of production decreases due to property sales, the Company's efforts
towards production growth have been largely successful as illustrated by the
five-year average daily production growth rates. Comparing 1992 to 1997, average
daily oil production has increased 279% and average daily gas production has
increased 327%, while production costs per BOE have declined 30%. Production,
price and cost information with respect to the Company's properties for each of
1997, 1996 and 1995 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 1993 through the end of 1997, the Company drilled 2,351 gross
(1,585 net) wells, 94% of which were successfully completed as productive wells,
at a total cost (net to the Company's interest) of $938 million. During 1997,
the Company drilled 592 gross (405 net) wells for a total cost (net to the
Company's interest) of approximately $343 million, 72% of which was spent on
development wells and related facilities. The Company's current 1998 capital
expenditure budget is $500 million which the Company has allocated as follows:
$301 million to exploitation activities, $125 million to exploration activities
and $74 million to oil and gas property acquisitions. This capital expenditure
budget reflects the Company's plans to drill approximately 600 development wells
and 95 exploratory wells and to perform recompletions on over 200 wells.
The Company believes that its current property base provides a substantial
inventory of prospects for continued reserve, production and cash flow growth.
The Company's domestic reserves as of December 31, 1997 include proved
undeveloped and proved developed nonproducing reserves of 71.9 million Bbls of
oil and NGLs and 395.6 Bcf of gas. Development of these reserves is anticipated
to occur principally in 1998 and 1999. 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
Since 1995, the Company has dedicated an increasing percentage of its
annual exploration/exploitation capital budget to exploratory projects, 17% in
1995, 18% in 1996 and 28% in 1997. The Company will continue to allocate a
significant portion of its capital budget to its exploration opportunities with
a focus on generating a portfolio of short to medium term impact projects. The
Company currently anticipates that approximately 29% of its 1998
exploration/exploitation capital budget will be spent on exploratory projects.
The majority of the 1998 exploratory budget is allocated to domestic activities
in the Gulf Coast region and internationally in Africa, Argentina and Canada.
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 nonstrategic 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
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solely for the purpose of reducing debt, such dispositions can have the result
of furthering the Company's objective of financial flexibility through decreased
debt levels.
For the year ended December 31, 1997, the Company's asset disposition
activity primarily consisted of the sale of certain domestic assets, primarily
oil and gas properties, for proceeds of $114.1 million, which resulted in a net
gain of $4.3 million and the sale of the Company's subsidiary with an ownership
interest in oil and gas properties in Turkey for proceeds of $1.6 million, which
resulted in the recognition of a gain of $706 thousand. During the year ended
December 31, 1996, the Company sold certain wholly-owned subsidiaries for
proceeds of $183.2 million resulting in a pre-tax gain of $83.3 million and
certain nonstrategic domestic assets for proceeds of $58.4 million that resulted
in the recognition of a pre-tax net gain of $13.8 million. During 1995, the
Company divested certain assets, primarily oil and gas properties, for proceeds
of $175.1 million that resulted in a pre-tax net gain of $16.6 million. The
proceeds from the asset dispositions were used to reduce the Company's
outstanding bank indebtedness and to provide funding for a portion of the
Company's capital expenditures, including purchases of oil and gas properties in
the Company's core areas.
In February 1998, the Company announced its intentions to sell domestic
nonstrategic properties for proceeds ranging from $375 to $550 million. These
properties represent approximately 15% of the Company's total cash flow from
operations. The Company plans to complete this divestiture in the latter part of
1998. The proceeds will be initially used to reduce the Company's outstanding
indebtedness and subsequently to provide funding for the Company's capital
expenditures program. This will leave the Company with approximately 25 domestic
fields, which represent the Company's core producing assets with complementary
development opportunities and the Company's assets with significant future
exploration opportunities.
The consummation of the Company's 1998 divestiture plans and any future
divestiture plans is entirely dependent on finding one or more willing buyers
who have the financial wherewithal to complete such a purchase. Until such a
buyer is found, the Company may reevaluate its portfolio of properties and at
any time may adjust its plans concerning divestitures. As a result, there can be
no assurance that the divestiture of any or all of these properties will be
completed or that the estimated proceeds will be realized.
Acquisition Activities
General. The Company regularly seeks to acquire properties that complement
its operations and provide exploitation and development opportunities and
cost-reduction potential. In addition, the Company pursues strategic
acquisitions that will allow the Company to expand into new geographical areas
that feature producing properties and provide exploration/exploitation
opportunities. During 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 $696.4 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 MidContinent region, the offshore
Gulf Coast region, Argentina and Canada and provided the Company with a
significant base of operations and experienced personnel for its areas of
geographic focus, including international areas. During 1996 and 1995, the
Company reduced its previous emphasis on major acquisitions and, instead,
concentrated its efforts on maximizing the value from its existing properties.
However, the Company continued its program of smaller acquisitions of properties
that exhibit one or more of the following characteristics: properties that are
near or otherwise complement the Company's existing properties, properties that
represent additional working interests in Company-operated properties or
properties that provide the Company with strategic exploitation or exploration
opportunities. In 1996 and 1995, aggregate expenditures to acquire such
interests and properties amounted to approximately $21 million and $48.5
million, respectively.
Future Acquisition Opportunities. The Company regularly pursues and
evaluates acquisition opportunities (including opportunities to acquire
particular oil and gas properties or related assets or entities owning oil and
gas properties or related assets and opportunities to engage in mergers,
consolidations or other business combinations with such entities) and at any
given time may be in various stages of evaluating such opportunities. Such
stages may take the form of internal financial analysis, oil and gas reserve
analysis, due diligence, the submission of an indication of interest,
preliminary negotiations, negotiation of a letter of intent or negotiation of a
definitive agreement.
5
Financial Management
The Company strives to maintain its outstanding indebtedness at a moderate
level in order to provide sufficient financial flexibility for future
exploration, development and acquisition opportunities. While the Company may
occasionally incur higher levels of debt to take advantage of opportunities,
management's objective is to maintain a flexible capital structure and to
strengthen the Company's financial position by reducing debt through an increase
in equity capital or through the divestiture of nonstrategic assets.
As with any organization, the Company has experienced various debt levels
in recent years as it has responded to strategic opportunities. During 1996 and
1995, the Company took deliberate actions to reduce its debt levels or extend
its debt maturities in order to improve its financial flexibility and enable it
to take advantage of future strategic opportunities. The Company was able to
reduce its debt level significantly each year through the application of
proceeds from the dispositions of assets that the Company had identified as
nonstrategic (see "Asset Divestitures" above). In 1997, the Company's debt level
increased as a result of the assumption of the debt of Mesa and Chauvco. Also
during 1997, the Company recorded a noncash pre-tax charge of $1.4 billion in
accordance with SFAS 121 as defined in Note B of Notes to Consolidated Financial
Statements included in "Item 8. "Financial Statements and Supplementary Data".
As a result of the decrease in capital and the increase in debt, the Company's
debt as a percentage of total capitalization was 56% at December 31, 1997, up
from 31% at December 31, 1996.
In January 1998, the Company completed the issuance of two series of
senior notes for total net proceeds of $593 million. The first issuance was for
$350 million of ten year notes with a coupon rate of 6.5%, and the second
issuance was for $250 million of thirty year notes with a coupon rate of 7.2%.
The proceeds were used primarily to repay the Company's bank indebtedness and
had the effect of extending the Company's debt maturities.
Marketing of Production
General. Production from the Company's properties is marketed consistent
with industry practices, which include the sale of oil at the wellhead to third
parties and the sale of gas to third parties. Sales prices for both oil and gas
production are negotiated based on factors normally considered in the industry
such as the spot price for gas or the posted price for oil, price regulations,
distance from the well to the pipeline, well pressure, estimated reserves,
commodity quality and prevailing supply conditions.
Significant Purchasers. During 1997, the Company's two primary purchasers
of crude oil were Mobil Oil Corporation ("Mobil") and Genesis Crude Oil, L.P.
("Genesis"), both of which purchase oil pursuant to contracts that provide for
prices that are based on prevailing market prices. Approximately 16% and 23% of
the Company's 1997 oil and gas revenues were attributable to sales to Mobil and
Genesis, respectively. During 1997, the Company marketed its natural gas,
including natural gas products, to a variety of purchasers. Approximately 11%
and 10% of the Company's 1997 oil and gas revenues were attributable to sales to
Producers Energy Marketing, LLC and Western Gas Resources, Inc., 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. The hedging strategy for each product the Company
sells is described in further detail below.
Crude Oil. All material purchase contracts governing the Company's oil
production are tied directly or indirectly to NYMEX prices. The average oil
prices per Bbl that the Company reports includes the effects of oil quality,
gathering and transportation costs and the net effect of the oil hedges.
Natural Gas Liquids. The Company employs a policy of hedging natural gas
liquids based on actual product prices in order to mitigate some of the
volatility associated with NYMEX pricing. Natural gas liquids are sold under
long-term contracts which provide price flexibility and allow the Company to
maximize prices between trading hubs.
