UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K/A
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended September 30, 2003

[ ] TRANSITION REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to __________

Commission file number: 0-4408

RESOURCE AMERICA, INC.
(Exact name of registrant as specified in its charter)

DELAWARE 72-0654145
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

1845 Walnut Street
Suite 1000
Philadelphia, PA 19103
(Address of principal executive offices) (Zip code)

Registrant's telephone number, including area code: (215) 546-5005
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:

Common stock, par value $.01 per share
(Title of class)

Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [X] No [ ]

The aggregate market value of the voting common equity held by non-affiliates of
the registrant, based upon the closing price of such stock on December 15, 2003,
was approximately $229.6 million.

The number of outstanding shares of the registrant's common stock on December
15, 2003 was 17,354,300.

DOCUMENTS INCORPORATED BY REFERENCE

None

[THIS PAGE INTENTIONALLY LEFT BLANK]

RESOURCE AMERICA, INC. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT
ON FORM 10-K/A

PART I Page
----

Item 1: Business.................................................................................. 2 - 24
Item 2: Properties................................................................................ 24 - 29
Item 3: Legal Proceedings......................................................................... 29
Item 4: Submission of Matters to a Vote of Security Holders....................................... 29

PART II
Item 5: Market for Registrant's Common Equity and Related Stockholder Matters..................... 30
Item 6: Selected Financial Data................................................................... 31
Item 7: Management's Discussion and Analysis of Financial Condition
and Results of Operation.............................................................. 32 - 51
Item 7A: Quantitative and Qualitative Disclosures about Market Risk................................ 52 - 53
Item 8: Financial Statements and Supplementary Data............................................... 54 - 103
Item 9: Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure................................................ 104
Item 9A: Controls and Procedures................................................................... 104

PART III
Item 10: Directors and Executive Officers of the Registrant........................................ 105 - 107
Item 11: Executive Compensation.................................................................... 108 - 111
Item 12: Security Ownership of Certain Beneficial Owners and Management............................ 112 - 115
Item 13: Certain Relationships and Related Transactions............................................ 115 - 117
Item 14: Principal Accountant Fees and Services.................................................... 118

PART IV
Item 15: Exhibits, Financial Statement Schedules and Reports on Form 8-K........................... 119 - 120

SIGNATURES................................................................................................ 121

PART I

ITEM 1. BUSINESS

THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS REGARDING EVENTS
AND FINANCIAL TRENDS WHICH MAY AFFECT THE REGISTRANT'S FUTURE OPERATING RESULTS
AND FINANCIAL POSITION. SUCH STATEMENTS ARE SUBJECT TO RISKS AND UNCERTAINTIES
THAT COULD CAUSE THE REGISTRANT'S ACTUAL RESULTS AND FINANCIAL POSITION TO
DIFFER MATERIALLY FROM THOSE ANTICIPATED IN SUCH STATEMENTS. IN OUR ENERGY
BUSINESS, THESE FACTORS INCLUDE, BUT ARE NOT LIMITED TO, LACK OF REVENUES,
COMPETITION, NEED FOR ADDITIONAL CAPITAL, RISKS ASSOCIATED WITH EXPLORING,
DEVELOPING, AND OPERATING OIL AND NATURAL GAS WELLS, AND FLUCTUATIONS IN THE
MARKET FOR NATURAL GAS AND OIL. IN REAL ESTATE, THESE FACTORS INCLUDE, BUT ARE
NOT LIMITED TO, RISKS OF LOAN DEFAULTS AND ADEQUACY OF OUR PROVISION FOR LOSSES
AND ILLIQUIDITY OF OUR PORTFOLIO. FOR A MORE COMPLETE DISCUSSION OF THE RISKS
AND UNCERTAINTIES TO WHICH WE ARE SUBJECT, SEE "RISK FACTORS" IN THIS ITEM 1.

General

We are a specialized asset management company that uses industry
specific expertise to generate and administer investment opportunities for our
own account and for outside investors in the energy, financial services, real
estate and equipment leasing sectors. As a specialized asset manager, we seek to
develop investment vehicles in which outside investors invest along with us and
for which we manage the assets acquired, pursuant to long-term management and
operating agreements. We limit our investment vehicles to investment areas where
we own existing operating companies or have specific expertise. We believe this
strategy enhances our return on investment as well as that of our third-party
investors. We typically receive an interest in the investment vehicle in
addition to the interest resulting from our investment. We managed approximately
$2.6 billion in assets at the end of fiscal 2003, as follows:

o $516 million of energy assets (20%) (1)
o $682 million of real estate assets (27%) (2)
o $1.3 billion of financial services assets (51%), (3) and
o $63 million of equipment leasing assets (2%) (4)

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(1) We value our managed energy assets as the sum of the PV-10 values, as of
September 30, 2003, of the proved reserves owned by us and the
investment partnerships and other entities whose assets we manage, plus
the book value, as of September 30, 2003, of the total assets of Atlas
Pipeline Partners, L.P. For a definition of the term "PV-10 value" see
Note 6 at page 3 of this report.
(2) We value our managed real estate assets as the sum of the amount of our
outstanding loan receivables, including the loans underlying the assets
and liabilities consolidated pursuant to Financial Accounting Standards
Board Interpretation No. 46, plus the book value of our interests in
real estate and the sum of the book values of real estate assets and
other assets held by a real estate investment partnership we managed as
of September 30, 2003.
(3) We value our financial services assets as the acquisition cost of
securities acquired by ventures which we co-manage that acquired trust
preferred securities of regional banks and bank holding companies.
(4) We value our equipment leasing assets as the sum of the book values of
equipment held by equipment leasing ventures or partnerships which we
managed as of September 30, 2003.

During fiscal 2003, we continued developing our energy operations,
which account for approximately 79% of our total revenues and 35% of our total
assets. The number of gross wells we drilled increased 17% and the number of net
wells increased 16% in fiscal 2003 as compared to fiscal 2002. We have funded
our development operations primarily by sponsoring drilling investment
partnerships. We, and our drilling investment partnerships, own interests in
approximately 5,300 wells, 85% of which we operate. At September 30, 2003,
proved reserves net to our interest were approximately 144.4 Bcfe (5) with a
PV-10 value (6) of $191.4 million and a standardized measure value(7) of $144.3
million. Of these reserves, 92% were natural gas and 68% were classified as
proved developed reserves.

We continued developing our natural gas transportation operations,
which we conduct through Atlas Pipeline Partners, L.P., a publicly held (AMEX:
APL) natural gas pipeline master limited partnership of which a subsidiary of
ours is the general partner and in which we own a 39% interest. At September 30,
2003, Atlas Pipeline Partners owned approximately 1,400 miles of intrastate
gathering systems located in eastern Ohio, western New York and western
Pennsylvania, to which approximately 4,200 natural gas wells were connected. In
September 2003, Atlas Pipeline Partners entered into an agreement to acquire the
Alaska Pipeline Company, LLC, the owner of approximately 354 miles of natural
gas gathering systems in the Anchorage, Alaska area.

In real estate finance, we continued to implement our strategic shift
from loan acquisition and resolution to the sponsorship and management of real
estate investments and the management of our existing loan portfolio. We
sponsored two private real estate partnerships, one of which was fully funded in
fiscal 2003 and anticipates full investment in properties in December 2003, and
one of which is in the offering stage. We have not purchased any loans since
fiscal 1999 although, as part of our portfolio management activities, we have
from time to time purchased senior lien interests relating to properties in
which we have junior lien interests. We did not purchase any loan participations
in fiscal 2003, but did acquire property interests through loan restructurings
and foreclosures.

We have also continued the development of our financial services and
equipment leasing operations. In financial services, we have co-sponsored and
are the co-manager of five investment entities that were formed to acquire the
trust preferred securities of small to mid-sized regional banks and bank holding
companies. One of these entities was sponsored in fiscal 2002 and became funded
and fully invested in fiscal 2002. Two of these entities were sponsored, funded
and became fully invested during fiscal 2003. The fourth and fifth entities were
in the offering stage in fiscal 2003, and became funded and fully invested by
December 2003. In equipment leasing, our Lease Equity Appreciation Fund I, L.P.
("LEAF I LP"), lease investment partnership commenced operations in March 2003,
and continues in its offering stage. In April 2003, we entered into an agreement
with a third party under which we originate equipment leases for sale to that
party, to a maximum of $300.0 million of equipment leases, retaining management
and servicing of these leases.

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(5) "Mcfe," "Mmcfe" and "Bcfe" mean thousand cubic feet equivalent, million
cubic feet equivalent and billion cubic feet equivalent, respectively.
Natural gas volumes are converted to barrels, or "Bbls", of oil
equivalent using the ratio of six thousand cubic feet, or "Mcf" of
natural gas to one Bbl of oil and are stated at the official temperature
and pressure bases of the area in which the reserves are located.
(6) "PV-10 value" means, in accordance with SEC guidelines, the estimated
future net cash flow to be generated from the production of proved
reserves discounted to present value using an annual discount rate of
10%. This amount is calculated net of estimated production costs and
future development costs, using prices and costs in effect as of a
specified date, without escalation and without giving effect to
non-property or non-production related expenses such as general
administrative expenses, debt service or future income tax expense, or to
depreciation, depletion and amortization.
(7) "Standardized measure value" means the estimated future net cash flows to
be generated from the production of proved reserves less a 10% discount.
This amount is calculated using year-end prices, adjusted for only fixed
and determinable increases in natural gas prices provided by contractual
arrangements. Future net cash flows are reduced by estimated future costs
to develop and produce the proved reserves, based on year-end cost
levels. See Note 18 to our Consolidated Financial Statements. The
difference between this amount and the total PV-10 value is attributable
to estimated income taxes.

During 2003 we reduced the amount of our outstanding 12% senior notes
due 2004 and expect to have fully paid them off by January 2004, seven months
ahead of their maturity date. We repurchased $11.3 million of senior notes
during fiscal 2003 and, subsequent to fiscal year-end, repurchased an
additional $1.0 million of senior notes. Also subsequent to year end, in
November 2003 we called our senior notes for redemption, of which $40.0 million
are scheduled for redemption on December 22, 2003 and the balance on January
20, 2004. After we sent notice of redemption, we repurchased $26.9 million of
senior notes in November 2003 and applied them to the December 22, 2003
redemption amount.

Our consolidated financial statements for fiscal 2003 have been
affected by our early adoption of Financial Accounting Standards Board's
Interpretation 46, "Consolidation of Variable Interest Entities," which we refer
to as FIN 46. As a result, we have consolidated certain entities in our real
estate loan business into our financial statements for the first time. FIN 46,
intended to increase the transparency of off-balance sheet transactions and
structures, affects our holding of real estate loans acquired at a discount
between 1991 and 1998. Since we control certain important indicia relating to
these loans, including cash flow and appointment of a property manager, FIN 46
affects our accounting for these holdings. FIN 46's consolidation criteria are
based on analysis of risks and rewards, not formalities of control and
ownership, and represent a significant and complex modification of previous
accounting principles. The adoption of FIN 46 resulted in a non-cash cumulative
effect adjustment of $13.9 million, net of taxes, in the fourth quarter of
fiscal 2003, as well as in our recording assets and liabilities of $78.2 million
and $45.2 million, respectively, related to the newly consolidated entities. In
line with our strategic focus in real estate, we classified an additional $222.7
million of our FIN 46 assets as being held for sale along with $141.5 million of
associated liabilities. For a more detailed discussion of FIN 46, you should
read Item 7, "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Cumulative Effect of Change in Accounting Principle" and
Note 3, Adoption of FASB Interpretation 46, to our Consolidated Financial
Statements.

For financial information about our operating segments, see Note 17,
Operating Segment Information and Major Customer Information, to our
Consolidated Financial Statements.

Energy

General. We concentrate our energy operations in the western New York,
eastern Ohio and western Pennsylvania region of the Appalachian Basin. As of
September 30, 2003, we owned proved reserves of approximately 144.4 Bcfe as
compared to 123.7 Bcfe at the beginning of fiscal 2000. As of September 30,
2003:

o We had, either directly or through investment partnerships managed by
us, interests in approximately 5,300 gross wells, including royalty
or overriding royalty interests in over 600 wells. We operate 85% of
these wells.

o Wells in which we have an interest produced, net to our interest,
approximately 19,100 Mcf of natural gas and 438 Bbls of oil per day.

o We had an acreage position of approximately 431,200 gross (379,000
net) acres, of which 205,400 gross (190,500 net) acres were
undeveloped.

o We owned and operated, either directly or through Atlas Pipeline
Partners, approximately 1,600 miles of gas gathering systems and
pipelines.

Since 1976, we or our predecessors have funded our development
operations through private and, since 1992, public drilling investment
partnerships. We act as the managing general partner of each of these
partnerships, contribute the leases on which the partnership drills, and
contribute a proportionate share of the partnership's capital. We receive an
interest in a partnership proportionate to the capital and leases we
contribute, generally 25% to 27%, plus a 7% carried interest. We typically
subordinate a portion of our partnership interest to a preferred return to the
limited partners for the first five years of distributions. We also receive
monthly operating fees of approximately $275 per well and monthly
administrative fees of $75 per well. In addition, we typically act as the
drilling contractor and operator of the wells drilled by the partnerships on a
cost-plus basis. In fiscal 2003, our drilling partnerships invested $68.6
million in drilling and completing wells, of which we contributed $15.7
million. In fiscal 2002, our drilling partnerships invested $75.5 million in
drilling and completing wells, of which we contributed $19.7 million. In fiscal
2001, our drilling partnerships invested $55.1 million in drilling and
completing wells of which we contributed $14.3 million. Additionally, we
invested $9.3 million, $10.6 million and $8.8 million in syndication and
organization costs related to these partnerships in fiscal 2003, 2002 and 2001,
respectively.

We transport the natural gas produced from wells we operate through the
gas gathering pipeline systems owned and operated by Atlas Pipeline Partners.
See "Energy- Pipeline Operations." We also own directly approximately 200 miles
of gathering systems. The gathering systems transport the natural gas to public
utility pipelines for delivery to customers. To a lesser extent, the gathering
systems deliver natural gas directly to customers. We sell the natural gas we
produce to customers such as gas brokers and local utilities under a variety of
contractual arrangements. We sell the oil we produce to regional oil refining
companies at the prevailing spot price for Appalachian crude oil.

Appalachian Basin Overview. The Appalachian Basin includes the states
of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and
Tennessee. It is the most mature oil and gas producing region in the United
States, having established the first oil production in 1859. In addition, the
Appalachian Basin is strategically located near the energy-consuming regions of
the mid-Atlantic and northeastern United States which has historically resulted
in Appalachian producers selling their natural gas at a premium to the benchmark
price for natural gas on the NYMEX.

According to the Energy Information Administration, a branch of the
U.S. Department of Energy, in 2002 there were 22.8 Tcf, of natural gas consumed
in the United States which represented approximately 23.9% of the total energy
used. The Appalachian Basin accounted for approximately 3.1% of total 2002
domestic natural gas production, or 603 Bcf. At December 31, 2001, there were
approximately 137,000 gas wells in the Appalachian Basin which represented
approximately 37.3% of the total number of gas wells in the United States. Of
those wells, we and our drilling investment partnerships own interests in
approximately 5,600 wells, 85% of which we operate.

Furthermore, according to the Advance Summary 2002 Annual Report
published in October 2003 by the Energy Information Administration, Office of
Oil and Gas,, the Appalachian Basin holds 10.6 Tcf of economically recoverable
reserves, representing approximately 5.7% of total domestic reserves as of
December 31, 2002. The raised forecast in August 2003 of World Oil magazine
predicted that approximately 5,060 gas wells would be drilled in the Appalachian
Basin during 2003, representing approximately 17.1% of the total number of wells
to be drilled in the United States, and that the average depth of those 4,600
wells would be approximately 3,200 feet, compared to an estimated average depth
of 5,100 feet for nationwide drilling efforts in 2003. The American Petroleum
Institute has reported that in recent years the drilling success rate in the
Appalachian basin has exceeded 90%. Our success rates have averaged in excess of
95% over the past 15 years.

Natural Gas and Oil Properties. For information concerning our natural
gas and oil properties, including the number of wells in which we have a
working interest, production, reserve and acreage information and information
concerning future dismantlement, restoration, reclamation and abandonment costs
and salvage values, see Item 2, "Properties - Energy."

Natural Gas Hedging. Pricing for gas and oil production has been
volatile and unpredictable for many years. To limit exposure to changing natural
gas prices, from time to time we use hedges. Through our hedges, we seek to
provide a measure of stability in the volatile environment of natural gas
prices. These hedges may include purchases of regulated NYMEX futures and
options contracts and non-regulated over-the-counter futures contracts with
qualified counterparties. The futures contracts are commitments to purchase or
sell natural gas at future dates and generally cover one-month periods for up to
24 months in the future. To assure that the financial instruments will be used
solely for hedging price risks and not for speculative purposes, we have a
committee to assure that all financial trading is done in compliance with our
hedging policies and procedures. We do not intend to contract for positions that
we cannot offset with actual production.

FirstEnergy Solutions and other third-party marketers to which we sell
gas, such as Colonial Energy, Inc. and UGI Energy Services, also use NYMEX-based
financial instruments to hedge their pricing exposure and make price hedging
opportunities available to us. These transactions are similar to NYMEX-based
futures contracts, swaps and options, but also require firm delivery of the
hedged quantity. Thus, we limit these arrangements to much smaller quantities
than those projected to be available at any delivery point. The price paid by
First Energy Solutions Corporation, Colonial Energy, Inc., UGI Energy Services,
and any other third-party marketers for certain volumes of natural gas sold
under these hedge agreements may be significantly different from the underlying
monthly spot market value.

Financing Our Drilling Activities. We derive a substantial portion of
our capital resources for drilling operations from our sponsored drilling
investment partnerships. Accordingly, the amount of development activities we
undertake depends upon our ability to obtain investor subscriptions to the
partnerships. During fiscal 2003, 2002 and 2001 our drilling investment
partnerships invested $68.6 million, $75.5 million and $55.1 million,
respectively, in drilling and completing wells, of which we contributed $15.7
million, $19.7 million and $14.3 million, respectively.

We generally structure our drilling investment partnership so that,
upon formation of a partnership, we contribute leaseholds to it, enter into a
drilling and well operating agreement with it and become its general or managing
partner. As general partner, we typically receive an interest in the
partnership's net revenues proportionate to our contributed capital, including
the costs of leases contributed, plus a 7% carried interest. Our interests in
partnerships formed during the past three fiscal years generally range from 25%
to 27% plus the 7% carried interest, a portion of which we subordinate to a
preferred return to our partnership investors for the first five years of
distributions. We also receive monthly operating fees of approximately $275 per
well and monthly administrative fees of $75 per well.

Pipeline Operations. We conduct our natural gas transportation
operations through Atlas Pipeline Partners. At September 30, 2003, Atlas
Pipeline Partners owned approximately 1,400 miles of intrastate gathering
systems located in eastern Ohio, western New York and western Pennsylvania, to
which approximately 4,200 natural gas wells were connected. Atlas Pipeline
Partners' gathering systems had an average daily throughput of 52.7 Mmcf , 49.7
Mmcf and 45.1 Mmcf of natural gas in fiscal 2003, 2002 and 2001, respectively.
We also directly own approximately 240 miles of natural gas gathering systems in
Ohio and Pennsylvania, whose throughputs are not material.

Atlas Pipeline Partners GP, our indirect wholly owned subsidiary, is
the general partner of Atlas Pipeline Partners. On a consolidated basis, it has
a 2% interest in Atlas Pipeline Partners. In addition, as of September 30, 2003,
we owned 1,641,026 subordinated units of Atlas Pipeline Partners, constituting
a 37% interest in it. Atlas Pipeline Partners GP manages the activities of
Atlas Pipeline Partners using Atlas America, Inc. a wholly owned subsidiary,
personnel who act as its officers and employees.

Our subordinated units in Atlas Pipeline Partners are a special class
of interest under which our right to receive distributions is subordinated to
those of the publicly-held common units. The subordination period is scheduled
to expire on January 1, 2005 unless certain financial tests specified in the
partnership agreement are not met. We expect that these tests will be met. Upon
expiration of the subordination period, our subordinated units will convert to
an equal number of common units.

As general partner, we have the right to receive incentive
distributions if Atlas Pipeline Partners meets or exceeds its minimum quarterly
distribution obligations to the common and subordinated units. The incentive
distributions are as follows:

o of the first $0.10 per unit available for distribution in excess of
the $0.42 minimum quarterly distribution, 85% goes to all unit
holders (including to us as a subordinated unit holder) and 15% goes
to us as a general partner;

o of the next $0.08 per unit available for distribution, 75% goes to
all unit holders and 25% goes to us as a general partner, and

o after that, 50% goes to all unit holders and 50% goes to us as a
general partner.

We have agreements with Atlas Pipeline Partners that require us to do
the following:

o Pay gathering fees to Atlas Pipeline Partners for natural gas
gathered by the gathering systems equal to the greater of $0.35 per
Mcf ($0.40 per Mcf in certain instances) or 16% of the gross sales
price of the natural gas transported. For the years ended September
30, 2003, 2002 and 2001, these gathering fees averaged $0.75, $0.57
and $0.81 per Mcf, respectively.

o Connect wells owned or controlled by us that are within specified
distances of Atlas Pipeline Partners' gathering systems to those
gathering systems.

o Provide stand-by construction financing to Atlas Pipeline Partners,
at its request, for gathering system extensions and additions, to a
maximum of $1.5 million per year, until 2005. We have not been
required to provide any construction financing under this agreement
since Atlas Pipeline Partners' inception.

We believe that we comply with all the requirements of these
agreements.

On September 16, 2003, Atlas Pipeline Partners entered into an
agreement to acquire the Alaska Pipeline Company for $95.0 million. We describe
the proposed acquisition in "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Pending Acquisition." At closing, the
seller will enter into various agreements that will require the seller to pay
Alaska Pipeline Company a minimum monthly capacity reservation fee and a
volume-based transportation fee for 10 years. These agreements also require the
seller to provide operational, maintenance and administrative services for five
years at a specified fee, subject to inflation-based adjustments in the fourth
and fifth contract years.

Availability of Oil Field Services. We contract for drilling rigs and
purchase goods and services necessary for the drilling and completion of wells
from a number of drillers and suppliers, none of which supplies a significant
portion of our annual needs. During fiscal 2003, we faced no shortage of these
goods and services. We cannot predict the duration of the current supply and
demand situation for drilling rigs and other goods and services with any
certainty due to numerous factors affecting the energy industry and the demand
for natural gas and oil.

Major Customers. During fiscal 2003, 2002 and 2001, gas sales to
FirstEnergy Solutions accounted for 14%, 13% and 14%, respectively, of our
total consolidated revenues.

Competition. The energy industry is intensely competitive in all of its
aspects. Competition arises not only from numerous domestic and foreign sources
of natural gas and oil but also from other industries that supply alternative
sources of energy. Competition is intense for the acquisition of leases
considered favorable for the development of natural gas and oil in commercial
quantities. Product availability and price are the principal means of
competition in selling oil and natural gas. Many of our competitors possess
greater financial and other resources than ours which may enable them to
identify and acquire desirable properties and market their natural gas and oil
production more effectively than we do. While it is impossible for us to
accurately determine our comparative industry position, we do not consider our
operations to be a significant factor in the industry. Moreover, we also compete
with a number of other companies that offer interests in drilling investment
partnerships. As a result, competition for investment capital to fund drilling
investment partnerships is intense.

Markets. The availability of a ready market for natural gas and oil
produced by us, and the price obtained, depends upon numerous factors beyond our
control, including the extent of domestic production, import of foreign natural
gas and oil, political instability in oil and gas producing countries and
regions, market demand, the effect of federal regulation on the sale of natural
gas and oil in interstate commerce, other governmental regulation of the
production and transportation of natural gas and oil and the proximity,
availability and capacity of pipelines and other required facilities. During
fiscal 2003, 2002 and 2001, we experienced no problems in selling our natural
gas and oil, although prices have varied significantly during and after those
periods.

Regulation of Production. The production of natural gas and oil is
subject to regulation under a wide range of local, state and federal statutes,
rules, orders and regulations. Federal, state and local statutes and regulations
require permits for drilling operations, drilling bonds and reports concerning
operations. All of the states in which we own and operate properties have
regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum allowable rates of production from oil and natural gas wells, the
regulation of well spacing, and plugging and abandonment of wells. The effect of
these regulations is to limit the amount of natural gas and oil that we can
produce from our wells and to limit the number of wells or the locations at
which we can drill, although we can apply for exceptions to such regulations or
to have reductions in well spacing. Moreover, each state generally imposes a
production or severance tax with respect to the production and sale of oil,
natural gas and natural gas liquids within its jurisdiction.

The failure to comply with these rules and regulations can result in
substantial penalties. Our competitors in the oil and natural gas industry are
subject to the same regulatory requirements and restrictions that affect our
operations.

Regulation of Transportation and Sale of Natural Gas. While natural gas
pipelines generally are subject to regulation by the Federal Energy Regulatory
Commission or FERC under the Natural Gas Act of 1938, because Atlas Pipeline
Partners' individual gathering systems perform primarily a gathering function,
as opposed to the transportation of natural gas in interstate commerce, Atlas
Pipeline Partners believes that it is not subject to regulation under the
Natural Gas Act. However, Atlas Pipeline Partners delivers a significant portion
of the natural gas it transports to interstate pipelines subject to FERC
regulation. In the past, the federal government has regulated the prices at
which natural gas could be sold. While sales by producers of natural gas can
currently be made at uncontrolled market prices, Congress could reenact price
controls in the future. Deregulation of wellhead natural gas sales began with
the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the
Natural Gas Wellhead Decontrol Act. The Decontrol Act removed all Natural Gas
Act and Natural Gas Policy Act price and non-price controls affecting wellhead
sales of natural gas effective January 1, 1993.

Since 1985, the FERC has endeavored to make natural gas
transportation more accessible to natural gas buyers and sellers on an open and
non-discriminatory basis. The FERC has stated that open access policies are
necessary to improve the competitive structure of the interstate natural gas
pipeline industry and to create a regulatory framework that will put natural gas
sellers into more direct contractual relations with natural gas buyers by, among
other things, unbundling the sale of natural gas from the sale of transportation
and storage services. Beginning in 1992, the FERC issued Order No. 636 and a
series of related orders to implement its open access policies. As a result of
the Order No. 636 program, the marketing and pricing of natural gas have been
significantly altered. The interstate pipelines' traditional role as wholesalers
of natural gas has been eliminated and replaced by a structure under which
pipelines provide transportation and storage service on an open access basis to
others who buy and sell natural gas. Although the FERC's orders do not directly
regulate natural gas producers, they are intended to foster increased
competition within all phases of the natural gas industry.

In 2000, the FERC issued Order No. 637 and subsequent orders, which
imposed a number of additional reforms designed to enhance competition in
natural gas markets. Among other things, Order No. 637 revised the FERC's
pricing policy by waiving price ceilings for short-term released capacity for a
two-year experimental period, and effected changes in FERC regulations relating
to scheduling procedures, capacity segmentation, penalties, rights of first
refusal and information reporting. Most pipelines' tariff filings to implement
the requirements of Order No. 637 have been accepted by the FERC and placed into
effect. While most major aspects of Order No. 637 have been upheld on judicial
review, certain issues such as capacity segmentation and right of first refusal
are pending further consideration by the FERC. We cannot predict what action
FERC will take on these matters in the future, or whether the FERC's actions
will survive further judicial review.

Intrastate natural gas transportation is subject to regulation by state
regulatory agencies. The basis for intrastate regulation of natural gas
transportation and the degree of regulatory oversight and scrutiny given to
intrastate natural gas pipeline rates and services varies from state to state.
Insofar as such regulation within a particular state will generally affect all
intrastate natural gas shippers within the state on a comparable basis, we
believe that the regulation of similarly situated intrastate natural gas
transportation in any states in which we operate and ship natural gas on an
intrastate basis will not affect our operations in any way that is of material
difference from those of our competitors.

Environmental and Safety Regulation. Under the Comprehensive
Environmental Response, Compensation and Liability Act, the Toxic Substances
Control Act, the Resource Conservation and Recovery Act, the Oil Pollution Act
of 1990, the Clean Air Act, and other federal and state laws relating to the
environment, owners and operators of wells producing natural gas or oil, and
pipelines, can be liable for fines, penalties and clean-up costs for pollution
caused by the wells or the pipelines. Moreover, the owners' or operators'
liability can extend to pollution costs from situations that occurred prior to
their acquisition of the assets. Natural gas pipelines are also subject to
safety regulation under the Natural Gas Pipeline Safety Act of 1968 and the
Pipeline Safety Act of 1992 which, among other things, dictate the type of
pipeline, quality of pipeline, depth, and methods of welding and other
construction-related standards. State public utility regulators in New York,
Ohio and Pennsylvania have either adopted federal standards or promulgated their
own safety requirements consistent with the federal regulations.

We do not anticipate that we will be required in the near future to
expend amounts that are material in relation to our revenues by reason of
environmental laws and regulations, but since as these laws and regulations
change frequently, we cannot predict the ultimate cost of compliance. We cannot
assure you that more stringent laws and regulations protecting the environment
will not be adopted or that we will not otherwise incur material expenses in
connection with environmental laws and regulations in the future.

Real Estate Finance

General. From fiscal 1991 through fiscal 1999, we sought to purchase
commercial real estate loans at discounts to their outstanding loan balances and
the appraised value of their underlying properties. In 1999, we shifted our
focus to managing our existing loan portfolio and, beginning in 2002, have
sought to expand our real estate operations through the sponsorship and
management of real estate investment partnerships. While we may sell, purchase
or originate portfolio loans or real property investments in the future as part
of our management process or as opportunities arise, during fiscal 2003 we
reduced the number of loans in our portfolio through the repayment of two loans,
the restructuring of one loan and the foreclosure of four loans. We have
retained interests in the properties underlying the restructured and foreclosed
loans. In fiscal 2002, we sponsored one real estate investment program, SR Real
Estate Investors, L.P., which completed a $20.0 million private equity offering
in fiscal 2003. This partnership is currently in the acquisition stage, which it
expects to complete in December 2003. At the conclusion of the acquisition
stage, we expect that the partnership will own approximately $87.8 million (net
book value) of multi-family residential properties. In fiscal 2003, we sponsored
a second program, S.R. Real Estate Investors II, L.P. which commenced operations
subsequent to fiscal year end and continues in its offering stage.

Real Estate Loan Portfolio. The following table sets forth information
concerning our portfolio loans at September 30, 2003. We include in this table
loans that we account for under FIN 46, presented in accordance with the legal
relationship of creditor/debtor between us and the borrowers.

