UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001
Or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE TRANSITION PERIOD
FROM TO COMMISSION FILE NUMBER 333-31375*
ASCENT ENERGY INC.
(Exact name of registrant as specified in its charter)
DELAWARE 72-1493233
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
1700 REDBUD BOULEVARD, SUITE 450 MCKINNEY,
TEXAS 75069 (972) 547-7150
(Address of principal executive (Registrant's telephone number
offices)(Zip Code) including area code)
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: NONE
THIS FILING CONTAINS UNAUDITED FINANCIAL STATEMENTS IN LIEU OF AUDITED FINANCIAL
STATEMENTS BECAUSE THE REGISTRANT WAS UNABLE TO OBTAIN FROM ARTHUR ANDERSEN LLP
A MANUALLY SIGNED REPORT. PLEASE SEE PAGE F-1 INCLUDED HEREIN FOR ADDITIONAL
INFORMATION.
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 [ ]
As of March 20, 2002, there were 4,950,000 shares of the Registrant's Common
Stock, $0.001 par value per share, outstanding.
* The Commission file number refers to a Form S-4 Registration Statement filed
by the Company under the Securities Act of 1933, which became effective June 29,
2001.
ASCENT ENERGY INC.
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2001
TABLE OF CONTENTS
<Table>
PART I 1
ITEM 1. BUSINESS 1
ITEM 2. PROPERTIES 13
ITEM 3. LEGAL PROCEEDINGS 14
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 14
PART II 15
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 15
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA 16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 17
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 25
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 27
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 27
PART III 28
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 28
ITEM 11. EXECUTIVE COMPENSATION 29
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 31
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 32
PART IV. 33
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 33
</Table>
ii
PART I
ITEM 1. BUSINESS
OVERVIEW
Ascent Energy Inc. ("Ascent," "we" or "us") is an independent energy
company engaged in the acquisition, exploitation, exploration, development and
production of natural gas and crude oil. Through our predecessor, we have been
active in South Louisiana since 1982. We were organized on January 9, 2001 by
the majority stockholders of our predecessor principally to facilitate the
acquisition of Pontotoc Production, Inc. ("Pontotoc"). In July, 2001, prior to
the consummation of the acquisition of Pontotoc, our predecessor was
restructured as a holding company by contributing to us all of its assets and
liabilities. We refer to this transaction as the "Restructuring." The
Restructuring is accounted for using reorganization accounting for entities
under common control, which results in retroactive restatement of all periods
presented to reflect the Restructuring as if it had occurred at the beginning of
the earliest period presented. The accompanying financial statements include the
accounts of our predecessor and Ascent prior to the Restructuring.
RECENT DEVELOPMENTS
Ascent Energy Inc. ("Ascent," "we" or "us") is an independent energy
company engaged in the acquisition, exploitation, exploration, development and
production of natural gas and crude oil. Through our predecessor, we have been
active in South Louisiana since 1982. We were organized on January 9, 2001 by
the majority stockholders of our predecessor principally to facilitate the
acquisition of Pontotoc Production, Inc. ("Pontotoc").
Our business strategy is to increase production, cash flow and reserves through
the acquisition and development of mature properties. Currently, our property
base consists of 679 active properties, 30 in South Louisiana and 625 shallow
wells in Pontotoc County, Oklahoma, and 24 wells in South Texas. We serve as
operator on the majority of our active properties, which enables us to better
control the timing and cost of rejuvenation activities. We are headquartered in
McKinney, Texas, with additional offices in New Orleans, Louisiana, and Ada,
Oklahoma.
The consolidated financial statements include our accounts and the accounts of
our subsidiaries. The subsidiaries include Pontotoc Acquisition Corp., Pontotoc
Production Company, Inc., Oklahoma Basic Economy Corporation, Pontotoc Holdings,
Inc. and Pontotoc Gathering, L.L.C. All significant inter-company balances have
been eliminated. Certain prior year amounts have been reclassified to conform to
current year presentation.
Restructuring
In July, 2001, prior to the consummation of the acquisition of Pontotoc, our
predecessor was restructured as a holding company by contributing to us all of
its assets and liabilities. We refer to this transaction as the "Restructuring."
The Restructuring is accounted for using reorganization accounting for entities
under common control, which results in retroactive restatement of all periods
presented to reflect the Restructuring as if it had occurred at the beginning of
the earliest period presented. The accompanying consolidated financial
statements include the accounts of our predecessor and Ascent prior to the
Restructuring.
Pontotoc Acquisition
On July 31, 2001, we acquired approximately 91% of Pontotoc's outstanding common
stock. Subsequently, we acquired the remaining Pontotoc shares on August 14,
2001 in the second-step of the merger and merged Pontotoc into one of our
wholly-owned subsidiaries. The purchase price for all the outstanding Pontotoc
common stock was approximately $48.5 million in cash and 5,323,695 shares of our
Series B mandatorily convertible preferred stock. These shares were valued at
$0.49 per share based on the trading price of Pontotoc's common stock for the
five trading days prior to and following the date of the merger agreement.
1
We financed the cash portion of the purchase price for the Pontotoc acquisition
through:
o borrowing $30 million under our credit facility;
o a portion of the proceeds from the private sale for $21.1 million of shares
of our Series A redeemable preferred stock and warrants to purchase
approximately 4.1 million shares of our common stock; and
o existing internal cash resources.
The proceeds from the sale of our Series A redeemable preferred stock were
approximately $21.1 million. We are required to redeem our Series A redeemable
preferred stock at 100% of its liquidation preference, or $21.1 million (plus
any unpaid dividends), in July 2006.
Devo Merger
On September 28, 2001, we acquired Devo Holding Company, LLC ("Devo") in a
statutory merger under Delaware law. The assets of Devo and its subsidiary, Devo
Operating Company, LLC, consist primarily of South Texas oil and gas producing
properties. We issued $75.0 million in principal amount of our unsecured 11 3/4%
Senior Notes due April 30, 2006 (the "Notes") in a private transaction in
connection with the Devo acquisition, at approximately a 1% discount.
Approximately $65.7 million of the Notes were issued to Devo's note holders in
exchange for all of the principal and accrued interest outstanding under Devo's
Senior Notes due 2003. Approximately $6.5 million of the Notes were issued to
Devo's equity holders as consideration in the Devo acquisition. Jefferies &
Company, Inc. (See Note 12 -Related Party Transactions) received approximately
$2.8 million of the Senior Notes as a financial advisory fee in connection with
the Devo acquisition and for the placement of the Senior Notes. The Senior Notes
are redeemable after April 30, 2004 at 105%. Prior to that date, Ascent may
redeem up to 35% of the Senior Notes at 111%. The Senior Notes subject Ascent to
certain covenants which, among other things, limit Ascent's ability to pay
dividends, incur additional indebtedness and certain lease obligations, issue
preferred stock exchange or transfer assets.
These transactions were treated as purchases for accounting purposes. The
purchase prices were allocated to the assets and liabilities based on estimated
fair value. No value was assigned to the warrants. The allocations of the
purchase prices are preliminary and subject to change within one year of the
acquisition dates. Net assets acquired in the transactions were as follows:
<Table>
<Caption>
Transactions
(in thousands)
--------------------------------------
Pontotoc Devo
-------- ----
Oil and gas properties $91,195 $67,449
Working capital,
excluding cash 656 1,775
Debt (7,315) (73,698)
Deferred taxes (31,745) (1,360)
Preferred stock (2,609) --
------- --------
Net cash paid (received) $50,182 $(5,834)
======= ========
</Table>
The operating results of Pontotoc and Devo have been consolidated in the
Company's statement of operations since July 28, 2001 and September 28, 2001,
respectively.
2
SIGNIFICANT PROPERTIES
We have summarized our most significant properties in the tables below as
of December 31, 2001:
<Table>
<Caption>
Net Proved Reserves (1)
-----------------------
December 2001
Our Our Net Average Daily
Working Revenue Net Production
Producing Properties Interest Interest MBOE % Developed (BOE)
- -------------------- -------- -------- ---- ----------- -----
Lake Enfermer Field, LA 92.9% 64.8% 2,954 37.0% 794
New Taiton Field, TX 89.3% 46.1% 3,332 59.9% 1,153
La Copita Field. TX 92.2% 56.7% 4,839 54.7% 687
Allen Anticline Field, OK 93.9% 81.3% 8,343 64.7% 0
</Table>
- ------------------
(1) Estimates of net proved reserves are based on our third party independent
reserve report as of December 31, 2001.
LAKE ENFERMER FIELD, LOUISIANA. The Lake Enfermer Field is located in a
marsh area on a deep, complexly faulted field, salt structure in Lafourche
Parish, Louisiana. Since 1992, we have acquired leases on 3,650 acres in this
field and operate the field. The field was first discovered in 1955 and through
December 2001 has produced more than 33.8 MMBoe (one million barrels of oil
equivalent, determined using the ratio of six Mcf (thousand cubic feet) of
natural gas to one barrel of oil).
NEW TAITON FIELD, TEXAS. The New Taiton Field is located in Wharton
County, Texas. This field was acquired in the Devo Acquisition. We are the
operator and own working interests ranging from 85% to 100%. This field was
discovered in 1949.
LA COPITA FIELD, TEXAS. The La Copita Field is located in east central
Starr County, Texas. This field was acquired in the Devo Acquisition. We operate
La Copita Field and own working interests ranging from 53% to 100%. La Copita
Field was discovered in 1949. Cumulative production from this field exceeds 200
BCF.
ALLEN ANTICLINE FIELD, OKLAHOMA. The Allen Anticline Field is located
throughout Pontotoc County, Oklahoma. This field was acquired in the Pontotoc
Acquisition. We operate nearly all of the wells in which we have an interest.
Working interests in this field generally range from 50% to 100%. The Allen
Anticline Field was discovered in the 1920's.
PRODUCTIVE WELLS
The following table sets forth the number of producing wells in which we
maintain an ownership interest at December 31, 2001:
<Table>
<Caption>
PRODUCTIVE WELLS
--------------------------------------
Gross Net
------------------ -------------------
Gas 305.0 267.1
Oil 374.0 341.3
----- -----
Total 679.0 608.4
===== =====
</Table>
3
Productive wells consist of producing wells and wells capable of
production. A gross well is a well in which we maintain a working interest while
a net well is deemed to exist when the sum of the fractional working interests
owned by us equals one. Wells with multiple completions are counted as one well.
Of the gross wells reported in the table, two had multiple completions.
DRILLING ACTIVITY
The following table sets forth our drilling activity for the last three
years:
<Table>
<Caption>
Year Ended December 31,
----------------------------------------------------------
2001 2000 1999
---------------- ----------------- ----------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Development wells:
Productive....................................... 5.0 4.6 1.0 1.0 0.0 0.0
Non-productive................................... 1.0 1.0 0.0 0.0 0.0 0.0
--- --- --- --- --- ---
Total........................................ 6.0 5.6 1.0 1.0 0.0 0.0
--- --- --- --- --- ---
Exploratory wells:
Productive....................................... 0.0 0.0 0.0 0.0 0.0 0.0
Non-productive................................... 1.0 1.0 1.0 0.5 0.0 0.0
--- --- --- --- --- ---
Total........................................ 1.0 1.0 1.0 0.5 0.0 0.0
--- --- --- --- --- ---
Total:
Productive....................................... 5.0 4.6 1.0 1.0 0.0 0.0
Non-productive................................... 2.0 2.0 1.0 0.5 0.0 0.0
--- --- --- --- --- ---
Total........................................ 7.0 6.6 2.0 1.5 0.0 0.0
=== === === === === ===
</Table>
4
NET PRODUCTION, UNIT PRICES AND COSTS
The following table presents certain information regarding our production
volumes, average sale prices and average production costs for the last three
years:
<Table>
<Caption>
Year Ended December 31,
---------------------------------------
2001 2000 1999
------- ------- --------
Production:
Natural gas (MMcf)...................... 3,010 1,797 3,091
Oil and condensate (MBbls).............. 442 270 343
Total (MMcfe)......................... 5,663 3,414 5,154
Average sales price per unit:
Natural gas--
Revenues from production
(per Mcf).......................... $ 3.74 $ 4.05 $ 2.28
Effects of hedging activities
(per Mcf).......................... 0.20 - -
------- ------- --------
Average price (per Mcf)............... $ 3.94 $ 4.05 $ 2.28
------- ------- --------
Oil and condensate--
Revenues from production
(per Bbl).......................... $ 21.83 $ 27.49 $ 17.34
Effects of hedging activities
(per Bbl).......................... 0.52 - -
------- ------- --------
Average price (per Bbl)............... 22.35 27.49 17.34
------- ------- --------
Total revenues from production
(per Mcfe)......................... $ 3.69 $ 4.30 $ 2.52
Effects of hedging activities
(per Mcfe)......................... 0.15 - -
------- ------- --------
Total average price
(per Mcfe)..................... $ 3.84 $ 4.30 2.52
======== ======= ========
Expenses (per Mcfe):
General and administrative.............. $ 0.75 $ 0.78 $ 0.59
Lease operating expenses (excluding
Production taxes)..................... $ 0.97 $ 0.98 $ 0.61
Depreciation, depletion and amortization
of oil and natural gas properties..... $ 1.37 $ 1.31 $ 1.09
</Table>
5
CAPITAL EXPENDITURES
The following table presents information regarding our net costs incurred
in oil and natural gas property acquisitions, exploration and development
activities for the past three years ended December 31, 2001:
<Table>
<Caption>
2001 2000 1999
---- ---- ----
Property acquisition
Proved $ 157,061,199 $ 574,008 $ 81,840
Unproved - - -
Exploration - 1,502,880 3,345,943
Development 7,693,813 46,853 1,745,862
Capitalized G&A costs. 307,064 842,391 -0-
-------------- ------------ -------------
$ 165,062,076 $ 2,966,132 $ 5,173,645
============== ============ ============
</Table>
EMPLOYEES
On December 31, 2001, we employed 80 people, including 51 that work in our
field offices. None of our employees is covered by a collective bargaining
agreement, and we believe that our relationships with our employees are
satisfactory. From time to time we utilize the services of independent
contractors to perform various field and other services.
RISK FACTORS RELATED TO OUR BUSINESS AND OPERATIONS
CAUTIONARY STATEMENTS
Certain statements made in this Report that are not historical facts are
"forward-looking statements" as defined in Section 27A of the Securities Act of
1933 and Section 21E of the Securities Exchange Act of 1934. Such
forward-looking statements may include statements that relate to:
o our objectives, business plans or strategies, and projected or
anticipated benefits or other consequences of such plans or
strategies;
o projected or anticipated benefits from future or past acquisitions;
and
o projections involving anticipated capital expenditures or revenues,
earnings or other aspects of capital projects or operating results.
Also, you can generally identify forward-looking statements by such
terminology as "may," "will," "expect," "believe," "anticipate," "project,"
"estimate" or similar expressions. We caution you that such statements are only
predictions and not guarantees of future performance or events. In evaluating
these statements, you should consider various risk factors, including but not
limited to the risks listed below. These risk factors may affect the accuracy of
the forward-looking statements and the projections on which the statements are
based.
All phases of our operations are subject to a number of uncertainties,
risks and other influences, many of which are beyond our control. Any one of
such influences, or a combination, could materially affect the results of our
operations and the accuracy of forward-looking statements made by us. Some
important factors that could cause actual results to differ materially from the
anticipated results or other expectations expressed in our forward-looking
statements include the following:
o dependence on exploratory drilling activities, uncertainties about
the estimates of reserves and the need to replace reserves;
o the volatility of prices of oil and gas;
6
o drilling and operating hazards, including the significant possibility
of accidents resulting in personal injury, property damage or
environmental damage;
o the effect on our performance of regulatory programs and
environmental matters;
o the continued active participation of our executive officers and key
operating personnel.
Many of these factors are beyond our ability to control or predict. We
caution investors not to place undue reliance on forward-looking statements. We
disclaim any intent or obligation to update the forward-looking statements
contained in this Report, whether as a result of receiving new information, the
occurrence of future events or otherwise. All subsequent written and oral
forward-looking statements attributable us or persons acting on our behalf are
expressly qualified in their entirety by the foregoing.
A more detailed discussion of certain of the foregoing factors follows:
OIL AND GAS MARKETING
We sell our natural gas and oil production under price sensitive or
market price contracts. Our revenues, profitability and future growth depend
substantially on prevailing prices for natural gas and oil. The price received
by us for natural gas and oil production historically has fluctuated widely.
Decreases in the price of natural gas and oil could adversely affect the
carrying value of our proved reserves and our revenues, profitability and cash
flow. From time to time we may enter into transactions hedging the price of oil
and natural gas production. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Quantitative and Qualitative
Disclosures About Market Risk."
COMPETITION AND MARKETS
We operate in a highly competitive environment. We compete with major and
independent oil and natural gas companies for the acquisition of desirable oil
and natural gas properties, as well as for the equipment and labor required to
develop and operate these properties. We also compete with major and independent
oil and natural gas companies in the marketing and sale of oil and natural gas
to marketers and end-users. Many of our competitors have financial and other
resources substantially greater than ours.
Competitors may be able to pay more for natural gas and oil properties and
may be able to define, evaluate, bid for and acquire a greater number of
properties than we can. Our ability to acquire and develop additional properties
in the future will depend on our ability to conduct operations, evaluate and
select suitable properties and close transactions in this highly competitive
market environment.
The marketability of our production depends upon the availability and
capacity of gas gathering systems, pipelines and processing facilities, and the
unavailability or lack of capacity thereof could result in the shut-in of
producing wells or the delay or termination of development plans for properties.
In addition, regulatory changes affecting oil and natural gas production and
transportation, general economic conditions and changes in supply and demand
could adversely affect our ability to produce and market our oil and natural gas
on a profitable basis. In addition, larger competitors may be able to absorb the
burden of any regulatory changes more easily than we can, which would adversely
affect our competitive position.
REGULATION
Our business can be affected by a number of regulatory policies, including
the regulation of production, federal and state regulations governing
environmental quality and pollution control, state limits of allowable rates of
production by a well or proration unit and incentives to promote alternative or
competitive fuels. State and federal regulations generally are intended to
prevent waste of oil and natural gas, protect rights to produce oil and natural
gas between owners in a common reservoir, control the amount of oil and natural
gas produced by assigning allowable rates of production and control
contamination of the environment. Pipelines are also subject to the jurisdiction
of various federal, state and local agencies.
7
Federal Regulation of Natural Gas. Federal legislation and regulatory
controls in the United States have historically affected the price of natural
gas and the manner in which natural gas production is marketed. In the past, the
federal government has regulated the price at which natural gas could be sold
and could reenact price controls in the future.
Our sales of natural gas are affected by the availability, terms and cost
of pipeline transportation. The price and terms for access to pipeline
transportation are subject to extensive federal regulation. Beginning in 1992,
the Federal Energy Regulatory Commission issued a series of orders, which
required interstate pipelines to provide open-access transportation on a not
unduly discriminatory basis for all natural gas shippers. The Federal Energy
Regulatory Commission has stated that it intends for these orders and its future
restructuring activities to foster increased competition within all phases of
the natural gas industry. Although these orders do not directly regulate our
production and marketing activities, they do affect how buyers and sellers gain
access to the necessary transportation facilities and how we and our competitors
sell natural gas.
The courts have largely affirmed the significant features of the Federal
Energy Regulatory Commission's deregulation orders and the numerous related
orders pertaining to individual pipelines. However, some appeals remain pending
and the Federal Energy Regulatory Commission continues to review and modify its
regulations regarding the transportation of natural gas. For example, the
Federal Energy Regulatory Commission issued Order No. 637 which:
o lifts the cost-based cap on pipeline transportation rates in the
capacity release market until September 30, 2002, for short-term
releases of pipeline capacity of less than one year;
o permits pipelines to file for authority to charge different maximum
cost-based rates for peak and off-peak periods;
o encourages, but does not mandate, auctions for pipeline capacity;
requires pipelines to implement imbalance management services;
o restricts the ability of pipelines to impose penalties for
imbalances, overruns and non-compliance with operational flow orders;
and
o implements a number of new pipeline reporting requirements.