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Natural Gas. The Company employs a policy of hedging gas production based
on the index price upon which the gas is actually sold in order to mitigate the
basis risk between NYMEX prices and actual index prices. The average gas prices
per Mcf that the Company reports includes the effects of Btu content, gathering
and transportation costs, gas processing and shrinkage and the net effect of the
gas hedges.
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 and Item 8. "Financial Statements and Supplementary Data" for
a description of the Company's open hedge positions at December 31, 1997 and the
related prices to be realized.
Operations by Geographic Area
The Company operates in one industry segment. During 1997 and 1996, the
Company did not have significant operations in geographic areas other than the
United States. For financial information with respect to the Company's 1995
operations by geographic area, see Note O of Notes to Consolidated Financial
Statements included in "Item 8.
Financial Statements and Supplementary Data".
Competition, Markets and Regulation
Competition. The oil and gas industry is highly competitive. A large
number of companies and individuals engage in the exploration for and
development of oil and gas properties, and there is a high degree of competition
for oil and gas properties suitable for development or exploration. Acquisitions
of oil and gas properties have been an important element of the Company's
growth, and the Company intends to continue to acquire oil and gas properties.
The principal competitive factors in the acquisition of oil and gas properties
include the staff and data necessary to identify, investigate and purchase such
properties and the financial resources necessary to acquire and develop them.
Many of the Company's competitors are substantially larger and have financial
and other resources greater than those of the Company.
Markets. The Company's ability to produce and market oil and gas
profitably depends on numerous factors beyond the Company's control. The effect
of these factors cannot be accurately predicted or anticipated. In recent years,
worldwide oil production capacity and gas production capacity in certain areas
of the United States have exceeded demand, with resulting declines in the price
of oil and gas. Although the Company cannot predict the occurrence of events
that may affect oil and gas prices or the degree to which oil and gas prices
will be affected, it is possible that prices for any oil or gas the Company
produces will be lower than those currently available. Any significant decline
in the price of oil or gas would adversely affect the Company's revenues,
profitability and cash flow and could, under certain circumstances, result in a
reduction in the carrying value of the Company's oil and gas properties.
During most of 1996 and 1997, the Company benefitted from higher oil
prices as compared to previous years. However, during the fourth quarter of
1997, oil prices began a downward trend that has continued into March 1998. A
continuation of the oil price environment experienced during the first quarter
of 1998 will have an adverse effect on the Company's revenues and operating cash
flow, and may result in a downward adjustment to the Company's current 1998
capital budget of $500 million. Also, a continuing decline in oil prices could
result in additional decreases in the carrying value of the Company's oil and
gas properties.
Governmental Regulation. Oil and gas exploration and production are
subject to various types of regulation by local, state, 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 nonjurisdictional entities,
FERC has retained the authority to exercise jurisdiction over those entities if
7
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.
The United States Minerals Management Service (the "MMS") is conducting an
inquiry into certain contract settlement agreements from which producers on
federal oil and gas leases have received settlement proceeds that the MMS claims
are royalty-bearing and into the extent to which producers have paid appropriate
royalty on those proceeds.
Additional proposals and proceedings that might affect the oil and gas
industry are considered from time to time by Congress, FERC, state regulatory
bodies, the courts and foreign governments. The Company cannot predict when or
if any such proposals might become effective or their effect, if any, on the
Company's operations.
Environmental and Health Controls. The Company's operations are subject to
numerous federal, state, local and foreign laws and regulations relating to
environmental and health protection. These laws and regulations may require the
acquisition of a permit before drilling commences, restrict the type, quantities
and concentration of various substances that can be released into the
environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands
and other protected areas and impose substantial liabilities for pollution
resulting from oil and gas operations. These laws and regulations may also
restrict air or other discharges resulting from the operation of natural gas
processing plants, pipeline systems and other facilities that the Company owns.
Although the Company believes that compliance with environmental laws and
regulations will not have a material adverse effect on operations or earnings,
risks of substantial costs and liabilities are inherent in oil and gas
operations, and there can be no assurance that significant costs and
liabilities, including potential criminal penalties, will not be incurred.
Moreover, it is possible that other developments, such as stricter environmental
laws and regulations or claims for damages to property or persons resulting from
the Company's operations, could result in substantial costs and liabilities.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
with respect to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of the disposal site or sites where
the release occurred and companies that disposed or arranged for the disposal of
hazardous substances released at the site. Persons who are or were responsible
for releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment.
The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The U.S. Environmental Protection Agency and various state
agencies have limited the approved methods of disposal for certain hazardous and
nonhazardous wastes. Furthermore, certain wastes generated by the Company's oil
and natural gas operations that are currently exempt from treatment as
"hazardous wastes" may in the future be designated as "hazardous wastes," and
therefore be subject to more rigorous and costly operating and disposal
requirements.
The Company currently owns or leases, and has in the past owned or leased,
properties that for many years have been used for the exploration and production
of oil and gas. Although the Company has used operating and disposal practices
that were standard in the industry at the time, hydrocarbons or other wastes may
have been disposed of or released on or under the properties owned or leased by
the Company or on or under other locations where such wastes have been taken for
disposal. In addition, some of these properties have been operated by third
parties whose treatment and disposal or release of hydrocarbons or other wastes
was not under the Company's control. These properties and the wastes diposed
8
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
quantities and imposes substantial liability for the costs of removing a spill.
State laws for the control of water pollution also provide varying civil and
criminal penalties and liabilities in the case of releases of petroleum or its
derivatives into surface waters or into the ground.
OPA requires responsible parties to establish and maintain evidence of
financial responsibility to cover removal costs and damages resulting from an
oil spill. OPA calls for a financial responsibility increase from $35 million to
$150 million to cover pollution cleanup for offshore facilities. In August 1993,
MMS, which has been charged with implementing certain segments of OPA, issued
its advanced notice of proposed rulemaking that would increase financial
responsibility requirements for offshore lessees and permittees to $150 million
as required by OPA. Due to the OPA's broad definition of "offshore facility,"
the Company could become subject to the financial responsibility rule if it is
proposed and adopted; to date, however, the MMS has not formally proposed the
financial responsibility regulations. On May 9, 1995, the U.S. House of
Representatives passed a bill that would lower the financial responsibility
requirements applicable to offshore facilities to $35 million (the current
requirement under the federal 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 Company
operations and earnings. The Company does not believe that the rule to be
proposed by the MMS will be any more burdensome to it than it will be to other
similarly situated oil and gas companies.
Many states in which the Company operates have recently begun to regulate
naturally occurring radioactive materials ("NORM") and NORM wastes that are
generated in connection with oil and gas exploration and production activities.
NORM wastes typically consist of very low-level radioactive substances that
become concentrated in pipe scale and in production equipment. State regulations
may require the testing of pipes and production equipment for the presence of
NORM, the licensing of NORM-contaminated facilities and the careful handling and
disposal of NORM wastes. The Company believes that the growing regulation of
NORM will have a minimal effect on the Company's operations because the Company
generates only a very small quantity of NORM on an annual basis.
The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, no assurance can be given that environmental laws will not, in the
future, result in a curtailment of production or processing or a material
increase in the costs of production, development, exploration or processing or
otherwise adversely affect the Company's operations and financial condition.
The Company employs an environmental specialist charged with monitoring
regulatory compliance. The Company performs an environmental review as part of
the due diligence work on potential acquisitions, including acquisitions of oil
and gas properties. The Company is not aware of any material environmental legal
proceedings pending against it or any significant environmental liabilities to
which it may be subject.
9
Risks Associated with Business Activities
The nature of the business activities conducted by the Company subjects it
to certain hazards and risks. The following is a summary of some of the material
risks relating to the Company's business activities.
Oil and Gas Prices and General Market Risks. The Company's revenues,
profitability, cash flow and future rate of growth are highly dependent on the
prevailing prices of oil and gas, which are affected by numerous factors beyond
the Company's control. Oil and gas prices historically have been very volatile.
A substantial or extended decline in the prices of oil or gas could have a
material adverse effect on the Company's revenues, profitability and cash flow
and could, under certain circumstances, result in a reduction in the carrying
value of the Company's oil and gas properties and a reduction in the Company's
borrowing base under its bank credit facility.
Risks of Drilling Activities. As noted under "Item 1. Business - Business
Activities," of the total 1998 capital budget of $500 million, the Company
anticipates spending approximately $301 million on exploitation activities and
$125 million on exploration activities. This capital expenditure budget reflects
the Company's plans to drill approximately 600 development wells and 95
exploratory wells and to perform recompletions on over 200 wells. Drilling
involves numerous risks, including the risk that no commercially productive
natural gas or oil reservoirs will be encountered. The cost of drilling,
completing and operating wells is often uncertain and drilling operations may be
curtailed, delayed or canceled as a result of a variety of factors, including
unexpected drilling conditions, pressure or irregularities in formations,
equipment failures or accidents, adverse weather conditions and shortages or
delays in the delivery of equipment. The Company's future drilling activities
may not be successful and, if unsuccessful, such failure could have an adverse
effect on the Company's future results of operations and financial condition.