Loan Status - Portfolio Loans. The following table sets forth
information about our portfolio loans, classified as portfolio loans on our
consolidated balance sheet, grouped by the type of property underlying the
loans, as of September 30, 2003 (in thousands):

Fiscal Appraised
Year Outstanding Value of
Loan Type of Loan Loan Property Cost of Third Party Net
Number Property Location Acquired Receivable(1) Loan(2) Investment(3) Liens(4) Investment(5)
- ------ -------- -------- -------- ------------- -------- ------------- ----------- -------------

020 (15) Office New Jersey 1996 $ 8,822 $ 4,700 $ 3,300 $ 2,258 $ 768

035 (09)(10) Office Pennsylvania 1997 2,799 2,900 1,846 1,664 96

53 (13) Office Washington, 1999 136,918 94,700 71,830 63,354 6,830
DC -------- -------- -------- -------- -------

Office Total $148,539 $102,300 $ 76,976 $ 67,276 $ 7,694
-------- -------- -------- -------- -------

Multi-
022 family Pennsylvania 1996 $ 6,326 $ 5,200 $ 2,472 $ 3,310 $ (963)
Multi-
024 family Pennsylvania 1996 3,196 4,300 2,743 2,342 424
Multi-
041 Family Connecticut 1998 20,974 22,600 14,737 13,312 637
-------- ------- -------- -------- -------
Multifamily Total $ 30,496 $ 32,100 $ 19,952 $ 18,964 $ 98
-------- -------- -------- -------- -------

013 (09)(14) Single User/
Commercial California 1994 $ 2,492 $ 2,700 $ 1,705 $ 2,273 $ (543)
Single User/
018 Retail California 1996 3,403 6,800 2,678 1,969 709
-------- ------- -------- -------- -------
Commercial Total $ 5,895 $ 9,500 $ 4,383 $ 4,242 $ 166
-------- -------- -------- -------- -------

Condo/ Pennsylvania
Multifamily 2001 $ 596 $ - $ 596 $ - $ 596
Office Pennsylvania 2003 1,350 - 1,350 - 1,350
-------- -------- -------- -------- -------
Other Total $ 1,946 $ - $ 1,946 $ - $ 1,946
-------- -------- -------- -------- -------

Balance as of September 30, 2003 $186,876 $143,900 $103,257 $ 90,482 $ 9,904
======== ======== ======== ======== =======

[RESTUBBED TABLE]

Company's Net
Fiscal Interest in
Year Carried Cost Outstanding
Loan Type of Loan of Loan
Number Property Location Acquired Investment(6) Receivables(7)
- ------ -------- -------- -------- ------------ --------------

020 (15) Office New Jersey 1996 $ 2,322 $ 6,564

035 (09)(10) Office Pennsylvania 1997 961 1,135

53 (13) Office Washington, 1999 24,331 73,564
DC ------- --------

Office Total $27,614 $ 81,263
------- --------

Multi-
022 family Pennsylvania 1996 $ 981 $ 3,016
Multi-
024 family Pennsylvania 1996 764 854
Multi-
041 Family Connecticut 1998 7,757 7,662
------- --------
Multifamily Total $ 9,502 $ 11,532
------- --------

013 (09)(14) Single User/
Commercial California 1994 $ 122 $ 219
Single User/
018 Retail California 1996 1,221 1,434
------- --------
Commercial Total $ 1,343 $ 1,653
------- --------

Condo/ Pennsylvania
Multifamily 2001 $ 596 $ 596
Office Pennsylvania 2003 1,361 1,350
------- --------
Other Total $ 1,957 $ 1,946
------- --------

Balance as of September 30, 2003 $40,416 $ 96,394
======= ========

Loan status - Loans held as FIN 46 Entities' Assets. The following
table sets forth information about our portfolio loans, classified as FIN 46
entities assets on our consolidated balance sheet, grouped by the type of
property underlying the loans, as of September 30, 2003 (in thousands).

005 (16) Office Pennsylvania 1993 $ 11,788 $ 1,700 $ 1,747 $ - $ 1,747
014 (8) Office Washington, DC 1995 22,975 14,300 12,696 5,895 6,209
026 (9) Office Pennsylvania 1997 11,380 4,700 2,953 1,961 721
029 Office Pennsylvania 1997 10,144 4,075 3,186 - 3,186
044 (11) Office Washington, DC 1998 118,446 108,525 85,120 65,661 21,472
049 (12) Office Maryland 1998 111,209 99,000 92,328 57,552 32,329
-------- -------- -------- -------- --------
Office Total $285,942 $232,300 $198,030 $131,069 $ 65,664
-------- -------- -------- -------- --------

Condo/ North Carolina 1995 &
015 Multifamily 1997 $ 6,403 $ 5,917 $ 2,337 $ 2,808 $ (663)
Condo/ North Carolina 1997 640 498 452 - 452
028 Multifamily
031 Multifamily Connecticut 1997 12,089 12,000 4,788 8,833 (4,587)
032 Multifamily New Jersey 1997 14,684 14,300 7,404 - 7,404
050 Multifamily Illinois 1998 57,124 24,000 20,014 14,845 4,664
-------- -------- -------- -------- --------
Multifamily Total $ 90,940 $ 56,715 $ 34,995 $ 26,486 $ 7,270
-------- -------- -------- -------- --------

Single
007 (9)(17) User/
Retail Minnesota 1993 $ 6,045 $ 2,300 $ 1,490 $ 1,706 $ (609)
Single
User/
017 (9) Retail West Virginia 1996 1,705 1,600 904 932 (95)
-------- -------- -------- -------- ---------
Commercial Total $ 7,750 $ 3,900 $ 2,394 $ 2,638 $ (704)
-------- -------- -------- -------- ---------

Hotel/
025 CommercialGeorgia $ 8,919 $ 10,173 $ 7,263 $ - $ 6,388
-------- -------- -------- -------- --------
Hotel Total $ 8,919 $ 10,173 $ 7,263 $ - $ 6,388
-------- -------- -------- -------- --------
Balance as of September 30, 2003 $393,551 $303,088 $242,682 $160,193 $ 78,618
======== ======== ======== ======== ========

[RESTUBBED TABLE]

005 (16) Office Pennsylvania 1993 $ 1,484 $ 11,788
014 (8) Office Washington, DC 1995 6,552 17,080
026 (9) Office Pennsylvania 1997 1,310 9,419
029 Office Pennsylvania 1997 3,002 10,144
044 (11) Office Washington, DC 1998 36,650 52,785
049 (12) Office Maryland 1998 35,841 53,657
-------- --------
Office Total $ 84,839 $154,873
-------- --------

Condo/ North Carolina 1995 &
015 Multifamily 1997 $ 1,319 $ 3,595
Condo/ North Carolina 1997 233 640
028 Multifamily
031 Multifamily Connecticut 1997 172 3,256
032 Multifamily New Jersey 1997 11,249 14,684
050 Multifamily Illinois 1998 6,969 42,279
-------- --------
Multifamily Total $ 19,942 $ 64,454
-------- --------

Single
007 (9)(17) User/
Retail Minnesota 1993 $ 394 $ 4,339
Single
User/
017 (9) Retail West Virginia 1996 631 773
-------- --------
Commercial Total $ 1,025 $ 5,112
-------- --------

Hotel/
025 CommercialGeorgia $ 7,796 $ 8,919
-------- --------
Hotel Total $ 7,796 $ 8,919
-------- --------
Balance as of September 30, 2003 $113,602 $233,358
======== ========

The following table reconciles the carried cost of investment
for our portfolio loans classified as FIN 46 assets to our consolidated balance
at September 30, 2003 (in thousands).

FIN 46 entities' assets and other assets held for sale.................................. $ 222,677
FIN 46 entities' assets and other liabilities associated with assets held for sale...... (141,473)
Real estate owned classified as held for sale net of related debt....................... (665)
FIN 46 entities' assets................................................................. 78,247
FIN 46 entities' liabilities............................................................ (45,184)
------------
Balance at September 30, 2003........................................................... $ 113,602
===========

- ------------
(1) Consists of the original stated or face value of the obligation plus
interest and the amount of the senior lien interest at September 30,
2003.
(2) We generally obtain appraisals on each of the properties underlying our
portfolio loans at least once every three years.
(3) Consists of the original cost of our investment, including the amount of
any senior lien obligation to which the property remains subject, plus
subsequent advances, but excludes the proceeds to us from the sale of
senior lien interests or borrower refinancings.

(4) Represents the amount of the senior lien interests at September 30, 2003.
(5) Represents the unrecovered costs of our investment, calculated as the
cash investment made in acquiring the loan plus subsequent advances, less
cash received from the sale of a senior lien interest in or borrower
refinancing of the loan. Negative amounts represent our receipt of
proceeds from the sale of senior lien interests or borrower refinancings
in excess of our investment.
(6) Represents the book cost of our investment, including subsequent
advances, after accretion of discount and allocation of gains from the
sale of a senior lien interest in, or borrower refinancing of, the loan,
but excludes an allowance for possible losses of $1.4 million. For loans
held as FIN 46 entities assets, the carried cost represents the book cost
of our investment adjusted to reflect the requirements of FIN 46.
(7) Consists of the amount set forth in the column "Outstanding Loan
Receivable" less senior lien interests at September 30, 2003.
(8) The borrower, Washington Properties Limited Partnership, is a limited
partnership in which Edward E. Cohen, our Chairman, Chief Executive
Officer and President, Daniel G. Cohen, our former President, Chief
Operating Officer and director, and Adam Kauffman, the President of
Brandywine Construction & Management are equal limited partners.
(9) With respect to loans 7 and 17, A. Kaufman is the general partner of the
borrower and, with respect to loan 29, he is the President of the sole
general partner of the borrower. With respect to loans 26 and 35, Mr.
Kauffman is the sole shareholder of the general partner of the borrower.
(10) The borrower, New 1521 Associates, is a limited partnership formed in
1991. The general partner, New 1521 G.P., Inc., is a corporation of which
A. Kauffman is the sole shareholder. E. Cohen, and his wife, Betsy Z.
Cohen, beneficially own a 49% limited partnership interest in the
partnership and A. Kauffman owns a 24.75% limited partnership interest.
(11) The borrower, Evening Star Associates, is a limited partnership in which
one of our subsidiaries, Resource Properties, Inc., is the sole
shareholder of ES GP, Inc., the sole general partner of the borrower. E.
Cohen, B. Cohen, D. Cohen, and S. Schaeffer are limited partners of
Evening Star Associates.
(12) The borrower, Commerce Place Associates, LLC, is a limited liability
company whose manager is a corporation of which S. Schaeffer, is the sole
shareholder, officer and director. Messrs. E. Cohen, D. Cohen, Schaeffer
and Kauffman are equal limited partners of an entity, Brandywine Equity
Investors, L.P., that owns approximately 30% of the borrower.
(13) Our subsidiary, Resource Press Building Manager, Inc., is the manager of
the borrower, Resource/Press Building Realty, LLC.
(14) E. Cohen and B. Cohen beneficially own a 40% limited partnership interest
in the borrower, Pasadena Industrial Associates. A. Kauffman is the
general partner of the borrower.
(15) The property is owned by EJGB, LLC, a limited liability company in which
D. Cohen owns a 94% interest.
(16) The borrower, Granite GEC (Pittsburgh), L.L.C., is a limited liability
company. D. Cohen owns 79% of Odessa Real Estate Management, Inc., the
assistant managing member of the borrower.
(17) The borrower, St. Cloud Associates, is a limited partnership of which
A. Kauffman is the sole general partner.

We seek to reduce the amount of our capital invested in portfolio
loans, and to enhance our returns, through borrower refinancing of the
properties underlying our loans. At September 30, 2003, senior lien holders on
these properties held outstanding obligations of $90.5 million. Pursuant to
agreements with most borrowers, we generally retain the excess of operating cash
flow after required debt service on senior lien obligations as debt service on
the outstanding balance of our loans.

After a refinancing of a senior lien interest, our retained interest
will usually be secured by a subordinate lien on the property. In some
situations, however, our retained interest may not be formally secured by a
mortgage because of conditions imposed by the senior lender. In these
situations, we may be protected by a judgment lien, an unrecorded deed-in-lieu
of foreclosure, the borrower's covenant not to further encumber the property
without our consent, a pledge of the borrower's equity or similar devices. As of
September 30, 2003, we have six retained interests aggregating $55.7 million and
constituting 36%, by carried cost of investment, of our loan portfolio and FIN
46 investments that are not secured by a lien on the underlying property. As of
September 30, 2003, senior lien interests with an aggregate balance of $4.9
million relating to three portfolio loans obligate us, in the event of a default
on a loan, to replace the loan with a performing loan.

Because our loans typically were not performing in accordance with the
original terms when we acquired them, they generally are subject to forbearance
agreements that defer foreclosure or other action so long as the borrower meets
the terms of the forbearance agreement. These terms are generally designed to
give us control over the operations and cash flow of the underlying properties,
subject to the rights of senior lien holders. We may permit a borrower to obtain
management control of a property's cash flow where we believe that operating
problems have been substantially resolved.

Our forbearance agreements require borrowers to retain a property
management firm acceptable to us. As a result, Brandywine Construction &
Management, Inc., a property manager affiliated with us, has assumed
responsibility for supervisory and, in many cases, day-to-day management of the
underlying properties with respect to substantially our entire loan portfolio as
of September 30, 2003. In seven instances, the president of Brandywine
Construction & Management, or an entity affiliated with him, has also acted as
the general partner, president or trustee of the borrower.

The minimum payments required under a forbearance agreement are
normally materially less than the debt service payments called for by the
original terms of the loan. The difference between the minimum required payments
under the forbearance agreement and the payments called for by the original loan
terms continues to accrue. However, except for amounts we recognize as accretion
of discount, we do not recognize the accrued but unpaid amounts as revenue until
actually paid. For a discussion of how we account for accretion of discount, you
should read "Real Estate Finance-Accounting for Discounted Loans."

At the end of a forbearance agreement, the borrower must pay the loan
in full. The borrower's ability to do so, however, will depend upon a number of
factors, including prevailing conditions of the underlying property, the state
of real estate and financial markets generally and as they pertain to the
particular property, and general economic conditions. If the borrower does not
or cannot repay the loan, we anticipate it will seek to sell the property
underlying the loan or otherwise liquidate the loan. If the borrower is
unsuccessful, we may foreclose on the underlying property. Alternatively, where
we already control all of the cash flow and other economic benefits from the
property, or where we believe that the cost of foreclosure is more than any
benefit we could obtain from foreclosure, we may continue our forbearance.

Investments in Real Estate. As part of the process of resolving our
loans, we may foreclose on a property underlying a loan or accept a deed-in-lieu
of foreclosure. In fiscal 2003, we foreclosed or accepted deeds-in-lieu of
foreclosure on four properties. Also, when we restructure a loan, we typically
retain an interest in the underlying property or in an entity owning the
property. We had one such restructuring in fiscal 2003, while in fiscal 2002 we
had one such restructuring. Moreover, in fiscal 2002 we invested in three
limited partnerships which acquired properties adjacent to a property in which
we had received a 50% interest in satisfaction of another portfolio loan in June
1999.

Accounting for Discounted Loans. We accrete the difference between our
cost basis in a portfolio loan and the sum of projected cash flows from the loan
into interest income over the estimated life of the loan using the interest
method, which results in a level rate of interest over the life of the loan. We
review projected cash flows, which include amounts realizable from the
disposition of the underlying property, on a quarterly basis. Changes to
projected cash flows reduce or increase the amounts accreted into interest
income over the remaining life of the loan.

We record our investments in real estate loans at cost, which is
discounted significantly from the stated principal amount plus accrued interest
and penalties on the loans. We refer to the stated principal, accrued interest
and penalties as the face value of the loan. The discount from face value, as
adjusted to give effect to refinancings totaled $56.0 million, $165.2 million
and $150.7 million at September 30, 2003, 2002 and 2001, respectively. We review
the carrying value of each of our loans quarterly to determine whether it is
greater than the sum of the future projected cash flows. Because of our
knowledge of the underlying properties, our monitoring of and influence over
their respective operating budgets and, for most properties, management of the
property by our affiliate, Brandywine Construction and Management, we believe
that we can reasonably estimate the amount and timing of our probable
collections from the underlying properties. For a discussion of our involvement
with the properties underlying our loans, see "Real Estate Finance-General." If
we determine that the carrying value is greater, we provide an appropriate
allowance through a charge to operations. In establishing our allowance for
possible losses, we also consider the historic performance of our loan
portfolio, characteristics of the loans and their underlying properties,
industry statistics and experience regarding losses in similar loans, payment
history on specific loans as well as general economic conditions in the United
States, in the borrower's geographic area or in the borrower's or its tenants'
specific industries.

Accounting for FIN 46 Assets. Subsequent to the adoption of FIN 46 in
July 2003, we record the assets, liabilities and operations of certain entities
in which we hold loans in our consolidated financial statements. We have
classified certain of these entities' assets as held for sale and accordingly
show their operations as discontinued in our consolidated financial statements.

Allowance for Possible Losses. For the year ended September 30, 2003,
we recorded a provision for possible losses of $1.8 million. Our allowance for
possible losses was $1.4 million at September 30, 2003 after write-downs of $3.9
million on three loans.

In determining our allowance for possible losses related to our real
estate loans, we consider general and local economic conditions, neighborhood
values, competitive overbuilding, casualty losses and other factors which may
affect the value of loans. The value of our loans may also be affected by
factors such as the cost of compliance with regulations and liability under
applicable environment laws, changes in interest rates and the availability of
financing. Income from a property will be reduced if a significant number of
tenants are unable to pay rent or if available space cannot be rented on
favorable terms. In addition, we continuously monitor collections and payments
from our borrowers and maintain an allowance for estimated losses based upon our
historical experience and our knowledge of specific borrower collection issues
identified. We reduce our investment in real estate loans by an allowance for
amounts that may become unrealizable in the future. Such allowance can be either
specific to a particular loan or venture or general to all loans.

We also follow the cost recovery method for certain loans due to
unanticipated events such as the loss of a major tenant of one underlying
property, the declaration of bankruptcy and voiding of the lease by a sole
tenant of another property and, for a hotel property underlying one loan, the
severe effect of the post-9/11 travel slump.

Financial Services

Our financial services operations currently focus on managing entities
that invest in trust preferred securities of small to mid-size regional banks
and bank holding companies and debt securities collateralized by these trust
preferred securities.

Beginning in fiscal 2002, through December 2003, we have co-sponsored a
series of five investments involving issuers of collateralized debt obligations,
or CDOs. The collateralized debt obligations of each CDO issuer are supported by
a pool of trust preferred securities issued by trusts affiliated with, and whose
preferred securities are guaranteed by small to mid-size regional banks and bank
holding companies. We own a 50% interest in the entities that act as the general
partners of the limited partnerships that own the equity interest in the CDO
issuers. We also invest in the partnerships, for which we receive partnership
interests. The issuers are Trapeza CDO I, LLC through Trapeza CDO V, Ltd. The
general partners are Trapeza Funding, LLC through Trapeza Funding V, LLC, and
the partnerships are Trapeza Partners L.P. through Trapeza Partners V L.P. We
also own a 50% interest in Trapeza Capital Management, LLC which acts as
collateral manager of the trust preferred securities pools. Through Trapeza
Capital Management the Trapeza Funding entities and the Trapeza partnerships, we
receive collateral management fees from the CDO issuers, as well as general
partner and limited partner distributions and partnership administration fees.
We also own a 50% interest in 1845 Warehouse, LLC, an entity created to support
a warehouse line of credit to be used to provide financing to CDO issuers we
sponsor in the future. We invested $2.5 million in 1845 Warehouse in November
2003 along with a like amount by the other owner of 1845 Warehouse. 1845
Warehouse has obtained a warehouse line of credit for its own account from an
unaffiliated third party. We expect that 1845 Warehouse will receive
distributions from future CDO closings equal to a portion of the positive spread
between its warehouse financing costs and the interest received on the trust
preferred securities it finances. The third party lender will receive the
balance of such positive spread.

We sponsored Trapeza CDO I in fiscal 2002, which, in November 2002
acquired $330.0 million of trust preferred securities. Trapeza Partners I, the
equity owner of Trapeza CDO I, raised $27.4 million for its equity investment,
including $2.8 million from us and a like amount from our co-sponsor. We also
provided a $5.0 million bridge loan, which was repaid in fiscal 2003, to
facilitate its purchase of trust preferred securities.

We sponsored Trapeza CDO II, Trapeza CDO III and Trapeza CDO IV in
fiscal 2003. Trapeza CDO IV was in the offering stage at September 30, 2003, and
thereafter closed in October 2003. These three Trapeza CDO issuers acquired $1.0
billion of trust preferred securities. The related partnerships invested $58.8
million in the Trapeza CDO issuers, including $2.4 million from us and a like
amount from our co-sponsor. Subsequent to September 30, 2003, we sponsored
Trapeza CDO V, Ltd., which we anticipate closed in December 2003 and acquired an
additional $300.0 million of trust preferred securities.

Equipment Leasing

We operate our equipment leasing business through LEAF Financial
Corporation, a wholly-owned subsidiary. A subsidiary of LEAF Financial acts as
the general partner of a public equipment leasing partnership, Lease Equity
Appreciation Fund I. The partnership began operations in March 2003 and, as of
September 30, 2003, had $18.5 million (original equipment cost) of equipment
under lease. As of September 30, 2003, LEAF Financial had invested $401,000 in
the partnership. The partnership continues in its offering stage.

In April 2003, LEAF Financial entered into a multi-year agreement to
originate and service equipment leases on behalf of Merrill Lynch Equipment
Finance LLC. Under this financing and service arrangement, LEAF Funding, Inc., a
subsidiary of LEAF Financial, will originate and, through a subsidiary, sell
equipment leases to Merrill Lynch Equipment Finance. LEAF Funding will receive
cash consideration for these leases equal to the present value of the remaining
scheduled payments under each lease plus the estimated residual value of the
leased equipment at the end of the lease. An affiliate of Merrill Lynch
Equipment Finance will finance its purchase of the equipment and leases to an
aggregate maximum amount of $300.0 million. Pursuant to a servicing agreement,
LEAF Financial will manage, administer and service the leases, for which it will
receive servicing and asset management fees. These agreements terminate on April
8, 2005, unless otherwise extended.

At the time we acquired LEAF Financial in 1995, it acted as the general
partner of a series of public equipment leasing partnerships. These partnerships
began their liquidation periods at various times commencing in December 1995. We
anticipate that the last four of these partnerships will complete their
liquidation procedures in December 2003.

Credit Facilities and Senior Notes

Credit Facilities. In July 2002, our principal energy subsidiary, Atlas
America, entered into a $75.0 million credit facility administered by Wachovia
Bank, National Association. The revolving credit facility is guaranteed by Atlas
America's subsidiaries and by us. Credit availability, which is principally
based on the value of Atlas America's assets, was $54.2 million at September 30,
2003. Up to $10.0 million of the borrowings under the facility may be in the
form of standby letters of credit. Borrowings under the facility are secured by
the assets of Atlas America and its subsidiaries, including the stock of Atlas
America's subsidiaries and our interests in Atlas Pipeline Partners and its
general partner. At September 30, 2003, $31.0 million was outstanding under this
facility

Loans under the facility bear interest at one of the following two
rates, at the borrower's election:

o the base rate plus the applicable margin; or

o the adjusted LIBOR plus the applicable margin.

The base rate for any day equals the higher of the federal funds rate
plus 1/2 of 1% or the Wachovia Bank prime rate. Adjusted LIBOR is LIBOR divided
by 1.00 minus the percentage prescribed by the Federal Reserve Board for
determining the reserve requirement for euro currency funding. The applicable
margin is as follows:

o where utilization of the borrowing base is equal to or less than 50%,
the applicable margin is 0.25% for base rate loans and 1.75% for
LIBOR loans;

o where utilization of the borrowing base is greater than 50%, but
equal to or less than 75%, the applicable margin is 0.50% for base
rate loans and 2.00% for LIBOR loans; and

o where utilization of the borrowing base is greater than 75%, the
applicable margin is 0.75% for base rate loans and 2.25% for LIBOR
loans.

At September 30, 2003, borrowings under the Wachovia credit facility
bore interest at rates ranging from 2.88% to 2.90%.

The Wachovia credit facility requires Atlas America to maintain
specified net worth and specified ratios of current assets to current
liabilities and debt to EBITDA, and requires us to maintain a specified interest
coverage ratio. In addition, the facility limits sales, leases or transfers of
assets and the incurrence of additional indebtedness. The facility limits the
dividends payable by us to 50% of our cumulative net income from April 1, 2002
to the date of determination plus $5.0 million. In addition, Atlas America is
permitted to repay intercompany debt to us only up to the amount of our federal
income tax liability attributable to Atlas America and accrued interest on the
our senior notes. The facility terminates in July 2005, when all outstanding
borrowings must be repaid. At September 30, 2003, $31.0 million was outstanding
under this facility.

Through our real estate subsidiaries, we have an $18.0 million line of
credit with Sovereign Bank. The facility bears interest at the prime rate
reported in The Wall Street Journal and expires in July 2005. Advances under
this facility must be used to acquire real property, loans on real property or
to reduce indebtedness on property loans. The facility is secured by the
interest of our subsidiaries in assets they acquire using advances under the
line of credit. Credit availability is based on the value of the assets pledged
as security and was $18.0 million as of September 30, 2003, all of which had
been drawn at that date. The facility imposes limitations on the incurrence of
future indebtedness by our subsidiaries whose assets were pledged, and on sales,
transfers or leases of their assets, and requires the subsidiaries to maintain
both a specified level of equity and a specified debt service coverage ratio.

We have a second line of credit with Sovereign Bank for $5.0 million
that is similar to the $18.0 million line of credit. This facility bears
interest at the same rate as the $18.0 million line of credit and also expires
in July 2005. Advances under this facility must be used to acquire real
property, loans on real property or to reduce indebtedness on property or loans.
The facility is secured by a pledge of approximately 425,000 of our RAIT common
shares and by a guaranty from the subsidiaries holding the assets securing the
$18.0 million line of credit. Credit availability is based on the value of the
pledged RAIT shares and was $5.0 million as of September 30, 2003, all of which
had been drawn at that date. The facility restricts us from making loans to our
affiliates other than:

o existing loans,

o loans in connection with lease transactions in an aggregate not to
exceed $50,000 in any fiscal year,

o loans to RAIT made in the ordinary course of business, and

o loans to our subsidiaries.

We have a line of credit with Commerce Bank for $5.0 million, all of
which had been drawn as of September 30, 2003. The facility is secured by our
pledge of 440,000 of our RAIT common shares. Credit availability is 50% of the
value of those shares, and was $5.0 million at September 30, 2003. Loans bear
interest, at our election, at either the prime rate reported in The Wall Street
Journal or specified LIBOR, plus 250 basis points, in either case with a minimum
rate of 5.5% and a maximum rate of 9.0%. The facility terminates in May 2005,
subject to extension. The facility requires us to maintain a specified net worth
and ratio of liabilities to tangible net worth, and prohibits our transfer of
the collateral.

We and certain of our real estate subsidiaries are the obligors under a
$6.8 million term note to Hudson United Bank. At September 30, 2003, $6.4
million was outstanding on this note which matures in October 2004. The note
bears interest at the prime rate reported in The Wall Street Journal, minus one
percent, and is secured by certain portfolio loans.

LEAF Financial and Lease Equity Appreciation Fund have entered into
revolving credit facilities with National City Bank and Commerce Bank that have
an aggregate borrowing limit of $20.0 million. Each facility bears interest at
the LIBOR plus 300 basis points at the time of borrowing. Borrowings under the
facilities are secured by an assignment of the leases being financed and the
underlying equipment being leased. Repayment of both facilities has been
guaranteed by us. The facility with National City Bank expires on December 31,
2003. At September 30, 2003, $2.5 million was outstanding on this facility with
current interest rates ranging from 4.10% to 4.18% per year. The facility with
Commerce Bank expires on May 27, 2004. At September 30, 2003, $4.7 million was
outstanding on this facility with a current interest rate of 4.10% per year. We
are a guarantor under both facilities.

Atlas Pipeline Partners has a $20.0 million revolving credit facility
administered by Wachovia Bank. Up to $3.0 million of the facility may be used
for standby letters of credit. Borrowings under the facility are secured by a
lien on all the property of Atlas Pipeline Partners' assets, including its
subsidiaries. The facility has a term ending in December 2005 and bears
interest, at Atlas Pipeline Partners' election, at the base rate plus the
applicable margin or the euro rate plus the applicable margin.

As used in the facility agreement, the base rate is the higher of:

o Wachovia Bank's prime rate or

o the sum of the federal funds rate plus 50 basis points.

The euro rate is the average of specified LIBORs divided by 1.00 minus
the percentage prescribed by the Federal Reserve Board for determining the
reserve requirement for euro currency funding. The applicable margin varies with
Atlas Pipeline Partners' leverage ratio from between 150 to 250 basis points,
for the euro rate option, or 0 to 50 basis points, for the base rate option.
Draws under any letter of credit bear interest as specified under the first
bullet point above. The credit facility requires Atlas Pipeline Partners to
maintain a specified net worth, ratio of debt to tangible assets and an interest
coverage ratio. In addition, the facility limits sales, leases or transfers of
assets, incurrence of other indebtedness and guarantees, and certain
investments. As of September 30, 2003, no amounts were outstanding under this
facility. Atlas Pipeline Partners expects that it will draw the full amount of
this facility as part of its financing of its acquisition of the Alaska Pipeline
Company.

As of September 30, 2003, we also had a $5.8 million term loan with The
Marshall Group. This loan was repaid in October 2003.

Senior Notes. As of September 30, 2003, we had outstanding $54.0
million of our 12% senior notes due 2004. Subsequent to our fiscal year end, we
repurchased $1.0 million of senior notes. The senior notes are payable interest
only until their maturity on August 1, 2004, but are subject to earlier
redemption at our option. We have called $40.0 million of senior notes for
redemption on December 22, 2003 (including $26.9 million repurchased in November
2003) and the balance of $13.0 million for redemption on January 20, 2004. See
"Business - General."

Employees

As of September 30, 2003, we employed 278 persons: 208 in energy, 41 in
equipment leasing, eight in real estate finance, three in financial services and
18 corporate employees.

Risk Factors

Statements made by us in written or oral form to various persons,
including statements made in filings with the SEC that are not strictly
historical facts are "forward-looking" statements that are based on current
expectations about our business and assumptions made by management. These
statements are subject to risks and uncertainties that exist in our operations
and business environment that could result in actual outcomes and results that
are materially different than predicted. The following includes some, but not
all, of those factors or uncertainties:

General

Interest rate increases will increase our interest costs under our
eight credit facilities. See Item 7A, "Quantitative and Qualitative Disclosures
about Market Risk." This could have material adverse effects, including
reduction of net revenues for our energy, real estate finance and equipment
leasing operations.

Risks Relating to Our Energy Business

Our future financial condition, results of operations and the value of
our natural gas and oil properties will depend upon market prices for natural
gas and oil. Natural gas and oil prices historically have been volatile and will
likely continue to be volatile in the future. Prices for natural gas and oil are
affected by many factors, over which we have no control, including:

o political instability or armed conflict in oil producing regions or
other market uncertainties;

o worldwide and domestic supplies of oil and gas;

o weather conditions;

o the level of consumer demand;

o the price and availability of alternative fuels;

o the availability of pipeline capacity;

o the price and level of foreign imports;

o domestic and foreign governmental regulations and taxes;

o the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil prices and production
controls; and

o the overall economic environment.

These factors and the volatility of the energy markets make it
extremely difficult for us to predict future oil and gas price movements with
any certainty. Price fluctuations can materially adversely affect us because:

o price decreases will reduce our energy revenues;

o price decreases may make it more difficult to obtain financing for
our drilling and development operations through sponsored investment
partnerships, borrowings or otherwise;

o price decreases may make some reserves uneconomic to produce,
reducing our reserves and cash flow;

o price decreases may cause the lenders under our energy credit
facility to reduce our borrowing base because of lower revenues or
reserve values, reducing our liquidity and, possibly, requiring
mandatory loan repayment;

o price increases may make it more difficult, or more expensive, to
drill and complete wells if they lead to increased competition for
drilling rigs and related materials; and

o price increases may make it more difficult, or more expensive, to
execute our business strategy of acquiring additional natural gas
properties and energy companies.

Further, oil and gas prices do not necessarily move in tandem. Because
approximately 92% of our proved reserves are natural gas reserves, we are more
susceptible to movements in natural gas prices.

