HAWKINS ENERGY CORP, 10KSB, 1997-03-31

HAWKINS ENERGY CORP
10KSB, 1997-03-31
EQUIPMENT RENTAL & LEASING, NEC

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<PAGE>

U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996.
or
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 [No fee required] for the transition period from
___________ to ___________.

Commission file number 0-18205
-------------

EQUITY COMPRESSION SERVICES CORPORATION
----------------------------------------------
(Name of Small Business Issuer in its charter)

Oklahoma 73-1345732
- ------------------------ ------------------
(State of Incorporation) (I.R.S. Employer)
Identification No.

Twenty East Fifth Street, Suite 1500, Tulsa, OK 74103
----------------------------------------------------------
(Address of principal executive offices) (Zip Code)

Issuer's telephone number, including area code 918-587-5815
------------------

Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Exchange Act:

Title of Class
----------------
Common Stock, par value $.01 per share

Check whether the issuer (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Exchange Act 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
----- -----

Check if there is no disclosure of delinquent filers in response to Item
405 of Regulation S-B contained in this form, and no disclosure will be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-KSB
or any amendment to this Form 10-KSB. [ ]

Issuer's revenue for the year ended December 31, 1996 -- $9,443,000

Aggregate Market Value of Voting Stock held by Non-affiliates
on March 22, 1997 -- $22,991,780

Number of Shares of Common Stock Outstanding
on March 22, 1997 -- 21,040,168

DOCUMENTS INCORPORATED BY REFERENCE

1. Portions of the Issuer's Proxy Statement with respect to Annual
Meeting of Stockholders to be held May 21, 1997 is incorporated by
reference in Part III of the Form 10-KSB

Transitional Small Business Issuer Disclosure Format (Check one):
Yes [ ] No [ X ]
<PAGE>

TABLE OF CONTENTS

PAGE
----

PART I

Items 1. & 2. Description of Business and Properties................... 3

Item 3. Legal Proceedings........................................ 13

Item 4. Submission of Matters to a Vote of Security Holders...... 13

Item 4A. Executive Officers of the Registrant..................... 14

PART II

Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters and Selected Financial Data........ 15

Item 6. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 15

Item 7. Financial Statements..................................... 18

Item 8. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure.................... 18

PART III

Item 9. Directors, Executive Officers, Promoters and Control
Persons of the Registrant; Compliance with
Section 16(a) of the Exchange Act...................... 18

Item 10. Executive Compensation................................... 19

Item 11. Security Ownership of Certain Beneficial Owners
and Management......................................... 19

Item 12. Certain Relationships and Related Transactions........... 19

Item 13. Exhibits and Reports on Form 8-K......................... 19

Index to Consolidated Financial Statements............... F-1

Signatures

2
<PAGE>

EQUITY COMPRESSION SERVICES CORPORATION
ANNUAL REPORT
FOR THE YEAR ENDED DECEMBER 31, 1996
PART I

ITEMS 1. AND 2. DESCRIPTION OF BUSINESS AND PROPERTIES

GENERAL
- -------

Equity Compression Services Corporation, formerly Hawkins Energy
Corporation (the "Company") is engaged in the leasing, remanufacturing and
direct sale of gas compression equipment to operators of producing natural gas
wells and gas gathering systems and in the production of natural gas and oil.
Its principal geographical operating areas lie within the states of Alabama,
Mississippi, Louisiana, Oklahoma, Arkansas, Kansas and Texas.

The Company was incorporated as Hawkins Energy Corporation in the state
of Oklahoma in June 1989 for the purpose of consolidating the businesses and
assets of Equity Compressors, Inc. ("Equity Compressors") and ten Hawkins
Exploration oil and gas limited partnerships. To effect the consolidation, the
Company extended an exchange offer to the stockholders of Equity Compressors and
the partners of the limited partnerships. Following approval by a majority in
interest of the limited partners in each of the ten limited partnerships, the
Company acquired the assets and assumed the liabilities of the partnerships and
acquired the stock of Equity Compressors, all in exchange for common stock of
the Company, and commenced operations on December 29, 1989.

The Company acquired Equity Compressors when its sole business was the
leasing of gas compression equipment to operators. Equity Compressors broadened
its scope of operations through its acquisition in April 1990 of a compressor
remanufacturing and service business. The business of the acquired company
centered around the acquisition, remanufacture and sale of existing gas
compressor units. By May 1990, this business was fully integrated into Equity
Compressors, and Equity Compressors relocated its headquarters from Tulsa to a
facility in Oklahoma City. This move positioned Equity Compressors
strategically in the heart of the Mid-Continent natural gas producing region.

In June 1993, the Company acquired Mid-South Compressors, Inc., a
privately held gas compression company ("Mid-South"). Mid-South leased
compression equipment throughout the gas producing regions of Mississippi,
Alabama and Northern Louisiana. The transaction involved the issuance of
approximately 5.4 million shares of Company common stock and the payment of $1.4
million in cash to Mid-South. The Company financed the cash portion of the
acquisition through additional borrowings.

In July 1993, the Company acquired all the outstanding shares of common
stock of Owens Compression Service, Inc. ("Owens"), a privately held company
that provided gas compression services primarily in East Texas and North
Louisiana in exchange for cash consideration of $42,000 and approximately 3.2
million shares of Company common stock.

During March 1995, the Board of Directors of Equity Compressors, Mid-
South and Owens each approved the formal merger of Mid-South and Owens with and
into Equity Compressors. The companies merged their operations under the Equity
Compressors name as of January 1, 1995. Currently, the businesses of Equity
Compressors include leasing, direct sales and remanufacturing services of
various types of gas compression equipment. At December 31, 1996, Equity
Compressors owned 411 gas compression units with a total of approximately 47,000
horsepower.

During December 1996, the shareholders of the Company approved an
increase in the number of authorized shares of common stock enabling the Company
to sell 8 million shares of common stock and 8 million contingent warrants for a
total cash consideration of $4.4 million to HACL, Ltd., a Dallas-based
investment group. Additionally, shareholders voted to change the name of the
Company to Equity Compression Services Corporation.

3
<PAGE>

The Company is also engaged in the production of natural gas and oil
through its ownership in 72 producing wells. At December 31, 1996, these
properties were estimated to have proved reserves of 4,989,186 thousand cubic
feet ("Mcf") of natural gas and 930,473 barrels of oil of which 4,717,275 Mcf
and 930,473 barrels of oil are proved developed. Natural gas reserves
constituted approximately 47% of the Company's proved developed reserve base on
a "gas equivalent" basis (converting each barrel of oil to 6 Mcf of natural gas,
representing the estimated relative energy content of oil and natural gas), and
crude oil makes up 53% of the total proved reserve base.

The primary business plan of the Company is growth within the
compression sector of the natural gas industry. The Company plans to expand its
activities in the compression service sector by expanding its existing
compressor fleet into larger horsepower equipment and utilizing the
relationships established among its expanded board of directors with large
independents and natural gas gathering and processing companies to gain entry to
that sector of the compression market. Service and sales growth will be pursued
along the same approach. Oil and gas property acquisitions will be pursued only
if they complement compression opportunities.

The Company had 87 employees at year-end 1996. Its principal executive
offices are maintained at Twenty East Fifth Street, Suite 1500, Tulsa, Oklahoma
74103.

GAS COMPRESSION OPERATIONS
- --------------------------

GENERAL. The Company conducts its compressor operations through Equity
Compressors, Inc., its wholly owned subsidiary. Equity Compressors, Inc.
currently operates facilities in Oklahoma City, Oklahoma, Columbia and Hamilton,
Mississippi and Kilgore, Texas.

Within the continental U.S. there are over 250,000 gas wells with
annual production in excess of 18 trillion cubic feet of natural gas. A very
large portion of these wells are located in the seven state area of the
Company's compression operations. The ages of these wells range from a few days
to decades. The age of a gas well usually affects its need for compression. A
gas well has a natural flowing pressure which may or may not be adequate to
overcome the pipeline pressure at the point where the gas is introduced into a
gathering system or transmission pipeline. If the flowing pressure of the gas
is not adequate to overcome the pipeline pressure, it is not physically possible
to produce or transport the gas. Gas compression is used to overcome this
problem by boosting the flowing pressure of the gas. Theoretically, all gas
wells will eventually need compression to boost natural well flowing pressure to
exceed pipeline pressure. Historically, gas compressors have generally been
purchased and operated by gas producers and gas transporters. However, over the
last several years, these same groups have also used equipment leasing as an
accepted means of providing for their gas compression needs.

EQUIPMENT LEASING. At year-end 1996, the Company's rental fleet
included 411 compressors located in Alabama, Arkansas, Kansas, Louisiana,
Mississippi, Oklahoma and Texas. These compressors generally average 113
horsepower in size and their cost as a new unit averages about $75,000. The
Company's rental fleet is comprised of used, remanufactured equipment which was
acquired at a substantial discount to the cost of comparable new compressor
units. The fleet includes engines and compressors of various manufacturers.
The size and configuration of each compressor vary depending on the particular
application for which it is utilized. Consideration is given to the
differential between the wellhead and pipeline flowing pressures and the volumes
of gas delivered from the wellhead.

4
<PAGE>

The following table sets forth certain data concerning the Company's
activity in the acquisition and leasing of compressors:

DECEMBER
1996 1995 1994 1993
------ ------ ------ ------
Number of units......................... 411 448 449 427
Average utilization rate
during period......................... 74% 66% 78% 82%
Equipment horsepower at end
of period............................. 46,531 48,980 49,208 45,814

At December 31, 1995, as a result of the highly competitive market for
compression rental equipment and the low utilization rates experienced on
certain of the Company's equipment, the Company identified certain compression
equipment (approximately 80 to 100 units) which it intended to dispose of. The
sale of these compressors occurred during the third quarter 1996. Proceeds of
this sale of equipment were used to acquire other compression equipment more
suited to the current marketplace.

LEASE TERMS. Generally, the Company's compressors are leased to well
operators under written lease agreements for periods of six or twelve months.
These leases are sometimes renewed at the end of the lease term at which time
the rentals and other terms may be renegotiated. Contract leasing rates are
generally set as a percentage of the new value of the equipment. The
competitive marketplace determines the percentage used in new contracts and in
renewals of existing contracts. Once the minimum term has expired, the
equipment is leased on a month-to-month basis, with the lessor or the lessee
having the right to terminate the contract by giving a thirty-day written
notice. The majority of the compressors under lease at December 31, 1996 were
on the month-to-month basis.

Under the typical lease terms, the lessee pays the costs of transporting
the compressor to the well site, installation and all fuel and other operating
costs. The compressors are operated on a daily basis by the employees of the
lessee. The Company maintains service departments which employ skilled
compressor mechanics who service and maintain compression equipment. Under the
most common type of lease, the lessee pays a flat fee for monthly compression
inclusive of service, equipment rental, lubricants and all parts and
maintenance.

REMANUFACTURING SERVICES. Remanufacturing services involve the overhaul
and rework of equipment owned by third parties. These services are performed
under contract with numerous customers, including gas gathering and transmission
companies, major oil companies, large independents and small producers to
overhaul and rework their gas compression equipment. Generally, the Company
prepares a description of the work to be conducted and the parts to be provided.
This description is accompanied by an estimate or a fixed bid of the costs to be
charged the customer for the overhaul work. In the event additional labor or
parts are required once the work is in process, the owner of the unit is
contacted regarding the work and additional charges are then agreed on.
Overhaul work is normally guaranteed for a period of ninety days.

COMPRESSOR SALES. The Company is also involved in the direct sales of
remanufactured gas compression equipment. The Company acquires, rebuilds and
sells previously owned gas compressor units to gas producers and transporters.
The Company maintains an inventory of compression parts and equipment at its
facilities in Oklahoma City, Oklahoma and Columbia, Mississippi. The Company is
able to sell its remanufactured equipment at a discount to the cost of
comparable new equipment, and in most cases is able to customize and complete a
compressor unit for a customer in substantially less time than the same customer
could acquire the equipment new from the original manufacturer. The Company
maintains a field service department which is responsible for the service and
maintenance of its direct sales units during their ninety-day warranty period.