While all drilling, whether developmental or exploratory, involves these risks,
exploratory drilling involves greater risks of dry holes or failure to find
commercial quantities of hydrocarbons. Because of the percentage of the
Company's capital budget devoted to exploratory projects, it is likely that the
Company will continue to experience exploration and abandonment expense.
Risks Associated with Unproved Properties. At December 31, 1997 and 1996,
the Company had unproved property costs of $545 million and $7 million,
respectively. U.S. GAAP requires 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, future sales
or expiration of all or a portion of such projects. If the quantity of proved
reserves determined by such evaluations are not sufficient to fully recover the
cost invested in each project, the Company may be required to recognize
significant non-cash charges in the earnings of future periods. There can be no
assurance that economic reserves will be determined to exist for such projects.
Acquisitions. Acquisitions of producing oil and gas properties have been a
key element of the Company's growth. The Company's growth following the full
development of its existing property base could be impeded if it is unable to
acquire additional oil and gas properties on a profitable basis. The success of
any acquisition will depend on a number of factors, including the ability to
estimate accurately the recoverable volumes of reserves, rates of future
production and future net revenues attributable to reserves and to assess
possible environmental liabilities. All of these factors affect whether an
acquisition will ultimately generate cash flows sufficient to provide a suitable
return on investment. Even though the Company performs a review of the
properties it seeks to acquire that it believes is consistent with industry
practices, such reviews are often limited in scope.
Divestitures. The Company regularly reviews its property base for the
purpose of identifying nonstrategic 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 nonstrategic assets, including
the availability of purchasers willing to purchase the nonstrategic assets at
prices acceptable to the Company.
Risks Associated with Operation of Natural Gas Processing Plants. The
Company owns interests in seven natural gas processing plants and operates three
of those plants, although the net revenues derived from natural gas processing
during 1997 represented only 1% of the total net revenues from oil and gas
activities. There are significant risks associated with the operation of natural
gas processing plants. Natural gas and natural gas liquids are volatile and
explosive and may include carcinogens. Damage to or misoperation of a natural
10
gas processing plant could result in an explosion or the discharge of toxic
gases, which could result in significant damage claims in addition to
interrupting a revenue source.
Operating Hazards and Uninsured Risks. The Company's operations are
subject to all the risks normally incident to the oil and gas exploration and
production business, including blowouts, cratering, explosions and pollution and
other environmental damage, any of which could result in substantial losses to
the Company due to injury or loss of life, damage to or destruction of wells,
production facilities or other property, clean-up responsibilities, regulatory
investigations and penalties and suspension of operations. Although the Company
currently maintains insurance coverage that it considers reasonable and that is
similar to that maintained by comparable companies in the oil and gas industry,
it is not fully insured against certain of these risks, either because such
insurance is not available or because of high premium costs.
Environmental Risks. The oil and gas business is also subject to
environmental hazards, such as oil spills, gas leaks and ruptures and discharges
of toxic substances or gases that could expose the Company to substantial
liability due to pollution and other environmental damage. A variety of federal,
state and foreign laws and regulations govern the environmental aspects of the
oil and gas business. Noncompliance with these laws and regulations may subject
the Company to penalties, damages or other liabilities, and compliance may
increase the cost of the Company's operations. Such laws and regulations may
also affect the costs of acquisitions. See "Item 1. Business - Competition,
Markets and Regulation - Environmental and Health Controls".
The Company does not believe that its environmental risks are materially
different from those of comparable companies in the oil and gas industry.
Nevertheless, no assurance can be given that environmental laws will not, in the
future, result in a curtailment of production or processing or a material
increase in the costs of production, development, exploration or processing or
otherwise adversely affect the Company's operations and financial condition.
Pollution and similar environmental risks generally are not fully insurable.
Competition. The oil and gas industry is highly competitive. The Company
competes with other companies, producers and operators for acquisitions and in
the exploration, development, production and marketing of oil and gas. Some of
these competitors have substantially greater financial and other resources than
the Company. See "Item 1. Business - Competition, Markets and Regulation".
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".
Risks of International Operations. At December 31, 1997, approximately 20%
of the Company's proved reserves of oil and gas were located outside the United
States (12% in Argentina and 8% in Canada). The success and profitability of
international operations may be adversely affected by risks associated with
international activities, including economic and labor conditions, political
instability, tax laws (including U.S. taxes on foreign subsidiaries) and changes
in the value of the United States dollar versus the local currency in which oil
and gas are sold. To the extent that the Company is involved in international
activities, changes in exchange rates may adversely affect the Company's
consolidated revenues and expenses (as expressed in United States dollars).
Estimates of Reserves and Future Net Revenues. Numerous uncertainties
exist in estimating quantities of proved reserves and future net revenues
therefrom. The estimates of proved reserves and related future net revenues set
forth in this Report are based on various assumptions, which may ultimately
prove to be inaccurate. Therefore, such estimates should not be construed as
estimates of the current market value of the Company's proved reserves.
Definition of Certain Oil and Gas Terms
When used in this Report, the following terms have the meanings indicated
below.
"Bbl" means a standard barrel of 42 U.S. gallons and represents the basic
unit for measuring the production of crude oil, natural gas liquids and
condensate.
11
"Bcf" means one billion cubic feet.
"Bcfe" means a billion cubic feet equivalent and is a customary convention
used in the United States to express oil and gas volumes on a comparable basis.
It is determined on the basis of the estimated relative energy content of oil to
natural gas, being approximately one barrel of oil per six Mcf of gas.
"BOE" means a barrel-of-oil-equivalent and is a customary convention used
in the United States to express oil and gas volumes on a comparable basis. It is
determined on the basis of the estimated relative energy content of natural gas
to oil, being approximately six Mcf of natural gas per Bbl of oil.
"Btu" means British thermal unit and represents the amount of heat needed
to raise the temperature of one pound of water one degree Fahrenheit.
"gross" acre or well means an acre or well in which a working interest is
owned.
"MBbl" means one thousand Bbls.
"MBOE" means one thousand BOEs.
"Mcf" means one thousand cubic feet under prescribed conditions of
pressure and temperature and represents the basic unit for measuring the
production of natural gas.
"MMcf" means one million cubic feet.
"net" acres or wells is determined by multiplying the gross acres or
wells, as the case may be, by the applicable working interest in those gross
acres or wells.
"NGLs" means natural gas liquids.
"NYMEX" means The New York Mercantile Exchange.
"proved reserves" means those estimated quantities of crude oil and
natural gas that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known oil and gas reservoirs
under existing economic and operating conditions. Proved reserves are limited to
those quantities of oil and gas that can be expected to be recoverable
commercially at current prices and costs, under existing regulatory practices
and with existing conventional equipment and operating methods.
"SEC 10 value" means the present value of estimated future net revenues,
before income taxes, of proved reserves, determined in all material respects in
accordance with the rules and regulations of the U.S. Securities and Exchange
Commission ("SEC") (generally using prices and costs in effect at the specified
date and a 10% discount rate). The reserve estimates for 1997 utilize an oil
price of $16.89 per Bbl (reflecting adjustments for oil quality and gathering
and transportation costs), an NGL price of $12.79 per Bbl and a gas price of
$2.06 per Mcf (reflecting adjustments for BTU content, gathering and
transportation costs and gas processing and shrinkage).
ITEM 2. PROPERTIES
The information included in this Report about the Company's proved oil and
gas reserves at December 31, 1997, including estimated quantities and SEC 10
value, is based on reserve reports prepared by the Company's engineers for all
properties other than Canada, which have been prepared by Martin Petroleum &
Associates and Gilbert Laustsen Jung Associates.
Numerous uncertainties exist in estimating quantities of proved reserves
and in projecting future rates of production and timing of development
expenditures, including many factors beyond the Company's control. This Report
contains estimates of the Company's proved oil and gas reserves and the related
future net revenues, which are based on various assumptions, including those
prescribed by the SEC. Actual future production, oil and gas prices, revenues,
12
taxes, capital expenditures, operating expenses, geologic success and quantities
of recoverable oil and gas reserves may vary substantially from those assumed in
the estimates and could materially affect the estimated quantities and related
SEC 10 value of proved reserves set forth in this Report. In addition, the
Company's reserves may be subject to downward or upward revisions based on
production performance, purchases or sales of properties, results of future
development, prevailing oil and gas prices and other factors. Therefore,
estimates of the SEC 10 value of proved reserves contained in this Report should
not be construed as estimates of the current market value of the Company's
proved reserves.
