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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
__________________
FORM 10-K/A
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15 (d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File No. 0-25058
FLORES & RUCKS, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 72-1277752
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
8440 JEFFERSON HIGHWAY, SUITE 420
BATON ROUGE, LOUISIANA 70809
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (504) 927-1450
Securities Registered Pursuant to Section 12 (b) of the Act:
COMMON STOCK, $0.01 PAR VALUE
(Title of Class)
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 .
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Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [x]
The aggregate market value of the voting stock held by non-affiliates of
the registrant was approximately $601,939,848 as of March 21, 1997.
19,640,956 shares of the registrant's Common Stock were outstanding as of
March 21, 1997.
DOCUMENT INCORPORATED BY REFERENCE
The information called for by Part III of this Form 10-K is incorporated by
reference from the Proxy Statement for the Annual Meeting of Stockholders of the
Company to be held June 17, 1997.
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TABLE OF CONTENTS
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PAGE
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PART I
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Item 1. Business................................................................ 3
Item 2. Properties.............................................................. 10
Item 3. Legal Proceedings....................................................... 14
Item 4. Submission of Matters to Vote of Security Holders....................... 14
Item 4 (A). Executive Officers of Registrant........................................ 14
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters... 16
Item 6. Selected Financial Data................................................. 17
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.......................................................... 19
Item 8. Financial Statements and Supplementary Data............................. 30
Item 9. Changes in and Disagreements with Accountants and Financial Disclosure.. 54
PART III
Item 10. Directors and Executive Officers of the Registrant...................... 55
Item 11. Executive Compensation.................................................. 55
Item 12. Security Ownership of Certain Beneficial Owners and Management.......... 55
Item 13. Certain Relationships and Related Transactions.......................... 55
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 10-K........ 55
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NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-K includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-K, including without
limitation the statements under "Business", "Properties" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
regarding the nature of the Company's oil and gas reserves, productive wells,
acreage, and drilling activities, the adequacy of the Company's financial
resources, current and future industry conditions and the potential effects of
such matters on the Company's business strategy, results of operations and
financial position, are forward-looking statements. Although the Company
believes that the expectations reflected in the forward-looking statements
contained herein are reasonable, no assurance can be given that such
expectations will prove to have been correct. Certain important factors that
could cause actual results to differ materially from expectations ("Cautionary
Statements"), including without limitation fluctuations of the prices received
for the Company's oil and natural gas, uncertainty of drilling results and
reserve estimates, competition from other exploration, development, and
production companies, operating hazards, abandonment costs, the effects of
governmental regulation and the highly leveraged nature of the Company, are
stated herein in conjunction with the forward-looking statements or are included
elsewhere in this Form 10-K. All subsequent written and oral forward-looking
statements attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by the Cautionary Statements.
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PART I
ITEM 1: BUSINESS
GENERAL
Flores & Rucks, Inc. (the "Company") is an independent energy company
engaged in the exploration, development, acquisition and production of crude oil
and natural gas with operations focused primarily on the coastal onshore and
shallow water offshore regions of Louisiana (the "Louisiana Gulf"), one of the
most prolific oil and gas producing regions in the United States. As of
December 31, 1996, the Company had estimated proved reserves of approximately
50.8 MMBbls of oil and 145.4 Bcf of natural gas, or an aggregate of
approximately 75.0 MMBOE, with a Present Value of Future Net Revenues of
approximately $693.5 million and a Standardized Measure of Discounted Future Net
Cash Flows of approximately $532.5 million. On a BOE basis, approximately 68%
of the Company's proved reserves on such date were oil. The majority of the
Company's existing proved reserves are attributable to Company operated wells or
leases and approximately 75% of these reserves were classified as proved
developed at December 31, 1996.
In order to reduce risks and lower drilling costs, the Company uses state-
of-the-art seismic evaluation technology in its exploitation and exploration
activities. The seismic evaluation technology is integrated with subsurface
data to improve the Company's ability to properly define the structural and
stratigraphic features which potentially contain accumulation of hyrdrocarbons.
As of January 16, 1997, the Company owned approximately 1,930 square miles of 3-
D seismic data and approximately 22,326 linear miles of 2-D seismic data on and
around its core properties.
The Company is a Delaware corporation formed in September 1994 to acquire
and own 100% of the outstanding Common Stock of Flores & Rucks, Inc., a
Louisiana corporation ("FRI Louisiana"). FRI Louisiana was formed in April 1992
to take advantage of opportunities to acquire and develop certain offshore
properties in the Louisiana Gulf. Unless otherwise indicated, all references to
the "Company" are to Flores & Rucks, Inc., a Delaware corporation, its
predecessors and their respective subsidiaries.
The Company's major acquisitions to date include the acquisition from Shell
Oil Company, its affiliates and subsidiaries ("Shell") of its interest in the
Main Pass 69 field ("Main Pass 69") in June 1992 and its interest in the South
Pass 24 and 27 fields (the "East Bay Fields", and together with the related
platforms and facilities, the "East Bay Complex") in June 1993. In September
1996, the Company acquired from Mobil Oil Exploration & Producing Southeast Inc.
("Mobil") certain interests in eleven oil and gas producing fields and related
production facilities primarily situated in the shallow federal waters of the
central Gulf of Mexico, offshore Louisiana (the "Central Gulf Properties"). The
above acquisitions coupled with the Company's successful exploration and
exploitation efforts on the acquired properties have resulted in substantial
increases in production and reserve growth. The Company manages its field costs
by combining administrative functions relating to its properties, controlling
the number of operating personnel and providing incentive compensation. Close
management of operating costs combined with the increased production mentioned
above have resulted in a 5% decrease to the Company's lease operating expense
per BOE to $3.52 per BOE in the year ended December 31, 1996 from $3.70 per BOE
in the comparable 1995 period.
OIL AND GAS MARKETING AND MAJOR CUSTOMERS
The revenues generated by the Company's operations are highly dependent
upon the prices of, and demand for, oil and natural gas. The price received by
the Company for its oil and natural gas production depends on numerous factors
beyond the Company's control, including seasonality, the condition of the United
States economy, particularly the manufacturing sector, foreign imports,
political conditions in other oil-producing and natural gas-producing countries,
the actions of the Organization of Petroleum Exporting Countries and domestic
government regulation, legislation and policies. Decreases in the prices of oil
and natural gas could have an adverse effect on the carrying value of the
Company's proved reserves and the Company's revenues, profitability and cash
flow. Although the Company is not currently experiencing any significant
involuntary curtailment of its oil or natural gas production, market, economic
and regulatory factors may in the future materially affect the Company's ability
to sell its oil or natural gas production. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
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The Company has a long term contract to sell all crude oil volumes produced
from its East Bay fields to Shell at a price based on the highest monthly posted
price of a number of principal purchasers of crude oil in the South Louisiana
area. The contract expires in June 2003. The Company markets its remaining
crude oil and natural gas production pursuant to short-term contracts.
Sales to Shell Oil Company, Murphy Oil USA, Inc. and Enron Capital & Trade
Resources Corp. accounted for 54%, 11% and 17%, respectively, of the Company's
oil and gas revenues for the year ended December 31, 1996, and 64%, 19% and 14%,
respectively for the year ended December 31, 1995.
Due to the availability of other markets and pipeline connections, the
Company does not believe that the loss of any single crude oil or natural gas
customer would adversely affect the Company's results of operations.
COMPETITION
The oil and gas industry is highly competitive in all of its phases. The
Company encounters competition from other oil and gas companies in all areas of
its operations, including the acquisition of producing properties. The Company's
competitors include major integrated oil and natural gas companies and numerous
independent oil and natural gas companies, individuals and drilling and income
programs. Many of its competitors are large, well established companies with
substantially larger operating staffs and greater capital resources than the
Company's and which, in many instances, have been engaged in the energy business
for a much longer time than the Company. Such companies may be able to pay more
for productive oil and natural gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and
prospects than the Company's financial or human resources permit. The Company's
ability to acquire additional properties and to discover reserves in the future
will be dependent upon its ability to evaluate and select suitable properties
and to consummate transactions in a highly competitive environment.
Capital available for investment in the oil and natural gas industry may
decline significantly as a result of decreases in product prices, future changes
in federal income tax laws and adverse economic conditions generally affecting
the industry and the country as a whole.
OPERATING HAZARDS AND UNINSURED RISKS
The Company's operations are subject to hazards and risks inherent in
drilling for and production and transportation of oil and natural gas, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, cratering, pipeline ruptures, and spills, any of which can
result in loss of hydrocarbons, environmental pollution, personal injury claims,
and other damage to properties of the Company and others. Additionally, the
Company's oil and gas operations are located in an area that is subject to
tropical weather disturbances, some of which can be severe enough to cause
substantial damage to facilities and possibly interrupt production. As
protection against operating hazards, the Company maintains insurance coverage
against some, but not all, potential losses. The Company's coverages include,
but are not limited to, operator's extra expense, physical damage on certain
assets, employer's liability, comprehensive general liability, automobile,
workers' compensation and loss of production income insurance. The Company
believes that its insurance is adequate and customary for companies of a similar
size engaged in operations similar to those of the Company, but losses could
occur for uninsurable or uninsured risks or in amounts in excess of existing
insurance coverage. The occurrence of an event that is not fully covered by
insurance could have an adverse impact on the Company's financial condition and
results of operations.
EMPLOYEES
As of January 1, 1997, the Company had 290 full-time employees, none of
whom is represented by any labor union. Included in the total were 120 corporate
employees located in the Company's Baton Rouge, Louisiana, Lafayette, Louisiana
and New Orleans, Louisiana offices, as well as 170 employees who work in the
Company's East Bay, Main Pass 69 and Central Gulf fields. The Company considers
its relations with its employees to be good.
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GOVERNMENTAL REGULATION
The Company's oil and gas exploration, production and related operations
are subject to extensive rules and regulations promulgated by Federal and state
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and affects its profitability.
Because such rules and regulations are frequently amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
laws.
The State of Louisiana and many other states require permits for drilling
operations, drilling bonds, and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
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 such wells.
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 (the "NGPA"), and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission (the "FERC"). In the
past, the federal government has regulated the wellhead price of natural gas.
Deregulation of wellhead sales in the natural gas industry began with the
enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was
enacted, which amended the NGPA to remove wellhead price controls on all
domestic natural gas as of January 1, 1993. While sales by producers of natural
gas, and all sales of crude oil, condensate and natural gas liquids, can
currently be made at uncontrolled market prices, Congress could re-enact price
controls in the future.
Several major regulatory changes have been implemented by the FERC from
1985 to the present that have had a major impact on natural gas pipeline
operations, services and rates and thus have significantly altered the marketing
and price of natural gas. Commencing in April 1992, the FERC issued Order Nos.
636, 636-A and 636-B (collectively, "Order No. 636"), which, among other things,
require each interstate pipeline company to "restructure" to provide
transportation separate or "unbundled" from the sale of gas and to make
available on an open and nondiscriminatory basis numerous constituent services
(such as gathering services, storage services, firm and interruptible
transportation services, and stand-by sales and gas balancing services) and to
adopt a new ratemaking methodology to determine appropriate rates for those
services. To the extent the pipeline company or its sales affiliate makes gas
sales as a merchant in the future, it does so in direct competition with all
other sellers pursuant to private contracts; however, pipeline companies and
their affiliates were not required to remain "merchants" of gas and several of
the interstate pipeline companies have become "transporters" only. Following
the conclusion of individual restructuring proceedings for each interstate
pipeline pursuant to Order No. 636, the FERC has approved, with modifications,
all of the restructuring plans and generally accepted compliance filings
implementing Order No. 636 on every interstate pipeline as of the end of 1994.
On July 16, 1996, the Court of Appeals for the District of Columbia Circuit
("D.C. Circuit") issued its opinion on review of Order No. 636. The opinion
upheld most elements of Order No. 636 including the unbundling of sales and
transportation services, curtailment of pipeline capacity, implementation of the
capacity release program and the mandatory imposition of straight-fixed-variable
("SFV") rate design for interstate pipeline companies. The D.C. Circuit did
remand certain aspects of Order No. 636 to the FERC for further explanation
including, inter alia, the FERC's decision to exempt pipelines from sharing in
gas supply realignment ("GSR") costs caused by restructuring; FERC's selection
of a twenty-year term matching cap for the right-of-first-refusal mechanism; the
FERC's restriction on the entitlement of no-notice transportation service to
only those customers receiving bundled sales service at the time of
restructuring; and FERC's determination that pipelines should focus on
individual customers, rather than customer classes, in mitigating the effects of
SFV rate design. On February 27, 1997, the FERC issued its order on remand.
The order reaffirmed the holding of Order No. 636 that pipelines should be
entitled to recover 100 percent of their prudently incurred GSR costs.
Moreover, since Order No. 636, few, if any, pipeline customers have been
willing, or required, to commit to twenty-year contracts for existing capacity.
Thus, FERC reduced the contract matching cap for the right-of-first-refusal
mechanism to five years. In light of the varied post-restructuring experience
with no-notice service, the FERC also decided to no longer limit a pipeline's
no-notice service to its bundled sales customers at the time of restructuring.
Finally, the FERC reaffirmed that pipelines should focus on individual
customers, rather that customer classes, in mitigating the effects of SFV rate
design. Four petitions were filed with the Supreme Court on January 27, 1997
for writ of certiorari to review those portions of the D.C. Circuit's opinion
which affirmed the capacity release and
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right-of-first-refusal provisions adopted in Order No. 636. Appeals of
individual pipeline restructuring orders are still pending before the D.C.
Circuit.
The FERC has announced its intention to reexamine certain of its
transportation-related policies, including the appropriate manner in which
interstate pipelines release transportation capacity under Order No. 636, and
the use of market-based rates for interstate gas transmission. While any
resulting FERC action would affect the Company only indirectly, the FERC's
current rules and policy statements may have the effect of enhancing competition
in natural gas markets by, among other things, encouraging non-producer natural
gas marketers to engage in certain purchase and sale transactions. The Company
cannot predict what action the FERC will take on these matters, nor can it
accurately predict whether the FERC's actions will achieve the goal of
increasing the competition in markets in which the Company's natural gas is
sold. However, the Company does not believe that it will be treated materially
differently than other natural gas producers and marketers with which it
competes.
On May 31, 1995, the FERC issued a policy statement on how interstate
natural gas pipelines can recover the costs of new pipeline facilities. The
policy statement focused on whether projects would be priced on a rolled-in
basis (rolling in the expansion costs with the existing facilities) or on an
incremental basis (establishing separate cost-of services and separate rates for
the existing and expansion facilities). The policy statement established a
presumption in favor of rolled-in rates when the rate increase to existing
customers from rolling in the new facilities is 5% or less. While this policy
statement affects the Company only indirectly, the new policy should enhance
competition in natural gas markets and facilitate construction of gas supply
laterals. In the policy statement, the FERC contemplated that the resolution of
pricing methodology would take place in individual proceedings based on the
facts and circumstances of the project. The Company cannot predict what action
the FERC will take in the individual proceedings.
In October of 1992 Congress passed the Energy Policy of 1992 ("Energy
Policy Act"). The Energy Policy Act deemed petroleum pipeline rates in effect
for the 365-day period ending on the date of enactment of the Energy Policy Act
or that were in effect on the 365th day preceding enactment and had not been
subject to complaint, protest or investigation during the 365-day period to be
just and reasonable under the Interstate Commerce Act. The Energy Policy Act
also provides that complaints against such rates may only be filed under the
following limited circumstances: (i) a substantial change has occurred since
enactment in either the economic circumstances or the nature of the services
which were a basis for the rate; (ii) the complainant was contractually barred
from challenging the rate prior to enactment; or (iii) the rate is unduly
discriminatory or preferential. The Energy Policy Act further required FERC to
issue rules establishing a simplified and generally applicable ratemaking
methodology for petroleum pipelines, and to streamline procedures in petroleum
pipeline proceedings. On October 22, 1993, the FERC responded to the Energy
Policy Act directive by issuing Order No. 561, which adopts a new indexing rate
methodology for petroleum pipelines. Under the new regulations, which were
effective January 1, 1995, petroleum pipelines are able to change their rates
within prescribed ceiling levels that are tied to the Producer Price Index for
Finished Goods, minus one percent. Rate increases made pursuant to the index
will be subject to protest, but such protests must show that the portion of the
rate increase resulting from application of the index is substantially in excess
of the pipeline's increase in costs. The new indexing methodology can be
applied to any existing rate, even if the rate is under investigation. If such
rate is subsequently adjusted, the ceiling level established under the index
must be likewise adjusted.
In Order No. 561, FERC said that as a general rule pipeliners must utilize
the indexing methodology to change their rates. FERC indicated, however, that
it was retaining cost-of-service ratemaking, market-based rates, and settlement
as alternatives to the indexing approach. A cost-of-service proceeding will be
instituted to determine just and reasonable initial rates for new services. A
pipeline can also follow a cost-of-service approach when seeking to increase its
rates above index levels for uncontrollable circumstances. A pipeline can seek
to charge market-based rates if it can establish that it lacks market power.
Finally, a pipeline can establish rates pursuant to settlement if agreed upon by
all current shippers.
On May 10, 1996, the D.C. Circuit affirmed Order No. 561. The Court held
that by establishing a general indexing methodology along with limited
exceptions to indexed rates, FERC had reasonably balanced its dual
responsibilities of ensuring just and reasonable rates and streamlining
ratemaking through generally applicable procedures. Because of the novelty and
uncertainty surrounding the indexing methodology, as well as the possibility of
the use of cost-of service ratemaking and market-based rates, the Company is not
able at this time to predict the effects of Order No. 561, if any, on the
transportation costs associated with oil production from the Company's oil
producing operations.
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Under the Outer Continental Shelf Lands Act ("OCSLA"), the FERC also
regulates certain activities on the Outer Continental Shelf (the "OCS"). Under
OCSLA, all gathering and transporting of oil and natural gas on the OCS must be
performed on an "open and non-discriminatory" basis. Consequently, the
Company's gathering and transportation facilities located on the OCS must be
made available to third parties. In addition, the MMS imposes regulations
relating to development and production of oil and gas properties in federal
waters. Under certain circumstances, the MMS may require any Company operations
on federal leases to be suspended or terminated. Any such suspensions or
terminations could materially and adversely affect the Company's financial
condition and operations.
Certain of the Company's businesses are subject to regulation by the
Federal Natural Gas Pipeline Safety Act of 1968 and other state and Federal
environmental statutes and regulations.
The Oil Pollution Act of 1990 (the "OPA") imposes a variety of regulations
on "responsible parties" related to the prevention of oil spills and liability
for damages resulting from such spills in United States waters. A "responsible
party" includes the owner or operator of a facility or vessel, or the lessee or
permittee of an area in which an offshore facility is located. The OPA assigns
liability to each responsible party for oil removal costs and a variety of
public and private damages. While liability limits apply in some circumstances,
a party cannot take advantage of liability limits if the spill was caused by
gross negligence or willful misconduct or resulted from violation of a federal
safety, construction or operating regulation. If the party fails to report a
spill or to cooperate fully in its cleanup, liability limits likewise do not
apply. Few defenses exist to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party including
proof of financial responsibility to cover at least some costs in a potential
spill. As amended by the Coast Guard Authorization Act of 1996, OPA requires
responsible parties for offshore facilities to provide financial assurance in
the amount of $35 million to cover potential OPA liabilities. This amount is
subject to upward regulatory adjustment up to $150 million.
ENVIRONMENTAL MATTERS
The Company's operations and properties are subject to extensive and
changing federal, state and local laws and regulations relating to environmental
protection, including the generation, storage, handling, emission,
transportation and discharge of materials into the environment, and relating to
safety and health. The recent trend in environmental legislation and regulation
is generally toward stricter standards, and this trend will likely continue.
These laws and regulations may require the acquisition of a permit or other
authorization before construction or drilling commences and for certain other
activities; limit or prohibit construction, drilling and other activities on
certain lands lying within wilderness or wetlands and other protected areas; and
impose substantial liabilities for pollution resulting from the Company's
operations. The permits required for various of the Company's operations are
subject to revocation, modification and renewal by issuing authorities. The
Company believes that its operations currently are in substantial compliance
with applicable environmental regulations.