MARKET FOR SERVICES. The Company's current market for compression
equipment is Western Kansas, Oklahoma, Arkansas, Alabama, Louisiana,
Mississippi, East Texas and the Texas Panhandle. Producing gas wells tend to
decline in flowing pressure over time; therefore, the significant number of gas
wells drilled during the late 1970's and early 1980's are now entering a phase
in their economic lives which typically calls for compression. The Company
relies upon established relationships and the development of new ones with
operators of producing wells and gas gathering systems to maintain or increase
its share of this potentially expanding market for gas compression services.

5
<PAGE>

The Company faces competition from a number of different companies, some of
which have larger staffs, more equipment and assets and greater financial
resources. The principal competition in the compressor leasing business comes
from major equipment fabricators who lease and sell gas compression equipment
and services.

COMPLIANCE WITH ENVIRONMENTAL LAWS
- ----------------------------------

The design and operation of gas compressors is subject to certain federal
and state environmental laws and regulations which, directly or indirectly,
relate to the discharge of materials into the environment. Complete compliance
with all of such laws and regulations may affect the Company's operations and
costs as a result of their effect on the design, condition and operation of its
gas compressors or its costs of repairing or remanufacturing them. Under most
of the leases for the gas compressors, responsibility for compliance with the
majority of these laws and regulations is placed on the lessee. However, there
can be no assurance that the Company would not be liable for any penalties or
fines that may be imposed as a result of any material noncompliance. It is not
anticipated that the Company will be required in the near future to expend
amounts that are material in the aggregate to the Company's overall operations
by reason of such laws and regulations.

NATURAL GAS AND OIL OPERATIONS
- ------------------------------

GENERAL. The Company acquired interests in natural gas and oil properties
by acquiring the assets and assuming the liabilities of ten oil and gas limited
partnerships on December 29, 1989 as a result of the exchange offer. The
Company continually reviews opportunities to acquire additional producing
properties, sells portions of its producing properties and conducts additional
development drilling on its properties. The Company is engaged in the
production and sale of natural gas, condensate and crude oil from these
properties.

The Company has effective control of operations on 44 of the wells in which
it owns an interest. Through the first quarter of 1996, the Company engaged an
affiliated company to handle the operations of the wells it controls. During
the second quarter of 1996, the Company directly assumed operations of some of
its key properties while engaging a contract operator to manage the remainder.

SIGNIFICANT PROPERTIES. At December 31, 1996, the Company owned oil and
gas interests in 72 producing wells, undrilled leasehold interests and related
assets located in Arkansas, Kansas, Oklahoma and Texas. Exploration and
development efforts have been concentrated in the Anadarko, Arkoma and Permian
Basins located in the states listed above. It is expected that the Company will
continue to focus on these areas in its future operations.

ANADARKO BASIN

In the Anadarko Basin, the interests owned by the Company consist of 38
gross (15.32 net) wells, of which 21 are controlled by the Company. The
properties in this basin contain proved reserves totalling 2,345,462 Mcf of gas
and 100,163 barrels of oil and represent approximately 20.08% of the present
value of the proved reserves of the Company at December 31, 1996.

ARKOMA BASIN

In the Arkoma Basin, the interests owned by the Company consist of 18 gross
(4.55 net) wells, seven of which are controlled by the Company. The properties
in this basin contain proved reserves totalling 2,597,773 Mcf of gas and
represent approximately 21.42% of the present value of the proved reserves of
the Company as of December 31, 1996.

PERMIAN BASIN

In the Permian Basin the interest owned by the Company consists of 16 gross
(15.88 net) wells, all of which are controlled by the Company. The properties
in this basin contain proved reserves totalling 45,951 Mcf of gas and 830,310
barrels of oil and represent approximately 58.50% of the present value of the
proved reserves of the Company at December 31, 1996.

6
<PAGE>

DRILLING ACTIVITIES. During the periods indicated, the Company
participated in the drilling of the following development wells:

<TABLE>
<CAPTION>
Years Ended December 31,

1996 1995 1994
Gross Net Gross Net Gross Net
----- ---- ----- --- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Development:
Productive 4.0 3.0 -- -- -- --
Non-Productive -- -- -- -- 1.0 .06
--- --- --- --- --- ---
Total 4.0 3.0 -- -- 1.0 .06
</TABLE>

PRODUCTIVE WELLS. The following table sets forth certain information
relating to oil and gas wells which are producing or which are shut in but
capable of producing oil and/or gas at December 31, 1996. A "gross" well is any
well in which the Company owned an interest while "net" wells equal the sum of
the Company's interests in the gross wells.

<TABLE>
<CAPTION>
PRODUCTIVE WELLS
AS OF DECEMBER 31, 1996

GROSS NET
----- ---
<S> <C> <C>
Oil 22 20.00
Gas 50 15.75
</TABLE>

ACREAGE. The following table sets forth the gross and net oil and gas
leasehold acreage of the Company as of December 31, 1996. "Gross" acreage
refers to any acreage in which the Company owns an interest while "net" acreage
refers to the Company's actual proportionate interest in the acreage.

<TABLE>
<CAPTION>
ACREAGE
AS OF DECEMBER 31, 1996
Developed
<S> <C>
Gross Acres 21,498
Net Acres 6,493
</TABLE>

PROVED RESERVES. The following table reflects the proved reserves of the
Company as estimated by Lee Keeling and Associates, Inc., independent petroleum
engineers, at the dates indicated. The increase in Mcf from 1995 to 1996 is
partly due to the drilling of two new gas wells which added proved reserves
totalling 965,032 Mcf.

7
<PAGE>
<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES
(IN THOUSANDS)
AS OF DECEMBER 31,

1996 1995 1994
------------ ------------- --------------
<S> <C> <C> <C> <C> <C>
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
---- ----- ---- ----- ---- -----

930 4,989 913 3,801 18 2,501
</TABLE>

The following table sets forth the estimated future net revenues from
proved reserves of the Company, before deducting the impact of federal and state
income taxes, based upon the report of Lee Keeling and Associates, Inc. and the
present value thereof. The present value of estimated future net revenues
discounted at 10% per annum was prepared using constant prices of approximately
$25.18 per barrel of oil and $3.10 per Mcf of gas, which were the average oil
and gas prices in effect at December 31, 1996. The 1996 net revenues disclosed
below reflect the expenditure of approximately $148,000 related to the Company's
proved undeveloped reserves. As of March 14, 1997, the Company's average prices
were approximately $21.28 per Bbl of oil and $1.95 per Mcf of gas. Based on
these prices the net present value would have totalled approximately
$10,600,000.
<TABLE>
<CAPTION>
ESTIMATED FUTURE NET REVENUES FROM PROVED RESERVES
<S> <C>
Estimated Future Net Revenues
Attributable to Production
During:
1997........................... $ 2,107,109
1998........................... 3,262,143
1999........................... 3,042,130
2000........................... 2,776,698
2001........................... 2,435,063
Remainder...................... 13,002,256
-----------

Total.......................... $26,625,399
===========
Net Present Value
(discounted at 10% per annum).. $16,297,582
===========
</TABLE>

The reserve data set forth herein represents estimates only. Reserve
engineering is a subjective process of estimating underground accumulations of
crude oil and natural gas that cannot be measured in an exact manner. The
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. As a result,
estimates of different engineers may vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revision of such estimate. Accordingly, reserve estimates often differ from the
quantities of crude oil and natural gas that are ultimately recovered. The
meaningfulness of such estimates is highly dependent upon the accuracy of the
assumptions upon which they were based.

MARKET FOR OIL AND GAS. The market for oil and gas production depends upon
a number of factors, including the availability of other domestic production,
crude oil imports, the proximity and size of oil and gas pipelines, the
marketing of competitive fuels and general fluctuations in the supply and demand
for oil and gas. For the past several years, there has existed a surplus of
imported oil and domestic natural gas. Such excess has resulted in reduced oil
and gas prices and curtailment of gas production. In addition, such
oversupplies may cause delays in marketing the natural gas from producing wells.

While certain of the Company's natural gas production is sold at the
wellhead to intrastate and interstate pipelines under contracts with terms
ranging from one to twenty years, most of its gas production is sold on the
"spot market" under commitments which generally extend for only thirty days.
All of the Company's long-term contracts contain provisions for readjustment of
price, termination and other terms

8
<PAGE>

customary in the industry. Certain of these contracts contain "market out" and
price adjustment provisions which could allow the purchaser to cancel the
contract or purchase the gas produced at a substantially lower price. Likewise,
if prices increase, the Company can cancel the contract or require the gas
produced to be purchased at the higher prices.

Approximately 53% of the Company's proved reserves are crude oil on an
equivalent unit basis, while the remaining 47% consist of natural gas.
Consequently, the financial results of the Company's gas and oil production
activities will be affected by positive or negative developments in the pricing
of and markets for both natural gas and crude oil. In previous years the
Company's proved reserve base consisted primarily of natural gas.

The Company does not believe that the loss of any of its oil purchasers if
replaced would have a material adverse effect on its operations. The loss of a
gas purchaser could result in contracts being executed for sales with prices
less than those previously in effect or in prolonged production delays. The loss
or termination of several gas purchase agreements or purchasers could, if not
replaced, adversely affect the Company's financial condition. The marketing of
oil and gas by the Company can be affected by a number of factors which are
beyond its control, the exact effects of which cannot be accurately predicted.

OIL AND GAS SALES PRICES AND PRODUCTION COSTS. The following table sets
forth the average sales prices per barrel of oil (including condensates and
other liquid hydrocarbons) and per Mcf of gas produced and the production
expense (including taxes and transportation charges) per equivalent Mcf of gas
production and Bbl of oil of the Company for each of the periods indicated.

<TABLE>
<CAPTION>
AVERAGE SALES PRICES AND PRODUCTION COSTS

YEAR ENDED DECEMBER 31,
----------------------------
1996 1995 1994
----------------------------
<S> <C> <C> <C>
Average Sales Price per Mcf of gas produced $ 2.36 $ 1.60 $ 1.91
Average Sales Price per barrel of oil produced $19.32 $17.47 $16.16
Production Costs per MCFE (1) $ .73 $ .80 $ .65
Production Cost per BOE (2) $ 4.35 $ 4.79 $ 3.91
</TABLE>

- ---------
(1) "MCFE" means equivalent Mcf of natural gas and is determined by converting
each barrel of oil to six Mcf of natural gas.
(2) "BOE" means equivalent barrels of oil and is determined by converting six
Mcf of natural gas to one barrel of oil.

REGULATIONS
- -----------

The oil and gas industry is extensively regulated by federal, state and
local authorities. Legislation affecting the oil and gas industry is under
constant review for amendment or expansion. Numerous departments and agencies,
both federal and state, have issued rules and regulations binding on the oil and
gas industry and its individual members some of which carry substantial
penalties for the failure to comply. The regulatory burden on the oil and gas
industry increases its cost of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently amended or
reinterpreted, the Company is unable to predict the future cost or impact of
complying with such regulations.

EXPLORATION AND PRODUCTION. Exploration and production operations of the
Company are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells, and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled and the
plugging and abandoning of wells. The Company's operations are also subject to
various conservation matters. These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which may
be drilled and the unitization or pooling of oil and gas properties. In this
regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely on voluntary pooling of lands and
leases. In addition, state conservation laws establish

9
<PAGE>

maximum rates of production from oil and gas wells, generally prohibit the
venting or flaring of gas and impose certain requirements regarding the
ratability of production. The effect of these regulations is to limit the
amounts of oil and gas the Company can produce from its wells, and to limit the
number of wells or the locations at which the Company can drill.

Oklahoma and Texas have adopted limits on gas production that attempt to
match production with market demand. In March 1992, Oklahoma enacted a law
which places statewide limits on gas production. The Oklahoma Corporation
Commission sets production levels quarterly. The production of natural gas from
a single well is limited to the greater of a specified Mcf per day or a
percentage of the total daily production capacity of the well. In April 1992,
the Texas Railroad Commission ("TRC") unanimously approved a new proration
system that eliminated monthly purchaser nominations as the starting point for
determining reservoir market demand. Instead, the TRC makes an initial
determination of reservoir market demand for prorated fields each month using
production in the same month from the previous year and the operator's forecast
for demand for that month. This initial determination is subject to certain
adjustments. Individual well allowable determinations are determined by an
enhanced capability determination routine. A well capacity is determined as the
lesser of the latest TRC well deliverability test on file or the highest monthly
production during the last six months. Alternatively, an operator may submit a
substitute capability determination that has been determined by a registered
professional engineer.