Well blowouts, cratering, explosions, uncontrollable flows of oil,
natural gas or well fluids, fires, formations with abnormal pressures, pipeline
ruptures or spills, pollution, releases of toxic gas and other environmental
hazards and risks are inherent operating hazards for us. The occurrence of any
of these hazards could result in substantial losses to us. In addition, we may
be liable for environmental damage caused by previous owners of properties
purchased or leased by us. As a result, we may incur substantial liabilities to
third parties or governmental entities. In accordance with customary industry
practices, we maintain insurance against some, but not all, of such risks and
losses. Pollution and environmental risks generally are not fully insurable. We
may elect to self-insure if we believe that insurance, although available, is
excessively costly relative to the risks presented. The occurrence of an event
that is not covered, or not fully covered, by insurance could reduce our
revenues and the value of our assets.

The amount of recoverable natural gas and oil reserves may vary
significantly from well to well. We may drill wells that, while productive, do
not produce sufficient net revenues to return a profit after drilling, operating
and other costs. The geologic data and technologies we use do not allow us to
know conclusively prior to drilling a well that natural gas or oil is present or
may be produced economically. The cost of drilling, completing and operating a
well is often uncertain, and cost factors can adversely affect the economics of
a project. Further, our drilling operations may be curtailed, delayed or
cancelled as a result of many factors, including:

o unexpected drilling conditions;

o title problems;

o pressure or irregularities in formations;

o equipment failures or accidents;

o adverse weather conditions;

o environmental or other regulatory concerns; and

o costs of, or shortages or delays in the availability of drilling rigs
and equipment.

We base our estimates of our proved natural gas and oil reserves and
future net revenues from those reserves upon analyses that rely upon various
assumptions, including those required by the SEC, as to natural gas and oil
prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. Any significant variance in these assumptions could
materially affect the estimated quantity of our reserves. As a result, our
estimates of our proved natural gas and oil reserves are inherently imprecise.
Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves may vary substantially from our estimates or
estimates contained in the reserve reports. Our properties also may be
susceptible to hydrocarbon drainage from production by other operators on
adjacent properties. In addition, our proved reserves may be subject to downward
or upward revision based upon production history, results of future exploration
and development, prevailing natural gas and oil prices, mechanical difficulties,
governmental regulation and other factors, many of which are beyond our control.

You should not assume that the PV-10 values referred to in this report
represent the current market value of our estimated natural gas and oil
reserves. In accordance with SEC requirements, the estimates are based on prices
and costs as of the date of the estimates. Moreover, the 10% discount factor,
which the SEC requires in calculating future net cash flows for reporting
purposes, is not necessarily the most appropriate discount factor to calculate
risk-based value. The effective interest rate at various times and the risks
associated with the oil and gas industry generally will affect the
appropriateness of the 10% discount factor.

Our proved reserves will decline as reserves are produced unless we
acquire additional properties containing proved reserves, successfully develop
new or existing properties or identify additional formations with primary or
secondary reserve opportunities on our properties. If we are not successful in
expanding our reserve base, our future natural gas and oil production and
drilling activities, the primary source of our energy revenues, will decrease.
Our ability to find and acquire additional reserves depends on our generating
sufficient cash flow from operations and other sources of capital, principally
our sponsored drilling partnerships, all of which are subject to risks discussed
elsewhere in this section.

The growth of our energy operations has resulted from both our
acquisition of energy companies and assets and from our ability to obtain
capital funds through our sponsored drilling partnerships. If we are unable to
identify acquisitions on acceptable terms, or if our ability to obtain capital
funds through sponsored partnerships is impaired, we may be unable to increase
or maintain our inventory of properties and reserve base, or may be forced to
curtail drilling, production or other activities. This would likely result in a
decline in our revenues from our energy operations.

Under current federal tax laws, there are tax benefits to investing in
drilling investment partnerships such as ours, including deductions for
intangible drilling costs and depletion deductions. Changes to federal tax laws
that reduce or eliminate these benefits may make investment in our drilling
partnerships less attractive and, thus, reduce our ability to obtaining funding
from this significant source of capital. Moreover, the Jobs and Growth Tax
Relief Reconciliation Act of 2003 has reduced the maximum federal income tax
rate on long-term capital gains and qualifying dividends to 15% through 2008.
This change may make investment in our drilling partnerships relatively less
attractive than investments in assets likely to yield capital gains or
qualifying dividends.

We operate in a highly competitive environment, competing with major
integrated and independent energy companies for desirable oil and gas
properties, as well as for the equipment, labor and materials required to
develop and operate such properties. Many of our competitors have financial and
technological resources substantially greater than ours. We may incur higher
costs or be unable to acquire and develop desirable properties at costs we
consider reasonable because of this competition.

Under our agreements with Atlas Pipeline Partners, we are required to
pay transportation fees for natural gas produced by our drilling partnerships
and certain unaffiliated producers. Many of our transportation arrangements with
our existing drilling partnerships and unaffiliated producers require them to
pay us lesser fees than those we pay to Atlas Pipeline Partners. For the years
ended September 30, 2003 and 2002, the fees we paid to Atlas Pipeline Partners,
net of reimbursements and distributions to us from our general and limited
partner interests in it, transportation revenues derived from our natural gas
transportation with partnerships we sponsor exceeded the amount we received from
producers by $4.5 million and $1.2 million, respectively.

Subsidiaries of ours currently serve as general partners of 84 energy
investment partnerships. We intend to develop further energy investment
partnerships for which we will act as general partner. As a general partner,
each subsidiary is contingently liable for the obligations of these partnerships
to the extent that these obligations cannot be repaid from program assets or
insurance proceeds.

Federal, state and local authorities extensively regulate our drilling
and production activities, including the drilling of wells, the spacing of
wells, the use of pooling of oil and gas properties, environmental matters,
safety standards, production limitations, plugging and abandonment, and
restoration. These laws are under constant review for amendment or expansion,
raising the possibility of changes that may affect, among other things, the
pricing or marketing of oil and gas production. If we do not comply with these
laws, we may incur substantial penalties. The overall regulatory burden on the
industry increases the cost of doing business and, in turn, decreases
profitability.

Our operations are subject to complex and constantly changing
environmental laws adopted by federal, state and local governmental authorities.
We could face significant liabilities to the government and third parties for
discharges of natural gas, oil or other pollutants into the air, soil or water,
and we could have to spend substantial amounts on investigation, litigation and
remediation. For a discussion of the environmental laws that affect our
operations, see "Business - Energy - Environmental and Safety Regulations."

Risks Relating to Our Real Estate Financial and
Financial Leasing Services Businesses

The primary or sole source of recovery for our real estate loans is
typically the underlying real property. Accordingly, the value of our loans
depends upon the value of that real property. Many of the properties underlying
our portfolio loans, while income producing, do not generate sufficient revenues
to pay the full amount of debt service required under the original loan terms or
have other problems. There may be a higher risk of default with these loans as
compared to conventional loans. Loan defaults will reduce our current return on
investment and may require us to become involved in expensive and time-consuming
bankruptcy, reorganization or foreclosure proceedings.

Our loans, include those treated in our consolidated financial
statements as FIN 46 assets and liabilities, typically provide payment
structures other than equal periodic payments that retire a loan over its
specified term, including structures that defer payment of some portion of
accruing interest, or defer repayment of principal, until loan maturity. Where a
borrower must pay a loan balance in a large lump sum payment, its ability to
satisfy this obligation may depend upon its ability to obtain suitable
refinancing or otherwise to raise a substantial cash amount, which we do not
control. In addition, lenders can lose their lien priority in many
jurisdictions, including those in which our existing loans are located, to
persons who supply labor or materials to a property. For these and other
reasons, the total amount which we may recover from one of our loans may be less
than the total amount of the loan or our cost of acquisition.

Declines in real property values generally and/or in those specific
markets where the properties underlying our portfolio loans are located could
affect the value of and default rates under those loans. Properties underlying
our loans may be affected by general and local economic conditions, neighborhood
values, competitive overbuilding, casualty losses and other factors beyond our
control. The value of real properties may also be affected by factors such as
the cost of compliance with, and liability under environmental laws, changes in
interest rates and the availability of financing. Income from a property will be
reduced if a significant number of tenants are unable to pay rent or if
available space cannot be rented on favorable terms. Operating and other
expenses of properties, particularly significant expenses such as real estate
taxes, insurance and maintenance costs, generally do not decrease when revenues
decrease and, even if revenues increase, operating and other expenses may
increase faster than revenues.

Many of our portfolio loans, including those treated in our
consolidated financial statements as FIN 46 assets and liabilities, are junior
lien obligations. Subordinate lien financing poses a greater credit risk,
including a substantially greater risk of nonpayment of interest or principal,
than senior lien financing. If we or any senior lender forecloses on a loan, we
will be entitled to share only in the net foreclosure proceeds after payment to
all senior lenders. It is therefore possible that we will not recover the full
amount of a foreclosed loan or the amount of our unrecovered investment in the
loan.

At September 30, 2003, our allowance for possible losses was $1.4
million, which represents 3% of the book value of our loan portfolio. We cannot
assure you that this allowance will prove to be sufficient to cover future
losses, or that future provisions for loan losses will not be materially greater
than those we have recorded to date. Losses that exceed our allowance for
losses, or an increase in our provision for losses, could materially reduce our
earnings.

Our loans, including those treated in our consolidated financial
statements as FIN 46 assets and liabilities typically do not conform to standard
loan underwriting criteria. Many of our loans are subordinate loans. As a
result, our loans are relatively illiquid investments. We may be unable to vary
our portfolio in response to changing economic, financial and investment
conditions.

The existence of hazardous or toxic substances on a property will
reduce its value and our ability to sell the property in the event of a default
in the loan it underlies. Contamination of a real property by hazardous
substances or toxic wastes not only may give rise to a lien on that property to
assure payment of the cost of remediation, but also can result in liability to
us as a lender, or, if we assume ownership or management, as an owner or
operator, for that cost regardless of whether we know of, or are responsible
for, the contamination. In addition, if we arrange for disposal of hazardous or
toxic substances at another site, we may be liable for the costs of cleaning up
and removing those substances from the site, even if we neither own nor operate
the disposal site. Environmental laws may require us to incur substantial
expenses to remediate contaminated properties and may materially limit use of
these properties. In addition, future laws or more stringent interpretations or
enforcement policies with respect to existing laws may increase our exposure to
environmental liability.

Our income from our real estate operations includes accretion of
discount, which is a non-cash item. For a discussion of accretion of discount,
see "Business - Real Estate Finance - Accounting for Discounted Loans." For the
years ended September 30, 2003, 2002 and 2001, accretion of discount, net of
collection of interest, was $2.0 million, $3.2 million and $5.9 million,
respectively. We accrete income on a loan to a maximum amount equal to the
difference between our cost basis in the loan and the present value of the
estimated cash flows from the property underlying the loan. If the actual cash
flows from the property are less than our estimates, or if we reduce our
estimates of cash flows, our earnings may be adversely affected. Moreover, if we
sell a loan, or foreclose upon and sell the underlying property, and the amount
we receive is less than the amount of our carrying cost, we will recognize an
immediate charge to our allowance for losses or, if that amount is insufficient
to absorb the shortfall and provide for possible losses on remaining real estate
investments, our statement of operations.

In addition, the property owners have obtained senior lien financing
with respect to nine loans. The senior loans are with recourse only to the
properties securing them subject to certain standard exceptions, which we have
guaranteed. These exceptions relate principally to the following:

o fraud or intentional misrepresentation in connection with the loan
documents;

o misapplication or misappropriation of rents, insurance proceeds or
condemnation awards during continuance of an event of default or, at
any time, of tenant security deposits or advance rents;

o payments of fees or commissions to various persons related to the
borrower or to us during an event of default, except as permitted by
the loan documents;

o failure to pay taxes, insurance premiums or specific other expenses,
failure to use property revenues to pay property expenses, and
commission of criminal acts or waste with respect to the property;

o environmental violations; and

o the undismissed or unstayed bankruptcy or insolvency of borrower.

We account for our investment in the Trapeza entities, described in
"Business-Financial Services," by the equity method of accounting. Accordingly,
we recognize our percentage share of any income or loss of these entities.
Because the Trapeza entities are investment companies for accounting purposes,
such income or loss will include a "mark-to-market" adjustment to reflect the
net changes in value, including unrealized appreciation or depreciation, in
investments and swap agreements. Such value will be impacted by changes in the
underlying quality of the Trapeza entities' investments, and by changes in
interest rates. To the extent that the Trapeza entities' investments are
securities denominated at a fixed rate of interest, increases in interest rates
will likely cause the value of the investments to fall and decreases in interest
rates will likely cause the value of the investments to rise. The Trapeza
entities' various interest rate hedges and swap agreements will also change in
value with changes in interest rates. Accordingly, our income or loss from our
Trapeza investments, and from future similar collateralized debt issuer
investments, may be volatile as interest rates change, and/or if the underlying
credit quality of their investments changes.

Before fiscal 2000, we entered into a series of standby commitments
with some participants in our loans which obligate us to repurchase their
participations or substitute a performing loan if the borrower defaults. At
September 30, 2003, the participations as to which we had standby commitments
had aggregate outstanding balances of $6.4 million. At September 30, 2003, we
also were contingently liable under guarantees of $1.2 million in mortgage loan
receivables connected with a discontinued operation and contingently liable
under guarantees of $1.9 in standby letters of credit issued in connection with
Atlas America and our lease of office space in New York City.

A real estate investment partnership in which we have a general partner
interest, has obtained senior lien financing with respect to four properties it
acquired. The senior liens are with recourse only to the properties securing
them subject to certain standard exceptions, which we have guaranteed. These
guarantees expire as the related indebtedness is paid down over the next ten
years. In addition, property owners have obtained senior lien financing with
respect to six of our loans. The senior liens are with recourse only to the
properties securing them subject to certain standard exceptions, which we have
guaranteed. These guarantees expire as the related indebtedness is paid down
over the next six years.

We believe that the likelihood of our being required to pay any claims
under any of them is remote under the facts and circumstances pertaining to each
of them. An adverse change in these facts and circumstances could cause us to
determine that the likelihood that a particular contingency may occur is no
longer remote. In that event, we may be required to include all or a portion of
the contingency as a liability in our financial statements, which could result
in:

o violations of restrictions on incurring debt contained in our senior
notes or in agreements governing our other outstanding debt; and

o prohibitions on additional borrowings under our credit lines.

In addition, if one or more of these contingencies were to occur, we
may not have sufficient funds to pay them and, in order to meet our obligations,
may have to sell assets at times and for prices that are disadvantageous to us.

Subsidiaries of ours currently serve as general partners of five public
equipment leasing partnerships, including one in the offering stage, two private
real estate investment partnerships, including one in the offering stage, and
five private investment partnerships that have invested and will invest in
issuers of debt obligations collateralized by trust preferred securities, one of
which is in the offering stage. We intend to develop further investment
partnerships for which we will act as general partner. As a general partner,
each subsidiary is contingently liable for the obligations of these partnerships
to the extent that their obligations cannot be repaid from partnership assets or
insurance proceeds.

ITEM 2. PROPERTIES

We maintain our executive office, real estate finance, leasing and
financial services operations in Philadelphia, Pennsylvania under leases for
18,000 square feet. These leases, which expire in May 2008, contains extension
options through 2033, and is located in an office building in which we have a
50% equity interest. We also maintain a 3,200 square foot office in New York,
New York under a lease agreement that expires in December 2006.

We own a 24,000 square foot office building in Pittsburgh,
Pennsylvania, a 17,000 square foot field office and warehouse facility in
Jackson Center, Pennsylvania and a field office in Deerfield, Ohio. We lease one
1,400 square foot field office in Ohio under a lease expiring in 2009 and one
3,100 square foot field office in Pennsylvania under a lease expiring in 2005.
In addition, we lease other field offices in Ohio and New York on a
month-to-month basis. We also rent 9,300 square feet of office space in
Uniontown, Ohio under a lease expiring in February 2006. All of these properties
are used for our energy operations.

Energy

Production. The following table sets forth the quantities of our
natural gas and oil production, average sales prices and average production
costs per equivalent unit of production for the periods indicated.

Production Average Sales Price Average Production
---------------------------- ----------------------- Cost per
Fiscal Year Oil (Bbls) Gas (Mcf) per Bbl per Mcf (1) Mcfe (2)
- ----------- ---------- ----------- --------- ----------- ----------

2003.......................... 160,048 6,966,899 $26.91 $4.92 $0.84
2002.......................... 172,750 7,117,276 $20.45 $3.56 $0.82
2001.......................... 177,437 6,342,667 $25.56 $5.04 $0.84

- ---------
(1) Our average sales price before the effects of hedging was $5.08, $3.57
and $5.13 for the fiscal years ending in 2003, 2002 and 2001,
respectively.

(2) Production costs include labor to operate the wells and related
equipment, repairs and maintenance, materials and supplies, property
taxes, severance taxes, insurance, gathering charges and production
overhead.

Productive wells. The following table sets forth information as of
September 30, 2003 regarding productive natural gas and oil wells in which we
have a working interest:

Number of Productive Wells
--------------------------
Gross (1) Net (1)
---------- --------

Oil wells..................................................................... 331 272
Gas wells..................................................................... 4,324 2,338
------------- -------------
4,655 2,610
============= =============

- ---------
(1) Includes our equity interest in wells owned by 84 drilling investment
partnerships for which we serve as general partner and various joint
ventures. Does not include our royalty or overriding interests in 619 other
wells that we do not operate.

Developed and Undeveloped Acreage. The following table sets forth
information about our developed and undeveloped natural gas and oil acreage as
of September 30, 2003. The information in this table includes our equity
interest in acreage owned by drilling investment partnerships sponsored by us.

Developed Acreage Undeveloped Acreage
-------------------------- -------------------------
Gross Net Gross Net
---------- ---------- ----------- ----------

Arkansas...................................... 2,560 403 - -
Kansas........................................ 160 20 - -
Kentucky...................................... 924 462 12,106 6,053
Louisiana..................................... 1,819 206 - -
Mississippi................................... 40 3 - -
Montana....................................... - - 2,650 2,650
New York...................................... 20,236 15,417 12,004 12,004
North Dakota.................................. 639 96 - -
Ohio.......................................... 115,709 96,600 41,498 37,989
Oklahoma...................................... 4,323 468 - -
Pennsylvania.................................. 73,784 73,701 126,277 126,277
Texas......................................... 4,520 329 - -
West Virginia................................. 1,078 539 10,806 5,403
Wyoming....................................... - - 80 80
---------- ---------- ---------- ----------
225,792 188,244 205,421 190,456
========== ========== =========== ==========

The leases for our developed acreage generally have terms that extend
for the life of the wells, while the leases on our undeveloped acreage have
terms that vary from less than one year to five years. We paid rentals of
approximately $386,300 in fiscal 2003 to maintain our leases.

We believe that we hold good and indefeasible title to our producing
properties, in accordance with standards generally accepted in the natural gas
industry, subject to exceptions stated in the opinions of counsel employed by us
in the various areas in which we conduct our activities. We do not believe that
these exceptions detract substantially from our use of any property. As is
customary in the natural gas industry, we conduct only a perfunctory title
examination at the time we acquire a property. Before we commence drilling
operations, we conduct an extensive title examination and we perform curative
work on defects that we deem significant. We have obtained title examinations
for substantially all of our managed producing properties. No single property
represents a material portion of our holdings.

Our properties are subject to royalty, overriding royalty and other
outstanding interests customary in the industry. Our properties are also subject
to burdens such as liens incident to operating agreements, taxes, development
obligations under natural gas and oil leases, farm-out arrangements and other
encumbrances, easements and restrictions. We do not believe that any of these
burdens will materially interfere with our use of our properties.

Drilling activity. The following table sets forth information with
respect to the number of wells on which we have completed drilling during the
periods indicated, regardless of when drilling was initiated.

Exploratory Wells Development Wells
-------------------------------------- ----------------------------------------
Productive Dry Productive Dry
-------------- ------------- -------------- -------------
Fiscal Year Gross Net Gross Net Gross Net Gross Net
- ----------- ----- --- ----- --- ----- ----- ----- ----

2003............. - - - - 295.0 92.9 1 .33
2002............. - - - - 246.0 78.7 6 2.00
2001............. - - 1.0 .18 256.0 76.6 1 .27

Natural gas sales. We have a natural gas supply agreement with
FirstEnergy Solutions Corp. for a 10-year term which began on April 1, 1999.
Subject to certain exceptions, FirstEnergy Solutions has a last right of refusal
to buy all of the natural gas produced and delivered by us and our affiliates,
including our drilling investment partnerships, at certain delivery points with
the facilities of:

o East Ohio Gas Company, National Fuel Gas Distribution, Columbia of
Ohio, and Peoples Natural Gas Company, which are local distribution
companies; and

o National Fuel Gas Supply, Columbia Gas Transmission Corporation,
Tennessee Gas Pipeline Company, and Texas Eastern Transmission
Company, which are interstate pipelines.

FirstEnergy Solutions is the marketing affiliate of FirstEnergy Corp.
(NYSE: FE), a large regional electric utility based in Akron, Ohio.

The agreement established an indexed price formula for each of the
delivery points during an initial period of one or two years, and requires the
parties to negotiate a new pricing arrangement at each delivery point for
subsequent periods. If, at the end of any applicable period, the parties cannot
agree to a new price for any delivery point, then we may solicit offers from
third-parties to buy the natural gas for that delivery point. If FirstEnergy
Solutions does not match this price, then we may sell the natural gas to the
third-party. This process is repeated at the end of each contract period which
is usually one year. For example, during the period April 1, 2000 through March
31, 2001, we sold natural gas delivered to National Fuel Gas Supply to other
entities under this process. In order to hedge our gas prices over a longer
period of time, we recently agreed upon prices with FirstEnergy Solutions that
will be effective through March 2005. We will market the remainder of our
natural gas, which is primarily located in the Fayette County area, primarily to
Colonial Energy, Inc. and UGI Energy Services, and possibly others, for the
period ending March 31, 2004.

Our pricing arrangements with FirstEnergy Solutions and the other
third-parties are tied to the NYMEX monthly futures contract price, which is
reported daily in the Wall Street Journal. The total price received for gas is a
combination of the monthly NYMEX futures price plus a fixed basis.

The agreement with FirstEnergy Solutions may be suspended for force
majeure, which means generally such things as an act of God, fire, storm, flood,
and explosion, but also includes the permanent closing of the factories of
Carbide Graphite or Duferco Farrell Corporation during the term of FirstEnergy
Solutions' agreements to sell natural gas to them. If these factories were
closed, however, we believe that FirstEnergy Solutions would be able to find
alternative purchasers and would not invoke the force majeure.

We expect that natural gas produced from wells drilled in areas of the
Appalachian Basin other than described above will be primarily tied to the spot
market price and supplied to:

o gas marketers;
o local distribution companies;
o industrial or other end-users; and/or
o companies generating electricity.

Crude oil sales. Crude oil produced from our wells flows directly into
storage tanks where it is picked up by the oil company, a common carrier, or
pipeline companies acting for the oil company which is purchasing the crude oil.
Unlike natural gas, crude oil does not present any transportation problem. We
anticipates selling any oil produced by our wells to regional oil refining
companies at the prevailing spot market price for Appalachian crude oil in spot
sales.

Natural Gas and Oil Reserves. The following tables summarize
information regarding our estimated proved natural gas and oil reserves as of
the dates indicated. All of our reserves are located in the United States. We
base our estimates relating to our proved natural gas and oil reserves and
future net revenues of natural gas and oil reserves upon reports prepared by
Wright & Company, Inc. In accordance with SEC guidelines, we make the
standardized and pre-tax PV-10 estimates of future net cash flows from proved
reserves using natural gas and oil sales prices in effect as of the dates of
the estimates which are held constant throughout the life of the properties. We
based our estimates of proved reserves upon the following weighted average
prices:

Years Ended September 30,
------------------------------------
2003 2002 2001
-------- -------- ------

Natural gas (per Mcf)............................................... $ 4.96 $ 3.80 $ 3.81
Oil (per Bbl)....................................................... $ 26.00 $ 26.76 $ 19.60

Reserve estimates are imprecise and may change as additional
information becomes available. Furthermore, estimates of natural gas and oil
reserves, of necessity, are projections based on engineering data. There are
uncertainties inherent in the interpretation of this data as well as the
projection of future rates of production and the timing of development
expenditures. Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil that cannot be measured in an
exact way and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports of our
consultants, Wright & Company. Results of drilling, testing and production
subsequent to the date of the estimate may justify revision of this estimate.
Future prices received from the sale of natural gas and oil may be different
from those estimated by Wright & Company in preparing its reports. The amounts
and timing of future operating and development costs may also differ from those
used. Accordingly, the reserves set forth in the following tables ultimately may
not be produced and the proved undeveloped reserves may not be developed within
the periods anticipated. You should not construe the estimated pre-tax PV-10
values as representative of the fair market value of our proved natural gas and
oil properties. PV-10 values are based upon projected cash inflows, which do not
provide for changes in natural gas and oil prices or for escalation of expenses
and capital costs. The meaningfulness of these estimates depends upon the
accuracy of the assumptions upon which they were based.

We evaluate natural gas reserves at constant temperature and pressure.
A change in either of these factors can affect the measurement of natural gas
reserves. We deduct operating costs, development costs and production-related
and ad valorem taxes in arriving at the estimated future cash flows. We make no
provision for income taxes, and base the estimates on operating methods and
conditions prevailing as of the dates indicated. We cannot assure you that these
estimates are accurate predictions of future net cash flows from natural gas and
oil reserves or their present value. For additional information concerning our
natural gas and oil reserves and estimates of future net revenues, see Note 18
of the Notes to Consolidated Financial Statements.

Proved Natural Gas and Oil Reserves
-----------------------------------
At September 30,
-----------------------------------
2003 2002 2001
-------- ---------- --------

Natural gas reserves (Mmcf):
Proved developed reserves.............................................. 87,760 83,996 80,249
Proved undeveloped reserves............................................ 45,533 39,226 37,868
-------- ------------ --------
Total proved reserves of natural gas................................... 133,293 123,222 118,117
======== ============ ========

Oil reserves (Mbbl):
Proved developed reserves.............................................. 1,825 1,846 1,735
Proved undeveloped reserves............................................ 30 32 66
-------- ------------ --------
Total proved reserves of oil........................................... 1,855 1,878 1,801
======== ============ ========

Total proved reserves (Mmcfe).......................................... 144,423 134,490 128,923
======== ============ ========

Standardized measure of discounted future cash flows
(in thousands)......................................................... $144,335 $ 104,126 $ 98,712
======== ============ ========
Pre-tax PV-10 estimate of cash flows of proved reserves
(in thousands):
Proved developed reserves.............................................. $164,617 $ 120,260 $109,288
Proved undeveloped reserves............................................ 26,802 12,209 17,971
-------- ------------ --------
Total pre-tax PV-10 estimate........................................... $191,419 $ 132,469 $127,259
======== ============ ========

Dismantlement, Restoration, Reclamation and Abandonment Costs. When we
determine that a well is no longer capable of producing natural gas or oil in
economic quantities, we must dismantle the well and restore and reclaim the
surrounding area before we can abandon the well. We contract these operations to
independent service providers to whom we pay a fee, currently averaging
approximately $7,700 per well. The contractor will also salvage the equipment on
the well, which we then sell in the used equipment market. Our proceeds from the
sales of salvaged equipment currently range between $6,900 and $11,000 per well.
Under the partnership agreements of our drilling investment partnerships, which
own substantially all of our wells, we are allocated abandonment costs in
proportion to our partnership interest (generally between 27% and 33%) and are
allocated between 66% and 100% of the salvage proceeds. As a consequence, we
generally receive revenues from salvaged equipment at least equal to, and
typically exceeding, our share of the related costs. See Note 2 of the notes to
Consolidated Financial Statements, "Asset Retirement Obligations."

ITEM 3. LEGAL PROCEEDINGS

We are a defendant in a proposed class action originally filed in
February 2000 in the New York Supreme Court, Chautauqua County, by individuals,
putatively on their own behalf and on behalf of similarly situated individuals,
who leased property to us. The complaint alleges that we are not paying
landowners the proper amount of royalty revenues derived from the natural gas
produced from the wells on leased property. The complaint seeks damages in an
unspecified amount for the alleged difference between the amount of royalties
actually paid and the amount of royalties that allegedly should have been paid.

We are also a party to various routine legal proceedings arising out of
the ordinary course of our business. Management believes that none of these
actions, individually or in the aggregate, will have a material adverse effect
on our financial condition or operations.

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

No matter was submitted to a vote of security holders during the
quarter ended September 30, 2003.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS

Our common stock is quoted on the Nasdaq National Market under the
symbol "REXI." The following table sets forth the high and low sale prices, as
reported by Nasdaq, on a quarterly basis for our last two fiscal years.

High Low
--------- ---------

Fiscal 2003
- -----------
Fourth Quarter............................................................................. $ 12.50 $ 9.79
Third Quarter.............................................................................. $ 11.04 $ 7.86
Second Quarter............................................................................. $ 9.50 $ 7.52
First Quarter.............................................................................. $ 9.50 $ 7.26

Fiscal 2002
- -----------
Fourth Quarter............................................................................. $ 11.24 $ 7.48
Third Quarter.............................................................................. $ 11.65 $ 9.78
Second Quarter............................................................................. $ 11.24 $ 8.22
First Quarter.............................................................................. $ 9.80 $ 7.89

As of December 15, 2003, there were 17,354,300 shares of common stock
outstanding held by 625 holders of record.

We have paid regular quarterly cash dividends on our common stock
commencing with the fourth quarter of fiscal 1995. The indenture governing our
senior notes restricts our payment of dividends on our common stock unless we
meet certain financial tests. However, we expect to redeem the outstanding
senior notes, at which time such restrictions will lapse. See Item 1 "Business -
General."

For information concerning common stock authorized for issuance under
our stock option plans and other equity compensation plans and stock options
outstanding under these plans, see Note 11 of our Notes to Consolidated
Financial Statements.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data should be read together with our
consolidated financial statements, the notes to our consolidated financial
statements and "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in Item 7 of this report. We have derived the selected
consolidated financial data set forth below for each of the years ended
September 30, 2003, 2002 and 2001, and at September 30, 2003 and 2002 from our
consolidated financial statements appearing elsewhere in this report, which have
been audited by Grant Thornton LLP, independent accountants. We have derived the
selected financial data for the years ended September 30, 2000 and 1999 and at
September 30, 2001, 2000 and 1999 from our consolidated financial statements for
those periods which have been audited by Grant Thornton LLP but are not included
in this report.