Order No. 637 also requires the Federal Energy Regulatory Commission's
staff to analyze whether the Federal Energy Regulatory Commission should
implement additional fundamental policy changes. These include whether to pursue
performance-based or other non-cost based ratemaking techniques and whether the
Federal Energy Regulatory Commission should mandate greater standardization in
terms and conditions of service across the interstate pipeline grid.
We cannot predict what other actions the Federal Energy Regulatory
Commission will take on these matters, nor can we accurately predict whether the
Federal Energy Regulatory Commission's actions will achieve the goal of
increasing competition in markets in which our natural gas is sold. However, we
do not believe that any action taken will affect us in a way that materially
differs from the way it affects other natural gas producers, gatherers and
marketers.
Oil Sales and Transportation Rates. Sales prices of crude oil and natural
gas liquids by us are not regulated. The price we receive from the sale of these
products may be affected by the cost of transporting the products to market. In
a number of instances, however, the ability to transport and sell these products
depends on pipelines whose rates, terms and conditions of service are subject to
Federal Energy Regulatory Commission jurisdiction. In other instances, the
ability to transport and sell our products depends on pipelines whose rates,
terms and conditions of service are subject to regulation by state regulatory
bodies. Certain regulations implemented by the Federal Energy Regulatory
Commission in recent years could result in an increase in the cost of
transportation service on these pipelines. However, we do not believe that these
regulations affect us any differently than any other producer or marketer.
8
Environmental Matters. Extensive federal, state and local laws regulating
the discharge of materials into the environment or otherwise relating to the
protection of the environment affect our oil and natural gas operations.
Numerous governmental departments issue rules and regulations to implement and
enforce such laws, which are often difficult and costly to comply with and which
carry substantial penalties for failure to comply. Some laws, rules and
regulations relating to protection of the environment may, in certain
circumstances, impose "strict liability" for environmental contamination,
rendering a person liable for environmental damages and cleanup costs without
regard to negligence or fault on the part of such person. Other laws, rules and
regulations may restrict the rate of oil and natural gas production below the
rate that would otherwise exist or even prohibit exploration and production
activities in sensitive areas. In addition, state laws often require various
forms of remedial action to prevent pollution, such as closure of inactive pits
and plugging of abandoned wells. The regulatory burden on the oil and natural
gas industry increases its cost of doing business and consequently affects its
profitability. We believe that we are in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on our operations.
However, environmental laws and regulations have been subject to frequent
changes over the years, and the imposition of more stringent requirements could
require us to make significant capital expenditures, increase our operating
costs or otherwise adversely affect our competitive position.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "CERCLA," imposes liability, without regard to fault or the
legality of the original conduct, on certain classes of persons that are
considered to be responsible for the release of a "hazardous substance" into the
environment. These persons include the current or former owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of hazardous substances. Under CERCLA,
such persons may be subject to joint and several liability for the costs of
investigating and cleaning up hazardous substances that have been released into
the environment, for damages to natural resources and for the costs of certain
health studies. In addition, companies that incur CERCLA liability frequently
also confront third party claims because it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by hazardous substances or other pollutants
released into the environment from a CERCLA site.
The Federal Solid Waste Disposal Act, as amended by the Resource
Conservation and Recovery Act of 1976, also known as "RCRA," regulates the
generation, transportation, storage, treatment and disposal of hazardous wastes
and can require cleanup of hazardous waste disposal sites. RCRA currently
excludes drilling fluids, produced waters and other wastes associated with the
exploration, development or production of oil and natural gas from regulation as
"hazardous waste." However, other wastes handled at exploration and production
sites may not fall within this exclusion. Disposal of non-hazardous oil and
natural gas exploration, development and production wastes usually is regulated
by state law.
Stricter standards for waste handling and disposal may be imposed on the
oil and natural gas industry in the future. From time to time legislation has
been proposed in Congress that would revoke or alter the current exclusion of
exploration, development and production wastes from the RCRA definition of
"hazardous wastes," thereby potentially subjecting such wastes to more stringent
handling, disposal and cleanup requirements. If such legislation were enacted,
it could have a significant impact on our operating costs, as well as the oil
and natural gas industry in general. Furthermore, although petroleum, including
crude oil and natural gas, is exempt from CERCLA, at least two courts have ruled
that certain wastes associated with the production of crude oil may be
classified as "hazardous substances" under CERCLA. The impact of future
revisions to environmental laws and regulations cannot be predicted.
The Oil Pollution Act of 1990, also known as OPA 90, provides that
persons responsible for facilities and vessels (including the owners and
operators of onshore facilities) are subject to strict joint and several
liability for cleanup costs and certain other public and private damages arising
from a spill of oil into waters of the United States. OPA 90 established a
liability limit for onshore facilities of $35 million. However, facilities
located in coastal waters may be considered "offshore" facilities subject to
greater liability limits under OPA 90 (all removal costs plus $75 million). In
addition, a party cannot take advantage of this liability limit if the spill was
caused by gross negligence or willful misconduct or resulted from a violation of
a federal safety, construction or operating regulation. If a party fails to
report a spill or
9
cooperate in the cleanup, liability limits likewise do not apply. OPA 90 also
imposes other requirements on facility owners and operators, such as the
preparation of an oil spill response plan. Failure to comply with ongoing
requirements or inadequate cooperation in a spill event may subject the
responsible party to civil or criminal enforcement actions.
OPA 90 also imposes financial responsibility requirements on the person
or persons statutorily responsible for certain facilities. Under the related
regulations, oil production and storage facilities that are located in wetlands
adjacent to coastal waters could be required to demonstrate various levels of
financial ability to reimburse governmental entities and private parties for
costs that they could incur in responding to an oil spill, if the Minerals
Management Services determines that spills from those particular facilities
could reach coastal waters.
OPERATING RISKS AND INSURANCE
The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosions, blow-outs, pipe failure, casing
collapse, abnormally pressured formations and hazards such as oil spills,
natural gas leaks, ruptures and discharges of toxic gases. The occurrence of any
of these operating risks could result in substantial losses to us due to injury
or loss of life, severe damage to or destruction of property and equipment,
pollution or other environmental damage, including damage to natural resources,
clean-up responsibilities, penalties and suspension of operations. Such hazards
may hinder or delay drilling, development and on-line operations. In accordance
with customary industry practice, we maintain insurance against some, but not
all, of the risks described above, including insuring the cost of clean-up
operations, public liability and physical damage. There can be no assurance that
any insurance we obtain will be adequate to cover any losses or liabilities or
that such insurance will continue to be available in the future or that such
insurance will be available at premium levels that justify its purchase. The
occurrence of a significant event not fully insured or indemnified against could
have a material adverse effect on our financial condition and operations.
OUR CAPITALIZATION OR VOLATILITY IN OUR RESULTS MAY PREVENT US FROM RAISING THE
CAPITAL NECESSARY TO DRILL WELLS.
We may not be able to successfully pursue our business strategy if our
balance sheet, volatility in our results or general industry or market
conditions prevents us from raising the capital required for our exploration and
development activities and other operations. We expect to make substantial
expenditures for the exploitation, exploration, development and production of
oil and natural gas reserves. If our revenues or cash flow from operations
decrease as a result of lower oil and natural gas prices, operating difficulties
or other factors, many of which are beyond our control, or we are unable to
raise additional debt or equity proceeds to fund such expenditures, then we may
curtail our drilling, development and other activities. In addition, we may be
forced or choose to sell some of our assets on an untimely or unfavorable basis.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations - Liquidity and Capital Resources."
THE OIL AND GAS RESERVES DATA AND FUTURE NET REVENUES ESTIMATES WE REPORT ARE
UNCERTAIN.
The process of estimating oil and natural gas reserves is a subjective
process of estimating underground accumulations of oil and natural gas that
cannot be measured in an exact manner. It requires interpretations of available
technical data and various assumptions, including assumptions relating to
economic and other factors beyond our control. Any significant inaccuracies in
these interpretations or assumptions could materially affect the estimated
quantities and present value of reserves shown.
Actual future production, oil and gas prices, revenues, taxes,
development costs, operating expenses and quantities of recoverable oil and gas
reserves will vary from those currently estimated. Any significant variance
could materially affect the estimated quantities and present value of reserves
set forth in this document and the information incorporated by reference. Our
properties may also be susceptible to hydrocarbon drainage from wells on
adjacent properties operated by other owners. In addition, we may adjust reserve
estimates to reflect production history, results of exploration and development,
availability of rigs and other equipment, prevailing oil and gas prices and
other factors, many of which are beyond our
10
control. Actual production, revenues, taxes, development expenditures and
operating expenses with respect to our reserves will vary from the estimates
used. Such variances may be material.
You should not assume that the present value of future net cash flows
from our proved reserves referred to in this prospectus is the current market
value of these reserves. In accordance with SEC requirements, we base the
estimated discounted future net cash flows from our proved reserves on prices
and costs on the date of the estimate. Current commodity prices are at
historically high levels. At current prices, we believe the present value of
future net revenue amounts included in this prospectus or incorporated herein
cannot be construed as the current market value of the estimated oil and gas
reserves attributable to our properties. Actual future prices and costs are
likely to differ materially from those used in the present value estimate
because of changes in commodity prices or hedging transactions. The timing of
both the production and the expenses from the development and production of oil
and gas properties will affect the timing of actual future net cash flows from
proved reserves and their present value. In addition, the 10% discount factor,
which is required by the SEC to be used in calculating discounted future net
cash flows for reporting purposes, is not necessarily the most accurate discount
factor. The effective interest rate at various times and the risks associated
with us or the oil and gas industry in general will affect the accuracy of the
10% discount factor.
LOWER OIL AND GAS PRICES MAY CAUSE US TO RECORD CEILING TEST WRITE-DOWNS.
We use the full cost method of accounting to account for our oil and gas
operations. Accordingly, we capitalize the cost to acquire, explore for and
develop oil and gas properties. Under full cost accounting rules, the net
capitalized costs of oil and gas properties may not exceed a "ceiling limit"
which is based upon the present value of estimated future net cash flows from
proved reserves at a point in time, discounted at 10%, plus the lower of cost or
fair value of unproved properties. If net capitalized costs of oil and gas
properties exceed the ceiling limit, we must charge the amount of the excess to
earnings. This is called a "ceiling test write-down." This charge does not
impact cash flow from operating activities, but does reduce our stockholders'
equity. The risk that we will be required to write down the carrying value of
oil and gas properties increases when oil and gas prices are low or volatile. In
addition, write-downs may occur if we experience substantial downward
adjustments to our estimated proved reserves. Due to low oil and gas prices in
the third quarter of 2001, we wrote down our oil and gas properties by $4.2
million on September 30, 2001. No ceiling test write-down was necessary at
December 31, 2001.
Our use of hedging transactions for a portion of our oil and gas
production may limit future revenues from price increases and result in
significant fluctuations in our stockholders' equity.
We use hedging transactions with respect to a portion of our oil and gas
production to achieve more predictable cash flow and to reduce our exposure to
price fluctuations. While the use of hedging transactions limits the downside
risk of price declines, their use may also limit future revenues from price
increases. While intended to reduce the effects of volatility of the price of
oil and natural gas, such transactions may limit our potential gains if oil and
natural gas prices were to rise substantially over the price established by the
hedge. In addition, these hedging arrangements may expose us to the risk of
financial loss if:
o production is less than expected;
o there is a change in the expected differential between the underlying
price in the hedging arrangement and actual prices received;
o the other party to the hedging contract defaults on its contract
obligations; or
o a sudden, unexpected event materially affects oil or natural gas
prices.
We adopted Statement of Financial Accounting Standards (SFAS) No. 133 as
of January 1, 2001. As a result of adopting SFAS No. 133, our stockholders'
equity may fluctuate significantly from period to period. SFAS No. 133 generally
requires us to record each derivative instrument as an asset or liability
measured at its fair value. We must record an initial adjustment in the other
comprehensive income
11
component of stockholders' equity on adoption of SFAS No. 133, which amount will
likely be significant. Thereafter, we must similarly record changes in the value
of our hedging, which could result in significant fluctuations in stockholders'
equity from period to period.
For further discussion of our hedging arrangements, please see
"Quantitative and Qualitative Disclosures About Market Risk."
WE MAY BE UNABLE TO IDENTIFY LIABILITIES ASSOCIATED WITH THE PROPERTIES THAT WE
ACQUIRE OR OBTAIN PROTECTION FROM SELLERS AGAINST THEM.
The acquisition of properties requires us to assess a number of factors,
including:
o value of the oil or gas properties and likelihood of future
production;
o future prices of oil and gas;
o recoverable reserves;
o development and operating costs;
o potential environmental and other liabilities;
o drilling and production difficulties; and
o other factors beyond our control.
Such assessments are inexact and inherently uncertain. We intend to
perform such reviews in a manner that we believe at the time to be generally
consistent with industry practice. These reviews, however, may not reveal all
existing or potential problems, nor would they permit a buyer to become
sufficiently familiar with such properties to assess fully their deficiencies or
benefits. For instance, inspections may not be performed on every well, and
structural or environmental problems, such as pipeline corrosion, may not be
observable even when an inspection is undertaken. In addition, we may not be
able to obtain contractual indemnities from the seller for liabilities that it
created. We may be required to assume the risk of the physical condition of the
properties in addition to the risk that the properties may not perform in
accordance with our expectations. We can make no assurance that any future
acquisitions will be beneficial. Any unsuccessful acquisition could have a
material adverse affect on us.
THERE IS A LACK OF AN ESTABLISHED TRADING MARKET FOR OUR SECURITIES.
There is no existing trading market for the common stock, preferred stock
or the warrants and it is not expected that any active market will develop.
TCW AND JEFFERIES CONTROL A MAJOR PORTION OF OUR OUTSTANDING COMMON STOCK AND
WARRANTS TO PURCHASE COMMON STOCK.
The TCW Funds and its affiliates and funds controlled by Jefferies &
Company, Inc. own approximately 95% of our outstanding common stock and 93% of
warrants to purchase common stock. By virtue of such ownership, the TCW Funds
and Jefferies will have the power to determine the outcome of various corporate
actions requiring shareholder approval.
WE HAVE NO INTENTION TO PAY DIVIDENDS.
We currently intend to retain any earnings for the future operation and
development of its business and do not currently intend to declare or pay any
dividends on our common stock in the foreseeable future.
12
ITEM 2. PROPERTIES
NATURAL GAS AND OIL RESERVES
Our proved oil and gas reserves at December 31, 2001 were attributable
to wells located in Louisiana, Oklahoma and Texas. The following table presents
estimated proved reserves as of December 31, 2001, and the related present value
of estimated future net revenues before income taxes at such date, as estimated
by our independent petroleum engineers, Netherland, Sewell & Associates, Inc.
The present values, discounted at 10% per annum, of estimated future net cash
flows before income taxes shown on the table are not intended to represent the
current market value of our estimated natural gas and oil reserves.
The present value of future net cash flows before income taxes as of
December 31, 2001, was determined using the December 31, 2001, prices of $2.84
per Mcf of natural gas and $18.40 per Bbl of oil.
The proved reserves and related present value of estimated future net
revenues, discounted at 10%, are found below:
<Table>
<Caption>
Non-
Producing Producing Undeveloped Total
--------- --------- ----------- -----
Natural gas (MMcf)............................ 13,526 36,988 34,929 85,443
Oil and NGLs (MBbls).......................... 4,655 2,596 5,042 12,293
Total proved reserves (MMcfe)...... 41,455 52,565 65,180 159,201
Present value of estimated future net
revenues before income taxes, discounted
at 10% (in thousands)....................... $ 43,444 $ 49,811 $ 64,928 $ 158,183
Standardized measure of discounted
future net cash flows (in thousands)........ $ 136,065
</Table>
These estimates of our proved reserves have not been filed with or
included in reports to any federal agency.
The process of estimating natural gas and oil reserves is a complex and
subjective process. It requires various assumptions, including assumptions
relating to product prices, operating expenses, capital expenditures, taxes and
the availability of funds. We must project production rates and timing of
development expenditures. We analyze available geological, geophysical,
production and other data, and the extent, quality and reliability of this data
will vary. As a result, estimates of different engineers may vary. In addition,
estimates of reserves are subject to revision based upon future product prices,
actual production, results of future development and exploration activities,
operating costs and other factors, and the revisions may be material.
Accordingly, reserve estimates will generally be different from the quantities
of oil and natural gas that are ultimately recovered. The meaningfulness of such
estimates highly depends on the accuracy of the assumptions upon which they are
based. Accordingly, the reserve data set forth herein represents only estimates.
In accordance with applicable SEC requirements, the estimates of our
proved reserves and future net revenues are made using oil and natural gas sales
prices that are in effect as of the date of such reserve estimates and are held
constant throughout the life of the properties. You should not assume that the
present value of future net revenues from our proved reserves is the current
market value of these reserves. Estimated quantities of proved reserves and
future net revenues therefrom are affected significantly by oil and natural gas
prices, which have fluctuated widely in recent years. Current commodity prices
are at historically high levels. At current prices, we believe of future net
revenue amounts included here or incorporated herein cannot be construed as the
current market value of the oil and gas reserves attributable to our properties.
The average prices of oil and gas we have actually received for years 2001, 2000
and 1999 were $22.35, $27.49 and $17.34 respectively, per barrel and $3.90,
$4.05 and $2.28, respectively, per Mcf. Subsequent to December 31, oil prices
have increased approximately 39% and natural gas prices have increased
approximately 20% from December 31, 2001 prices. Accordingly, the discounted
future net cash flows would be increased if the standardized measure were
calculated at a later date. Actual future prices
13
and costs are likely to differ materially from those used in the present value
estimate because of changes in commodity prices or hedging transactions.
TITLE TO PROPERTIES
We believe that we have satisfactory title to all of our producing
properties in accordance with standards generally accepted in the oil and
natural gas industry, subject to such exceptions as, in our view, do not
materially detract from the use or value of the properties. As is customary in
the oil and gas industry, we perform only a preliminary title investigation
before leasing undeveloped properties. A title opinion is typically obtained
before the commencement of drilling operations and any material defects are
remedied prior to the time the actual drilling of a well is commenced. If the
operator or we were unable to remedy or cure any title defect, we could suffer a
loss of our entire investment in the property. Our properties are subject to
customary royalty interests, liens for current taxes, liens of vendors and other
customary burdens, which we do not believe materially interfere with the use of
or affect the value of our producing properties.
ACREAGE
The table below summarizes our developed and undeveloped leasehold
acreage as of December 31, 2001:
<Table>
<Caption>
Acreage
-------------------------------------
Gross Net
---------------- ----------------
Developed 30,321 23,658
Undeveloped 5,361 5,593
------ ------
Total 35,682 29,251
====== ======
</Table>
Gross acreage is acreage in which a working interest is owned while a net
acre is deemed to exist when the sum of the fractional working interests in
gross acres equals one. Undeveloped acreage is considered to be those 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 natural gas,
regardless of whether or not such acreage contains proved reserves. As is
customary in the industry, we can retain our interests in undeveloped acreage by
drilling activity that establishes commercial production or by payment of delay
rentals during the remaining primary term. The oil and natural gas leases in
which we have an interest are for varying primary terms; however, most of our
developed leased acreage is beyond the primary term and is held by producing
wells.
ITEM 3. LEGAL PROCEEDINGS
From time to time, we may be a party to various legal proceedings. We
currently are a party to a lawsuit arising in the ordinary course of business.
Management does not expect this matter to have a material adverse effect on our
financial position or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
14
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
There is no established public trading market for our common stock,
preferred stock or our warrants and it is unlikely that any will develop. As of
January 15, 2002, there was 1 holder of record of our common stock and 154
holders of record of our Preferred Series B stock.