Governmental authorities have the power to enforce compliance with their
regulations, and violations are subject to fines, injunction, or both. The
Company does not expect environmental compliance matters to have a material
adverse effect on its financial position. It is also not anticipated that the
Company will be required in the near future to expend amounts that are material
to the financial condition or operations of the Company by reason of
environmental laws and regulations, but because such laws and regulations are
frequently changed, and may impose increasingly stricter requirements, the
Company is unable to predict the ultimate cost of complying with such laws and
regulations.
The following are examples of environmental, safety and health laws that
potentially relate to the Company's operations:
Solid Waste. The Company's operations may generate and result in the
transportation, treatment, and disposal of both hazardous and nonhazardous solid
wastes that are subject to the requirements of the federal Resource Conservation
and Recovery Act and comparable state and local requirements. The Environmental
Protection Agency ("EPA") is currently considering the adoption of stricter
disposal standards for nonhazardous waste. Further, it is possible that some
wastes that are currently classified as nonhazardous, perhaps including wastes
generated during pipeline, drilling and production operations, may in the future
be designated as "hazardous wastes," which are subject
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to more rigorous and costly disposal requirements. Such changes in the
regulations may result in additional expenditures or operating expenses by the
Company.
Hazardous Substances. The Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA") and comparable state statutes, also
known as "Superfund" laws, impose liability, without regard to fault or the
legality of the original conduct, on certain classes of persons for the release
of a "hazardous substance" into the environment. These persons include the
owner or operator of a site, and companies that transport, dispose of or arrange
for the disposal of, the hazardous substances found at the site. CERCLA also
authorizes the EPA, and in some cases, third parties to take actions in response
to threats to the public health or the environment and to seek to recover from
the classes of responsible persons the costs they incur. Although "petroleum"
is excluded from CERCLA's definition of a "hazardous substance," in the course
of its ordinary operations the Company may generate other materials which may
fall within the definition of a "hazardous substance." The Company may be
responsible under CERCLA for all or part of the costs required to clean up sites
at which such wastes have been disposed and for natural resource damages. The
Company has not received any notification that it may be potentially responsible
for cleanup costs under CERCLA or any comparable state law.
Air. The Company's operations may be subject to the Clean Air Act ("CAA")
and comparable state and local requirements. Amendments to the CAA were adopted
in 1990 and contain provisions that may result in the gradual imposition of
certain pollution control requirements with respect to air emissions from the
operations of the Company. The EPA has been developing regulations to implement
these requirements. The Company may be required to incur certain capital
expenditures in the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals
addressing other air emission-related issues. However, the Company does not
believe its operations will be materially adversely affected by any such
requirements.
Water. The Federal Water Pollution Control Act ("FWPCA") imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and gas wastes into navigable waters. Such discharges are typically
authorized by National Pollutant Discharge Elimination System ("NPDES") permits.
The FWPCA provides for civil, criminal and administrative penalties for any
unauthorized discharges of oil and other hazardous substances in reportable
quantities and, along with the Oil Pollution Act of 1990, imposes substantial
potential liability for the costs of removal, remediation and damages. State
laws for the control of water pollution also provide varying civil, criminal and
administrative penalties and liabilities in the case of a discharge of petroleum
or its derivatives into state waters. In addition, the Coastal Zone Management
Act authorizes state implementation and development of programs of management
measures for non-point source pollution to restore and protect coastal waters.
As of January 1, 1997, the federal NPDES permits prohibit the discharge of
produced water, and some other substances related to the oil and gas industry,
from wells located in the coastal waters of Louisiana. The Louisiana Department
of Environmental Quality ("LDEQ"), as administrator of the NPDES permits in
Louisiana, issued on December 30, 1996, and reissued on February 28, 1997, an
emergency rule to allow continued discharge of produced waters in the coastal
area, subject to a zero discharge requirement by no later than December 31, 1999
for produced water being currently discharged into major deltaic passes of the
Mississippi River. On February 24, 1997, LDEQ issued to the Company a compliance
order allowing it to temporarily discharge produced water into Southwest Pass, a
major deltaic pass of the Mississippi River. The Company has submitted to LDEQ a
compliance plan for achievement of zero discharge of produced water at its East
Bay Central Facility by no later than December 31, 1999. Simultaneously, the
Company plans to reformat a portion of its East Bay Facilities to allow for
discharge of produced water in the offshore areas, to the extent allowed by
NPDES permits. Although the costs to reformat Company operations to comply with
these zero discharge mandates under federal or state law may be significant, the
Company believes that these costs will not have a material adverse impact on the
Company's financial conditions and operations.
Protected Species. The Endangered Species Act ("ESA") seeks to ensure that
activities do not jeopardize endangered or threatened animal, fish and plant
species, nor destroy or modify the critical habitat of such species. Under the
ESA, exploration and production operations, as well as actions by federal
agencies, may not significantly impair or jeopardize the species or its habitat.
The ESA provides for criminal penalties for willful violations of the act.
Other statutes which provide protection to animal and plant species and which
may apply to the Company's operations which include, but are not necessarily
limited to, the Marine Mammal Protection Act, the Marine Protection and
Sanctuaries Act, the Fish and Wildlife Coordination Act, the Fishery
Conservation and Management Act, the Migratory Bird Treaty Act and the National
Historic Preservation Act.
Wetlands. Pursuant to the FWPCA, the United States Corps of Engineers,
with oversight by the EPA, administers a complex program that regulates
activities in wetland areas. Some of the Company's operations are in areas that
have been designated as wetlands and, as such, are subject to permitting
requirements. Failure to properly
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obtain a permit or violation of permit terms could result in the issuance of
compliance orders, restorative injunctions and a host of civil, criminal and
administrative penalties. The Company believes that it is currently in
substantial compliance with these permitting requirements.
Wildlife Refuges/Bird Sanctuaries. Portions of the Company's properties
are located in or adjacent to federal and state wildlife refuges and bird
sanctuaries. The Company's operations in such areas must comply with
regulations governing air and water discharge which are more stringent than its
other areas of operations. The Company has not been, and does not anticipate
that it will be, materially affected by any such requirements.
Safety and Health. The Company's operations are subject to the
requirements of the federal Occupational Safety and Health Act ("OSHA") and
comparable state statutes. The OSHA hazard communication standard, the EPA
community-right-to-know regulations under Title III of the Federal Superfund
Amendment and Reauthorization Act, and similar state statutes require that
certain information be organized and maintained about hazardous materials used
or produced in the operations. Certain of this information must be provided to
employees, state and local government authorities and citizens.
The Company incurred approximately $620,000, $694,000 and $975,000 relating
to environmental compliance during 1994, 1995 and 1996, respectively.
ABANDONMENT COSTS
The Company is responsible for payment of abandonment costs on the oil and
gas properties it operates. As of December 31, 1996, total abandonment costs on
the Company's oil and gas properties estimated to be incurred through the year
2011 were approximately $84.0 million. Estimates of abandonment costs and their
timing may change due to many factors including actual production results,
inflation rates, and changes in environmental laws and regulations.
In connection with its acquisition of the East Bay Complex and Main Pass
69, the Company entered into two escrow agreements to provide for the future
plugging and abandonment costs of these properties. The East Bay agreement
requires the Company to make monthly deposits of $100,000 through June 30, 1998,
and $350,000 thereafter until the balance in the escrow account equals $40
million unless the Company commits to the plug and abandonment of a certain
number of wells in which case the increase will be deferred. The Main Pass 69
agreement requires monthly deposits of $50,000 until the balance in the escrow
account equals $7.5 million. Such funds are restricted as to withdrawal by the
agreement. With respect to any specifically planned plugging and abandoning
operation, funds are partially released to the Company when it presents to the
escrow agent the planned plugging and abandonment operations approved by the
applicable governmental agency, with the balance to be released upon the
presentation by the Company to the trustee of evidence from the governmental
agency that the operation was conducted in compliance with applicable laws and
regulations. As of December 31, 1996, the escrow balances totaled $6.3 million.
In addition, the MMS requires lessees of OCS properties to post bonds in
connection with the plugging and abandonment of wells located offshore and the
removal of all production facilities. Operators in the OCS waters of the Gulf
of Mexico are currently required to post area wide bonds of $3 million or
$500,000 per producing lease and supplemental bonds at the discretion of the
MMS. On January 17, 1995, as amended May 1, 1996, the Company entered into an
agreement with Planet Indemnity Company ("Planet") whereby Planet agreed to
issue $11.7 million of MMS surety bonds for the Company and the Company agreed
to post collateral for same in favor of Planet. The collateral includes a
mortgage on the Company's federal (OCS) leases in the amount of $8.2 million, a
letter of credit for $2.0 million and a pledge of certain rights to escrowed
funds. The Company has posted with the MMS an area wide bond of $3.0 million
and supplemental bonds totaling $17.1 million. Pursuant to a schedule
previously imposed by the MMS, the Company will be required to post additional
supplemental bonds up to a level of $24.6 million by January 1999, unless the
Company is determined by the MMS to be exempt from such requirement due to
certain financial tests. In addition, the Company is currently working with the
MMS to determine the level of supplemental bonding (and the timing thereof)
which will be required for some of the recently acquired Central Gulf
Properties. The Company does not anticipate that the cost of any such bonding
requirements will materially affect the Company's financial position. Under
certain circumstances, the MMS may require any Company operations on federal
leases to be suspended or terminated. Any such suspensions or terminations
could have a material adverse effect on the Company's financial condition and
operations.
9
<PAGE>
ITEM 2: PROPERTIES
Mississippi Delta Area
The Company's Mississippi delta area (the "Mississippi Delta Area") is
comprised of six Company operated fields - South Pass 1, South Pass 24, South
Pass 27, South Pass 39, Main Pass 69 and Main Pass 138, as well as two non-
operated fields - South Pass 41 and Main Pass 140. The Mississippi Delta Area
encompasses approximately 75,458 gross leased acres in state and federal waters
situated near the mouth of the Mississippi River in the Gulf of Mexico. In
addition, the Company has interests in approximately 19,230 gross leased acres
in the Chandeleur Sound, Blind Bay, Breton Sound and Main Pass 71/75 areas,
where there are currently no producing wells.
At the core of the Mississippi Delta Area is the East Bay Complex. The
East Bay Complex is a major oil production facility with daily production
capacity for 70 MBbls of oil, 240 MMcf of gas and 240 MBbls of water. Within
the East Bay Complex, the South Pass 24 field, discovered in 1950, has
production established from 40 horizons and 460 reservoirs with cumulative
production through December 31, 1996, of 321,869 MBbls of oil and 401,924 MMcf
of gas. The South Pass 27 field, discovered in 1954, has production established
from 40 horizons and 460 reservoirs with cumulative production through December
31, 1996, of 334,559 MBbls of oil and 798,056 MMcf of gas.
The Company owns an average 96% working interest in these fields, and for
the three months ended December 31, 1996, the Mississippi Delta Area averaged
daily net sales to the Company of 20.3 MBbls of oil and 56.1 MMcf of gas from
478 gross producing wells.
Central Gulf Area
The Company's Central Gulf Area (the "Central Gulf Area") is comprised of
nine Company operated fields - Eugene Island 45, Eugene Island 100, Eugene
Island 126, Eugene Island 128, South Marsh Island 235, South Marsh Island 243,
Vermilion 215, Vermilion 273 and Ship Shoal 64, as well as two non-operated
fields - South Marsh Island 269 and Vermilion 76. The Central Gulf Area
consists of approximately 94,800 gross leased acres in federal waters situated
in the shallow federal waters of the Central Gulf of Mexico, offshore Louisiana.
The Company owns an average 45% working interest in these fields, and for
the three months ended December 31, 1996, the Central Gulf Area averaged daily
net sales to the Company of 4.0 MBbls of oil and 17.4 MMcf of gas from 76
producing wells.
Effective January 3, 1997, the Company sold its interest in the South Marsh
Island 269 field for $37.2 million. The South Marsh Island 269 field consisted
of 27 producing wells located on approximately 11,450 gross leased acres and had
average daily sales net to the Company for the three months ended December 31,
1996 of 0.8 MBbls of oil and 7.4 MMcf of gas. The Company owned an average 20%
working interest in this field.
Onshore Louisiana
During 1996, the Company extended its operations to include several coastal
onshore exploration projects and believes this region has been underexplored due
to its complex geology and lack of 3-D seismic data. Advances in 3-D seismic
acquisition techniques over the past few years have led the Company to purchase
options to conduct 3-D seismic survey and explore for oil and gas on 26,945
acres in eastern Cameron Parish, Louisiana on its Mallard Bay prospect area
("Mallard Bay"). The Company is currently conducting a 70 square mile
proprietary 3-D seismic survey on Mallard Bay along with its 50% working
interest partner, Mobil. Over 70 prospects or leads have been identified at
Mallard Bay from review of 2-D seismic and subsurface data. Separately, the
Company recently acquired seismic and lease options covering 14,060 acres in its
Lacassine Refuge prospect area ("Lacassine") located approximately 6 miles
northwest of Mallard Bay, where it expects to begin drilling in 1997. In
addition, the Company owns an average 14% working interest in 2,004 gross leased
acres in the Turtle Bayou field, located in Terrebone Parish, Louisiana
10
<PAGE>
OIL AND NATURAL GAS RESERVES
Presented below are the estimated quantities of proved developed and proved
undeveloped reserves of crude oil and natural gas and the Present Value of
Future Net Revenues (before income taxes) owned by the Company as of December
31, 1996. A portion of these reserves will be consumed by the Company in the
form of fuel for its oil and gas fields. Information set forth in the following
table is based upon reserve reports prepared by Netherland, Sewell & Associates,
Inc., independent petroleum engineers, in accordance with the rules and
regulations of the Commission. The Company includes as proven reserves, future
gas production estimated by Netherland, Sewell & Associates, Inc., to be used as
fuel gas. In accordance with such rules and regulations, the pretax estimate of
future net revenues and the pretax present value of future net revenues was
decreased by approximately $20.5 million and $18.6 million, respectively,
representing the effect of hedging transactions entered into as of December 31,
1996.
<TABLE>
<CAPTION>
PROVED RESERVES AT
DECEMBER 31, 1996
----------------------------------------------
DEVELOPED DEVELOPED UNDEVELOPED TOTAL
--------- ------------ ----------- --------
PRODUCING NONPRODUCING
--------- ------------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Net proved reserves:
Oil (Mbbls) 27,029 11,318 12,429 50,776
Gas (Mmcf) 56,836 52,738 35,784 145,358
MBOE (6 Mcf per Bbl) 36,490 20,120 18,393 75,003
Estimated future net revenues (before income taxes) $306,470 $285,671 $289,633 $881,774
Present value of future net revenues (before income
taxes; discounted at 10%) $295,668 $188,764 $209,083 $693,515
Standardized measure of discounted future net
cash flows (1) $532,492
</TABLE>
(1) The Standardized Measure of Discounted Future Net Cash Flows represents
the Present Value of Future Net Revenues after income taxes discounted
at 10%.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
Company. Reserve engineering is a subjective process of estimating underground
accumulations of crude oil and natural gas that cannot be measured in an exact
manner, and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
The quantities of oil and natural gas that are ultimately recovered, production
and operating costs, the amount and timing of future development expenditures
and future oil and natural gas sales prices may all differ from those assumed in
these estimates. Therefore, the Present Value of Future Net Revenue figures
shown above should not be construed as the current market value of the estimated
oil and natural gas reserves attributable to the Company's properties. The
information set forth in the foregoing table includes revisions of certain
volumetric reserve estimates attributable to proved properties included in the
preceding year's estimates. Such revisions are the result of additional
information from subsequent completions and production history from the
properties involved or the result of a decrease (or increase) in the projected
economic life of such properties resulting from changes in product prices.
The Company's future success depends upon its ability to find, develop or
acquire additional oil and gas reserves that are economically recoverable. The
proved reserves of the Company will generally decline as reserves are depleted,
except to the extent that the Company conducts successful exploration or
development activities or acquires properties containing proved reserves, or
both. In order to increase reserves and production, the Company must continue
its development and exploration drilling and recompletion programs or undertake
other replacement activities. The Company's current strategy includes increasing
its reserve base through acquisitions of producing properties and by continuing
to exploit its existing properties. There can be no assurance, however, that the
Company's planned development and exploration projects and acquisition
activities will result in significant additional reserves or that the Company
will have continuing success drilling productive wells at low finding and
11
<PAGE>
development costs. Furthermore, while the Company's revenues may increase if
prevailing oil and gas prices increase significantly, the Company's finding
costs for additional reserves could also increase.
In accordance with the Commission's guidelines, the engineers' estimates of
future net revenues from the Company's properties and the Present Value of
Future Net Revenue thereof are made using oil and natural gas sales prices in
effect as of the date of such estimates and are held constant throughout the
life of the properties except where such guidelines permit alternate treatment,
including the use of fixed and determinable contractual price escalations. The
average prices as of December 31, 1996, for the Company's properties were $25.52
per Bbl of crude oil and $4.17 per Mcf of natural gas. The foregoing prices
exclude the effect of net price hedging positions. Prices for natural gas and,
to a lesser extent, oil are subject to substantial seasonal fluctuations and
prices for each are subject to substantial fluctuations as a result of numerous
other factors. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and "Business--Oil and Gas Marketing and Major
Customers."
PRODUCTIVE WELLS AND ACREAGE
Productive Wells
The following table sets forth the Company's existing productive wells as
of December 31, 1996:
<TABLE>
<CAPTION>
GROSS NET
----- ---
<S> <C> <C>
Oil 481 458
Gas 78 61
--- ---
Total Productive Wells 559 519
=== ===
</TABLE>
Productive wells consist of producing wells and wells capable of
production, including gas wells awaiting pipeline connections. Wells that are
completed in more than one producing horizon are counted as one well. Of the
gross wells reported above, 49 had multiple completions.
Acreage Data
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether or not such acreage contains
proved reserves. A gross acre is an acre in which an interest is owned. A net
acre is deemed to exist when the sum of fractional ownership interests in gross
acres equals one. The number of net acres is the sum of the fractional
interests owned in gross acres expressed as whole numbers and fractions thereof.
The following table sets forth the approximate developed and undeveloped acreage
in which the Company held a leasehold mineral or other interest at December 31,
1996.
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
--------------- -----------------
GROSS NET GROSS NET
------- ------ -------- -------
<S> <C> <C> <C> <C>
Federal waters 92,203 53,758 4,994 4,994
State waters and onshore 44,272 38,747 55,861 45,125
------- ------ ------ ------
Total 136,475 92,505 60,855 50,119
======= ====== ====== ======
</TABLE>
In January 1997, the Company exercised lease options in Cameron Parish,
Louisiana, which increased gross undeveloped acreage by 12,695 acres and net
undeveloped acreage by 6,348 acres. In addition, the Company currently holds
options covering approximately 28,893 gross acres (21,254 net) in Cameron
Parish, Louisiana, and 16,727 gross and net acres in Plaquemines Parish,
Louisiana, which allow the Company to conduct 3-D seismic operations on such
acreage and to subsequently acquire oil and gas leases.
12
<PAGE>
DRILLING ACTIVITIES
Drilling activities are subject to many risks, including the risk that no
commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that the
Company will recover all or any portion of its investment. Drilling for oil and
natural gas may involve unprofitable efforts, not only from dry wells, but from
wells that are productive but do not produce sufficient net revenues to return a
profit after drilling, operating, and other costs. The cost of drilling,
completing and operating wells is often uncertain. The Company's drilling
operations may be curtailed, delayed or canceled as a result of numerous
factors, many of which are beyond the Company's control, including title
problems, weather conditions, compliance with governmental requirements and
shortages or delays in the delivery of equipment and services.