As of and for the Years Ended September 30,
-------------------------------------------------------------------------
2003 2002 2001 2000 1999
------------ ------------ ------------ ------------ ------------
(in thousands, except per share data)

Income statement data:
Revenues:
Energy......................................... $ 105,262 $ 97,912 $ 94,806 $ 70,552 $ 55,093
Real estate finance............................ 14,335 16,582 16,899 18,649 45,907
Leasing........................................ 4,071 1,246 1,066 - -
Equity in earnings in Trapeza entities......... 1,444 185 - - -
Interest, dividends, gains and other........... 7,417 5,459 6,222 11,460 8,525
----------- --------- ---------- --------- ----------
Total revenues............................... $ 132,529 $ 121,384 $ 118,993 $ 100,661 $ 109,525
=========== ========= ========== ========== ==========

Income from continuing operations before
income taxes and cumulative effect of
change in accounting principle................. $ 14,330 $ 11,772 $ 20,410 $ 7,882 $ 35,775
Provision for income taxes........................ 4,586 3,414 6,327 2,401 11,262
----------- --------- ---------- ---------- ----------
Income from continuing operations before
cumulative effect of change in accounting
principle...................................... $ 9,744 $ 8,358 $ 14,083 $ 5,481 $ 24,514
=========== ========= ========== ========== ==========
Net (loss) income.............................. $ (2,915) $ (3,309) $ 9,829 $ 18,165 $ 18,460
=========== ========= ========== ========== ==========

Net (loss) income per common share-basic:
From continuing operations before cumulative
effect of change in accounting principle....... $ .57 $ .48 $ .78 $ .24 $ 1.10
=========== ========= ========== ========== ==========

Net (loss) income per common share-basic....... $ (.17) $ (.19) $ .55 $ .78 $ .83
=========== ========= ========== ========== ==========

Net (loss) income per common share-diluted:
From continuing operations before cumulative
effect of change in accounting principle....... $ .55 $ .47 $ .76 $ .23 $ 1.07
=========== ========= ========== ========== ==========

Net (loss) income per common share-diluted..... $ (.17) $ (.19) $ .53 $ .76 $ .81
=========== ========= ========== ========== ==========

Cash dividends per common share................... $ .13 $ .13 $ .13 $ .13 $ .13
=========== ========= ========== ========== ==========

Balance sheet data:
Total assets...................................... $ 670,782 $ 467,498 $ 466,464 $ 507,831 $ 540,132
Long-term debt (including current maturities)..... $ 133,167 $ 153,089 $ 150,131 $ 134,932 $ 234,028
FIN 46 entities' liabilities...................... $ 186,657 $ - $ - $ - $ -
Stockholders' equity.............................. $ 227,454 $ 233,539 $ 235,459 $ 281,215 $ 263,789

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

Overview

During fiscal 2002 and 2001, our operations reflected the dominant
position of our energy business. In fiscal 2003, while our energy operations
remained the single largest contributor to our revenues, our strategic
initiatives in financial services and equipment leasing also began to generate
material revenues. We anticipate that these operations will increase in
importance to us in fiscal 2004. Our decision in fiscal 2000 to focus our real
estate finance operations on managing our existing portfolio of real estate
loans and property interests has resulted in a decline in the relative
significance of real estate operations to us. However, beginning in fiscal 2002
we began to seek new growth from our real estate operations through the
sponsorship of real estate investment partnerships. While the assets in our real
estate finance business increased significantly in fiscal 2003 from fiscal 2002
as a percentage of our total assets, the increase was due to the effects of our
adoption of FIN 46. This new accounting standard required us to consolidate in
our financial statements the assets and liabilities of a number of entities
which are borrowers on loans in our portfolio, although our legal relationship
as creditor of the entities has not been altered. We have classified $222.7
million of these FIN 46 assets as held for sale and, accordingly, expect to
dispose of them in fiscal 2004.

The following tables set forth the percentages of revenues and assets
allocable to each of our four principal businesses for the periods indicated:

Revenues as a Percent of Total Revenues (1)

Year Ended September 30,
---------------------------------------
2003 2002 2001
------------ ---------- ---------

Energy............................................................... 79% 81% 80%
Real estate finance.................................................. 11% 14% 14%
Leasing.............................................................. 3% 1% 1%
Financial services (Trapeza)......................................... 1% - -

Assets as a Percent of Total Assets (2)

As of September 30,
------------------------
2003 2002
---------- ----------
Energy............................................................... 35% 41%
Real estate finance.................................................. 55% 44%
Leasing.............................................................. 2% 2%
Financial services (Trapeza)......................................... 1% 1%

- --------
(1) The balance (6% in 2003, 4% in 2002 and 5% in 2001) is attributable to
revenues derived from corporate assets not attributable to a specific
industry segment.
(2) The balance (7% in 2003 and 12% in 2002) is attributable to corporate assets
not attributable to a specific industry segment.

Results of Operations: Energy

The following tables set forth information relating to revenues
recognized and costs and expenses incurred, daily production volumes, average
sales prices, production costs as a percentage of natural gas and oil sales, and
production costs per Mcfe for our energy operations during fiscal 2003, 2002 and
2001:

Years Ended September 30
-----------------------------------------
2003 2002 2001
------------ ---------- ----------
(in thousands)

Revenues:
Production............................................................. $ 38,639 $ 28,916 $ 36,681
Well drilling.......................................................... 52,879 55,736 43,464
Well services.......................................................... 7,843 7,871 8,946
Transportation......................................................... 5,901 5,389 5,715
---------- --------- ---------
$ 105,262 $ 97,912 $ 94,806
========== ========= =========

Costs and expenses:
Production............................................................. $ 6,770 $ 6,693 $ 6,185
Exploration............................................................ 1,715 1,571 1,661
Well drilling.......................................................... 45,981 48,443 36,602
Well services.......................................................... 3,916 3,938 4,151
Transportation......................................................... 2,444 2,052 2,001
Non-direct............................................................. 6,389 6,883 9,376
---------- --------- ---------
$ 67,215 $ 69,580 $ 59,976
========== ========= =========

Years Ended September 30
----------------------------------------
2003 2002 2001
------------ ---------- ----------

Revenues (in thousands):
Gas (1)................................................................ $ 34,276 $ 25,359 $ 31,945
Oil.................................................................... $ 4,307 $ 3,533 $ 4,535

Production volumes:
Gas (Mcf/day) (1) (2).................................................. 19,087 19,499 17,377
Oil (Bbls/day)......................................................... 438 473 486

Average sales prices:
Gas (per Mmcf) (2)..................................................... $ 4.92 $ 3.56 $ 5.04
Oil (per Bbl).......................................................... $ 26.91 $ 20.45 $ 25.56

Production costs (3):
As a percent of sales.................................................. 18% 23% 17%
Per Mcfe............................................................... $ .84 $ .82 $ .84

- -------------------
(1) Excludes sales of residual gas and sales to landowners.
(2) Our average sales price before the effects of hedging was $5.08, $3.57
and $5.13 for the years ended 2003, 2002 and 2001, respectively.
(3) Production costs include labor to operate the wells and related
equipment, repairs and maintenance, materials and supplies, property
taxes, severance taxes, insurance, gathering charges and production
overhead.

Our well drilling revenues and expenses represent the billings and
costs associated with the completion of 282, 242 and 234 net wells for drilling
investment partnerships sponsored by Atlas America in fiscal 2003, 2002 and
2001, respectively. The following table sets forth information relating to
these revenues and costs and expenses during the periods indicated:

Years Ended September 30,
----------------------------------------
2003 2002 2001
------ ------ -----
(in thousands)

Average drilling revenue per well......................................... $ 187 $ 230 $ 186
Average drilling cost per well............................................ 163 200 156
---------- ---------- ----------
Average drilling gross profit per well.................................... $ 24 $ 30 $ 30
========== ========== ==========
Gross profit margin....................................................... $ 6,898 $ 7,293 $ 6,862
========== ========== ==========
Gross margin percent...................................................... 13% 13% 16%
========== ========== ==========

Year Ended September 30, 2003 Compared to Year Ended September 30, 2002

Our natural gas revenues were $34.3 million in fiscal 2003, an increase
of $8.9 million (35%) from $25.4 million in fiscal 2002. The increase was due to
a 38% increase in the average sales price of natural gas partially offset by a
2% decrease in production volumes. The $8.9 million increase in natural gas
revenues consisted of $9.7 million attributable to price increases, partially
offset by $740,000 attributable to volume decreases. Production volumes
decreased because normal production declines in our existing wells were not
offset by the new wells we had drilled in Crawford County, Pennsylvania, since
those wells could not be brought on line until the extension of our Crawford
gathering system had been completed. The Crawford extension was completed in the
fourth quarter of fiscal 2003.

Our oil revenues were $4.3 million in fiscal 2003, an increase of
$774,000 (22%) from $3.5 million in fiscal 2002. The increase resulted from a
32% increase in the average sales price of oil partially offset by a 7% decrease
in production volumes. The $774,000 increase in oil revenues consisted of $1.1
million attributable to price increases partially offset by $342,000
attributable to volumes decreases. The decrease in oil volumes is a result of
the natural production decline inherent in the life of a well. We did not offset
the decline through the addition of new wells, as substantially all of the wells
we have drilled during the past several years have targeted natural gas
reserves.

Our well drilling gross margin was $6.9 million in the year ended
September 30, 2003, a decrease of $395,000 (5%) from $7.3 million in the year
ended September 30, 2002. During the period, our average cost per well decreased
because we drilled many of them to a shallower formation and, in certain areas
where we have become more active, many of our wells either have not required
fracture stimulation or have needed less equipment than wells we have drilled in
prior years. Since our drilling contracts are on a "cost plus" basis (typically
cost plus 15%), a decrease in our average cost per well also results in a
decrease in our average revenue per well. On the other hand, the decrease in our
average cost per well allowed us to drill more wells with the funds available.
In addition, it should be noted that "Liabilities associated with drilling
contracts" includes $14.1 million of funds raised in our drilling investment
partnerships in fiscal 2003 that had not been applied to drill wells as of
September 30, 2003 due to the timing of drilling operations, and thus had not
been recognized as well drilling revenues. We expect to recognize this amount as
income in fiscal 2004. Because we raised $40.0 million in the first quarter of
fiscal 2004 alone, we anticipate drilling revenues and related costs to be
substantially higher than in fiscal 2003.

Although we raised approximately $23.7 million more in drilling funds
in fiscal 2003 than in fiscal 2002, $14.1 million of these funds raised in
fiscal 2003 had not been recognized as income as of September 30, 2003 due to
the timing of drilling operations. We expect these amounts will be recognized as
income in fiscal 2004. In addition, we raised $40.0 million in the first quarter
of fiscal 2004. We anticipate drilling revenues and related costs to be
substantially higher than in fiscal 2003.

Our transportation revenues, which are derived from arrangements with
the drilling investment partnerships we sponsor, increased $512,000 (10%) in
fiscal 2003 to $5.9 million from $5.4 million in fiscal 2002. The increase was a
result of a 6% increase in natural gas volumes transported by Atlas Pipeline
Partners and an increase in the average prices received for the natural gas
transported, upon which the fees chargeable under a portion of our
transportation arrangements are based in fiscal 2003 as compared to fiscal 2002.

Our transportation expenses increased 19% in the year ended September
30, 2003, as compared to the similar prior year period. This increase resulted
from an increase in compressor expenses due to the addition of more compressors
and increased compressor lease rates. Compressors were added to increase the
transportation capacity of our gathering systems.

Our exploration costs were $1.7 million in the year ended September 30,
2003, an increase of $144,000 (9%) from the year ended September 30, 2002. The
increase in the year ended September 30, 2003 as compared to the prior period
was attributable to expenditures for lease costs of $275,000 which were charged
to operations upon our decision to discontinue drilling on certain leases.

Our non-direct expenses were $6.4 million in fiscal 2003, a decrease of
$494,000 (7%) from $6.9 million in fiscal 2002. These expenses include, among
other things, salaries and benefits not allocated to a specific energy activity,
costs of running our energy corporate office, partnership syndication activities
and outside services. These expenses were partially offset by reimbursements we
received for costs we incurred in our partnership management and drilling
activities, resulting from an increase in the number of wells we drilled and
managed during the year as compared to the prior year. Reimbursements received
by us related to our drilling activities increased $470,000 in year ended
September 30, 2003 as compared to the year ended September 30, 2002. In
addition, we more closely allocated direct costs associated with our other
energy activities to those activities, thereby reducing non-direct expenses.

Depletion of oil and gas properties as a percentage of oil and gas
revenues was 21% in fiscal 2003 compared to 27% in fiscal 2002. The variance
from period to period is directly attributable to changes in our oil and gas
reserve quantities, product prices and fluctuations in the depletable cost basis
of oil and gas. Higher gas and oil prices caused depletion as a percentage of
oil and gas revenues to decrease in fiscal 2003 as compared to fiscal 2002.

Year Ended September 30, 2002 Compared to Year Ended September 30, 2001

Our natural gas revenues were $25.4 million in fiscal 2002, a decrease
of $6.6 million (21%) from $31.9 million in fiscal 2001. The decrease was due to
a 29% decrease in the average sales price of natural gas partially offset by a
12% increase in production volumes. The $6.6 million decrease in gas revenues
consisted of $9.3 million attributable to price decreases, partially offset by
$2.7 million attributable to volume increases. Natural gas volume increases
resulted from new wells drilled for our partnerships, partially offset by the
natural production decline inherent in the life of a well.

Our oil revenues were $3.5 million in fiscal 2002, a decrease of $1.0
million (22%) from $4.5 million in fiscal 2001. The decrease resulted from a 20%
decrease in the average sales price of oil and a 3% decrease in production
volumes. The $1.0 million decrease in oil revenues consisted of $906,000
attributable to price decreases, and $96,000 attributable to volume decreases.
The decrease in oil volumes is a result of the natural production decline
inherent in the life of a well. This decline was not offset by new wells added,
as the majority of the wells we have drilled during the past several years
targeted gas reserves.

Our well drilling gross margin was $7.3 million in fiscal 2002, an
increase of $431,000 (6%) from $6.9 million in fiscal 2001 due to an increase in
the number of wells drilled ($241,000) and the gross profit per well ($190,000),
during fiscal 2002 as compared to fiscal 2001. Both the average revenue and cost
per well which are affected by changes in oil and gas prices and competition for
drilling equipment and services increased $44,000 in fiscal 2002 as compared to
fiscal 2001. Demand for drilling equipment and services increased in the fiscal
year ended September 30, 2002 as compared to fiscal 2001 as a result of
increases in the prices obtainable for natural gas in fiscal 2001, resulting in
an increase in the cost to us of obtaining such equipment and services. In
fiscal 2002, we changed the structure of our drilling contracts to a cost-plus
basis from a turnkey basis. Cost-plus contracts protect us in an inflationary
environment while limiting our profit margin.

Our well services revenues increased $182,000 (2%) in fiscal 2002 to
$7.6 million as compared to $7.4 million in fiscal 2001 primarily as a result of
an increase in fee income due to an increase in the number of wells we operate.
Our well service expenses were $3.7 million in fiscal 2002, an increase of
$786,000 (27%) from $3.0 million in fiscal 2001. The increase in fiscal 2002
resulted from a closer allocation of direct costs associated with our well
services activities.

Our transportation revenues, which derive from arrangements with the
drilling investment partnerships we sponsor, decreased $326,000 (6%) in fiscal
2002 to $5.4 million from $5.7 million in fiscal 2001. The decrease was a result
of a decrease in the average prices received for natural gas transported by our
pipelines, as a portion of our transportation contracts are based on the price
of the gas transported..

We sold our gas marketing operation in fiscal 2000, and while we
maintained a small in-house gas marketing operation in 2001, we reduced our
activities in this area to an immaterial amount in fiscal 2002.

While we reduced our average production cost from $.84 per Mcf in
fiscal 2001 to $.82 per Mcf in fiscal 2002, our production costs increased
$508,000 (8%) to $6.7 million in fiscal 2002 from $6.2 million in fiscal 2001 as
a result of an increase in the number of wells in which we have an interest and
transportation expenses associated with the increased volumes we produced to our
interest.

Our non-direct expenses were $6.9 million in fiscal 2002, a decrease of
$2.5 million (27%) from $9.4 million in fiscal 2001. These expenses include,
among other things, salaries and benefits not allocated to a specific energy
activity, costs of running our energy corporate office, partnership syndication
activities and outside services. These expenses were partially offset by fees we
earned from our partnership management activities, resulting from an increase in
the number of wells drilled and managed during the year as compared to the prior
year. In addition, we more closely allocated direct costs associated with our
other energy activities to those activities, thereby reducing non-direct
expenses.

Depletion of oil and gas properties as a percentage of oil and gas
revenues was 27% in fiscal 2002 compared to 17% in fiscal 2001. The variance
from period to period is directly attributable to changes in our oil and gas
reserve quantities, product prices and fluctuations in the depletable cost basis
of oil and gas. Lower gas prices caused depletion as a percentage of oil and gas
revenues to increase in fiscal 2002 as compared to fiscal 2001.

Results of Operations: Real Estate Finance

During fiscal 2003, 2002 and 2001, our real estate finance operations
were affected by three principal trends or events:

o We determined to selectively resolve the loans in our existing
portfolio through repayments, sales, refinancings, restructurings and
foreclosures.

o In fiscal 2002 to seek growth in our real estate business through the
sponsorship of real estate investment partnerships in which we are
also an investor.

o In fiscal 2003, we adopted FIN 46.

The principal effects of the first two factors has been to reduce the
number of our real estate loans, while increasing our interests in real
property and, as a result of repayments, sales, refinancings and
restructurings, increasing our cash flow from loan resolutions. The principal
effect of FIN 46 has been to consolidate in our financial statements the assets
and liabilities of a number of borrowers (although not affecting our
creditor-debtor legal relationship with these borrowers and not causing these
assets and obligations to become our legal assets or obligations). Our FIN 46
assets and liabilities were $300.9 million and $186.7 million, respectively, at
September 30, 2003. The adoption of FIN 46 also resulted in a $13.9 million
non-cash after-tax cumulative effect adjustment in the fourth quarter of fiscal
2003. For a more detailed discussion of FIN 46, you should read "Cumulative
Effect of Change in Accounting Principle" and Note 3 to the Notes to the
Consolidated Financial Statements.

The following table sets forth information relating to the revenues
recognized and costs and expenses incurred in our real estate finance operations
during the periods indicated:

Years Ended September 30,
--------------------------------------------
2003 2002 2001
------------ ------------ -----------
(in thousands)

Revenues:
Interest on loans...................................................... $ 6,103 $ 9,907 $ 9,251
Accreted discount (net of collection of interest) on loans............. 1,962 3,212 5,923
Gains on resolutions of loans and loan payments in excess
of the carrying value of loans...................................... 1,024 2,398 1,612
Fee income from sponsorship of partnerships............................ 3,062 - -
Rental income from properties.......................................... 997 611 442
FIN 46 revenues........................................................ 948 - -
Equity in earnings (loss) of equity investees.......................... 239 454 (329)
---------- ---------- ----------
$ 14,335 $ 16,582 $ 16,899
========== ========== ==========

Cost and expenses:
Real estate general and administrative................................. $ 3,880 $ 2,423 $ 1,504
Rental expense from properties......................................... 854 - -
FIN 46 expenses........................................................ 730 - -
---------- ---------- ----------
$ 5,464 $ 2,423 $ 1,504
========== ========== ==========

Year Ended September 30, 2003 Compared to Year Ended September 30, 2002

Revenues from our real estate finance operations decreased $2.3 million
(14%) from $16.6 million in fiscal 2002 to $14.3 million in fiscal 2003. We
attribute these changes to the following:

o A decrease in interest income and accreted discount of $5.1 million
(38%) in fiscal 2003 as compared to fiscal 2002, primarily resulting
from the following:

- The sale or repayment of three loans in fiscal 2003 which decreased
interest income by $1.3 million in fiscal 2003 as compared to
fiscal 2002.

- The completion of accretion of discount on one loan, which
decreased interest income by $1.6 million in fiscal 2003 as
compared to fiscal 2002.

- A decrease in our average accretion rate, resulting in a decrease
in interest income of $84,000 in fiscal 2003 as compared to fiscal
2002.

- The early adoption of FIN 46 on July 1, 2003 resulted in our
consolidating 14 entities and resulted in a decrease in interest
income of $2.1 million.

o A decrease of $1.4 million (57%) in gains on resolutions of loans and
loan payments in excess of carrying value in fiscal 2003 as compared
to fiscal 2002, resulting primarily from the following:

- In fiscal 2003, we received repayments of $10.7 million on three
loans having aggregate book values of $9.7 million, resulting in
gains of $1.0 million.

- In fiscal 2002, we sold one loan having a book value of $1.0
million to RAIT for $1.8 million, resulting in a gain of $757,000.

- In fiscal 2002, we received repayments of $24.9 million on two
loans having an aggregate book value of $23.3 million, resulting in
gains of $1.6 million.

o An increase of $3.1 million in fee income in fiscal 2003, as compared
to fiscal 2002. This increase resulted primarily from fees we earned
for services provided to the real estate investment partnership which
we sponsored. These fees relate to the purchase and third party
financing of four partnership properties. We anticipate earning
additional fees from this partnership and any future real estate
investment partnerships which we may sponsor.

Gains on resolutions of loans and loan payments in excess of the
carrying value of loans (if any) and the amount of fees received (if any) vary
from transaction to transaction and there may be significant variations in our
gains on resolutions and fee income from period to period.

Costs and expenses of our real estate finance operations increased $3.0
million (126%) from $2.4 million in fiscal 2002 to $5.4 million in fiscal 2003.
Primarily resulting from the following:

o An increase in wages and benefits of $532,000 due to the addition of
personnel in connection with of our sponsorship and management of
our real estate investment partnerships.

o An increase in insurance and professional services fees of $716,000
due to an increase in insurance rates in general and additional
activity associated with the management of our loan portfolio and
investment partnership.

o Rental property expenses represent expenses associated with two
properties which we acquired in fiscal 2003 through foreclosure.

o FIN 46 expenses associated with 14 real estate entities consolidated
upon adoption on July 1, 2003 of FIN 46 (see Note 3 to our
consolidated financial statements).

Year Ended September 30, 2002 Compared to Year Ended September 30, 2001

o An increase of $786,000 (49%) in gains from resolution of loans and
loan repayments in excess of carrying values in fiscal 2002 as
compared to fiscal 2001, resulting primarily from the following:

- In fiscal 2002, we sold one loan having a book value of $1.0
million to RAIT for $1.8 million, resulting in a gain of $757,000,
and we sold a second loan having a book value of $22.4 million for
$24.0 million, resulting in a gain of $1.6 million.

- In fiscal 2001, we sold five loans having aggregate book values of
$23.6 million for $25.1 million, resulting in gains of $1.5
million.

- In fiscal 2001, we received repayments on two loans having
aggregate book values of $130,000, for $225,000, resulting in gains
of $95,000.

o An increase of $783,000 in our equity earnings in one real estate
joint venture in which we own a 50% equity interest.

o An increase in net rental and fee income of $169,000 to $611,000 in
fiscal 2002 from $442,000 in fiscal 2001, primarily resulting from
the receipt of a consulting fee from another real estate joint
venture in which we own a 25% equity interest.

Costs and expenses of our real estate finance operations were $2.4
million in fiscal 2002, an increase of $919,000 (61%) from $1.5 million in the
same period of the prior fiscal year. The increase primarily resulted from an
increase in professional fees of $577,000 associated with litigation settled in
fiscal 2002 regarding two of our real estate loans. In addition, wages and
benefits increased $308,500 in fiscal 2002 as a result of the addition of a new
president and other personnel in our real estate subsidiary to manage our
existing portfolio of commercial loans and real estate joint ventures and to
expand our real estate operations through the sponsorship of real estate
investment partnerships. One real estate partnership sponsored in fiscal 2002
was in its offering phase in that year and, as a consequence, did not generate
fees or other revenues for us.

Results of Operations: Financial Services

Our equity in the earnings of the Trapeza entities were $1.4 million in
fiscal 2003, an increase of $1.3 from $185,000 in fiscal 2002. The increase in
fiscal 2003 reflects our equity earnings subsequent to completion of the funding
and investment stages of three of the Trapeza CDO issuers we sponsored.

Results of Operations: Leasing

In fiscal 2002 we began to pursue expansion of our equipment leasing
operations through sponsorship of equipment leasing programs. Our first such
program commenced operations in March 2003. We intend to further develop our
equipment leasing operations through the sponsorship of subsequent equipment
leasing programs. In addition, in April 2003, we entered into a multi-year
agreement to originate and service leases on behalf of Merrill Lynch Equipment
Finance LLC.

The following table sets forth certain information relating to the
revenue recognized and costs and expenses incurred in our equipment leasing
operations during the periods indicated:

Years Ended September 30,
--------------------------------------------
2003 2002 2001
------------ ----------- ----------
(in thousands)

Revenues:
Partnership management................................................. $ 3,416 $ 954 $ 1,066
Leasing................................................................ 491 262 -
Other.................................................................. 164 30 -
---------- ---------- ----------
$ 4,071 $ 1,246 $ 1,066
========== ========== ==========

Costs and expenses......................................................... $ 5,883 $ 745 $ 695
========== ========== ==========

Year Ended September 30, 2003 Compared to Year Ended September 30, 2002

Our leasing revenues were $4.1 million in fiscal 2003, an increase of
$2.9 million from $1.2 million in fiscal 2002, primarily due to management fees
and leasing income associated with our new leasing investment programs.

Our leasing expenses were $5.9 million in fiscal 2003, an increase of
$5.1 million from $745,000 in fiscal 2002, primarily due to expenses associated
with the expansion of our operations in connection with our new leasing
programs.

Year Ended September 30, 2002 Compared to Year Ended September 30, 2001

Our leasing revenues were $1.2 million in fiscal 2002, an increase of
$180,000 from $1.1 million in fiscal 2001, primarily due to lease income and
fees associated with the commencement of our new leasing operations.

Our leasing expenses were $745,000 in fiscal 2002, an increase of
$50,000 from $695,000 in fiscal 2001, primarily due to expenses associated with
the startup of our new leasing operations.

Results of Operations: Other Revenues, Costs and Expenses

Our interest, dividends, gains and other income was $7.4 million in
fiscal 2003, an increase of $1.9 million (36%) as compared to $5.5 million in
fiscal 2002. The following table sets forth information relating to interest and
other income during the periods indicated:

Years Ended September 30,
-----------------------------------------
2003 2002 2001
----------- ---------- -----------
(in thousands)

Dividend income........................................................... $ 2,628 $ 3,276 $ 2,170
Interest income........................................................... 671 1,242 3,199
Gains on sale of RAIT shares.............................................. 4,036 - -
Other..................................................................... 82 941 853
---------- ---------- ----------
$ 7,417 $ 5,459 $ 6,222
========== ========== ==========

Year Ended September 30, 2003 Compared to Year Ended September 30, 2002

Dividend income decreased $648,000 (20%) to $2.6 million in fiscal 2003
from $3.3 million in fiscal 2002. The decrease was due to the sale of RAIT
Investment Trust shares during the year ended September 30, 2003, thus lowering
our dividends received. Interest income decreased $571,000 (46%) to $671,000 in
fiscal 2003 from $1.2 million in fiscal 2002. This decrease was the result of a
decrease in funds invested and as well as interest rates earned on those funds.
Gains on sale of RAIT shares for the year ended September 30, 2003 were $4.0
million. There were no such sales in the year ended September 30, 2002. Other
income decreased $859,000 to $82,000 in fiscal 2003 from $941,000 in fiscal 2002
due to gains associated with the sale of certain gas and oil assets in fiscal
2002 which were not located within the Appalachian basin and thus did not fit
our business model.

Our general and administrative expenses decreased $964,000 (12%) to
$6.9 million in fiscal 2003 from $7.9 million in fiscal 2002. This decrease
primarily resulted from the allocation of greater amounts of salaries and
benefits to our energy and leasing segments, which reflects management time
spent on these segments as a result of their growth and a decrease in our
pension costs. These decreases were partially offset by an increase in
professional services associated with a proposed offering of debt securities
that we terminated prior to completion.

Our provision for possible losses increased $455,000 (33%) to $1.8
million in fiscal 2003 as compared to $1.4 million in fiscal 2002. This increase
resulted primarily from estimated reductions in future cash flows from a
property underlying one of our loans. In the year ended September 30, 2003, we
foreclosed on the property underlying this loan and three other loans. In
addition, in the year ended September 30, 2002, we recovered $117,000 previously
written off due to the bankruptcy filing of an energy customer, thus reducing
our expense in the prior period.

Our provision for legal settlement represents the estimated cost
associated with the settlement of an action filed by the former chairman of TRM
Corporation as described in Note 15 of our consolidated financial statements. To
the extent that our actual cost (because of insurance recovery) is less than the
provision, it will be recorded as a reduction to our expenses in the period so
determined.

We own 39% of the partnership interests in Atlas Pipeline Partners
through both our general partner interest and the subordinated units we received
at the closing of Atlas Pipeline Partners' public offering. During the year
ended September 30, 2003, our ownership interest in Atlas Pipeline decreased
from 51% to 39% as the result of the completion by Atlas Pipeline of an offering
of limited partner common units. Because we control the operations of Atlas
Pipeline Partners, we include it in our consolidated financial statements and
show the ownership by the public as a minority interest. The minority interest
in Atlas Pipeline Partners earnings was $4.4 million for the year ended
September 30, 2003, as compared to $2.6 million for the twelve months September
30, 2002, an increase of $1.8 million (70%). This increase was the result of an
increase in Atlas Pipeline Partners' net income principally caused by increases
in transportation volumes and rates received and the increase in the percentage
interest of common unitholders. Atlas Pipeline Partners' transportation rates
vary, to a significant extent, with the price of natural gas which, on average,
was higher in fiscal 2003 than fiscal 2002.

Our effective tax rate increased to 32% in fiscal 2003 as compared to
29% in fiscal 2002 as a result of a reduction in statutory depletion and certain
tax credits, partially offset by a decrease in state income taxes.

Year Ended September 30, 2002 Compared to Year Ended September 30, 2001

Our dividend income from RAIT in fiscal 2002, increased due to the
purchase in December 2001 of an additional 125,000 RAIT shares; additionally,
the amount of dividends declared by RAIT increased. Interest income decreased
$2.0 million in fiscal 2002 to $1.2 million from $3.2 million due to the
continued decrease in our cash balances from the level at September 30, 2000
which was a result of the sale of our small ticket leasing subsidiary in August
2000, as well as to lower rates on those funds invested. During fiscal 2002 and
2001, such funds were used to invest in our drilling partnerships and to
repurchase our common stock. Gains on sales of property and equipment increased
primarily due to the sale of certain gas and oil assets which were not located
within the Appalachian basin and thus did not fit our business model for our
exploration and production operations.

Our general and administrative expenses increased $2.2 million (39%) to
$7.9 million in fiscal 2002, from $5.7 million in fiscal 2001. This increase
primarily resulted from increases in salaries and benefits, including health
insurance, and increases in the costs of our professional services.

Our interest expense was $12.8 million in fiscal 2002, a decrease of
$1.9 million (13%) from $14.7 million in fiscal 2001. This decrease primarily
resulted from our repurchase of senior notes during fiscal 2002, which reduced
interest by $1.2 million in as compared to fiscal 2001. In addition, in energy
and real estate finance, our interest expense decreased $867,000 due to
decreases in short-term interest rates in fiscal 2002 as compared to fiscal 2001
which reduced rates under our credit facilities.

Our provision for possible losses was $1.4 million in fiscal 2002, an
increase of $530,000 (61%) from $863,000 in fiscal 2001. The increase resulted
from a $910,000 increase in the allowance for possible losses associated with
the write-down of one real estate loan which was sold during fiscal 2002 and an
increase in the general allowance for possible losses, offset by the recovery in
fiscal 2002 of $117,000 from an account previously written off due to the
bankruptcy filing of an energy customer.

Our provision for legal settlement represents the maximum amount of our
out-of-pocket liability for the settlement of an amended class action complaint
instituted in October 1998. To the extent that our actual cost is less than the
provision, we will recognize income.