The Company cannot predict whether other states will adopt similar
legislation or rules governing gas production. The effect of the Oklahoma and
Texas provisions and any other restrictions, if adopted, could be to decrease
allowable production on certain properties and the revenues from gas properties.
It is also possible that such legislation and regulations may result in a
decrease in natural gas production, which might also have the effect of exerting
upward pressure on prices of natural gas, although there can be no assurance
that any such increase will occur. However, if such restrictions do result in
increased prices of natural gas, they could face challenges in the courts and
there can be no assurance as to the outcome of any such challenge, or federal
legislation may be enacted to override the effects of state provisions.

Various federal, state and local laws and regulations covering the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, may affect the Company's operations and costs as
a result of their effect on exploration, development and production operations.
Violation of environmental legislation and regulations may result in the
imposition of fines or civil or criminal penalties and, in certain
circumstances, the entry of an order for the removal, remediation and abatement
of the conditions, and the suspension of the activities, giving rise to the
violation. The Company is also subject to laws and regulations concerning
occupational safety and health. It is not anticipated that the Company will be
required in the near future to expend amounts that are material in the aggregate
to the Company's overall operations by reason of environmental or occupational
safety and health laws and regulations, but inasmuch as such laws and
regulations are frequently changed, the Company is unable to predict the
ultimate cost of compliance.

Certain of the Company's oil and gas leases are granted by the federal
government and administered by various federal agencies. Such leases require
compliance with detailed federal regulations and orders which regulate, among
other matters, drilling and operations on these leases and calculation of
royalty payments to the federal government. The Mineral Lands Leasing Act of
1920 places limitations on the number of acres under federal leases that may be
owned in any one state. While subject to this law, the Company does not have a
substantial federal lease acreage position in any state or in the aggregate.
The Mineral Lands Leasing Act of 1920 and related regulations also may restrict
a corporation from the holding of a federal onshore oil and gas lease if stock
of such corporation is owned by citizens of foreign countries which are not
deemed reciprocal under such Act. Reciprocity depends, in large part, on
whether the laws of the foreign jurisdiction discriminate against a United
States person's ownership of rights to minerals in such jurisdiction. The
purchase of shares in the Company by citizens of foreign countries who are not
deemed to be reciprocal under such Act could have an impact on the Company's
ownership of federal leases.

MARKETING, GATHERING AND TRANSPORTATION. Federal legislation and
regulatory controls have historically affected the price of the gas produced by
the Company and the manner in which such production is marketed. Historically,
the transportation and sale for resale of gas in interstate commerce have been
regulated pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural
Gas Policy Act of 1978 (the "NGPA") and Federal Energy Regulatory Commission
("FERC") regulations promulgated thereunder. Since

10
<PAGE>

1978, maximum selling prices of certain categories of gas, whether sold in
interstate or intrastate commerce, have been regulated pursuant to the NGPA.
The NGPA established various categories of gas and provided for graduated
deregulation of price controls of several categories of gas and the deregulation
of sales of certain categories of gas. All price deregulation contemplated
under the NGPA has already taken place.

On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the
"Decontrol Act") was enacted. The Decontrol Act amended the NGPA to remove, as
of July 27, 1989, both price and non-price controls from gas not subject to a
contract in effect on July 26, 1989. Gas under contract on July 26, 1989, was
decontrolled on the earlier of the termination of the contract or January 1,
1993. Gas from wells spudded after July 26, 1989, was decontrolled on May 15,
1991, even if those wells were still covered by an existing contract.

In December 1992, the FERC issued Order No. 547, which is a blanket
certificate of public convenience and necessity pursuant to Section 7 of the NGA
and which authorizes any company which is not an interstate natural gas pipeline
or an affiliate thereof to make sales for resale at negotiated rates in
interstate commerce of any category of gas that is subject to the FERC's NGA
jurisdiction. The blanket certificates were effective January 7, 1993, and do
not require any further application. There are certain requirements which must
be met before an affiliated marketer of an interstate pipeline can avail itself
of this certificate.

The cumulative impact on the Company of the deregulation provisions of the
NGPA, the Decontrol Act and Order No 547 is that the Company's gas production is
no longer subject to price regulation. Rather, it is subject only to that price
contractually agreed upon between the producer and purchaser. Under current
market conditions, deregulated gas prices under new contracts tend to be lower
than most regulated price ceilings previously prescribed by the NGPA.

In February 1988, the FERC issued Order No. 490, which promulgated new
abandonment regulations for expired, canceled or modified contracts involving
the sale of certain gas committed or dedicated to interstate commerce prior to
the enactment of the NGPA. The new rules largely eliminate delays and
regulatory burdens associated with securing approval to abandon gas service upon
termination or expiration of a contract for the sale of such gas. The new rules
also significantly facilitate certain pipelines' ability to discontinue
purchasing such gas under terms unfavorable to the pipeline in situations in
which the contract has expired or terminated, but abandonment authorization is
required to terminate the service. The Company has gas purchase agreements with
purchasers that have been abandoned pursuant to Order No. 490. Order No. 490 is
currently being challenged in the courts. The Company is unable to predict the
outcome of these proceedings, and is also unable to predict the consequences to
it of any possible future vacation of Order No. 490.

Commencing in late 1985, the FERC issued a series of orders (Order No. 436,
Order No. 500 and related orders), which promulgated regulations designed to
create a more competitive, less regulated market for natural gas. These and
subsequent regulations have significantly altered the marketing and pricing of
gas. Among other things, these regulations (a) require interstate pipelines that
elect to transport gas for others under self-implementing authority to provide
transportation services to all shippers on a non-discriminatory basis, and (b)
permit each existing firm sales customer of any such pipeline to modify over at
least a five-year period, its existing purchase obligations. Although the new
regulations do not directly regulate gas producers such as the Company, the
availability of non-discriminatory transportation services and the ability of
pipeline customers to modify their existing purchase obligations under these
regulations has greatly enhanced the ability of producers to market their gas
directly to end users and local distribution companies. In this regard, access
to markets through interstate pipelines is critical to the Company's marketing
initiatives.

In April 1992, (and clarified in August 1992 and finalized in November
1992), the FERC issued Order 636, a complex regulation which has had a major
impact on natural gas pipeline operations, services and rates. Among other
things, Order 636 requires each interstate pipeline company to "unbundle" its
traditional wholesale services and create and make available on an open and
nondiscriminatory basis numerous constituent services (such as gathering
services, storage services, firm and interruptible transportation services, and
stand-by sales services) and to adopt a new rate making methodology to determine
appropriate rates for those services. To the extent the pipeline company or its
sales affiliate makes gas sales as a merchant in the future, it will do so in
direct competition with all other sellers pursuant to private contracts;
however, pipeline companies are not required to remain "merchants" of gas, and
many of the interstate

11
<PAGE>

pipeline companies have or will become transporters only. Each pipeline company
had to develop the specific terms of service in individual proceedings. The new
rules are subject to pending court challenges by numerous parties. In addition,
many of the individual pipeline restructurings are the subject of pending
appeals, either before the FERC or in the courts.

As noted, Order 636 is still in the judicial review stage. On October 29,
1996, the United States Court of Appeals for the District of Columbia Circuit
denied petitions for rehearing of its earlier decision, United Distribution
-------------------
Companies v. FERC, 88 F.3d 1105, 1191 (D.C. Cir. 1996), in which the D.C.
- -----------------
Circuit upheld most of Order 636. However, the Court remanded to the FERC for
further explanation the provisions pertaining to (1) restriction of entitlement
to receive no-service to those customers who received bundled firm-sales service
on May 18, 1992; (2) the twenty year term-matching cap for the right-of-first
refusal mechanism; (3) two aspects of the straight fixed variable rate design
mitigation measures; and (4) why, in light of Order 500 and the general cost
spreading principles of Order 636, pipelines can pass through all their gas
supply realignment ("GSR") transition costs to customers and why interruptible
transportation customers should bear 10% of GSR costs.

The issuance of Order 636, and its future interpretation, as well as the
future interpretation and application by FERC of all of the above rules and its
broad authority, or of the state and local regulations by the relevant agencies,
could affect the terms and availability of transportation services for
transportation of natural gas to customers and the prices at which gas can be
sold. For instance, as a result of Order 636 a number of interstate pipeline
companies have (i) "spun-down" their gathering systems from regulated pipeline
transportation companies to unregulated affiliates, (ii) spun-off gathering
systems to non-related entities, and/or (iii) "refunctionalized" portions of
their pipeline facilities from transmission to gathering. In a May 27, 1994
order and a December 2, 1994 rehearing order, FERC ruled that it generally does
not have jurisdiction over gathering facilities absent abuse involving the
pipeline-affiliate relationship. However, FERC directed pipelines spinning down
or off their gathering systems to include certain Order No. 497 standards of
conduct in their tariffs and to enter into continuity of service agreements with
existing users or to execute a "default contract" with users with whom they
cannot reach agreement, with the default contract to contain a minimum two-year
term, use the pipeline gatherer's then current rate (with an appropriate
escalator clause) for existing customers for similar service, and contain terms
and conditions consistent with those applicable to the pipeline's gathering
service. However, in 1996 the United States Court of Appeals for the District
of Columbia upheld the FERC's allowing the spinning down of gathering facilities
to a non-regulated affiliate, but remanded the FERC's default contract
mechanism. On October 31, 1996, four producers, Amoco Energy Trading Corp.
(together with its parent, Amoco Production Co.), Anadarko Production Corp.,
Conoco Inc. and Marathon Oil Co., petitioned the Supreme Court of the United
States to review the D.C. Circuit's upholding the FERC's determination not to
regulate the gathering systems spun down to affiliates except in circumstances
of affiliate abuse. Consequently, the Company cannot reliably predict at this
time how regulation will ultimately impact the Company's natural gas operations.

With respect to oil pipeline rates subject to the FERC's jurisdiction, in
October 1993 the FERC issued Order No. 561 in order to fulfill the requirements
of Title XVIII of the Energy Policy Act of 1992. Order No. 561 establishes an
indexing system, effective January 1, 1995, under which oil pipelines will be
able to readily change their rates to track changes in the Producer Price Index
for Finished Goods (PPI-FG), minus one percent. This index established ceiling
levels for rates. Order No. 561 also permits cost-of-service proceedings to
establish just and reasonable rates for initial rates for new service. Cost-of-
service review may be invoked when an oil pipeline company claims it is
significantly under-recovering its costs, or when customers claim the pipeline's
rates are excessive in relation to actual costs. The order does not alter the
right of a pipeline to seek FERC authorization to charge market-bases rates.
However, until the FERC makes the finding that the pipeline does not exercise
significant market power, the pipeline's rates cannot exceed the applicable
index ceiling level or a level justified by the pipeline's cost of service.

EMPLOYEES
- ---------

At December 31, 1996, Equity Compression Services had 79 full time
employees and 8 part time employees. The Company has 78 employees in its gas
compression operations, one employee in its oil and gas operations and 8
employees in its general corporate area. None of these employees are
represented by a union or labor organization. The Company considers its
relations with these employees to be satisfactory.

12
<PAGE>

ITEM 3. LEGAL PROCEEDINGS

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On December 19, 1996, the Company held a special meeting of its
stockholders to consider and vote on proposals to (i) amend the Company's
Certificate of Incorporation to increase the number of authorized shares of the
Company's Common Stock from 20,000,000 shares to 40,000,000 shares, and (ii)
amend the Company's Certificate of Incorporation to change the name of the
Company to "Equity Compression Services Corporation". Both proposals were
approved by the Company's stockholders at the special meeting. Set forth below
is certain information with respect to the voting on the proposals.

Proposal to increase the number of shares of authorized Common Stock:

FOR AGAINST ABSTAIN
Number of Shares 7,836,048 81,147 4,845

Proposal to change the name of the Company:

FOR AGAINST ABSTAIN
Number of Shares 7,831,044 84,793 6,203

13
<PAGE>

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

Set forth below is certain information with respect to each executive
officer of the Company. Executive officers are elected by the Board of Directors
of the Company and serve at its discretion.