The following table sets forth the drilling activity of the Company on its
properties for the years ended December 31, 1994, 1995 and 1996.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1994 1995 1996
------------ ---------- -----------
GROSS NET GROSS NET GROSS NET
----- ----- ----- --- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Productive 1 .88 1 1 6 5.5
Nonproductive 1 .88 3 2 6 4.6
Development Wells:
Productive 10 8.75 17 17 24 23.7
Nonproductive 1 .43 0 0 1 1
-- ----- -- -- -- ----
Total 13 10.94 21 20 37 34.8
== ===== == == == ====
</TABLE>
NET PRODUCTION, UNIT PRICES AND COSTS
The following table presents certain information with respect to oil and
gas production and lease operating expenses attributable to all oil and gas
property interests owned by the Company for the years ended December 31, 1994,
1995 and 1996.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------
1994 1995 1996
------- ------- -------
<S> <C> <C> <C>
Production:
Oil (MBbls) 4,286 6,057 7,149
Gas (MMcf) 7,234 12,393 18,720
MBOE 5,492 8,123 10,269
Average Sales Prices(1):
Oil (per Bbl) $14.24 $ 17.39 $ 21.58
Gas (per Mcf) 1.76 1.82 2.79
Per BOE 13.42 15.75 20.10
Average lease operating
expenses (per BOE) $ 4.29 $ 3.70 $ 3.52
</TABLE>
(1) Excludes results of hedging activities. Including the effect of hedging
activities, the Company's average oil price per Bbl received was $14.56,
$17.27 and $19.70 in the years ended December 31, 1994, 1995 and 1996,
respectively, and the average gas price per Mcf received was $1.81, $1.84
and $2.50 in the years ended December 31, 1994, 1995 and 1996,
respectively.
OTHER FACILITIES
The Company currently leases approximately 8,600 square feet of office
space in Baton Rouge, Louisiana, where its administrative offices are located,
and approximately 42,400 square feet of office space in Lafayette,
13
<PAGE>
Louisiana and approximately 1,150 square feet of office space in New Orleans,
Louisiana, where the Company's technical personnel are collectively located.
The Company also leases dock and warehouse space in Venice, Louisiana and
Morgan City, Louisiana.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and gas
industry. The Company's properties are subject to customary royalty interests,
liens incident to operating agreements, liens for current taxes and other
burdens which the Company believes do not materially interfere with the use of
or affect the value of such properties. The Company's Revolving Credit Facility
is secured by substantially all of the Company's oil and gas properties. The
MMS and Louisiana State Mineral Board must approve all transfers of record title
or operating rights on its respective leases. The MMS and Louisiana State
Mineral Board approval process can in some cases delay the requested transfer
for a significant period of time.
ITEM 3: LEGAL PROCEEDINGS
The Company is not a party to any material pending legal proceedings, other
than ordinary routine litigation incidental to its business that management
believes would not have a material adverse effect on its financial condition or
results of operations.
ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 4(A): EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information concerning the executive
officers of the Company:
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- --------
<S> <C> <C>
James C. Flores 37 Chairman of the Board of Directors and Chief Executive Officer
Richard G. Zepernick, Jr. 36 Executive Vice President, Chief Operating Officer and Director
Robert L. Belk 47 Senior Vice President, Chief Financial Officer Treasurer and Director
Robert K. Reeves 39 Senior Vice President, General Counsel and Secretary
David J. Morgan 49 Senior Vice President--Geology
Michael O. Aldridge 38 Vice President--Corporate Communications
William S. Flores, Jr. 40 Vice President--Operations
Doss R. Bourgeois 39 Vice President--Production
Clint P. Credeur 40 Vice President--Reservoir Engineering
</TABLE>
The following biographies describe the business experience of the executive
officers of the Company.
James C. Flores has served as Chairman of the Board of the Company since
its inception in 1992 and as Chief Executive Officer since July 1995. From 1985
to 1992, Mr. Flores served as Vice President of FloRuxco, Inc., an oil and gas
exploration company.
Richard G. Zepernick, Jr. has been with the Company since its inception,
presently serving as Executive Vice President and Chief Operating Officer. Mr.
Zepernick became a director of the Company in September 1994. From June 1992
until May 1993, Mr. Zepernick served as Senior Vice President and Secretary of
Flores & Rucks, Inc. From 1985 to 1992, Mr. Zepernick served as General Manager
of FloRuxco, Inc.
14
<PAGE>
Robert L Belk has served as Senior Vice President, Chief Financial Officer
and Treasurer of the Company since 1993. Mr. Belk became a director of the
Company in September 1994. Prior to joining the Company, Mr. Belk worked in
public accounting for H.J. Lowe & Company from 1988 to 1993. Mr. Belk is a
Certified Public Accountant.
Robert K. Reeves has served as Senior Vice President, General Counsel and
Secretary of the Company since May 1994. From November 1993 to May 1994, Mr.
Reeves served as the Company's Vice President and General Counsel. Prior to
joining the Company in 1993, he was a partner in the law firm of Onebane,
Bernard, Torian, Diaz, McNamara & Abell in Lafayette, Louisiana.
David J. Morgan joined the Company in 1993 as Vice President -- Geology and
became a Senior Vice President in December 1995. Mr. Morgan has 27 years of
experience in the oil and gas industry. From 1983 to 1993, Mr. Morgan served as
a geologist for and President of Morgan Resources, LTD., an oil and gas
exploration company.
Michael O. Aldridge joined the Company in 1992 as Vice President and
Controller, and became Vice President--Corporate Communications in September
1996. From 1991 until 1992, he was Vice President and Chief Financial Officer
of Fleet Petroleum Partners. Mr. Aldridge is a Certified Public Accountant.
William S. Flores, Jr. joined the Company in 1993 as its Vice President --
Operations. Mr. Flores worked from 1988 to 1993 at CNG Producing Co. where he
served as a Senior Operations Engineer.
Doss R. Bourgeois has served as Vice President -- Production of the Company
since August 1993. From 1982 to 1993 Mr. Bourgeois worked for CNG Producing Co.
until he joined the Company. His positions at CNG Producing Co. included
Production Engineer, Manager Offshore Production, Supervisor Drilling
Engineering, and finally Workovers & Completion/Workover Superintendent.
Clint P. Credeur has served the Company as Vice President -- Reservoir
Engineering since 1993. Mr. Credeur served as a Reservoir Engineer and Special
Projects Engineer with Chevron U.S.A. from November 1987 to December 1992.
James C. Flores and William S. Flores, Jr. are brothers; there are no other
family relationships between any of the executive officers of the Company.
15
<PAGE>
PART II
ITEM 5: MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Since March 25, 1996, the Company's Common Stock has traded on the NYSE
under the symbol "FNR". The following table presents the quarterly high and low
sales prices for the Common Stock on the NYSE since March 25, 1996 and, during
the prior periods indicated, the high and low bid quotations in the over-the-
counter market as quoted by the Nasdaq National Market since the shares became
publicly traded (which quotations reflect the inter-dealer prices, without
retail mark-up, mark-down or commission and may not necessarily represent actual
transactions).
<TABLE>
<CAPTION>
HIGH LOW
------ ------
<S> <C> <C>
1995
First Quarter 12 3/8 9 1/4
Second Quarter 13 3/4 11 1/4
Third Quarter 12 3/4 10 1/2
Fourth Quarter 15 1/4 11 1/4
1996
First Quarter 18 3/4 13 1/2
Second Quarter 36 3/8 17 7/8
Third Quarter 41 1/2 28 3/4
Fourth Quarter 54 3/8 38 3/8
</TABLE>
As of March 21, 1997 there were approximately 153 holders of record of the
Common Stock.
The Company does not anticipate paying cash dividends on its Common Stock
in the foreseeable future. The Company expects that it will retain all
available earnings generated by the Company's operations for the development and
growth of its business. Any future determination as to the payment of dividends
will be made at the discretion of t he Board of Directors of the Company and
will depend upon the Company's operating results, financial condition, capital
requirements, general business conditions and such other factors as the Board of
Directors deems relevant. The Company's debt instruments include certain
restrictions on the payment of cash dividends on the Common Stock. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources."
16
<PAGE>
ITEM 6: SELECTED FINANCIAL DATA
The selected financial data set forth below for the years ended
December 31, 1992, 1993, 1994, 1995 and 1996 for the Company are derived from
the audited financial statements. The selected historical financial data are
qualified in their entirety by, and should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the financial statements and the notes thereto included
elsewhere in this Form 10-K. For additional information relating to the
Company's operations, see "Business" and "Properties."
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1992 1993 1994 1995 1996
--------- -------------- ---------- --------- --------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS AND
OTHER FINANCIAL AND OPERATING DATA:
REVENUE & EXPENSE DATA:
Revenues:
Flores & Rucks, Inc. (1) $ 13,279 $ 47,483 $ 75,395 $127,970 $188,451
Combined acquisitions (2) 95,018 38,197 8,707 - -
Direct Operating Expenses:
Flores & Rucks, Inc. (1) 6,687 19,201 30,324 40,047 47,098
Combined acquisitions (2) 40,155 13,779 4,089 - -
General & Administrative Expenses 385 5,032 10,351 11,312 16,154
Depreciation, Depletion & Amortization 3,420 20,140 36,459 54,084 74,652
Interest Expense 241 1,055 4,507 17,620 17,954
Loss on Production Payment Repurchase
and Refinancing(3) - - 16,681 - -
Net Income (Loss) Before Income Tax
Benefit 2,584 2,227 (22,179) 5,210 32,988
Income Tax Expense (Benefit)(4) - - - (4,692) 12,037
Net Income (Loss) 2,584 2,227 (22,179) 9,902 20,951
Earnings (Loss) per Common Share(5)
Primary - - - $ 0.65 $ 1.07
Fully diluted - - - 0.65 1.05
OTHER FINANCIAL DATA:
EBITDA(6) $ 6,245 $ 23,422 $ 35,855 $ 77,645 $129,100
Net Cash Provided By (Used In)
Operating Activities(7) 38,042 103,112 (115,485) 58,880 125,989
Capital Expenditures(8) 34,978 123,600 74,477 73,652 251,305
OPERATING DATA:
Sales Volumes:
Oil (MBbls) 670 2,850 4,286 6,057 7,149
Gas (MMcf) 1,484 3,704 7,234 12,393 18,720
MBOE 917 3,467 5,492 8,123 10,269
Average Prices (9):
Oil (per Bbl) $ 16.18 $ 13.82 $ 14.24 $ 17.39 $ 21.58
Gas (per MCF) 1.64 1.81 1.76 1.82 2.79
BOE (per BOE) 14.48 13.30 13.42 15.75 20.10
Lease Operating Expenses (per BOE) $ 5.45 $ 4.10 $ 4.29 $ 3.70 $ 3.52
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
1992 1993 1994 1995 1996
--------- -------------- ---------- --------- --------
(IN THOUSANDS)
BALANCE SHEET DATA:
Oil and Gas Assets, Net $30,998 $122,374 $160,311 $ 179,944 $355,698
Total Assets 36,837 131,613 181,344 215,457 460,710
Long-Term Debt - 13,448 154,039 171,692 284,142
Deferred Revenue on
Production Payments(10) 32,347 108,784 - - -
Stockholders' Equity 349 (825) 9,703 19,976 105,153
</TABLE>
17
<PAGE>
- --------
(1) Historical 1992 Company data is presented for the period from the date of
formation of the Company on April 20, 1992 through December 31, 1992.
Historical company data reflect the acquisitions of Main Pass 69 on June
11, 1992, the East Bay Complex on June 10, 1993, and a 12.5% minority
interest thereon on December 7, 1994.
(2) Represents combined revenues and direct operating expenses for (i) all of
Shell's interest in Main Pass 69 and the East Bay Complex until the
acquisition by the Company of 87.5% of such interests on June 11, 1992 and
June 10, 1993, respectively and (ii) the 12.5% ownership of Main Pass 69
and the East Bay Complex acquired by Franks Petroleum, Inc. on June 11,
1992 and June 10, 1993, respectively, until acquired by the Company on
December 7, 1994.
(3) The amount shown for the year ended December 31, 1994 represents primarily
the excess of the purchase price of the Production Payments over the book
value of the Production Payments (as defined herein) liability as of
December 7, 1994.
(4) The Company was formed as an S corporation under the Internal Revenue Code
and, as such, all income taxes were the obligation of the Company's
stockholders. Therefore, through the date of the Initial Offerings (as
defined herein), no historical federal or state income tax expense has been
provided for in the financial statements. In conjunction with the Initial
Offerings, the Company converted to a C corporation under the Internal
Revenue Code. The Company recorded a deferred tax asset of $6.3 million,
offset by a valuation allowance of $6.3 million at December 31, 1994 and a
deferred tax asset of $4.7 million at December 31, 1995. As a result of
the reversal of the valuation allowance, the Company recorded a net income
tax benefit of $4.7 million in the year ended December 31, 1995.
(5) If the Company had recognized a tax provision at statutory rates for the
year ended December 31, 1995, rather than an income tax benefit, earnings
per common share would have been $0.22 for such period. Earnings per share
has not been presented for periods prior to or including the date of the
Initial Offerings, as these amounts would not be meaningful or indicative
of the ongoing entity.
(6) Earnings before interest, taxes, depreciation, depletion and amortization.
EBITDA has not been reduced for the recognition of noncash revenues
associated with the Production Payments. EBITDA is not intended to
represent cash flow in accordance with generally accepted accounting
principles and does not represent the measure of cash available for
distribution. EBITDA is not intended as an alternative to earnings from
continuing operations or net income.
(7) Cash flow from operating activities in 1992 and 1993 includes $36.8 million
and $95.7 million, respectively, from the sale of the Production Payments.
Cash flow from operating activities for the year ended December 31, 1994
was reduced by $123.6 million related to the repurchase of the Production
Payments.
(8) Includes $34.3 million in the year ended December 31, 1992 related to the
acquisition of Main Pass 69, $115.5 million in the year ended December 31,
1993 related to the acquisition of the East Bay Complex and $117.6 million
in the year ended December 31, 1996 related to the acquisition of the
Central Gulf Properties.
(9) Excludes results of hedging activities which increased (decreased) revenue
recognized in the 1993, 1994, 1995 and 1996 periods by $1.2 million, $1.7
million, $(0.5) million and $(18.7) million, respectively. Including the
effect of hedging activities, the Company's average oil price per Bbl
received was $14.23, $14.56, $17.27 and $19.70 in the years ended December
31, 1993, 1994, 1995 and 1996, respectively, and the average gas price per
Mcf received was $1.81, $1.84 and $2.50 in the years ended December 31,
1994, 1995 and 1996, respectively. The Company did not enter into any
hedging activities relating to oil during 1992 or relating to gas during
1992 and 1993.
(10) Amounts represent deferred revenues recognized from the sale of the
Production Payments. See Note 4 to the consolidated financial statements
of the Company.
18
<PAGE>
ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is a discussion and analysis of the Company's financial
condition and results of operations and should be read in conjunction with the
Company's consolidated financial statements and the notes thereto included
elsewhere in or incorporated by reference into this Form 10-K.
GENERAL
The Company is an independent energy company engaged in the exploration,
development, acquisition and production of crude oil and natural gas with
operations focused primarily on the Louisiana Gulf, one of the most prolific oil
and gas producing regions in the United States. As of December 31, 1996, the
Company had estimated proved reserves of approximately 50.8 MMBbls of oil and
145.4 Bcf of natural gas, or an aggregate of approximately 75.0 MMBOE, with a
Present Value of Future Net Revenues of approximately $693.5 million and a
Standardized Measure of Discounted Future Net Cash Flows of approximately $532.5
million. On a BOE basis, approximately 68% of the Company's proved reserves on
such date were oil. The majority of the Company's existing proved reserves are
attributable to Company operated wells or leases and approximately 75% of these
reserves were classified as proved developed at December 31, 1996.
The Company is a Delaware corporation formed in September 1994 to acquire
and own 100% of the outstanding Common Stock of FRI Louisiana. FRI Louisiana was
formed in April 1992 to take advantage of opportunities to acquire and develop
certain offshore properties in the Louisiana Gulf.
The Company's major acquisitions to date include the acquisition from Shell
of its interest in Main Pass 69 in June 1992 and its interest in the East Bay
Complex in June 1993. In September 1996, the Company acquired the Central Gulf
Properties from Mobil. The above acquisitions coupled with the Company's
successful exploration and exploitation efforts on the acquired properties have
resulted in substantial increases in production and reserve growth. The Company
manages its field costs by combining administrative functions relating to its
properties, controlling the number of operating personnel and providing
incentive compensation. Close management of operating costs combined with the
increased production mentioned above have resulted in a 5% decrease to the
Company's lease operating expense per BOE to $3.52 per BOE in the year ended
December 31, 1996 from $3.70 per BOE in the comparable 1995 period.
In December 1994, the Company closed the initial public offerings (the
"Initial Offerings") of 5,790,000 shares of common stock ("Common Stock") at $10
per share and $125,000,000 of 13 1/2% Senior Notes due December 1, 2004 (the
"Senior Notes") and entered into the $50 million borrowing based senior
revolving bank credit facility (the "Revolving Credit Facility"). In
conjunction with the Initial Offerings, the Company (i) acquired 100% of the
outstanding common stock of FRI Louisiana from James C. Flores, trusts for the
benefit of his children and William W. Rucks, IV in exchange for a total of
8,248,000 shares of Common Stock, (ii) repurchased certain nonrecourse
volumetric production payment interests (the "Production Payments"), (iii)
purchased additional interests in its existing properties and (iv) repaid debt
owed by the Company.
In March 1996, the Company completed a public offering of 4,500,000 shares
of common stock at a price of $14.75 per share (the "Common Stock Offering").
Net proceeds to the Company from the Common Stock Offering were approximately
$62.2 million, which was used primarily to repay outstanding indebtedness. In
September 1996, the Company completed an offering of $160,000,000 of 9 3/4%
Senior Subordinated Notes due October 1, 2006 (the "Senior Subordinated Notes")
at a discount for proceeds of $159,120,000 (before offering costs). Net
proceeds to the Company were approximately $154.0 million, which was used
primarily to complete the acquisition of the Central Gulf Properties and to
repay outstanding indebtedness.
19
<PAGE>
The following table reflects certain information with respect to the
Company's oil and gas properties. Sales volumes, revenues and average sales
prices presented below have been segregated into those subject to Production
Payments and amounts in excess of Production Payments in the applicable periods.
On December 7, 1994, the Company purchased an outstanding 12 1/2% minority
interest in Main Pass 69 and the East Bay Fields (the "Minority Interest"). The
amounts for the year ended December 31, 1994 do not reflect the Minority
Interest prior to its acquisition.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1994 1995 1996
------- -------- --------
(IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<S> <C> <C> <C>
SALES VOLUMES
Oil (MBbls)
Excess over Production Payments 2,771 6,057 7,149
Production Payments 1,515 - -
------- -------- --------
Total Oil Volumes 4,286 6,057 7,149
======= ======== ========
Gas (MMcf)
Excess over Production Payments 3,456 12,393 18,720
Production Payments 3,778 - -
------- -------- --------
Total Gas Volumes 7,234 12,393 18,720
======= ======== ========
REVENUES (1)
Oil
Excess over Production Payments $43,106(2) $105,360 $154,284
Production Payments 17,906 - -
------- -------- --------
Total Oil Revenues $61,012 $105,360 $154,284
======= ======== ========
Gas
Excess over Production Payments $ 6,757 $ 22,581 $ 52,175
Production Payments 5,951 - -
------- -------- --------
Total Gas Revenues $12,708 $ 22,581 $ 52,175
======= ======== ========
AVERAGE SALES PRICES (1)
Oil (per Bbl)
Excess over Production Payments $ 15.56(2) $ 17.39 $ 21.58
Production Payments 11.82 - -
Net average oil price 14.24 17.39 21.58
Gas (per Mcf)
Excess over Production Payments $ 1.96 $ 1.82 $ 2.79
Production Payments 1.58 - -
Net average gas price 1.76 1.82 2.79
BOE (per BOE)
Excess over Production Payments $ 14.90 $ 15.75 $ 20.10
Production Payments 11.12 - -
Net average price 13.42 15.75 20.10
Severance Taxes (3) $ 6,747 $ 10,023 $ 10,906
Lease Operating Expenses (3) $23,577 $ 30,023 $ 36,192
Lease Operating Expenses (per BOE) $ 4.29 $ 3.70 $ 3.52
- ----------
</TABLE>
(1) Excludes results of hedging activities which increased (decreased) revenue
recognized in the 1994, 1995 and 1996 periods by $1.7 million, $(0.5)
million and $(18.7) million, respectively. Including the effect of hedging
activities, the Company's average oil price received was $14.56, $17.27 and
$19.70 in the years ended December 31, 1994, 1995 and 1996, respectively,
and the average gas price received was $1.81, $1.84 and $2.50 in the years
ended December 31 1994, 1995 and 1996, respectively.