SEC 10 value is a reporting convention that provides a common basis for
comparing oil and gas companies subject to the rules and regulations of the 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. SEC 10 values as of any date are not
necessarily indicative of future results of operations. Accordingly, estimates
of future net revenues in this Report may be materially different from the net
revenues that are ultimately received.
The Company did not provide estimates of total proved oil and gas reserves
during 1997 to any federal authority or agency, other than the SEC.
Proved Reserves
The Company's proved reserves totaled 761.6 million BOE at December 31,
1997, 302.2 million BOE at December 31, 1996 and 296.8 million BOE at December
31, 1995, representing $3.1 billion, $2.3 billion and $1.4 billion,
respectively, in SEC 10 value. The Company achieved these annual increases in
reserves despite having sold reserves of 18.1 million BOE in 1997, 45.8 million
BOE in 1996 and 34.8 million BOE in 1995.
On a BOE basis, 86% of the Company's total proved reserves at December 31,
1997 are proved developed reserves. Based on reserve information as of December
31, 1997 and using the Company's reserve report production information for 1998,
the reserve-to-production ratio associated with the Company's proved reserves is
11.3 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, 1997.
PROVED OIL AND GAS RESERVES
1997 Average
Proved Reserves as of December 31, 1997 Daily Production (a)
------------------------------------------ ---------------------------
Oil Natural SEC 10 Oil Natural
& NGLs Gas Value & NGLs Gas
(MBbls) (MMcf) MBOE (000) (Bbls) (Mcf) BOE
------- -------- ------- ---------- ------- -------- ------
United States:
Gulf Coast Region.... 19,289 316,238 71,996 $ 412,296 5,919 110,657 24,362
MidContinent Region.. 102,331 1,101,421 285,901 1,153,385 9,828 101,860 26,805
Permian Basin........ 207,696 301,471 257,941 931,345 32,847 74,792 45,312
-------- -------- ------- --------- ------- ------- -------
329,316 1,719,130 615,838 2,497,026 48,594 287,309 96,479
Argentina............. 31,612 340,392 88,344 345,721 406 - 406
Canada................ 22,796 207,868 57,441 232,925 - - -
-------- -------- ------- --------- ------- ------- -------
Total............... 383,724 2,267,390 761,623 $ 3,075,672 49,000 287,309 96,885
======== ========= ======= ========== ======= ======= =======
- ---------------
(a) The 1997 average daily production is calculated using a 365-day year and
without making pro forma adjustments for any acquisitions, divestitures or
drilling activity that occurred during the year.
Reserve Replacement
For the ninth consecutive year, the Company was able to replace its annual
production volumes with proved reserves of crude oil, NGLs and natural gas,
stated on an energy equivalent basis. During 1997, the Company added 512.9
million BOE resulting in reserve replacement of 1450% of total production. Of
the 512.9 million BOE reserve additions, 457.7 million BOE were added through
acquisitions of proved properties, 2.4 million BOE were added through
13
exploration and development drilling activities and 52.8 million BOE were the
net result of revisions. Reserves added by development drilling are primarily
from the identification of additional infill drilling locations and new
secondary recovery projects. Reserve revisions result from several factors
including changes in existing estimates of quantities available for production
and changes in estimates of quantities which are economical to produce under
current pricing conditions. The Company's reserves as of December 31, 1997 were
estimated using a price of $16.89 per Bbl of oil, $12.79 per Bbl of NGLs and
$2.06 per Mcf of gas. Should prices decline in future periods, reserves may be
revised downward for quantities which may be uneconomical to produce at lower
prices.
The Company's 1997 reserve replacement rate on a BOE basis was 1450%,
which included reserve replacement rates for oil and natural gas of 1375% and
1528%, respectively. Previous reserve replacement performance rates were 314% in
1996 (398% for oil and 239% for gas) and 281% in 1995 (263% for oil and 297% for
gas). For the three year period ended December 31, 1997, the average reserve
replacement rate was 769%, as compared to a three year average replacement rate
of 377% in 1996 and 412% in 1995. During 1997, the Company's reserve replacement
rate was primarily the product of its acquisition activities. In 1995, and to a
greater extent in 1996, the reserve replacement rates were influenced more by
exploration and development activities and less by acquisition activities.
Finding Cost
The Company's acquisition and finding cost for 1997 was $8.23 per BOE as
compared to the 1996 and 1995 acquisition and finding costs of $3.10 and $2.87
per BOE, respectively. The increased rate in 1997 is a result of the fair value
associated with Mesa's and Chauvco's long-lived, low production cost reserves.
The average acquisition and finding cost for the three-year period from 1995 to
1997 was $7.04 per BOE representing a 76% increase from the 1996 three-year
average rate of $3.99.
Oil and Gas Mix
The Company seeks to maintain a strategic balance between oil and natural
gas reserves and production. While the Company's reserve and production mix may
vary somewhat on a short-term basis as the Company takes advantage of market
conditions and specific acquisition and development opportunities, management
believes that a relative mix of approximately 50% oil and NGLs and 50% natural
gas is in the best long-term interests of the Company and its stockholders. The
Company's reserve mix was 50% oil and NGLs and 50% gas at December 31, 1997, and
its production mix was 51% oil and NGLs and 49% gas during 1997.
Description of Properties
The Company manages its domestic oil and gas properties based upon their
geographic area, and, as a result, the Company has divided its domestic
operations into three domestic operating regions: the Permian Basin region, the
onshore and offshore Gulf Coast region and the MidContinent region. In addition,
at December 31, 1997, the Company has international operations principally in
Argentina and Canada.
Gulf Coast. The Gulf Coast region includes onshore oil and gas properties
located in South and East Texas, Louisiana and Mississippi and offshore
properties in the Gulf of Mexico. In the Gulf Coast region, 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 region as well as its
investment in and utilization of 3-D seismic technology.
Utilization of 3-D seismic technology during 1997 yielded substantial
results in the Company's Lopeno field which produces from the Wilcox formation.
Gross gas production from this area increased from 36 MMcf per day to 57 MMcf
per day during 1997 as a result of drilling eight development wells, most of
which were identified from 3-D seismic data. The Company has identified at least
eight additional drilling locations after further interpretation of the 3-D
data. In addition, the Company continues to experience successful results in its
100% owned Pawnee field which produces 21 MMcf per day from 23 wells in the
Edwards formation. The Company has been actively developing this field with new
drilling, horizontal recompletions, adding new perforations and acidizing
existing wellbores which increased field production seven MMcf per day during
1997. A 3-D seismic survey will be utilized to identify additional drilling
locations in this field area.
14
Cotton Valley. In May of 1997, the Company acquired a 35% interest in
approximately 375,000 acres within the Cotton Valley Pinnacle Reef Trend from
Union Pacific Resources Company ("UPRC") for $26.9 million. The Company and UPRC
have signed an exploration agreement to jointly explore and develop this area
located in eastern Texas.
On December 19, 1997, the Company completed the acquisition of assets in
the East Texas Basin from affiliates of American Cometra, Inc. ("ACI") and
Rockland Pipe Co. ("Rockland"), both subsidiaries of Electrafina S.A. of
Belgium. Purchase consideration consisted of $85 million cash and 1.6 million
shares of Company common stock. The Company acquired all of ACI's producing
wells, acreage (95,000 gross and 38,000 net), seismic data, royalties and
mineral interests and Rockland's gathering system, pipeline and Plum Creek gas
processing plant in the East Texas Basin. The acquired acreage is in Henderson,
Freestone, Anderson and Leon counties. The acquired wells are currently
producing approximately 18 MMcf of gas per day and have significant upside
potential with the planned drilling of additional wells.
During 1998, the Company plans an aggressive drilling program in the Gulf
Coast region with a total budget of $157.5 million to drill approximately 49
exploratory wells and 25 development wells. Exploration expenditures are
estimated at $75 million and will be focused in the inland water transition zone
areas of Louisiana and Texas and the Cotton Valley Pinnacle Reef Trend in East
Texas. During 1998, the Company will focus development activities in five core
properties: Lopeno and Pawnee fields in South Texas, Timbalier Bay and Grand Bay
fields in South Louisiana and Eugene Island 208 field in the Gulf of Mexico.
MidContinent. The MidContinent region includes properties located in the
Texas Panhandle, Oklahoma, Arkansas and Kansas. By far, the largest of these
assets is the Company's Hugoton field followed by the West Panhandle field, both
acquired from Mesa in August 1997. These two fields combined account for
approximately $1 billion of the Company's $3.1 billion of SEC 10 reserve value
at December 31, 1997. During 1998, the Company plans to spend approximately
$48.8 million in the MidContinent region. This activity includes drilling
approximately 110 development wells and six exploratory wells and performing
recompletions on approximately 26 targeted wells.
Hugoton Field. The Hugoton field in southwest Kansas is one of the largest
producing gas fields in the continental United States. The Company's Hugoton
properties represent approximately 13% of the proved reserves in the field and
are located on over 237,000 net acres, covering approximately 400 square miles.