We have never declared or paid any cash dividends on our common stock and
do not anticipate paying cash dividends in the foreseeable future. Payments of
cash dividends on our preferred stock is decided on a quarterly basis by the
board of directors. To date, no preferred stock dividends have been declared and
paid.
15
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
The following table sets forth a summary of our selected historical
financial information for the periods set forth below. This information is
derived from our financial statements and the notes thereto. See "Item 7.
Management Discussion and Analysis of Financial Condition and Results of
Operations" and "Item 8. Financial Statements and Supplementary Data."
This filing contains unaudited financial statements in lieu of
audited financial statements because the Company was unable to obtain
from Arthur Andersen LLP a manually signed report. The Company expects
to obtain a manually signed report from Arthur Andersen LLP and file
an amended report on Form 10-K containing audited financial
statements on or before April 22, 2002. No auditor has opined that
the unaudited financial statements present fairly, in all material
respects, the financial position, the results of operations, cash
flows and the changes in shareholders' equity of the Company for each
of the periods reported in accordance with generally accepted
accounting principles.
SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)
<Table>
<Caption>
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
STATEMENT OF OPERATIONS DATA:
Oil and natural gas revenue................ $ 21,617 $ 14,696 $ 12,993 $ 15,950 $ 14,235
Operating expenses......................... 23,199 11,163 12,494 36,691 24,814
-------- -------- -------- -------- --------
Operating income (loss).................... (1,582) 3,533 499 (20,741) (10,579)
Interest expense......................... (3,335) - 6,244 10,122 7,724
Other income............................. 182 264 123 325 474
-------- -------- -------- -------- --------
Net gain (loss) from operations before
reorganization items, income taxes and
extraordinary items................... (4,735) 3,797 (5,622) (30,538) (17,829)
Reorganization items:
Reorganization costs..................... - (899) (1,184) - -
Adjust accounts to fair value............ - - 6,268 - -
-------- -------- -------- -------- --------
Net gain (loss) before income taxes
and extraordinary item................. (4,735) 2,898 (538) (30,538) (17,829)
Provision (benefit) for income
taxes.................................... (1,247) (1,182) (188) - -
-------- -------- -------- -------- --------
Net income (loss) before extraordinary
items..................................... (3,488) 1,716 (349) (30,538) (17,829)
Extraordinary gain on extinguishment of
debt, net of taxes of $10,089........... - - 46,724 - -
-------- -------- -------- -------- --------
Net gain (loss)............................ (3,488) 1,716 46,375 (30,538) (17,829)
Preferred stock dividends................ (1,168) - (1,153) (1,729) (923)
-------- -------- -------- -------- --------
Net income (loss) attributed to common shares $ (4,656) $ 1,716 $ 45,222 $ (32,267) $ (18,752)
Basic and diluted
Net income (loss) per share attributable to
Common shares before extraordinary
item.................................. $ (0.94) $ 0.35 $ 0.30) $ (6.52) $ (3.79)
Extraordinary item per
share.................................... - - 9.44 $ - -
-------- -------- -------- -------- --------
Net income (loss) per share................ $ (0.94) $ 0.35 $ 9.14 $ (6.52) $ (3.79)
======== ======== ======== ========= =========
Weighted average shares outstanding 4,950 4,950 4,950 4,950 4,950
</Table>
16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
This filing contains unaudited financial statements in lieu of
audited financial statements because the Company was unable to obtain
from Arthur Andersen LLP a manually signed report. The Company expects
to obtain a manually signed report from Arthur Andersen LLP and file
an amended report on Form 10-K containing audited financial
statements on or before April 22, 2002. No auditor has opined that
the unaudited financial statements present fairly, in all material
respects, the financial position, the results of operations, cash
flows and the changes in shareholders' equity of the Company for each
of the periods reported in accordance with generally accepted
accounting principles.
The following discussion is intended to assist in understanding our
financial position and results of operations for each year of the three-year
period ended December 31, 2001. Our consolidated financial statements and notes
thereto contain detailed information that should be referred to in conjunction
with the following discussion.
Organization, Restructuring and Mergers
Ascent Energy Inc. ("Ascent," "we" or "us") is an independent energy company
engaged in the acquisition, exploitation, exploration, development and
production of natural gas and crude oil. Through our predecessor, we have been
active in South Louisiana since 1982. We were organized on January 9, 2001 by
the majority stockholders of our predecessor principally to facilitate the
acquisition of Pontotoc Production, Inc. ("Pontotoc").
Our business strategy is to increase production, cash flow and reserves through
the acquisition and development of mature properties. Currently, our property
base consists of 679 active properties, 30 in South Louisiana and 625 shallow
wells in Pontotoc County, Oklahoma, and 24 wells in South Texas. We serve as
operator on the majority of our active properties, which enables us to better
control the timing and cost of rejuvenation activities. We are headquartered in
McKinney, Texas, with additional offices in New Orleans, Louisiana, and Ada,
Oklahoma.
The consolidated financial statements include our accounts and the accounts of
our subsidiaries. The subsidiaries include Pontotoc Acquisition Corp., Pontotoc
Production Company, Inc., Oklahoma Basic Economy Corporation, Pontotoc Holdings,
Inc. and Pontotoc Gathering, L.L.C. All significant inter-company balances have
been eliminated. Certain prior year amounts have been reclassified to conform to
current year presentation.
Restructuring
In July, 2001, prior to the consummation of the acquisition of Pontotoc, our
predecessor was restructured as a holding company by contributing to us all of
its assets and liabilities. We refer to this transaction as the "Restructuring."
The Restructuring is accounted for using reorganization accounting for entities
under common control, which results in retroactive restatement of all periods
presented to reflect the Restructuring as if it had occurred at the beginning of
the earliest period presented. The accompanying consolidated financial
statements include the accounts of our predecessor and Ascent prior to the
Restructuring.
Pontotoc Acquisition
On July 31, 2001, we acquired approximately 91% of Pontotoc's outstanding common
stock. Subsequently, we acquired the remaining Pontotoc shares on August 14,
2001 in the second-step of the merger and merged Pontotoc into one of our
wholly-owned subsidiaries. The purchase price for all the outstanding Pontotoc
common stock was approximately $48.5 million in cash and 5,323,695 shares of our
Series B mandatorily convertible preferred stock. These shares were valued at
$0.49 per share based on the trading price of Pontotoc's common stock for the
five trading days prior to and following the date of the merger agreement.
We financed the cash portion of the purchase price for the Pontotoc acquisition
through:
o borrowing $30 million under our credit facility;
o a portion of the proceeds from the private sale for $21.1 million of
shares of our Series A redeemable preferred stock and warrants to
purchase approximately 4.1 million shares of our common stock; and
o existing internal cash resources.
17
The proceeds from the sale of our Series A redeemable preferred stock were
approximately $21.1 million. We are required to redeem our Series A redeemable
preferred stock at 100% of its liquidation preference, or $21.1 million (plus
any unpaid dividends), in July 2006.
Devo Merger
On September 28, 2001, we acquired Devo Holding Company, LLC ("Devo") in a
statutory merger under Delaware law. The assets of Devo and its subsidiary, Devo
Operating Company, LLC, consist primarily of South Texas oil and gas producing
properties. We issued $75.0 million in principal amount of our unsecured 11 3/4
% Senior Notes due April 30, 2006 (the "Notes") in a private transaction in
connection with the Devo acquisition, at approximately a 1% discount.
Approximately $65.7 million of the Notes were issued to Devo's note holders in
exchange for all of the principal and accrued interest outstanding under Devo's
Senior Notes due 2003. Approximately $6.5 million of the Notes were issued to
Devo's equity holders as consideration in the Devo acquisition. Jefferies &
Company, Inc. (See Note 12 - Related Party Transactions) received approximately
$2.8 million of the Senior Notes as a financial advisory fee in connection with
the Devo acquisition and for the placement of the Senior Notes. The Senior Notes
are redeemeable after April 30, 2004 at 105%. Prior to that date, Ascent may
redeem up to 35% of the Senior Notes at 111%. The Senior Notes subject Ascent to
certain covenants which, among other things, limit Ascent's ability to pay
dividends, incur additional indebtedness and certain lease obligations, issue
preferred stock exchange or transfer assets.
These transactions were treated as purchases for accounting purposes. The
purchase prices were allocated to the assets and liabilities based on estimated
fair value. No value was assigned to the warrants. The allocations of the
purchase prices are preliminary and subject to change within one year of the
acquisition dates. Net assets acquired in the transactions were as follows:
<Table>
<Caption>
Transactions
(in thousands)
--------------------------------------
Pontotoc Devo
-------- -------
Oil and gas properties $ 91,195 $ 67,449
Working capital,
excluding cash 656 1,775
Debt (7,315) (73,698)
Deferred taxes (31,745) (1,360)
Preferred stock (2,609) -
-------- --------
Net cash paid (received) $ 50,182 $ (5,834)
======== ========
</Table>
The operating results of Pontotoc and Devo have been consolidated in the
Company's statement of operations since July 28, 2001 and September 28, 2001,
respectively.
PREDECESSOR PLAN OF REORGANIZATION.
Our predecessor, Forman Petroleum Corporation, had a Bankruptcy Plan confirmed
by the Bankruptcy Court on December 29, 1999 and consummated effective January
14, 2000. As of the confirmation date, it had total assets of $33.9 million and
liabilities of $96.0 million. Except as described herein, all of our liabilities
as of the confirmation date were extinguished pursuant to the Bankruptcy Plan.
Pursuant to the Bankruptcy Plan, our predecessor issued an aggregate of
approximately $3.6 million of promissory notes to general unsecured creditors
and paid approximately $300,000 to holders of convenience claims. All disputed
claims related to the bankruptcy have been resolved and, by order entered on
December 9, 2000, a final decree was entered that closed the bankruptcy case.
PREDECESSOR FRESH START REPORTING.
Our predecessor accounted for the reorganization by using the principles of
fresh start accounting required by AICPA Statement of Position 90-7, "Financial
Reporting by Entities in Reorganization Under the Bankruptcy Code." For
accounting purposes, our predecessor assumed that the Bankruptcy Plan was
consummated on December 31, 1999. Under the principles of fresh start
accounting, its total assets were recorded at their assumed reorganization
value, with the reorganization value allocated to identifiable tangible assets
at their estimated fair value. Accordingly, its oil and gas full
18
cost pool was reduced by approximately $60 million, its unevaluated oil and gas
properties were increased by approximately $3 million, its other property and
equipment was reduced by approximately $1.6 million, and its accumulated DD&A of
$64.1 million was written off. In addition, its senior notes payable of $70
million, the interest payable of $11.1 million on the senior notes, its
preferred stock of $13.6 million and the related deferred financing costs of
$4.4 million were all written off.
The total reorganization value assigned to its proved oil and gas
properties was estimated by adjusting the net pre-tax future cash flows
discounted at a 10% annual rate (PV-10) of its proved reserves ($36.4 million)
as set forth in the Estimate of Reserves and Future Revenue report on its proved
oil and gas properties as of December 31, 1999, prepared by Netherland, Sewell &
Associates. This report was prepared in accordance with SEC guidelines,
utilizing constant prices existing as of December 31, 1999. These prices were
adjusted to reflect the product prices used in valuing producing properties, and
then our predecessor applied risking factors to the various categories of proved
properties, discounting the properties as indicated:
<Table>
<Caption>
PROVED CATEGORY RISK FACTOR
- --------------- -----------
Proved Producing 95%
Proved Non-producing 75%
Proved Undeveloped 25%
</Table>
Applying these risk factors and adjusting the product pricing resulted in
an estimated net realizable value of the PV-10 of the proved properties of $25.5
million. Our predecessor's other assets, including other property and equipment,
were valued at $4.9 million. As a result of the implementation of fresh start
accounting, our predecessor's financial statements after consummation of the
Bankruptcy Plan are not comparable to our financial statements of prior periods.
The effect of the Bankruptcy Plan and the implementation of fresh start
accounting on our predecessor's balance sheet as of December 31, 1999 are
discussed in detail in Note 1 to the Consolidated Financial Statements.
Oil and Gas Properties
Ascent uses the full-cost method of accounting, which involves capitalizing all
exploration and development costs incurred for the purpose of finding oil and
gas reserves, including the costs of drilling and equipping productive wells,
dry hole costs, lease acquisition costs and delay rentals. The Company also
capitalizes certain related employee costs and general and administrative costs
which can be directly identified with significant acquisition, exploration and
development projects undertaken. Such costs are amortized on the future gross
revenue method whereby amortization is computed using the ratio of gross
revenues generated during the period to total estimated future gross revenues
from proved oil and gas reserves. Additionally, the capitalized costs of oil and
gas properties cannot exceed the present value of the estimated net cash flow
from its proved reserves, together with the lower of cost or estimated fair
value of its undeveloped properties (the full cost ceiling). Transactions
involving sales of reserves in place, unless extraordinarily large portions of
reserves are involved, are recorded as adjustments to accumulated depreciation,
depletion and amortization.
Revenue Recognition
We recognize oil and gas revenue upon the sale to a third party purchaser and
follow the sales method for accounting for gas imbalances. Our gas imbalances as
of December 31, 2001 and 2000 were insignificant.
Recent Accounting Pronouncements
In July 2001, SFAS No. 143 "Accounting for Asset Retirement Obligations" was
approved, requiring the fair value of liabilities for asset retirement
obligations to be recorded in the period incurred. The standard is effective
for fiscal years beginning after June 15, 2002, with earlier application
permitted. We expect to adopt SFAS No. 143 on January 1, 2003. Upon adoption of
the standard, we will be required to use a cumulative-effect approach to
recognize transition amounts for any existing asset retirement obligation
liabilities, asset retirement costs and accumulated depreciation. We have not
yet determined the transition amounts.
In July 2001, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standard (SFAS) No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 prohibits
the use of the pooling-of-interest method of accounting for all business
combinations initiated after June 30, 2001. SFAS No. 142 requires that goodwill
not be amortized in any circumstances and also requires goodwill to be tested
for impairment annually or when events or circumstances occur between annual
tests indicating that goodwill for a reporting unit might be impaired and is
effective for fiscal years beginning after December 15, 2001. The adoption of
SFAS Nos. 141 and 142 is not expected to have a material impact on our
financial statements, because we do not have any goodwill recorded.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Statement establishes accounting and
reporting standards that require every derivative instrument (including certain
derivative instruments embedded in other contracts) to be recorded in the
balance sheet as either an asset or a liability measured at its fair value and
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. The Company adopted SFAS No.
133 on January 1, 2001.
OPERATING ENVIRONMENT
Our revenues, profitability and future growth and the carrying value of
our oil and natural gas properties are substantially dependent on prevailing
prices of oil and natural gas. Our ability to increase our borrowing capacity
and to obtain additional capital on attractive terms is also influenced by oil
and natural gas prices. Prices for oil and natural gas are subject to large
fluctuations in response to relatively minor changes in the supply of or demand
for oil and natural gas, market uncertainty and a variety of additional factors
beyond our control. Any substantial and extended decline in the price of oil or
natural gas would have an adverse effect on the carrying value of our proved
reserves, borrowing capacity, revenues, profitability and cash flows from
operations. Price volatility also makes it difficult to budget for and project
the return on either acquisitions or development and exploitation projects.
We use the full cost method of accounting for our investment in oil and
natural gas properties. Under the full cost method of accounting, all costs of
acquisition, exploration and development of oil and natural gas reserves are
capitalized into a "full cost pool" as incurred, and properties in the pool are
depleted and charged to operations using the future gross revenue method based
on the ratio of current gross revenue to total proved future gross revenues,
computed based on current prices. To the extent that such capitalized costs (net
of accumulated depreciation, depletion and amortization) less deferred taxes
exceed the present value (using a 10% discount rate) of estimated future net
cash flow from proved oil and natural gas reserves, and the lower of cost and
fair value of unproved properties after income tax effects, excess costs are
charged to operations. Once incurred, a write-down of oil and natural gas
properties is not reversible at a later date even if oil or natural gas prices
increase. We reduced our full cost pool in 1999 in connection with the
bankruptcy of our predecessor and again in the third quarter of 2001 with a
ceiling-test write down.
At the third quarter 2001 review of the ceiling test, we utilized substantially
higher subsequent period prices from the September 30, 2001 levels to determine
any potential ceiling test write-down. Utilizing November 12, 2001 pricing
levels which left the oil price unchanged from September 30, 2001 and the
natural gas price increasing to $2.95 per MMBtu from $2.24 per MMBtu for that
same period, we calculated and recorded a non-cash ceiling test write-down of
$2.7 million (net of taxes of $1.6 million). If our discounted cash flows
valued using September 30, 2001 prices had been used in calculating the ceiling
test write-down, we would have recorded a write-down of $22.8 million (net of
taxes of $11.6 million).
At the December 31, 2001 review of the ceiling test, we utilized substantially
higher subsequent period prices from the December 31, 2001 levels to determine
any potential ceiling test write-down. Utilizing April 10, 2001 pricing levels
which showed oil prices increasing to $26.13 per barrel from $19.84 per barrel
at December 31, 2001 and the natural gas price increasing to $3.18 per MMBtu
from $2.65 per MMBtu for that same period, we calculated that no non-cash
ceiling test write-down was necessary. If our discounted cash flows valued
using December 31, 2001 prices had been used in calculating the ceiling test
write-down, we would have recorded a write-down of $39.7 million (net of taxes
of $23.3 million).
19
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect
to our oil and natural gas operations and summary information with respect to
our estimated proved oil and natural gas reserves. See "Item 2. Properties -
Natural Gas and Oil Reserves."
<Table>
<Caption>
YEAR ENDED DECEMBER 31,
2001 2000 1999
---- ---- ----
Production:
Oil (MBbls) 442 270 343
Gas (MMcf) 3,010 1,797 3,091
Oil and gas (MMCFE) 5,662 3,418 5,149
Sales data (in thousands):
Total oil sales $ 9,884 $ 7,421 $ 5,954
Total gas sales $ 11,860 $ 7,276 $ 7,038
Average sales prices:
Oil (per Bbl) $ 22.36 $ 27.49 $ 17.36
Gas (per Mcf) $ 3.94 $ 4.05 $ 2.28
Per MCFE $ 3.84 $ 4.30 $ 2.52
Average costs (per MCFE):
Lease operating expenses $ 0.97 $ 0.98 $ 0.61
General and administrative $ 0.75 $ 0.78 $ 0.59
Depreciation, depletion and amortization (1) $ 1.37 $ 1.31 $ 1.09
Reserves at December 31:
Oil (MBbls) 12,376 2,667 1,612
Gas (MMcf) 85,704 26,260 18,996
Oil and gas (MMCFE) 159,960 42,262 28,668
Present value of estimated pre-tax future
Net cash flows (in thousands) $158,183 $182,313 $36,440
</Table>
(1) - Excludes impairment.
YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000
Our oil and gas revenues increased approximately $7.0 million, or 48%
during 2001 to $21.7 million compared to $14.7 million in 2000. Production
levels for 2001 increased 65.8% to 5,662 million cubic feet of gas equivalent
("MMCFE") from 3,418 MMCFE for 2000. Gas production volumes increased 67.5%,
while oil production volumes increased 63.8%. Our average sale prices (including
hedging activities) for oil and natural gas for 2001 were $22.35 per Bbl and
$3.94 per Mcf versus $27.49 per Bbl and $4.05 per Mcf in 2000. Revenues
decreased $904,000 due to lower oil and gas prices during 2001, offset by a
$867,000 increase in revenues due to the production increases from properties
owned at the beginning of 2001, plus a $7.0 million increase from properties
acquired during 2001..
On an MCFE basis, lease operating expenses decreased 1.1%, to $0.97 per
MCFE for 2001 from $0.98 per MCFE in 2000. For 2001, actual lease operating
expenses were up 61.8%, from $3.4 million in 2000 to $5.5 million in 2001. This
increase was due primarily to property acquisitions in 2001.