(2) Includes Main Pass 69 sales of 800 MBbls for the year ended December 31,
1994, subject to a long-term contract at prices averaging $1.29 per Bbl for
the eleven months ended November 30, 1994. The long-term contract was
terminated in connection with the Initial Offerings. See "Business--Oil and
Gas Marketing and Major Customers."
20
<PAGE>
(3) Volumes delivered under Production Payments were received by Enron Reserve
Acquisition Corp. free and clear of severance taxes and lease operating
expenses. These costs were borne in full by the Company under the terms of
the Production Payments.
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1995 AND 1996
Revenues. The following table reflects an analysis of differences in
the Company's oil and gas revenues (expressed in thousands of dollars) between
the year ended December 31, 1996, and the comparable 1995 period:
<TABLE>
<CAPTION>
YEAR ENDED 1996
COMPARED TO
YEAR ENDED 1995
----------------
<S> <C>
Increase (decrease) in oil and gas revenues
resulting from differences in:
Crude oil and condensate --
Price $ 29,929
Production 18,995
--------
48,924
Natural gas --
Price 18,067
Production 11,527
--------
29,594
--------
Hedging and other, net (18,037)
--------
Increase in oil and gas revenues $ 60,481
========
</TABLE>
The Company's total revenues increased approximately $60.5 million, or 47%,
to $188.5 million for the year ended December 31, 1996, from $128.0 million for
the comparable period in 1995. Production levels for the year ended December
31, 1996, increased 26% to 10,269 MBOE from 8,123 MBOE for the comparable period
in 1995. The Company's average sales prices (excluding hedging activities) for
oil and natural gas for the year ended December 31, 1996 were $21.58 per Bbl and
$2.79 per Mcf versus $17.39 per Bbl and $1.82 per Mcf in the prior period.
Revenues increased by $48.0 million due to the aforementioned production
increases and by $30.5 million as a result of increased oil and gas prices.
For the year ended December 31, 1996, the Company recognized additional
production of 680 MBOE and related revenues of $14.8 million associated with the
acquisition of the Central Gulf Properties.
For the year ended December 31, 1996, the Company's total revenues were
further affected by a $18.2 million decrease in hedging revenues. In order to
manage its exposure to price risks in the sale of its crude oil and natural gas,
the Company from time to time enters into price hedging arrangements. See "--
Other Matters - Energy Swap Agreements." The Company's average sales prices
(including hedging activities) for oil and natural gas for the year ended
December 31, 1996, were $19.70 per Bbl and $2.50 per Mcf versus $17.27 per Bbl
and $1.84 per Mcf in the prior period.
Lease operating expenses. Lease operating expenses decreased to $3.52 per
BOE for the year ended December 31, 1996, from $3.70 per BOE in the comparable
1995 period. This decrease is primarily the result of increased production in
the Company's oil and gas fields, which have substantial fixed operating costs
due to the capital intensive nature of the facilities and the underutilization
of capacity. For the year ended December 31, 1996, total lease operating
expenses were $36.2 million, as compared to $30.0 million in the 1995 period.
This increase primarily results from fluctuations in normal operating expenses,
including operating expenses associated with increased production and an
increase of approximately $2.8 million relating to lease operating expenses of
the newly acquired Central Gulf Properties. In addition, workover expenses for
the year ended December 31, 1996, increased by $1.1 million to $2.5 million, as
compared to $1.4 million in the comparable 1995 period.
Severance taxes. The effective severance tax rate as a percentage of oil
and gas revenues (excluding the effect of hedging activities) decreased to 5.3%
in the year ended December 31, 1996, from 7.8% in the comparable 1995 period.
The decrease was primarily due to increased production from new wells on federal
leases, including wells located on the Central Gulf Properties, and from state
leases which were exempt from state severance tax under Louisiana's severance
tax abatement program.
21
<PAGE>
General and administrative expenses. For the year ended December 31, 1996,
general and administrative expenses were $16.2 million as compared to $11.3
million in the comparable 1995 period. This increase is primarily due to costs
of increased corporate staffing associated with both an increase in drilling
activities and the Company's acquisition of the Central Gulf Properties,
partially offset in the 1996 period by an increase in the capitalization of a
portion of the salaries paid to employees directly engaged in the acquisition,
exploration and development of oil and gas properties. In addition, the Company
expensed $.9 million relating to costs associated with efforts to purchase an
oil and gas property outside of its United States cost center.
Depreciation, depletion, and amortization expense. For the year ended
December 31, 1996, depreciation, depletion and amortization ("DD&A") expense was
$74.7 million as compared to $54.1 million in the comparable 1995 period. On a
BOE basis, DD&A for the year ended December 31, 1996, was $7.27 per BOE as
compared to $6.66 per BOE for the year ended December 31, 1995. This variance
can primarily be attributed to the Company's increased production and related
current and future capital costs from the 1995 and 1996 drilling programs and
the Company's purchase of the Central Gulf Properties, partially offset by the
increase to proved reserves resulting from the programs and the acquisition.
Interest expense. For the year ended December 31, 1996, interest expense
increased approximately $0.4 million to $18.0 million, from $17.6 million in the
comparable 1995 period. This increase is primarily a result of interest expense
of approximately $4.1 million related to the issuance of the Senior Subordinated
Notes in September 1996. The increase was partially offset by the repayment of
a portion of the Company's debt with proceeds from the Common Stock Offering and
the issuance of the Senior Subordinated Notes. The increase was also partially
offset by increases in the amount of interest capitalized in the 1996 period, as
a result of an increase in the Company's unevaluated assets, including
additional acreage and seismic data.
Income tax expense (benefit). For the year ended December 31, 1996, the
Company recorded income tax expense of $12.0 million, as compared to a $4.7
million benefit in the comparable 1995 period during which the Company realized
a deferred tax asset.
Net income. Due to the factors described above, net income for the year
ended December 31, 1996, increased to $21.0 million, an increase of $11.1
million or 112% from net income of $9.9 million for the comparable 1995 period.
22
<PAGE>
RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1995
Revenues. The following table reflects an analysis of differences in the
Company's oil and gas revenues (expressed in thousands of dollars) between the
year ended December 31, 1995, and the comparable 1994 period:
<TABLE>
<CAPTION>
YEAR ENDED 1995
COMPARED TO
YEAR ENDED 1994
----------------
<S> <C>
Increase (decrease) in oil and gas revenues resulting
from differences in:
Crude oil and condensate--
Price $19,143
Production 25,205
-------
44,348
Natural Gas--
Price 811
Production 9,062
-------
9,873
-------
Hedging and other, net (1,646)
-------
Increase in oil and gas revenues $52,575
=======
</TABLE>
For the year ended December 31, 1995, the Company's total revenues
increased approximately $52.6 million, or 70%, to $128.0 million from $75.4
million for the comparable period in 1994. Production levels for the year ended
December 31, 1995, increased 48% to 8,123 MBOE from 5,492 MBOE for the
comparable period in 1994. The Company's average sales prices (excluding
hedging activities) for oil and natural gas for the year ended December 31, 1995
were $17.39 per Bbl and $1.82 per Mcf, respectively, versus $14.24 per Bbl and
$1.76 per Mcf, respectively, in the comparable 1994 period. Oil and natural gas
volumes sold pursuant to Production Payment obligations represented
approximately 35% and 52% of total sales volumes, respectively, for the year
ended December 31, 1994. As a result of the repurchase of the Production
Payments on December 7, 1994, the Company was able to sell all of its production
at market prices in 1995 as compared to previously selling a portion of its
production subject to the Production Payments at implicit contractual prices per
BOE substantially below then current market prices.
For the year ended December 31, 1995, the Company recognized additional
production of 950 MBOE and related revenues of $15.0 million associated with the
Minority Interest purchased December 7, 1994. Of the $15.0 million, $12.4
million was primarily related to production associated with the purchased
Minority Interest with the remaining $2.6 million primarily related to increased
oil prices for the 1995 period.
For the year ended December 31, 1995, the Company's total revenues were
further affected by a $2.2 million decrease in hedging revenues. In order to
manage its exposure to price risks in the sale of its crude oil and natural gas,
the Company from time to time enters into price hedging arrangements. See "--
Other Matters--Energy Swap Agreements." The Company's average sales prices
(including hedging activities) for oil and natural gas for the year ended
December 31, 1995, were $17.27 per Bbl and $1.84 per Mcf versus $14.56 per Bbl
and $1.81 per Mcf in the prior period.
Lease operating expenses. On a BOE basis, lease operating expenses
decreased 14% in the year ended December 31, 1995, to $3.70 per BOE from $4.29
per BOE in the comparable period of 1994. This decrease was primarily the
result of increased production at Main Pass 69 and the East Bay Fields, which
have substantial fixed operating costs due to the capital intensive nature of
the facilities and the underutilization of capacity. Total lease operating
expenses for the year ended December 31, 1995 were $30.0 million, as compared to
$23.6 million for the comparable 1994 period. The increase was primarily
related to the Company's operating expenses associated with increased
production, the purchase of the Minority Interest in December 1994, an increase
in painting and other preventive maintenance type programs which the Company
believed to be cost effective, and increased workover costs in the 1995 period.
Workover expenses increased to $1.4 million for the year ended December 31,
1995, as compared to $0.9 million for the comparable 1994 period.
23
<PAGE>
Severance taxes. The effective severance tax rate as a percentage of
revenues decreased to 7.8% in the year ended December 31, 1995, from 8.9% in the
comparable period of 1994. This decrease was primarily due to increased
production from new wells on federal leases and from state leases which were
exempt from state severance tax under Louisiana's severance tax abatement
program.
General and administrative expenses. General and administrative expenses
per BOE decreased 26% to $1.39 per BOE in the year ended December 31, 1995 from
$1.88 per BOE in the comparable period of 1994. In the year ended December 31,
1995, general and administrative expenses were $11.3 million, as compared to
$10.4 million in the comparable 1994 period. The increase in general and
administrative expenses was primarily due to increased corporate staffing, an
increase in director and officer insurance premiums, an increase in franchise
taxes and in incentive compensation. These increases were partially offset by
the nonrecurring $0.9 million release and indemnity expenses incurred by the
Company in the year ended December 31, 1994, a decrease in legal and other
professional fees during 1995 and an increase in the capitalization of the
salaries paid to employees directly engaged in the acquisition, exploration and
development of oil and gas properties during 1995.
Depreciation, depletion, and amortization expense. For the year ended
December 31, 1995, DD&A per BOE remained relatively unchanged at $6.66 as
compared to $6.64 in the 1994 period. Total DD&A expense for the 1995 period
was $54.1 million, as compared to $36.5 million for the comparable 1994 period.
This variance was primarily related to the Company's increased production and
related capital costs from the 1994 and 1995 drilling programs, as well as the
increase in proved reserves. Also contributing to increased DD&A expense was
the December 1994 acquisition of the Minority Interest.
Interest expense. Interest expense for the year ended December 31, 1995
was $17.6 million, an increase of approximately $13.1 million from $4.5 million
for the comparable 1994 period. This increase was due primarily to interest
expense relating to the Senior Notes and the Revolving Credit Facility. This
increase was partially offset by interest that was capitalized during the year
ended December 31, 1995, of $2.8 million, as compared to $0.1 million in the
1994 period.
Income tax expense (benefit). The Company was originally formed as an S
corporation under the Internal Revenue Code and, as such, all income taxes were
the obligation of the Company's stockholders. In conjunction with the Initial
Offerings, the Company converted to a C corporation under the Internal Revenue
Code. Due to a valuation allowance, the Company did not record a tax benefit
for the year ended December 31, 1994. During 1995, due to drilling successes
and increases in realized prices, the Company generated income from operations.
At December 31, 1995, management believed it was more likely than not that the
deferred tax asset would be realized. As a result, in 1995 the Company reversed
the valuation allowance and recognized a tax benefit of $4.7 million.
Net income. Due to the factors described above, net income increased
approximately $32.1 million from a net loss of $22.2 million for the year ended
December 31, 1994 to net income of $9.9 million for the year ended
December 31, 1995. For the year ended December 31, 1995, net income before the
income tax benefit was $5.2 million.
24
<PAGE>
LIQUIDITY AND CAPITAL RESOURCES
The following summary table reflects comparative cash flows for the Company
for the years ended December 31, 1994, 1995 and 1996:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1994 1995 1996
---------- --------- ----------
(IN THOUSANDS)
<S> <C> <C> <C>
Net cash provided by (used in) operating activities (1) $(115,485) $ 58,880 $ 125,989
Net cash used in investing activities (46,607) (77,699) (293,132)
Net cash provided by financing activities 162,462 18,463 172,689
</TABLE>
- ----------
(1) Cash flow from operating activities for the year ended December 31, 1994
was reduced by $123.6 million related to the repurchase of the Production
Payments.
For the year ended December 31, 1996, net cash provided by operating
activities increased by $67.1 million. This increase related primarily to an
increase in revenues, partially offset by increases in lease operating expenses,
severance taxes and general and administrative expenses. In addition, excluding
non cash items, the Company's net working capital decreased by $14.4 million due
primarily to (i) an increase in accounts payable primarily resulting from a more
aggressive drilling program in 1996 as compared to 1995, and (ii) a $3.7 million
deposit on assets held for resale by the Company. Net working capital was
increased by increased oil and gas sales receivables due to higher prices and
production during December of 1996 as compared to December of 1995.
Cash used in investing activities during the year ended December 31, 1996,
increased to $293.1 million as compared to $77.7 million in the comparable 1995
period, reflecting the purchase of the Central Gulf Properties for approximately
$117.6 million during 1996 and a more aggressive 1996 drilling program.
Financing activities during the year ended December 31, 1996, generated
cash of $172.7 million, as compared to $18.5 million in the comparable 1995
period. The increase in cash during the 1996 period was primarily a result of
the Common Stock Offering and the issuance of the Senior Subordinated Notes,
which yielded net proceeds to the Company of $62.2 million and $154.0 million,
respectively. This increase in cash was partially offset by the repayment of
(i) a $13.0 million note to Shell Offshore, Inc. and (ii) a $32.2 million
outstanding balance under the Company's Revolving Credit Facility, which is
discussed below under "--Liquidity".
Capital requirements. The Company's capital investments to date have
focused primarily on exploration, acquisitions and development of proved
properties. The Company's expenditures for property acquisition, exploration and
development for the years ended December 31, 1994, 1995 and 1996 are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1994 1995 1996
------- ------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Property acquisition costs of evaluated properties $25,442 $ 624 $ 59,419
Property acquisition costs of unevaluated properties 14,736 2,381 69,766
Reclass of properties held for resale - - (37,200)
Exploration costs (drilling and completion) 8,467 12,153 31,767
Development costs (drilling and completion) 21,634 42,443 81,616
Abandonment costs 727 236 352
Geological and geophysical costs 1,362 5,953 13,999
Capitalized interest and general and administrative costs 660 4,476 9,191
Other capital costs 1,449 5,386 22,395
------- ------- --------
$74,477 $73,652 $251,305
======= ======= ========
</TABLE>
The Company makes, and will continue to make, substantial capital
expenditures for the acquisition, exploration, development, production and
abandonment of its oil and natural gas reserves. The Company intends to finance
capital expenditures related to this strategy primarily with funds provided by
operations and borrowings under the Revolving Credit Facility. During the year
ended December 31, 1996, the Company spent $113.4 million on exploration and
development drilling and $14.0 million on 3-D seismic surveys and other
geological and geophysical
25
<PAGE>
costs. Included in other capital costs for the year ended December 31, 1996, is
$20.0 million, that relates primarily to capital costs incurred on production
facilities and flowlines. The Company is also a party to two escrow agreements
which provide for the future plugging and abandonment costs associated with oil
and gas properties. The first agreement, related to the East Bay Fields,
requires monthly deposits of $100,000 through June 30, 1998, and $350,000
thereafter until the balance in the escrow account equals $40 million, unless
the Company commits to the plugging and abandonment of a certain number of wells
in which case the increase will be deferred. The second agreement, related to
Main Pass 69, required an initial deposit of $250,000 and monthly deposits
thereafter of $50,000 until the balance in the escrow account equals $7,500,000.
As of December 31, 1996, the escrow balances totaled $6.3 million.
The Company has budgeted $200 million for 1997 drilling activities and an
additional $30 million for other direct capital expenditures including lease
acquisitions and seismic purchases. In addition, in the first quarter of 1997
the Company completed an acquisition of certain interests in various state
leases in the Main Pass 69 field for a gross purchase price of $55.7 million.
The Company's other primary capital requirements include $16.9 million for
payment of interest on the Senior Notes, $15.6 million for payment of interest
on the Senior Subordinated Notes and interest on any borrowings the Company may
incur under the Revolving Credit Facility. The Company expects to fund its
obligations with operating cash flow and borrowings under the Revolving Credit
Facility.
In addition to developing its existing reserves, the Company attempts to
increase its reserve base, production and operating cash flow by engaging in
strategic acquisitions of oil and gas properties. During the year ended December
31, 1996, the Company spent $129.2 million on the acquisition of evaluated and
unevaluated properties. In order to finance other possible future acquisitions,
the Company may seek to obtain additional debt or equity financing. The
availability and attractiveness of these sources of financing will depend upon a
number of factors, some of which will relate to the financial condition and
performance of the Company, and some of which will be beyond the Company's
control, such as prevailing interest rates, oil and gas prices and other market
conditions. There can be no assurance that the Company will acquire any
additional producing properties. In addition, the ability of the Company to
incur additional indebtedness and grant security interests with respect thereto
will be subject to the terms of the Indentures (as defined herein).
Liquidity. The ability of the Company to satisfy its obligations and fund
planned capital expenditures will be dependent upon its future performance,
which will be subject to prevailing economic conditions, including oil and gas
prices, and to financial and business conditions and other factors, many of
which are beyond its control, supplemented if necessary with existing cash
balances and borrowings under the Revolving Credit Facility. The Company
expects that its cash flow from operations and availability under the Revolving
Credit Facility will be adequate to execute its 1997 business plan. However, no
assurance can be given that the Company will not experience liquidity problems
from time to time in the future or on a long-term basis. If the Company's cash
flow from operations and availability under the Revolving Credit Facility are
not sufficient to satisfy its cash requirements, there can be no assurance that
additional debt or equity financing will be available to meet its requirements.
The Revolving Credit Facility has a borrowing base of $50 million. The
lenders may redetermine the borrowing base at their option once within any 12-
month period as well as on scheduled redetermination dates as outlined in the
Revolving Credit Facility. The borrowing base automatically reduces by an
amount equal to one-sixteenth (1/16) of the borrowing base in effect on March
30, 1998, unless the Company requests and is granted a one-year deferral of such
reductions.
The Company's ability to draw additional amounts on the Revolving Credit
Facility is limited to the extent that Adjusted Consolidated Net Tangible Assets
(as defined) minus $25 million exceeds 110% of all indenture indebtedness (as
defined) excluding subordinated indebtedness (as defined). Adjusted
Consolidated Net Tangible Assets is determined quarterly, utilizing certain
financial information, and is primarily based on a quarterly estimate of the
present value of future net revenues of the Company's proved oil and gas
reserves. Such quarterly estimates utilize the most recent year end oil and gas
prices and vary based on additions to proved reserves and net production. As of
December 31, 1996, the Company's outstanding balance on its Revolving Credit
Facility was $2.0 million (which amount represented a letter of credit
associated with future abandonment obligations). The Company had remaining
availability of $48.0 million under the Revolving Credit Facility as of December
31, 1996.