The Company has working interest in approximately 1,200 wells in the Hugoton
field, 977 of which it operates, and royalty interest in approximately 750
wells. The Company owns substantially all of the gathering and processing
facilities, primarily the Satanta plant, that service its production from the
Hugoton field. Such ownership allows the Company to control the production,
gathering, processing and sale of its gas and associated NGLs.
Production in the Hugoton field is subject to allowables set by state
regulators, but the Company's Hugoton properties are capable of producing
approximately 188 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 1997. By continuing its successful installation of compression and
artificial lift, in combination with an extensive stimulation program and a
selective replacement well drilling program, the Company anticipates that the
normal 8% Hugoton properties production decline may be temporarily arrested.
The Company intends to submit an application to the Kansas Corporation
Commission (the "KCC") to allow infill drilling into the Council Grove
Formation. The Company believes that such infill drilling could increase
production from its Hugoton properties. There can be no assurance that the
application will be approved or as to the timing of receipt of such approval if
such approval is obtained.
West Panhandle Field. The West Panhandle properties are located in the
panhandle region of Texas where initial production commenced in 1918. These
stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite,
Granite Wash and fractured Granite formations at depths no greater than 3,500
feet. The Company's natural gas in the West Panhandle field is produced from
approximately 600 wells on more than 241,000 gross (185,000 net) acres covering
over 375 square miles. The Company's wellhead gas produced from the West
Panhandle field contains a high quantity of NGLs, yielding relatively greater
NGL volumes than realized from other natural gas fields. The Company operates
the wells and production equipment and Colorado Interstate Gas Company owns and
operates the gathering system.
15
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 is scheduled for completion in mid-1998, will allow the
Company to recover in excess of 90% of the helium in the processed gas, increase
NGL recoveries and upgrade residue quality to improve marketing flexibility.
As of December 31, 1997, the Company's West Panhandle properties
represented approximately 12% of the Company's equivalent proved reserves and
approximately 12% of the present value of estimated future net cash flows,
determined in accordance with SEC guidelines. The Company has identified over 50
locations that have additional production potential in new areas or deeper zones
that the Company plans to redrill in 1998.
Permian Basin. Of the $931.3 million of SEC 10 value contained in the
properties in the Permian Basin region, the Spraberry field accounts for $642.6
million. The Spraberry field was discovered in 1949 and encompasses eight
counties in West Texas. The field is approximately 150 miles long and 75 miles
wide at its widest point. The oil produced is West Texas Intermediate Sweet, and
the gas produced is casinghead gas with an average Btu content of 1,400 Btu per
Mcf. The oil and gas is produced from three formations, the upper and lower
Spraberry and the Dean, at depths ranging from 6,700 feet to 9,200 feet. The
center of the Spraberry field was unitized in the late 1950's and early 1960's
by the major oil companies but until the late 1980's experienced very limited
development activity. Since 1989, the Company has focused acquisition and
development drilling activities in the unitized portion of the Spraberry field
due to the dormant condition of the properties and the high net revenue
interests available. The Company believes the area offers excellent
opportunities to enhance oil and gas reserves because of the hundreds of
undeveloped infill drilling locations and the ability to reduce operating
expenses through economies of scale. In February 1997, the Texas Railroad
Commission (which regulates oil and gas production) entered a favorable order on
the Company's application to allow administrative approval of uncontested
applications to increase the density of drilling in the Spraberry field from one
well per 80 acres to one well in 40 acres. The Company believes such reduced
spacing may provide in excess of 1,000 additional drilling locations which have
the potential to add 70 million BOE's to the Company's reserve base. Through
December 31, 1997, the Company has drilled 60 wells in the Spraberry field under
the reduced spacing requirements resulting in the addition of approximately 6.9
million BOE's to its reserve portfolio.
Since the early 1960's, the Company has been involved in acquisition and
development activities in other fields in the Permian region which includes all
of West Texas and Southeastern New Mexico. The Iatan field in Mitchell County,
Texas, the Lusk and Dagger Draw fields in Eddy County, New Mexico, the Abell
(Devonian) field in Crane and Pecos Counties of Texas, the Ozona field in
Crockett and Sutton Counties of Texas and the War-Wink West Field in the
Delaware Basin of West Texas are core areas for the Company's Permian region
operations in terms of existing production, production and reserve growth, and
identification of additional drilling locations.
The Company will continue to focus on the development of the existing
properties utilizing waterflood procedures and secondary recovery technologies
as these efforts have consistently resulted in increased production, reserve
additions due to development drilling, and new drilling locations. In addition,
all of the fields in this operational group have been screened for feasibility
for carbon dioxide (CO2) flood implementation, and the Company plans to move
forward in utilizing this technology in 1998. In total, the Company anticipates
spending $112.5 million in 1998 in the Permian Basin to drill approximately 295
wells and to perform recompletions on approximately 135 targeted wells.
Development activities will account for 95% of these planned expenditures.
International. The acquisition of Chauvco provided the Company with a
significant presence in Argentina and Canada, representing 11% and 8% of the
Company's SEC 10 value at December 31, 1997. The Canadian producing properties
are primarily located in Alberta and British Columbia, Canada in the following
areas: Thompson/Alliance, Spirit River/Rycroft, Cherhill, Killam, Choice, David,
Martin Creek and Chinchaga. During 1997, these properties produced an average of
17,532 BOE's per day, net to the Company's interest. These properties currently
include more than 700 development drilling locations.
The Company's Argentine properties are primarily located in the Tierra del
Fuego and Neuquen basins. Chauvco's share of Argentine production during 1997
averaged 16,147 BOE's per day. The Tierra del Fuego production concession is
located in the extreme southern portion of Argentina, approximately 1,500 miles
south of the country's capital, Buenos Aires. Crude oil, natural gas, condensate
and NGLs are produced from six separate fields in which the Company has a 35%
16
working interest. The most significant area is the San Sebastian field which
accounts for approximately 40% of crude oil and condensate production, 100% of
propane and butane production, and 84% of natural gas sales from the concession.
In Argentina, recent expansion of gas processing facilities and completed
pipeline connections at Tierra del Fuego will allow handling of increased
production volumes committed for delivery under a gas contract to a
petrochemical plant in Chile. Natural gas deliveries under the contract to the
methanol plant in Chile commenced in January 1997 at a rate of 17.0 MMcf per
day.
The Company's operated production in Argentina is concentrated in the
Neuquen Basin which is located about 925 miles southwest of the country's
capital city and just to the east of the Andes Mountains. Crude oil and natural
gas are produced from two separate fields in the Loma Negra/NI Block, the
Huincul field in the Dadin Block and from three oil fields and one natural gas
field in the Al Norte de la Dorsal Block in which the Company has a 100% working
interest.
In addition to the proved producing assets of Chauvco, the Company
acquired a substantial inventory of unproved oil and gas properties which will
provide the Company with many exploration opportunities with the potential for
significant reserve additions. Although the acquisition of a portfolio of
unproved properties represents an exciting challenge to the Company's team of
engineers, geologists and geophysicists, such opportunities are not without
risk. U.S. GAAP requires 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, future sales
or expiration of all or a portion of such projects. If the quantity of proved
reserves determined by such evaluations are not sufficient to fully recover the
cost invested in each project, the Company may be required to recognize
significant noncash charges to the earnings of future periods. There can be no
assurance that economic reserves will be determined to exist for such projects.
On a smaller scale, the Company has recently entered into agreements to
begin exploratory activity in the African nations of South Africa and Gabon. The
South African Block covers over five million acres along the southern coast of
South Africa, generally in water depths less than 650 feet. It is located
between Block 9, which produces quantities of oil from Oribi Field (up to 25,000
barrels per day) and gas from F-A Field (about 190 MMcf per day), and Pioneer's
study block 13A/14A offshore Port Elizabeth. In addition, Pioneer concluded in
November of 1997, a Technical Cooperation Agreement on Block 7 which is located
adjacent to and west of Block 9, and covers an area of about three million
acres, the most prospective portion of which is in water depths of less than 500
feet.
The Company plans to spend approximately $181.2 million internationally in
1998 as follows: $97.5 million in Argentina, $57.5 million in Canada, and $26.2
million in Africa and other international areas. The Company's international
exploration budget of $50 million is primarily devoted to Africa, Argentina and
Canada.
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, 1997, 1996 and 1995.
Because of normal production declines, increased or decreased drilling
activities and the effects of future acquisitions or divestitures, the
historical information presented below should not be interpreted as indicative
of future results.
17
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, 1997, 1996 and 1995.