NAME AGE POSITION
---- --- --------

Richard D. Brannon 38 Chairman of the Board

Matthew S. Ramsey 42 Chief Executive Officer/
President

Jack D. Brannon 40 Senior Vice President/
Chief Financial Officer

Frank W. Gagliardi 39 Vice President

The following is a brief description of the business background of each of
the executive officers of the Company.

Mr. Brannon has served as Chairman of the Board since December 19, 1996.
Mr. Brannon is President of Brannon Oil & Gas, Inc., an independent energy
investment company. Mr. Brannon is an investor in oil and gas production,
natural gas pipelines, real estate and equity investments. Mr. Brannon served
as director of Cornerstone Natural Gas, Inc., a natural gas pipeline and
processing company, until its sale to El Paso Natural Gas company in 1996. Mr.
Brannon also previously served as an Advisory Board member to First Interstate
Bank, Fort Worth. Mr. Brannon has a B.S. degree in Petroleum Engineering from
the University of Texas and is a Certified Professional Engineer.

Mr. Ramsey has served as Chief Executive Officer since December 19, 1996.
Mr. Ramsey served as Vice President of Nuevo Energy Company, an independent
energy company, from 1990 to 1996. From 1990 to 1996, he was employed by Torch
Energy Advisors Incorporated, a company providing management and operations
services to energy companies including Nuevo Energy Company, last serving as a
director and Executive Vice President. Mr. Ramsey joined Torch Energy as Vice
President of Land and was named Senior Vice President of Land in 1992. Prior to
joining Torch Energy, Mr. Ramsey was self-employed for eleven years. Mr. Ramsey
holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D.
from South Texas College of Law. Mr. Ramsey is a graduate of Harvard Business
School's Advanced Management Program. He is licensed to practice law in the
State of Texas.

Mr. Jack Brannon has served as Senior Vice President and Chief Financial
Officer since January 1, 1997. Previously, he was employed by BOK Capital
Services Corporation as Senior Vice President (1994 -1996) and its affiliate,
Bank of Oklahoma, N.C., as Vice President, Energy Group (1984 - 1996). He holds
three degrees from the University of Texas, Austin: a B.S. with honors in
Zoology (1978), an M.A. in Population Biology (1980) and an M.B.A. (1984).

Mr. Gagliardi has served as Vice President since January 1996 and has been
with the Company since 1989 serving as Senior Exploration Geologist. He was
employed by Hawkins Oil & Gas, Inc. as Senior Exploration Geologist (1981 to
1989). Previously, he was employed with Boomer Drilling Company, Nowata,
Oklahoma, as an Exploration-Development Geologist (1980 to 1981) and with
Exploration Logging, Inc., Houston, Texas as a Wellsite Geologist (1979 to
1980). He holds a B.S. Degree in Geology (1979) from Edinboro University,
Edinboro, Pennsylvania and a M.S. Degree in Environmental Engineering from
Oklahoma State University (1995). Mr. Gagliardi is a Certified Petroleum
Geologist.

14
<PAGE>

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS AND
SELECTED FINANCIAL DATA

As of March 1, 1997, the Company had approximately 1,400 holders of record
of its Common Stock. The Company's stock is quoted on the NASDAQ Small Cap
Market under the symbol "EQCS". The table below reflects the high and low bid
prices per share of the Company`s common stock for each calendar quarter during
1996 and 1995 as quoted by NASDAQ. The bid quotations reflect inter-dealer
prices without adjustment for retail markups, markdowns or commissions and may
not reflect actual transactions.

<TABLE>
<CAPTION>
1996 1995
--------------- ---------------
<S> <C> <C> <C> <C>
QUARTER HIGH LOW HIGH LOW
------- ----- ----- ----- -----

First 9/16 13/32 5/8 3/8

Second 13/16 13/32 9/16 7/16

Third 13/16 9/16 11/16 15/32

Fourth 1 7/8 19/32 5/8 15/32
</TABLE>

The Company has not paid any cash dividends on shares of its Common Stock
since its organization and currently intends to continue its policy of retaining
earnings, if any, for the Company's operations. The Company is prohibited by
certain loan agreement provisions from paying dividends.

SELECTED FINANCIAL DATA

Certain selected financial data is presented for each of the five years
ended December 31.
<TABLE>
<CAPTION>

1996 1995 1994 1993 1992
-------- --------- -------- ------- -------
(In thousands of dollars except per share amounts)
<S> <C> <C> <C> <C> <C>
Total revenues $ 9,443 $ 9,943 $13,676 $ 8,978 $4,274
Net income (loss) (160) (1,438)(1) 1,049(2) 288 20
Income (loss) per
common share (.01) (.11) .08 .03 .01
Total assets 25,810 26,041 27,914 26,357 7,541
Long-term debt:
Current portion 177 682 2,263 570 1,925
Long-term portion 5,362 9,000 6,967 5,666 --
Obligation under capital
lease -- -- -- 3,220 --
</TABLE>

(1) Includes a provision to reduce the carrying value of certain compression
equipment of $1,790,000.
(2) Includes gain on sale of oil and gas properties of $1,880,000.

ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

During December 1996, the Company sold 8 million shares of common stock and
8 million contingent warrants for a total cash consideration of $4.4 million to
HACL, Ltd., a Dallas based investment group. The Company's board was expanded
to include five members of the HACL group. Matthew S. Ramsey, a member of the
HACL group, joined the Company in December as Chief Executive Officer. Jack D.
Brannon joined the Company on January 1, 1997 as Chief Financial Officer. The
Company utilized the proceeds from the HACL stock purchase to reduce its bank
borrowings. At year-end, the Company had available borrowing capacity under its
existing bank credit facility of approximately $3.8 million.

15
<PAGE>

The Company reported a net loss of $160,000 in 1996 due principally to a
loss on sale from the third quarter auction of idle compression equipment and
the severance costs associated with the resignation of certain senior management
following the HACL, Ltd. transaction in December. During 1996, the company sold
by auction a group of compressors and other equipment which had been idle in the
fleet in excess of 12 months which resulted in a loss on sale of $372,000.
Additionally, certain of these compressors had been identified and written down
in the prior year. Certain management of the Company elected to resign their
respective positions following the HACL, Ltd. transaction in December. The cash
costs associated with their collective severance packages totaled $237,500.

In 1997, the Company is focused on expansion of its compressor leasing
operation through more efficient utilization of its existing compressor fleet as
well as from fleet additions through both individual unit acquisitions for
identified leasing opportunities and the acquisition of other rental fleets and
rental companies.

FINANCIAL CONDITION AND LIQUIDITY
- ---------------------------------

In March 1997, the Company received and accepted a formal bank commitment
to refinance its existing bank credit facility to increase the amounts available
for new investment and working capital. The debt is structured as a two year
revolving line of credit with a $20 million maximum commitment (previous
commitment was $12 million) and has an initial borrowing base of $12.5 million.
Under the terms of the credit agreement, the outstanding balance at the
revolving period's maturity will be converted to a term note payable over 60
months. The credit agreement contains a variety of covenants and a material
adverse change clause. The covenants require the Company to maintain certain
ratios, prohibit the payment of cash dividends and establish maximum annual
capital expenditures. The debt is collateralized by substantially all the
assets of the company. At March 14, 1997, the Company had utilized $7.3 million
of its credit line.

Net cash provided by operating activities increased to $3.1 million in 1996
from $1 million primarily due to decreased levels of accounts and notes
receivable. Net cash used in investing activities increased to $3.4 million in
1996 from $1.5 million in 1995, due to increased acquisitions of compressor
equipment in 1996. Net cash provided by financing activities was $116,000 in
1996 and decreased from $498,000 in 1995, as proceeds from stock issuance were
used to pay down debt. At December 31, 1996 the Company had current assets of
approximately $2.8 million and current liabilities of $2 million. The Company
anticipates that 1997 cash flow from operations, as well as the credit line will
be sufficient to fund the Company's working capital and capital expenditure
needs.

RESULTS OF OPERATIONS
- ---------------------

1996 VERSUS 1995

In 1996, compressor rental revenue decreased $357,000 from 1995 primarily
as a result of the Company's decision to remove approximately 50 compressor
units from it rental fleet at the end of 1995. The overall compressor
utilization rate increased in December 1996 to 74% from 66% in December 1995,
generally, as a result of the sale of approximately 50 of the Company's idle
compression units at auction during the third quarter of 1996. Revenues from
compressor sales and remanufacturing services decreased $434,000 or 27% in 1996
from 1995. Gross profit of $284,000 in 1996 decreased from $518,000 during 1995.
The profit margins on compressor sales and remanufacturing decreased to 24% in
1996 from 32% in 1995.

Due to the Company's effort to minimize operating costs, compressor
operating costs incurred on rental units decreased 26%. Compressor operating
costs were 41% and 52% of related revenues for the years ended December 31, 1996
and 1995, respectively. This percentage decrease is related to lower operating
costs on newly leased compressors.

Revenues from the sale of oil and gas increased by $291,000 or 19% in 1996
from 1995, reflecting the increase in the average sales price per Mcf of gas of
48% from $1.60 per Mcf in 1995 to $2.36 in 1996 and the increase in the average
sales price per Bbl of oil of 11% from $17.47 in 1995 to $19.32 in 1996. Oil
and gas operating costs for 1996 were 17% lower than for 1995, primarily due to
lower overhead costs on outside operated wells.

16
<PAGE>

At December 31, 1996, the Company had oil price swaps related to its
production and sale of oil which provided the Company a minimum price of $18.00
per Bbl and a maximum price of $22.90 per Bbl for 2,000 Bbls per month for the
months of October 1996 through September of 1997. The swaps are accounted for
as hedges of the Company's oil sales.

Depletion, depreciation and amortization of the composite cost of evaluated
oil and gas properties is computed on the units-of-production method based on
estimated proved reserves. The 1996 expense related to oil and gas properties
is 21% lower than 1995, due to lower production volumes and an upward revision
of reserves estimates. Depreciation of the compressor fleet decreased 4% in
1996 from 1995 primarily as a result of the decrease in the Company's compressor
fleet.

At December 31, 1995, associated with the highly competitive marketplace
for compression rental equipment and the low utilization rates experienced on
certain of the Company's equipment, the Company identified certain equipment
which it intended to dispose of. Accordingly, the book value of the equipment
was reduced to its estimated fair value of approximately $800,000, resulting in
a provision to reduce the carrying value of the equipment of $1,790,000. These
and certain other equipment were disposed of in 1996, generating proceeds of
approximately $724,000 and resulting in an additional loss of $437,000. For the
year ended December 31, 1995, these compressors generated revenues of
approximately $338,000 and depreciation expense of $246,000. The Company used
the proceeds of this sale of equipment to acquire other compression equipment
more suited to the current marketplace.

General and administrative expense increased $230,000 or 12%, generally due
to termination benefits accrued at year-end associated with certain changes in
management of the Company.

Interest expense decreased by $116,000 in 1996 compared to 1995 as a result
of lower debt balances in 1996.

1995 VERSUS 1994

In 1995, compressor rental revenue decreased $904,000 from 1994. The
overall compressor utilization rate decreased in December 1995 to 66% from 78%
in December 1994, generally, as a result of lagging demand resulting from the
deterioration in gas prices and increased competition from larger rental
companies. Revenues from compressor sales and remanufacturing services
decreased $598,000 or 27% in 1995 from 1994, also as a result of these market
conditions. However, the gross profit of $518,000 in 1995 was about the same as
the $522,000 realized during 1994. The profit margins on compressor sales and
remanufacturing increased to 32% in 1995 from 24% in 1994.

Compressor operating costs incurred on rental units decreased 3% primarily
due to the fewer number of actively leased units and the centralization of
compressor operations in Columbia, Mississippi. Compressor operating costs were
52% and 48% of related revenues for the years ended December 31, 1995 and 1994,
respectively. This percentage increase is generally related to the lower rental
rates on newly leased compressors.

Revenues from the sale of oil and gas decreased by $320,000 or 17% in 1995
from 1994, reflecting the sale of properties at year-end 1994 and a decrease in
the average sales price per Mcf of gas of 16% from $1.91 per Mcf in 1994 to
$1.60 in 1995. The decline in oil and gas revenue was offset somewhat by
$65,040 received by the Company from a financial hedge which provided a price
floor of $2.00 per Mcf on approximately 50% of the Company's production since
May 1994. This price hedge expired in April 1995. Oil and gas operating costs
for 1995 were 2% lower than for 1994, primarily due to lower production due to
the 1994 property sale, partially offset by initial one-time costs incurred on
acquisitions of new properties during early 1995.