20
Our effective severance tax rate as a percentage of oil and gas revenues
increased to 6.6% for 2001 from 4.4% for 2000. This relatively higher effective
rate is attributable to the increased production from wells that do not have a
state severance tax exemption under Louisiana's severance tax abatement program.
For 2001, depreciation, depletion and amortization ("DD&A") expense
increased 73.2% from 2000. The increase for the year is attributable to our
increased production and related future capital costs in 2002 and from
acquisitions of reserves. On a MCFE basis, which reflects the increases in
production, the DD&A rate for 2001 was $1.37 per MCFE compared to $1.31 per MCFE
for 2000, an increase of 4.6%. The increase in DD&A per MCFE was due primarily
to an increase in the full cost pool and variations in pricing during the year.
At September 30,2001 a non-cash ceiling-test write-down of $4.3 million ($2.7
million net of taxes) was recorded.
For 2001, on an MCFE basis, general and administrative ("G&A") expenses
decreased 3.8%, from $0.78 per MCFE in 2000 to $0.75 per MCFE in 2001. The
decrease in G&A per MCFE in 2001 was due to the increase in production during
2001 as compared to 2000. Actual G&A expenses increased 59.2%, from $2.7 million
in 2000 to $4.3 million in 2001. The increase in G&A expenses was due to the
addition of Pontotoc and Devo, severance payments and new staffing of the
enlarged company.
The discounted present value of our reserves decreased 13.2%, from $182.3
million at the end of 2000 to $158.2 million at the end of 2001, primarily as a
result of the significant decreases in both oil and gas prices between December
2000 and December 2001, despite the significant addition of reserves from
acquisitions.
Interest expense for 2001 increased from $0.0 million in 2000 to $3.3
million for 2001. This increase of $3.3 million in interest expense is due to
the incurrence of interest from the Revolving Credit Facility and the Senior
Notes incurred in conjunction with the Pontotoc and Devo acquisitions.
Due to the factors described above, our net loss attributable to common
shares for 2001 was $3.0 million, a decrease of $4.7 million from the net income
of $1.7 million in 2000.
We were required to establish a net deferred tax liability calculated at
the applicable Federal and state tax rates resulting primarily from financial
reporting and income tax reporting basis differences in oil and gas properties.
Accordingly, as a result of fresh start accounting and the Pontotoc and Devo
acquisitions a net deferred tax liability of $38.6 million was recorded at
December 31, 2001.
YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999
Our oil and gas revenues increased approximately $1.7 million, or 13%
during 2000 to $14.7 million compared to $13.0 million in 1999. Production
levels for 2000 decreased 33.7% to 569 thousand barrels of oil equivalent
("MBOE") from 859 MBOE for 1999. Gas production volumes decreased 41.9%, while
oil production volumes decreased 21.4%. Our average sale prices (including
hedging activities) for oil and natural gas for 2000 were $27.49 per Bbl and
$4.05 per Mcf versus $17.34 per Bbl and $2.28 per Mcf in 1999. Revenues
increased $5.9 million due to higher oil and gas prices during 2000, offset by a
$4.2 million decrease in revenues due to the aforementioned production
decreases.
On a BOE basis, lease operating expenses increased 60.7%, to $5.89 per
BOE for 2000 from $3.66 per BOE in 1999. For 2000, actual lease operating
expenses were up 6.6%, from $3.1 million in 1999 to $3.4 million in 2000. This
increase was due primarily to an increase in workover activity in 2000.
Our effective severance tax rate as a percentage of oil and gas revenues
decreased to 4.4% for 2000 from 5.6% for 1999. This relatively low effective
rate is attributable to the increased production from wells that have a state
severance tax exemption under Louisiana's severance tax abatement program. The
decreases in the effective tax rates between 1999 and 2000 are partially offset
by the increase in the gas severance tax rate in 2000.
For 2000, depreciation, depletion and amortization ("DD&A") expense
decreased 19.9% from 1999. The decrease for the year is attributable to our
decreased production and related future capital costs in 2000 and the upward
revision of reserves. On a BOE basis, which reflects the decreases in
production, the
21
DD&A rate for 2000 was $7.87 per BOE compared to $6.52 per BOE for 1999, an
increase of 21%. The increase in DD&A per BOE was due primarily to an increase
in the full cost pool and variations in pricing during the year. Reserve
additions as of December 31, 2000, affected only the fourth quarter DD&A
calculation.
For 2000, on a BOE basis, general and administrative ("G&A") expenses
increased 32.9%, from $3.51 per BOE in 1999 to $4.67 in 2000. The increase in
G&A per BOE in 2000 was due to the decrease in production during 2000 as
compared to 1999. Actual G&A expenses decreased 11.8%, from $3.0 million in 1999
to $2.7 million in 2000. The decrease in actual G&A expenses for 2000 was
primarily the result of the capitalization of G&A expenses, in the amount of
$842,391, into the full cost pool in 2000. No G&A was capitalized into the full
cost pool for 1999 due to the bankruptcy and lack of funds to conduct
acquisition and exploration activities. Without this capitalization of G&A in
2000, G&A on a BOE basis increased 75%, to $6.14 in 2000. Actual G&A in 2000,
without the capitalization in 2000, increased $485,000 primarily due to income
and franchise taxes, the addition of directors' fees and increases in contract
services related to the appointment of our new president in June 2000. The
recapitalization costs incurred in conjunction with our reorganization of
$899,000 were not included in recurring G&A for comparison purposes.
The discounted present value of our reserves increased 500%, from $36.4
million at the end of 1999 to $182 million at the end of 2000, primarily as a
result of the significant increases in both oil and gas prices between December
1999 and December 2000, combined with the new reserves attributable to workovers
and recompletions of wells in our Boutte and Lake Enfermer Fields. Our realized
oil prices increased 58.6% between December 31, 1999 and December 31, 2000, from
an average price per barrel of $17.34 for 1999 to an average price of $27.49 for
2000. Our realized gas prices in 2000 increased 77.8% over the realized 1999
price, from an average price per Mcf of $2.28 for 1999 to an average price per
Mcf of $4.05 for 2000.
Interest expense for 2000 decreased from $6.2 million in 1999 to $0 for
2000. Actual interest expense of $274,000 was incurred in 2000 but was
capitalized into the unevaluated property within the full cost pool for
reporting purposes. This decrease of $5.9 million in interest expense is due to
the cessation of interest payable on our senior notes, which were canceled as a
result of the reorganization effective January 14, 2000.
Due to the factors described above, our net income from operations before
extraordinary items for 2000 was $1.7 million, an increase of $2.1 million from
the net loss of $349,405 for 1999.
We were required to establish a net deferred tax liability calculated at
the applicable Federal and state tax rates resulting primarily from financial
reporting and income tax reporting basis differences in oil and gas properties.
Accordingly, as a result of fresh start accounting a net deferred tax liability
of $9.9 million was recorded at December 31, 1999.
LIQUIDITY AND CAPITAL RESOURCES
WORKING CAPITAL AND CASH FLOW. We use cash flows from operations and borrowings
under our credit facility to fund our future acquisition, exploration and
development activities and our working capital requirements. Our future cash
flow from operations will depend on our ability to maintain and increase
production through our exploration, development and exploitation activities, as
well as the prices of oil and natural gas.
As of December 31, 2001, we had $6.0 million of working capital,
compared to working capital at December 31, 2000 of $4.7 million. The increase
in working capital between the periods is primarily due to the increase in fair
value of derivatives of $4.9 million despite lower product prices during the
last three months of 2001 as compared to the same period in 2000.
The following summary table reflects our comparative cash flows for
the twelve month periods ended December 31, 2001 and 2000:
22
<Table>
<Caption>
TWELVE MONTHS ENDED
DECEMBER 31,
(IN THOUSANDS)
2001 2000
-------- --------
Net cash provided by operating activities $ 6,775 $ 4,050
Net cash (used) by investing activities (53,635) (3,325)
Net cash provided (used) by financing
activities 45,203 (177)
</Table>
For the twelve months ended December 31, 2001 net cash provided by
operating activities increased to $6.8 million from $4.1 million during the
comparable period in 2000 due primarily to the property acquisitions during the
twelve months of 2001 as compared to those realized during the same period in
2000. Cash used in investing activities during the twelve months ended December
31, 2001 increased to $53.6 million from $3.3 million during the comparable
period in 2000 due to the acquisition of Pontotoc, offset by net cash received
in the Devo acquisition, during the 2001 period. Cash used by financing
activities increased from $(0.2) in the twelve months of 2000 to $45.3 million
2001 due primarily to proceeds from the Bank Credit Facility and the Series A
preferred stock.
Our capital expenditure budget for 2002 will focus on exploitation,
exploration and development of our existing properties in Oklahoma, Louisiana
and South Texas. We plan to retain controlling interests in our operated
properties which allows us the ability to control the timing of our capital
commitments and the ability to adjust our spending as oil and gas prices
fluctuate. Our capital expenditure plans for development and exploitation
activities for 2002 are currently estimated to be approximately $22.0 million.
Actual levels of capital expenditures may vary significantly due to many
factors, including drilling results, oil and natural gas prices, industry
conditions, participation by other working interest owners and the prices of
drilling rigs and other oilfield goods and services. We believe that our cash
flows from operations, borrowings under our credit facility and our working
capital will be sufficient to meet our capital expenditure plans for development
and exploitation activities through the end of 2002 and our obligations for 2002
under the long term notes issued under our predecessor's bankruptcy plan.
Part of our strategy involves the acquisition of additional
properties. We plan to explore outside funding opportunities including equity or
additional debt financings for use in consummating additional acquisitions. We
do not know whether any financing can be accomplished on terms that are
acceptable to us.
The Company is currently considering the sale of its Louisiana
properties. It intends to engage Jefferies & Company, Inc., a large shareholder
of the Company, to act as financial advisor for this possible sale.
BANK CREDIT FACILITY. As of March 29, 2002, we had $38.5 million
outstanding under our credit facility with our bank. Our line of credit is
secured by a mortgage lien on substantially all or our oil and gas properties
and a security interest in all oil and gas production and production proceeds
from those properties.
The credit facility provides for interest periods of one, two, three
or six months for LIBOR rate loans. We may also elect to pay interest at a base
rate calculated by reference to the higher of the federal funds rate or The
Chase Manhattan Bank's prime rate. In the case of either LIBOR rate loans or
base rate loans, we must pay an additional interest rate margin that varies with
the aggregate amount of loans and letters of credit outstanding under the line
of credit.
At September 28, 2001, our bank agreed to amend our credit facility
to provide for borrowings of up to $50 million to finance our future acquisition
opportunities and to assist in meeting our working capital requirements. Our
initial borrowing base is $45 million. The amended credit facility will allow
our bank to periodically redetermine our borrowing base by applying similar
criteria to those used with
23
similarly situated oil and gas borrowers. The availability under the Credit
Facility at March 29, 2002 is $4.2 million.
We have received from our bank an amendment to the credit agreement which
provides for both a modification to the EBITDA to debt test as well as a change
to the calculation of EBITDA. EBITDA is defined as earnings before interest,
tax, depletion and amortization. The test thresholds will be changed for the
first three quarter of 2002 to now require the debt/EBITDA result to be no
greater than 5:1 from the previous 4.5:1 test level. In addition, our bank
modified the EBITDA calculation to now be based on a full trailing twelve-months
on a pro forma basis versus the previous test which started calculating EBITDA
from July 1, 2001 and then annualizing that period. If the amendment had not
been made we would have been out of compliance with our credit agreement at
December 31, 2001.
PREFERRED STOCK. In order to preserve cash on hand, our board of
directors elected not to declare the quarterly dividends on 21,100 shares of our
outstanding 8% Series A redeemable preferred stock (Series) with an aggregate
liquidation value of $21,100,000, and on 5,323,695 shares of our outstanding 8%
Series B convertible preferred stock (Series B) with an aggregate liquidation
value of $13,309,237. Unpaid dividends on our preferred stock continue to accrue
and accumulate despite nonpayment, and the liquidation preference of our
preferred stock increases by the amount of any unpaid dividends. We are required
to redeem our Series A redeemable preferred stock for 100% of its liquidation
preference, plus an amount equal to all dividends (whether or not earned or
declared) accrued and unpaid on each share, in July 2006. In addition, we are
required to pay any accrued and unpaid dividends on our Series B convertible
preferred stock in July 2003 when our Series B convertible preferred stock
automatically converts into shares of our common stock. The total amount of the
dividends accrued on our Series A redeemable preferred stock as of December 31,
2001 is approximately $721 thousand, and the total amount of the dividends
accrued on our Series B convertible preferred stock as of the same date is
approximately $446 thousand.
Neither the Series A nor the Series B have voting rights except to the extent
that to vote on an amendment or waiver of the provisions of our certificate of
incorporation or the related certificates of designations that would materially
and adversely affect any right, preferences or privilege of the Series A or
Series B or the holders thereof.
WARRANTS. In conjunction with the issuance of the Series A, warrants to purchase
4,050,000 shares of common stock were issued to the holders of the Series A. The
warrants may be exercised in whole or part at any time until June 30, 2011. Each
warrant entitles the holder to purchase 191.943 shares of common stock at an
exercise price of $5.21 per share.
Beginning 185 days after our common stock is registered under Section 12(b) or
12(g) of the Securities Exchange Act of 1934, the holders of a majority of the
shares of common stock issuable upon exercise of the warrants described above
will have the right to require us to file a registration under the Securities
Act of 1933 for the sale by such holders of not less than 5% of our then
outstanding shares of common stock. We will not be required to make more than
four such stand-alone registrations under the Registration Rights Agreement, and
no more than two such registrations during any twelve-month period. Under the
Registration Rights Agreement, the holders of registrable securities will also
have the right to include their registrable securities in any other registration
statement we file involving our common stock.
24
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
HEDGING ACTIVITY - We enter into hedging transactions to secure a price
for a portion of future production that is acceptable to us at the time the
transaction is entered into. The primary objective of these activities is to
reduce our exposure to the possibility of declining oil and gas prices during
the term of the hedge. We do not enter into hedging transactions for trading
purposes. We currently utilize four forms of hedging contracts: fixed price
swaps, puts, collars and physical futures contracts.
Fixed price swaps typically provide monthly payments by us (if prices
rise) or to us (if prices fall) based on the difference between the strike price
and the agreed-upon average of either New York Mercantile Exchange ("NYMEX") or
other widely recognized index prices ("Index").
Put contracts are not costless; they are purchased at a rate per unit of
hedged production that fluctuates with the commodity futures market. The
historical cost of the put contracts represents our maximum cash exposure. We
are not obligated to make any further payments under the put contracts
regardless of future commodity price fluctuations. Under put contracts, monthly
payments are made to us if Index prices fall below the agreed upon floor price,
while allowing us to fully participate in commodity prices above that floor.
Collar contracts can often be costless; they are purchased at a rate per
unit of hedged production that fluctuates with the commodity futures market. If
Index prices fall below the floor level of a collar, a monthly payment is made
to us; if Index prices rise above the ceiling level of a collar, a monthly
payment is made by us.
Physical futures contracts are an obligation to deliver the physical
commodity at a designated location at the end of a contract period. We use this
type of a contract as a financial vehicle and do not intend to deliver physical
quantities. Margin accounts are often required. The upside and downside exposure
on this type of contract is great. If the commodity price drops the contracts
increase in value and if the commodity price increases the contracts decrease in
value and may become a liability.
We believe that fluctuations in Index prices will closely match changes in
market prices for our production. Oil contracts typically settle using the
average of the daily closing prices for a calendar month. Natural gas contracts
typically settle using the average closing prices of near month Index futures
contracts for the three days prior to the settlement date.
Our hedge positions as of December 31, 2001 are summarized as follows:
<Table>
<Caption>
PUTS
---------------------------------------------------------------
GAS OIL
---------------------------- ---------------------------
VOLUME VOLUME
(BBTUS) FLOOR (BBLS) FLOOR
-------- ----------- -------- ---------
2002 0.420 3.50 - 4.00 - -
2003 - - 180,000 20.00
</Table>
25
<Table>
<Caption>
FIXED PRICE GAS SWAPS
--------------------------------------------
Volume (Bbtus) Price
------------------ ----------------
2002 1.460 3.60
2003 0.972 3.60
</Table>
<Table>
<Caption>
OIL COLLARS
-------------------------------------------------------
VOLUME (BBLS) FLOOR CEILING
------------- ------------ --------------
2002 18,600 $24.00 $26.90
2002 9,300 $25.00 $28.70
2002 200,400 $24.00 $26.90
2003 18,600 $24.00 $26.90
2003 15,500 $23.00 $24.85
</Table>
<Table>
<Caption>
PHYSICAL FUTURE CONTRACTS
------------------------------------------------------------------------
GAS OIL
--------------------------------- ---------------------------------
VOLUME (BBTUS) STRIKE PRICE (1) VOLUME (BBLS) STRIKE PRICE (1)
-------------- ---------------- ------------- ----------------
2002 1.050 $3.101 153,000 $24.70
2003 1.140 $3.543 - -
</Table>
- -----------------------------------
(1) Average strike price for the period
During the year ended December 31, 2000, we realized no oil and gas
revenues related to hedging transactions. During the year ended December 31,
2001 and during the fourth quarter of 2001, we realized oil and gas revenues
related to hedging settlements of $$0.8 million.
At December 31, 2001, the unsettled contracts were recorded as assets
totaling $4.9 million. All changes in fair values of the contracts were recorded
in equity through other comprehensive income, amounting to $1.1 million, net of
tax.
See "Item 1. Cautionary Statements - Our use of hedging transactions for a
portion of our oil and gas production may limit future revenues from price
increases and result in significant fluctuations in our stockholders' equity".
26
Despite the measures we may take to attempt to control price risk, we will
remain subject to price fluctuations for oil and natural gas sold in the spot
market. Prices received for natural gas sold in the spot market are volatile due
primarily to seasonality of demand and other factors beyond our control. Oil and
natural gas prices can change dramatically primarily as a result of the balance
between supply and demand. Over the last four years there has been significant
volatility in both the natural gas price and the oil price. Our average natural
gas price received for 2001 was $3.90 per Mcf, down from $4.05 per Mcf in 2000
and $2.28 per Mcf in 1999. Our average oil price received for 2001 was $22.35
per Bbl, down from our average price received of $27.49 in 2000 and $17.34 in
1999. There can be no assurance that prices will not decline from current
levels. Declines in domestic oil and natural gas prices could have a material
adverse effect on our financial position, results of operations and quantities
of reserves recoverable on an economic basis.
Subsequent to December 31, 2001, in early March 2002, the Company entered
into a series of natural gas hedges covering 9.8 BCF of natural gas for the
period April 2002 through December 2004. The derivatives are settled based upon
the Houston Ship Channel Index Price at the end of the preceding month. The new
hedging transactions are as follows:
<Table>
<Caption>
FIXED PRICE NATURAL GAS SWAPS
---------------------------------------
Volume (Bbtus) Price
-------------- ---------
2002 0.735 3.25
2003 1.095 3.25
2003 1.098 3.25
</Table>
<Table>
<Caption>
NATURAL GAS COLLARS
------------------------------------------------------
VOLUME (BBTUS) FLOOR CEILING
-------------- --------- ------------
2002 490.0 $2.50 $2.85
1,225.0 $2.50 $3.19
2003 730.0 $2.75 $3.53
1,825.0 $3.00 $3.39
2004 732.0 $3.00 $3.47
1,830.0 $3.00 $3.66
</Table>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information concerning this Item begins on Page F-1
This filing contains unaudited financial statements in lieu of audited financial
statements because the Company was unable to obtain from Arthur Andersen LLP a
manually signed report. Please see page F-1 for additional information.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
27
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following table provides information concerning our directors and
executive officers. All officers serve at the discretion of the Board of
Directors.