In fiscal 2002 and 2001, we owned 51% of the partnership interests in
Atlas Pipeline Partners through both our general partners' interest and the
subordinated units we received at the closing of Atlas Pipeline Partners' public
offering. The minority interest in Atlas Pipeline Partners is the interest of
Atlas Pipeline Partners' common unitholders. Because we owned more than 50% of
Atlas Pipeline Partners, we included it in our consolidated financial statements
for fiscal 2002 and 2001 and showed the ownership by the public as a minority
interest. The minority interest in Atlas Pipeline Partners earnings was $2.6
million for the twelve months ended September 30, 2002, as compared to $4.1
million for the twelve months ended September 30, 2001, a decrease of $1.5
million (36%). This decrease was the result of a decrease in Atlas Pipeline
Partners' net income principally caused by decreases in transportation fees
received. These fees vary with the price of natural gas, which on average was
lower in fiscal 2002 than fiscal 2001.

Our effective tax rate decreased to 29% in fiscal 2002 as compared to
31% in fiscal 2001 as a result of differences between book and taxable income
related to permanently non-deductible goodwill amortization and excess employee
remuneration in 2001 and an increase in 2002 in statutory depletion, which were
partially offset by an increase in 2002 in state income taxes.

Discontinued Operations

Year Ended September 30, 2003 Compared to Year Ended September 30, 2002

In accordance with SFAS 144 "Accounting for the Impairment or Disposal
of Long Lived Assets," our decision in fiscal 2002 to dispose of Optiron
Corporation, our former energy technology subsidiary, resulted in the
presentation of Optiron as a discontinued operation for the three years ended
September 30, 2003. We had held a 50% equity interest in Optiron; as a result of
the disposition, we currently hold a 10% equity interest in Optiron.

The plan of disposal required Optiron to pay to the Company 10% of
Optiron's revenues if such revenues exceeded $2.0 million in the twelve month
period following the closing of the transaction. As a result, Optiron became
obligated to pay us $295,000. The payment is due in March 2004.

Year Ended September 30, 2002 Compared to Year Ended September 30, 2001

On August 1, 2000, we sold our small ticket equipment leasing
subsidiary, Fidelity Leasing, Inc., to European American Bank and AEL Leasing
Co., Inc., subsidiaries of ABN AMRO Bank, N.V. We received total consideration
of $152.2 million, including repayment of indebtedness of Fidelity Leasing to
us; the purchasers also assumed approximately $431.0 million in debt payable to
third parties and other liabilities. Of the $152.2 million consideration, $16.0
million was paid by a non-interest bearing promissory note. The promissory note
is payable to the extent that payments are made on a pool of Fidelity Leasing
lease receivables and refunds are received with respect to certain tax
receivables. In addition, $10.0 million was placed in escrow as security for our
indemnification obligations to the purchasers.

The successor in interest to the purchaser, made a series of claims
with respect to our indemnification obligations and representations which were
settled in December 2002. Under the settlement, we and the successor were
released from certain terms and obligations of the original purchase agreements
and from claims arising from circumstances known at the settlement date. In
addition, we (i) released to the successor the $10.0 million escrow fund; (ii)
paid the successor $6.0 million; (iii) guaranteed that the successor will
receive payments of $1.2 million from a note, secured by FLI lease receivables,
delivered at the close of the FLI sale; and (iv) delivered two promissory notes
to the successor, each in the principal amount of $1.75 million, bearing
interest at the two-year treasury rate plus 500 basis points, and due on
December 31, 2003 and 2004, respectively. We recorded a loss from discontinued
operations, net of taxes, of $9.4 million in connection with the settlement.

Cumulative Effect of Change in Accounting Principle

The cumulative effect of change in accounting principle in fiscal 2002
relates to Optiron which adopted SFAS 142 on January 1, 2002, and as a result of
this adoption, realized an impairment and write-down on its books of goodwill
associated with the on-going viability of the product with which the goodwill
was associated. This impairment resulted in a cumulative effect adjustment of
$1.9 million on Optiron's books, and as a result, we recorded our 50% share of
this adjustment.

In January 2003, the FASB issued Interpretation 46, "Consolidation of
Variable Interest Entities". This interpretation changed the method of
determining whether certain entities called variable interest entities ("VIE")
should be included in our consolidated financial statements. The analysis of
whether an entity is a VIE and a result, must be consolidated is based on an
analysis of risks and rewards, not control, and represents a significant and
complex modification of previous accounting principles. Under FIN 46, VIE is an
entity that has (1) equity that is insufficient to permit the entity to finance
its activities without additional subordinated financial support from other
parties, or (2) equity investors that cannot make significant decisions about
the entity's operations, or that do not absorb the expected losses or receive
the expected residual returns of the entity. A VIE must be consolidated by its
primary beneficiary, which is the party involved with the VIE that has exposure
to a majority of the expected losses or a majority of the expected residual
returns or both. All other entities are evaluated for consolidation in
accordance with SFAS No. 94, "Consolidation of All Majority-Owned Subsidiaries"
("SFAS 94").

FIN 46 is applicable to VIEs created after January 31, 2003, and to
VIEs in which an enterprise obtains an interest after that date. For VIEs in
which an enterprise holds an interest that it acquired before February 1, 2003,
FIN 46 is applicable for financial statements issued for the first period ending
after December 15, 2003. For any VIEs that must be consolidated under FIN 46,
the assets, liabilities and non-controlling interest of the VIE are initially
measured at their carrying amounts, as defined in FIN 46, with any difference
between the net amount added to the balance sheet and the value at which the
primary beneficiary carried its interest in the VIE prior to the adoption of FIN
46 being recognized as a cumulative effect of a change in accounting principle.
If determining the carrying amounts is not practicable, the fair value at the
date of adoption may be used to measure the assets, liabilities and
non-controlling interests of the VIE. We have determined that it was not
practicable to determine the carrying values of the VIE's as of the date of the
qualifying event and accordingly, have used the fair values at the date of
adoption, July 1, 2003.

As encouraged by the pronouncement, we early-adopted FIN 46 on July 1,
2003. Consequently, certain entities relating to our real estate finance
business have been consolidated in its financial statements for the first time.
Several factors that distinguish these entities from others included in our
consolidated statements follow:

o The assets and liabilities, revenues and expenses of the consolidated
VIEs are included in our financial statements. The investments in
real estate loans and accreted interest income thereon, which were
our variable interests in the VIEs, have been removed from the
financial statements.

o We consolidated the VIEs because we determined that we were the
primary beneficiary of these entities within the meaning of FIN 46.

o The assets and liabilities of the VIEs that are now included in our
consolidated financial statements are neither our assets nor our
liabilities. Liabilities of the VIE can only be satisfied from the
VIE's assets, not our assets, nor can we use the VIE's assets to
satisfy our obligations.

As of July 1, 2003, the date of adoption, the consolidation of FIN 46
entities resulted in the addition of $296.5 million in assets, $185.5 million in
liabilities to our consolidated balance sheet and in a $13.9 million after-tax
cumulative effect adjustment in our fourth fiscal quarter. In addition, because
we classified certain of our FIN 46 assets as being held for sale, the
operations of those assets are recognized in our consolidated statement of
operations as income (loss) from discontinued operations. We recognized $1.0
million of such income (net of income taxes) in fiscal 2003.

FIN 46 has been the subject of significant continuing interpretation by
the FASB, and changes to its complex requirements are possible. Currently, it is
not possible to conclude whether such changes would be likely to affect the
amounts we have recorded.

Liquidity and Capital Resources

General. Our major sources of liquidity have been funds generated by
operations, funds raised and fees earned from investor partnerships, resolutions
of real estate loans, borrowings under our existing energy, real estate finance,
leasing and corporate credit facilities and the sale of our RAIT Investment
Trust shares. We have employed these funds principally in the expansion of our
energy operations, the repurchase of our senior notes and common stock, the
repayment of our energy credit facility and the acquisition of senior lien
interests relating to our real estate loans. The following table sets forth our
sources and uses of cash for the periods indicated:

Years Ended September 30,
------------------------------------------
2003 2002 2001
----------- ----------- ------------
(in thousands)

Provided by continuing operations......................................... $ 43,007 $ 6,467 $ 19,058
Used in investing activities.............................................. (13,978) (24,504) (28,020)
Used in financing activities.............................................. (8,012) (3,477) (58,385)
Used in discontinued operations........................................... (5,624) (1,398) (1,112)
------------ ------------ ------------
Increase (decrease) in cash and cash equivalents.......................... $ 15,393 $ (22,912) $ (68,459)
=========== ============ ============

Our liquidity is affected by national, regional and local economic
trends and uncertainties as well as trends and uncertainties more particular to
us, including natural gas prices, interest rates and our ability to raise funds
through our sponsorship of investment partnerships. While the current favorable
natural gas pricing and interest rate environment have been positive
contributors to our liquidity, and lead us to believe that we will be able to
refinance, or renew, our indebtedness as it matures, there are numerous risks
and uncertainties involved. We describe factors affecting our liquidity, as well
as the risks and uncertainties relating to our ability to generate this
liquidity, in Item 1, "Business - Risk Factors" and in this item in "Results of
Operations," "Changes in Prices and Inflation," and "-Contractual Obligations
and Commercial Commitments."

In fiscal 2004, our liquidity will be affected by our redemption of our
senior notes, as described in Item 1, Business - General."

Year Ended September 30, 2003 Compared to Year Ended September 30, 2002

We had $41.1 million in cash and cash equivalents on hand at September
30, 2003 as compared to $25.7 million at September 30, 2002. Our ratio of
earnings (from continuing operations before income taxes, minority interest and
interest expense) to fixed charges was 2.5 to 1.0 in the fiscal year ended
September 30, 2003 as compared to 2.1 to 1.0 in the fiscal year ended September
30, 2002.

Our working capital at September 30, 2003 was $30.3 million, an
increase of $28.2 million from $2.1 million at September 30, 2002. This increase
primarily resulted from the classification of $81.2 million of our FIN 46 assets
(net of related liabilities) as held for sale, partially offset by the
classification of the outstanding $54.0 million principal amount of our senior
notes as current liabilities due to their August 1, 2004 maturity date. Our
long-term debt (including current maturities) to total capital ratio at
September 30, 2003 was 59% as compared to 66% at September 30, 2002.

Cash flows from operating activities. Cash provided by operations is an
important source of short-term liquidity for us. Net cash provided by operating
activities increased $36.5 million in fiscal 2003, as compared to fiscal 2002,
primarily due to the following:

o Operating assets and liabilities increased $28.4 million primarily as
a result of an increase in deferred revenues on drilling contracts at
September 30, 2003 as compared to September 30, 2002, due to the
timing of investor funds raised and the subsequent use of those funds
in our drilling programs.

o Gas and oil production revenues increased $9.7 million primarily
attributable to a 38% increase in the average price we received for
our natural gas production.

o Offsetting these increases in operating cash flow was a decrease in
collections of interest of $4.1 million associated with our real
estate finance segment due in part to our adoption of FIN 46.

Cash flows from investing activities. Net cash used in our investing
activities decreased $10.5 million in fiscal 2003 as compared to fiscal 2002,
primarily due to the following:

o A realization of net proceeds of $12.0 million from sale of RAIT
shares in fiscal 2003 as compared to a use of $1.9 million to acquire
RAIT shares in fiscal 2002.

o A decrease of $13.9 million in investments in real estate loans and
real estate in fiscal 2003 as compared to 2002.

o A decrease of $4.6 million in cash spent on other assets due
principally to investments with the commencement of the Trapeza
entities and our equipment leasing operation in fiscal 2002,

o Offsetting these items was a decrease of $15.2 million in principal
payments on notes receivable and proceeds from sale of assets.

o An increase in capital expenditures of $6.6 million associated with
the expansion of our energy operations.

Cash flows from financing activities. Net cash used in our financing
activities increased $4.5 million in fiscal 2003 as compared to fiscal 2002,
primarily due to the following

o An increase in net repayments of debt of $28.3 million in fiscal
2003 as compared to fiscal 2002.

o An increase in purchases of treasury stock of $3.1 million in fiscal
2003 as compared to fiscal 2002.

o Offsetting these increases were net proceeds of $25.2 million from
Atlas Pipeline's public offering in fiscal 2003.

o An increase in proceeds from issuance of stock of $2.9 million in
fiscal 2003 as compared to fiscal 2002.

Year Ended September 30, 2002 Compared to Year Ended September 30, 2001

We had $25.7 million in cash and cash equivalents on hand at September
30, 2002 as compared to $48.6 million at September 30, 2001. Our ratio of
earnings (from continuing operations before income taxes, minority interest and
interest expense) to fixed charges was 2.1 to 1.0 in the fiscal year ended
September 30, 2002 as compared to 2.7 to 1.0 in the fiscal year ended September
30, 2001.

Our working capital at September 30, 2002 was $2.1 million, a decrease
of $23.8 million from $25.9 million at September 30, 2001 primarily as a result
of our use of the proceeds received from the sale of our equipment leasing
subsidiary. Our long-term debt (including current maturities) to total capital
ratio at September 30, 2002 was 67% as compared to 64% at September 30, 2001.

Cash flows from operating activities. Net cash provided by operating
activities decreased $12.6 million in fiscal 2002, as compared to fiscal 2001,
primarily due to the following:

o Gas and oil production revenues decreased $7.6 million, primarily
attributable to a 29% and 20% decrease in the price we received for
our natural gas and oil production, respectively.

o The timing of investor funds raised and the subsequent use of those
funds in our drilling activities decreased operating cash flow by
$14.0 million in fiscal 2002 as compared to fiscal 2001. A larger
amount of funds were received at September 30, 2001, but not spent on
our drilling activities until fiscal 2002.

o Prepaid expenses by our equipment leasing operations increased $1.9
million in fiscal 2002 compared to fiscal 2001. This increase was
attributable to costs incurred by us which are reimbursable from a
public partnership that is currently in its offering stage, depending
upon the funds raised by that partnership.

o Offsetting these decreases in operating cash flow was an increase of
$10.1 million due to lesser amounts owed and paid for income taxes
for fiscal 2002 as compared to fiscal 2001.

Cash flows from investing activities. Net cash used in our investing
activities decreased $3.5 million in fiscal 2002 as compared to fiscal 2001. Our
investing activities primarily consisted of capital expenditures for
developmental drilling, expansion of Atlas Pipeline Partners' gas gathering
facilities and investments in our real estate loans. The decrease in fiscal 2002
was due to $2.4 million decrease in payments received on a note issued in
conjunction with the sale of our small ticket leasing subsidiary and a $2.2
million decrease in payments received from our real estate investments. Payments
received on real estate investments are normally dependent on third party
refinancing or from the sale of a loan and vary from period to period.

Cash flows from financing activities. Net cash used in our financing
activities decreased $54.9 million in fiscal 2002 as compared to fiscal 2001.
The decrease in fiscal 2002 was primarily due to our repurchase of $54.7 million
of our common stock in fiscal 2001 through our dutch auction tender offer.

Capital Requirements

During fiscal 2003, our capital requirements related primarily to our
investments in our drilling partnerships and pipeline extensions. In fiscal
2003, we invested approximately $26.6 million in our drilling partnerships and
pipeline extensions as compared to $21.3 million in fiscal 2002. We funded these
capital expenditures through cash on hand, borrowings under our credit
facilities, and from operations. We obtained an increase in our borrowing base
on our Wachovia credit facility to $54.2 million in fiscal 2003. Atlas Pipeline
also increased its credit facility to $20.0 million to fund its growth and
expansion.

We have a wide degree of discretion in the level of capital
expenditures we must devote in our energy operations on an annual basis and the
timing of those expenditures. The amount of our expenditures depends upon the
level of funds raised through investment partnerships. We believe cash flow from
operations and amounts available under our credit facilities will be adequate to
fund our contributions to these partnerships. The level of our capital
expenditures will vary in the future depending on commodity market conditions,
among others things.

We continuously evaluate acquisitions of gas and oil and pipeline
assets. If we make any acquisitions, we believe we will be required to access
outside capital either through debt or equity placements or through joint
venture operations with other energy companies. There can be no assurance that
we will be successful in our efforts to obtain outside capital.

Pending Acquisition

As described in Note 16 to our consolidated financial statements, Atlas
Pipeline Partners has agreed to acquire Alaska Pipeline Company for $95.0
million. The acquiring entity will be a special purpose vehicle, or SPV, created
by Atlas Pipeline Partners. Atlas Pipeline Partners anticipates that expenses in
connection with the transaction will be approximately $4.0 million. The
acquisition is contingent upon the satisfaction of certain conditions,
principally the approval of the transaction by the Regulatory Commission of
Alaska and the expiration of waiting periods under the Hart-Scott-Rodino
Antitrust Improvements Act. The Hart-Scott-Rodino waiting period terminated in
January 2004. If, as we believe will be the case, Atlas Pipeline Partners
obtains these approvals and consummates the transaction, it intends to fund the
acquisition price and expenses as follows:

o Atlas Pipeline Partners will invest $24.4 million in common equity of
the SPV. It will fund this investment by borrowing all of the $20.0
million available under its existing credit facility and through $4.4
million of advances from us.

o Friedman, Billings, Ramsey Group, Inc. has committed to make a $25.0
million preferred equity investment the SPV which will be jointly
owned by FBR and Atlas Pipeline Partners.

o The SPV has received a commitment for a $50.0 million credit facility
to be administered by Wachovia Bank. It will borrow $50.0 million
under this facility.

All of this funding will be consolidated in our financial statements as
indebtedness. Atlas Pipeline Partners may seek to replace or repay the funding
from FBR and some portion of either or both of the Wachovia Bank credit
facilities with equity capital obtained through an offering of Atlas Pipeline
Partners' common units. If Atlas Pipeline Partners determines not to make an
offering of our common units or seek other alternative financing, the debt and
preferred equity financings will remain in place. Although the continuation of
these financings may reduce our capacity for further borrowing and reduce the
amount of cash from operations that would otherwise be available from the
combination of Atlas Pipeline Partners' operations with those of Alaska
Pipeline Company, we believe that our remaining liquidity and capital resources
would be more than sufficient to meet our post-acquisition operational needs.

Changes in Prices and Inflation

Our revenues, the value of our assets, our ability to obtain bank loans
or additional capital on attractive terms and our ability to finance our
drilling activities through drilling investment partnerships have been and will
continue to be affected by changes in oil and gas prices. Natural gas and oil
prices are subject to significant fluctuations that are beyond our ability to
control or predict. During fiscal 2003, we received an average of $4.92 per Mcf
of natural gas and $26.91 per Bbl of oil as compared to $3.56 per Mcf natural
gas and $20.45 per Bbl oil in fiscal 2002 and $5.04 per Mcf and $25.56 per Bbl
of oil in fiscal 2001.

Although certain of our costs and expenses are affected by general
inflation, inflation has not normally had a significant effect on us. However,
inflationary trends may occur if the price of natural gas were to increase since
such an increase may increase the demand for acreage and for energy equipment
and services, thereby increasing the costs of acquiring or obtaining such
equipment and services.

Environmental Regulation

To date, compliance with environmental laws and regulations has not had
a material impact on our capital expenditures, earnings or competitive position.
We cannot assure you that compliance with environmental laws and regulations
will not, in the future, materially adversely affect our operations through
increased costs of doing business or restrictions on the manner in which we
conduct our operations.

Dividends

In the years ended September 30, 2003, 2002 and 2001, we paid dividends
of $2.3 million, $2.3 million and $2.4 million, respectively. We have paid
regular quarterly dividends since August 1995.

The determination of the amount of future cash dividends, if any, is at
the sole discretion of our board of directors and will depend on the various
factors affecting our financial condition and other matters the board of
directors deems relevant. While we were subject to restrictions on our payment
of dividends imposed by the indenture under which our senior notes were issued,
these restrictions will lapse upon completion of the redemption of our senior
notes. See "Business - General."

Contractual Obligations and Commercial Commitments

The following tables set forth our obligations and commitments as of
September 30, 2003.

Payments Due By Period
(in thousands)
------------------------------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual cash obligations: Total 1 Year Years Years Years
-------------- -------------- --------------- ------------ -------------

Long-term debt........................... $ 133,167 $ 59,471 $ 73,660 $ 36 $ -
Secured revolving credit facilities...... 7,168 7,168 - - -
Capital lease obligations................ - - - - -
Operating leases......................... 3,910 1,217 1,792 900 1
Unconditional purchase obligations....... - - - - -
Other long-term obligations.............. - - - - -
----------- ----------- ----------- ----------- ---------
Total contractual cash obligations....... $ 144,245 $ 67,856 $ 75,452 $ 936 $ 1
=========== =========== =========== =========== =========

Amount of Commitment Expiration Per Period
(in thousands)
------------------------------------------------------------------
Less than 1 - 3 4 - 5 After 5
Other commercial commitments: Total 1 Year Years Years Years
-------------- -------------- --------------- ------------ -------------

Lines of credit........................ $ - $ - $ - $ - $ -
Standby letters of credit.............. 1,945 1,275 420 250 -
Guarantees............................. 1,161 1,161 - -
Standby replacement commitments........ 6,363 1,732 4,631 - -
Other commercial commitments........... 257,090 3,211 62,398 66,033 125,448
----------- ----------- ------------ ---------- ----------
Total commercial commitments........... $ 266,559 $ 7,379 $ 67,449 $ 66,283 $ 125,448
=========== =========== ============ ========== ==========

Critical Accounting Policies

The discussion and analysis of our financial condition and results of
operations is based upon our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States of America. The preparation of these financial statements requires
us to make estimates and judgments that affect the reported amounts of our
assets, liabilities, revenues, costs and expenses, and related disclosure of
contingent assets and liabilities. On an on-going basis, we evaluate our
estimates, including those related to bad debts, deferred tax assets and
liabilities, goodwill and identifiable intangible assets, and certain accrued
liabilities. We base our estimates on historical experience and on various other
assumptions that we believe reasonable under the circumstances, the results of
which form the basis for making judgments about the carrying values of assets
and liabilities that are not readily apparent from other sources. Actual results
may differ from these estimates under different assumptions or conditions.

We have identified the following policies as critical to our business
operations and the understanding of our results of operations.

Accounts Receivable and Investments in Real Estate Loans, Ventures and
Allowance for Possible Losses.

Through our business segments, we engage in credit extension,
monitoring, and collection.

In energy, in evaluating our allowance for possible losses, we perform
ongoing credit evaluations of our customers and adjust credit limits based upon
payment history and the customer's current creditworthiness, as determined by
our review of our customer's credit information. We extend credit on an
unsecured basis to many of our energy customers. At September 30, 2003, our
credit evaluation indicated that we have no need for an allowance for possible
losses for our oil and gas receivables.

In real estate finance, in evaluating the carrying value of our
investments and our allowance for possible losses, we consider general and local
economic conditions, neighborhood values, competitive overbuilding, casualty
losses and other factors which may affect the value of our loans. The value of
our investments may also be affected by factors such as the cost of compliance
with regulations and liability under applicable environmental laws, changes in
interest rates and the availability of financing. Income from a property will be
reduced if a significant number of tenants are unable to pay rent or if
available space cannot be rented on favorable terms. We reduce our investment in
real estate loans by an allowance for amounts that may become unrealizable in
the future. Such allowance can be either specific to a particular loan or
venture or general to all loans or ventures. As of September 30, 2003 and 2002,
we had investments in real estate loans and real estate of $68.9 million and
$202.4 million, net of an allowance for possible losses of $1.4 million and $3.5
million, respectively. We believe our allowance for possible losses is adequate
at September 30, 2003. However, an adverse change in the facts and circumstances
with regard to one of our larger loans or ventures could cause us to experience
a loss in excess of our allowance.

In equipment leasing, in evaluating our allowance for possible losses,
we consider our contractual delinquencies, economic conditions and trends,
industry statistics, lease portfolio characteristics and management's prior
experience with similar lease assets. At September 30, 2003, our credit
evaluation indicated that we have no need for an allowance for possible losses
for our lease assets.

We believe that our allowance for possible losses is reasonable based
on our experience and our analysis of the net realizable value of our
receivables at September 30, 2003.

Reserve Estimates

Our estimates of our proved natural gas and oil reserves and future net
revenues from them are based upon reserve analyses that rely upon various
assumptions, including those required by the SEC, as to natural gas and oil
prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. Any significant variance in these assumptions could
materially affect the estimated quantity of our reserves. As a result, our
estimates of our proved natural gas and oil reserves are inherently imprecise.
Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves may vary substantially from our estimates or
estimates contained in the reserve reports and may affect our ability to pay
amounts due under our credit facilities or cause a reduction in our energy
credit facilities. In addition, our proved reserves may be subject to downward
or upward revision based upon production history, results of future exploration
and development, prevailing natural gas and oil prices, mechanical difficulties,
governmental regulation and other factors, many of which are beyond our control.

Impairment of Oil and Gas Properties

We review our producing oil and gas properties for impairment on an
annual basis and whenever events and circumstances indicate a decline in the
recoverability of their carrying values. We estimate the expected future cash
flows from our oil and gas properties and compare such future cash flows to the
carrying amount of the oil and gas properties to determine if the carrying
amount is recoverable. If the carrying amount exceeds the estimated undiscounted
future cash flows, we will adjust the carrying amount of the oil and gas
properties to their fair value in the current period. The factors used to
determine fair value include, but are not limited to, estimates of reserves,
future production estimates, anticipated capital expenditures, and a discount
rate commensurate with the risk associated with realizing the expected cash
flows projected. Because of the complexities associated with oil and gas reserve
estimates and the history of price volatility in the oil and gas markets, events
may arise that will require us to record an impairment of our oil and gas
properties. Any such impairment may affect or cause a reduction in our energy
credit facilities.

Dismantlement, Restoration, Reclamation and Abandonment Costs

On an annual basis, we estimate the costs of future dismantlement,
restoration, reclamation and abandonment of our natural gas and oil-producing
properties. We also estimate the salvage value of equipment recoverable upon
abandonment. On October 1, 2002 we adopted SFAS 143, as discussed in Note 2 to
our consolidated financial statements. As of September 30, 2002 and 2001, our
estimate of salvage values was greater than or equal to our estimate of the
costs of future dismantlement, restoration, reclamation and abandonment. A
decrease in salvage values or an increase in dismantlement, restoration,
reclamation and abandonment costs from those we have estimated, or changes in
our estimates or costs, could reduce our gross profit from energy operations.

Goodwill and Other Long-Lived Assets

As of January 1, 2002, the accounting for goodwill has changed; in
prior years, goodwill was amortized. As of January 1, 2002, goodwill and other
intangibles with an indefinite useful life are no longer amortized, but instead
are assessed for impairment at least annually. We have recorded goodwill of
$37.5 million in connection with several acquisitions of assets. In assessing
impairment of goodwill, we use estimates and assumptions in estimating the fair
value of reporting units. If under these estimates and assumptions we determine
that the fair value of a reporting unit has been reduced, the reduction can
result in an "impairment" of goodwill. However, future results could differ from
the estimates and assumptions we use. Events or circumstances which might lead
to an indication of impairment of goodwill would include, but might not be
limited to, prolonged decreases in expectations of long-term well servicing
and/or drilling activity or rates brought about by prolonged decreases in
natural gas or oil prices, changes in government regulation of the natural gas
and oil industry or other events which could affect the level of activity of
exploration and production companies.

In assessing impairment of long-lived assets other than goodwill, where
there has been a change in circumstances indicating that the carrying amount of
a long-lived asset may not be recoverable, we have estimated future undiscounted
net cash flows from the use of the asset based on actual historical results and
expectations about future economic circumstances, including natural gas and oil
prices and operating costs. Our estimate of future net cash flows from the use
of an asset could change if actual prices and costs differ due to industry
conditions or other factors affecting our performance.

Intangible Assets

In connection with a review of our financial statements by the staff of
the Securities and Exchange Commission, we have been made aware that an issue
has arisen within the industry regarding the application of provisions of
Statement of Financial Accounting Standards No. 141, "Business Combinations,"
and Statement of Financial Accounting Standards No. 142, "Goodwill and Other
Intangible Assets" (SFAS No. 142), to companies in the extractive industries,
including gas and oil companies. The issue is whether SFAS No. 142 requires
companies to reclassify costs associated with mineral rights, including both
proved and unproved leasehold acquisition costs, as intangible assets in the
balance sheet, apart from other capitalized gas and oil property costs.
Historically, we and other gas and oil companies have included the cost of these
gas and oil leasehold interests as part of gas and oil properties. Also under
consideration is whether SFAS No. 142 requires companies to provide the
additional disclosures prescribed by SFAS No. 142 for intangible assets for
costs associated with mineral rights.

If it is ultimately determined that SFAS No. 142 requires us to
reclassify costs associated with mineral rights from property and equipment to
intangible assets, the amounts that would be reclassified would be immaterial to
our financial position. The reclassification of these amounts would not affect
the method in which such costs are amortized or the manner in which we assess
impairment of capitalized costs. As a result, our cash flows and results of
operations would not be affected by the reclassification.

Recently Issued Financial Accounting Standards

In July 2002, SFAS No. 146, "Accounting for Costs Associated with Exit
or Disposal Activities" was issued. SFAS 146 is effective for exit or disposal
activities initiated after December 31, 2002. The adoption of SFAS 146 did not
have a material effect on our financial position or results of operations.

In April 2003, the FASB issued SFAS No. 149 ("SFAS 149") "Amendment of
Statement 133 on Derivative Instruments and Hedging Activates." SFAS 149 is
effective for contracts entered into or modified after June 30, 2003 and amends
and clarifies financial accounting and reporting for derivative instruments. The
adoption of SFAS 149 did not have a material effect on our financial position or
results of operations.

In May 2003, the FASB issued Statement No. 150 ("SFAS 150") "Accounting
for Certain Financial Instruments with Characteristics of Both Liabilities and
Equity." SFAS 150 requires that certain instruments that were previously
classified as equity on a company's statement of financial position now be
classified as liabilities. SFAS 150 is effective for financial instruments
entered into or modified after May 31, 2003, and otherwise is effective at the
beginning of the first interim period beginning after June 15, 2003. The
adoption of SFAS did not have a material impact on our results of operations or
financial position.

In November 2002, the FASB issued Interpretation 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 clarifies the
requirements of FASB Statement of Financial Accounting Standards No. 5,
Accounting for Contingencies ("SFAS 5") relating to a guarantor's accounting
for, and disclosure of, the issuance of certain types of guarantees. FIN 45
provides for additional disclosure requirements related to guarantees which
were effective for financial periods ending after December 15, 2002.
Additionally, FIN 45 outlines provisions for initial recognition and
measurement of the liability incurred in providing a guarantee. We adopted the
initial recognition and measurement requirements for all guarantees as of
January 1, 2003. The initial adoption of the recognition and measurement
requirements of FIN 45 did not have a significant impact on our results of
operations or financial position.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about our potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in interest rates and oil and gas prices. The
disclosures are not meant to be precise indicators of expected future losses,
but rather indicators of reasonable possible losses. This forward-looking
information provides indicators of how we view and manage our ongoing market
risk exposures. All of our market risk sensitive instruments were entered into
for purposes other than trading.

General

We are exposed to various market risks, principally fluctuating
interest rates and changes in commodity prices. These risks can impact our
results of operations, cash flows and financial position. We manage these risks
through regular operating and financing activities and periodically use
derivative financial instruments such as forward contracts and interest rate cap
and swap agreements.

The following analysis presents the effect on our earnings, cash flows
and financial position as if hypothetical changes in market risk factors
occurred on September 30, 2003. Only the potential impacts of hypothetical
assumptions are analyzed. The analysis does not consider other possible effects
that could impact our business.

Energy

Interest Rate Risk. At September 30, 2003, the amount outstanding under
our credit facility had decreased to $31.0 million from $43.7 million at
September 30, 2002. The weighted average interest rate for this facility
decreased from 3.86% at September 30, 2002 to 2.90% at September 30, 2003 due to
a decrease in market index rates used to calculate the facility's interest
rates. Holding all other variables constant, if interest rates hypothetically
increased or decreased by 10%, our net income would change by approximately
$61,000.