Depletion, depreciation and amortization of the composite cost of evaluated
oil and gas properties is computed on the units-of-production method based on
estimated proved reserves. The 1995 expense related to oil and gas properties
is 31% less than 1994, due to lower production and the effect of property
acquisitions in 1995. Depreciation of the compressor fleet increased 1% in 1995
from 1994 due to acquisitions of equipment.

17
<PAGE>

General and administrative expense decreased $740,000 or 29% due to
reductions in corporate expenses related to the Company's ongoing efforts to
control such costs, as well as certain administrative efficiencies resulting
from the merger of the Company's three wholly owned gas compressor subsidiaries.

Interest expense increased by $201,000 in 1995 compared to 1994 as a result
of additional bank borrowings.

NEW ACCOUNTING PRONOUNCEMENTS
- -----------------------------

In February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128, Earnings Per Share ("FAS 128"). FAS
------------------
128 will change the computation, presentation and disclosure requirements for
earnings per share. FAS 128 requires the presentation of "basic" and "diluted"
earnings per share, as defined, on the face of the income statement for all
entities with complex capital structures. FAS 128 is effective for financial
statements issued for periods ending after December 15, 1997, and requires
restatement of all prior period earnings per share amounts. The Company has not
yet determined the impact that FAS 128 will have on its earnings per share when
adopted.

EFFECTS OF INFLATION
- --------------------

In recent years inflation has not had a significant impact on the Company's
operations or financial condition. The impact of inflation on the Company in
the future will depend on the relative increases, if any, the Company may
realize from its compressor sales and rental rates and the selling price of its
oil and gas.

ITEM 7. FINANCIAL STATEMENTS

The Company's Consolidated Financial Statements required by this Item begin
at page F-1 following page 21 hereof.

ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS OF THE
REGISTRANT; COMPLIANCE WITH SECTION 16(A) OF THE EXCHANGE ACT

Information required by this item with respect to the Company's Directors
and compliance with Section 16(a) of the Securities Exchange Act of 1934 is
incorporated by reference to the Section entitled "Election of Directors" and
"Section 16(a) Beneficial Ownership Reporting Compliance", respectively, of the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1997 annual meeting. The
information required by this item with respect to the Company's executive
officers appears at Item 4A of Part I of this Form 10-KSB.

18
<PAGE>

ITEM 10. EXECUTIVE COMPENSATION

Information required by this item is incorporated by reference to the
Section entitled "Compensation of Directors and Executive Officers" of the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1997 annual meeting.

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Information required by this item is incorporated by reference to the
Section entitled "Voting Securities and Principal Holders Thereof" of the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1997 annual meeting.

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Information required by this item is incorporated by reference to the
Section entitled "Certain Relationships and Related Transactions" of the
Company's Proxy Statement to be filed with the Securities and Exchange
Commission in connection with the Company's 1997 annual meeting.

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits:

3.1 Certificate of Incorporation. Previously filed as Exhibit 3.1 to
the Company's Registration Statement on Form S-8 (S.E.C. File No.
333-23925), which Exhibit is incorporated herein by reference
thereto.
3.2 Amendment to Certificate of Incorporation. Previously filed as
Exhibit 3.2 to the Company's Registration Statement on Form S-8
(S.E.C. File No. 333-23925), which Exhibit is incorporated herein
by reference thereto.
3.3 By-Laws. Previously filed as Exhibit 3.5 to the Company's
Registration Statement on Form S-4 (S.E.C. File No. 33-30686),
which Exhibit is incorporated herein by reference thereto.
10.1 Equity Compressors Leasing 1990 Limited Partnership dated July 31,
1990 between Equity Compressors, Inc. and Limited Partners.
Previously filed as Exhibit 10.4 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1991, which Exhibit is
incorporated herein by reference thereto.
10.2 Employment Agreement dated as of June 11, 1993, between Don E.
Smith and Mid-South Compressors, Inc. Previously filed as Exhibit
10.5 to the Company's Annual Report on Form 10-KSB for the year
ended December 31, 1993, which Exhibit is incorporated herein by
reference thereto. (2)
10.3 Amended and Restated Employee Stock Option Plan. Previously filed
as Exhibit 4.8 to the Company's Registration Statement on Form S-8
(S.E.C. File No. 333-23925), which Exhibit is incorporated herein
by reference thereto. (2)
10.4 Hawkins Energy Corporation 1994 Directors Stock Option Plan.
Previously filed as Exhibit 10.8 to the Company's Annual Report on
Form 10-KSB for the year ended December 31, 1994, which Exhibit is
incorporated herein by reference thereto. (2)
10.5 Hawkins Energy Corporation 401(k) Plans. Previously filed as
Exhibit 4(c) to the Company's Registration Statement on Form S-8
(S.E.C. File No. 33-74640), which Exhibit is incorporated herein
by reference thereto. (2)
10.6 Hawkins Energy Corporation Revolving Credit and Term Loan
Agreement dated September 1, 1995. Previously filed as Exhibit
10.10 to the Company's Annual Report on Form 10-KSB for the year
ended December 31, 1995, which Exhibit is incorporated herein by
reference thereto.
10.7 Hawkins Energy Corporation Director Stock Plan. Previously filed
as Exhibit 4.6 to the Company's Registration Statement on Form S-8
(S.E.C. File No. 333-23925), which Exhibit is incorporated herein
by reference thereto. (2)
21.1 Subsidiaries of the Registrant. (1)
23.1 Consent of Independent Accountants. (1)
23.2 Consent of Independent Petroleum Engineers. (1)
27 Financial Data Schedule. (1)
____________________
(1) Filed herewith.
(2) Management contract or agreement.

(b) Reports on Form 8-K
-------------------

No reports on Form 8-K were filed for the three months ended December 31, 1996.

19
<PAGE>

SIGNATURES

Pursuant to the requirements of Sections 13 of 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

EQUITY COMPRESSION SERVICES CORPORATION

DATE: March 25, 1997 By: /s/ Matthew S. Ramsey
----------------------------------------------
Matthew S. Ramsey,
Chief Executive Officer, President

By: /s/ Jack D. Brannon
----------------------------------------------
Jack D. Brannon,
Senior Vice President,
Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.

DATE: March 25, 1997

/s/ Richard D. Brannon Chairman of the Board and Director
- ----------------------------------
RICHARD D. BRANNON

/s/ Matthew S. Ramsey Chief Executive Officer, President
- ---------------------------------- and Director
MATTHEW S. RAMSEY

/s/ Thomas F. Ostrye Director
- ----------------------------------
THOMAS F. OSTRYE

/s/ Clifford S. Lewis Director
- ----------------------------------
CLIFFORD S. LEWIS

/s/ Charles M. Butler, III Director
- ----------------------------------
CHARLES M. BUTLER, III

/s/ Ray C. Davis Director
- ----------------------------------
RAY C. DAVIS

/s/ Don E. Smith Director
- ----------------------------------
DON E. SMITH

/s/ Kelcy L. Warren Director
- ----------------------------------
KELCY L. WARREN

/s/ Jon P. Stephenson Director
- ----------------------------------
JON P. STEPHENSON

20
<PAGE>

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----

Report of independent accountants........................... F-2

Consolidated balance sheets................................. F-3

Consolidated statements of operations....................... F-4

Consolidated statements of changes in stockholders' equity.. F-5

Consolidated statements of cash flows....................... F-6

Notes to consolidated financial statements.................. F-8

F-1
<PAGE>

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholders
Equity Compression Services Corporation

We have audited the consolidated balance sheets of Equity Compression
Services Corporation ("the Company") at December 31, 1996 and 1995 and the
related consolidated statements of operations, changes in stockholders' equity
and cash flows for each of the three years in the period ended December 31,
1996. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
the Company as of December 31, 1996 and 1995 and the consolidated results of
their operations and their cash flows for each of the three years in the period
ended December 31, 1996 in conformity with generally accepted accounting
principles.

As explained in Note 1 to the Consolidated Financial Statements, in 1995
the Company changed its method of accounting for long-lived assets.

COOPERS & LYBRAND L.L.P.

Tulsa, Oklahoma
March 25, 1997

F-2
<PAGE>

EQUITY COMPRESSION SERVICES CORPORATION
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------
1996 1995
------- -------
(In thousands)
<S> <C> <C>
Current Assets:
Cash and cash equivalents....................... $ 10 $ 177
Accounts receivable, less allowance for
doubtful accounts of $76 and $25 in 1996
and 1995, respectively......................... 1,220 1,377
Accounts receivable -- related party............ 25 25
Notes receivable................................ 6 262
Income tax receivable........................... -- 58
Compressors and compressor parts inventory...... 1,476 1,458
Other........................................... 46 121
------- -------
Total current assets........................... 2,783 3,478
------- -------

Property and Equipment, net (Note 4)............. 22,280 21,399
------- -------

Goodwill and other intangibles, net of
amortization of $1,742 in 1996 and $1,690
in 1995......................................... 742 794
Notes receivable................................. -- 315
Other assets, net................................ 5 55
------- -------
Total Assets..................................... $25,810 $26,041
======= =======

Current Liabilities:
Current portion of long-term debt............... $ 177 $ 682
Accounts payable and accrued liabilities........ 1,806 1,778
Accounts payable - affiliate.................... -- 88
Income tax payable.............................. 13 --
------- -------
Total current liabilities...................... 1,996 2,548

Long-term debt................................... 5,362 9,000
Deferred income taxes............................ 3,566 3,697
Other............................................ 89 98
------- -------
Total Liabilities................................ 11,013 15,343
------- -------

Commitments (Note 9)

Stockholders' Equity:
Preferred stock, $1.00 par value, 1,000,000
shares authorized, none issued................. -- --
Common stock, $.01 par value, 40,000,000
shares authorized, 21,049,235 and 13,049,235
shares issued and 21,040,168 and 12,961,968
outstanding in 1996 and 1995, respectively..... 210 130
Additional paid-in capital...................... 17,692 12,114
Retained earnings (deficit)..................... (1,656) (1,448)
Treasury stock, at cost (9,067 and 87,267
shares in 1996 and 1995, respectively)......... (9) (98)
Deferred expense - contingent warrants.......... $(1,440) --
------- -------
Total stockholders' equity....................... 14,797 10,698
------- -------
Total Liabilities and Stockholders' Equity....... $25,810 $26,041
======= =======
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements.

F-3
<PAGE>

EQUITY COMPRESSION SERVICES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
(In thousands, except for
per share amounts)
Revenues:
Oil and gas sales.......................... $ 1,821 $ 1,530 $ 1,850
Compressor sales and remanufacturing...... 1,177 1,611 2,209
Compressor rentals and service fees....... 6,445 6,802 7,706
Gain on sale of oil and gas properties
(Note 4)................................ -- -- 1,880
Gain on sale of assets.................... -- -- 31
------- ------- -------
Total revenues.......................... 9,443 9,943 13,676
------- ------- -------

Operating Expenses:
Operating costs-oil and gas............... 516 621 636
Cost of compressor sales and
remanufacturing.......................... 894 1,093 1,687
Operating costs-compressors............... 2,643 3,558 3,687
Depreciation, depletion and amortization.. 2,096 2,253 2,368
Provision to reduce the carrying value
of compressor equipment (Note 3)........ -- 1,790 --
Loss on sale of assets.................... 437 23 --
General and administrative................ 2,080 1,850 2,590
Amortization of intangibles............... 105 73 106
Other..................................... -- 31 91
------- ------- -------
Total expenses.......................... 8,771 11,292 11,165
------- ------- -------

Income (loss) from operations............... 672 (1,349) 2,511
------- ------- -------
Other income (expense):
Interest and other income................. 26 102 79
Interest expense.......................... (927) (1,043) (842)
------- ------- -------
(901) (941) (763)
------- ------- -------

Income (loss) before income taxes............ (229) (2,290) 1,748

Income tax benefit (expense)................. 69 852 (699)
------- ------- -------

Net income (loss)............................ $ (160) $(1,438) $ 1,049
======= ======= =======

Income (loss) per common share.............. $ (.01) $ (.11) $.08
======= ======= =======

Weighted average number of
shares outstanding......................... 13,687 12,931 12,826
======= ======= =======
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements.