<Table>
<Caption>
Name Age Position Since
- ---- --- -------- -----
Jeffrey Clarke 56 President, CEO, and Director 2001
Nicholas Tell, Jr. 40 Chairman of the Board 2001
Jerry W. Box 63 Director 2001
Daniel O. Conwill, IV 41 Director 2001
James L. Luikart 57 Director 2001
Eric R. Macy 43 Director 2001
James "Robby" Robson, Jr. 43 Vice President and Director 2001
Kevin D. McMillan 43 Senior Vice President and CFO 2001
Larry L. Keller 43 Senior Vice President of Operations 2001
</Table>
Our bylaws provide that we have a classified board of directors comprised
of three classes, each of which serves for three years, with one class being
elected each year. The terms of Messrs. Clarke and Robson will expire in 2002,
terms of Messrs. Box and Luikart in 2003, and the terms of Messrs. Conwill, Macy
and Tell in 2004.
A brief biography of each director and executive officer follows:
Jeffrey Clarke has been a Director since our inception. Mr. Clarke has
been the President of the Company since January 2001. Since June 2000, Mr.
Clarke has been President of our predecessor company. From September 1993 to
March 2000, Mr. Clarke served as Chairman and Chief Executive Officer of Coho
Energy, Inc., an independent energy company engaged in the development and
production of, and exploration for, crude oil and natural gas principally in
Mississippi and Oklahoma. From August 1990 to September 1993, Mr. Clarke served
as President and Chief Operating Officer of Coho Energy, Inc. Prior to that
time, Mr. Clarke served in various capacities with Coho Resources, Ltd. and Coho
Resources, Inc., affiliates of Coho Energy, Inc. Coho Energy, Inc. and certain
of its affiliates filed for protection under Chapter 11 of the United States
Bankruptcy Code on August 23, 1999. Coho's bankruptcy reorganization plan was
approved in March 2000. Mr. Clarke holds a BS, in Physics, from University of
Wales, 1967, and conducted postgraduate work in Physics at the University of
East Anglia, 1967-1968.
Nicholas Tell, Jr., has been a Director since our inception. Mr. Tell is
the Managing Director, Capital Markets and Special Situations, of TCW. Mr. Tell
joined TCW when TCW acquired Crescent in 1995. Previously, Mr. Tell was Vice
President and Counsel of Crescent where he structured and negotiated many of the
firm's private investments. Prior to joining Crescent, Mr. Tell was a Senior
Associate at Latham & Watkins. From 1987 through 1992, Mr. Tell was involved in
a wide variety of corporate transactions, including mergers and acquisitions and
corporate financings for below-investment-grade companies. Mr. Tell received his
Juris Doctor from the University of Chicago and his B.A. from Carleton College.
Jerry W. Box has been a Director since August 2001. .Mr. Box served as
the President and Chief Operating Officer of Oryx Energy Company from 1998 until
shortly after the merger of Oryx Energy Company with Kerr-McGee Corporation in
early 1999. From 1988 through 1998, Mr. Box served in various other capacities
with Oryx Energy Company. Mr. Box holds a BS and an MS, in Geology, from
Louisiana Tech University. He is also a graduate of the Program for Management
Development at Harvard Business School.
28
Daniel O Conwill, IV has been a Director since our inception. Mr. Conwill
has been an Executive Vice President and Director of Corporate Finance of
Jefferies & Company, Inc. since January 1993. He has also been a member of the
Board of Directors of Jefferies & Company, Inc. since 1993. From June 1987 to
January 1993, Mr. Conwill was a Managing Director in the Corporate Finance
Department of Howard, Weil, Labouisse, Friedrichs Incorporated where he had
primary responsibility for exploration and production companies. From February
1985 to June 1987, Mr. Conwill was a Certified Public Accountant with the Tax
Department of Arthur Andersen & Co. Mr. Conwill received his Bachelors and
Masters Degrees in Accounting from the University of Mississippi and has a law
degree from the University of Mississippi School of Law.
James L. Luikart has been a Director since September, 2001. Mr. Luikart
is an Executive Vice President of FS Private Investments, the sponsor and
manager of a series of private equity investment funds. Mr. Luikart joined the
management of FS Private Investments in 1994 after serving for over 20 years as
an officer of Citicorp, the last seven years of which were as Vice President of
Citicorp Venture Capital, Ltd., where his investing and directorships were
largely concentrated in the healthcare, software, media and consumer products
sectors. Mr. Luikart received a BA magna cum laude in history from Yale
University and an M.I.A. from Columbia University. Mr. Luikart currently serves
on the boards of Amerifit Nutrition, Ascent Pediatrics, Dynamic Gunver
Technologies ivpcare and K-Sea Transportation.
Eric R. Macy has been a Director since September, 2001. Mr. Macy is an
Executive Vice President of Jefferies, where he is head of High Yield Trading.
Prior to joining Jefferies in 1991, Mr. Macy worked for six years in the High
Yield Department of Donaldson, Lufkin and Jenrette Securities Corporation. Mr.
Macy received a B.A. in Business from the University of California at Los
Angeles.
James "Robby" Robson, Jr. has been a Director since August 2001. Mr.
Robson served as President, Chief Executive Officer and Director of Pontotoc
Production, Inc. from December 1997 until we acquired Pontotoc in July 2001 and
he became one of our Vice Presidents. Mr. Robson also held these same positions
with Pontotoc Production Company, Inc., Pontotoc Production, Inc.'s wholly-owned
subsidiary, from January 1987 until we acquired Pontotoc in August 2000. From
January 1985 to January 1987, he worked as a consultant for Pontotoc Production
Company, Inc. From April 1982 to January 1985, he served as President of Robco
Oil Co. From August 1981 to March 1982 he served as Vice President of Marketing
for Daner Oil Co., Inc. From March 1981 until August 1981, he was a free agent
running back with the Pittsburgh Steelers. Mr. Robson attended Youngstown State
University from 1977 to 1981.
Kevin D. McMillan has been Senior Vice President and Chief Financial
Officer since October 2001. From June 2000 to September 2001 Mr. McMillan served
as Treasurer of PetroCosm Corporation. During the period of June 1999 to May
2000, Mr. McMillan served as Senior Vice President and Chief Financial Officer
of Panther Resources L.L.P. From April 1998 to May 1999, Mr. McMillan served as
Senior Vice President and Chief Financial Officer of Frontera Resources
Corporation. From July 1986 until March 1998, Mr. McMillan served in various
capacities for United Meridian Corporation the last of which being Vice
President and Treasurer. He is a graduate of the University of Notre Dame with a
B.B.A. in Accounting.
Larry L. Keller has been Senior Vice President of Operations since July
2001. For the period July 1990 until June 2001, Mr. Keller served in various
capacities with Coho Energy, Inc., the last of which was Vice President,
Exploitation. Coho Energy, Inc. and certain of its affiliates filed for
protection under Chapter 11 of the United States Bankruptcy Code on August
23,1999. Coho's bankruptcy reorganization plan was approved in March 2000. Mr.
Keller received a B.S. in Petroleum Engineering from the Colorado School of
Mines
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth certain information for the fiscal year
ended December 31, 2001 with respect to the compensation paid to Mr. Clarke, the
Chief Executive Officer and President, and the two
29
other most highly compensated executive officers of the Company. No other
executive officers of the Company received annual compensation (including salary
and bonuses earned) that exceeded $100,000 for the fiscal year ended December
31, 2001.
<Table>
<Caption>
Long-Term Compensation
Name and ANNUAL COMPENSATION Securities Underlying All Other
Principal Position YEAR Salary Bonus Options Awarded Compensation
- ------------------ ------ ---------- ---------------------- ------------
Jeffrey Clarke,
President and Chief Executive
Officer 2001 $40,000(1) - - $547,000(4)
Kevin D.
McMillan
Senior Vice President
and Chief Financial
Officer 2001 $39,205(2) - - $3,461(5)
Larry L. Keller
Senior Vice President
of Operations 2001 $78,365(3) - - -
</Table>
(1) - Mr. Clarke became an employee on November 1, 2001.
(2) - Mr. McMillan became an employee on October 29, 2001.
(3) - Mr. Keller became an employee on July 1, 2001.
(4) - From January 1, 2001 through October 31, 2001, Mr. Clarke was a
consultant to the Company and received $200,000 in compensation. In
addition, Mr. Clarke received a success fee, for the completion of the
Pontotoc acquisition, of $347,000, which was paid in-kind with Series B
preferred stock
(5) - Payment of disability insurance premium for Mr. McMillan.
401(K) PLAN
The Company has adopted a defined contribution retirement plan that
complies with Section 401(k) of the Code (the "401(k) Plan"). Pursuant to the
terms of the 401(k) Plan, all employees with at least three months of continuous
service are eligible to participate and may contribute up to 15% of their annual
compensation (subject to certain limitations imposed under the Code). The 401(k)
Plan provides for a discretionary match of employee contributions may be made by
the Company in cash. The 401(k) Plan became effective for the Company on January
1, 2002 These matching employer contributions to the 401(k) Plan are fully
vested to the individuals over a three-year period. Employee contributions under
the 401(k) Plan are 100% vested and participants are entitled to payment of
vested benefits upon termination of employment. The amounts held under the
401(k) Plan are invested among various investment funds maintained under the
401(k) Plan in accordance with the directions of each participant.
Compensation of Directors
COMPENSATION OF DIRECTORS
Outside independent Directors of the Company will receive compensation
for their service as directors in the amount of $5,000 per quarter. Directors of
the Company are also entitled to reimbursement of their reasonable out-of-pocket
expenses in connection with their travel to and attendance at meetings of the
Board of Directors or committees thereof.
EMPLOYMENT AGREEMENTS
There are no employment agreements.
30
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table and notes thereto set forth information regarding
ownership of shares of the Company's Common Stock as of March 30, 2002:
<Table>
<Caption>
BENEFICIAL OWNERSHIP
NUMBER OF PERCENT OF
NAME OF BENEFICIAL OWNERS SHARES CLASS
------------------------- --------- ----------
Forman Petroleum Corporation (1)
650 Poydras Street,
Suite 2200
New Orleans, LA 70130 4,950,000 100.0%
Jefferies & Company (2)(3)
11100 Santa Monica Boulevard
12th Floor
Los Angeles, CA 90025 2,735,188 35.6%
The TCW Funds (4)
11100 Santa Monica Boulevard
Suite 2000
Los Angeles, CA 90025 840,710 14.5%
The ING Funds (5)
11100 Santa Monica Boulevard
12th Floor
Los Angeles, CA 90025 294,057 5.6%
Nicholas W. Tell, JR. 0 0.0%
Daniel O. Conwill, IV (6) 383,886 7.2%
Jeffrey Clarke (7) 113,822 2.2%
Jerry W. Box 0 0.0%
James "Robby" Robson (8) 91,200 1.8%
James L. Luikart (9) 294,057 5.6%
Eric R. Macy (6) 383,886 7.2%
Kevin McMillan 0 0.0%
Larry L. Keller 28,791 Less than 1%
All Directors and Executive
Officers as a group 1,295,642 20.7%
(1) Jefferies & Company, Inc. ("Jefferies") and the TCW Funds own approximately
77.5% and 17.6%, respectively, of the total outstanding voting power of
Forman. In addition, Jefferies and The TCW Funds are each entitled to
designate one member of Forman's four member board of directors.
(2) Represents 2,735,188 shares issuable upon exercise of immediately
exercisable warrants. Includes 672,758 shares issuable upon exercise of
warrants held by Jefferies & Company, Inc.; 383,061 shares issuable upon
exercise of warrants held by Jefferies Partners Opportunity Fund, L.L.C.;
325,085 shares issuable upon exercise of warrants held by Jefferies
Partners Opportunity Fund II, L.L.C.; 81,318 shares issuable upon exercise
of warrants held by Jefferies Employee Opportunity Fund, L.L.C.; and
1,272,966 shares issuable upon exercise of warrants held by Jefferies
Investors XVI, L.L.C. Does not include 4,950,000 shares held by Forman
Petroleum Corporation.
(3) Jefferies Group, Inc., the parent company of Jefferies & Company, Inc., is
deemed to beneficially own the shares owned by Jefferies. As reported in
Jefferies Group's most recent proxy statement, the Jefferies Group, Inc.
Employee Stock Ownership Plan and all the directors and executive officers
of Jefferies Group, Inc., as a group, beneficially own, respectively,
3,897,324 shares (or 15.2%) and 3,294,074 shares (or
31
12.6%) of the outstanding shares of common stock of Jefferies Group. The
terms of the ESOP provide for the voting rights associated with the shares
held by the ESOP to be passed through and exercised exclusively by the
participants in the ESOP to the extent that such securities are allocated
to a participant's account. The shares reported as beneficially owned by
the directors and executive officers include shares subject to immediately
exercisable options.
(4) Represents 840,710 shares issuable upon exercise of immediately exercisable
warrants. Includes 150,099 shares issuable upon exercise of warrants held
by TCW Leveraged Income Trust, IV, L.P.; 510,568 shares issuable upon
exercise of warrants held by TCW Shared Opportunity Fund, III, L.P.; 90,021
shares issuable upon exercise of warrants held by Shared Opportunity Fund,
IIB, L.L.C.; 67,564 shares issuable upon exercise of warrants held by
TCW/Crescent Mezzanine Partners, L.P.; 20,528 shares issuable upon exercise
of warrants held by TCW/Crescent Mezzanine Trust; and 1,919 shares issuable
upon exercise of warrants held by TCW/Crescent Mezzanine Investment
Partners, L.P. Does not include 4,950,000 shares held by Forman Petroleum
Corporation.
(5) Represents 294,057 shares issuable upon exercise of immediately exercisable
warrants. Includes 204,803 shares issuable upon exercise of warrants held
by ING Furman Selz Investors III, L.P.; 62,382 shares issuable upon
exercise of warrants held by ING Barings U.S. Leveraged Equity Plan LLC;
and 26,872 shares issuable upon exercise of warrants held by ING Barings
Global Leveraged Equity Plan Ltd.
(6) Represents 383,866 shares issuable upon exercise of immediately exercisable
warrants held by Jefferies Investors XVI, L.L.C. Messrs. Conwill and Macy
each hold a 30.2% equity interest in Jefferies Investors XVI, L.L.C.
(7) Represents 113,822 shares issuable upon exercise of immediately exercisable
warrants.
(8) Represents 91,200 shares issuable upon conversion of immediately
convertible Series B convertible preferred stock.
(9) Represents 294,057 shares beneficially owned by The ING Funds.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
During September 2001, approximately $65.7 million of the Senior Notes
were issued in exchange for all the principal and accrued interest outstanding
under notes owed by Devo. As further consideration for the acquisition,
approximately $6.5 million of additional Senior Notes were issued to the
shareholders of Devo and approximately $2.8 million in Senior Notes were issued
to Jefferies & Company, Inc. (Jefferies) who together with the TCW Funds held
substantially all of of Devo's senior secured notes and equity and are the
principal shareholders of Ascent. The Devo properties had been acquired by
certain of Devo's members and their affiliates and contributed to Devo in
exchange for Devo's senior secured notes. The seller of the properties was paid
approximately $64.5 million for their interests. Devo paid debt issuance costs
of $1.5 million to Jefferies and $0.4 million to TCW in connection with the
acquisition of the properties.
Also during 2001, Jefferies agreed to lease a portion of the Company's office
space in New Orleans at market prices through the remaining balance of the
Company's lease.
The Company leases office space at market rates on a month-to-month basis from a
company partially owned by a director, James "Robby" Robson, Jr.
In connection with the Pontotoc acquisition, Ascent Energy, our wholly-owned
subsidiary, has agreed to pay its president, Jeffrey Clarke, a success fee in
the amount of approximately $347,000 which was paid in Series A mandatorily
redeemable convertible preferred stock.
32
PART IV.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements
The following consolidated financial statements of the Company are
included on pages F-1 through F-25 of this Form 10-K.
Consolidated Balance Sheet as of the years ended December 31, 2001 and 2000
Consolidated Statement of Operations for the three years in the period ended
December 31, 2001
Consolidated Statement of Stockholders' Equity (Deficit) for the three years in
the period ended December 31, 2001
Consolidated Statement of Cash Flows for the three years in the period ended
December 31, 2001
Notes to the Consolidated Financial Statements
2. Financial Statement Schedules
All schedules are omitted because the required information is
inapplicable or the information is presented in the Financial Statements or the
notes thereto.
3. Exhibits
The following instruments and documents are included as Exhibits to this
Form 10-K:
Exhibit
No. Exhibit
- -------- -------
10 Ascent Energy Inc 2002 Stock Incentive Plan
21.1 List of Subsidiaries
EXHIBITS AND REPORTS ON FORM 8-K
(A) EXHIBITS -
<Table>
<Caption>
Exhibit
No. Exhibit
- ------- -------
2 Agreement and Plan of Merger dated as of January 19, 2001 among
Ascent, Pontotoc Acquisition Corp. and Pontotoc (incorporated herein
by reference to Ascent's Registration Statement on Form
S-4 (Registration No. 333-57746)).
3.1 Certificate of Incorporation of Ascent (incorporated herein by reference to Ascent's
Registration Statement on Form S-4 (Registration No. 333-57746)).
3.2 Bylaws of Ascent (incorporated herein by reference to Ascent's Registration Statement on Form
S-4 (Registration No. 333-57746)).
33
<Table>
<Caption>
Exhibit
No. Exhibit
- ------- -------
4.1 Certificate of Designations of 8% Series A Redeemable Preferred Stock
of Ascent (incorporated herein by reference to Ascent's Quarterly
Report on Form 10-Q for the period ended June 30,
2001).
4.2 Specimen 8% Series A Redeemable Preferred Stock Certificate of Ascent
(incorporated herein by 4.2 reference to Ascent's Quarterly Report on Form
10-Q for the period ended June 30, 2001).
4.3 Certificate of Designations of 8% Series B Convertible Preferred
Stock of Ascent, (incorporated herein by reference to the Ascent's
Registration Statement on Form S-4 (Registration No.
333-57746)).
4.4 Specimen 8% Series B Convertible Preferred Stock Certificate of Ascent
(incorporated herein by 4.4 reference to Ascent's Quarterly Report on
Form 10-Q for the period ended June 30, 2001).
4.5 Form of Warrant (incorporated herein by reference to Ascent's Quarterly
Report on Form 10-Q for 4.5 the period ended June 30, 2001).
4.6 Warrant Agreement dated July 27, 2001 between Ascent and Mellon
Investor Services LLC, as Warrant Agent (incorporated herein by
reference to Ascent's Quarterly Report on Form 10-Q for
the period ended June 30, 2001).
10.1 Stockholders' Agreement dated as of January 19, 2001 among Ascent and
Pontotoc stockholders listed on the signature page thereof
(incorporated herein by reference to Ascent's Registration
Statement on Form S-4 (Registration No. 333-57746)).
10.2 Lease Agreement by and between Pontotoc Gathering, L.L.C. and Enerfin
Resources I Limited Partnership dated July 1, 2000 (incorporated
herein by reference to Ascent's Registration
Statement on Form S-4 (Registration No. 333-57746)).
10.3 Form of Indemnity Agreement (incorporated herein by reference to Ascent's
Registration 10.3 Statement on Form S-4 (Registration No. 333-57746)).
10.4 Registration Rights Agreement, dated as of July 27, 2001 by and among
Ascent and the purchasers named on the signature pages thereto
(incorporated herein by reference to Ascent's Quarterly
Report on Form 10-Q for the period ended June 30, 20 01).
10.5 Loan Agreement, dated as of July 27, 2001 among Ascent, Fortis
Capital Corp., as agent and the lenders signatory thereto
(incorporated herein by reference to Ascent's Quarterly Report on
Form 10-Q for the period ended June 30, 2001).
10.6 Asset Contribution Agreement, dated July 26, 2001 by and between
Ascent and Forman Petroleum Corporation (incorporated herein by
reference to Ascent's Quarterly Report on Form 10-Q for the
period ended June 30, 2001).
10.7 Agreement and Plan of Merger dated as of September 28, 2001 among
Ascent, Devo and Devo Operating Company, LLC (incorporated herein by
reference to Ascent's Current Report on Form 8-K
dated August 14, 2001).