PRODUCTION, PRICE AND COST DATA (a)
Year ended December 31,
-------------------------------------------------------------------------------------------
1997 1996 1995
----------------------------- ----------------------------- -----------------------------
Australia(b)
United United and United
States Argentina Total States Argentina Total States Australia Total
-------- --------- -------- ------- ---------- -------- -------- --------- --------
Production information:
Annual production:
Oil (MBbls)..... 13,470 148 13,618 10,872 403 11,275 11,328 1,574 12,902
NGLs (MBbls)... 4,267 - 4,267 - - - - - -
Gas (MMcf)...... 104,868 - 104,868 73,924 1,927 75,851 76,669 8,626 85,295
Total (MBOE).... 35,215 148 35,363 23,193 723 23,916 24,106 3,012 27,118
Average daily
production:
Oil (Bbls).... 36,903 406 37,309 29,705 1,100 30,805 31,036 4,312 35,348
NGLs (Bbls)... 11,691 - 11,691 - - - - - -
Gas (Mcf)..... 287,309 - 287,309 201,979 5,265 207,244 210,052 23,633 233,685
Total (BOE)... 96,479 406 96,885 63,368 1,978 65,346 66,045 8,251 74,296
Average prices:
Oil (per Bbl).... $ 18.50 $ 19.68 $ 18.51 $ 19.96 $ 19.81 $ 19.96 $ 16.70 $ 18.78 $ 16.96
NGLs (per Bbl)... $ 12.59 $ - $ 12.59 $ - $ - $ - $ - $ - $ -
Gas (per Mcf).... $ 2.20 $ - $ 2.20 $ 2.27 $ 1.95 $ 2.27 $ 1.84 $ 1.88 $ 1.84
Revenue (per BOE) $ 15.16 $ 19.68 $ 15.18 $ 16.61 $ 16.21 $ 16.60 $ 13.69 $ 15.21 $ 13.85
Average costs:
Production costs
(per BOE):
Lease operating
expense....... $ 3.01 $ 5.47 $ 3.02 $ 3.39 $ 4.75 $ 3.43 $ 3.97 $ 4.12 $ 3.99
Production taxes. .81 .19 .81 .94 - .91 .70 - .62
Workover....... .25 - .25 .28 - .27 .25 - .22
------- ------ ------- ------- ------ ------- ------- ----- -------
Total........ $ 4.07 $ 5.66 $ 4.08 $ 4.61 $ 4.75 $ 4.61 $ 4.92 $ 4.12 $ 4.83
Depletion expense
(per BOE)...... $ 5.77 $ 8.70 $ 5.78 $ 4.25 $ 5.73 $ 4.30 $ 5.19 $ 6.74 $ 5.36
- ---------------
(a) These amounts are calculated without making pro forma adjustments for any
acquisitions, divestitures or drilling activity that occurred during the
respective years.
(b) Represents production associated with the Company's Australian subsidiaries
prior to their divestiture in 1996.
18
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,
1997, 1996 and 1995.
PRODUCTIVE WELLS(a)
Gross Productive Wells Net Productive Wells
------------------------ -----------------------
Oil Gas Total Oil Gas Total
------ ------ ------ ------ ------ ------
Year ended December 31, 1997:
United States.................. 6,075 3,931 10,006 3,399 2,326 5,725
Argentina...................... 213 53 266 154 38 192
Canada......................... 1,666 428 2,094 667 202 869
------ ------ ------ ------ ------ ------
Total.......................... 7,954 4,412 12,366 4,220 2,566 6,786
====== ====== ====== ====== ====== ======
Year ended December 31, 1996:
United States.................. 5,572 1,393 6,965 3,119 650 3,769
Argentina...................... 5 - 5 1 - 1
------ ------ ------ ------ ------ ------
Total.......................... 5,577 1,393 6,970 3,120 650 3,770
====== ====== ====== ====== ====== ======
Year ended December 31, 1995:
United States.................. 6,138 2,137 8,275 3,198 680 3,878
Australia and Other Foreign.... 112 450 562 27 54 81
------ ------ ------ ------ ------ ------
Total.......................... 6,250 2,587 8,837 3,225 734 3,959
====== ====== ====== ====== ====== ======
- ---------------
(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, 1997, the Company owned interests in 182 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, 1997.
LEASEHOLD ACREAGE
Developed Acreage Undeveloped Acreage
------------------------ ------------------------ Royalty
Gross Acres Net Acres Gross Acres Net Acres Acreage
----------- ---------- ----------- ---------- --------
Year ended December 31, 1997:
United States................. 1,665,292 989,027 1,472,049 591,005 420,907
Canada........................ 331,000 152,000 701,000 478,000 -
Argentina..................... 697,683 301,820 1,650,769 1,027,490 -
----------- ---------- ----------- ---------- --------
Total......................... 2,693,975 1,442,847 3,823,818 2,096,495 420,907
=========== ========== =========== ========== ========
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, 1997, 1996 and 1995.
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
DRILLING ACTIVITIES
Gross Wells Net Wells
Year Ended December 31, Year Ended December 31,
---------------------- ----------------------
1997 1996(b) 1995 1997 1996(b) 1995
----- ------ ----- ----- ------ -----
United States:
Productive wells:
Development................ 483 535 432 341.2 362.9 307.0
Exploratory................ 38 37 30 23.8 24.2 18.0
Dry holes:
Development................ 18 7 7 8.8 4.4 2.1
Exploratory................ 46 10 16 30.3 6.0 4.7
----- ----- ----- ----- ------ -----
585 589 485 404.1 397.5 331.8
----- ----- ----- ----- ------ -----
Australia and other foreign:
Productive wells:
Development................ - 2 6 - .3 1.4
Exploratory................ - - 1 - - .3
Dry holes:
Development................ - 1 - - .2 -
Exploratory................ 1 1 9 .4 .2 2.8
----- ----- ----- ----- ------ -----
1 4 16 .4 .7 4.5
----- ----- ----- ----- ------ -----
Argentina:
Productive wells:
Development................ 4 3 - .6 .4 -
Exploratory................ 1 - 1 .1 - .1
Dry holes:
Development................ - - - - - -
Exploratory................ 1 3 7 .1 .4 1.0
----- ----- ----- ----- ------ -----
6 6 8 .8 .8 1.1
----- ----- ----- ----- ------ -----
Total.................... 592 599 509 405.3 399.0 337.4
===== ===== ===== ===== ====== =====
Success ratio(a)............. 89% 96% 92% 90% 97% 97%
- ---------------
(a) Represents those wells that were successfully completed as productive wells.
(b) The 1996 Australian amounts include only three months of activity related
to the Company's Australian properties prior to their sale in March 1996.
The following table sets forth information about the Company's wells that
were in progress at December 31, 1997.
Gross Wells Net Wells
----------- ---------
United States:
Development....................... 112 82.0
Exploratory....................... 13 9.1
----- ------
125 91.1
----- ------
Canada:
Development....................... 1 0.9
Exploratory....................... 1 0.6
----- ------
2 1.5
----- ------
Argentina:
Development....................... 5 5.0
Exploratory....................... 4 2.3
----- ------
9 7.3
----- ------
Total.......................... 136 99.9
===== ======
ITEM 3. LEGAL PROCEEDINGS
The Company is party to various legal proceedings, which are described
under "Legal Actions" in Note H of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data". The Company
is also party to other litigation incidental to its business. The claims for
damages from such other legal actions are not in excess of 10% of the Company's
current assets and the Company believes none of these actions to be material.
20
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Acquisition of Chauvco
On December 18, 1997, the Company held a Special Meeting for stockholders
in Dallas, Texas. The Special Meeting related to the acquisition by the Company
of the Canadian and Argentine oil and gas businesses of Chauvco Resources Ltd.,
an Alberta corporation, and the spinoff to Chauvco shareholders and
optionholders of Chauvco's Gabonese oil and gas operations and other
international interests (the "Combination Agreement"). Also on December 18,
1997, Chauvco held a Special Meeting for its stockholders in Alberta, Canada in
connection with the Combination Agreement. Each of the proposals was approved by
stockholders as follows:
The Company
- -----------
Broker
Proposal For Against Abstain Non-Votes
-------- ---------- ------- ------- ---------
Combination Agreement 57,282,078 345,596 285,770 -
Chauvco
- -------
Broker
Proposal For Against Abstain Non-Votes
-------- ---------- ------- ------- ---------
Combination Agreement 43,788,841 1,226 - -
21
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
--------- -------- --------------
1997
Fourth quarter..................... $43 13/16 $ 25 5/8 -
Third quarter...................... $ 44 3/8 $ 34 3/4 $.05
Second quarter..................... $ 36 3/16 $ 28 1/2 -
First quarter...................... $ 37 5/8 $ 28 7/8 $.05
1996
Fourth quarter..................... $ 37 1/4 $ 26 1/8 -
Third quarter...................... $ 27 3/4 $ 22 1/4 $.05
Second quarter..................... $ 27 7/8 $ 22 3/4 -
First quarter...................... $ 23 3/4 $ 19 3/8 $.05
On February 27, 1998, the last reported sales price of the Company's
common stock, as reported in the New York Stock Exchange composite transactions,
was $23.69 per share.