During 1996, the Company successfully completed a consent solicitation
which resulted in the amendment of the indenture governing the Senior Notes (the
"Senior Notes Indenture"). The amendment increased the Company's
26
<PAGE>
ability to borrow under a revolving credit facility from $50 million to the
greater of (i) $50 million and (ii) $20 million plus 20% of adjusted
consolidated net tangible assets as defined in the Senior Notes Indenture.
As of February 24, 1997, the Company was in the process of amending and
restating its Revolving Credit Facility and had obtained commitments from all
lenders which will increase the facility size to $150 million and the borrowing
base to $100 million.
Effects of Leverage. The Company is highly leveraged with outstanding
indebtedness of approximately $284.1 million as of December 31, 1996. The
Company's level of indebtedness has several important effects on its future
operations, including (i) a substantial portion of the Company's cash flow from
operations must be dedicated to the payment of interest on its indebtedness and
will not be available for other purposes, (ii) the covenants contained in the
Indentures (as defined herein) require the Company to meet certain financial
tests, and contains other restrictions which limit the Company's ability to
borrow additional funds or to dispose of assets and may affect the Company's
flexibility in planning for, and reacting to, changes in its business, including
possible acquisition activities and (iii) the Company's ability to obtain
additional financing in the future for working capital, expenditures,
acquisitions, general corporate purposes or other purposes may be impaired.
Moreover, future acquisition or development activities may require the Company
to alter its capitalization significantly.
The Company is required to make semi-annual interest payments of
approximately $8.4 million on its Senior Notes each June 1 and December 1
through the year 2004 and semi-annual interest payments of $7.8 million on its
Senior Subordinated Notes each April 1 and October 1 commencing April 1, 1997.
In addition, the Company is required to make quarterly interest payments on the
Revolving Credit Facility based on outstanding borrowings for the quarterly
period. The Company may also, at its discretion, make principal payments on the
Revolving Credit Facility.
Pursuant to the Senior Notes Indenture, the Company may not incur any
Indebtedness other than Permitted Indebtedness (as defined in the Senior Notes
Indenture) unless the Company's Consolidated Fixed Charge Coverage Ratio (as
defined in the Senior Notes Indenture) for the four full fiscal quarters
preceding the proposed new indebtedness is greater than 2.75 to 1.0 (3.0 to 1.0
if the indebtedness is incurred after December 1, 1997) after giving pro forma
effect to the proposed new Indebtedness, the application of the proceeds of such
Indebtedness and other significant transactions during the period. In addition,
the Company's Adjusted Consolidated Net Tangible Assets (as defined in the
Senior Notes Indenture) must be greater than 150% of Indebtedness after giving
effect to the proposed new Indebtedness and related transactions. If the ratio
of Adjusted Consolidated Net Tangible Assets to Indebtedness excluding
Subordinated Indebtedness (as defined in the Senior Notes Indenture) falls below
110%, the Company may be required to buy back a portion of the Senior Notes.
Pursuant to the indenture governing the Senior Subordinated Notes (the "Senior
Subordinated Notes Indenture" and, together with the Senior Notes Indenture, the
"Indentures"), the Company may not incur any Indebtedness other than Permitted
Indebtedness (as defined in the Senior Subordinated Notes Indenture) for the
four full fiscal quarters preceding the proposed new Indebtedness is greater
than 2.5 to 1.0 after giving pro forma effect to the proposed new Indebtedness,
the application of the proceeds of such Indebtedness and other significant
transactions during the period.
In accordance with the terms of the Indentures, if the Company disposes of
oil and gas assets, it must apply such proceeds to permanently pay down
indebtedness other than the Senior Notes or within a specified time from the
date of the asset sale, purchase additional oil and gas assets. If proceeds not
applied as indicated above exceed $10 million ($15 million with respect to the
Senior Subordinated Notes), the Company shall be required to offer to purchase
outstanding Senior Notes and Senior Subordinated Notes or other pari passu
indebtedness in an amount equal to the unapplied proceeds.
The Company believes it is currently in compliance with all covenants
contained in the respective Indentures and has been in compliance since the
issuance of the Senior Notes and the Senior Subordinated Notes.
The Company's ability to meet its debt service obligations and to reduce
its total indebtedness will be dependent upon the Company's future performance,
which will be subject to oil and gas prices, general economic conditions and to
financial, business and other factors affecting the operations of the Company,
many of which are beyond its control. There can be no assurance that the
Company's future performance will not be adversely affected by such economic
conditions and financial, business and other factors.
27
<PAGE>
OTHER MATTERS
Energy swap agreements. The Company hedges certain of its production
through master swap agreements ("Swap Agreements"). The Swap Agreements provide
for separate contracts tied to the NYMEX light sweet crude oil and natural gas
futures contracts. The Company has contracts which contain specific contracted
prices ("Swaps") that are settled monthly based on the differences between the
contract prices and the average NYMEX prices for each month applied to the
related contract volumes. To the extent the average NYMEX price exceeds the
contract price, the Company pays the spread, and to the extent the contract
price exceeds the average NYMEX price the Company receives the spread. In
addition, the Company has combined contracts which have agreed upon price floors
and ceilings ("Costless Collars"). To the extent the average NYMEX price
exceeds the contract ceiling, the Company pays the spread between the ceiling
and the average NYMEX price applied to the related contract volumes. To the
extent the contract floor exceeds the average NYMEX price, the Company receives
the spread between the contract floor and the average NYMEX price applied to the
related contract volumes. Under the terms of the Swap Agreements, each
counterparty has extended the Company a $5 million line of credit for use in
conjunction with its hedging activities. As of March 21, 1997, the Company's
net exposure under all contracts covered by the Swap Agreements was
approximately $2.6 million.
As of December 31, 1996, after giving effect to three additional oil Swaps
that the Company entered into in February 1997, the Company's open forward
position on its outstanding crude oil Swaps was as follows:
<TABLE>
<CAPTION>
AVERAGE
YEAR MBBLS PRICE
------ ----- -------
<S> <C> <C>
1997 1,500 $19.73
1998 300 18.55
1999 300 18.55
2000 300 18.55
----- ------
2,400 $19.29
===== ======
</TABLE>
The Company currently has no outstanding natural gas Swaps.
As of December 31, 1996, after giving effect to three additional Costless
Collars entered into through February 24, 1997, the Company's open forward
position on its outstanding Costless Collars was as follows:
<TABLE>
<CAPTION>
EFFECTIVE CONTRACTED CONTRACTED CONTRACTED
------------------ VOLUMES FLOOR CEILING
YEAR FROM THROUGH (MBBLS) PRICE PRICE
---- ------- --------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
1997 January March 600 $21.00 $24.45
1997 January June 1,200 $20.00 $24.25
1997 April June 375 $20.00 $25.14
1997 July September 900 $20.00 $24.40
</TABLE>
As a result of hedging activity under the Swap Agreement, the Company
estimates that on a BOE basis, approximately 36% of its estimated 1997
production which is classified as proved reserves as of December 31, 1996, will
not be subject to price fluctuation for 1997.
Currently, it is the Company's intention to commit no more than 50% of its
production on a BOE basis to such arrangements at any point in time. Moreover,
under the Revolving Credit Facility the Company is prohibited from committing
more than 75% of its production estimates for the next 24 months to such
arrangements at any point in time. As the current swap agreements expire, the
portion of the Company's oil and natural gas production which is subject to
price fluctuations will increase substantially, unless the Company enters into
additional hedging transactions.
Despite the measures taken by the Company to attempt to control price risk,
the Company remains subject to price fluctuations for natural gas and oil sold
in the spot market. Prices received for natural gas sold on the spot market are
volatile due primarily to seasonality of demand and other factors beyond the
Company's control.
28
<PAGE>
Domestic oil prices generally follow worldwide oil prices which are subject to
price fluctuations resulting from changes in world supply and demand. While the
price the Company receives for its oil and natural gas production has
significant financial impact on the Company, no prediction can be made as to
what price the Company will receive for its oil and natural gas production in
the future.
Gas balancing. It is customary in the industry for various working interest
partners to produce more or less than their entitlement share of natural gas
from time to time. The Company's net overproduced position increased from
1,080,726 Mcf at December 31, 1995, to 2,059,954 Mcf at December 31, 1996,
primarily as a result of imbalances assumed in conjunction with the acquisition
of the Central Gulf Properties. During the make-up period, the Company's gas
revenues will be adversely affected, limited by an unjust enrichment clause
contained in the gas balancing agreement. The Company recognizes revenue and
imbalance obligations under the sales method of accounting.
Environmental. The Company's business is subject to certain federal, state,
and local laws and regulations relating to the exploration for, and the
development production and transportation of, oil and natural gas, as well as
environmental and safety matters. Many of these laws and regulations have become
more stringent in recent years, often imposing greater liability on a larger
number of potentially responsible parties. Although the Company believes it is
in substantial compliance with all applicable laws and regulations, the
requirements imposed by such laws and regulations are frequently changed and
subject to interpretation, and the Company is unable to predict the ultimate
cost of compliance with these requirements or their effect on its operations.
Under certain circumstances, the MMS may require any Company operations on
federal leases to be suspended or terminated. Any such suspensions, terminations
or inability to meet applicable bonding requirements could materially and
adversely affect the Company's financial condition and operations. Although
significant expenditures may be required to comply with governmental laws and
regulations applicable to the Company, to date such compliance has not had a
material adverse effect on the earnings or competitive position of the Company.
It is possible that such regulations in the future may add to the cost of
operating offshore drilling equipment or may significantly limit drilling
activity. See "Business--Governmental Regulation," "--Environmental Matters" and
"--Abandonment Costs."
The OPA imposes ongoing requirements on a responsible party including proof
of financial responsibility to cover at least some costs in a potential spill.
As amended by the Coast Guard Authorization Act of 1996, OPA requires
responsible parties for offshore facilities to provide financial assurance in
the amount of $3.5 million to cover potential OPA liabilities. This amount is
subject to upward regulatory adjustment up to $150 million.
29
<PAGE>
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants........................................... 31
Consolidated Balance Sheets as of December 31, 1996 and 1995....................... 32
Consolidated Statements of Operations for the years ended December 31, 1996, 1995
and 1994...................................................................... 33
Consolidated Statements of Stockholders' Equity for the years ended December 31,
1996, 1995 and 1994........................................................... 34
Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995
and 1994...................................................................... 35
Notes to Consolidated Financial Statements......................................... 36
</TABLE>
30
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of
Flores & Rucks, Inc. and subsidiaries:
We have audited the accompanying consolidated balance sheets of Flores &
Rucks, Inc. (a Delaware corporation) and subsidiaries, as of December 31, 1996
and 1995 and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1996. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Flores & Rucks, Inc. and
subsidiaries as of December 31, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
February 24, 1997
31
<PAGE>
FLORES & RUCKS, INC.
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1996 1995
------------ ------------
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 5,758,978 $ 212,238
Joint interest receivables 2,001,605 390,275
Oil and gas sales receivables 33,770,044 17,546,127
Notes and accounts receivable - stockholders - 129,129
Accounts receivable - other 1,500,000 -
Assets held for resale 37,200,000 -
Prepaid expenses 1,213,143 390,412
Other current assets 2,414,803 424,824
------------ ------------
Total current assets 83,858,573 19,093,005
Oil and gas properties - full cost method:
Evaluated 464,485,367 274,942,435
Less accumulated depreciation, depletion, and
amortization (188,692,223) (114,040,044)
------------ ------------
275,793,144 160,902,391
Unevaluated properties excluded from amortization 79,904,974 19,041,148
Other assets:
Furniture and equipment, less accumulated depreciation of
$2,772,983 and $1,258,225 in 1996 and 1995, respectively 4,286,773 2,340,641
Restricted deposits 6,323,515 4,259,182
Deferred financing costs 10,543,226 5,127,974
Deferred tax asset - 4,692,263
------------ ------------
Total assets $460,710,205 $215,456,604
============ ============
</TABLE>
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
Current liabilities:
<S> <C> <C>
Accounts payable and accrued liabilities $ 47,718,102 $ 15,090,791
Oil and gas sales payable 7,830,415 5,177,277
Accrued interest 5,521,070 2,651,097
Current notes payable 127,154 -
Deposit on assets held for resale 3,720,000 -
------------ ------------
Total current liabilities 64,916,741 22,919,165
Long-term debt 284,141,999 157,391,556
Notes payable to be refinanced under revolving line of credit - 14,300,000
Deferred hedge revenue 400,000 870,333
Deferred tax liability 6,098,144 -
Stockholders' equity:
Preferred stock, $.01 par value; authorized 10,000,000 shares,
no shares issued or outstanding at December 31, 1996 and 1995 - -
Common stock, $.01 par value; authorized 100,000,000 shares;
issued and outstanding 19,640,656 shares and 15,044,125
shares at December 31, 1996 and 1995, respectively 196,407 150,441
Paid-in capital 91,819,465 27,638,465
Retained earnings (deficit) 13,137,449 (7,813,356)
------------ ------------
Total stockholders' equity 105,153,321 19,975,550
------------ ------------
Total liabilities and stockholders' equity $460,710,205 $215,456,604
============ ============
</TABLE>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
32
<PAGE>
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1996 1995 1994
------------- ------------- -------------
<S> <C> <C> <C>
Oil and gas sales $188,451,215 $127,970,126 $ 75,395,112
Operating expenses:
Lease operations 36,192,253 30,023,426 23,577,089
Severance taxes 10,905,731 10,023,104 6,746,928
Depreciation, depletion and amortization 74,652,179 54,083,782 36,459,029
------------ ------------ ------------
Total operating expenses 121,750,163 94,130,312 66,783,046
General and administrative expenses 16,153,823 11,312,153 10,350,572
Interest expense 17,954,053 17,620,226 4,507,307
Interest income and other (394,909) (302,597) (748,479)
Loss on production payment repurchase
and refinancing - - 16,681,211
------------ ------------ ------------
Net income (loss) before income taxes 32,988,085 5,210,032 (22,178,545)
Income tax expense (benefit) 12,037,280 (4,692,263) -
------------ ------------ ------------
Net income (loss) $ 20,950,805 $ 9,902,295 $(22,178,545)
============ ============ ============
Earnings per common share
Primary $1.07 $.65 N.M.
Fully diluted 1.05 .65 N.M.
Weighted average common and common
equivalent shares outstanding
Primary 19,639,942 15,158,514 N.M.
Fully diluted 19,901,461 15,329,740 N.M.
</TABLE>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
33
<PAGE>
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
RETAINED
COMMON PAID-IN EARNINGS
STOCK CAPITAL (DEFICIT) TOTAL
-------- ------------- ------------- -------------
<S> <C> <C> <C> <C>
Balance at December 31, 1993 $ 1,000 $ - $ (825,702) $ (824,702)
Sale of stock 149,000 52,657,553 - 52,806,553
Repurchase of common stock - (18,700,000) - (18,700,000)
Net loss - - (22,178,545) (22,178,545)
Distributions - - (1,400,000) (1,400,000)
Reclassification of accumulated deficit at
date of conversion to a subchapter C
corporation - (6,688,596) 6,688,596 -
-------- ------------ ------------ ------------
Balance at December 31,1994 $150,000 $ 27,268,957 $(17,715,651) $ 9,703,306
Sale of stock 441 369,508 - 369,949
Net income - - 9,902,295 9,902,295
-------- ------------ ------------ ------------
Balance at December 31,1995 $150,441 $ 27,638,465 $ (7,813,356) $ 19,975,550
Sale of stock - public offering 45,000 62,146,285 - 62,191,285
Sale of stock - exercise of stock options 966 2,034,715 - 2,035,681
Net income - - 20,950,805 20,950,805
-------- ------------ ------------ ------------
Balance at December 31,1996 $196,407 $ 91,819,465 $ 13,137,449 $105,153,321
======== ============ ============ ============
</TABLE>
The accompanying notes to consolidated financial statements are an integral part
of these statements.
34
<PAGE>
FLORES & RUCKS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1996 1995 1994
-------------- ------------- --------------
<S> <C> <C> <C>
Operating activities:
Net income (loss) $ 20,950,805 $ 9,902,295 $ (22,178,545)
Adjustments to reconcile net income (loss) to net
cash provided by (used in) operating activities:
Depreciation, depletion and amortization 76,166,937 54,751,429 36,845,015
Deferred hedge revenue (470,333) 203,666 (565,180)
Deferred tax expense (benefit) 10,790,407 (4,692,263) -
Recognition of deferred revenue on sale of
production payment interest - - (23,857,212)
Repurchase of production payment interests - - (107,951,703)
Changes in operating assets and liabilities:
Accrued interest 1,569,973 1,555,132 1,947,489
Receivables (19,206,115) (7,055,051) (6,208,990)
Prepaid expenses (822,731) 126,106 -
Other current assets (1,989,979) (352,106) (139,976)
Accounts payable and accrued liabilities 32,627,311 1,957,344 5,155,926
Oil and gas sales payable 2,653,135 2,483,037 1,468,107
Deposit on assets held for resale 3,720,000 - -
------------- ------------ -------------
Net cash provided by (used in) operating activities 125,989,410 58,879,589 (115,485,069)
------------- ------------ -------------
Investing activities:
Additions to oil and gas properties and furniture
and equipment (291,067,648) (75,740,369) (39,408,546)
Increase in restricted deposits (2,064,333) (1,958,884) (1,221,377)
Purchase of minority interest - - (5,977,097)
------------- ------------ -------------
Net cash used in investing activities (293,131,981) (77,699,253) (46,607,020)
------------- ------------ -------------
Financing activities:
Sale of stock 64,226,966 369,949 52,806,553
Borrowings on notes payable 242,120,000 99,000,020 181,014,776
Payments of notes payable (128,264,402) (81,357,944) (55,632,361)
Deferred financing costs (5,393,253) 451,187 (5,626,787)
Repurchase of common stock - - (8,700,000)
Distributions to stockholders - - (1,400,000)
------------- ------------ -------------
Net cash provided by financing activities 172,689,311 18,463,212 162,462,181
------------- ------------ -------------
Increase (decrease) in cash and cash equivalents 5,546,740 (356,452) 370,092
Cash and cash equivalents, beginning of the period 212,238 568,690 198,598
------------- ------------ -------------
Cash and cash equivalents, end of the period $ 5,758,978 $ 212,238 $ 568,690
============= ============ =============
Interest paid during the period $ 20,896,826 $ 18,288,156 $ 2,808,721
============= ============ =============
</TABLE>
The accompanying notes to consolidated financial statements are an integral
part of these statements.
35
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization
Flores & Rucks, Inc., a Delaware corporation (the "Company"), is an
independent energy company engaged in the exploration, development, acquisition
and production of crude oil and natural gas, with operations primarily in the
shallow offshore regions of Louisiana. The Company was formed on September 22,
1994, to succeed to the business of Flores & Rucks, Inc., a Louisiana
corporation ("FRI Louisiana") and Flores & Rucks LLC ( the "LLC"). Concurrent
with the closing of the Initial Offerings (See Note 2) on December 7, 1994, FRI
Louisiana was merged into a wholly owned subsidiary of the Company. Because the
transaction represented the reorganization of entities under common control, the
merger was treated in a manner similar to a pooling of interests.
During 1996, the Company issued 4.5 million additional shares of common
stock and $160 million of 9 3/4% Senior Subordinated Notes through public
offerings (See Note 2).
Hereinafter, the "Company" refers to Flores & Rucks, Inc., a Delaware
corporation, its predecessors and their respective subsidiaries.
Effective January 1, 1993, FRI Louisiana issued 2,000 shares of common
stock to the two stockholders of an entity which held the rights under an
operating agreement to operate substantially all of FRI Louisiana's oil and gas
properties. These two stockholders were deemed co-promoters of FRI Louisiana
upon the exchange. As no tangible assets, or any assets with predecessor basis,
were acquired by FRI Louisiana in connection with the exchange, no value was
attributed to the stock issued. These shares were subsequently reacquired (See
Note 7).
On December 28, 1993, FRI Louisiana transferred its interests in
substantially all of its oil and gas properties to the LLC in return for an
87.5% ownership interest. The remaining 12.5% interest (the "Minority Interest")
was owned by an unrelated party, Franks Petroleum, Inc. ("Franks"). FRI
Louisiana proportionately consolidated its interest in LLC.