Commodity Price Risk. Our major market risk exposure in commodities is
fluctuating prices for our natural gas and oil production. Realized pricing is
primarily driven by the prevailing worldwide prices for crude oil and spot
market prices applicable to United States natural gas production. Pricing for
natural gas and oil production has been volatile and unpredictable for many
years. To limit our exposure to changing natural gas prices we use hedges.
Through our hedges, we seek to provide a measure of stability in the volatile
environment of natural gas prices. Our risk management objective is to lock in a
range of pricing for expected production volumes. This allows us to forecast
future earnings within a predictable range.

We do not hold or issue derivative instruments for trading purposes.
Historically, we have entered into financial hedging activities for a portion of
our projected natural gas production. We recognize gains and losses from the
settlement of these hedges in gas revenues when the associated production
occurs. The gains and losses realized as a result of hedging are substantially
offset in the market when we deliver the associated natural gas. We determine
gains or losses on open and closed hedging transactions as the difference
between the contract price and a reference price, generally closing prices on
NYMEX. Net losses relating to these hedging contracts in fiscal 2003, 2002 and
2001 were $1.1 million, $59,000 and $599,000, respectively. We had no open hedge
transactions in place as of September 30, 2003.

In addition, FirstEnergy Solutions and other third party marketers to
which we sell gas, also use financial hedges to hedge their pricing exposure and
make price hedging opportunities available to us. These transactions are similar
to NYMEX-based futures contracts, swaps and options, but also require firm
delivery of the hedged quantity. Thus, we limit these arrangements to much
smaller quantities than those projected to be available at any delivery point.
For the fiscal year ending September 30, 2004, we estimate in excess of 50% of
our produced natural gas volumes will be sold in this manner, leaving our
remaining production to be sold at contract prices in the month produced or at
spot market prices. We also negotiate with certain purchasers for delivery of a
portion of natural gas we will produce for the upcoming twelve months. The
prices under most of our gas sales contracts are negotiated on an annual basis
and are index-based. Considering those volumes already designated for the fiscal
year ending September 30, 2004, and current indices, a theoretical 10% upward or
downward change in the price of natural gas would result in approximately a 5%
change in our projected natural gas revenues.

We periodically enter into financial hedging activities with respect to
a portion of our projected natural gas production. We recognize gains and losses
from the settlement of these hedges in gas revenues when the associated
production occurs. The gains and losses realized as a result of hedging are
substantially offset in the market when we deliver the associated natural gas.
We do not hold or issue derivative instruments for trading purposes. We
determine gains or losses on open and closed hedging transactions as the
difference between the contract price and a reference price, generally closing
prices on NYMEX. Net losses relating to these hedging contracts in fiscal 2003,
2002 and 2001 were $1.1 million, $59,000 and $599,000, respectively. We had no
open hedge transactions in place as of September 30, 2003.

Real Estate Finance

Portfolio Loans and Related Senior Liens. We believe that none of the
ten loans held in our portfolio as of September 30, 2003 (including loans
treated in our consolidated financial statements as FIN 46 assets and
liabilities) are sensitive to changes in interest rates since:

o the loans are subject to forbearance or other agreements that require
all of the operating cash flow from the properties underlying the
loans, after debt service on senior lien interests, to be paid to us
and thus are not currently being paid based on the stated interest
rates of the loans;

o the senior lien interests are at fixed rates and are thus not subject
to interest rate fluctuation that would affect payments to us; and

o each loan has significant accrued and unpaid interest and other
charges outstanding to which cash flow from the underlying property
would be applied even if cash flow were to exceed the interest due,
as originally underwritten.

Debt. The interest rates on our real estate revolving lines of credit,
which are at the prime rate minus 1% for the outstanding $6.4 million under our
line at Hudson United Bank and at the prime rate for the outstanding $18.0
million and $5.0 million lines of credit at Sovereign Bank, decreased during the
year ended September 30, 2003 because there were three decreases in the defined
prime rate. This defined prime rate was the "prime rate" as reported in The Wall
Street Journal (4.00% at September 30, 2003). A hypothetical 10% change in the
average interest rate applicable to these lines of credit would change our net
income by approximately $76,000.

Financial Services

LEAF Financial Corporation, our equipment-leasing subsidiary, entered
into a $10.0 million secured revolving credit facility with National City Bank
which terminates December 31, 2003. We guarantee this facility, outstanding
loans bear interest at one of two rates, elected at our option; (i) the lender's
prime rate plus 200 basis points, or (ii) LIBOR plus 300 basis points. As of
September 30, 2003, the balance outstanding was $2.5 million at an average
interest rate of 4.12%. LEAF Financial Corporation also has a $10.0 million
secured credit facility with Commerce Bank. The facility has the same interest
rate structure as the National City Bank facility and expires May 27, 2004. As
of September 30, 2003, the balance outstanding was $4.7 million at an average
interest rate of 4.10%. A hypothetical 10% change in the average interest rate
on these facilities would change our net income by approximately $20,000.

Other

In June 2002, we established a $5.0 million revolving line of credit
with Commerce Bank. The facility expires in May 2005 and bears interest at one
of two rates, elected at the borrower's option; (i) the prime rate, or (ii)
LIBOR plus 250 basis points; both of which are subject to a floor of 5.5% and a
ceiling of 9.0%. As of September 30, 2003, $5.0 million was outstanding under
this facility. A hypothetical 10% change in the average interest rate on this
facility would not affect our net income.

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Stockholders and Board of Directors
RESOURCE AMERICA, INC.

We have audited the accompanying consolidated balance sheets of Resource
America, Inc. (a Delaware corporation) and subsidiaries as of September 30, 2003
and 2002, and the related consolidated statements of operations, comprehensive
income, changes in stockholders' equity, and cash flows for each of the three
years in the period ended September 30, 2003. These financial statements and
Schedules I, III and IV are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements and
schedules based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Resource America,
Inc. and subsidiaries as of September 30, 2003 and 2002, and the consolidated
results of their operations and cash flows for each of the three years in the
period ended September 30, 2003, in conformity with accounting principles
generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, effective
October 1, 2002, the Company adopted Statement of Financial Accounting Standards
No. 143, Accounting for Asset Retirement Obligations, and changed its method of
accounting for its plugging and abandonment liability related to its oil and gas
wells and associated pipelines and equipment.

As discussed in Note 3 to the consolidated financial statements, effective July
1, 2003, the Company adopted FASB Interpretation 46, Consolidation of Variable
Interest Entities, and changed its method of accounting for certain investments
in real estate loans.

As discussed in Note 4 to the consolidated financial statements, effective
October 1, 2001, the Company changed its method of accounting for goodwill for
the adoption of Statement of Financial Accounting Standards No. 142, Goodwill
and Other Intangible Assets.

We have also audited Schedules I, III and IV as of September 30, 2003. In our
opinion, these schedules, considered in relation to the basic financial
statements taken as a whole, presents fairly, in all material respects, the
information required to be set forth therein.

Cleveland, Ohio
December 5, 2003

RESOURCE AMERICA, INC.
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 2003 AND 2002

2003 2002
----------- -----
(in thousands, except share data)

ASSETS
Current assets:
Cash and cash equivalents................................................. $ 41,129 $ 25,736
Accounts receivable and prepaid expenses.................................. 30,416 18,756
FIN 46 entities' and other assets held for sale........................... 222,677 5,488
---------- ----------
Total current assets.................................................... 294,222 49,980

Investments in real estate loans and real estate............................. 68,936 202,423
FIN 46 entities' assets...................................................... 78,247 -
Investment in RAIT Investment Trust.......................................... 20,511 29,580
Property and equipment, net.................................................. 143,410 119,177
Other assets................................................................. 19,509 19,278
Intangible assets............................................................ 8,476 9,589
Goodwill..................................................................... 37,471 37,471
---------- -----------
$ 670,782 $ 467,498
========== ==========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt......................................... $ 59,471 $ 4,320
Secured revolving credit facilities - leasing............................. 7,168 2,421
Accounts payable.......................................................... 19,065 12,378
FIN 46 entities' and other liabilities associated with assets held for sale 141,473 11,317
Accrued liabilities....................................................... 14,626 11,568
Estimated income taxes.................................................... - 893
Liabilities associated with drilling contracts............................ 22,158 4,948
---------- ----------
Total current liabilities............................................... 263,961 47,845

Long-term debt:
Senior.................................................................... - 65,336
Other..................................................................... 73,696 83,433
---------- ----------
73,696 148,769

Liabilities associated with assets held for sale............................. - 3,144
Deferred revenue and other liabilities....................................... 3,633 1,074
FIN 46 entities' liabilities................................................. 45,184 -
Deferred income taxes........................................................ 12,878 13,733
Minority interest in Atlas Pipeline Partners, L.P............................ 43,976 19,394
Commitments and contingencies................................................ - -

Stockholders' equity:
Preferred stock $1.00 par value: 1,000,000 authorized shares.............. - -
Common stock, $.01 par value: 49,000,000 authorized shares................ 255 250
Additional paid-in capital................................................ 227,211 223,824
Less treasury stock, at cost.............................................. (78,860) (74,828)
Less ESOP loan receivable................................................. (1,137) (1,201)
Accumulated other comprehensive income.................................... 5,611 5,911
Retained earnings......................................................... 74,374 79,583
---------- ----------
Total stockholders' equity.............................................. 227,454 233,539
---------- ----------
$ 670,782 $ 467,498
========== ==========

See accompanying notes to consolidated financial statements

RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED SEPTEMBER 30, 2003, 2002 AND 2001

2003 2002 2001
----------- ---------- ----------
(in thousands, except per share data)

REVENUES
Energy....................................................................... $ 105,262 $ 97,912 $ 94,806
Real estate finance.......................................................... 14,335 16,582 16,899
Leasing...................................................................... 4,071 1,246 1,066
Equity in earnings in Trapeza entities....................................... 1,444 185 -
Interest, dividends, gains and other......................................... 7,417 5,459 6,222
---------- ---------- ----------
132,529 121,384 118,993

COSTS AND EXPENSES
Energy....................................................................... 67,215 69,580 59,976
Real estate finance.......................................................... 5,464 2,423 1,504
Leasing...................................................................... 5,883 745 695
General and administrative................................................... 6,925 7,889 5,672
Depreciation, depletion and amortization..................................... 12,148 11,161 11,038
Interest..................................................................... 13,092 12,816 14,736
Provision for possible losses................................................ 1,848 1,393 863
Provision for legal settlement............................................... 1,185 1,000 -
Minority interest in Atlas Pipeline Partners, L.P............................ 4,439 2,605 4,099
---------- ---------- ----------
118,199 109,612 98,583
---------- ---------- ----------
Income from continuing operations before income taxes
and cumulative effect of change in accounting principle.................. 14,330 11,772 20,410
Provision for income taxes................................................... 4,586 3,414 6,327
---------- ---------- ----------
Income from continuing operations before
cumulative effect of change in accounting principle...................... 9,744 8,358 14,083
Income (loss) on discontinued operations, net of income taxes
of $(658), $5,944 and $2,439............................................. 1,222 (11,040) (4,254)
Cumulative effect of change in accounting principle, net of
income taxes of $7,474 and $336.......................................... (13,881) (627) -
---------- ---------- ----------

Net (loss) income............................................................ $ (2,915) $ (3,309) $ 9,829
========== ========== ==========

Net income (loss) per common share - basic:
From continuing operations................................................... $ .57 $ .48 $ .78
Discontinued operations...................................................... .07 (.63) (.23)
Cumulative effect of change in accounting principle.......................... (.81) (.04) -
---------- ---------- ----------
Net income (loss) per common share - basic................................... $ (.17) $ (.19) $ .55
========== ========== ==========
Weighted average common shares outstanding................................... 17,172 17,446 17,962
========== ========== ==========

Net income (loss) per common share - diluted:
From continuing operations................................................... $ .55 $ .47 $ .76
Discontinued operations...................................................... .07 (.62) (.23)
Cumulative effect of change in accounting principle.......................... (.79) (.04) -
---------- ---------- ----------

Net (loss) income per common share - diluted................................. $ (.17) $ (.19) $ .53
========== ========== ==========

Weighted average common shares outstanding................................... 17,568 17,805 18,436
========== ========== ==========

See accompanying notes to consolidated financial statements

RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME
YEARS ENDED SEPTEMBER 30, 2003, 2002 AND 2001

2003 2002 2001
---------- ------ -----
(in thousands)

Net (loss) income........................................................... $ (2,915) $ (3,309) $ 9,829
Other comprehensive (loss) income:
Unrealized gain on investment in RAIT Investment Trust,
net of taxes of $1,040, $2,305 and $1,350............................. 2,211 4,475 2,622
Less: reclassification adjustment for gains realized in net income, net of
taxes of $1,291........................................................ (2,744) - -
---------- ---------- ----------
(533) 4,475 2,622

Unrealized holding losses on natural gas futures arising during the period
net of taxes of $245, $118 and $181................................... (520) (263) (404)
Less: reclassification adjustment for losses realized in net income, net of
taxes of $355, $17 and $186............................................ 753 42 413
---------- ---------- ----------
233 (221) 9
---------- ---------- ----------
Comprehensive (loss) income................................................. $ (3,215) $ 945 $ 12,460
========== ========== ==========

See accompanying notes to consolidated financial statements

RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED SEPTEMBER 30, 2003, 2002, AND 2001
(in thousands, except share data)

Common Stock Additional Treasury Stock ESOP
------------------------ Paid-In -------------------- Loan
Shares Amount Capital Shares Amount Receivable
- ---------------------------------------------------------------------------------------------------------------------------------

Balance, September 30, 2000.................. 24,621,962 $ 246 $ 221,361 (1,029,982) $ (15,778) $ (1,393)
Treasury shares issued....................... (407) 33,916 804
Issuance of common stock..................... 318,075 3 2,758
Cancellation of shares issued................ (153,526) (1,305)
Purchase of treasury shares.................. (6,349,021) (57,801)
Other comprehensive income...................
Cash dividends ($.13 per share)..............
Repayment of ESOP loan....................... 96
Net income...................................
- ---------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2001.................. 24,940,037 $ 249 $ 223,712 (7,498,613) $ (74,080) $ (1,297)
Treasury shares issued....................... (429) 31,537 769
Issuance of common stock..................... 104,029 1 297
Tax benefit from employee stock 244
options......exercise........................
Purchase of treasury shares.................. (156,122) (1,517)
Other comprehensive income...................
Cash dividends ($.13 per share)..............
Repayment of ESOP loan....................... 96
Net loss.....................................
- ---------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2002.................. 25,044,066 $ 250 $ 223,824 (7,623,198) $ (74,828) $ (1,201)
Treasury shares issued....................... (373) 29,666 622
Issuance of common stock..................... 419,579 5 3,352
Tax benefit from employee stock options...... 408
Purchase of treasury shares.................. (519,968) (4,654)
Other comprehensive loss.....................
Cash dividends ($.13 per share)..............
Repayment of ESOP loan....................... 64
Net loss.....................................
- ---------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2003................. 25,463,645 $ 255 $ 227,211 (8,113,500) $ (78,860) $ (1,137)
========== ======= ========== ========== ========== ========

[RESTUBBED TABLE]

Accumulated
Other Totals
Comprehensive Retained Stockholders'
Income (Loss) Earnings Equity
- ------------------------------------------------------------------------------------------

Balance, September 30, 2000.................. $ (974) $ 77,753 $ 281,215
Treasury shares issued....................... 397
Issuance of common stock..................... 2,761
Cancellation of shares issued................ (1,305)
Purchase of treasury shares.................. (57,801)
Other comprehensive income................... 2,631 2,631
Cash dividends ($.13 per share).............. (2,364) (2,364)
Repayment of ESOP loan....................... 96
Net income................................... 9,829 9,829
- ------------------------------------------------------------------------------------------
Balance, September 30, 2001.................. $ 1,657 $ 85,218 $ 235,459
Treasury shares issued....................... 340
Issuance of common stock..................... 298
Tax benefit from employee stock 244
options......exercise........................ 244
Purchase of treasury shares.................. (1,517)
Other comprehensive income................... 4,254 4,254
Cash dividends ($.13 per share).............. (2,326) (2,326)
Repayment of ESOP loan....................... 96
Net loss..................................... (3,309) (3,309)
- ------------------------------------------------------------------------------------------
Balance, September 30, 2002.................. $ 5,911 $ 79,583 $ 233,539
Treasury shares issued....................... 249
Issuance of common stock..................... 3,357
Tax benefit from employee stock options...... 408
Purchase of treasury shares.................. (4,654)
Other comprehensive loss..................... (300) (300)
Cash dividends ($.13 per share).............. (2,294) (2,294)
Repayment of ESOP loan....................... 64
Net loss..................................... (2,915) (2,915)
- ------------------------------------------------------------------------------------------
Balance, September 30, 2003................. $ 5,611 $ 74,374 $ 227,454
========= ========= ===========

See accompanying notes to consolidated financial statements

RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2003, 2002 AND 2001

2003 2002 2001
---------- ---------- ----------
(in thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income.......................................................... $ (2,915) $ (3,309) $ 9,829
Adjustments to reconcile net (loss) income to net cash provided by
operating activities:
Depreciation, depletion and amortization................................ 11,944 11,161 11,038
Accretion of asset retirement obligation discount....................... 204 - -
Amortization of discount on senior notes and deferred finance costs..... 1,762 1,095 1,005
Provision for possible losses........................................... 1,848 1,393 863
Minority interest in Atlas Pipeline Partners, LP........................ 4,439 2,605 4,099
Equity in (earnings) loss of equity investees........................... (1,683) (639) 329
(Income) loss on discontinued operations................................ (1,222) 11,040 4,254
Deferred income taxes................................................... 1,616 (7,413) (885)
Accretion of discount................................................... (1,962) (3,212) (5,923)
Collection of interest.................................................. 1,130 5,243 1,207
Non-cash compensation................................................... 250 341 396
Cumulative effect of change in accounting principle..................... 13,881 627 -
Gain on asset dispositions.............................................. (4,775) (2,507) (1,738)
Property impairments and abandonments................................... 24 24 207
Changes in operating assets and liabilities................................. 18,466 (9,982) (5,623)
---------- ---------- ----------
Net cash provided by operating activities of continuing operations......... 43,007 6,467 19,058

CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid in asset acquisitions........................................ - - (7,875)
Capital expenditures....................................................... (28,568) (21,967) (14,210)
Principal payments on notes receivable and proceeds from sale of assets.... 10,053 25,220 29,610
Proceeds from sale (purchase) of RAIT Investment Trust shares.............. 12,044 (1,890) (6,405)
Increase in other assets................................................... (1,586) (6,008) (3,745)
Investments in real estate loans and real estate........................... (5,921) (19,859) (25,395)
---------- ---------- ----------
Net cash used in investing activities of continuing operations............. (13,978) (24,504) (28,020)

CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings................................................................. 96,937 173,753 135,021
Principal payments on borrowings........................................... (120,135) (168,619) (129,272)
Net proceeds from Atlas Pipeline Partners, L.P. public offering............ 25,182 - -
Distributions paid to minority interest of Atlas Pipeline Partners, L.P.... (4,233) (3,623) (3,783)
Dividends paid............................................................. (2,294) (2,326) (2,364)
Purchase of treasury stock................................................. (4,654) (1,517) (57,801)
Repayment of ESOP loan..................................................... 64 96 96
Increase in other assets................................................... (1,812) (1,258) (702)
Proceeds from issuance of stock............................................ 2,933 17 420
---------- ---------- ----------
Net cash used in financing activities of continuing operations............. (8,012) (3,477) (58,385)
Net cash used in discontinued operations................................... (5,624) (1,398) (1,112)
---------- ---------- ----------
Increase (decrease) in cash and cash equivalents........................... 15,393 (22,912) (68,459)
Cash and cash equivalents at beginning of year............................. 25,736 48,648 117,107
---------- ---------- ----------
Cash and cash equivalents at end of year................................... $ 41,129 $ 25,736 $ 48,648
========== ========== ==========

See accompanying notes to consolidated financial statements

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - NATURE OF OPERATIONS

Resource America, Inc. (the "Company") is a specialized asset
management company that uses industry specific expertise to generate and
administer investment opportunities for the Company and for outside investors in
the energy, real estate finance, financial services and equipment leasing
sectors.

In energy, the Company drills for and sells natural gas and, to a
significantly lesser extent, oil in the Appalachian Basin. Through Atlas
Pipeline Partners, L.P. ("Atlas Pipeline"), a master limited partnership of
which a subsidiary of the Company is the general partner and in which the
Company has a 39% interest; the Company transports natural gas from wells it
owns and operates to interstate pipelines and, in some cases, to end users. The
Company finances a substantial portion of its drilling activities through energy
partnerships it sponsors. The Company typically acts as the general or managing
partner of these partnerships and has a material partnership interest.

In real estate finance, the Company manages a portfolio of real estate
loans and, principally as a result of loan restructurings or foreclosures,
interests in real property. In fiscal 2002, the Company sought to expand its
operations through the sponsorship of real estate investment partnerships. It
has sponsored two such investment partnerships, one of which has commenced
operations and the other of which was in the offering stage as of September 30,
2003.

In financial services, the Company has acted as the co-sponsor of four
limited liability companies that invest in trust preferred securities of banks,
bank holding companies and similar financial institutions. Three of the limited
liability companies have commenced operations; the fourth was in the offering
stage as of September 30, 2003.

In equipment leasing, the Company has sponsored one publicly-held
equipment leasing partnership which commenced operations in March 2003 and, as
of September 30, 2003, continues to be in its offering stage. In April 2003, the
Company entered into an agreement with a third party under which the Company
originates equipment leases and sells them to the third party. Under the
agreement, the Company retains management and servicing rights for the leases
sold.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Reclassifications

Certain reclassifications have been made to the fiscal 2002 and fiscal
2001 consolidated financial statements to conform to the fiscal 2003
presentation.

Principles of Consolidation

The consolidated financial statements include the accounts of the
Company and its subsidiaries, all of which are wholly-owned except for Atlas
Pipeline. In addition, commencing with the adoption of FASB Interpretation 46,
"Consolidation of Variable Interest Entities" ("FIN 46") on July 1, 2003, the
Company has consolidated certain variable interest entities ("VIEs") as to which
the Company has determined that the Company is the primary beneficiary. The
Company also owns individual interests in the assets, and is separately liable
for its share of the liabilities of energy partnerships, whose activities
include only exploration and production activities. In accordance with
established practice in the oil and gas industry, the Company also includes its
pro-rata share of income and costs and expenses of the energy partnerships in
which the Company has an interest. All material intercompany transactions have
been eliminated.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Use of Estimates

Preparation of the consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the consolidated financial statements and the
reported amounts of revenues and costs and expenses during the reporting period.
Actual results could differ from these estimates.

Impairment of Long Lived Assets

The Company reviews its long-lived assets for impairment whenever
events or circumstances indicate that the carrying amount of an asset may not be
recoverable. If it is determined that an asset's estimated future cash flows
will not be sufficient to recover its carrying amount, an impairment charge will
be recorded to reduce the carrying amount for that asset to its estimated fair
value.

Stock-Based Compensation

The Company accounts for its stock option plans in accordance with the
provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees ("APB 25"), and related interpretations. Compensation
expense is recorded on the date of grant only if the current market price of the
underlying stock exceeded the exercise price. The Company adopted the disclosure
requirement of Statement of Financial Accounting Standards ("SFAS") No. 123,
"Accounting for Stock-Based Compensation, ("SFAS 123") as amended by the
required disclosures SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure." (See Note 11 for required pro forma disclosures.)

Comprehensive Income (Loss)

Comprehensive income (loss) includes net income (loss) and all other
changes in the equity of a business during a period from transactions and other
events and circumstances from non-owner sources. These changes, other than net
income (loss), are referred to as "other comprehensive income" and for the
Company include changes in the fair value, net of taxes, of marketable
securities and unrealized hedging gains and losses. Accumulated other
comprehensive income is related to the following:

At September 30,
-------------------------
2003 2002
---------- ----------
(in thousands)

Marketable securities - unrealized gains.................................. $ 5,611 $ 6,144
Unrealized hedging losses................................................. - (233)
---------- ----------
$ 5,611 $ 5,911
========== ==========

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Property and Equipment

Property and equipment consists of the following:

At September 30,
---------------------
2003 2002
-------- --------
(in thousands)

Mineral interest in properties:
Proved properties........................................................ $ 844 $ 843
Unproved properties...................................................... 563 584
Wells and related equipment.................................................. 184,226 152,225
Support equipment............................................................ 2,189 1,422
Other........................................................................ 9,136 8,390
-------- --------
196,958 163,464
Accumulated depreciation, depletion, amortization and valuation allowances:
Oil and gas properties................................................... (50,170) (41,893)
Other (3,378) (2,394)
-------- --------
(53,548) (44,287)
-------- --------
$143,410 $119,177
======== ========

Oil and Gas Properties

The Company follows the successful efforts method of accounting.
Accordingly, property acquisition costs, costs of successful exploratory wells,
all development costs, and the cost of support equipment and facilities are
capitalized. Costs of unsuccessful exploratory wells are expensed when such
wells are determined to be nonproductive or, if this determination cannot be
made, within twelve months of completion of drilling. The costs associated with
drilling and equipping wells not yet completed are capitalized as uncompleted
wells, equipment, and facilities. Geological and geophysical costs and the costs
of carrying and retaining undeveloped properties, including delay rentals, are
expensed as incurred. Production costs, overhead and all exploration costs other
than the costs of exploratory drilling are charged to expense as incurred.

Oil and gas properties include mineral rights with a cost of $1.4
million before accumulated depletion. In connection with a review of the
Company's financial statements by the staff of the Securities and Exchange
Commission, the Company has been made aware that an issue has arisen within the
industry regarding the application of provisions of SFAS No. 142, "Goodwill and
Other Intangible Assets" and SFAS No. 141, "Business Combinations," to companies
in the extractive industries, including gas and oil companies. The issue is
whether SFAS No. 142 requires companies to reclassify costs associated with
mineral rights, including both proved and unproved leasehold acquisition costs,
as intangible assets in the balance sheet, apart from other capitalized gas and
oil property costs. Historically, the Company and other gas and oil companies
have included the cost of these gas and oil leasehold interests as part of gas
and oil properties. Also under consideration is whether SFAS No. 142 requires
companies to provide the additional disclosures prescribed by SFAS No. 142 for
intangible assets for costs associated with mineral rights.

If it is ultimately determined that SFAS No. 142 requires the Company
to reclassify costs associated with mineral rights from property and equipment
to intangible assets, the amounts would be immaterial to the Company's financial
position. The reclassification of these amounts would not affect the method in
which such costs are amortized or the manner in which the Company assesses
impairment of capitalized costs. As a result, net income would not be affected
by the reclassification.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Property and Equipment - (Continued)

Oil and Gas Properties - (Continued)

The Company assesses unproved and proved properties periodically to
determine whether there has been a decline in value and, if a decline is
indicated, a loss is recognized. The assessment of significant unproved
properties for impairment is on a property-by-property basis. The Company
considers whether a dry hole has been drilled on a portion of, or in close
proximity to, the property, the Company's intentions of further drilling, the
remaining lease term of the property, and its experience in similar fields in
close proximity. The Company assesses unproved properties whose costs are
individually insignificant in the aggregate. This assessment includes
considering the Company's experience with similar situations, the primary lease
terms, the average holding period of unproved properties and the relative
proportion of such properties on which proved reserves have been found in the
past.

The Company compares the carrying value of its proved developed gas and
oil producing properties to the estimated future cash flow from such properties
in order to determine whether their carrying values should be reduced. No
adjustment was necessary during any of the fiscal years in the three year period
ended September 30, 2003.

Upon the sale or retirement of a complete or partial unit of a proved
property, the cost and related accumulated depletion are eliminated from the
property accounts, and the resultant gain or loss is recognized in the statement
of operations. Upon the sale of an entire interest in an unproved property where
the property had been assessed for impairment individually, a gain or loss is
recognized in the statement of operations. If a partial interest in an unproved
property is sold, any funds received are accounted for as a reduction of the
cost in the interest retained.

On an annual basis, the Company estimates the costs of future
dismantlement, restoration, reclamation, and abandonment of its gas and oil
producing properties. Additionally, the Company estimates the salvage value of
equipment recoverable upon abandonment. At September 30, 2003, the Company's
estimate of equipment salvage values was greater than or equal to the estimated
costs of future dismantlement, restoration, reclamation, and abandonment. On
October 1, 2002, the Company adopted SFAS No. 143 "Accounting for Asset
Retirement Obligations" ("SFAS 143") as discussed further in this footnote.

Depreciation, Depletion and Amortization

The Company amortizes proved gas and oil properties, which include
intangible drilling and development costs, tangible well equipment and leasehold
costs, on the unit-of-production method using the ratio of current production to
the estimated aggregate proved developed gas and oil reserves.

The Company computes depreciation on property and equipment, other than
gas and oil properties, using the straight-line method over the estimated
economic lives, which range from three to 39 years.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Asset Retirement Obligations

Effective October 1, 2002, the Company adopted SFAS 143 which requires
the Company to recognize an estimated liability for the plugging and abandonment
of its oil and gas wells and associated pipelines and equipment. Under SFAS 143,
the Company must currently recognize a liability for future asset retirement
obligations if a reasonable estimate of the fair value of that liability can be
made. The present values of the expected asset retirement costs are capitalized
as part of the carrying amount of the long-lived asset. SFAS 143 requires the
Company to consider estimated salvage value in the calculation of depletion,
depreciation and amortization. Consistent with industry practice, historically
the Company had determined the cost of plugging and abandonment on its oil and
gas properties would be offset by salvage values received. The adoption of SFAS
143 resulted in (i) an increase of total liabilities because retirement
obligations are required to be recognized, (ii) an increase in the recognized
cost of assets because the retirement costs are added to the carrying amount of
the long-lived assets and (iii) a decrease in depletion expense, because the
estimated salvage values are now considered in the depletion calculation.

The estimated liability is based on historical experience in plugging
and abandoning wells, estimated remaining lives of those wells based on reserves
estimates, external estimates as to the cost to plug and abandon the wells in
the future, and federal and state regulatory requirements. The liability is
discounted using an assumed credit-adjusted risk-free interest rate. Revisions
to the liability could occur due to changes in estimates of plugging and
abandonment costs or remaining lives of the wells, or if federal or state
regulators enact new plugging and abandonment requirements.

The adoption of SFAS 143 as of October 1, 2002 resulted in a cumulative
effect adjustment to record (i) a $1.9 million increase in the carrying values
of proved properties, (ii) a $1.5 million decrease in accumulated depletion and
(iii) a $3.4 million increase in non-current plugging and abandonment
liabilities. The cumulative and pro forma effects of the application of SFAS 143
were not material to the Company's consolidated statements of operations.

The Company has no assets legally restricted for purposes of settling
asset retirement obligations. Except for the item previously referenced, the
Company has determined that there are no other material retirement obligations
associated with tangible long-lived assets.