F-4
<PAGE>

EQUITY COMPRESSION SERVICES CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY

Years Ended December 31, 1996, 1995 and 1994
(In thousands)
<TABLE>
<CAPTION>
DEFERRED
ADDITIONAL RETAINED EXPENSE--
COMMON PAID IN EARNINGS TREASURY CONTINGENT
STOCK CAPITAL (DEFICIT) STOCK WARRANTS TOTAL
----- ------- --------- -------- ---------- -------
<S> <C> <C> <C> <C> <C> <C>
Balances, December 31, 1993 $130 $12,105 $ (997) $(260) $ -- $10,978

Sale of treasury stock -- 9 -- 54 -- 63
(63,994 shares)

Net Income -- -- 1,049 -- -- 1,049
---- ------- ------- ----- ------- -------

Balances, December 31, 1994 $130 $12,114 $ 52 $(206) $ -- $12,090
---- ------- ------- ----- ------- -------

Sale of treasury stock
(99,400 shares) -- -- (62) 108 -- 46

Net Loss -- -- (1,438) -- -- (1,438)
---- ------- ------- ----- ------- -------

Balances, December 31, 1995 $130 $12,114 $(1,448) $ (98) $ -- $10,698
---- ------- ------- ----- ------- -------

Sale of stock
(8,000,000 shares) 80 4,138 -- -- -- 4,218

Issuance of contingent warrants -- 1,440 -- -- (1,440) --

Sale of treasury stock
(78,200 shares) -- -- (48) 89 -- 41

Net loss -- -- (160) -- -- (160)
---- ------- ------- ----- ------- -------

Balances, December 31, 1996 $210 $17,692 $(1,656) $ (9) $(1,440) $14,797
==== ======= ======= ===== ======= =======
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements.

F-5
<PAGE>

EQUITY COMPRESSION SERVICES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1996 1995 1994
-------- -------- --------
(In thousands)
<S> <C> <C> <C>
Cash flows from operating activities
Net income (loss)............................ $ (160) $(1,438) $ 1,049
Adjustments to reconcile net income
(loss) to net cash provided by
operating activities:
Depletion, depreciation, and
amortization........................... 2,201 2,326 2,474
Provision to reduce the carrying
value of compressor equipment.......... -- 1,790 --
Deferred taxes............................ (131) (958) 567
(Gain) loss on sale of assets............. 437 23 (1,911)
Changes in operating assets and liabilities:
Accounts receivable...................... 106 (564) 618
Allowance for doubtful accounts.......... 51 52 69
Note receivable.......................... 571 98 216
Compressors and parts inventory.......... (18) (234) 97
Accounts payable and accrued
liabilities............................. (47) 25 13
Other.................................... 124 (72) 149
------- ------- -------
Net cash provided by operating
activities............................. 3,134 1,048 3,341
------- ------- -------

Cash flows from investing activities:
Additions to oil and gas
properties................................. (732) (2,534) (222)
Proceeds from disposition of oil
and gas properties......................... 174 -- 2,499
Acquisitions of compressor and other
equipment.................................. (3,580) (1,753) (3,092)
Proceeds from sale of compressor
and other equipment....................... 724 291 170
Cash held for reinvestment in
oil and gas properties..................... -- 2,513 (2,513)
Increase in goodwill and
other assets............................... (3) (1) (23)
------- ------- -------
Net cash used in investing activities.. (3,417) (1,484) (3,181)
------- ------- -------
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements.

F-6
<PAGE>

EQUITY COMPRESSION SERVICES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1996 1995 1994
-------- -------- --------
(In thousands)
<S> <C> <C> <C>
Cash flows from financing activities:
Sale of treasury stock....................... $ 41 $ 46 $ 63
Purchase of common stock subject
to repurchase.............................. -- -- (23)
Payments of capital lease obligations........ -- -- (3,099)
Proceeds of long-term debt................... 6,752 1,804 6,797
Payments on long-term debt................... (10,895) (1,352) (3,803)
Proceeds of stock issuance................... 4,218 -- --
-------- ------- -------
Net cash provided by (used in)
financing activities.................. 116 498 (65)
-------- ------- -------

Net increase (decrease) in cash
and cash equivalents......................... (167) 62 95

Cash and cash equivalents,
beginning of year............................ 177 115 20
-------- ------- -------

Cash and cash equivalents,
end of year.................................. $ 10 $ 177 $ 115
======== ======= =======

Supplemental disclosure of cash
flow information:
Interest paid................................ $ 947 $ 952 $ 759
======== ======= =======
Income taxes paid............................ $ 48 $ 170 $ 376
======== ======= =======
</TABLE>
The accompanying notes are an integral part of the
consolidated financial statements.

F-7
<PAGE>

EQUITY COMPRESSION SERVICES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Equity Compression Services Corporation (the "Company") formerly Hawkins
Energy Corporation is engaged in the leasing, remanufacturing and direct sale of
gas compression equipment to operators of producing natural gas wells and gas
gathering systems and in the production of natural gas and oil. Its principal
geographical operating areas lie within the states of Alabama, Mississippi,
Louisiana, Oklahoma, Arkansas, Kansas and Texas.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company
and its wholly owned subsidiaries. All inter-company transactions have been
eliminated.

Cash Equivalents

The Company includes in cash equivalents all investments with original
maturities of three months or less at the date of purchase, which are readily
convertible into known amounts of cash.

Compressors and Compressor Parts Inventory

Compressors and compressor parts are carried at the lower of cost or
market, using specific identification of costs and weighted average costs,
respectively. At December 31, compressor and compressor parts inventory
consisted of:
<TABLE>
<CAPTION>

1996 1995
------ ------
(In thousands)
<S> <C> <C>
Compressor Work in Progress $ 335 $ 326
Cylinders 99 281
Parts and Supplies 1,042 851
------ -----

$1,476 $ 1,458
====== =====
</TABLE>

Oil and Gas Operations

The Company accounts for its oil and gas exploration and development
activities on the full cost method of accounting prescribed by the Securities
and Exchange Commission ("SEC"). Accordingly, all productive and non-productive
costs incurred in connection with the acquisition, exploration and development
of oil and gas reserves are capitalized and amortized using the units-of-
production method based on proved oil and gas reserves. The Company's oil and
gas reserves are estimated annually by independent petroleum engineers. The
depreciation, depletion and amortization rates were $.37, $.43 and $.48 per
equivalent Mcf produced in 1996, 1995 and 1994, respectively. In the event the
unamortized cost of oil and gas properties being amortized exceeds the full cost
ceiling as defined by the SEC, the excess is charged to expense in the period
during which such excess occurs. Changes in reserve estimates or a decline in
oil and natural gas prices could cause the Company in the near-term to reduce
the carrying value of its oil and natural gas properties. (See Note 11)

Sales and abandonments of properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized unless a significant amount of
reserves is involved (see Note 4). Since all of the Company's oil and gas
properties are located in the United States, a single cost center is used.

F-8
<PAGE>

Property and Equipment

Compressor equipment held by the Company for rental purposes is stated at
cost and depreciated on a straight-line basis over an estimated 12 or 15-year
useful life. Buildings and other equipment are stated at cost and depreciated
over their estimated useful lives of 30 years and 5 years, respectively.

Repairs and maintenance are charged to expense as incurred and major
renewals and betterments are capitalized. Upon sale or retirement of equipment,
the cost of the equipment disposed of and the related accumulated depreciation
are removed from the accounts and the resulting gain or loss is reflected in
operations.

In the fourth quarter of 1995, the Company adopted Financial Accounting
Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and Long
Lived Assets to be Disposed Of." This standard requires that long-lived assets
be evaluated for impairment whenever events or changes and circumstances
indicate that the carrying value of an asset may not be recoverable. Assets
determined to be impaired based on estimated future net cash flows are reduced
to estimated fair value. Changes in such estimates could cause the Company to
reduce the carrying value of its property and equipment and goodwill.

Goodwill and Other Intangibles

Goodwill is amortized using the straight-line method over the estimated
benefit periods of twenty-four to thirty years. Noncompete agreements are
amortized using the straight-line method over the life of the agreement of seven
years.

Gas Balancing

The Company accounts for oil and gas revenue on the sales method--recording
revenues earned when gas is delivered. During such times as the Company's sales
of gas exceeds its percentage ownership in a well, such sales are recorded as
revenue unless total sales from the well have exceeded the Company's share of
total estimated reserves underlying the property, at which time such excess is
recorded as a liability. At December 31, 1996, based on the year-end price of
$3.10, the Company estimates its balancing position to be approximately $59,000
on underproduced properties and $413,000 on overproduced properties. The
Company's policy is to record lease operating costs from all wells to correspond
with the related recognition of revenue.

Income Taxes

The Company uses the liability method of accounting for income taxes. This
method requires the measurement of deferred tax assets for deductible temporary
differences and deferred tax liabilities for taxable temporary differences.
Measurement of current and deferred tax liabilities and assets is based on
provisions of enacted tax law; the effects of future changes in tax laws or
rates are not included in the measurement. Deferred tax liabilities primarily
result from the recognition of depreciation, depletion and amortization in
different periods for financial reporting and tax purposes. Income tax benefit
or expense is the tax payable for the current year and the change during that
year in deferred tax assets and liabilities.

Stock Based Compensation

The Company applies APB Opinion 25 in accounting for its stock option
plans. Under this standard, no compensation expense is recognized for grants of
options which include an exercise price equal to or greater than the market
price of the stock on the date of grant. Accordingly, based on the Company's
grants in 1996, 1995 and 1994, no compensation expense has been recognized. As
allowed by Financial Accounting Standard No. 123 "Accounting for Stock-Based
Compensation", the Company has disclosed the pro forma effects of recording
compensation for such option grants based on fair value in Note 7 to the
financial statements.

Financial Instruments and Concentration of Credit Risk

F-9
<PAGE>

Bbls per month for the months of October 1996 through September of 1997. The
swaps are accounted for as hedges of the Company's oil sales. Gains or losses
resulting from these swaps are recognized in the consolidated statement of
operations and included in operating cash flows in the same period as the
associated sale of oil.

Financial instruments which subject the Company to concentrations of credit
risk consist primarily of trade receivables with a variety of oil and gas
companies. The Company generally does not require collateral related to
receivables. Such credit risk is considered by management to be limited due to
the large number of customers comprising the Company's customer base.

The Company maintains its cash in bank deposit accounts which, at times,
may exceed federally insured limits.

Accounting 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 revenue and expenses during the reporting
period. Actual results could differ from those estimates.

Reclassifications

Certain prior year amounts have been reclassified to conform with the
current year presentation.

Recently Issued Accounting Pronouncements

NOTE 2 SALE OF COMMON STOCK AND ISSUANCE OF CONTINGENT WARRANTS

Effective December 19, 1996, the Company sold to a private investment group
(HACL) 8,000,000 shares of its common stock and warrants which, upon satisfying
certain vesting requirements, will entitle the purchase of an additional
8,000,000 shares of its common stock at a price of $.91 per share, for aggregate
consideration of $4,400,000. The Company has reported the cash consideration
received, net of related costs, of $4,400,000 as an addition to common stock and
paid-in-capital. The fair value of the contingent warrants has been estimated by
an independent valuation firm to be $1,440,000, which has been reflected as a
deferred expense and an increase in additional paid in capital. The deferred
expense associated with the warrants will be recognized as HACL performs
services resulting in the vesting of the warrants.