The Company is substantially leveraged. As such, a significant portion of
the Company's cash flow from operations will be dedicated to debt service. As
with other independent oil and gas producers, the Company is subject to numerous
uncertainties and commitments associated with its operations. For example, the
Company's results of operations are highly dependent upon the prices received
for oil and gas. In addition, the Company will be required to make substantial
future capital expenditures for the acquisition, exploration, development,
production and abandonment of its oil and gas properties.
Subsidiary Guaranty
All of the Company's operating income and cash flow is generated by FRI
Louisiana, a wholly owned subsidiary and the Subsidiary Guarantor of the
Company. The separate financial statements of FRI Louisiana are not included
herein because (i) FRI Louisiana is the only direct active subsidiary of the
Company; (ii) FRI Louisiana has fully and unconditionally guaranteed the Senior
Notes and the Senior Subordinated Notes (as defined in Note 2); (iii) the
aggregate assets, liabilities, earnings, and equity of FRI Louisiana are
substantially equivalent to the assets, liabilities, earnings and equity of the
Company on a consolidated basis; and (iv) the presentation of separate financial
statements and other disclosures concerning FRI Louisiana are not deemed
material.
36
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Oil and Gas Properties
The Company's exploration and production activities are accounted for under
the full cost method. Under this method, all acquisition, exploration and
development costs, including certain related employee costs, incurred for the
purpose of finding oil and gas are capitalized. Such amounts include the cost
of drilling and equipping productive wells, dry hole costs, lease acquisition
costs, delay rentals, and costs related to such activities. Employee costs
associated with production operations and general corporate activities are
expensed in the period incurred. The Company capitalized $3,893,000, $1,643,000
and $535,000 of employee related costs directly associated with the acquisition,
development or exploration of oil and gas properties during the years ended
December 31, 1996, 1995 and 1994, respectively. The Company's proportionate
interests in properties held under joint venture, partnership or similar
arrangements are included in oil and gas properties. Transactions involving
sales of reserves in place, unless unusually significant, are recorded as
adjustments to oil and gas properties. Capitalized costs are limited to the sum
of the present value of future net revenues discounted at 10% related to
estimated production of proved reserves (which includes deferred hedge revenue)
and the lower of cost or estimated fair value of unevaluated properties.
Depreciation, depletion and amortization of oil and gas properties are
computed on a composite unit-of-production method based on estimated proved
reserves. All costs associated with oil and gas properties, including an
estimate of future development, restoration, dismantlement and abandonment costs
of proved properties, are included in the computation base, with the exception
of certain costs associated with unevaluated oil and gas properties. The oil
and gas reserves are estimated periodically by independent petroleum engineers.
The Company evaluates all unevaluated oil and gas properties on a quarterly
basis to determine if any impairment has occurred. Any impairment to unevaluated
properties will be reclassified as a proved oil and gas property, and thus
subject to amortization if there are proved reserves associated with the related
cost center. Otherwise, such impairment will be recognized in the period in
which it occurs.
In March 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121 ("SFAS 121") regarding
accounting for the impairment of long-lived assets. The Company adopted SFAS
121 in 1996. The effect of adopting SFAS 121 did not materially impact the
Company's results of operations or financial position as of December 31, 1996.
Furniture and Equipment
Depreciation is computed using the straight-line method over the estimated
useful lives of the assets, which range from 3 to 5 years.
Oil and Gas Revenue
The Company records oil and gas revenue on the sales method. As a result of
this policy, the Company did not record revenues of $642,663 and $20,000 for
the years ended December 31, 1996 and 1995, respectively, on gas volumes that
the Company was entitled to, but which were sold by a joint owner in order to
reduce previous gas imbalances. The Company recorded revenue of $376,000 during
the year ended December 31, 1994, on gas volumes sold in excess of its entitled
share of production. As of December 31, 1996, the Company is in a net
overdelivered position of 2,059,954 Mcf, which will reduce future oil and gas
revenue as the underdelivered parties
37
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
recoup their share of production. In connection with acquisitions, under the
sales method the Company records a gas balancing liability only to the extent
any net gas imbalance acquired exceeds the reserves acquired.
The Company records as oil and gas revenue the payments received from (or
made to) a third party under contracts to hedge future oil and gas production
(See Note 13).
Statements of Cash Flows
The Company considers all highly liquid investments with a maturity of
three months or less when purchased to be cash equivalents.
Earnings Per Common Share
Primary and fully diluted earnings per common share are based on the
weighted average number of shares of common stock outstanding for the periods,
including common equivalent shares which reflect the dilutive effect of stock
options granted to certain employees and outside directors on various dates
through December 31, 1996. Dilutive options that are issued during a period or
that expire or are canceled during a period are reflected in both primary and
fully diluted earnings per share computations for the time they were outstanding
during the periods being reported.
Earnings per common share has not been presented for the Company for the
year ended December 31, 1994, as this amount would not be meaningful or
indicative of the ongoing entity due to the Initial Offerings (See Note 2) and
related transactions.
Deferred Financing Costs
The Company has $10,543,226, net of accumulated amortization of $1,423,572,
recorded as deferred financing costs as of December 31, 1996, which is related
to the sale of the Senior Notes and the sale of the Senior Subordinated Notes
(See Note 2) and the senior revolving bank credit facility (the "Revolving
Credit Facility"),. In conjunction with the Initial Offerings (See Note 2), a
balance of $1,007,114, which represented deferred financing costs associated
with the term and development loans, discussed in Note 9, was expensed in the
fourth quarter of 1994. Deferred financing costs are being amortized on a
straight-line basis over the life of the related loans.
Fair Value of Financial Instruments
Fair value of cash, cash equivalents, accounts receivable and accounts
payable approximate book value at December 31, 1996. Fair value of debt is
determined based upon market value, if traded, or discounted at the estimated
rate the Company would incur currently on similar debt.
Reclassifications
Certain reclassifications have been made to conform financial statement
presentation between periods.
In addition, prior year oil and gas reserve quantity information in Note 15
has been restated to include estimated future reserves expected to be consumed
by the Company as fuel gas.
2. INITIAL AND SUBSEQUENT PUBLIC OFFERINGS
On December 7, 1994, the Company closed initial public offerings (the
"Initial Offerings") issuing 5,750,000 shares of common stock at $10 per share
and $125 million of 13 1/2% Senior Notes due December 1, 2004
38
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(the "Senior Notes"), and concurrently exchanged the Enron Option (See Note 4)
and $1,000 for one million shares of common stock. Additionally, the Company
acquired the Franks interest (for $6.0 million cash) and the LLC was merged into
the Company. Also, concurrent with the closing of the Initial Offerings, the
Company acquired the production payment obligations for East Bay Complex and
Main Pass 69 (See Notes 3 and 4), repaid the term loan and development loans
(See Note 9) and paid off notes to current and former stockholders (See Note 7).
In January 1995, the Company issued an additional 40,000 shares of common
stock relating to the exercise of the underwriters over allotment option. Net
proceeds to the Company from the issuance of these shares was $372,000.
On March 19, 1996, the Company completed a public offering of 4,500,000
shares of common stock at a price of $14.75 per share (the "Offering"). Net
proceeds of the Offering were approximately $62.2 million, of which $15.4
million was used to repay a note payable to Shell Offshore, Inc. and
approximately $33.0 million was used to repay indebtedness under the Revolving
Credit Facility.
On September 26, 1996, the Company completed an offering of $160,000,000 of
9 3/4% Senior Subordinated Notes at a discount (the "Senior Subordinated Notes")
for proceeds of $159,120,000 (before offering costs). The principal is due
October 1, 2006. Interest on the notes will be payable semi-annually in arrears
on April 1 and October 1 of each year, commencing April 1, 1997. Net proceeds
to the Company were approximately $154 million, which was used primarily to
complete the acquisition of the Central Gulf Properties (See Note 3) and to
repay outstanding indebtedness of $25.1 million under the Company's Revolving
Credit Facility.
3. INVESTMENT IN OIL AND GAS PROPERTIES
On June 11, 1992, the Company acquired a producing oil and gas property
("Main Pass 69") from Shell Oil Company, its affiliates and subsidiaries
("Shell"), for $39.2 million. On June 10, 1993, the Company acquired a second
producing property (the "East Bay Complex") from Shell for $131.9 million.
Concurrent with these acquisitions, the Company assigned overriding royalty
interests burdening one-eighth of the working interests to a company owned by a
stockholder for services rendered in connection with the acquisitions. In
addition, the Company sold to Franks the one-eighth working interests subject to
the override in return for the assumption of one-eighth of the volumetric
production payment liabilities related thereto (See Note 4) and, for the East
Bay Complex, one-eighth of a note payable to Shell (Note 9). In addition, see
Note 4 for a discussion of the sale of an option to Enron Financial Corporation
related to the East Bay Complex.
On December 7, 1994, the Company acquired Franks' interest in the LLC for
$6 million and recorded the acquisition using the purchase method. Included in
the purchase the Company acquired cash totaling $23,000, other current assets
totaling $56,000, the Minority Interest's share of a plug and abandonment escrow
totaling $269,000 and other assets totaling $124,000. In addition, the Company
assumed accrued interest payable of $53,000, notes payable on JEDI loans (as
defined in Note 9) of approximately $4.4 million, deferred hedge revenue of
$85,000, an approximate $1.8 million liability owed to the Company and deferred
production payment revenues of approximately $15.5 million, as well as the
assumption of a $710,000 liability owed to the LLC. The Company recorded an
increase in the full cost pool of $28.1 million. The Company allocated the
purchase price between evaluated and unevaluated properties based on estimated
relative fair market value.
On September 26, 1996, the Company acquired from Mobil Oil and Producing
Southeast, Inc. ("Mobil"), certain interests in eleven oil and gas producing
fields and related production facilities primarily situated in the shallow
federal waters of the central Gulf of Mexico, offshore Louisiana, (the "Central
Gulf Properties") for approximately $117.6 million. The Company financed the
acquisition with proceeds from the issuance of the Senior Subordinated Notes
(See Note 2). At December 31, 1996, one of the eleven Central Gulf Properties
was reclassified as "Assets held for resale". The subject property was sold on
January 3, 1997, for $37.2. No gain or loss was recognized on the sale.
39
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following pro forma information gives effect to the acquisition of the
Central Gulf Properties by the Company as if it had occurred on January 1, 1995.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------
1996 1995
------------ ------------
<S> <C> <C>
(UNAUDITED)
Total revenues $216,528,093 $168,829,040
Net income 24,854,741 13,840,044
Earnings per common share:
Primary $ 1.27 $ 0.91
Fully diluted 1.25 0.90
</TABLE>
The following table discloses certain financial data relative to the
Company's oil and gas producing activities, substantially all of which are
located in the offshore waters of the continental United States.
<TABLE>
<CAPTION>
1996 1995 1994
------------- ------------ ------------
<S> <C> <C> <C>
Costs incurred during period:
Capitalized
Purchase of producing properties $ 59,419,082 $ 624,097 $ 25,441,295
Purchase of unevaluated properties 69,765,719 2,381,227 14,736,334
Properties held for resale (37,200,000) - -
Exploration costs 45,765,965 18,106,000 9,829,000
Development costs, including capitalized
workovers 104,010,914 47,829,175 23,083,108
Plugging and abandonment costs 352,043 236,000 727,370
Capitalized interest on unevaluated properties
and capitalized general and administrative
costs 9,191,313 4,475,979 659,552
------------ ------------ ------------
$251,305,036 $ 73,652,478 $ 74,476,659
============ ============ ============
Charged to expense
Operating costs:
Recurring lease operating expenses $ 33,709,222 $ 28,648,019 $ 22,709,507
Major maintenance expenses 2,483,031 1,375,407 867,582
------------ ------------ ------------
Total operating costs $ 36,192,253 $ 30,023,426 $ 23,577,089
============ ============ ============
Severance taxes $ 10,905,731 $ 10,023,104 $ 6,746,928
============ ============ ============
Oil and gas properties:
Balance, beginning of period $293,983,583 $220,331,105 $145,934,272
Additions 287,606,758 73,652,478 74,396,833
Properties held for resale (37,200,000) - -
------------ ------------ ------------
Balance, end of period $544,390,341 $293,983,583 $220,331,105
============ ============ ============
Accumulated depreciation, depletion and
amortization:
Balance, beginning of period $114,040,044 $ 60,019,583 $ 23,560,554
Provision for depreciation, depletion and
amortization 74,652,179 54,020,461 36,459,029
------------ ------------ ------------
Balance, end of period 188,692,223 114,040,044 60,019,583
------------ ------------ ------------
Net capitalized costs $355,698,118 $179,943,539 $160,311,522
============ ============ ============
</TABLE>
40
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following table discloses financial data associated with capitalized
unevaluated costs as of December 31, 1996.
<TABLE>
<CAPTION>
COSTS INCURRED DURING THE
BALANCE AT YEARS ENDED DECEMBER 31,
DECEMBER 31, ---------------------------------------------
1996 1996 1995 1994
----------- ----------- ---------- ----------
<S> <C> <C> <C> <C>
Acquisition costs $54,710,827 $45,864,414 $2,232,685 $6,613,728
Exploration costs 18,196,979 13,267,654 4,929,325 -
Development costs 2,291,218 2,291,218 - -
Capitalized interest 4,705,950 3,478,046 1,170,301 57,603
----------- ----------- ---------- ----------
$79,904,974 $64,901,332 $8,332,311 $6,671,331
=========== =========== ========== ==========
</TABLE>
4. PRODUCTION PAYMENTS
Concurrent with the Main Pass 69 and East Bay Complex acquisitions, the
Company sold to Enron Reserve Acquisition Corp. ("ERAC") nonrecourse volumetric
production payment interests of approximately $36.7 million and $95.7 million,
respectively, net of the amounts assumed by Franks.
The Company deferred the revenue associated with the sale of these
production payment interests because a substantial obligation for future
performance existed. Under the terms of the sales, the Company was obligated to
deliver the production payment volumes free and clear of lease operating
expenses, production taxes, plugging and abandonment and other capital costs.
The deferred revenue was amortized on the unit-of-production method and
recognized as oil and gas revenues as the associated hydrocarbons were
delivered. In addition, under separate agreements, the Company was required to
sell all excess production over production payment volumes from the subject
properties to an affiliate of ERAC during the same periods. Sales from the East
Bay Complex were made at market prices, whereas sales from Main Pass 69 were
made at the affiliate's posted price, which during the eleven months ended
November 30, 1994 was approximately $1.29 per barrel below other buyers'
postings for similar crude oil. Sales from Main Pass 69 for December 1994 were
made to the affiliate at market prices.
In connection with the East Bay Complex production payment, Enron Finance
Corp. ("Enron") obtained from the Company the right to acquire during a ten-year
period commencing January 1, 1996 (or upon a registration of securities), at a
nominal cost, a one-eighth working interest in the East Bay Complex or a 9%
interest in LLC (the "Enron Option"). If the working interest was acquired, it
would have been burdened by its share of the production payment. For accounting
purposes, the total proceeds received by the Company from ERAC related to the
East Bay Complex production payment were allocated between deferred revenue from
the sale of the production payment interest ($95.7 million) and a reduction in
the full cost pool resulting from the sale of a portion of the Company's
interest in East Bay Complex ($7.5 million) based upon the relationship of one-
eighth of post-January 1, 1996 reserves to total reserves, as determined at the
date of acquisition. The production payment volumes attributed to this interest
were 401 MBbls and 1,369 MMcf. In December 1994 Enron contributed its Enron
Option and $1,000 in exchange for one million shares of the Company's common
stock. As a result of the exchange, the Company recorded a $7.5 million
increase to oil and gas properties as well as an increase of $7.5 million for
the related production payment obligation, which were originally reduced from
the respective accounts.
Concurrent with the Initial Offerings, the Company repurchased the
production payment interests. The cost to acquire the production payment
liability exceeded its book value by approximately $15.7 million. This excess
represented the difference between the amount paid and the book value of the
production payment liability as of December 7, 1994. This excess was recorded as
an expense in the period acquired.
41
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
5. RESTRICTED DEPOSITS
The Company, as the operator of the acquired oil and gas properties, is a
party to two escrow agreements, the first, related to East Bay, requires monthly
deposits of $100,000 through June 30, 1998, and $350,000 thereafter until the
balance in the escrow account equals $40 million unless the Company commits to
the plug and abandonment of a certain number of wells in which case the increase
will be deferred. The second agreement, related to Main Pass, required an
initial deposit of $250,000 and monthly deposits thereafter of $50,000 until the
balance in the escrow account equals $7,500,000. These deposits are to provide
for the future plugging and abandonment costs associated with the oil and gas
properties. Such funds are restricted as to withdrawal by the agreements. With
respect to any specifically planned plugging and abandoning operation, funds are
partially released when the Company presents to the escrow agent the planned
plugging and abandoning operations approved by the applicable governmental
agency, with the balance released upon the presentation by the Company to the
escrow agent of evidence from the governmental agency that the operation was
conducted in compliance with applicable laws and regulations. The escrow agent
for both agreements is an unrelated financial institution. As of December 31,
1996 and 1995, the escrow balances were approximately $6.3 million and $4.3
million, respectively.
6. INCOME TAXES
The Company was formed as an S corporation under the Internal Revenue Code
and, as such, all income taxes were the obligation of the Company's
stockholders. Therefore, through December 7, 1994, no historical federal or
state income tax expense has been provided for in the financial statements. In
conjunction with the Initial Offerings, the Company converted to a C corporation
under the Internal Revenue Code.
The Company has adopted Statement of Financial Accounting Standards No.
109, "Accounting for Income Taxes" ("SFAS 109"). SFAS 109 requires deferred tax
liabilities or assets be recognized for the anticipated future tax effects of
temporary differences that arise as a result of the difference in the carrying
amounts and the tax bases of assets and liabilities. The components of the
income tax provision (benefit) for each of the periods presented are as follows:
<TABLE>
<CAPTION>
1996 1995 1994
----------- ------------ -----
<S> <C> <C> <C>
Current $ - $ - $ -
Deferred 12,037,280 (4,692,263) -
----------- ----------- -----
Total $12,037,280 $(4,692,263) $ -
=========== =========== =====
</TABLE>
Deferred income taxes are provided to reflect temporary differences in the
basis of net assets for income tax and financial reporting purposes. The tax
effected temporary differences and tax loss carryforwards which comprise
deferred taxes are as follows:
<TABLE>
<CAPTION>
1996 1995 1994
------------- ------------ ------------
<S> <C> <C> <C>
Net operating loss carryforward $ 11,271,173 $3,849,463 $ 6,019,935
Temporary differences:
Oil and gas properties (17,369,317) 1,734,991 (1,598,426)
Other - (892,191) 1,882,490
------------ ---------- -----------
Total deferred tax (liability) asset (6,098,144) 4,692,263 6,303,999
Valuation allowance - - (6,303,999)
------------ ---------- -----------
Net deferred tax (liability) asset $ (6,098,144) $4,692,263 $ -
============ ========== ===========
</TABLE>
A valuation allowance is provided for that portion of the asset for which
it is deemed more likely than not that it will not be realized. Due to the
Company's losses in 1994 and the substantial volatility in oil and gas prices,
42
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
management provided a valuation allowance for the entire deferred tax asset at
December 31, 1994. During the second half of 1995, due to drilling successes
and increases in oil and gas prices, the Company generated income from
operations. Based upon estimates, management believed it was more likely than
not that the deferred tax asset as of December 31, 1995 would be realized, and
thus eliminated the valuation allowance in 1995.