34
<Table>
<Caption>
Exhibit
No. Exhibit
- ------- -------
Indenture dated September 28, 2001 among Ascent, the subsidiary
guarantors named therein and U.S. Bank N.A., as trustee (incorporated
herein by reference to Ascent's Current Report on Form
8-K dated August 14, 2001).
10.9 Exchange Agreement, dated as of September 28, 2001 by and among
Ascent, the subsidiary guarantors named therein and other parties
named therein (incorporated herein by reference to
Ascent's Current Report on Form 8-K dated August 14, 2001).
10.10 First Amendment to the Loan Agreement dated as of September 28, 2001,
between Ascent and Fortis Capital Corp. (incorporated herein by
reference to Ascent's Current Report on Form 8-K dated
August 14, 2001).
10.11 Registration Rights Agreement, dated as of September 28, 2001 among
Ascent and the other parties named therein (incorporated herein by
reference to Ascent's Current Report on Form 8-K
dated August 14, 2001).
</Table>
Reports on Form 8-K
None
35
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, the Registrant has duly caused this Form 10-K to be signed on its
behalf by the undersigned, thereunto duly authorized.
ASCENT ENERGY INC
By: /s/ Kevin D. McMillan
------------------------
Kevin D. McMillan
Senior Vice President and
Chief Financial Officer
Date: April 15, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this Form 10-K has been signed by the following persons in the
capacities and on the dates indicated.
NAME TITLE DATE
---- ----- ----
Chairman of the Board
------------------------
Nicholas Tell, Jr.
/s/ Jeffrey Clarke President, Chief Executive Officer April 15, 2002
------------------------ and Director
Jeffrey Clarke (Principal Executive Officer)
/s/ Kevin D. McMillan Senior Vice President and Chief April 15, 2002
--------------------- Financial Officer
Kevin D. McMillan (Principal Financial Officer)
/s/ Daniel O Conwill, IV Director April 15, 2002
------------------------
Daniel O Conwill, IV
Director
------------------------
Jerry W. Box
/s/ James L. Luikart Director April 15, 2002
------------------------
James L. Luikart
/s/ Eric R. Macy Director April 15, 2002
------------------------
Eric R. Macy
Vice President and
------------------------ Director
James "Robby" Robson, Jr.
</Table>
36
This filing contains unaudited financial statements in lieu of
audited financial statements because the Company was unable to obtain
from Arthur Andersen LLP a manually signed report. The Company expects
to obtain a manually signed report from Arthur Andersen LLP and file
an amended report on Form 10-K containing audited financial
statements on or before April 22, 2002. No auditor has opined that
the unaudited financial statements present fairly, in all material
respects, the financial position, the results of operations, cash
flows and the changes in shareholders' equity of the Company for each
of the periods reported in accordance with generally accepted
accounting principles.
INDEX TO FINANCIAL STATEMENTS
<Table>
<Caption>
Page
----
Consolidated Balance Sheets as of the Years Ended
December 31, 2001 and 2000.................................................................... F-3
Consolidated Statements of Operations for each of the Three Years
in the Period Ended December 31, 2001......................................................... F-4
Consolidated Statements of Stockholder's Equity for each of the
Three Years in the Period Ended December 31, 2001............................................. F-5
Consolidated Statements of Cash Flows for each of the Three Years
In the Period Ended December 31, 2001......................................................... F-6
Notes to Consolidated Financial
Statements.................................................................................... F-7
</Table>
F-1
[TO COME]
F-2
ASCENT ENERGY INC.
CONSOLIDATED BALANCE SHEETS
<Table>
<Caption>
December 31,
---------------------------------
2001 2000
-------------- --------------
ASSETS
------
CURRENT ASSETS:
Cash and cash equivalents $ 2,071,698 $ 3,728,332
Oil and gas revenue receivable 4,452,725 2,594,724
Joint interest and other receivables 921,352 135,473
Prepaid expenses 670,761 373,158
Inventory and other 131,514 -
Fair value of derivatives 4,920,950 -
Current deferred taxes 1,025,807 371,778
-------------- --------------
Total current assets 14,194,807 7,203,465
-------------- --------------
PROPERTY AND EQUIPMENT, at cost:
Oil and gas properties, full cost method 197,845,779 28,481,661
Unevaluated oil and gas properties - 5,006,197
Other property and equipment 3,851,983 287,524
-------------- --------------
201,697,762 33,775,382
Less - accumulated depreciation, depletion and amortization (16,272,089) (4,484,364)
-------------- --------------
Net property and equipment 185,425,673 29,291,018
-------------- --------------
OTHER ASSETS:
Deferred financing costs 2,112,597 -
Escrowed and restricted funds 572,216 487,783
-------------- --------------
Total assets $ 202,305,293 $ 36,982,266
============== ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities $ 3,691,218 $ 518,760
Undistributed oil and gas proceeds 611,565 745,024
Interest payable 2,568,407 -
Current portion of notes payable 1,309,435 1,219,214
-------------- --------------
Total current liabilities 8,180,625 2,482,998
-------------- --------------
LONG-TERM DEBT:
Revolving credit agreement 34,500,000 -
Subordinated debt 74,608,170 -
Notes payable - 1,309,790
Dividends Payable 446,315 -
-------------- --------------
Total debt 109,554,485 1,309,790
-------------- --------------
Deferred income taxes 41,269,514 10,788,208
-------------- --------------
Series A mandatorily redeemable preferred stock, par value $.001 per share,
21,100 shares authorized, issued and outstanding,
liquidation preference $1,000 per share, including accrued dividends 21,813,472 -
-------------- --------------
STOCKHOLDERS' EQUITY:
Series B preferred stock, par value $.001 per share, 5,500,000 shares
authorized, 5,323,695 issued and outstanding, liquidation preference
$2.50 per share 2,608,611 -
Common stock, par value $.001 per share, 20,000,000 shares authorized,
4,950,000 shares issued and outstanding 4,950 4,950
Paid in capital 20,680,057 20,680,057
Retained earnings (accumulated deficit) (2,939,353) 1,716,263
Other comprehensive income 1,132,932 -
-------------- --------------
Total stockholders' equity 21,487,197 22,401,270
-------------- --------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 202,305,293 $ 36,982,266
============== ==============
</Table>
The accompanying notes are an integral part of these
consolidated financial statements.
This filing contains unaudited financial statements in lieu of audited
financial statement because the Company was unable to obtain
from Arthur Andersen LLP a manually signed report.
F-3
ASCENT ENERGY INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
<Table>
<Caption>
Years Ended December 31,
----------------------------------------------
2001 2000 1999
------------ ------------ -------------
Revenues:
Oil sales $ 9,884,171 $ 7,420,871 $ 5,954,302
Gas sales 11,745,624 7,275,817 7,038,412
Other (12,612) 77,517 123,272
------------- ------------- -------------
Total revenues 21,617,183 14,774,205 13,115,986
------------- ------------- -------------
Costs and expenses:
Production taxes 1,421,883 559,334 731,542
Lease operating expenses 5,492,470 3,353,441 3,146,581
General and administrative expenses 4,268,680 2,656,765 3,013,809
Recapitalization expense - 109,130 -
Depreciation, depletion and amortization 7,766,189 4,484,364 5,601,733
Impairment of oil and gas properties 4,250,000 - -
------------- ------------- -------------
Total expenses 23,199,222 11,163,034 12,493,665
------------- ------------- -------------
Net income (loss) from operations (1,582,039) 3,611,171 622,321
Interest and other income 182,072 186,284 -
Interest expense (3,334,883) - (6,243,778)
------------- ------------- -------------
Net income (loss) before reorganization item and income taxes (4,734,850) 3,797,455 (5,621,457)
Reorganization items:
Reorganization costs - (898,760) (1,184,111)
Adjust accounts to fair value (Note 1) - - 6,268,022
------------- ------------- -------------
Net income (loss) before income taxes and extraordinary item (4,734,850) 2,898,695 (537,546)
Income tax provision (benefit) (1,246,996) 1,182,432 (188,141)
------------- ------------- -------------
Net income (loss) before extraordinary item (3,487,854) 1,716,263 (349,405)
Extraordinary gain on extinguishment of debt, net of
taxes of $10,088,721 - - 46,724,052
------------- ------------- -------------
Net income (loss) (3,487,854) 1,716,263 46,374,647
Preferred stock dividends (1,167,762) - (1,152,991)
-------------- ------------- -------------
Net income (loss) attributable to common shares $ (4,655,616) $ 1,716,263 $ 45,221,656
============= ============= =============
Per common share amounts:
Net income (loss) per share attributable to common
shares before extraordinary item $ (0.94) $ 0.35 $ (0.30)
Extraordinary item per share - - 9.44
------------- ------------- ------------
Net income (loss) per share $ (0.94) $ 0.35 $ 9.14
============= ============= ============
Weighted average basic and diluted shares outstanding 4,950,000 4,950,000 4,950,000
============= ============= ============
</Table>
The accompanying notes are an integral part of these
consolidated financial statements.
This filing contains unaudited financial statements in lieu of
audited financial statement because the Company was unable
to obtain from Arthur Andersen LLP a manually signed report.
F-4
ASCENT ENERGY INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
<Table>
<Caption>
Retained Accumulated
Series B Additional Earnings Other
Common Treasury Preferred Paid-In (Accumulated Comprehensive
Stock Stock Stock Capital Deficit) Income Total
------ -------- --------- ----------- ------------- ------------- -------------
Balance, December 31, 1998 $4,950 $ - $ - $20,679,710 $(56,483,603) $ - $(35,798,943)
====== ====== ========== =========== ============ =========== ============
Net income - - - - 46,374,647 - 46,374,647
Accretion of Discount
On Mandatorily
Redeemable
Preferred Stock - - - (27,778) - (27,778) -
Dividends On
Mandatorily Redeemable
Preferred Stock - - - - (1,152,991) - (1,152,991)
Discharge of Preferred
Stock In
Reorganization - - - - 13,555,971 - 13,555,971
Fresh Start Accounting
Adjustments (Note 1) - - - - (2,266,246) - (2,266,246)
Balance, December 31, 1999 $4,950 $ - $ - $20,679,710 $ - $ - $ 20,684,660
------ ------ ---------- ----------- ------------ ----------- ------------
New Common Stock Issued In
Exchange For Warrants - - - 347 - - 347
Net Income - - - - 1,716,263 - 1,716,263
------ ------ ---------- ----------- ------------ ----------- ------------
Balance, December 31, 2000 $4,950 $ - $ - $20,680,057 $ 1,716,263 $ - $ 22,401,270
====== ======= ========== =========== ============ =========== ============
Net Income (Loss)
attributable to common
shares - - - - (4,655,616) - (4,655,616)
Other comprehensive income:
Net change in fair
value of derivatives,
net of tax of $665,372 - - - - - 1,132,932 1,132,932
------ ------ ---------- ----------- ------------ ----------- ------------
Comprehensive income (loss) (3,522,684)
Series B Preferred Stock
Issued in Acquisition of
Pontotoc - - 2,608,611 - - - 2,608,611
------ ------- ---------- ----------- ------------ ----------- ------------
Balance, December 31, 2001 $4,950 $ - $2,608,611 $20,680,057 $ (2,939,353) $ 1,132,932 $ 21,487,197
====== ======= ========== =========== ============ =========== ============
</Table>
The accompanying notes are an integral part of these
consolidated financial statements.
This filing contains unaudited financial statements in lieu of
audited financial statement because the Company was unable
to obtain from Arthur Andersen LLP a manually signed report.
F-5
ASCENT ENERGY INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<Table>
<Caption>
Years Ended December 31,
---------------------------------------------------
2001 2000 1999
--------------- --------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (3,487,854) $ 1,716,263 $ 46,374,647
Adjustments to reconcile net income (loss) to net cash provided
by operating activities-
Extraordinary item - - (46,724,052)
Depreciation and amortization 7,766,189 4,484,364 5,601,733
Deferred income tax provision (benefit) (1,246,996) 515,850 (188,141)
Adjust accounts to fair value - - (6,268,022)
Interest on obligations discharged in bankruptcy - - 6,144,915
Impairment of oil and gas properties 4,250,000 - -
Change in assets and liabilities-
Oil and gas revenue receivable 297,318 (1,235,331) (702,960)
Accounts receivable (1,673,473) 101,190 (188,833)
Prepaid expenses and tax overpayment 13,062 (329,056) 11,067
Interest payable 2,568,407 - 253,309
Accounts payable and accrued liabilities (837,581) (1,052,950) 1,500,435
Undistributed oil and gas revenues (132,459) (150,040) (473,127)
Taxes payable (252,287) - -
Hedge premium paid (489,000) - -
Advance to operator - - 1,200,000
Capitalized recapitalization costs - - 384,313
-------------- -------------- --------------
Net cash provided by operating activities 6,775,326 4,050,290 6,925,284
-------------- -------------- --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for Pontotoc acquisition, net of cash received (50,182,105) - -
Net cash received from Devo acquisition 5,834,398 - -
Additions to oil and gas properties (8,834,200) (3,240,190) (5,173,645)
Reduction of escrow account (78,386) 2,261 3,437
Purchase of other property and equipment (374,939) (87,524) (48,639)
--------------- --------------- ---------------
Net cash used in investing activities (53,635,232) (3,325,453) (5,218,847)
-------------- -------------- --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of Pontotoc debt (7,314,512) - -
Proceeds on revolver 34,500,000 - -
Proceed from (payments on) notes payable (1,219,619) (177,777) -
Issuance of Series A preferred stock 21,100,000 - -
Proceeds from sale of common stock - 347 -
Debt issue costs (1,862,597) - -
--------------- -------------- --------------
Net cash used in financing activities 45,203,272 (177,430) -
-------------- -------------- --------------
NET INCREASE IN CASH AND CASH EQUIVALENTS (1,656,634) 547,407 1,706,437
CASH AND CASH EQUIVALENTS - BEGINNING OF PERIOD 3,728,332 3,180,925 1,474,488
-------------- -------------- --------------
CASH AND CASH EQUIVALENTS - END OF PERIOD $ 2,071,698 $ 3,728,332 $ 3,180,925
============== ============== ==============
SUPPLEMENTAL DISCLOSURES:
Cash paid for-
Interest $ 587,000 $ 274,058 $ 82,451
============== ============== ==============
Income taxes $ 941,468 $ 920,500 $ -
============== ============== ==============
</Table>
The accompanying notes are an integral part of these
consolidated financial statements.
This filing contains unaudited financial statements in lieu of
audited financial statement because the Company was unable to
obtain from Arthur Andersen LLP a manually signed report.
F-6
ASCENT ENERGY INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001 AND 2000
1. ORGANIZATION, RESTRUCTURING, MERGERS AND REORGANIZATION:
Ascent Energy Inc. ("Ascent," "we" or "us") is an independent energy company
engaged in the acquisition, exploitation, exploration, development and
production of natural gas and crude oil. Through our predecessor, we have been
active in South Louisiana since 1982. We were organized on January 9, 2001 by
the majority stockholders of our predecessor principally to facilitate the
acquisition of Pontotoc Production, Inc. ("Pontotoc").
Our business strategy is to increase production, cash flow and reserves through
the acquisition and development of mature properties. Currently, our property
base consists of 679 active properties, 30 in South Louisiana and 625 shallow
wells in Pontotoc County, Oklahoma, and 24 wells in South Texas. We serve as
operator on the majority of our active properties, which enables us to better
control the timing and cost of rejuvenation activities. We are headquartered in
McKinney, Texas, with additional offices in New Orleans, Louisiana, and Ada,
Oklahoma.
The consolidated financial statements include our accounts and the accounts of
our subsidiaries. The subsidiaries include Pontotoc Acquisition Corp., Pontotoc
Production Company, Inc., Oklahoma Basic Economy Corporation, Pontotoc Holdings,
Inc. and Pontotoc Gathering, L.L.C. All significant inter-company balances have
been eliminated. Certain prior year amounts have been reclassified to conform to
current year presentation.
Restructuring
In July, 2001, prior to the consummation of the acquisition of Pontotoc, our
predecessor was restructured as a holding company by contributing to us all of
its assets and liabilities. We refer to this transaction as the "Restructuring."
The Restructuring is accounted for using reorganization accounting for entities
under common control, which results in retroactive restatement of all periods
presented to reflect the Restructuring as if it had occurred at the beginning of
the earliest period presented. The accompanying consolidated financial
statements include the accounts of our predecessor and Ascent prior to the
Restructuring.
Pontotoc Acquisition
On July 31, 2001, we acquired approximately 91% of Pontotoc's outstanding common
stock. Subsequently, we acquired the remaining Pontotoc shares on August 14,
2001 in the second-step of the merger and merged Pontotoc into one of our
wholly-owned subsidiaries. The purchase price for all the outstanding Pontotoc
common stock was approximately $48.5 million in cash and 5,323,695 shares of our
Series B mandatorily convertible preferred stock. These shares were valued at
$0.49 per share based on the trading price of Pontotoc's common stock for the
five trading days prior to and following the date of the merger agreement.
We financed the cash portion of the purchase price for the Pontotoc acquisition
through:
o borrowing $30 million under our credit facility;
o a portion of the proceeds from the private sale for $21.1 million of
shares of our Series A redeemable preferred stock and warrants to
purchase approximately 4.1 million shares of our common stock; and
o existing internal cash resources.
The proceeds from the sale of our Series A redeemable preferred stock were
approximately $21.1 million. We are required to redeem our Series A redeemable
preferred stock at 100% of its liquidation preference, or $21.1 million (plus
any unpaid dividends), in July 2006.
Devo Merger
On September 28, 2001, we acquired Devo Holding Company, LLC ("Devo") in a
statutory merger under Delaware law. The assets of Devo and its subsidiary, Devo
Operating Company, LLC, consist primarily of South Texas oil and gas producing
properties. We issued $75.0 million in principal amount of our unsecured 11 3/4%
Senior Notes due April 30, 2006 (the "Senior Notes") in a private transaction in
connection with the Devo acquisition, at approximately a 1% discount.
Approximately $65.7 million of the Senior Notes were issued to Devo's note
holders in exchange for all of the principal and accrued interest outstanding
under Devo's Senior Notes due 2003.
F-7
Approximately $6.5 million of the Senior Notes were issued to Devo's equity
holders as consideration in the Devo acquisition. Jefferies & Company, Inc. (See
Note 12 -Related Party Transactions) received approximately $2.8 million of the
Senior Notes as a financial advisory fee in connection with the Devo acquisition
and for the placement of the Senior Notes. The Senior Notes are redeemable after
April 30, 2004 at 105%. Prior to that date, Ascent may redeem up to 35% of the
Senior Notes at 111%. The Senior Notes subject Ascent to certain covenants
which, among other things, limit Ascent's ability to pay dividends, incur
additional indebtedness and certain lease obligations, issue preferred stock
exchange or transfer assets.
These transactions were treated as purchases for accounting purposes. The
purchase prices were allocated to the assets and liabilities based on estimated
fair value. No value was assigned to the warrants. The allocations of the
purchase prices are preliminary and subject to change within one year of the
acquisition dates. Net assets acquired in the transactions were as follows:
<Table>
<Caption>
Transactions
(in thousands)
-------------------------
Pontotoc Devo
-------- --------
Oil and gas properties $ 91,195 $ 67,449
Working capital,
excluding cash 656 1,775
Debt (7,315) (73,698)
Deferred taxes (31,745) (1,360)
Preferred stock (2,609) --
-------- --------
Net cash paid (received) $ 50,182 $ (5,834)
======== ========
</Table>
The operating results of Pontotoc and Devo have been consolidated in the
Company's statement of operations since July 28, 2001 and September 28, 2001,
respectively. The following summarized unaudited pro forma income statement data
reflects the impact the transactions would have had on the Company's results of
operations for the twelve months ended December 30, 2001 had the transactions
occurred January 1, 2000. These unaudited pro forma results have been prepared
for comparative purposes only and do not purport to be indicative of the amounts
which actually would have resulted had the transaction occurred on January 1,
2000, or which may result in the future.