A reconciliation of the Company's liability for well plugging and
abandonment costs for the year ended September 30, 2003 is as follows (in
thousands):

Asset retirement obligations, September 30, 2002........................................... $ -
Adoption of SFAS 143....................................................................... 3,380
Liabilities incurred....................................................................... 93
Liabilities settled........................................................................ (52)
Revision in estimates...................................................................... (494)
Accretion expense.......................................................................... 204
---------
Asset retirement obligations, September 30, 2003........................................... $ 3,131
=========

The above accretion expense is included in depreciation, depletion and
amortization in the Company's consolidated statements of operations and the
asset retirement obligation liabilities are included in deferred revenue and
other liabilities in the Company's consolidated balance sheet.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Investment in RAIT Investment Trust

The Company accounts for its investment in RAIT Investment Trust
("RAIT") in accordance with SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities." This investment is classified as available-for-sale
and as such is carried at fair market value based on market quotes. Unrealized
gains and losses, net of taxes, are reported as a separate component of
stockholders' equity. The cost of securities sold is based on the specific
identification method.

The following table discloses the pre-tax unrealized gains relating to
the Company's investment in RAIT at the periods indicated:

At September 30,
--------------------------
2003 2002
---------- ----------
(in thousands)

Cost...................................................................... $ 12,260 $ 20,268
Unrealized gains.......................................................... 8,251 9,312
---------- ----------
Estimated fair value...................................................... $ 20,511 $ 29,580
========== ==========

In fiscal 2003, the Company sold 542,600 common shares of RAIT for
$12.0 million and realized gains of $4.0 million (see Note 5).

Fair Value of Financial Instruments

The Company used the following methods and assumptions in estimating
the fair value of each class of financial instruments for which it is
practicable to estimate fair value.

For cash and cash equivalents, receivables and payables, the carrying
amounts approximate fair value because of the short maturity of these
instruments.

For investments in real estate loans, because each loan is a unique
transaction involving a discrete property, it is impractical to determine their
fair values. However, the Company believes the carrying amounts of the loans are
reasonable estimates of their fair value considering the nature of the loans and
the estimated yield relative to the risks involved.

For secured revolving credit facilities - leasing, the carrying amount
approximates fair value because of the short maturity of these instruments.

The following table provides information on other financial
instruments:

At September 30, 2003 At September 30, 2002
------------------------ ------------------------
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
------ ---------- ------ ----------
(in thousands)

Energy non-recourse debt..................................... $ 31,194 $ 31,194 $ 49,345 $ 49,345
Real estate finance debt..................................... 19,469 19,469 33,214 33,214
Senior debt.................................................. 54,027 55,648 65,336 67,623
Other debt................................................... 28,477 28,477 7,615 7,615
---------- ----------- ---------- ----------
$ 133,167 $ 134,788 $ 155,510 $ 157,797
========== =========== ========== ==========

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Fair Value of Financial Instruments - (Continued)

For all debt except the senior debt, the carrying value approximates
fair value because of the short term maturity of these instruments and the
variable interest rates in the debt agreements. The fair value of the senior
debt was based upon the most recent purchase price of the debt by the Company.

Concentration of Credit Risk

Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist principally of periodic temporary
investments of cash. The Company places its temporary cash investments in
high-quality short-term money market instruments and deposits with high-quality
financial institutions and brokerage firms. At September 30, 2003, the Company
had $50.2 million in deposits at various banks, of which $47.7 million is over
the insurance limit of the Federal Deposit Insurance Corporation. No losses have
been experienced on such investments.

Environmental Matters

The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. The Company has
established procedures for the ongoing evaluation of its operations, to identify
potential environmental exposures and to comply with regulatory policies and
procedures.

The Company accounts for environmental contingencies in accordance with
SFAS No. 5 "Accounting for Contingencies." Environmental expenditures that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are
probable, and the costs can be reasonably estimated. The Company maintains
insurance which may cover in whole or in part certain environmental
expenditures. For the three years ended September 30, 2003, the Company had no
environmental matters requiring specific disclosure or requiring recording of a
liability.

Revenue Recognition

Energy

The Company conducts certain energy activities through, and a portion
of its revenues are attributable to, sponsored energy limited partnerships.
These energy partnerships raise capital from investors to drill gas and oil
wells. The Company serves as general partner of the energy partnerships and
assumes customary rights and obligations for them. As the general partner, the
Company is liable for partnership liabilities and can be liable to limited
partners if it breaches its responsibilities with respect to the operations of
the partnerships. The income from the Company's general partner interest is
recorded when the gas and oil are sold by a partnership.

The Company contracts with the energy partnerships to drill partnership
wells. The contracts require that the energy partnerships must pay the Company
the full contract price upon execution. The income from a drilling contract is
recognized as the services are performed. The contracts are typically completed
in less than 60 days. On an uncompleted contract, the Company classifies the
difference between the contract payments it has received and contract costs
previously incurred as a current liability.

The Company recognizes transportation revenues at the time the natural
gas is delivered to the purchaser.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Revenue Recognition - (Continued)

Energy - (Continued)

The Company recognizes field services revenues at the time the services
are performed.

The Company is entitled to receive management fees according to the
respective partnership agreements. The Company recognizes such fees as income
when earned and includes them in energy revenues.

The Company sells interests in gas and oil wells and retains a working
interest and/or overriding royalty. The Company records the income from the
working interests and overriding royalties when the gas and oil are sold.

Real Estate Finance

The Company accretes the difference between its cost basis in a real
estate loan and the sum of projected cash flows from that loan into interest
income over the estimated life of the loan using the interest method which
recognizes a level interest rate over the life of the loan. The Company reviews
projected cash flows, which include amounts realizable from the underlying
properties, on a regular basis. Changes to projected cash flows, which can be
based upon updated property appraisals, changes to the property and changes to
the real estate market in general, reduce or increase the amounts accreted into
interest income over the remaining life of the loan.

The Company recognizes gains or losses on the partial sale of a real
estate loan based on an allocation of the Company's cost basis between the
portions of the loan sold and the portion retained based upon the fair value of
those respective portions on the date of sale. Gains or losses on the
refinancing of a real estate loan only arise if the proceeds received by the
Company when a property owner refinances the property exceed the carrying cost
of the loan. The Company records any gain or loss recognized on a sale of a
senior lien interest or a refinancing to income at the time of such sale or
refinancing.

The Company sponsored and manages one real estate partnership which was
organized to invest in multi-family residential properties. The Company receives
acquisition fees equal to 2% of the net purchase price of properties acquired
and an additional 2% fee for debt placement related to the properties acquired.
The Company recognizes these fees upon acquisition of the properties and
obtaining the related financing.

The Company also receives a fee equal to 5% of the gross operating
revenues from the Partnerships' properties, payable monthly. The Company
recognizes this fee as the Partnerships' revenues are earned. Additionally, the
Company receives an annual investment management fee from the Partnerships equal
to 2% of the gross offering proceeds, for its services. This investment
management fee is recognized ratably over each annual period.

Equipment Leasing

The Company, through its wholly owned subsidiary, LEAF Financial
Corporation ("LEAF"), is a specialized asset manager of investments in the
commercial equipment leasing sector. As such, LEAF serves as the general partner
and manager and holds limited partnership interests in four active public
equipment leasing partnerships (the "Leasing Partnerships"). At September 30,
2003, the Company is the sponsor and general partner of an additional public
partnership, LEAF I LP. Limited Partnership units of LEAF I LP are sold through
a select network of broker dealers throughout the United States. LEAF I LP
invests in equipment leases originated by the Company.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Revenue Recognition - (Continued)

Equipment Leasing - (Continued)

In April 2003, LEAF, through certain of its subsidiaries, entered into
a Purchase, Sale and Contribution Agreement ("the Agreement") with certain
subsidiaries of Merrill Lynch ("ML"). In accordance with the Agreement, LEAF may
sell and ML will purchase up to $300 million of leases originated by LEAF.

Direct Financing Leases. The Company's lease transactions are generally
classified as direct financing leases (as distinguished from sales-type or
operating leases). Such leases transfer substantially all benefits and risks of
equipment ownership to the customer. A lease is a direct financing lease if the
creditworthiness of the lessee ("customer") and the collectibility of lease
payments are reasonably certain and it meets one of the following criteria: (i)
the lease transfers ownership of the equipment to the customer at the end of the
lease term; (ii) the lease contains a bargain purchase option; (iii) the lease
term at inception is at least 75% of the estimated economic life of the leased
equipment; or (iv) the present value of the minimum lease payments is at least
90% of the fair market value of the leased equipment at inception of the lease.
The Company's investment in leases consists of the sum of the total future
minimum lease payments receivable and the estimated unguaranteed residual value
of leased equipment, less unearned lease income. Unearned lease income, which is
recognized as revenue over the term of the lease by the effective interest
method, represents the excess of the total future minimum lease payments plus
the estimated unguaranteed residual value expected to be realized at the end of
the lease term over the cost of the related equipment. The Company discontinues
the recognition of revenue for leases for which payments are more than 90 days
past due. As of September 30, 2003 and 2002, no leases were 90 days or more past
due. Initial direct costs incurred in consummating a lease are capitalized as
part of the investment in leases and amortized over the lease term as a
reduction in the yield.

Management Fees. The Company receives management fees from the leasing
partnerships and LEAF I LP (collectively "the Partnerships") for administrative
and management services performed on their behalf. These management fees range
from 3% to 6% of gross rental payments on operating leases and 2% to 3% of gross
rental payments on direct financing leases.

Income from Investments in Partnerships. The Company receives 1% to
3.5% of cash distributions paid by the Partnerships for its investment as the
general partner in the Partnerships.

Acquisition Expense Reimbursements. The Company receives a
reimbursement of 2% of the cost of lease equipment acquired for LEAF I LP and
ML. This reimbursement is recognized at the time of the sale of the related
equipment leases to these third parties.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Supplemental Cash Flow Information

The Company considers temporary investments with maturity at the date
of acquisition of 90 days or less to be cash equivalents.

Supplemental disclosure of cash flow information:

Years Ended September 30,
----------------------------------------
2003 2002 2001
----------- ---------- ----------
(in thousands)

Cash paid during the years for:
Interest..................................................................... $ 11,666 $ 11,683 $ 13,976
Income taxes (refunded) paid................................................. $ (1,067) $ 3,243 $ 13,393

Non-cash activities include the following:
Real estate received in exchange for notes upon foreclosure
on loans................................................................. $ 14,235 $ - $ -
Receipt of a note in connection with the sale of a real estate
loan..................................................................... $ 1,350 $ - $ -
Cancellation of shares issued in contingency settlement...................... $ - $ - $ 1,305
Shares issued in contingency settlement...................................... $ - $ - $ 2,089
Atlas Pipeline units issued in exchange for gas gathering and
transmission facilities.................................................. $ - $ - $ 2,250
Buyer's assumption of liabilities upon sale of real estate loan.............. $ - $ - $ 460
Tax benefit from employee stock option exercise.............................. $ 408 $ 244 $ -
Assumption of debt upon foreclosure of real estate loans..................... $ 5,560 $ - $ -
Asset retirement obligations................................................. $ 3,380 $ - $ -
Treasury stock issued for employee compensation.............................. $ 249 $ 340 $ 397
Common stock issued under stock option plans, net of cash proceeds........... $ 424 $ 281 $ 252

Details of acquisitions:
Fair value of assets acquired............................................ $ - $ - $ 10,555
Atlas Pipeline units issued in exchange for gas gathering and
transmission facilities................................................ - - (2,250)
Liabilities assumed...................................................... - - (430)
---------- ---------- ----------
Net cash paid.......................................................... $ - $ - $ 7,875
========== ========== ==========

Income Taxes

The Company records deferred tax assets and liabilities, as
appropriate, to account for the estimated future tax effects attributable to
temporary differences between the financial statement and tax bases of assets
and liabilities and operating loss carryforwards, using currently enacted tax
rates. The deferred tax provision or benefit each year represents the net change
during that year in the deferred tax asset and liability balances.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Earnings (Loss) Per Share

Basic earnings (loss) per share is determined by dividing net income
(loss) by the weighted average number of shares of common stock outstanding
during the period. Earnings (loss) per share - diluted is computed by dividing
net income (loss) by the sum of the weighted average number of shares of common
stock outstanding and dilutive potential shares issuable during the period.
Dilutive potential shares of common stock consist of the excess of shares
issuable under the terms of various stock option agreements over the number of
such shares that could have been reacquired (at the weighted average price of
shares during the period) with the proceeds received from the exercise of the
options.

The components of basic and diluted earnings (loss) per share for each
year were as follows:

Years Ended September 30,
----------------------------------------
2003 2002 2001
-------- ----------- -----------
(in thousands)

Income from continuing operations......................................... $ 9,744 $ 8,358 $ 14,083
Income (loss) from discontinued operations................................ 1,222 (11,040) (4,254)
Cumulative effect of change in accounting principle....................... (13,881) (627) -
-------- ----------- -----------
Net (loss) income..................................................... $ (2,915) $ (3,309) $ 9,829
======== =========== ===========

Weighted average common shares outstanding-basic.......................... 17,172 17,446 17,962
Dilutive effect of stock option and award plans........................... 396 359 474
-------- ----------- -----------
Weighted average common shares-diluted.................................... 17,568 17,805 18,436
======== =========== ===========

Recently Issued Financial Accounting Standards

In May 2003, the FASB issued Statement No. 150 ("SFAS 150") "Accounting
for Certain Financial Instruments with Characteristics of Both Liabilities and
Equity." SFAS 150 requires that certain instruments that were previously
classified as equity on a Company's statement of financial position now be
classified as liabilities. SFAS 150 is effective for financial instruments
entered into or modified after May 31, 2003, and otherwise is effective at the
beginning of the first interim period beginning after June 15, 2003. The
adoption of SFAS 150 did not have a material impact on the Company's results of
operations or financial position.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)

Recently Issued Financial Accounting Standards - (Continued)

In November 2002, the FASB issued Interpretation 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 clarifies the
requirements of FASB No. 5, "Accounting for Contingencies" ("SFAS 5") relating
to a guarantor's accounting for, and disclosure of, the issuance of certain
types of guarantees. FIN 45 provides for additional disclosure requirements
related to guarantees in financial statements for financial periods ending
after December 15, 2002. Additionally, FIN 45 outlines provisions for initial
recognition and measurement of the liability incurred upon the issuance of new
guarantees or the modification of existing guarantees subsequent to December
31, 2002. The adoption of the recognition and measurement requirements of FIN
45 on January 1, 2003, did not have a significant impact on the results of
operations or equity of the Company.

NOTE 3 - ADOPTION OF FASB INTERPRETATION 46, CONSOLIDATION OF VARIABLE
INTEREST ENTITIES ("FIN 46")

In January 2003, the FASB issued FIN 46. This interpretation changes
the method of determining whether certain entities should be included in the
Company's consolidated financial statements. FIN 46's consolidation criteria are
based on analyses of risks and rewards, not control, and represent a significant
and complex modification of previous accounting principles. Under FIN 46 a
variable interest entity ("VIE") is one that has (1) equity that is insufficient
to permit the entity to finance its activities without additional subordinated
financial support from other parties, or (2) equity investors that cannot make
significant decisions about the entity's operations, or that do not absorb the
expected losses or receive the expected returns of the entity. A VIE must be
consolidated by its primary beneficiary, which is the party involved with the
VIE that has exposure to a majority of the expected losses or a majority of the
expected residual returns or both. All other entities are evaluated for
consolidation in accordance with SFAS No. 94, "Consolidation of All
Majority-Owned Subsidiaries" ("SFAS 94").

For any VIEs that must be consolidated under FIN 46, the assets,
liabilities and non-controlling interest of the VIE would be initially measured
at their carrying amounts, as defined in FIN 46. If determining the carrying
amounts is not practicable, the fair value at the date FIN 46 first applies may
be used to measure the assets, liabilities and non-controlling interests of the
VIE. Any difference between the net amount added to the balance sheet and the
value at which the primary beneficiary carried its interest in the VIE prior to
the adoption of FIN 46 is recognized as a cumulative effect of a change in
accounting principle. The Company has determined that it was not practicable to
determine the carrying values of the VIE's assets and liabilities and
accordingly, has used the fair values at the date of adoption.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 3 - ADOPTION OF FASB INTERPRETATION 46, Consolidation of Variable Interest
Entities ("FIN 46") - (Continued)

The Company, as encouraged by the pronouncement, early-adopted FIN 46
on July 1, 2003. Consequently, certain entities relating to the Company's real
estate finance business have been consolidated in the Company's financial
statements for the first time. Several factors that distinguish these entities
from others included in its consolidated statements follow:

o The assets and liabilities of the consolidated VIEs are included in
the Company's financial statements and the investments in real estate
loans, which were the Company's variable interests in the VIEs, have
been removed from the financial statements.

o These VIEs are consolidated because the Company has been determined
to be the primary beneficiary of these entities as defined in FIN 46.

o The assets and liabilities of the VIE's that are now included in the
consolidated financial statements are not the Company's. The
liabilities will be satisfied from the cash flows of the VIE's
assets, not from the assets of the Company, which has no legal
obligation to satisfy those liabilities.

As of July 1, 2003, the date of adoption, the consolidation of FIN 46
entities resulted in the addition of $296.5 million in assets, $185.5 million in
liabilities and a $13.9 million after-tax accounting cumulative effect charge in
the company's fourth fiscal quarter.

FIN 46 has been the subject of significant continuing interpretation by
the FASB, and changes to its complex requirements are possible. Currently, it is
not possible to conclude whether such changes, if any, would be likely to affect
the amounts the Company has recorded.

The following tables provide supplemental information about assets and
liabilities associated with entities that were consolidated effective
July 1, 2003 in accordance with FIN 46 and not classified as held for sale.
Operating information is for the period July 1, 2003 through September 30, 2003
and balance sheet information is as of September 30, 2003 (in thousands):

Assets:
Cash.............................................................. $ 1,689
Accounts receivables.............................................. 451
Real estate assets, net........................................... 76,035
Other............................................................. 72
-----------
Total assets.................................................... $ 78,247
===========

Liabilities:
Mortgage loans on real estate..................................... $ 37,620
Other............................................................. 7,564
-----------
Total liabilities............................................... $ 45,184
===========

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 3 - ADOPTION OF FASB INTERPRETATION 46, Consolidation of Variable Interest
Entities ("FIN 46") - (Continued)

The following tables provide supplemental information about assets,
liabilities, revenues and expenses associated with entities that were
consolidated effective July 1, 2003 in accordance with FIN 46, but classified as
held for sale at September 30, 2003 (See Note 14). Operating information is for
the period July 1, 2003 through September 30, 2003 and balance sheet information
is as of September 30, 2003 (in thousands):

Assets:
Cash............................................................ $ 3,960
Accounts receivables............................................ 2,988
Real estate assets, net......................................... 213,026
Other........................................................... 2,703
-------------
Total assets held for sale.................................... $ 222,677
=============

Liabilities:
Mortgage loans on real estate................................... $ 130,687
Other........................................................... 10,786
-------------
Total liabilities associated with assets held for sale........ $ 141,473
=============

The mortgage loans on real estate shown above in which the VIE's are
the debtors are secured by the VIE's underlying properties. Interest reates
range from 6% to 10% and the loans mature at various dates through 2014.
Maturities for the next five fiscal years, assuming loans associated with assets
held for sale will be paid within the next fiscal year are as follows: 2004 -
$131.5 million; 2005 - $909,000; 2006 - $3.6 million; 2007 - $905,000 and 2008 -
$962,000.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 4 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

Other Assets

The following table provides information about other assets at the
dates indicated.

At September 30,
----------------------------
2003 2002
---------- ---------
(in thousands)

Deferred financing costs, net of accumulated amortization of
$5,504 and $3,742..................................................... $ 2,105 $ 2,122
Equity method investments in Trapeza entities............................. 4,802 3,085
Investments at lower of cost or market.................................... 6,185 6,137
Other..................................................................... 6,417 7,934
---------- ----------
$ 19,509 $ 19,278
========== ==========

Deferred financing costs are amortized over the terms of the related
loans (two to seven years)

Investments in Trapeza entities are accounted for using the equity
method of accounting because the Company, as a 50% owner of the general partner
of these entities, has the ability to exercise significant influence over their
operating and financial decisions. The Company's combined general and limited
partner interests in these entities range from 15% to 18%.

Investments at the lower of cost or market include non-marketable
investments in entities in which the Company has less than a 20% ownership
interest, and in which it does not have the ability to exercise significant
influence. These investments include approximately 10% of the outstanding shares
of The Bancorp, Inc. ("TBI"), a related party as disclosed in Note 5.

Intangible Assets

Partnership management and operating contracts and the Company's
equipment leasing operating system, or leasing platform, were acquired through
acquisitions recorded at fair value on their acquisition dates. The Company
amortizes contracts acquired on a declining balance method, over their
respective estimated lives, ranging from five to thirteen years. The leasing
platform is amortized on the straight-line method over seven years. Amortization
expense for the years ended September 30, 2003, 2002 and 2001 was $1.1 million,
$1.2 million and $1.5 million, respectively. The aggregate estimated annual
amortization expense is approximately $1.1 million for each of the succeeding
five years.

The following table provides information about intangible assets at the
dates indicated:

At September 30,
------------------------
2003 2002
---------- ----------
(in thousands)

Partnership management and operating contracts............................ $ 14,343 $ 14,343
Leasing platform.......................................................... 918 918
---------- ----------
15,261 15,261
Accumulated amortization.................................................. (6,785) (5,672)
---------- ----------
Intangible assets, net.................................................... $ 8,476 $ 9,589
========== ==========

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 4 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL - (Continued)

Goodwill

On October 1, 2001, the Company early-adopted SFAS 142 "Goodwill and
Other Intangible Assets," which requires that goodwill no longer be amortized,
but instead tested for impairment at least annually. At that time, the Company
had unamortized goodwill of $31.4 million. The transitional impairment test
required upon adoption of SFAS 142, which involved the use of estimates related
to the fair market value of the business operations associated with the
goodwill, did not indicate an impairment loss. The Company will continue to
evaluate its goodwill at least annually and will reflect the impairment of
goodwill, if any, in operating income in the statement of operations in the
period in which the impairment is indicated. All goodwill recorded on the
Company's balance sheets is related to the Company's energy segments.

Changes in the carrying amount of goodwill for the periods indicated
are as follows:

Years Ended September 30,
----------------------------------
2003 2002 2001
------ ------ -----
(in thousands)

Goodwill at beginning of period,
(less accumulated amortization of $4,209, $4,063 and $2,612)............. $ 37,471 $ 31,420 $ 28,434
Additions to goodwill related to asset acquisitions.......................... 15 4,387
Amortization expense......................................................... - - (1,451)
Atlas Pipeline goodwill amortization, whose fiscal year
began January 1, 2002, at which time it adopted SFAS 142................. - (22) -
Leasing platform transferred from goodwill to other assets in
accordance with SFAS 142 (net of accumulated amortization
of $587)................................................................. - (331) -
Syndication network reclassified from other assets
in accordance with SFAS 142 (net of accumulated amortization
of $711)................................................................. - 6,389 -
------- -------- --------
Goodwill at end of period (net of accumulated amortization
of $4,209, $4,209 and $4,063)............................................ $ 37,471 $ 37,471 $ 31,420
======== ======== ========

Adjusted net income from continuing operations for the year ended
September 30, 2001 would have been $15.1 million, excluding goodwill
amortization, net of taxes, using the Company's effective tax rate in fiscal
2001 of 31%. Adjusted basic income per share from continuing operations for the
year ended September 30, 2001 would have been $.84. Adjusted diluted income per
share from continuing operations for the year ended September 30, 2001 would
have been $.82.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

In the ordinary course of its business operations, the Company has
ongoing relationships with several related entities:

Relationship with Brandywine Construction & Management, Inc. ("BCMI").
BCMI manages the properties underlying 21 of the Company's real estate loans and
real estate and FIN 46 assets. Adam Kauffman ("Kauffman"), President of BCMI, or
an entity affiliated with him, has also acted as the general partner, president
or trustee of seven of the borrowers. Edward E. Cohen ("E. Cohen"), the
Company's chairman and chief executive officer and president, is the chairman of
BCMI and holds approximately 8% of its common stock.

In September 2001, the Company sold a wholly-owned subsidiary to BCMI
for $4.0 million, recognizing a gain of $356,000.

Relationship with RAIT Investment Trust ("RAIT"). Organized by the
Company in 1997, RAIT is a real estate investment trust in which, as of
September 30, 2003, the Company owned approximately 4% of the shares of
beneficial interests. Betsy Z. Cohen ("B. Cohen"), Mr. E. Cohen's spouse, is the
chief executive officer of RAIT, and Jonathan Z. Cohen ("J. Cohen"), a son of E.
and B. Cohen and the executive vice president and chief operating officer and a
director of the Company, is the vice chairman and a trustee of RAIT. Scott F.
Schaeffer, a former officer and director of the Company, is RAIT's president and
chief operating officer.

Since October 1, 2000, the Company and RAIT have engaged in the
following transactions:

o In June 2002, the Company sold a mortgage loan having a book value of $1.0
million to RAIT for $1.8 million, recognizing a gain of $757,000. Mr.
Schaeffer was an officer and director of the general partner of the
borrower.

o In March 2002, RAIT provided the initial financing, which has since been
repaid, on the Company's purchase for $2.7 million of an interest in a real
estate venture.

o In June 2001, the Company sold to an unrelated person a $1.6 million first
mortgage loan having a book value of $1.1 million, resulting in a gain of
$459,000. RAIT provided acquisition financing to the unrelated purchaser.

o In March 2001, the Company sold a mortgage loan to RAIT for $20.2 million,
recognizing a gain of $335,000.

o In March 2001, the Company consolidated its position in two loans in which
it had held subordinated interests since 1998 and 1999, respectively, by
purchasing from RAIT the related senior lien interests at face value for
$13.0 million and $8.6 million, respectively.

Relationship with The Bancorp, Inc. ("TBI"). The Company owns 9.7% of
the outstanding common stock of TBI. In 2001, the Company acquired 70,400 shares
of TBI's convertible preferred stock (9.7%) for approximately $704,000 pursuant
to a rights offering to TBI's stockholders. B. Cohen and Daniel G. Cohen ("D.
Cohen") are officers and directors of TBI. D. Cohen, a son of E. and B. Cohen,
is a former officer and director of the Company.

Relationship with Ledgewood Law Firm ("Ledgewood"). Until April 1996,
E. Cohen was of counsel to Ledgewood Law Firm. The Company paid Ledgewood $1.2
million, $839,000 and $975,000 during fiscal 2003, 2002 and 2001, respectively,
for legal services rendered to the Company. E. Cohen receives certain debt
service payments from Ledgewood related to the termination of his affiliation
with Ledgewood and its redemption of his interest.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (Continued)

Relationship with Retirement Trusts. Upon his retirement, E. Cohen is
entitled to receive payments from a Supplemental Employee Retirement Plan
("SERP"). The Company has established two trusts to fund the SERP. The 1999
Trust purchased 100,000 shares of the common stock of TBI. The 2000 Trust holds
42,633 shares of convertible preferred stock of TBI and a loan to a limited
partnership of which E. Cohen and D. Cohen own the beneficial interests. This
loan was acquired for its outstanding balance of $720,167 by the 2000 Trust in
April 2001 from a corporation of which E. Cohen is chairman and J. Cohen is the
president. In addition, the 2000 Trust invested $1.0 million in Financial
Securities Fund, an investment partnership which is managed by a corporation of
which D. Cohen is the principal shareholder and a director. The fair value of
the 1999 Trust is approximately $1.1 million at September 30, 2003. This trust
and its assets are not included in the Company's consolidated balance sheet.
However, its assets are considered in determining the amount of the Company's
liability under the SERP.

The carrying value of the assets in the 2000 Trust is approximately
$3.6 million at September 30, 2003 and, because it is a "Rabbi Trust" its assets
are included in Other Assets in the Company's consolidated balance sheets and
the Company's liability under the SERP has not been reduced by the value of
those assets.

Relationship with Cohen Bros & Company. During fiscal 2003, 2002 and
2001, the Company purchased 26,450, 125,095 and 67,500 shares of its common
stock at a cost of $212,100, $1.1 million and $737,000, respectively, from Cohen
Bros. & Company. In 2002, the Company repurchased $1.5 million principal amount
of its senior notes at a cost of $1.6 million from Cohen Bros. & Company. Cohen
Bros. & Company acted as a principal in the sales to the Company. D. Cohen is
the principal owner of the corporate parent of Cohen Bros. & Company.

Relationship with 9 Henmar. The Company owns a 50% interest in the
Trapeza entities that have sponsored collateralized debt obligation issuers
("CDO issuers") and manage pools of trust preferred securities acquired by the
CDO issuers. The Trapeza entities and CDO issuers were originated and developed
in large part by D. Cohen. The Company has agreed to pay his company, 9 Henmar
LLC ("9 Henmar"), 10% of the fees the Company receives in connection with
Trapeza entities one through four and their management of the trust preferred
securities held by the CDO issuers. In fiscal 2003, the Company paid 9 Henmar
$93,400 in such fees. In addition, the Company made advances of $1.4 million and
$48,600 in fiscal 2003 and 2002, respectively to 9 Henmar for its expenses in
connection with originating and developing the Trapeza entities and the CDO
issuers. All of such advances were reimbursed to the Company by the CDO issuers
by September 30, 2003.

Relationship with Certain Borrowers. The Company has from time to time
purchased loans in which affiliates of the Company were or have become
affiliates of the borrowers.

In 2002, D. Cohen acquired beneficial ownership of a property on which
the Company had held a loan interest since 1998. At September 30, 2003, the
Company's receivable was $6.6 million and the Company's carrying value of the
loan was $2.3 million.

In 2000, to protect the Company's interest, the property securing a
loan held by the Company since 1997 was purchased by a limited partnership owned
in equal parts by Messrs. Schaeffer, Kauffman, E. Cohen and D. Cohen. In
September 2003, in furtherance of its position, the Company foreclosed on the
property.

In 1998, the Company acquired a defaulted loan in the original
principal amount of $91.0 million for a cost of $90.6 million. In September
2000, in connection with a refinancing and to protect the Company's interest, a
newly-formed limited liability company owned in equal parts by Messrs.
Schaeffer, Kauffman, E. Cohen and D. Cohen assumed equity title to the property.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (Continued)

In 1998, the Company acquired a loan under a plan of reorganization in
bankruptcy for a cost of $95.6 million. An order of the bankruptcy court
required that legal title to the property underlying the loan be transferred. In
order to comply with that order, to maintain control of the property and to
protect the Company's interest, an entity whose general partner is a subsidiary
of the Company and whose limited partners are Messrs. Schaeffer, D. Cohen and E.
Cohen (with a 94% beneficial interest), assumed title to the property.

Relationship with Certain Lienholders. In 1997, the Company acquired a
first mortgage lien with a face amount of $14.0 million and a book value of $4.5
million on a hotel property owned by a corporation in which, on a fully diluted
basis, J. Cohen and E. Cohen would have a 19% interest. The corporation acquired
the property through foreclosure of a subordinate loan. In May 2003, the Company
acquired this property through further foreclosures proceedings and recorded
write-downs of $2.7 million associated with this property in fiscal 2003.