The principal reasons for the differences between income taxes computed at
the statutory federal income tax rate and the income tax provision (benefit) are
as follows:
<TABLE>
<CAPTION>
1996 1995 1994
------------------------ ------------------------- ------------------------
% OF NET % OF NET % OF NET
INCOME INCOME INCOME
BEFORE BEFORE BEFORE
AMOUNT TAXES AMOUNT TAXES AMOUNT TAXES
----------- ----------- ------------ ------------ ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
Income tax expense (benefit) computed
at the statutory federal income
tax rate $11,545,830 35 $1,823,511 35 $(7,762,491) (35)
Increase attributable to nontaxable
period - - - - 1,622,168 8
Cumulative temporary differences upon
conversion to a "C" corporation - - - - (729,312) (3)
Change in valuation allowance - - (6,303,999) (121) 6,303,999 28
Other, net 491,450 1 (211,775) (4) 565,636 2
----------- ----------- ----------- ---------- ---------- -----------
Income tax provision (benefit) $12,037,280 36 $(4,692,263) (90) $ - -
=========== =========== =========== ========== ========== ===========
</TABLE>
At December 31, 1996, the Company had regular tax net operating loss
carryforwards of approximately $29.0 million and alternative minimum tax net
operating loss carryforwards of approximately $12.6 million. These loss
carryforward amounts will expire during the years 2009 through 2111.
7. STOCKHOLDERS' EQUITY
In February 1994, the Company agreed to re-acquire 1,000 shares of stock
from a former stockholder discussed in Note 1, for a total of $10.0 million (two
notes in the amount of $5 million each). The notes bore interest at 8% and were
paid on March 1, 1995. In June 1994, the Company agreed to reacquire 1,000
shares of stock from the other former stockholder discussed in Note 1 for $8.7
million, $5.0 million of which was paid in June 1994, and the remainder of which
was paid with the proceeds of the Initial Offerings.
8. RELATED PARTY TRANSACTIONS
Effective July 1, 1994, the Company acquired indirectly from stockholders
various overriding royalty interests for $1.2 million.
During 1994, the Company forgave $500,000 due from two stockholders. The
amounts related to promissory notes which bore interest at 8% per annum and were
due upon demand, and if no demand, then by December 31, 1994. On March 1, 1995,
$250,000 due from a former stockholder was received.
In July 1994, the Company purchased a portion of the overriding royalty
interests previously assigned to an affiliate of a stockholder for $3 million
(See Note 3). At that time, two stockholders loaned the Company $5 million to
make a payment to a former stockholder (See Note 7). In September 1994, the
stockholder affiliate exercised its right to repurchase the overriding royalty
interest from the Company for $3 million and the Company repaid $3
43
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
million of the loans by the stockholders. The Company utilized a portion of the
net proceeds of the Initial Offerings to repay the remaining $2 million in loans
to stockholders.
During 1994, the Company contracted with oilfield service companies
previously owned by current and former stockholders. The total amounts paid for
these services was $1,091,152 during the first six months of 1994 (at June 30,
1994, the stockholders assigned their interest in such companies to a former
stockholder). The Company believes that the cost of such services would have
been substantially similar to costs that would have been charged by unaffiliated
third parties for such services.
During 1994, the Company was assigned an oil and gas prospect from an
officer of the Company, who retained an overriding royalty interest. In
addition, the Company paid the officer $50,000 for services rendered in
connection therewith as well as $108,000 to a third party for acquisition of the
leases. During 1996, the Company purchased a working interest ownership in a
field where the Company had an existing working interest from the officer for
$188,026.
During 1996, 1995 and 1994, the Company paid $1,430,089, $1,041,088 and
$635,960, respectively, to an affiliate of a stockholder associated with an
overriding royalty interest owned by it. In addition, during 1995 and 1994, the
Company paid $4,753 and $124,376, respectively, with respect to oil and gas
properties previously owned by the affiliate. These amounts are included in
accounts receivable from stockholders at December 31, 1995 and 1994, and were
repaid in full on March 27, 1996.
During 1994, the Company obtained a loan from Union Planters Bank in
connection with the purchase of a seaplane. During 1995, Mr. Flores was named a
member of the Board of Directors of that bank. The loan was made to the Company
for the amount of $132,500, bearing interest at the Wall Street Prime rate.
Principal and interest payments were payable monthly, with the balance due on
February 10, 1997. The outstanding principal balance plus accrued interest at
December 31, 1996, was $92,133. On February 10, 1997, the balance of the loan
was paid in full. In addition, Union Planters Bank is a member of the syndicate
under the Revolving Credit Facility. Effective December 31, 1996, Mr. Flores
resigned as a member of the Board of Directors of Union Planters Bank.
Effective November 1, 1995, the Company entered into a consulting
agreement for geological services with a party related to an officer of the
Company. The original term of this agreement expired on October 31, 1996, and
the term was extended for a one year period. In 1995, the Company paid $5,200
pursuant to the agreement as well as $5,000 for other miscellaneous geological
consulting services received. In addition, in 1995 the Company paid $50,000 for
services rendered in connection with an oil and gas prospect assigned to it by
such party. In 1996, the Company paid $110,565 relating to the agreement.
On September 13, 1996, the Company entered into a retainer agreement
for legal services to be rendered by a law firm owned by a party related to an
officer of the Company. This agreement is automatically extended for successive
3 month periods unless terminated by one of the parties. Legal fees paid by the
Company relating to this retainer during 1996 totaled $25,196.
44
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
9. LONG-TERM DEBT
<TABLE>
<CAPTION>
Long-term debt consisted of the following at:
DECEMBER 31,
---------------------------------------------
1996 1995
---------------------- ---------------------
<S> <C> <C>
Note payable to Shell, including accrued interest of $2,183,735
in 1995, with interest payable at a rate of 6% per annum
principal and interest paid March 29, 1996, collateralized
by the vendor's lien and privilege retained by Shell which
was subordinate to the Revolving Credit Facility $ - $ 15,183,735
$50,000,000 revolving line of credit with a bank, bearing interest
as described below, collateralized by first mortgage on the
Main Pass and East Bay properties - 32,200,000
Senior unsecured notes bearing interest at 13 1/2% payable semi-
annually on June 1 and December 1 of each year, commencing
June 1, 1995, due December 1, 2004 125,000,000 125,000,000
$160,000,000 Senior subordinated unsecured notes bearing interest
at 9 3/4% payable semi-annually on April 1 and October 1 of
each year, commencing April 1, 1997, due October 1, 2006,
issued at a discount for proceeds of $159,120,000 159,141,999 -
Promissory note to Union Planters Bank bearing interest at Wall Street
Prime due February 10, 1997, collateralized by a Company
owned seaplane 91,492 106,478
Capital lease from Green Tree Vendor Services Corp. due August
1997, collateralized by certain computer equipment 35,662 85,078
------------ ------------
Total debt 284,269,153 172,575,291
Less: Current portion 127,154 883,735
------------ ------------
Total long-term debt $284,141,999 $171,691,556
============ ============
</TABLE>
The Revolving Credit Facility was committed for up to a five-year period. The
Revolving Credit Facility had an initial borrowing base of $50 million. Chase
Manhattan Bank, N.A. (the "Agent"), with the concurrence of majority lenders (as
defined in the $50,000,000 Credit Agreement among Flores & Rucks, Inc. and Chase
Manhattan Bank, N.A.) (the "Credit Agreement"), can redetermine the borrowing
base at its option once within any 12-month period as well as on scheduled
redetermination dates as outlined in the Credit Agreement. The borrowing base
automatically reduces by an amount equal to one-sixteenth (1/16) of the
borrowing base in effect on each quarter beginning March 31, 1998, unless the
Company requests and is granted a one-year deferral of such reductions. In
addition, the borrowing base may be reduced if the Company sells a portion of
its oil and gas properties. As of December 31, 1996, the borrowing base under
the Revolving Credit Facility remained at $50 million.
As of February 24, 1997, the Company was in the process of amending and
restating its Revolving Credit Facility and had obtained commitments from all
lenders which will increase the facility size to $150 million and the borrowing
base to $100 million.
45
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company's ability to draw additional amounts on the Revolving Credit
Facility is limited to the extent that adjusted consolidated net tangible assets
(as defined in the Credit Agreement) minus $25 million exceeds 110% of all
indenture indebtedness (as defined in the Credit Agreement), excluding
subordinated indebtedness. Adjusted consolidated net tangible assets is
determined quarterly, utilizing certain financial information, and is primarily
based on a quarterly estimate of the present value of future net revenues of the
Company's proved oil and gas reserves. Such quarterly estimates utilize the
most recent year end oil and gas prices and vary based on additions to proved
reserves and net production. As of December 31, 1996, the Company's outstanding
balance was $2.0 million, all of which represented letters of credit, primarily
associated with bonding for future abandonment obligations, and thus the Company
had remaining availability of $48.0 million.
At the Company's option, borrowings under the Revolving Credit Facility
bear interest either at the base rate (the higher of the federal funds rate plus
0.5% per annum or the Agent's prime commercial lending rate) or the London
Interbank Offered Rate ("LIBOR"), in each case plus the applicable margin. The
applicable margin will be from 125 to 175 basis points for LIBOR loans and from
zero to 50 basis points for the base rate loans.
The loan agreement for the Revolving Credit Facility contains restrictive
covenants substantially similar to those for the Senior Notes. The Revolving
Credit Facility also includes certain additional covenants and restrictions
relating to the activities of the Company which are customary for similar credit
facilities and are not expected to have a material adverse effect on the conduct
of the Company's business.
The Indentures relating to the Senior Notes and the Senior Subordinated
Notes contain certain covenants, including, with limitation, covenants with
respect to the following matters: (i) limitation on indebtedness; (ii)
limitation on restricted payments; (iii) limitation on issuances and sales of
restricted subsidiary stock; (iv) limitation on sale/leaseback transactions; (v)
limitation on transactions with affiliates; (vi) limitation on liens; (vii)
disposition of proceeds of asset sales; (viii) limitation on dividends and other
payment restrictions affecting subsidiaries; and (ix) limitation of mergers,
consolidations and transfers of assets. In addition, the Indenture related to
the Senior Notes includes a covenant with respect to maintenance of adjusted
consolidated net tangible assets, as defined.
Aggregate minimum principal payments for debt and the capital lease at
December 31, 1996, for the next five years are as follows:
1997 $127,154
1998 -
1999 -
2000 -
2001 -
--------
$127,154
========
On June 11, 1994, LLC entered into two loan agreements with Joint Energy
Development Investments Limited Partnership ("JEDI"), a venture between
California Public Employees Retirement System and Enron Capital Corp. The first
was a $20 million term loan, bearing interest at 12.5% payable monthly, maturing
on June 11, 1997. The second loan, the development loan, provided for draws up
to a maximum of $40 million, bearing interest at 15% payable monthly. In
connection with this loan, LLC conveyed to JEDI a 20% overriding royalty
interest (defined to be net of production costs) on certain unevaluated
interests (computed prior to the one-eighth override conveyed to a related party
discussed in Note 3) which commenced upon payment in full of the development
loan. This interest was purchased from JEDI in December 1994, for $4.25
million. Proceeds from the Initial Offerings were used to repay these loans in
December 1994.
46
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
10. EMPLOYEE BENEFIT PLANS
The Company has a 401(K) plan which covers all employees. The Company's
contributions to the plan during 1996, 1995 and 1994 were $521,619, $513,690 and
$432,202, respectively.
Stock-Based Compensation Plans
In October 1995, the FASB issued Statement of Financial Accounting
Standards No. 123 ("SFAS 123"), "Accounting for Stock-Based Compensation,"
effective for the Company for 1996. Under SFAS 123, companies can either record
expense based on the fair value of stock-based compensation upon issuance or
elect to remain under the current "APB Opinion No. 25" method whereby no
compensation cost is recognized upon grant if certain requirements are met. The
Company is continuing to account for its stock-based compensation plans under
APB Opinion No. 25. However, proforma disclosures as if the Company adopted the
cost recognition requirements under SFAS 123 are presented below.
Had compensation for the Company's 1996 and 1995 grants for stock-based
compensation plans been determined consistent with SFAS 123, the Company's net
income and earnings per common share for the years ended December 31, 1996 and
1995 would have approximated the proforma amounts below:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------------------
1996 1995
------------------------ -----------------------
AS REPORTED PROFORMA AS REPORTED PROFORMA
----------- ----------- ----------- ----------
<S> <C> <C> <C> <C>
Net income $20,950,805 $19,544,426 $9,902,295 $9,779,272
Earnings per common share
Primary $ 1.07 $ 1.00 $ .65 $ .65
Fully diluted 1.05 0.98 .65 .64
</TABLE>
The effects of applying SFAS 123 in this proforma disclosure are not
indicative of future amounts. SFAS 123 does not apply to grants prior to 1995,
and additional awards in the future are anticipated.
Prior to consummation of the Initial Offerings, the Board of Directors
adopted and the stockholders approved a long-term incentive plan. The plan
provides for not more than 1,500,000 shares of common stock to be issued to
employees and directors of the Company. In 1995, the Board of Directors also
adopted and the stockholders approved a long-term incentive plan for non-
executive employees. This plan has an evergreen provision which replenishes
options available for grant to 300,000 on January 1 of each year. In 1996,
pending approval of the stockholders at the Annual Meeting, the Board of
Directors adopted a plan which provides for not more than 1,000,000 shares of
common stock to be issued to employees of the Company. Upon consummation of the
Initial Offerings, the Company issued 645,000 stock options with an exercise
price of $10.00 per share, the fair value at the date of grant. The options
vest equally over a three-year period and terminate ten years from date of
grant. A summary of the Company's stock options under both plans as of December
31, 1996 and 1995 and changes during the years ended on those dates is presented
below:
47
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------------------
1996 1995
------------------------ ------------------------
NUMBER OF WGTD. AVG. NUMBER OF WGTD. AVG.
OPTIONS EXER. PRICE OPTIONS EXER. PRICE
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Outstanding at beginning of year 1,495,500 $11.13 645,000 $10.00
Granted 693,500 24.91 856,500 11.97
Canceled (195,167) 11.09 (6,000) 9.38
Exercised (96,531) 10.06 - -
---------- ----------
Outstanding at end of year 1,897,302 $16.23 1,495,500 $11.13
Options exercisable at year-end 565,580 $11.01 261,667 $10.31
Options available for future grant 542 131,042
Weighted average fair value of
options granted during the year $11.48 $4.66
</TABLE>
The fair value of each option granted during the periods presented is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following assumptions: (i) dividend yield of 0%, (ii) expected volatility of
41.16% and 35.07% in the years 1996 and 1995, respectively, (iii) risk-free
interest rate of 6.21% and 5.58% in the years 1996 and 1995, respectively, and
(iv) expected life of 5 years.
The following table summarizes information about stock options outstanding
at December 31, 1996:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------------- ----------------------
RANGE OF NUMBER WGTD. AVG. WGTD. AVG. NUMBER WGTD AVG.
EXERCISE OUTSTANDING REMAINING EXERCISE EXERCISABLE EXERCISE
PRICES AT 12/31/96 CONTRACTUAL LIFE PRICE AT 12/31/96 PRICE
-------- ----------- ---------------- ---------- ----------- ---------
<S> <C> <C> <C> <C> <C>
$9 - $19 1,214,802 8 11.26 565,580 11.01
$19 - $29 389,500 10 19.40 - -
$29 - $39 293,000 10 32.59 - -
--------- -- ----- ----------- ---------
$9 - $39 1,897,302 9 16.23 565,580 11.01
========= == ===== =========== =========
</TABLE>
In addition, in 1995, the Company issued 4,125 shares of stock which are
considered bonus shares.
The Company is self-insured for employee medical benefits up to certain
stop-loss limits.
The Company has no other significant formal benefit plans.
48
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
11. MAJOR CUSTOMERS
The Company sold the majority of its oil and gas to a few customers based
on long-term contracts in 1996 and prior years. Sales to the following customers
exceeded 10% of revenues during the years indicated (expressed in thousands):
<TABLE>
<CAPTION>
1996 1995 1994
-------- ------- -------
<S> <C> <C> <C>
Enron Corp., its subsidiaries and affiliates $ 33,074 $17,431 $73,658
Shell Oil Company 110,131 79,927 -
Murphy Oil USA, Inc. 23,338 24,193 -
</TABLE>
12. COMMITMENTS AND CONTINGENCIES
While the Company is a defendant in various lawsuits in the ordinary course
of business, management believes the potential liability in such lawsuits is not
material. The Company maintains liability and other insurance customary in its
industry. The Company is also subject to contingencies as a result of
environmental laws and regulations. The related future cost is indeterminable
due to such factors as the unknown timing and extent of the corrective actions
that may be required and the application of joint and several liability.
However, the Company believes that such costs will not have a material adverse
effect on its operations or financial position.
The Company, as operator, is responsible for payment of plugging and
abandonment costs on its properties. As of December 31, 1996, the total estimate
of these costs on the Company's oil and gas properties was approximately $84.0
million, estimated to be incurred through the year 2011. The provision for such
costs is recorded through depreciation, depletion and amortization expense. The
estimates of plugging and abandonment costs and their timing may change due to
many factors including, among others, actual production results, inflation
rates, and changes in environmental laws and regulations.
In August 1993, the Minerals Management Service ("MMS") provided notice to
lessees of Outer Continental Shelf ("OCS") leases that new levels of lease and
area wide bonds would be required effective November 26, 1993, in connection
with the plugging and abandoning of wells located offshore and the removal of
all production facilities. The coverage is designed to reflect an appropriate
balance between encouraging the maximum economic recovery of oil and natural gas
from federal offshore leases while providing the federal government an adequate
level of protection in the event the lessee defaults on its obligations to
properly abandon lease wells and remove platforms and other structures from the
property.
The MMS requires lessees of OCS properties to post bonds in connection with
the plugging and abandonment of wells located offshore and the removal of all
production facilities. Operators in the OCS waters of the Gulf of Mexico are
currently required to post area wide bonds of $3 million or $500,000 per
producing lease and supplemental bonds at the discretion of the MMS. On January
17, 1995, the Company entered into an agreement with Planet Indemnity Company
("Planet") whereby Planet agreed to issue $11.7 million of MMS surety bonds for
the Company and the Company agreed to post collateral for same in favor of
Planet. The collateral includes a mortgage on the Company's federal OCS leases
in the amount of $8.2 million, a letter of credit for $2.0 million and a pledge
of certain rights to escrowed funds. The Company has posted with the MMS an
area wide bond of $3.0 million and supplemental bonds totaling $17.1 million.
Pursuant to a schedule previously imposed by the MMS, the Company will be
required to post additional supplemental bonds up to a level of $24.6 million by
January 1999, unless the Company is determined by the MMS to be exempt from such
requirement due to certain financial tests. In addition, the Company is
currently working with the MMS to determine the level of supplemental bonding
(and the timing thereof) which will be required for some of the recently
acquired Central Gulf Properties. The Company does not anticipate that the cost
of any such bonding requirements will materially affect the Company's financial
position. Under certain circumstances, the MMS may require any Company
operations on federal leases to be suspended or terminated. Any such
suspensions or terminations could
49
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
have a material adverse effect on the Company's financial condition and
operations. The MMS also intends to adopt financial responsibility regulations
under the Oil Pollution Act of 1990 (the "OPA"). The OPA regulations impose a
variety of regulations on "responsible parties" related to the prevention of oil
spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of an area in which an offshore facility is
located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. While liability limits apply
in some circumstances, a party cannot take advantage of liability limits if the
spill was caused by gross negligence or willful misconduct or resulted from
violation of a federal safety, construction or operating regulation. If the
party fails to report a spill or to cooperate fully in the cleanup, liability
limits likewise do not apply. Few defenses exist to the liability imposed by the
OPA.
The OPA also imposes ongoing requirements on a responsible party, including
proof of financial responsibility to cover at least some costs in a potential
spill. As amended by the Coast Guard Authorization Act of 1996, OPA requires
responsible parties for offshore facilities to provide financial assurance in
the amount of $35 million to cover potential OPA liabilities. This amount is
subject to upward regulatory adjustment up to $150 million.
In 1996, Statement of Position 96-1 ("SOP 96-1") - Environmental
Remediation Liabilities was issued. The Company is required to adopt SOP 96-1 in
1997. The Company believes adoption of SOP 96-1 will not have a material effect
on its results of operations or financial position.
Total rental expenses under operating leases amounted to approximately
$690,000, $527,000 and $297,000 in 1996, 1995 and 1994, respectively.