<Table>
<Caption>
Pro forma Twelve Months Ended December 31,
(in thousands)
------------------------------------------
2001 2000
---------- --------
Revenues $ 45,086 $ 35,374
========== ========
Net income (loss) attributable to
Common shareholders $ 479 $ (1,314)
========== ========
Earnings (loss) per common share:
Basic and diluted $ 0.10 $ (0.27)
========== ========
</Table>
Per common share amounts do not include the potentially dilutive effects of our
warrants and convertible preferred stock discussed below under "Per Share
Amounts."
Reorganization and Fresh Start Reporting
On August 6, 1999, Ascent's predecessor, Forman Petroleum Corporation
("Forman"), filed a voluntary petition for relief under Chapter 11 of the United
States Bankruptcy Code in the United States District Court for the Eastern
District of Louisiana (the Bankruptcy Court) (Case No. 99-14319). On November
22, 1999, Forman and certain of its creditors filed a Second Amended Joint Plan
of Reorganization, as amended on December 29, 1999 (the Bankruptcy Plan).
Forman's reorganization plan was confirmed by the Bankruptcy Court on December
29, 1999 and consummated January 14, 2000.
Pursuant to the Bankruptcy Plan, all of the Forman issued and outstanding
securities were canceled and, as of December 31, 2000, 984,042 shares of common
stock, no par value, and warrants to purchase up to 490,516 shares of common
stock were issued to the existing security holders.
F-8
As of the confirmation date, Forman had total assets of $33.9 million and
liabilities of $96.0 million. With the exception of an aggregate of
approximately $2.7 million of promissory notes issued pursuant to the Bankruptcy
Plan, approximately $300,000 in convenience claims which were paid in full in
2000, undistributed oil and gas revenues of $895,000, and approximately $3
million in additional pre-petition bankruptcy claims that were disputed by
Forman and have now been resolved before the Bankruptcy Court, all of the
liabilities and preferred stock as of the confirmation date were extinguished
pursuant to the Bankruptcy Plan.
As of September 30, 2000, Forman had resolved all pre-petition bankruptcy claims
that had previously been disputed. The Bankruptcy Court overruled an objection
to one creditor's proof of claim. In July, 2000, in accordance with the
Bankruptcy Plan, Forman issued the holder of that claim a promissory note in the
approximate amount of $984,000 the amortized value of which is included in Notes
Payable at December 31, 2001. In addition, on July 24, 2000, Forman
compromised its objection to a creditor's proof of claim by paying approximately
$501,000 in cash and agreeing to perform future work worth approximately
$122,000. Forman's objection to the Louisiana Department of Revenue and
Taxation's proof of claim in the amount of $223,000 was resolved in favor of
Forman. As a result, we are obligated to pay $119,000 to the Louisiana
Department of Revenue and Taxation over six years, with interest, in accordance
with the Bankruptcy Plan. Finally, in September and October, 2000, Forman
resolved all other disputed proofs of claims, in the aggregate amount of
$632,000, by paying approximately $416,000 in cash to the holders of those
claims. Accordingly, on November 2, 2000, Forman filed a motion for final decree
with the Bankruptcy Court to close our predecessor's bankruptcy case. At the
hearing on November 29, 2000, the final decree was granted by the Bankruptcy
Court.
Costs incurred during 1999 directly related to the reorganization, consisting
primarily of legal, accounting and financial consulting fees, were recorded to
reorganization costs in the accompanying statement of operations. These costs
are net of interest income earned on cash and cash equivalents because the
maintenance of cash balances during 1999 was directly related to our
predecessor's bankruptcy filing.
Forman ceased accruing interest on its Senior Debt and dividends on its
preferred stock on August 6, 1999, when it filed for relief under Chapter 11.
Forman accounted for the reorganization using the principles of fresh start
accounting required by AICPA Statement of Position 90-7, "Financial Reporting by
Entities in Reorganization Under the Bankruptcy Code" (SOP 90-7). For accounting
purposes, the accompanying financial statements reflect the confirmed plan as if
it was consummated on December 31, 1999. Under the principles of fresh start
accounting, total assets and liabilities at December 31, 1999 were recorded at
their estimated fair market values. Accordingly, Forman's net proved oil and gas
properties were increased by approximately $3.0 million, its unevaluated oil and
gas properties were increased by approximately $3.1 million and other net
property and equipment was increased by approximately $0.2 million. Obligations
arising from the Bankruptcy Plan were recorded at the amounts expected to be
paid in settlements of such obligations. In addition, Forman's Senior Notes with
a net book value of $68.6 million, related interest payable of $11.1 million,
preferred stock of $13.6 million and deferred financing costs related to the
Senior Notes and preferred stock of $4.4 million were all written off.
Since the holders of Forman's Senior Notes (the former noteholders) received
92.5% of the shares of the common stock, the gain on discharge of indebtedness
was computed using 92.5% of the net assets received by the former noteholders.
The remaining 7.5% of the net assets allocable to the former holders of Forman's
preferred stock was recorded to equity and is included in fresh start accounting
adjustments in the accompanying statement of stockholders' equity. Also included
in such amount is the write-off of the remaining deferred costs allocable to the
preferred stock.
As a result of the implementation of fresh start accounting, the financial
statements as of and for the year ended December 31, 1999 reflecting the fresh
start accounting principles discussed above are not comparable to the financial
statements of prior periods.
It is the intention of the Company to dissolve Forman. It is our belief that
none of the warrant securities of Forman have any current value.
F-9
2. SIGNIFICANT ACCOUNTING POLICIES:
A summary of significant accounting policies followed in the preparation of the
accompanying consolidated financial statements is set forth below:
Oil and Gas Properties
Ascent uses the full-cost method of accounting, which involves capitalizing all
exploration and development costs incurred for the purpose of finding oil and
gas reserves, including the costs of drilling and equipping productive wells,
dry hole costs, lease acquisition costs and delay rentals. The Company also
capitalizes certain related employee costs and general and administrative costs
which can be directly identified with significant acquisition, exploration and
development projects undertaken. Such costs are amortized on the future gross
revenue method whereby amortization is computed using the ratio of gross
revenues generated during the period to total estimated future gross revenues
from proved oil and gas reserves. Additionally, the capitalized costs of oil and
gas properties cannot exceed the present value of the estimated net cash flow
from its proved reserves, together with the lower of cost or estimated fair
value of its undeveloped properties (the full cost ceiling). Transactions
involving sales of reserves in place, unless extraordinarily large portions of
reserves are involved, are recorded as adjustments to accumulated depreciation,
depletion and amortization.
Ceiling Test Write-Down
The SEC requires companies to compare net capitalized costs of proved oil and
gas properties to the discounted present value of future cash flows from the
related proved reserves (the ceiling test). The calculation is made using posted
commodity prices as of the last day of the quarter held flat for the life of the
reserves. If capitalized costs exceed discounted cash flows, the assets are
required to be written down to the value of the discounted cash flows. The SEC
also allows companies to, alternatively, calculate the ceiling test using posted
prices in effect subsequent to the end of the quarter.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of
three months or less to be cash and cash equivalents. Substantially all of our
cash balances are in excess of federally insured limits.
Depreciation of Other Property and Equipment
Depreciation of property and equipment other than oil and gas properties is
provided on the straight-line method over the estimated useful lives of the
assets.
Deferred Financing Costs
The Company is amortizing deferred financing costs on the 11 3/4% Senior Notes
and on the Revolving Loan. Total unamortized cost at December 31, 2001 was
approximately $1 million. A total of approximately $81,000 was amortized
during 2001 and shown as interest expense.
Revenue Recognition
We recognize oil and gas revenue upon the sale to a third party purchaser and
follow the sales method for accounting for gas imbalances. Our gas imbalances as
of December 31, 2001 and 2000 were insignificant.
Interest income and other income are recorded as revenue in the month earned.
Fair Value of Financial Instruments
Cash, cash equivalents, accounts receivable, accounts payable and promissory
notes were reflected at their fair market values at December 31, 1999, in
accordance with SOP 90-7 as discussed in Note 1. As of December 31, 2001 and
2000, the fair market values of the financial instruments mentioned above
approximated their respective book values. Our gas swaps, oil and gas puts and
oil collars are reflected at fair market values in the accompanying financial
statements.
The Senior Notes which were issued at the end of the third quarter in
conjunction with the Devo Acquisition have a carrying value which we believe
approximates their market value at December 31, 2001.
The following methods and assumptions were used to estimate the fair value of
the financial instruments detailed above. The carrying amount of the revolving
credit agreement approximated fair value because the interest rate is variable
and reflective of market rates. The fair value of the oil and gas price hedges
are based upon quotes obtained from the counterparties to the hedge agreements.
F-10
Income Taxes
The Company follows the asset and liability method for accounting for deferred
income taxes and income taxes in accordance with SFAS No. 109, "Accounting for
Income Taxes." Provisions for income taxes include deferred taxes resulting
primarily from temporary differences due to different reporting methods for oil
and gas properties for financial reporting purposes and income tax purposes. For
financial reporting purposes, all exploratory and development expenditures
related to evaluated projects are capitalized and depreciated, depleted and
amortized on the future gross revenue method. For income tax purposes, only the
equipment and leasehold costs relative to successful wells are capitalized and
recovered through depreciation or depletion. Generally, most other exploratory
and development costs are charged to expense as incurred; however, we follow
certain provisions of the Internal Revenue Code that allow capitalization of
intangible drilling costs where management deems appropriate. Other financial
and income tax reporting differences occur as a result of statutory depletion,
and different reporting methods used in the capitalization of employee, general
and administrative and interest expenses.
Pervasiveness 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. Estimates are used primarily
when accounting for depreciation, depletion and amortization, unevaluated
property costs, estimated future net cash flows, taxes, reserves of accounts
receivable, capitalized general and administrative costs, fair value of
financial instruments, contingencies and the purchase price allocations on
properties acquired.
Derivatives
We enter into hedging transactions to secure a price for a portion of future
production that is acceptable to us at the time the transaction is entered into.
The primary objective of these activities is to reduce our exposure to the
possibility of declining oil and gas prices during the term of the hedge. We do
not enter into hedging transactions for trading purposes. We currently utilize
four forms of hedging contracts: fixed price swaps, puts, collars and physical
futures contracts.
Fixed price swaps typically provide monthly payments by us (if prices rise) or
to us (if prices fall) based on the difference between the strike price and the
agreed-upon average of either New York Mercantile Exchange ("NYMEX") or other
widely recognized index prices ("Index").
Put contracts are not costless; they are purchased at a rate per unit of hedged
production that fluctuates with the commodity futures market. The historical
cost of the put contracts represents our maximum cash exposure. We are not
obligated to make any further payments under the put contracts regardless of
future commodity price fluctuations. Under put contracts, monthly payments are
made to us if Index prices fall below the agreed upon floor price, while
allowing us to fully participate in commodity prices above that floor.
Collar contracts can often be costless; they are purchased at a rate per unit of
hedged production that fluctuates with the commodity futures market. If Index
prices fall below the floor level of a collar, a monthly payment is made to us;
if Index prices rise above the ceiling level of a collar, a monthly payment is
made by us.
Futures contracts are an obligation to deliver the physical commodity at a
designated location at the end of a contract period. We use this type of a
contract as a financial vehicle and do not intend to deliver physical
quantities. Margin accounts are often required. The upside and downside exposure
on this type of contract is great. If the commodity price drops the contracts
increase in value and if the commodity price increases the contracts decrease in
value and may become a liability.
We believe that fluctuations in Index prices will closely match changes in
market prices for our production. Oil contracts typically settle using the
average of the daily closing prices for a calendar month. Natural gas contracts
typically settle using the average closing prices of near month Index futures
contracts for the three days prior to the settlement date.
F-11
Our hedge positions as of December 31, 2001 are summarized as follows:
<Table>
<Caption>
PUTS
---------------------------------------------------------------
GAS OIL
---------------------------- ---------------------------
VOLUME VOLUME
(BBTUS) FLOOR (BBLS) FLOOR
-------- ----------- -------- -----
2002 0.420 3.50 - 4.00 - -
2003 - - 180,000 20.00
</Table>
<Table>
<Caption>
FIXED PRICE GAS SWAPS
-------------------------------------
Volume (Bbtus) Price
-------------- -----
2002 1.460 3.60
2003 0.972 3.60
</Table>
<Table>
<Caption>
OIL COLLARS
--------------------------------------------------
VOLUME (BBLS) FLOOR CEILING
------------- ------ -------
2002 18,600 $24.00 $26.90
2002 9,300 $25.00 $28.70
2002 200,400 $24.00 $26.90
2003 18,600 $24.00 $26.90
2003 15,500 $23.00 $24.85
</Table>
<Table>
<Caption>
PHYSICAL FUTURE CONTRACTS
---------------------------------------------------------------------
GAS OIL
--------------------------------- ---------------------------------
VOLUME (BBTUS) STRIKE PRICE (1) VOLUME (BBLS) STRIKE PRICE (1)
-------------- ---------------- ------------- ----------------
2002 1.050 $3.101 153,000 $24.70
2003 1.140 $3.543 - -
</Table>
- ---------------
(1) Average strike price for the period
F-12
During the year ended December 31, 2000, we realized no oil and gas revenues
related to hedging transactions. During the year ended December 31, 2001 and
during the fourth quarter of 2001, we realized oil and gas revenues related to
hedging settlements of $0.8 million.
At December 31, 2001, the unsettled contracts were recorded as assets totaling
$4.9 million. All changes in fair values of the puts and swaps were recorded in
equity through other comprehensive income, amounting to $1.1 million, net of
tax.
Subsequent to December 31, 2001, in early March 2002, the Company entered into a
series of natural gas hedges covering 9.8 BCF of natural gas for the period
April 2002 through December 2004. The derivatives are settled based upon the
Houston Ship Channel Index Price at the end of the preceding month. The new
hedging transactions are as follows:
<Table>
<Caption>
FIXED PRICE NATURAL GAS SWAPS
---------------------------------------
Volume (Bbtus) Price
-------------- ---------
2002 0.735 3.25
2003 1.095 3.25
2003 1.098 3.25
</Table>
<Table>
<Caption>
NATURAL GAS COLLARS
------------------------------------------------------
VOLUME (BBTUS) FLOOR CEILING
-------------- --------- ------------
2002 490.0 $2.50 $2.85
1,225.0 $2.50 $3.19
2003 730.0 $2.75 $3.53
1,825.0 $3.00 $3.39
2004 732.0 $3.00 $3.47
1,830.0 $3.00 $3.66
</Table>
Certain Concentrations
During 2001, 100% of the Company's oil and gas production was sold to 45
customers. Based on the current demand for oil and gas, the Company does not
believe the loss of any of these customers would have a significant financially
disruptive effect on its results of operations or financial condition.
Per Share Amounts
The number of shares of common stock outstanding for each period shown has been
restated to reflect the number of Ascent shares issued in the Restructuring
discussed in Note 1. Net income or loss per share of common stock was calculated
by dividing net loss applicable to common stock by the weighted-average number
of common shares outstanding during the year. Warrants to purchase 4,050,000
shares of common stock and an additional 1 million shares of common stock
issuable upon conversion of the Series B mandatorily convertible preferred stock
were not included in the computation of diluted earnings per share because the
effect of the assumed exercise of these stock warrants and conversion of these
preferred shares as of the beginning of the year would have been anti-dilutive.
The exercise price for the warrants is $5.21 per share. There has been limited
trading of the Series B on the Over The Counter exchange at values of less than
40% of the stated value of the Series B which we believe justifies no assumed
conversion.
Recent Accounting Pronouncements
In July 2001, SFAS No. 143 "Accounting for Asset Retirement Obligations" was
approved, requiring the fair value of liabilities for asset retirement
obligations to be recorded in the period incurred. The standard is effective for
fiscal years beginning after June 15, 2002, with earlier application permitted.
We expect to adopt SFAS No. 143 on January 1, 2003. Upon adoption of the
standard, we will be required to use a cumulative-effect approach to recognize
transition amounts for any existing asset retirement obligation liabilities,
asset retirement costs and accumulated depreciation. We have not yet determined
the transition amounts.
In July 2001, the Financial Accounting Standards Board (FASB) issued Statement
of Financial Accounting Standard (SFAS) No. 141, "Business Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 prohibits the
use of the pooling-of-interest method of accounting for all business
combinations initiated after June 30, 2001. SFAS No. 142 requires that goodwill
not be amortized in any circumstances and also requires goodwill to be tested
for impairment annually or when events or circumstances occur between annual
tests indicating that goodwill for a reporting unit might be impaired and is
effective for fiscal years beginning after December 15, 2001. The adoption of
SFAS Nos. 141 and 142 is not expected to have a material impact on our financial
statements, because we do not have any goodwill recorded.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Statement establishes accounting and
reporting standards that require every derivative instrument (including certain
derivative instruments embedded in other contracts) to be recorded in the
balance sheet as either an asset or a liability measured at its fair value and
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. The Company adopted SFAS No.
133 on January 1, 2001.
F-13
Escrow and Restricted Funds
Cash restricted for payment of abandonment costs for the Boutte and Bayou
Dularge Fields is classified as a long-term asset. Such amounts are invested in
short-term interest-bearing investments. As of December 31, 2001, the escrow
accounts are fully funded.
3. LONG TERM DEBT
As of December 31, 2001 our credit facility provides for borrowings secured by
substantially all our oil and gas properties of up to $50 million to finance our
future acquisition opportunities and to assist in meeting our working capital
requirements. Our current borrowing base is $45 million. The borrowing base is
redetermined semi-annually by applying similar criteria to those used with
similarly situated oil and gas borrowers. The credit facility provides for
interest rates of LIBOR plus 1.75% to 2.5% and Prime plus 0.5% to 1.0%. The
average interest rate on December 31, 2001 was 4.98%. The Credit Facility has a
maturity date of July 2004 if not extended further out in time. The availability
under the Credit Facility at March 29, 2002 is $4.2 million.
We have received from our bank an amendment to the credit agreement which
provides for both a modification to the EBITDA to debt test as well as a change
to the calculation of EBITDA. EBITDA is defined as earnings before interest,
tax, depletion and amortization. The test thresholds will be changed for the
three quarters of 2002 to now require the debt/EBITDA result to be no greater
than 5:1 from the previous 4.5:1 test level. In addition, our bank modified the
EBITDA calculation to now be based on a full trailing twelve-months on a pro
forma basis versus the previous test which started calculating EBITDA from July
1, 2001 and then annualizing that period. If the amendment had not been made we
would have been out of compliance with our credit agreement at December 31,
2001.
As discussed in Note 1, all of our predecessor's debt, including accrued
interest, and preferred stock were discharged in the reorganization resulting in
an extraordinary gain of $46.7 million, net of taxes.
The $75 million 11 3/4% Senior Notes mature in full on April 30, 2006. Interest
is paid semi-annually on each April 30th and October 31st. Up to 35% of the
Senior Notes may be redeemed prior to April 30, 2004 at a redemption price equal
to 111% of the principal amount and after April 30, 2004 at 105% of principal.
The weighted average interest rate of our outstanding debt at December 31, 2001
was 9.73%.
If the current debt facilities are not extended to a later maturity, the
aggregate minimum principal payments required as of December 31, 2001 would be
as follows: 2002 -0-, 2003 -0- , 2004 $34.5 million, 2005 -0-, and 2006 $75
million.
4. LEGAL PROCEEDINGS
From time to time, we may be a party to various legal proceedings. We currently
are a party to a lawsuit arising in the ordinary course of business. Management
does not expect this matter to have a material adverse effect on our financial
position or results of operations.