NOTE 3 PROVISION TO REDUCE THE CARRYING VALUE OF COMPRESSOR EQUIPMENT

At December 31, 1995, associated with the highly competitive marketplace
for compression rental equipment and the low utilization rates experienced on
certain of the Company's equipment, the Company identified certain equipment
which it intended to dispose of. Accordingly, the book value of the equipment
was reduced to its estimated fair value of approximately $800,000, resulting in
a provision to reduce the carrying value of the equipment of $1,790,000. Certain
of these compressors were disposed of in the third quarter of 1996, resulting in
an additional loss of $372,000. For the year ended December 31, 1995, these
compressors generated revenues of approximately $338,000 and depreciation
expense of $246,000.
F-10
<PAGE>

NOTE 4 PROPERTY AND EQUIPMENT
<TABLE>
<CAPTION>

1996 1995
------- -------
(In thousands)

<S> <C> <C>
Land and building................................ $ 307 $ 299
Oil and gas properties, on the full cost method.. 35,102 34,544
Compressor equipment............................. 23,489 22,110
Other equipment.................................. 479 469
------- -------
59,377 57,422
Less accumulated depreciation, depletion and
amortization.................................... 37,097 36,023
------- -------
Net property and equipment....................... $22,280 $21,399
======= =======
</TABLE>

On January 1, 1996, the Company sold interests in certain wells receiving
$157,300 for the well interests and related production equipment. The proceeds
from the sale were placed in trust and utilized by management to purchase oil
and gas properties in 1996 resulting in a "like kind exchange" for tax purposes,
with the tax gain on sale being deferred.

On December 30, 1994, the Company sold interests in fifty-seven wells
located in the Arkoma Basin of northwest Arkansas. The natural gas reserves
attributable to the properties sold represented approximately one-third of the
total equivalent natural gas reserves owned by the Company. The Company
received $2,513,000 for the well interests and related production equipment and
recognized a gain of $1,880,000 on the sale. The proceeds from the sale were
utilized to purchase oil and gas properties in early 1995, resulting in a "like
kind exchange" for tax purposes, with the gain on sale being deferred for tax
purposes.

NOTE 5 LONG-TERM DEBT

Long-term debt consists of the following:
<TABLE>
<CAPTION>
1996 1995
------- -------
(In thousands)
<S> <C> <C>
Note payable to bank at 2% over prime
(10% at December 31, 1995)(a)(c)............. $ -- $1,086
Revolving line of credit
(8.25 at December 31, 1996,
10% at December 31, 1995)(b)(c).............. 5,358 8,274
Note payable to bank at 2.5% over prime
(10.50% at December 31, 1995)................ -- 159
Notes payable, other.......................... 181 163
------ ------
Total debt.................................... 5,539 9,682
Less current portion.......................... 177 682
------ ------
Total long-term debt.......................... $5,362 $9,000
====== ======
</TABLE>

- -------------------
(a) In September 1995, the Company finalized an oil and gas loan of $1,225,722
to replace prior loans outstanding. Under the agreement, 34 monthly
principal installments of $35,000 commenced September 30, 1995 with a
final payment due July 31, 1998. The loan was collateralized by the
Company's interest in oil and gas properties. In December 1996, common
stock sale proceeds were used to pay the outstanding note balance.

(b) In March 1997, the Company received and accepted a formal bank commitment
to refinance its existing bank credit facility. The debt is structured as
a two year revolving line of credit with a $20 million maximum commitment
(previous commitment was $12 million) and has an initial borrowing base of
$12.5 million. Under the terms of the credit agreement, the outstanding
balance at the revolving period's maturity will be converted to a term
note payable over 60 months. The credit agreement contains a material
adverse change clause. The debt is collateralized by substantially all the
assets of the company.

F-11
<PAGE>

(c) Covenants related to the debt agreements include the maintenance of
specified levels of working capital, tangible net worth and debt service
ratio, as defined by the agreements. Additionally, the agreements prohibit
the payment of dividends and place limitations on the repurchase of shares
of the Company's stock and the incurrence of new borrowings. During 1996,
the Company was not in compliance with certain covenants of its debt
agreements, which were waived by the lender.

Long-term debt maturities as of December 31, 1996 are $177,000, $3,000,
$1,072,000, $1,072,000 and $1,072,000 in 1997, 1998, 1999, 2000 and 2001,
respectively, with a remainder of $2,143,000 due in subsequent years. Based on
the interest rates currently available to the Company for borrowings with
similar terms and maturities, the long-term debt at December 31, 1996
approximates fair value.

NOTE 6 INCOME TAXES

Consolidated income tax expense for each of the three years in the period
ended December 31, 1996, consists of the following components:
<TABLE>
<CAPTION>

YEAR ENDED DECEMBER 31,
---------------------------
1996 1995 1994
------- ------- ------
(In thousands)

<S> <C> <C> <C>
Current provision................... $ 28 $ 20 $132
Deferred expense (benefit).......... (97) (872) 567
---- ----- ----

Total income tax expense (benefit).. $(69) $(852) $699
==== ===== ====
</TABLE>

The Company's effective tax rate on pre-tax income differs from the U.S.
federal statutory regular tax rate as follows:
<TABLE>
<CAPTION>

YEAR ENDED DECEMBER 31,
---------------------------
1996 1995 1994
------- ------- ------
(In thousands)

<S> <C> <C> <C>
U.S. statutory regular tax rate.... (34%) (34%) 34%
State taxes........................ (4%) (4%) 4%
Goodwill and other................. 8% 1% 1%
---- ---- ----
Total.............................. (30%) (37%) 39%
==== ==== ====
</TABLE>
F-12
<PAGE>

Deferred tax assets and liabilities are comprised of the following at
December 31, 1996 and 1995:
<TABLE>
<CAPTION>

1996 1995
----- -----
(In thousands)
<S> <C> <C>
Deferred tax assets:
Allowances for losses........................ $ 29 $ 10
Net operating loss carryforward.............. 1,219 894
Alternative minimum tax credit carryforward.. 358 335
------ ------
Gross deferred tax assets.................. 1,606 1,239
------ ------

Deferred tax liabilities:
Property and equipment -- depreciation,
depletion and amortization................. 5,172 4,936
------ ------
Gross deferred tax liabilities............. 5,172 4,936
------ ------

Net deferred tax liability..................... $3,566 $3,697
====== ======
</TABLE>

At December 31, 1996, the Company had net operating loss carryforwards for
regular tax purposes of $3,208,000 which expire in 2009 through 2011. Deferred
income taxes of approximately $34,000 were reclassified to current in 1996 to
correct certain prior year estimates.

NOTE 7 COMPENSATION PLANS

EMPLOYEE STOCK OPTION PLAN. On August 8, 1989, the Board of Directors of
Hawkins Energy adopted and its stockholders approved the Hawkins Energy Employee
Stock Option Plan (the "Stock Option Plan") which became effective on that date.
An aggregate of 130,000 shares of common stock were initially available for sale
upon exercise of options granted under the Stock Option Plan, provided that the
number of shares available for options which may be granted under the Stock
Option Plan will automatically be increased without action of the directors or
stockholders of Hawkins Energy to an amount equal to (when added to the number
of shares of Hawkins Energy Common Stock subject to all other options granted by
Hawkins Energy) 8% of the issued and outstanding shares of common stock upon
each issuance of shares of common stock occurring after February 28, 1990 (other
than issuances of shares upon the exercise of options granted under the Stock
Option Plan). The Board of Directors may make authorized but unissued common
stock available for the exercise of options or it may utilize shares held in the
treasury. The Stock Option Plan is not subject to the provisions of the Employee
Retirement Income Security Act of 1974 and the options will not be "incentive
stock options," as such term is defined in Internal Revenue Code Section 422A.
At December 31, 1996, options to acquire 372,500 shares of common stock at a
price of $0.50 were outstanding.

DIRECTOR STOCK OPTION PLANS. On August 8, 1989, the Board of Directors
adopted and the stockholders approved the Hawkins Energy Director Stock Option
Plan (the "1989 Director Plan") which became effective on that date. An
aggregate of 170,000 shares of Hawkins Energy Common Stock are available for
sale upon exercise of options granted under the Director Plan. The 1989
Director Plan is not subject to the provisions of the Employee Retirement Income
Security Act of 1974 and the options will not be "incentive stock options," as
such term is defined in Internal Revenue Code Section 422A.

On May 25, 1994, the Board of Directors adopted and the stockholders
approved the 1994 Director Stock Option Plan which became effective on that
date. Options to acquire an aggregate of 355,000 shares of Common Stock were
initially granted; however, options to acquire 280,000 shares of Common Stock
were surrendered for cancellation in 1996. At December 31, 1996, options for
75,000 shares at a price of $1.40 were exercisable. As of December 31, 1996,
no options had been exercised. These options expire on May 24, 2004.

On March 27, 1996, the Board of Directors adopted and on May 29, 1996, the
stockholders approved the Director Stock Plan, which became effective on the
date of its approval by the Company's stockholders. Under the Director Stock
Plan, non-qualified stock options may be issued to non-employee directors of the
Company. An aggregate of 250,000 shares of common stock are reserved for
issuance upon the exercise of options granted under the Director Stock Plan. The
Director Stock Plan provided for, effective upon its approval by the Company's
stockholders, the automatic grant to eligible directors of an option to

F-13
<PAGE>

purchase either (i) 50,000 shares of Common Stock, if such eligible director had
been an employee of the Company at any time, or (ii) 17,500 shares of Common
Stock, if such eligible director had never been an employee of the Company. On
each anniversary of each eligible director's election to the Board for the term
as a director which he or she is currently serving, each such director will be
granted an option to purchase 5,000 shares of Common Stock. In addition, upon
an eligible director's initial election or appointment to the Board, such
director will receive the grant of an option to purchase 10,000 shares of common
stock. At December 31, 1996, options to acquire 260,000 shares of common stock
at prices ranging from $0.56 to $2.50 were outstanding. As of December 31,
1996, no options issued under the Director Stock Plan had been exercised. The
Director Stock Plan is not subject to any of the provisions of the Employee
Retirement Income Security Act of 1974 and the options will not be "incentive
stock options", as such term is defined in Internal Revenue Code Section 422A.

Activity pertaining to the Company's employee and director stock option
plans is as follows:

<TABLE>
<CAPTION>
WEIGHTED
NUMBER AVERAGE
OF EXERCISE
SHARES PRICE
------- --------
<S> <C> <C>
Outstanding at January 1, 1994 185,000 $ 2.50
Granted 355,000 1.40
Exercised -- --
-------- -------

Outstanding at December 31, 1994 540,000 $ 1.78
Granted -- --
Exercised -- --
Canceled -- --
-------- -------

Outstanding at December 31, 1995 540,000 $ 1.78
Granted 527,500 0.60
Exercised -- --
Canceled (420,000) (1.40)
-------- -------

Outstanding at December 31, 1996 647,500 $ 0.82
======== =======
</TABLE>

<TABLE>
<CAPTION>
OUTSTANDING OPTIONS

WEIGHTED WEIGHTED
NUMBER AVERAGE AVERAGE
EXERCISE OF REMAINING EXERCISE
PRICES SHARES CONTRACTUAL LIFE* PRICE
------------ ------- ----------------- --------
<S> <C> <C> <C> <C>
$0.50 - 1.00 477,500 39.5 Years $ 0.51
1.00 - 2.00 125,000 39.5 Years 1.39
2.50 45,000 35.0 Years 2.50
</TABLE>

All options were exercisable at December 31, 1996.

* Upon termination of employment or board service the option term becomes
four years from date of termination.

The Company applies APB Opinion 25 in accounting for its Stock Option Plan
and Non-Employee Director's Stock Option Plan. Accordingly, based on the nature
of the Company's grants of options, no compensation cost has been recognized in
1996 and 1995. Had compensation been determined on the basis of fair value
pursuant to FASB Statement No. 123, net income (loss) and earnings per share
would have been as follows:

F-14
<PAGE>

1996 1995
------ --------
<S> <C> <C>
Net Income (loss) (In thousands):
As reported $(160) $(1,438)
Pro forma $(381) $(1,438)

Earnings (loss) per Share:
As reported $(.01) $ (.11)
Pro forma $(.03) $ (.11)
</TABLE>

The fair value of each option granted is estimated using the Black-Scholes
model. The Company's estimated stock volatility was 96% based on previous stock
performance. Dividend yield was estimated to remain at zero with a risk free
interest rate of 6% in 1996. Expected life was estimated at four years based on
prior experience depending on the vesting periods involved and the make up of
participating employees within each grant. Fair value of options granted during
1996 was approximately $130,400 under the Employees Stock Option Plan and
approximately $91,000 under the Directors Stock Option Plan. No options were
granted during 1995.

EMPLOYEE BENEFIT PLAN. Substantially all of the Company's employees are
covered by a defined contribution 401(k) plan adopted in 1991. The Company
matches 50% of the employee contributions up to a limit of 4% of employee annual
earnings. All matching contributions are made in Company stock. Total expense
related to the plan amounted to $41,000 in 1996, $48,000 in 1995 and $55,000 in
1994.