In connection with the Initial Offerings, the Company entered into a
Registration Rights Agreement (the "Registration Agreement") entitling Enron to
require the Company to register common stock of the Company owned by Enron with
the Securities and Exchange Commission (the "SEC") for sale to the public in a
public offering, at no cost to Enron except for discounts and commissions, if
any. During 1996, the unregistered shares subject to the Registration Agreement
were transferred by Enron to Merrill Lynch Capital Markets, plc., together with
Enron's rights under the Registration Agreement.
13. HEDGING ACTIVITIES
The Company hedges certain of its production through master swap agreements
("Swap Agreements"). The Swap Agreements provide for separate contracts tied to
the NYMEX light sweet crude oil and natural gas futures contracts. The Company
has contracts which contain specific contracted prices ("Swaps") that are
settled monthly based on the differences between the contract prices and the
average NYMEX prices for each month applied to the related contract volumes. To
the extent the average NYMEX price exceeds the contract price, the Company pays
the spread, and to the extent the contract price exceeds the average NYMEX price
the Company receives the spread. In addition, the Company has combined
contracts which have agreed upon price floors and ceilings ("Costless Collars").
To the extent the average NYMEX price exceeds the contract ceiling, the Company
pays the spread between the ceiling and the average NYMEX price applied to the
related contract volumes. To the extent the contract floor exceeds the average
NYMEX price, the Company receives the spread between the contract floor and the
average NYMEX price applied to the related contract volumes. Under the terms of
the Swap Agreements, each counterparty has extended the Company a $5 million
line of credit for use in conjunction with its hedging activities. As of
February 24, 1997, the fair market value of all contracts covered by the
Swap Agreements was approximately $0.6 million.
50
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
As of December 31, 1996, after giving effect to three additional oil Swaps
that the Company entered into in February 1997, the Company's open forward
position on its outstanding crude oil Swaps was as follows:
<TABLE>
<CAPTION>
AVERAGE
YEAR MBBLS PRICE
------- ----- -------
<S> <C> <C>
1997 1,500 $19.73
1998 300 18.55
1999 300 18.55
2000 300 18.55
----- ------
2,400 $19.29
===== ======
</TABLE>
The Company currently has no outstanding natural gas Swaps.
As of December 31, 1996, after giving effect to three additional Costless
Collars entered into through February 24, 1997, the Company's open forward
position on its outstanding Costless Collars was as follows:
<TABLE>
<CAPTION>
EFFECTIVE CONTRACTED CONTRACTED CONTRACTED
------------------ VOLUMES FLOOR CEILING
YEAR FROM THROUGH (MBBLS) PRICE PRICE
---- ------- --------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C>
1997 January March 600 $21.00 $24.45
1997 January June 1,200 $20.00 $24.25
1997 April June 375 $20.00 $25.14
1997 July September 900 $20.00 $24.40
</TABLE>
Revenue was increased (decreased) under the Swap Agreements by
approximately $(18.7) million, $(0.5) million and $1.7 million, respectively,
for the years ended December 31, 1996, 1995 and 1994.
14. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair value as of December 31, 1996 and 1995, of financial
instruments other than current assets and liabilities is presented in the
following table:
<TABLE>
<CAPTION>
AS OF DECEMBER 31
--------------------------------------------------------------
1996 1995
------------------------------ ------------------------------
ESTIMATED ESTIMATED
BOOK VALUE FAIR VALUE BOOK VALUE FAIR VALUE
-------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Debt
Senior Notes $(125,000,000) $(149,375,000) $(125,000,000) $(141,875,000)
Senior Subordinated Notes (159,141,999) (168,690,519) - -
Shell Note - - (15,183,735) (15,094,232)
Revolving Credit Facility - - (32,200,000) (32,200,000)
------------- ------------- ------------- -------------
$(284,141,999) $(318,065,519) $(172,383,735) $(189,169,232)
============= ============= ============= =============
Hedges
Gas $ - $ - $ - $ (2,423,240)
Oil - (4,555,720) - 950,750
------------- ------------- ------------- -------------
$ - $ (4,555,720) $ - $ (1,472,490)
============= ============= ============= =============
</TABLE>
51
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
15. OIL AND GAS RESERVE INFORMATION - UNAUDITED
The Company's net proved oil and gas reserves at December 31, 1996, 1995
and 1994, have been determined by independent petroleum consultants in
accordance with guidelines established by the SEC and the Financial Accounting
Standards Board. Accordingly, the following reserve estimates are based upon
existing economic and operating conditions at the respective dates. Future cash
flows from oil and natural gas reserves were computed on the basis of prices
being received at year end for oil and natural gas, adjusted for hedges in place
at that date and the Company's policy regarding fuel gas.
There are many uncertainties inherent in estimating quantities of proved
reserves and in providing the future rates of production and timing of
development expenditures. The following reserve data represent estimates only
and should not be construed as being exact. In addition, the present values
should not be construed as the current market value of the Company's oil and gas
properties or the cost that would be incurred to obtain equivalent reserves.
The following tables set forth an analysis of the Company's estimated
quantities of net proved and proved developed oil (includes condensate) and gas,
all located offshore in the continental United States:
<TABLE>
<CAPTION>
OIL NATURAL GAS (1)
(MBBL) (MMCF)
------- ---------------
<S> <C> <C>
Proved reserves as of December 31, 1993 21,093 52,724
Revisions of previous estimates 1,979 7,294
Extensions, discoveries, and other additions 688 2,775
Repurchase of production payment 6,111 19,523
Purchase of producing properties 5,944 7,708
Production (sold by the Company) (2,771) (3,456)
Production (consumed by the Company) - (3,220)
------ -------
Proved reserves as of December 31, 1994 33,044 83,348
Revisions of previous estimates 4,857 9,093
Extensions, discoveries, and other additions 1,640 10,647
Purchase of producing properties 345 85
Production (sold by the Company) (6,057) (12,393)
Production (consumed by the Company) - (3,576)
------ -------
Proved reserves as of December 31, 1995 33,829 87,204
Revisions of previous estimates 2,546 23,935
Extensions, discoveries, and other additions 9,766 31,060
Sale of producing properties (450) (9,929)
Purchase of producing properties 12,234 35,171
Production (sold by the Company) (7,149) (18,720)
Production (consumed by the Company) - (3,363)
------ -------
Proved reserves as of December 31, 1996 50,776 145,358
====== =======
Proved developed reserves:
As of December 31, 1994 30,088 77,019
As of December 31, 1995 31,702 84,258
As of December 31, 1996 38,347 109,574
</TABLE>
(1) The Company includes as proven reserves, future gas production estimated by
Netherland, Sewell & Associates, Inc., to be used as fuel gas.
52
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following table presents the standardized measure of future net cash
flows related to proved oil and gas reserves together with changes therein, as
defined by the Financial Accounting Standards Board. The oil, condensate and gas
price structure utilized to project future net cash flows reflects current
prices at each year end and have been escalated only where known and
determinable price changes are provided by contracts and law. Crude prices have
declined significantly from December 31, 1996. Accordingly, the discounted
future net cash flows would be reduced if the standardized measure was
calculated at the latter date. Future production and development costs are based
on current costs with no escalations. Estimated future cash flows have been
discounted to their present values based on a 10% annual discount rate.
<TABLE>
<CAPTION>
STANDARDIZED MEASURE AS OF DECEMBER 31,
------------------------------------------
1996 1995 1994
------------ --------------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash flows $1,789,544 $ 762,488 $ 645,091
Future production, development and abandonment costs (907,770) (482,658) (433,193)
Income tax provision (204,733) (36,712) (11,530)
---------- --------- ---------
Future net cash flows 677,041 243,118 200,368
10% annual discount (144,549) (39,178) (35,390)
---------- --------- ---------
Standardized measure of discounted future net cash flows $ 532,492 $ 203,940 $ 164,978
========== ========= =========
CHANGES IN STANDARDIZED MEASURE
PERIODS ENDED DECEMBER 31,
----------------------------------------
1996 1995 1994
---------- --------- ---------
(IN THOUSANDS)
Standardized measure at beginning of period $ 203,940 $ 164,978 $ 13,175
Sales and transfers of oil and gas produced, net of
production costs (159,361) (87,924) (21,214)
Changes in price, net of future production costs 242,943 61,865 34,412
Extensions and discoveries, net of future production
and development costs 215,013 46,429 14,397
Repurchase of production payment - - 106,572
Reserves transferred for resale (10,009) - -
Previously estimated development and abandonment
costs incurred during the period 10,453 19,132 8,606
Revisions of quantity estimates 88,994 46,761 8,184
Accretion of discount 20,394 17,474 2,352
Net change in income taxes (130,226) (21,034) (9,762)
Purchase of reserves in place 123,284 3,193 17,564
Changes in production rates (timing), estimated
development and abandonment costs, and other (72,933) (46,934) (9,308)
---------- --------- ---------
Standardized measure at end of year $ 532,492 $ 203,940 $ 164,978
========== ========= =========
</TABLE>
53
<PAGE>
FLORES & RUCKS, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
16. QUARTERLY FINANCIAL DATA- UNAUDITED
Summarized unaudited quarterly financial data for 1996 and 1995 are as
follows:
<TABLE>
<CAPTION>
QUARTER ENDED
-----------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1996 1996 1996 1996
---------- ------------- ------------- ------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
Net sales 36,829 32,253 47,589 71,780
Gross profit 11,147 6,918 16,487 32,148
Net income 1,901 435 5,363 13,252
Earnings per common share:
Primary $ .12 $ .02 $ .26 $ .63
Fully diluted $ .12 $ .02 $ .26 $ .63
QUARTER ENDED
-----------------------------------------------------
MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
1996 1996 1996 1996
---------- ------------- ------------- ------------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
Net sales 26,034 29,838 34,609 37,489
Gross profit 6,354 7,381 8,089 12,016
Net income (loss) (1,062) 811 1,052 9,101
Earnings per common share:
Primary $ (.07) $ .05 $ .07 $ .60
Fully diluted $ (.07) $ .05 $ .07 $ .59
</TABLE>
17. EVENTS SUBSEQUENT TO DATE OF AUDITOR'S REPORT - UNAUDITED
On March 7, 1997, the Company completed an acquisition of certain interests
in various state leases in the Main Pass 69 field, offshore Plaquemines Parish,
Louisiana, from Chevron U.S.A. Inc. for a gross purchase price of $55.7 million.
The acquisition includes interests in 27 producing wells located on 5,898 gross
acres. Post acquisition, the Company owns a 100% working interest in the 27
wells. Current estimated production from the newly acquired interest is
approximately 3,000 BOE per day net to the Company. The Company's ownership now
encompasses a total of approximately 22,000 gross acres in the Main Pass 69
field.
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
54
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is partially included under Item 4A
of this Form 10-K with the remainder of the required information incorporated by
reference from the sections entitled "Management" and "Section 16(a) Beneficial
Ownership Reporting Compliance" in the Company's definitive Proxy Statement for
its 1997 Annual Meeting of Stockholders (the "Proxy Statement") to be filed with
the Securities and Exchange Commission no later than April 30, 1997.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated by reference from the
section entitled "Executive Compensation" in the Proxy Statement. Nothing in
this report shall be construed to incorporate by reference the Board
Compensation Committee Report on Executive Compensation or the Performance Graph
which are contained in the Proxy Statement, but expressly not incorporated
herein.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item is incorporated by reference from the
section entitled "Security Ownership of Certain Beneficial Owners and
Management" in the Proxy Statement.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is incorporated by reference from the
section entitled "Certain Relationships and Other Transactions" in the Proxy
Statement.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) Financial Statements and Supplementary Data, Financial Statement
Schedules and Exhibits
<TABLE>
<CAPTION>
<S> <C>
1. Consolidated Financial Statements
Page
--
Report of Independent Public Accountants 31
Consolidated Balance Sheets 32
Consolidated Statements of Operations 33
Consolidated Statements of Stockholders' Equity 34
Consolidated Statements of Cash Flows 35
Notes to Consolidated Financial Statements 36
</TABLE>
2. Consolidated Financial Statement Schedules
All consolidated financial statement schedules have been omitted
because they are not required, are not applicable or the information
required has been included elsewhere herein.
55
<PAGE>
3. Exhibits and Financial Statement Schedules (except as otherwise
designated below, all exhibits have been previously filed.)
a. Exhibits
3.1 Certificate of Incorporation of the Company (filed as Exhibit
3.1 to the Company's Registration Statement on Form S-1
(33-84308) and incorporated herein by reference)
3.2 Bylaws of the Company (filed as Exhibit 3.3 to the Company's
Registration Statement on Form S-1 (33-84308) and incorporated
herein by reference)
4.1 Indenture among the Company, FRI Louisiana and Shawmut Bank
Connecticut, National Association, as Trustee, relating to the
13 1/2% Senior Notes due 2004 (filed as Exhibit 4.1 to the
Company's Annual Report on Form 10-K for the year ended December
31, 1994 and incorporation herein by reference)
4.2 First Supplemental Indenture, dated as of September 19, 1996,
among the Company, the Subsidiary Guarantors named therein, and
Fleet National Bank (formerly Shawmut Bank Connecticut, National
Association), as Trustee (filed as Exhibit 4.1 to the Company's
Current Report on Form 8-K dated September 26, 1996, and
incorporated herein by reference)
4.3 Indenture among the Company, the Subsidiary Guarantors named
therein and Fleet National Bank, as Trustee relating to the 9
3/4% Senior Subordinated Notes due 2006 (filed as Exhibit 4.1 to
the Company's Quarterly Report Form 10-Q for the quarter ended
September 30, 1996 and incorporated herein by reference).
*10.1 1994 Long-Term Incentive Plan (filed as Exhibit 10.3 to the
Company's Registration Statement on Form S-1 (33-84308) and
incorporated herein by reference)
*10.2 Form of Indemnification Agreement among the Company and certain
executive officers (filed as Exhibit 10.5 to the Company's
Registration Statement on Form S-1 (33-84308) and incorporated
herein by reference)
10.3 Credit Agreement among FRI Louisiana and certain lenders in the
amount of $50,000,000, as amended (filed as Exhibit 10.3 to the
Company's Annual Report on Form 10-K for the year ended December
31, 1994 and incorporated herein by reference)
10.3.1 Amendment to Credit Agreement dated December 20, 1995
10.3.2 Second Amendment to Credit agreement, dated August 14, 1996
(filed as Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1996 and incorporated
herein by reference)
10.4 Mortgage, Assignment of Production, Security Agreement and
Financing Statement (filed as Exhibit 10.4 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1994
and incorporation herein by reference)
*10.5 Assignment and Bill of Sale between FRI Louisiana (as assignor),
Franks Petroleum, Inc. (as assignee), and Sable Minerals, Inc.
dated May 22, 1992, as amended by that Act of Correction dated
December 14, 1992 (filed as Exhibit 10.25 to the Company's
Registration Statement on Form S-1 (33-84308) and incorporated
herein by reference)
*10.6 Assignment and Bill of Sale between FRI Louisiana (as assignor),
Franks Petroleum, Inc. (as assignee), and Sable Minerals, Inc.
dated June 9, 1993 (state leases, private leases and BLM lease)
(filed as Exhibit 10.26 to the Company's Registration Statement
on Form S-1 (33-84308) and incorporated herein by reference)
*10.7 Assignment of Record Title Interest in a Lease for Oil and
Gas or Geothermal Resources between FRI Louisiana (as assignor),
and Franks Petroleum, Inc. and Sable Minerals, Inc. (as
assignees) dated May 12, 1993 (BLM Form) (filed as Exhibit 10.27
to the Company's Registration Statement on Form S-1 (33-84308)
and incorporated herein by reference)
*10.8 Overriding Royalty Assignment and Bill of Sale between FRI
Louisiana (as assignor) and Sable Minerals, Inc. (as assignee)
dated June 9, 1993 (OCS leases) (filed as Exhibit 10.28 to the
Company's Registration Statement on Form S-1 (33-84308) and
incorporated herein by reference)
10.9 Pledge of Production Proceeds and Trust Agreement dated May
12, 1992, by and among Shell Offshore, Inc., FRI Louisiana and
First National Bank of Commerce, New Orleans, Louisiana (filed
as Exhibit 10.31 to the Company's Registration Statement on Form
S-1 (33-84308) and incorporated herein by reference)
56
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10.10 Pledge of Production Proceeds and Trust Agreement dated May
12, 1993, by and among Shell Offshore, Inc., FRI Louisiana and
First National Bank of Commerce, New Orleans, Louisiana (filed
as Exhibit 10.32 to the Company's Registration Statement on Form
S-1 (33-84308) and incorporated herein by reference)
10.11 Registration Rights Agreement of Enron Finance Corp. (filed as
Exhibit 10.14 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1994 and incorporation herein by
reference)
10.12 Waiver and Amendment of Registration Rights Agreement,
effective as of December 7, 1994
10.13 Second Amendment to Registration Rights Agreement, dated
August, 1996, among the Company, FRI Louisiana, Enron Finance
Corp. and Merrill Lynch Capital Markets plc
10.14 Indenture Assumption Agreement by FRI Louisiana in favor of the
Company (Senior Notes) (filed as Exhibit 10.15 to the Company's
Annual Report on Form 10-K for the year ended December 31, 1994
and incorporation herein by reference)
10.15 Indenture Assumption Agreement by FRI Louisiana in favor of the
Company (Senior Subordinated Notes)
10.16 Crude Oil Purchase Contract, dated May 12, 1993, between FRI
Louisiana and Shell Oil Company, as amended (filed as Exhibit
10.16 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1994 and incorporation herein by reference)
10.17 MMS Bonding Agreement, dated January 17, 1995, between FRI
Louisiana and Planet Indemnity Company, with related Act of
Mortgage and Financing Statement (filed as Exhibit 10.17 to the
Company's Annual Report on Form 10-K for the year ended December
31, 1994 and incorporation herein by reference)
10.18 Modification Agreement effective May 1, 1996 to that MMS Bonding
Agreement, dated January 17, 1995, between FRI Louisiana and
Planet Indemnity Company (filed as Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the quarter ended June 30,
1996 and incorporated herein by reference)
10.19 Gas Purchase Agreement, dated January 1, 1995, between FRI
Louisiana and Enron Capital & Trade Resources Corp. (filed as
Exhibit 10.18 to the Company's Annual Report on Form 10-K for
the year ended December 31, 1994 and incorporation herein by
reference)
*10.20 Form of Employment Agreement entered into between the Company
and Robert L. Belk, Robert K. Reeves, David J. Morgan and
Richard G. Zepernick, Jr., effective as of September 1, 1995
(filed as Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1995 and incorporated
herein by reference)
*10.21 Form of First Amendment to Employment Agreements dated May 8,
1996 and effective as of September 1, 1995 (filed as Exhibit
10.2 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1996 and incorporated herein by
reference)
*10.22 Form of Second Amendment to Employment Agreements dated
December 6, 1996
21.1 Subsidiaries of Registrant (filed as Exhibit 21.1 to the
Company's Annual Report on Form 10-K for the year ended December
31, 1995 and incorporated herein by reference)
+23.1 Consent of Arthur Andersen, LLP
+23.2 Consent of Netherland, Sewell & Associates, Inc.
27.1 Financial Data Schedule
*Management contract or compensatory plan.
+Filed herewith.
57
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
FLORES & RUCKS, INC.
By: /s/ Robert K. Reeves
--------------------------------
Robert K. Reeves
Senior Vice President,
General Counsel and Secretary
Date: May 6, 1997
58
<PAGE>
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference of our report included in this Form 10-KA, into Flores & Rucks,
Inc.'s previously filed Registration Statements on Form S-8 (File Nos. 33-89516,
33-94704, and 33-97154).
Original Signed by Arthur Andersen LLP
--------------------------------------
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
May 6, 1997
<PAGE>
EXHIBIT 23.2
[NSA LOGO APPEARS HERE]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
---------------------------------------------------------
We hereby consent to the reference to our firm and to our reports
effective December 31, 1994; December 31, 1995; and December 31, 1996, and to
the use of our reports in the Annual Report of Flores & Rucks, Inc. on Form
10-KA for the year ended December 31, 1996 to be filed with the Securities and
Exchange Commission on or about May 7, 1997.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: Original Signed by Frederic D. Sewell
-----------------------------------------
Frederic D. Sewell
President
Dallas, Texas
May 6, 1997