5. PREFERRED STOCK
In order to preserve cash on hand, our board of directors elected not to declare
the quarterly dividends for the third and fourth quarters of 2001 on 21,100
shares of our outstanding 8% Series A redeemable preferred stock with an
aggregate liquidation value of $21,100,000, and 5,323,695 shares of our
outstanding 8% Series B convertible
F-14
preferred stock with an aggregate liquidation value of $13,309,237. Unpaid
dividends on our preferred stock continue to accrue and accumulate despite
nonpayment, and the liquidation preference of our preferred stock increases by
the amount of any unpaid dividends. We are required to redeem our Series A
redeemable preferred stock for 100% of its liquidation preference, plus an
amount equal to all dividends (whether or not earned or declared) accrued and
unpaid on each share, in July 2006. In addition, we are required to pay any
accrued and unpaid dividends on our Series B convertible preferred stock in July
2003 when our Series B convertible preferred stock automatically converts into
shares of our common stock. We believe we will have adequate resources to make
such dividend payment at conversion if it is still outstanding. Both the Series
A redeemable preferred stock and the 8% Series B convertible preferred stock
accrue dividends on a quarterly basis at 8%. The total amount of the dividends
accrued on our Series A redeemable preferred stock as of December 31, 2001 is
approximately $0.7 million, and the total amount of the dividends accrued on our
Series B convertible preferred stock as of the same date is approximately $0.4
million.
6. NOTES PAYABLE
Forman, the Company's predecessor, had issued to certain general unsecured
creditors seven promissory notes aggregating approximately $3.7 million payable
beginning April 1, 2000, in equal quarterly installments of principal and
interest over three years and bearing interest at the rate of 8% per year. The
remaining principal payments of $1.3 million are classified as a short-term
obligation.
7. INCOME TAXES:
Under the applicable income tax rules and regulations, the Company was not
required to recognize taxable income, or pay taxes on the gain resulting from
discharge of indebtedness (DOI) as a result of the Bankruptcy Plan. Rather, the
gain (represented for tax purposes as the face value of the debt and accrued
interest discharged in excess of the fair market value of the reorganized
company) reduced the Company's net operating loss carryforwards (NOLs). Any
remaining gain (after offsetting the Company's NOLs) reduced the Company's tax
basis in its net assets. The magnitude of the DOI resulted in the elimination of
$20.9 million of NOLs from 1998 and $9.6 million of NOLs generated during 1999.
Additionally, it substantially eliminated the tax basis in the net assets of the
reorganized company. The significant excess of book basis over tax basis in the
net assets of the Company resulted in the recording of a $9.9 million deferred
tax liability in the reorganized balance sheet (See Note 1). Realization of the
NOLs used to offset the gain on DOI also resulted in the reversal of the
valuation allowance, the impact of which is included in the tax effect of the
extraordinary item of $10.1 million in the accompanying statement of operations.
The provision (benefit) for income taxes for the years ended December 31, 2000
and 2001 consisted of the following (in thousands):
<Table>
<Caption>
2001 2000 1999
------- ------ ------
Current $ 889 $ 667 $ --
Deferred (2,136) 515 (188)
------- ------ ------
Total provision (benefit) $(1,247) $1,182 $ (188)
======= ====== ======
</Table>
At December 31, the Company has the following deferred tax assets and
liabilities recorded (in thousands):
2001 2000
------- -------
Temporary differences:
Oil and gas properties $40,604 $10,788
(372)
Hedges 665
Unused depletion allowance and accrued espenses (1,025)
------- -------
Net deferred tax liability $40,244 $10,416
======= =======
</Table>
F-15
The provision for income taxes (on net loss before extraordinary item) at the
Company's effective tax rate differed from the provision for income taxes at the
federal statutory rate as follows (in thousands) at December 31, 2001:
<Table>
<Caption>
2001 2000
---- ----
Computed provision (benefit) at the expected
federal statutory rate............................. $(1,610) $ 985
State taxes............................................ (142) 197
Other.................................................. 505 -
------- ------
Income tax provision (benefit)......................... $(1,247) $1,182
======= ======
</Table>
F-16
8. COMMON STOCK AND WARRANTS
Common Stock
The Company has 20,000,000 shares of common stock authorized with 4,950,000
issued and outstanding. Both the Senior Notes and the Revolving Credit Facility
place limitations on the payment of dividends on the common stock.
Warrants
In conjunction with the issuance of the Series A preferred stock, warrants to
purchase 4,050,000 shares of common stock were issued to the holders of the
Series A preferred stock. The warrants may be exercised in whole or part at any
time until June 30, 2011. Each warrant entitles the holder to purchase 191.943
shares of common stock at an exercise price of $5.21 per share.
9. COMMITMENTS AND CONTINGENCIES
Operating Leases
Ascent has four non-cancelable operating leases for the rental of office space,
which expire on September 14, 2004, January 14, 2005, October 31, 2004 and
august 31, 2006. Future commitments under these leases are as follows:
<Table>
<Caption>
December 31, Amount
------------ ------
2002 $ 484,436
2003 $ 512,041
2004 $ 485,134
2005 $ 311,611
2006 $ 184,550
</Table>
Rental expense under operating leases during 2001, 2000 and 1999 was $334,967,
$210,480 and $240,980, respectively.
Jefferies & Company, Inc., a significant shareholder, has leased a portion of
the company's New Orleans office space at market rates for the balance of the
lease.
F-17
10. EMPLOYEE BENEFITS:
The Company has adopted a defined contribution retirement plan that complies
with Section 401(k) of the Code (the 401(k) Plan). Pursuant to the terms of the
401(k) Plan, all employees with at least three months of continuous service are
eligible to participate and may contribute up to 15% of their annual
compensation (subject to certain limitations imposed under the Code). The 401(k)
Plan provides that a discretionary match of employee contributions may be made
by the Company in cash. In December, 1999 the Company made a matching
contribution, in the amount of $70,012, based upon each individual employee's
plan contributions for 1999. During 2000 and 2001, the Company made matching
contributions on a monthly basis, in the aggregate amounts of $76,244 and
$75,638, respectively, based upon each individual employee's plan contributions
for the respective plan year. These matching employer contributions to the
401(k) Plan are fully vested to the individual employees after three years of
service. The amounts held under the 401(k) Plan are invested among various
investment funds maintained under the 401(k) Plan in accordance with the
directions of each participant. Employee contributions under the 401(k) Plan are
100% vested and participants are entitled to payment of vested benefits upon
termination of employment.
11. WRITEDOWN OF OIL AND GAS PROPERTIES:
At the third quarter 2001 review of the ceiling test, we utilized substantially
higher subsequent period prices from the September 30, 2001 levels to determine
any potential ceiling test write-down. Utilizing November 12, 2001 pricing
levels which left the oil price unchanged from September 30, 2001 and the
natural gas price increasing to $2.95 per MMBtu from $2.24 per MMBtu for that
same period, we calculated and recorded a non-cash ceiling test write-down of
$2.7 million (net of taxes of $1.6 million). If our discounted cash flows
valued using September 30, 2001 prices had been used in calculating the ceiling
test write-down, we would have recorded a write-down of $22.8 million (net of
taxes of $11.6 million).
At the December 31, 2001 review of the ceiling test, we utilized substantially
higher subsequent period prices from the December 31, 2001 levels to determine
any potential ceiling test write-down. Utilizing April 10, 2001 pricing levels
which showed oil prices increasing to $26.13 per barrel from $19.84 per barrel
at December 31, 2001 and the natural gas price increasing to $3.18 per MMBtu
from $2.65 per MMBtu for that same period, we calculated that no non-cash
ceiling test write down was necessary. If our discounted cash flows valued
using December 31, 2001 prices had been used in calculating the ceiling test
write-down, we would have recorded a write-down of $39.7 million (net of taxes
of $23.3 million).
12. RELATED PARTY TRANSACTIONS:
During September 2001, approximately $65.7 million of the Senior Notes were
issued in exchange for all the principal and accrued interest outstanding under
notes owed by Devo. As further consideration for the acquisition, approximately
$6.5 million of additional Senior Notes were issued to the shareholders of Devo
and approximately $2.8 million in Senior Notes were issued to Jefferies &
Company, Inc. (Jefferies) who together with the TCW Funds held substantially all
of of Devo's senior secured notes and equity and are the principal shareholders
of Ascent. The Devo properties had been acquired by certain of Devo's members
and their affiliates and contributed to Devo in exchange for Devo's senior
secured notes. The seller of the properties was paid approximately $64.5 million
for their interests. Devo paid debt issuance costs of $1.5 million to Jefferies
and $0.4 million to TCW in connection with the acquisition of the properties.
Also during 2001, Jefferies agreed to lease a portion of the Company's office
space in New Orleans at market prices through the remaining balance of the
Company's lease.
The Company leases office space at market rates on a month-to-month basis from a
company partially owned by a director, James "Robby" Robson, Jr.
In connection with the Pontotoc acquisition, Ascent Energy, our wholly-owned
subsidiary, has agreed to pay its president, Jeffrey Clarke, a success fee in
the amount of approximately $347,000 which was paid in Series A mandatorily
redeemable preferred stock.
13. OIL AND GAS ACTIVITIES:
The following tables provide information required by SFAS No. 69 "Disclosures
About Oil and Gas Producing Activities."
F-18
Capitalized Costs
Capitalized costs and accumulated depreciation, depletion and amortization
relating to the Company's oil and gas producing activities, all of which are
conducted within the continental United States, are summarized below:
<Table>
<Caption>
Year Ended December 31,
-------------------------------------------------
2001 2000 1999
-------------- -------------- --------------
Proved producing oil and gas properties $ 197,845,799 $ 28,481,661 $ 25,515,529
Unevaluated properties - 5,006,197 4,732,139
Accumulated depreciation, depletion
and amortization (16,272,089) (4,435,612) -
-------------- -------------- --------------
Net capitalized costs $ 181,573,710 $ 29,052,246 $ 30,247,668
============== ============== ==============
</Table>
Amounts previously carried in Unevaluated Properties were moved to Proved Oil
and Gas Properties and were subject to depletion in the fourth quarter of 2001.
These costs represent 3-D seismic expenditures on a portion of our Louisiana
acreage. The seismic data has generated many exploration prospects and has been
used in our development work. Limited proved reserves have been added as a
result of this data.
Costs Incurred
Costs incurred in oil and gas property acquisition, exploration and development
activities are summarized below:
<Table>
<Caption>
Year Ended December 31,
--------------------------------------------------
2001 2000 1999
-------------- -------------- ---------------
Acquisition costs $ 157,061,199 $ 574,008 $ 81,840
Exploration costs - 46,853 1,745,862
Development costs 7,693,813 1,502,880 3,345,943
Capitalized G&A costs 307,064 842,391 -
--------------- --------------- ---------------
Costs incurred $ 165,062,076 $ 2,966,132 $ 5,173,645
============== ============== ==============
D,D&A per Mcfe $ 1.37 $ 1.31 $ 1.09
</Table>
Gross cost incurred excludes sales of proved and unproved properties which are
accounted for as adjustments of capitalized costs with no gain or loss
recognized, unless such adjustments would significantly alter the relationship
between capitalized costs and proved reserves. For 2001 and 2000, G&A costs in
the amount of $307,064 and $842,391, respectively, were capitalized into the
full cost pool. No such capitalization of G&A was made for 1999. The amount of
interest capitalized on Unevaluated Properties during 2001, 2000 and 1999 were
$98,080, $274,058, and $-0-, respectively. This capitalized interest is in
acquisition cost.
Proved Oil and Gas Reserves - (Unaudited)
Proved reserves are estimated quantities of oil and natural gas which geological
and engineering data demonstrate, with reasonable certainty, to be recoverable
in future years from known reservoirs under existing economic and operating
conditions. Proved developed reserves are proved reserves that can reasonably be
expected to be recovered through existing wells with existing equipment and
operating methods. All estimates of oil and gas reserves are inherently
imprecise and subject to change as new technical information about the
properties is obtained.
Proved oil and natural gas reserve quantities and the related discounted future
net cash flows before income taxes for the periods presented are based on
estimates prepared by Netherland, Sewell & Associates for 1999, 2000 and 2001.
Netherland, Sewell & Associates are independent petroleum engineers. Such
estimates have been prepared in accordance with guidelines established by the
Securities and Exchange Commission.
As of April 1, 2001, Pontotoc had proved reserves of approximately 11.83 MMBoe,
approximately 73% of which were oil, based on estimates by our independent
petroleum engineers, Netherland, Sewell & Associates, Inc.
At August 1, 2001 Devo's estimated net proved reserves were 8.9 Mmboe, as
estimated by Netherland, Sewell.
F-19
The Company's net ownership interests in estimated quantities of proved oil and
natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below:
<Table>
<Caption>
Oil, Condensate and Natural Gas Liquids
(Bbls)
-----------------------------------------------------
Year Ended December 31,
-----------------------------------------------------
2001 2000 1999
--------------- --------------- ---------------
Proved developed and undeveloped reserves:
Beginning of year 2,667,191 1,612,124 1,530,724
Revisions of previous estimates (375,953) 169,698 273,709
Purchases of oil and gas properties 10,178,942 405,571 -
Extensions and discoveries 265,071 749,697 151,085
Production (442,172) (269,899) (343,394)
--------------- --------------- ---------------
End of year 12,293,079 2,667,191 1,612,124
=============== =============== ===============
Proved developed reserves at end of year 7,251,171 1,832,778 1,330,675
=============== =============== ===============
</Table>
<Table>
<Caption>
Natural Gas (Mcf)
-----------------------------------------------------
Year Ended December 31,
-----------------------------------------------------
2001 2000 1999
--------------- --------------- ---------------
Proved developed and undeveloped reserves:
Beginning of year 26,259,826 18,995,838 14,558,000
Revisions of previous estimates (5,652,973) 934,260 3,405,862
Purchases of oil and gas properties 65,885,915 1,256,479 -
Extensions and discoveries 1,959,909 6,870,554 4,123,150
Production (3,010,383) (1,797,305) (3,091,174)
--------------- --------------- ---------------
End of year 85,442,294 26,259,826 18,995,838
=============== =============== ===============
Proved developed reserves at end of year 50,513,574 12,804,123 13,599,050
=============== =============== ===============
</Table>
F-20
Standardized Measure (Unaudited)
The table of the Standardized Measure of Discounted Future Net Cash Flows
related to the Company's ownership interests in proved oil and gas reserves as
of period end is shown below:
<Table>
<Caption>
Year Ended December 31,
----------------------------------------------------
2001 2000 1999
------------- ------------- --------------
(In Thousands)
Future cash inflows $ 468,506 $ 331,656 $ 88,182
Future oil and natural gas operating expenses (147,177) (43,647) (29,045)
Future development costs (50,452) (17,666) (7,371)
------------ ------------ ------------
Future net cash flows before income taxes 270,877 270,343 51,766
Future income taxes (44,756) (100,313) (17,401)
------------ ------------ ------------
Future net cash flows (226,121) 170,030 34,365
10% annual discount for estimating timing of
cash flows (90,056) (56,585) (9,962)
------------ ------------ ------------
Standardized measure of discounted future net
cash flows $ 136,065 $ 113,445 $ 24,403
============ ============ ============
</Table>
Future cash flows are computed by applying year-end posted prices of oil and
natural gas to year-end quantities of proved oil and natural gas reserves.
Future operating expenses and development costs are computed primarily by the
Company's petroleum engineers by estimating the expenditures to be incurred in
developing and producing the Company's proved oil and natural gas reserves at
the end of the year, based on year end costs and assuming the continuation of
existing economic conditions. Future income taxes are computed using the
Company's tax basis in evaluated oil and gas properties and other related tax
carryforwards. The standardized measure of discounted future net cash flows does
not purport, nor should it be interpreted, to present the fair value of the
Company's oil and natural gas reserves. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs, a discount
factor more representative of the time value of money and the risks inherent in
reserve estimates. The weighted average prices of oil and gas used with the
above tables at December 31, 2001, 2000, and 1999 were $18.40, $25.48 and $24.58
respectively, per barrel and $2.84, $10.04 and $2.56 respectively, per Mcf.
F-21
Changes in Standardized Measure (Unaudited)
Changes in standardized measure of future net cash flows relating to proved oil
and gas reserves are summarized below:
<Table>
<Caption>
Year Ended December 31,
------------------------------------------
2001 2000 1999
----------- ----------- -----------
(In Thousands)
Changes due to current year operations:
Sales of oil and natural gas, net of oil and
natural gas operating expenses $(14,716) $ (11,048) $ (9,246)
Extensions and discoveries 5,118 72,785 8,604
Purchases of oil and gas properties 123,363 9,289 -
Changes due to revisions in standardized variables:
Prices and operating expenses (134,822) 80,438 10,747
Revisions of previous quantity estimates (10,575) 12,931 6,897
Estimated future development costs 5,098 (8,684) 3,055
Accretion of discount 18,231 3,608 1,917
Net change in income taxes 46,750 (57,191) (12,037)
Production rates, timing and other (15,827) (13,086) (4,703)
---------- --------- --------
Net Change 22,620 89,042 5,234
Beginning of year 113,445 24,403 19,169
---------- --------- --------
End of year $ 136,065 $ 113,445 $ 24,403
========== ========= ========
</Table>
F-22
14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED:
The following table summarizes the quarterly financial information for 2000 and
2001. For 2000, the Company capitalized $842,000 of G&A expenses and $274,000 of
interest incurred during 2000 into the full cost pool in the fourth quarter. For
presentation purposes, the expenses as reported in the respective quarterly Form
10-Qs for the first three quarters of 2000 have been restated below to reflect
this capitalization ratably over the four quarters of 2000.
<Table>
<Caption>
2000
--------------------------------------------------------------------------------
First Quarter Second Quarter Third Quarter Fourth Quarter Total
------------- -------------- ------------- -------------- -----------
Revenues $ 3,382,051 $3,241,941 $3,762,392 $4,574,105 $14,960,489
Expenses 2,504,620 2,687,521 3,265,193 2,705,700 11,163,034
----------- ---------- ---------- ---------- -----------
Net income (loss) from
operations 877,431 554,420 497,199 1,868,405 3,797,455
Reorganization items and income
taxes 1,196,317 -- 76,330 808,545 2,081,192
----------- ---------- ---------- ---------- -----------
Net income (loss) $ (318,886) $ 554,420 $ 420,869 $1,059,860 $ 1,716,263
=========== ========== ========== ========== ===========
Basic and diluted earnings
(loss) per share: $ (0.32) $ 0.56 $ 0.43 $ 1.07 $ 1.74
=========== ========== ========== ========== ===========
</Table>
<Table>
<Caption>
2001
-------------------------------------------------------------------------------------
First Quarter Second Quarter Third Quarter Fourth Quarter Total
------------- -------------- ------------- -------------- -----------
Revenues $ 5,095,645 $ 3,833,640 $ 4,799,698 $ 7,888,200 $ 21,617,183
Expenses 2,394,060 3,206,456 8,882,429 8,716,277 23,199,222
----------- ----------- ----------- ----------- ------------
Net income (loss) from
operations 2,701,585 627,184 (4,082,731) (828,077) (1,582,039)
------------
Interest, reorganization items
and income taxes 999,586 232059 (1,470,277) 2,144,447 1,905,815
----------- ----------- ----------- ----------- ------------
Net income (loss) 1,701,999 395,125 (2,612,454) (2,972,524) (3,487,854)
Preferred stock dividends (317,160) (850,602) 1,167,762
----------- ----------- ----------- ----------- ------------
Net income (loss) attributable
to common shares $ 1,701,999 $ 395,125 $(2,929,614) $(3,823,126) $ (4,655,616)
=========== =========== =========== =========== ============
Basic and diluted earnings
(loss) per share: $ 0.34 $ 0.08 $ (0.59) $ (0.77) $ (0.94)
=========== =========== =========== =========== ============
</Table>
F-23
EXHIBIT INDEX
<Table>
<Caption>
Exhibit No. Description of Exhibit
- ----------- -----------------------
10 Ascent Energy Inc. 2002 Stock Incentive Plan
21.1 Subsidiaries of the Company.
- ------------
</Table>