OTHER. Non-qualified options for 15,000 shares at a price of $2.50 per
share were granted to a former employee of the Company in 1990, all of which are
currently exercisable with an expiration date of January 2030.

NOTE 8 TRANSACTIONS WITH RELATED PARTIES

Amounts have been accrued in the years ended December 31 by the Company to
an affiliate for general and administrative overhead including rent and
production and drilling overhead as follows: $53,000 in 1996, $135,000 in 1995
and $155,000 in 1994.

The Company earned compressor rental revenues from an affiliate in the
amount of $32,000 in 1996, $104,000 in 1995 and $154,000 in 1994. The Company
earned rental revenues from a related entity of $21,000 in 1996, $67,000 in 1995
and $227,000 in 1994.

NOTE 9 COMMITMENTS

The Company leases compressor equipment under contracts with terms ranging
from month to month to three years. The future revenues to be received under
contracts at December 31, 1996 are $653,000 and $43,000 in 1997 and 1998,
respectively.

The Company leases facilities for its corporate and field offices with
lease terms ranging from month to month to two years. The Company has certain
other operating leases for other facilities, office equipment and automobiles.
Future minimum rental payments under these leases total $117,000, $72,000,
$25,000 and $2,000 for 1997, 1998, 1999 and 2000, respectively. The Company's
rental expense was $431,000, $400,000 and $318,000 in 1996, 1995 and 1994,
respectively.

F-15
<PAGE>

NOTE 10 INDUSTRY SEGMENT INFORMATION
OPERATIONS BY INDUSTRY SEGMENT
(In thousands)
<TABLE>
<CAPTION>
1996 1995 1994
------- ------- -------
<S> <C> <C> <C>

Revenues:
Oil and gas......................... $ 1,821 $ 1,530 $ 3,730(2)
Compressor operations............... 7,679 8,470 10,039
Intersegment........................ (57) (57) (93)
------- ------- -------
Total revenue..................... $ 9,443 $ 9,943 $13,676
======= ======= =======

Operating profit(loss)(includes
depreciation, depletion and
amortization)
Oil and gas......................... $ 441 $ (45) $ 1,540
Compressor operations............... 231 (1,304)(1) 971
------- ------- -------
Total operating profit (loss)....... 672 (1,349) 2,511

Interest income....................... 26 102 79
Interest expense...................... (927) (1,043) (842)
------- ------- -------
Income (loss) before income taxes..... $ (229) $(2,290) $ 1,748
======= ======= =======

Identifiable assets:
Oil and gas......................... $ 4,543 $ 4,277 $ 4,023
Compressor operations............... 21,267 21,764 23,891
------- ------- -------

Total identifiable assets........... $25,810 $26,041 $27,914
======= ======= =======

Capital expenditures:
Oil and gas......................... $ 732 $ 2,534 $ 222
Compressor operations............... 3,580 1,753 3,092
------- ------- -------

Total capital expenditures.......... $ 4,312 $ 4,287 $ 3,314
======= ======= =======

Depreciation, depletion and
amortization:
Oil and gas......................... $ 310 $ 350 $ 532
Compressor operations............... 1,891 1,976 1,942
------- ------- -------

Total depreciation, depletion and
amortization...................... $ 2,201 $ 2,326 $ 2,474
======= ======= =======
</TABLE>
(1) Includes a provision to reduce the carrying value of certain compression
equipment of $1,790,000.
(2) Includes gain on sale of oil and gas properties of $1,880,000.

F-16
<PAGE>

NOTE 11 OIL AND GAS INFORMATION (UNAUDITED AS TO RESERVE INFORMATION)

Capitalized costs at year-end and costs incurred during the year were
as follows:
<TABLE>
<CAPTION>
1996 1995 1994
------- ------- -------
(In thousands)
<S> <C> <C> <C>
Capitalized costs:
Proved properties.......................... $35,102 $34,544 $32,010
Unproved properties........................ -- -- --
------- ------- -------
Total........................................ 35,102 34,544 32,010

Less:
Accumulated depreciation, depletion
and amortization and provision to
reduce carrying value.................. 31,376 31,115 30,786
------- ------- -------
Net capitalized costs................ $ 3,726 $ 3,429 $ 1,224
======= ======= =======

Costs incurred:
Proved properties.......................... -- 2,534 --
Development................................ 732 -- 222
------- ------- -------

Total costs incurred..................... $ 732 $ 2,534 $ 222
======= ======= =======
</TABLE>

Results of operations for producing activities were as follows:
<TABLE>
<CAPTION>
1996 1995 1994
------- ------- -------
(In thousands)
<S> <C> <C> <C>
Revenues..................................... $ 1,821 $ 1,530 $ 1,850
Production costs............................. (516) (621) (636)
Depreciation, depletion and amortization..... (261) (329) (477)
Income taxes................................. (397) (220) (280)
------- ------ -------

Results of operations for producing
activities (excluding overhead and
financing costs)........................... $ 647 $ 360 $ 457
======= ======= =======
</TABLE>
Estimated quantities of proved developed oil and natural gas reserves and
changes in net quantities of proved oil and natural gas reserves were as
follows:
<TABLE>
<CAPTION>

YEARS ENDED DECEMBER 31,
1996 1995 1994
------------ ------------ -------------
Oil Gas Oil Gas Oil Gas
Bbls Mcf Bbls Mcf Bbls Mcf
---- ----- ---- ----- ---- ------
(In thousands)
<S> <C> <C> <C> <C> <C> <C>
Proved Reserves:
Beginning of year 913 3,801 18 2,501 19 4,788
Revision of estimates 39 604 3 (75) 3 111
Extensions and discoveries -- 965 631 -- -- --
Purchase of reserves 9 144 286 2,000 -- --
Sales of reserves -- -- -- -- -- (1,451)
Production (31) (525) (25) (625) (4) (947)
--- ----- --- ----- ---- ------
End of year 930 4,989 913 3,801 18 2,501
=== ===== === ===== ==== ======

Proved Developed Reserves: 930 4,717 282 3,801 18 2,501
=== ===== === ===== ==== ======
</TABLE>

Proved reserves are those quantities which, upon analysis of
geological and engineering data, appear with reasonable certainty to be
recoverable in the future from known oil and gas reservoirs under existing

F-17
<PAGE>

economic and operating conditions. Proved developed reserves are those reserves
which can be expected to be recovered through existing wells with existing
equipment and operating methods.

Oil and gas reserves cannot be measured exactly. Estimates of oil and
gas reserves require extensive judgments of reservoir engineering data and are
generally less precise than other estimates made in connection with financial
disclosures. The Company utilizes Lee Keeling & Associates, Inc., independent
petroleum consultants, to estimate the Company's reserves.

Assigning monetary values to such estimates does not reduce the
subjectivity and changing nature of such reserve estimates. Indeed the
uncertainties inherent in the disclosure are compounded by applying additional
estimates of the rates and timing of production and the costs that will be
incurred in developing and producing the reserves. The information set forth
herein is therefore subjective and, since judgments are involved, may not be
comparable to estimates submitted by other oil and gas producers. In addition,
since prices and costs do not remain static and no price or cost escalations or
de-escalations have been considered, the results are not necessarily indicative
of the estimated fair market value of estimated proved reserves nor of estimated
future cash flows.

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS

The standardized measure of discounted future net cash flows was
calculated using year-end prices and costs, and year-end statutory tax rates,
adjusted for permanent differences, that relate to existing proved oil and gas
reserves. Future net cash flows as of December 31 are as follows:
<TABLE>
<CAPTION>

DECEMBER 31,
-----------------------------
1996 1995 1994
------- ------- -------
(In thousands)
<S> <C> <C> <C>

Future cash flows................... $ 38,897 $22,906 $ 4,414
Production costs.................... (12,124) (7,745) (2,145)
Development costs................... (148) (576) (94)
Income tax expense.................. (9,900) (5,410) (755)
-------- ------- -------
Future net cash flows............... 16,725 9,175 1,420
10% discount factor................. (6,487) (3,759) (368)
-------- ------- -------
Standardized measure of discounted
future net cash flows............. $ 10,238 $ 5,416 $ 1,052
======== ======= =======
</TABLE>

In early 1997, the oil and natural gas industry has experienced a
downturn in prices. The Company's reserves were determined at December 31, 1996
using constant prices of approximately $25.18 per Bbl of oil and $3.10 per MCF
of gas. During March 1997, the prices received by the Company fell to
approximately $21.28 per Bbl of oil and $1.95 per MCF of natural gas. This
decrease in prices would have a significant effect on the SMOG value of the
Company's reserves at December 31, 1996.

F-18
<PAGE>

The following table summarizes the principal factors comprising the changes
in the standardized measure of discounted future net cash flows.
<TABLE>
<CAPTION>

DECEMBER 31,
---------------------------
1996 1995 1994
------ ------ ------
(In thousands)
<S> <C> <C> <C>
Standardized measure, beginning
of year.......................... $ 5,416 $ 1,052 $ 3,032
Sales of oil and gas net of
production costs................. (1,305) (909) (1,214)
Net changes in prices and
production costs................. 6,184 1,371 (1,173)
Extensions and discoveries less
related costs.................... 1,454 3,659 --
Purchase of reserves............... 157 2,714 --
Sale of reserves................... -- -- (1,113)
Revisions of previous estimates.... 674 74 135
Accretion of discount.............. 524 89 244
Change in income tax expense....... (2,866) (2,634) 1,141
------- ------- -------
Standardized measure, end of year.. $10,238 $ 5,416 $ 1,052
======= ======= =======
</TABLE>

F-19
<PAGE>

EXHIBIT INDEX
-------------

EXHIBIT SEQUENTIAL
NO. DESCRIPTION PAGE
- ------- ----------- ----

21.1 Subsidiaries of the Registrant

23.1 Consent of Independent Accountants

23.2 Consent of Independent Petroleum Engineers

27 Financial Data Schedule

<PAGE>

EXHIBIT 21.1

SUBSIDIARIES OF THE REGISTRANT

STATE OF PERCENTAGE
SUBSIDIARY INCORPORATION OWNED
- ------------------------ ------------- -------------

Equity Compressors, Inc. Oklahoma 100%

<PAGE>

Exhibit 23.1

CONSENT OF INDEPENDENT ACCOUNTANTS

We consent to the incorporation by reference in the Registration Statements
of Equity Compression Services Corporation (formerly Hawkins Energy Corporation,
the "Company") on Form S-8 (File Nos. 33-74640 and 333-23925) of our report
dated March 25, 1997, on our audits of the consolidated financial statements of
the Company as of December 31, 1996 and 1995, and for the years ended December
31, 1996, 1995 and 1994, which report is included in this Annual Report on Form
10-KSB.

COOPERS & LYBRAND L.L.P.

Tulsa, Oklahoma
March 28, 1997

<PAGE>

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the inclusion of the information incorporated by
reference in the Registration Statements of Equity Compression Services
Corporation (the "Company") on Form S-8 (Nos. 33-74640 and 333-23925) with
respect to the oil and gas reserve information of the Company included in its
Annual Report on Form 10-KSB for the year ended December 31, 1996.

LEE KEELING AND ASSOCIATES, INC.

BY: /s/ KENNETH RENBERG
------------------------------------------
Kenneth Renberg
Vice President

Tulsa, Oklahoma
March 26, 1997

<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<CASH> 10
<SECURITIES> 0
<RECEIVABLES> 1,327
<ALLOWANCES> 76
<INVENTORY> 1,476
<CURRENT-ASSETS> 2,783
<PP&E> 59,377
<DEPRECIATION> 37,097
<TOTAL-ASSETS> 25,810
<CURRENT-LIABILITIES> 1,996
<BONDS> 0
210
0
<COMMON> 0
<OTHER-SE> 14,587
<TOTAL-LIABILITY-AND-EQUITY> 25,810
<SALES> 2,998
<TOTAL-REVENUES> 9,443
<CGS> 1,410
<TOTAL-COSTS> 8,771
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> (927)
<INCOME-PRETAX> (229)
<INCOME-TAX> 69
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (160)
<EPS-PRIMARY> (.01)
<EPS-DILUTED> (.01)

</TABLE>