As of February 27, 1998, the Company's common stock was held by
approximately 55,000 holders of record, representing approximately 112,000 total
owners.
Since the third quarter of 1991, the Company has paid a cash dividend of
$.05 per share of common stock in the first and third quarters of each calendar
year. Subject to the continuation of successful operations and the discretion of
the Company's Board of Directors, the Company intends to continue to declare a
$.05 per share dividend on a semi-annual basis to achieve an annual dividend
level of $.10 per share. The Company's Board of Directors may from time to time
reconsider the dividend policy and make any changes that it deems appropriate.
There can be no assurance that any future dividends or distributions will be
paid on the Company's common stock.
On December 19, 1997, the Company completed the purchase of certain assets
in the East Texas Basin from affiliates of American Cometra, Inc. and Rockland
Pipeline Co., both of which are subsidiaries of Electrafina S.A. of Belgium. The
total consideration paid was approximately $130 million, consisting of $85
million in cash and 1.6 million shares of the Company's common stock. The common
stock, which was issued in a private placement, was distributed to the following
persons:
Common Stock Common Stock
Owned Prior to Acquired in
Transaction Transaction
-------------- -----------
Cometra Energy, L.P. 0 1,605,290
Terry N. McClure 0 9,800
James D. Paquin 0 19,600
Mark W. Young 1,000 19,600
In connection with such purchase of assets, the Company agreed to file and keep
continuously effective for up to 24 months a registration statement covering the
resale of the common stock issued in the transaction. Such registration
statement was declared effective by the SEC on March 2, 1998.
22
ITEM 6. SELECTED FINANCIAL DATA
The following selected consolidated financial data for the Company should
be read in conjunction with "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Company's Consolidated
Financial Statements, related notes and other financial information included in
"Item 8. Financial Statements and Supplementary Data".
Year ended December 31,
-------------------------------------------------
1997(a) 1996 1995 1994(b) 1993(c)
--------- -------- -------- -------- --------
(in millions, except per share data)
Statement of Operations Data:
Revenues:
Oil and gas.............................. $ 536.8 $ 396.9 $ 375.7 $ 337.6 $ 207.2
Natural gas processing................... - 23.8 33.2 39.2 77.5
Gas marketing............................ - - 76.8 103.0 43.8
Interest and other....................... 4.3 17.5 11.4 6.9 4.4
Gain on disposition of assets, net(d).... 4.9 97.1 16.6 9.5 23.2
-------- ------- ------- ------- -------
546.0 535.3 513.7 496.2 356.1
-------- ------- ------- ------- -------
Costs and expenses:
Oil and gas production................... 144.2 110.3 130.9 127.1 78.3
Natural gas processing................... - 12.5 25.9 33.6 51.6
Gas marketing............................ - - 75.7 101.5 42.8
Depletion, depreciation and amortization. 212.4 112.1 159.1 145.4 80.4
Impairment of oil and gas properties and
natural gas processing facilities...... 1,356.4 - 130.5 - -
Exploration and abandonments............. 77.2 23.0 27.5 25.2 3.6
General and administrative............... 48.8 28.4 37.4 29.0 23.8
Interest................................. 77.5 46.2 65.4 50.6 23.3
Other.................................... 7.1 2.5 11.3 4.3 3.9
-------- ------- ------- ------- -------
1,923.6 335.0 663.7 516.7 307.7
-------- ------- ------- ------- -------
Income (loss) before income taxes,
extraordinary item and cumulative effect
of accounting change..................... (1,377.6) 200.3 (150.0) (20.5) 48.4
Income tax benefit (provision)............. 500.3 (60.1) 45.9 6.5 (17.0)
-------- ------- ------- ------- -------
Income (loss) before extraordinary item and
cumulative effect of accounting change... (877.3) 140.2 (104.1) (14.0) 31.4
Extraordinary item......................... (13.4) - 4.3 (.6) -
Cumulative effect of accounting change..... - - - - 17.1
-------- ------- ------- ------- -------
Net income (loss)............................ $ (890.7) $ 140.2 $ (99.8) $ (14.6) $ 48.5
======== ======= ======= ======= =======
Income (loss) before extraordinary item
and cumulative effect of accounting
change per share:
Basic.................................. $ (16.88) $ 3.95 $ (2.96) $ (.47) $ 1.15
======== ======= ======= ======= =======
Diluted................................ $ (16.88) $ 3.47 $ (2.96) $ (.47) $ 1.12
======== ======= ======= ======= =======
Net income (loss) per share:
Basic.................................... $ (17.14) $ 3.95 $ (2.84) $ (.49) $ 1.77
======== ======= ======= ======= =======
Diluted.................................. $ (17.14) $ 3.47 $ (2.84) $ (.49) $ 1.73
======== ======= ======= ======= =======
Dividends per share ....................... $ .10 $ .10 $ .10 $ .10 $ .10
======== ======= ======= ======= =======
Weighted average shares outstanding........ 52.0 35.5 35.1 29.9 27.4
Other Financial Data:
Cash flows from operating activities....... $ 228.2 $ 230.1 $ 156.6 $ 129.8 $ 112.2
Cash flows from investing activities....... (341.2) 13.7 (52.6) (446.0) (398.2)
Cash flows from financing activities....... 166.0 (245.4) (107.9) 331.4 278.9
Balance Sheet Data:
Working capital............................ $ 46.6 $ 26.1 $ 31.5 $ 43.7 $ 39.5
Property, plant and equipment, net......... 3,515.8 1,040.4 1,121.7 1,349.9 802.0
Total assets............................... 3,946.6 1,199.9 1,319.2 1,604.9 1,016.9
Long-term obligations...................... 2,124.0 329.0 603.2 727.2 544.3
Preferred stock of subsidiary.............. - 188.8 188.8 188.8 -
Total stockholders' equity................. 1,548.8 530.3 411.0 509.6 348.8
- ---------------
23
(a) Includes amounts relating to the acquisition of Mesa beginning in August
1997.
(b) Includes amounts relating to the acquisition of Bridge Oil Limited in July
1994 and the acquisition of properties from PG&E Resources Company in
August 1994.
(c) Includes amounts relating to the acquisition of certain Prudential-Bache
Energy limited partnerships in July 1993. Also includes results of
operations related to the Company's interest in the Carthage gas processing
plant that had been deferred in 1992 and 1993 and the gain of $7.3 million
recognized on the sale of that interest on June 30, 1993.
(d) Includes a gain of $83.3 million in 1996 related to the disposition of
certain wholly-owned subsidiaries.
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The Formation of Pioneer
Pioneer Natural Resources Company (the "Company"), a Delaware corporation,
was formed by the merger of Parker & Parsley Petroleum Company ("Parker &
Parsley") and MESA Inc. ("Mesa") on August 7, 1997. The Company was
significantly expanded by the subsequent acquisition of the Canadian and
Argentine oil and gas business of Chauvco Resources Ltd. ("Chauvco"), a publicly
traded independent oil and gas company based in Calgary, Canada on December 18,
1997. The Company is an oil and gas exploration and production company with
ownership interests in oil and gas properties located principally in the
MidContinent, Southwestern and onshore and offshore Gulf Coast regions of the
United States and in Argentina and Canada.
Combining the physical assets and management teams of Parker & Parsley and
Mesa into the Company created a company with a solid foundation of core assets.
This foundation includes three core areas (the Hugoton gas field located in
Southwest Kansas, the West Panhandle gas field located in the Texas Panhandle,
and the Spraberry oil and gas field in West Texas) that provide consistent and
dependable production, cash flow and ongoing development opportunities; a
reserve portfolio which is balanced between oil and natural gas liquids and gas;
a portfolio of exciting exploration opportunities; and a team of dedicated
employees representing the professional disciplines and sciences which will
allow the Company to continue to provide its shareholders with superior
long-term value.
The Company's first significant accomplishment after the merger was the
acquisition of Chauvco. The Chauvco acquisition provided the Company with 87.6
MMBOE and 57.4 MMBOE of proved reserves in Argentina and Canada, respectively,
and a substantial inventory of unproved oil and gas properties which will
provide the Company with many exploration opportunities with the potential for
significant reserve additions. Although the acquisition of the portfolio of
unproved properties from Chauvco represents an exciting challenge to the
Company's team of engineers, geologists and geophysicists, such opportunities
are not without risk. U.S. GAAP requires periodic evaluations 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, future sales
or expiration of all or a portion of such projects. If the quantity of proved
reserves determined by such evaluations are not sufficient to fully recover the
cost invested in each project, the Company may be required to recognize
significant noncash charges to the earnings of future periods. There can be no
assurance that economic reserves will be determined to exist for such projects.
In accordance with the provisions of Accounting Principles Board No. 16,
"Business Combinations", both the merger with Mesa and the acquisition of
Chauvco have been accounted for as purchases by the Company (formerly Parker &
Parsley). As a result, the historical financial statements for the Company are
those of Parker & Parsley, and the Company's financial statements present the
addition of Mesa's and Chauvco's assets and liabilities as an acquisition by the
Company in August and December 1997, respectively. Specifically, the
accompanying Consolidated Statements of Operations and Consolidated Statements
of Cash Flows include the financial results of Mesa beginning in August 1997.
The aggregate purchase consideration related to the assets and liabilities of
Mesa and Chauvco, including transaction costs, was $991.0 million and $696.4
million, respectively.
Financial Performance
The Company reported a net loss of $890.7 million ($17.14 per share) as
compared to net income of $140.2 million ($3.95 per share) for the years ended
December 31, 1997 and 1996, respectively. The 1997 loss is primarily generated
by a noncash charge of $1.4 billion ($863 million after-tax) in December of
1997, resulting from an impairment charge taken in accordance with the Statement
of Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("SFAS 121"). In
addition to the above, the process of organizationally, operationally and
financially combining Parker & Parsley and Mesa to create the Company resulted
in the following pre-tax charges: the redemption of two issuances of senior
notes at a loss of $18.3 million; $6.4 million of relocation expenses and $1.9
million of severance expenses; and a $2.3 million write-off of commitment fees
related to Parker & Parsley's credit facility that was replaced with a new $1.4
billion credit agreement for the Company during 1997. As discussed more fully in
"Results of Operations" below, the Company's financial performance during 1997
has been positively affected by increases in oil and gas production and
25
decreases in production costs per BOE due to ongoing cost reduction efforts,
offset by decreases in commodity prices, increases in exploration and general
and administrative expenses and an increase in interest expense due to the
additional debt assumed from Mesa. The year ended December 31, 1996 includes
$67.3 million ($1.90 per share) related to net after-tax gains on asset
dispositions primarily due to the sale of the Company's Australasian
subsidiaries.
Net cash provided by operating activities of $228.2 million for the year
ended December 31, 1997 was comparable to $230.1 million for the year ended
December 31, 1996. The additional cash flow generated by increased production
was offset by increased general and administrative expenses and interest expense
and the payment of certain liabilities assumed from Mesa.
Long-term debt has increased to $2.0 billion at December 31, 1997 from
$320.9 million at December 31, 1996 due principally to the assumption of the
outstanding debt of Mesa and Chauvco and the property acquisitions described
below. The Company strives to maintain its outstanding indebtedness at a
moderate level in order to provide sufficient financial flexibility for future
opportunities. The Company's total book capitalization at December 31, 1997 was
$3.5 billion, consisting of total long-term debt of $2.0 billion and
stockholders' equity of $1.5 billion. Consequently, the Company's long-term debt
to total capitalization increased to 56% at December 31, 1997 from 31% at
December 31, 1996.
1998 Outlook
During 1998, the Company plans to accelerate its portfolio management
initiatives through a major divestiture program focused on improving operating
efficiency and profitability. Approximately 95% of the Company's domestic fields
generate only 15% of the Company's total cash flow. The Company plans to sell
these nonstrategic fields for estimated proceeds of $375 to $550 million during
the latter part of 1998. The proceeds will be used to reduce the Company's
outstanding indebtedness and to fund the Company's capital expenditures program.
This will leave the Company with approximately 25 fields, which represent its
core producing assets and complementary development and exploration
opportunities.
The consummation of the Company's 1998 divestiture plans is entirely
dependent on finding one or more willing buyers who have the financial
wherewithal to complete such a purchase. Until such a buyer is found, the
Company may reevaluate its portfolio of properties and at any time may adjust
its plans concerning divestitures. As a result, there can be no assurance that
the divestiture of any or all of these properties will be completed or that the
estimated proceeds will be realized.
Coincidentally with the property divestiture program, the Company has
announced its intentions to reorganize its operations to take advantage of the
economies of scale provided by the concentration of reserves in a small number
of fields. The Company will combine the six domestic regions created by the
merger between Parker & Parsley and Mesa into three geographic regions: the
Permian Basin region, the MidContinent region and the onshore and offshore Gulf
Coast region. The Company anticipates that it will incur nonrecurring
expenditures of approximately $20 million during 1998 as a result of this
reorganization.
During 1998, the Company will continue its emphasis on core development,
exploration and production activities, with a primary focus on the exploitation
of its current portfolio of drilling locations. This portfolio was significantly
enhanced and expanded by the major acquisitions completed in 1997. In addition,
the 1996 and 1997 drilling programs have added a large number of new locations
to which proved reserves have been assigned. The Company believes that its
current portfolio of undeveloped prospects provides attractive development and
exploration opportunities for at least the next three to five years. The Company
expects to invest $500 million in capital projects during 1998. Of the total
1998 capital expenditure budget of $500 million, the Company has allocated $301
million to exploitation activities, $125 million to exploration activities and
$74 million to oil and gas property acquisitions. The Company anticipates that
the $426 million exploration and development budget will be spent geographically
as follows: $106 million in the Permian Basin, $142 million in the onshore and
offshore Gulf Coast, $47 million in the MidContinent, $26 million in Canada, $79
million in Argentina and $26 million in Africa and other international areas.
This capital expenditure budget reflects the Company's plan to drill
approximately 695 oil and gas wells. The Company currently expects to fund its
1998 capital expenditure budget primarily with internally-generated cash flow
and the proceeds from the 1998 oil and gas property divestiture program.
26
This budget reflects the Company's ongoing strategy to commit a greater
portion of its cash flow to higher growth potential projects, including
significant 3-D seismic projects. Historically, Mesa and Parker & Parsley had
each spent a small percentage of its respective capital on exploration projects.
The Company now expects to spend approximately 29% of its
exploration/exploitation capital budget on exploration.
During most of 1996 and 1997, the Company benefitted from higher oil
prices as compared to previous years. However, during the fourth quarter of
1997, oil prices began a downward trend that has continued into March 1998. A
continuation of the oil price environment experienced during the first quarter
of 1998 will have an adverse effect on the Company's revenues and operating cash
flow, and may result in a downward adjustment to the Company's current 1998
capital budget of $500 million. Also, a continuing decline in oil prices could
result in additional decreases in the carrying value of the Company's oil and
gas properties.
The forward looking statements in these projections, including statements
relating to capital budget, production, cash flows and drilling activities, are
based upon a number of assumptions, including among others, limited changes in
oil and gas prices and the accuracy of reserve engineering studies. These
assumptions may prove not to have been accurate.
Significant Activities in 1997
Property Acquisition Activities
Cotton Valley. In May of 1997, the Company acquired a 35% interest in
approximately 375,000 gross acres within the Cotton Valley Pinnacle Reef Trend
from Union Pacific Resources Company ("UPRC") for $26.9 million. The Company and
UPRC have signed an exploration agreement to jointly explore and develop this
area located in eastern Texas and plan to begin drilling the first exploration
well before the end of the year.
On December 19, 1997, the Company completed the acquisition of assets in
the East Texas Basin from American Cometra, Inc. ("ACI") and Rockland Pipe Co.
("Rockland"), both subsidiaries of Electrafina S.A. of Belgium. The total
consideration paid was approximately $130 million, consisting of $85 million in
cash and 1.6 million shares of the Company's common stock. The Company acquired
all of ACI's producing wells, acreage (95,000 gross and 38,000 net), seismic
data, royalties and mineral interests and Rockland's gathering system, pipeline
and Plum Creek gas processing plant in the East Texas Basin. The acquired
acreage is in Henderson, Freestone, Anderson and Leon counties. The acquired
wells are currently producing approximately 18 MMcf per day and have significant
future drilling opportunities.
Maude Traylor. In February of 1997, the Company completed the acquisition
of a majority interest in the Maude Traylor field in Calhoun County, Texas for
approximately $8.8 million. This acquisition represented an average working
interest of 87% in approximately 1,840 acres and five wells which produce from
the upper and lower Frio formations.
Guatemala. During May of 1997, the Company finalized negotiations with
Triton Energy for a 40% working interest in a joint exploration program of two
blocks in Guatemala's South Peten Basin. Drilling on the Piedras Blancas #1
resulted in an unsuccessful exploratory well at a total cost to the Company of
$5.4 million.
Exploration and Development Activities
Drilling Activities. Excluding the merger with Mesa and the acquisition of
Chauvco, the Company's 1997 capital expenditures totaled $544 million reflecting
expenditures of $247 million for exploitation activities, $96 million for
exploration activities and $201 million for oil and gas property acquisitions in
the Company's core areas. During 1997, the Company participated in the
completion of 592 gross exploration and development wells, 453 wells in the
Permian region, 56 wells in the Gulf Coast region, 76 wells in the MidContinent
region, six wells in Argentina and one well in Guatemala. Of these wells, 85
were in progress at December 31, 1996. Of the total wells completed during the
year ended December 31, 1997, 526 wells were completed successfully which
resulted in an 89% success rate. In addition to the wells completed during 1997,
the Company had 136 wells in progress at December 31,