NOTE 6 - INVESTMENTS IN LEASE RECEIVABLES

Components of the investment in direct financing leases at September
30, 2003 and 2002 are as follows:

At September 30,
--------------------------
2003 2002
---------- -----------
(in thousands)

Total future minimum lease payments
receivable........................................................ $ 7,982 $ 2,908
Initial direct costs, net of amortization............................ 122 58
Unguaranteed residual................................................ 51 50
Unearned lease income................................................ (1,326) (504)
Unearned residual income............................................. (12) (17)
---------- ----------
Investment in lease receivables................................... $ 6,817 $ 2,495
========== ==========

Although the lease terms extend over many years as indicated in the
table below, the investment in lease receivables is included in accounts
receivable and prepaid expenses in the Company's consolidated balance sheets,
since the Company routinely sells them to third parties shortly after their
origination. The contractual future minimum lease payments receivable for each
of the five succeeding fiscal years ended September 30. and thereafter, are as
follows (in thousands):

2004................... $ 2,438
2005................... 2,024
2006................... 1,282
2007................... 1,055
2008................... 816
Thereafter............. 367
----------
$ 7,982
==========

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 7 - INVESTMENTS IN REAL ESTATE LOANS AND REAL ESTATE

The Company focuses primarily on the management and resolution of
income-producing real estate loans. The Company records as income the accretion
of a portion of the difference between its cost basis in a loan and the sum of
projected cash flows therefrom. Cash received by the Company for payment on each
loan is allocated between principal and interest. This accretion of discount
amounted to $2.0 million, $3.2 million and $5.9 million during the years ended
September 30, 2003, 2002, and 2001, respectively. As the Company sells senior
lien interests or receives funds from refinancings of its loans by the borrower,
a portion of the cash received is employed to reduce the cumulative accretion of
discount included in the carrying value of the Company's investments in real
estate loans.

The Company has also adopted the cost recovery method for certain loans
due to unanticipated events including the loss of a major tenant of an
underlying property, the declaration of bankruptcy and voiding of the lease by a
sole tenant and, for a hotel property underlying a loan, the severe effects of
the post-9/11 travel slump.

At September 30, 2003 and 2002, the Company held real estate loans
having aggregate face values of $186.9 million and $610.0 million, respectively,
after the removal in 2003 of $393.6 face value ($132.7 million of carrying
value) upon the adoption of FIN 46 on July 1, 2003 as discussed in Note 3.
Amounts receivable, net of senior lien interests and deferred costs, were
$96.4 million and $349.3 million at September 30, 2003 and 2002, respectively.

The following is a summary of the changes in the carrying value of the
Company's investments in real estate loans and real estate for the years ended
September 30, 2003 and 2002.

September 30,
-------------------------
2003 2002
----------- -----------
(in thousands)

Loan balance, beginning of year...................................... $ 187,542 $ 192,263
New loans............................................................ 1,350 -
Addition to existing loans........................................... 4,855 17,185
Loan write-downs..................................................... (1,448) (559)
Accretion of discount (net of collection of interest)................ 1,962 3,212
Loans reclassified as FIN 46 entities' assets........................ (132,312) -
Foreclosures transferred to real estate.............................. (11,404) -
Collections of principal............................................. (10,129) -
Cost of loans resolved............................................... - (24,559)
---------- ----------
Loan balance, end of year............................................ 40,416 187,542
Real estate ventures................................................. 14,131 14,029
Real estate owned, net of accumulated depreciation of $640
and $432 (see Note 8)............................................. 15,806 4,332
Allowance for possible losses........................................ (1,417) (3,480)
---------- ----------
Balance, end of year................................................. $ 68,936 $ 202,423
========== ==========

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 7 - INVESTMENTS IN REAL ESTATE LOANS AND REAL ESTATE - (Continued)

In determining the Company's allowance for possible losses related to
its real estate loans and real estate, the Company considers general and local
economic conditions, neighborhood values, competitive overbuilding, casualty
losses and other factors which may affect the value of loans and real estate.
The value of loans and real estate may also be affected by factors such as the
cost of compliance with regulations and liability under applicable environment
laws, changes in interest rates and the availability of financing. Income from
properties will be reduced if a significant number of tenants are unable to pay
rent or if available space cannot be rented on favorable terms. In addition, the
Company continuously monitors collections and payments from its borrowers and
maintains an allowance for estimated losses based upon its historical experience
and its knowledge of specific borrower collection issues identified. The Company
reduces its investment in real estate loans and real estate by an allowance for
amounts that may become unrealizable in the future. Such allowance can be either
specific to a particular loan or property or general to all loans and real
estate.

The following is a summary of activity in the Company's allowance for
possible losses related to real estate loans for the years ended September 30,
2003 and 2002:

September 30,
-------------------------
2003 2002
---------- ---------
(in thousands)

Balance, beginning of year........................................... $ 3,480 $ 2,529
Provision for possible losses........................................ 1,848 1,510
Transfers upon foreclosure........................................... (2,339) -
Write-downs associated with foreclosure.............................. (1,572) (559)
---------- ----------
Balance, end of year................................................. $ 1,417 $ 3,480
========== ==========

NOTE 8 - REAL ESTATE LEASING ACTIVITIES

The following table provides information about the Company's
investments in real estate owned at September 30, 2003 (in thousands):

Land................................................................. $ 630
Leasehold interest................................................... 4,800
Office building...................................................... 3,596
Apartment buildings.................................................. 3,380
Hotel................................................................ 4,040
-----------
16,446
Less accumulated depreciation........................................ (640)
-----------
Total........................................................... $ 15,806
===========

Minimum future rental income on non-cancelable operating leases
associated with the real estate investments that have terms in excess of one
year for each of the five succeeding fiscal years ended September 30, are as
follows (in thousands): 2004 - $255; 2005 - $255; 2006 - $185; 2007 - $29 and
2008 - $20.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 9 - DEBT

Debt other than secured revolving credit facilities-leasing consists of
the following:

At September 30,
--------------------------
2003 2002
---------- -----------
(in thousands)

Senior debt.......................................................... $ 54,027 $ 65,336

Non-recourse debt:
Energy:
Revolving credit facilities..................................... 31,000 49,345
Real estate finance:
Revolving credit facility....................................... 18,000 18,000
Other........................................................... 1,663 875
---------- ----------
Total non-recourse debt....................................... 50,663 68,220
Other debt........................................................... 28,477 19,533
---------- ----------
133,167 153,089
Less current maturities.............................................. 59,471 4,320
---------- ----------
$ 73,696 $ 148,769
========== ==========

Following is a description of borrowing arrangements in place at
September 30, 2003 and 2002:

Senior Debt. In July 1997, the Company issued $115.0 million of 12%
Senior Notes (the "12% Notes") due August 2004 in a private placement. These
notes were exchanged in November 1997 with a like amount of 12% Notes which were
registered under the Securities Act of 1933. Provisions of the indenture under
which the 12% Notes were issued limit dividend payments, mergers and
indebtedness, place restrictions on liens and guarantees and require the
maintenance of certain financial ratios. At September 30, 2003, the Company was
in compliance with such provisions.

Energy-Revolving Credit Facilities. In July 2002, Atlas America, the
Company's energy subsidiary, entered into a $75.0 million credit facility led by
Wachovia Bank. The revolving credit facility has a current borrowing base of
$54.2 million which may be increased or decreased subject to growth in the
Company's oil and gas reserves. The facility permits draws based on the
remaining proved developed non-producing and proved undeveloped natural gas and
oil reserves attributable to Atlas America's wells and the projected fees and
revenues from operation of the wells and the administration of energy
partnerships. Up to $10.0 million of the facility may be in the form of standby
letters of credit. The facility is secured by Atlas America's assets. The
revolving credit facility has a term ending in July 2005 and bears interest at
one of two rates (elected at the borrower's option) which increase as the amount
outstanding under the facility increases: (i) Wachovia prime rate plus between
25 to 75 basis points, or (ii) LIBOR plus between 175 and 225 basis points.

The Wachovia credit facility requires Atlas America to maintain
specified net worth and specified ratios of current assets to current
liabilities and debt to EBITDA, and requires the Company to maintain a specified
interest coverage ratio. In addition, the facility limits sales, leases or
transfers of assets and the incurrence of additional indebtedness. The facility
limits the dividends payable by Atlas America to the Company, on a cumulative
basis, to 50% of Atlas America's net income from and after April 1, 2002 plus
$5.0 million. In addition, Atlas America is permitted to repay intercompany debt
to the Company only up to the amount of the Company federal income tax liability
attributable to Atlas America and accrued interest on the senior notes. The
facility terminates in July 2005, when all outstanding borrowings must be
repaid. At September 30, 2003 and 2002, $32.3 million and $45.0 million,
respectively, were outstanding under this facility, including $1.3 million each
year under letters of credit. The interest rates ranged from 2.88% to 2.90% at
September 30, 2003.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 9 - DEBT - (Continued)

In September 2003, Atlas Pipeline amended and increased its revolving
credit facility with Wachovia Bank to provide for maximum borrowings of $20.0
million. Up to $3.0 million of the facility may be used for standby letters of
credit. Borrowings under the facility are secured by a lien on and security
interest in all the property of Atlas Pipeline and its subsidiaries, including
pledges by Atlas Pipeline of the issued and outstanding units of its
subsidiaries. The revolving credit facility has a term ending in December 2005
and bears interest at one of two rates, elected at Atlas Pipeline's option: (i)
the Base Rate plus the Applicable Margin or (ii) the Euro Rate plus the
Applicable Margin. As used in the facility agreement, the Base Rate is the
higher of (a) Wachovia Bank's prime rate or (b) the sum of the federal funds
rate plus 50 basis points. The Euro Rate is the average of specified LIBOR rates
divided by 1.00 minus the percentage prescribed by the Federal Reserve Board for
determining the reserve requirements for euro currency funding. The Applicable
Margin varies with Atlas Pipeline's leverage ratio from between 150 to 250 basis
points (for the Euro Rate option) or 0 to 75 basis points (for the Base Rate
option). Draws under any letter of credit bear interest as specified under (i),
above. The credit facility contains financial covenants, including the
requirement that Atlas Pipeline maintain: (a) a leverage ratio not to exceed 3.0
to 1.0, (b) an interest coverage ratio greater than 3.5 to 1.0 and (c) a minimum
tangible net worth of $30.5 million. In addition, the facility limits, among
other things, sales, leases or transfers of property by Atlas Pipeline, the
incurrence by Atlas Pipeline of other indebtedness and certain investments by
Atlas Pipeline. There were no outstanding borrowings on this facility at
September 30, 2003 and $5.6 million at September 30, 2002.

Real Estate Finance-Revolving Credit Facility. The Company has an $18.0
million revolving line of credit with Sovereign Bank. Interest is payable
monthly at The Wall Street Journal prime rate (4.0% at September 30, 2003) and
principal is due upon expiration in July 2005. Advances under this line are to
be utilized to acquire commercial real estate or interests therein, to fund or
purchase loans secured by commercial real estate or interests, or to reduce
indebtedness on loans or interests which the Company owns or holds. The advances
are secured by the properties related to these funded transactions. At September
30, 2003 and 2002, $18.0 million had been advanced under this line.

The more significant components of Other Debt are described as follows:

Real Estate Finance-Other Debt. The Company, through certain operating
subsidiaries, has a $6.8 million term note with Hudson United Bank for its
commercial real estate loan operations. At September 30, 2003 and 2002, $6.4
million was outstanding on this note. The credit facility bears interest at The
Wall Street Journal prime rate minus one percent (3.0% at September 30, 2003)
and is secured by the borrowers' interests in certain commercial loans and by a
pledge of their outstanding capital stock. The Company has guaranteed repayment
of the credit facility. The facility is due on October 1, 2004.

The Company, through certain operating subsidiaries, has a $10.0
million term loan with The Marshall Group. The loan bears interest at the three
month LIBOR rate plus 350 basis points (4.92% at September 30, 2003), adjusted
annually. Principal and interest are payable monthly based on a five-year
amortization schedule maturing October 31, 2006. The loan is secured by the
Company's interest in certain portfolio loans and real estate. At September 30,
2003 and 2002, $5.8 million and $7.9 million, respectively, was outstanding on
this loan.

The Company has a $5.0 million revolving line of credit with Sovereign
Bank, which expires August 2005. Interest accrues at The Wall Street Journal
prime rate (4.0% at September 30, 2003) and payment of accrued interest and
principal is due upon the expiration date. Advances under this line are with
full recourse to the Company and are secured by a pledge of 425,000 common
shares of RAIT held by the Company. Credit availability, which was $5.0 million
at September 30, 2003, is based upon the value of those shares. Advances under
this facility must be used to repay bank debt, to acquire commercial real estate
or interests therein, fund or purchase loans secured by commercial real estate
or interests therein, or reduce indebtedness on loans or interests which the
Company owns or holds and for other general corporate purposes. At September 30,
2003 and 2002, $5.0 million had been advanced under this line.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 9 - DEBT - (Continued)

The Company maintains a line of credit with Commerce Bank for $5.0
million. The facility is secured by a pledge of 440,000 common shares of RAIT
held by the Company. Credit availability is 60% of the value of those shares,
and was $5.0 million at September 30, 2003. The loans bear interest, at the
Company's election, at either The Wall Street Journal prime rate or LIBOR plus
250 basis points, with a minimum rate of 5.5% and a maximum rate of 9.0%. The
facility terminates in May 2005, subject to extension. The facility requires the
Company to maintain a specified net worth and ratio of liabilities to tangible
net worth, and prohibits transfer of the collateral. At September 30, 2003, $5.0
million had been advanced under this line of credit. No amounts had been
advanced under this line of credit at September 30, 2002.

During the year ended September 30, 2002, the Company issued
convertible notes payable in the amount of $11,000 to two executive officers of
its subsidiary, LEAF. The notes accrue interest at a rate of 8% per annum, and
mature in 2012. No payment of accrued interest or principal is due until 2007,
at which time accrued interest is due. Thereafter, monthly interest payments are
required until the notes mature. The notes can be converted into 11.5% of the
subsidiary's common stock at the earlier of August 1, 2004 or the date of legal
defeasance of the senior debt.

Annual debt principal payments over the next five fiscal years ending
September 30 are as follows: (in thousands):

2004............................. $ 59,471
2005............................. $ 71,728
2006............................. $ 1,932
2007............................. $ 25
2008............................. $ 11

Secured revolving credit facilities-leasing. In June 2002, the Company
and LEAF I LP (the "Borrowers") entered into a warehouse credit line with
National City Bank that has an aggregate borrowing limit of up to $10.0 million,
consisting of revolving credit and term loan components. The Borrowers are
jointly, severally and directly liable for the full and prompt payment of each
loan under the warehouse credit line. Interest on the facility is calculated at
LIBOR plus three percent per annum at the time of borrowing. Interest rates on
the debt outstanding at September 30, 2003 ranged from 4.10% to 4.18%.
Borrowings under the facility are collateralized by the leases being financed
and the underlying equipment being leased. Obligations under this facility are
guaranteed by the Company. The agreement contains certain covenants pertaining
to the Borrowers, including the maintenance of certain financial ratios and
restrictions on changes in the Borrower's ownership. Outstanding borrowings at
September 30, 2003 were approximately $2.5 million. The facility expires in
December 2003.

In May 2003, the Company and LEAF I LP (the "Borrowers") entered into a
revolving credit facility with Commerce Bank that has an aggregate borrowing
limit of up to $10.0 million. The Borrowers are jointly, severally and directly
liable for the full and prompt payment of each loan under the revolving credit
facility. Interest on the facility is calculated at the Borrower's option, at
the bank's prime rate plus 1 percent or the bank's LIBOR rate plus 3 percent.
The interest rate on outstanding borrowings at September 30, 2003 was 4.12%.
Borrowings under the facility are collateralized by the leases being financed
and the underlying equipment being leased. Obligations under this facility are
guaranteed by the Company. The agreement contains certain covenants pertaining
to the Borrowers, including the maintenance of certain financial ratios. As of
September 30, 2003, approximately $4.7 million was outstanding on the facility.
The facility expires in May of 2004.

At September 30, 2003, the Company has complied with all financial
covenants in its debt agreements.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 10 - INCOME TAXES

The following table details the components of the Company's income tax
expense from continuing operations for the fiscal years 2003, 2002 and 2001.

Years Ended September 30,
---------------------------------
2003 2002 2001
---------- ----------- --------
(in thousands)

Provision (benefit) for income taxes:
Current:
Federal................................................................. $ 341 $ 6,365 $ 6,023
State................................................................... 24 (619) 158
Deferred................................................................... 4,221 (2,332) 146
---------- ---------- ----------
$ 4,586 $ 3,414 $ 6,327
========== ========== ==========

A reconciliation between the statutory federal income tax rate and the
Company's effective income tax rate is as follows:

Years Ended September 30,
---------------------------------
2003 2002 2001
---------- ----------- --------

Statutory tax rate........................................................... 35% 35% 35%
Statutory depletion.......................................................... (2) (4) (3)
Non-conventional fuel and low income housing credits......................... - (3) (3)
Excessive employee remuneration.............................................. - - 2
Goodwill..................................................................... - - 1
Tax-exempt interest.......................................................... (2) (2) (2)
State income tax............................................................. 1 3 1
-------- -------- --------
32% 29% 31%
======== ======== ========

The components of the net deferred tax liability are as follows:

September 30,
2003 2002
------------ ---------
(in thousands)

Deferred tax assets related to:
Tax credit carryforwards............................................... $ - $ 28
FIN 46 assets.......................................................... 8,858 -
Interest receivable on real estate loans............................... 6,480 688
Stock option exercises................................................. 558 -
Accrued expenses....................................................... 6,057 7,335
Provision for possible losses.......................................... 674 1,185
----------- ---------
$ 22,627 $ 9,236
----------- ---------

Deferred tax liabilities related to:
Property and equipment bases differences............................... (29,065) (17,447)
Investments in real estate ventures.................................... (3,812) (2,491)
Unrealized gain on investments......................................... (2,628) (2,899)
ESOP benefits.......................................................... - (132)
----------- ---------
(35,505) (22,969)
Net deferred tax liability................................................ $ (12,878) $ (13,733)
=========== =========

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 10 - INCOME TAXES - (Continued)

Generally accepted accounting principles require that deferred tax
assets be reduced by a valuation allowance if it is more likely than not that
some portion or all of the deferred tax assets will not be realized. No
valuation allowance was needed at September 30, 2003 or 2002.

NOTE 11 - EMPLOYEE BENEFIT PLANS

Employee Stock Ownership Plan. The Company sponsors an Employee Stock
Ownership Plan ("ESOP"), which is a qualified non-contributory retirement plan
established to acquire shares of the Company's common stock for the benefit of
all employees who are 21 years of age or older and have completed 1,000 hours of
service for the Company. Contributions to the ESOP are made at the discretion of
the Board of Directors. In September 1998, the Company loaned $1.3 million to
the ESOP, which the ESOP used to acquire 105,000 shares of the Company's common
stock. The ESOP loan receivable (a reduction in stockholders' equity) is reduced
by the amount of any loan principal reduction resulting from contributions by
the Company to the ESOP.

The common stock purchased by the ESOP is held by the ESOP trustee in a
suspense account. On an annual basis, a portion of the common stock is released
from the suspense account. As of September 30, 2003, there were 269,800 shares
allocated to participants, and 105,000 unallocated shares in the plan.
Compensation expense related to the plan amounted to $159,800, $182,200 and
$151,200 for the years ended September 30, 2003, 2002 and 2001, respectively.

Employee Savings Plan. The Company sponsors an Employee Retirement
Savings Plan and Trust under Section 401(k) of the Internal Revenue Code which
allows employees to defer up to 15% of their income, subject to certain
limitations, on a pretax basis through contributions to the savings plan. Prior
to March 1, 2002, the Company matched up to 100% of each employee's
contribution, subject to certain limitations; thereafter, up to 50%. Included in
general and administrative expenses are $283,700 $335,200 and $363,800 for the
Company's contributions for the years ended September 30, 2003, 2002 and 2001,
respectively.

Stock Options. The following table summarizes certain information about
the Company's equity compensation plans, in the aggregate, as of September 30,
2003.

- ----------------------------------------------------------------------------------------------------------------------------
(a) (b) (c)
- ----------------------------------------------------------------------------------------------------------------------------
Number of securities remaining
Number of securities to be available for future issuance
issued upon exercise of Weighted-average exercise under equity compensation plans
outstanding options, price of outstanding excluding securities reflected
Plan category warrants and rights options, warrants and rights in column (a)
- ----------------------------------------------------------------------------------------------------------------------------

Equity compensation plans 1,918,986 $ 10.39 288,599
approved by security
holders
- ----------------------------------------------------------------------------------------------------------------------------
Equity compensation plans 36,554 $ .11 -
not approved by security
holders
- ----------------------------------------------------------------------------------------------------------------------------
Total 1,955,540 $ 10.21 288,599
- ----------------------------------------------------------------------------------------------------------------------------

The Company has four existing employee stock option plans, those of
1989, 1997, 1999 and 2002. No further grants may be made under the 1989 and 1997
plans. Options under all plans become exercisable as to 25% of the optioned
shares each year after the date of grant, and expire not later than ten years
after the date of grant.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 11 - EMPLOYEE BENEFIT PLANS - (Continued)

The 1989 plan authorized the granting of up to 1,769,670 shares (as
amended during the fiscal year ended September 30, 1996) of the Company's common
stock in the form of incentive stock options ("ISO's"), non-qualified stock
options and stock appreciation rights ("SAR's").

The 1997 Key Employee Stock Option Plan authorized the granting of up
to 825,000 shares of the Company's common stock in the form of ISO's,
non-qualified stock options and SAR's. No options were issued under this plan
during fiscal 2003. In fiscal 2002 and 2001, options for 4,000 and 55,000 shares
were issued under this plan, respectively.

The 1999 Key Employee Stock Option Plan authorized the granting of up
to 1,000,000 shares of the Company's common stock in the form of ISO's,
non-qualified stock options and SAR's. No options were issued under this plan
during fiscal 2003. In fiscal 2002 and 2001, options for 62,533 and 371,000
shares, respectively, were issued under this plan.

In April 2002, stockholders approved the Resource America, Inc. 2002
Key Employee Stock Option Plan. This plan, for which 750,000 shares were
reserved, provides for the issuance of ISO's, non-qualified stock options and
SAR's. In fiscal 2003 and 2002, options for 5,000 shares and 664,967,
respectively, were issued under this plan.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 11 - EMPLOYEE BENEFIT PLANS - (Continued)

Transactions for the four employee stock option plans are summarized as
follows:

Years Ended September 30,
---------------------------------------------------------------------------------
2003 2002 2001
------------------------- ------------------------- ---------------------------
Weighted Weighted Weighted
Average Average Average
Shares Exercise Price Shares Exercise Price Shares Exercise Price
------ -------------- ------ -------------- ------ ---------------

Outstanding - beginning of year.. 2,375,504 $ 9.86 1,892,447 $ 10.27 1,642,967 $ 9.38
Granted....................... 5,000 $ 11.50 731,500 $ 8.24 424,000 $ 11.06
Exercised..................... (385,281) $ 7.61 (222,682) $ 7.93 (155,947) $ 2.68
Forfeited..................... (145,969) $ 10.67 (25,761) $ 11.06 (18,573) $ 13.33
--------- ---------- ---------
Outstanding - end of year..... 1,849,254 $ 10.26 2,375,504 $ 9.86 1,892,447 $ 10.27
========= ========= ========== ========= ========= ========

Exercisable, at end of year...... 1,053,843 $ 11.29 1,036,006 $ 10.36 743,213 $ 9.64
========= ========= ========== ========= ========= ========
Available for grant.............. 227,688 86,719 42,458
========= ========== =========
Weighted average fair value per
share of options granted
during the year............... $ 8.07 $ 5.10 $ 8.73
========= ========= ========

The following information applies to employee stock options outstanding
as of September 30, 2003:

Outstanding Exercisable
--------------------------------------------- --------------------------
Weighted
Average Weighted Weighted
Range of Contractual Average Average
Exercise Prices Shares Life (Years) Exercise Price Shares Exercise Price
- -------------------- ------ ------------ -------------- ------ --------------

$ 2.73 80,057 2.22 $ 2.73 80,057 $ 2.73
$ 7.47 - $ 8.08 693,750 7.55 $ 7.65 276,437 $ 7.60
$ 9.19 - $ 9.34 237,500 8.74 $ 9.32 59,375 $ 9.32
$ 11.03 - $ 11.50 394,947 7.36 $ 11.06 194,974 $ 11.06
$ 15.50 443,000 6.64 $ 15.50 443,000 $ 15.50
---------- ----------
1,849,254 1,053,843
========== ==========

In connection with the acquisition of Atlas America, the Company issued
options for 120,213 shares at an exercise price of $.11 per share to certain
employees of Atlas America who had held options of Atlas America before its
acquisition by the Company. Options for 36,554 shares remain outstanding and are
exercisable as of September 30, 2003.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 11 - EMPLOYEE BENEFIT PLANS - (Continued)

SFAS No. 123 requires the disclosure of pro forma net income (loss) and
earnings (loss) per share as if the Company had adopted the fair value method
for stock options granted after June 30, 1996. Under SFAS No. 123, the fair
value of stock-based awards to employees is calculated through the use of option
pricing models, even though such models were developed to estimate the fair
value of freely tradable, fully transferable options without vesting
restrictions, which significantly differ from the Company's stock option awards.
These models also require subjective assumptions, including future stock price
volatility and expected time to exercise, which greatly affect the calculated
values. The Company's calculations were made using the Black-Scholes option
pricing model with the following weighted average assumptions: expected life, 10
years following vesting; stock volatility, 70%, 64% and 68% in fiscal 2003, 2002
and 2001, respectively; risk-free interest rate, 4.0%, 4.4% and 5.5% in fiscal
2003, 2002 and 2001, respectively; dividends were based on the Company's
historical rate.

The Company accounts for its four existing employee stock option plans
under the recognition and measurement principles of APB No. 25 and related
interpretations. No stock-based employee compensation cost is reflected in net
income (loss), as all options granted under those plans had an exercise price
equal to the market value of the underlying common stock on the date of grant.
The following table illustrates the effect on net income (loss) and earnings per
share if the Company had applied the fair value recognition provisions of SFAS
123 to stock-based employee compensation.

Years Ended September 30,
-----------------------------------------
2003 2002 2001
---------- ----------- ---------
(in thousands, except per share data)

Net (loss) income, as reported............................................ $ (2,915) $ (3,309) $ 9,829

Less total stock-based employee compensation expense determined under the fair
value based method for all awards, net
of income taxes........................................................ (3,100) (3,464) (2,505)
----------- ----------- -----------
Pro forma net (loss) income............................................... $ (6,015) $ (6,773) $ 7,324
=========== =========== ===========

(Loss) earnings per share:
Basic - as reported.................................................... $ (.17) $ (.19) $ .55
Basic - pro forma...................................................... $ (.35) $ (.39) $ .41

Diluted - as reported.................................................. $ (.17) $ (.19) $ .53
Diluted - pro forma.................................................... $ (.34) $ (.38) $ .40

Other Plans. In addition to the employee stock option plans, the
stockholders approved the Resource America, Inc. 1997 Non-Employee Director
Deferred Stock and Deferred Compensation Plan for which a maximum of 75,000
units were reserved for issuance, all of which have been issued. The fair value
of the grants awarded (at an average of $13.43 per unit), $1.1 million in total,
has been charged to operations over the vesting period. As of September 30,
2003, 57,000 units (average $13.54 per unit) were outstanding and fully vested.
During the fiscal year, 3,000 units were forfeited and 15,000 units (at an
average of $13.37 per unit) were converted to 15,000 shares of the Company's
common stock and issued to a former director who resigned in April 2003. The
plan was terminated as of April 30, 2002, as provided by the terms of the plan,
except with respect to previously awarded grants. No further grants can be made
under this plan.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 11 - EMPLOYEE BENEFIT PLANS - (Continued)

In April 2002, the stockholders approved the Resource America, Inc.
2002 Non-Employee Director Deferred Stock and Deferred Compensation Plan for
which a maximum of 75,000 units were reserved for issuance. In fiscal 2003,
9,130 units (at an average of $8.21 per unit) were issued under this plan. As of
September 30, 2003, 12,732 units (at an average of $9.42 per unit) were
outstanding under this plan. During the fiscal year, 7,540 units were forfeited
and 1,357 units (at an average of $11.05 per unit) were converted to 1,357
shares of the Company's common stock and issued to a former director who
resigned in April 2003. The fair value of the grants awarded (at an average of
$9.85 per unit), $213,080 in total, has been charged to operations over the
vesting period. As of September 30, 2003, 60,911 units are available for
issuance under this plan.

Under these plans, non-employee directors of the Company are awarded
units on an annual basis representing the right to receive one share of the
Company's common stock for each unit awarded. In April 2003, the stockholders
approved an amendment to each plan concerning the vesting schedule whereby units
are now vested on the later of the fifth anniversary of the date of becoming an
eligible director and the first anniversary of the grant of units. Units will
vest sooner upon a change of control of the Company or death or disability of a
director, provided the director has completed at least six months of service.
Upon termination of service by a director, all unvested units are forfeited.

Under the SERP of E. Cohen, the Company will pay an annual benefit of
75% of his average income after he has reached retirement age (each as defined
in the employment agreement). Upon termination, he is entitled to receive lump
sum payments in various amounts of between 25% and five times average
compensation (depending upon the reason for termination) and, for termination
due to disability, a monthly benefit equal to the SERP benefit (which will
terminate upon commencement of payments under the SERP). During fiscal 2003,
2002 and 2001, operations were charged $315,000, $1.1 million and $927,000,
respectively, with respect to these commitments.

NOTE 12 - COMMITMENTS AND CONTINGENCIES

The Company leases office space and equipment under leases with varying
expiration dates through 2008. Rental expense was $2.6 million, $2.1 million and
$1.9 million for the years ended September 30, 2003, 2002 and 2001,
respectively. At September 30, 2003, future minimum rental commitments for the
next five fiscal years were as follows (in thousands):

Leases Subleases Net Commitments
-------- ----------- ----------------

2004.............................. $ 1,400 $ (183) $ 1,217
2005.............................. 1,251 (182) 1,069
2006.............................. 884 (161) 723
2007.............................. 650 (113) 537
2008.............................. 363 - 363

The Company is the managing general partner of various energy
partnerships, and has agreed to indemnify each investor partner from any
liability that exceeds such partner's share of partnership assets. Subject to
certain conditions, investor partners in certain energy partnerships have the
right to present their interests for purchase by the Company, as managing
general partner. The Company is not obligated to purchase more than 5% or 10% of
the units in any calendar year. Based on past experience, the Company believes
that any liability incurred would not be material.

The Company may be required to subordinate a part of its net
partnership revenues to the receipt by investor partners of cash distributions
from the energy partnerships equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreements.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 12 - COMMITMENTS AND CONTINGENCIES - (Continued)

The Company is party to employment agreements with certain executives
that provide for compensation and certain other benefits. The agreements also
provide for severance payments under certain circumstances.

The Company is a defendant in a proposed class action originally filed
in February 2000 in the New York Supreme Court, Chautauqua County, by
individuals, putatively on their own behalf and on behalf of similarly situated
individuals, who leased property to the Company. The complaint alleges that the
Company is not paying lessors the proper amount of royalty revenues derived from
the natural gas produced from the wells on the leased property. The complaint
seeks damages in an unspecified amount for the alleged difference between the
amount of royalties actually paid and the amount of royalties that allegedly
should have been paid. The Company believes the complaint is without merit and
is defending itself vigorously.

A real estate investment partnership in which the Company has a general
partner interest, has obtained senior lien financing with respect to four
properties it acquired. The senior liens are with recourse only to the
properties securing them subject to certain standard exceptions, which the
Company has guaranteed. These guarantees expire as the related indebtedness is
paid down over the next ten years. In addition, property owners have obtained
senior lien financing with respect to six of our loans. The senior liens are
with recourse only to the properties securing them subject to certain standard
exceptions, which we have guaranteed. These guarantees expire as the related
indebtedness is paid down over the next six years.

The Company is also a party to various routine legal proceedings
arising out of the ordinary course of its business. Management believes that
none of these actions, individually or in the aggregate, will have a material
adverse effect on the Company's financial condition or operations.

NOTE 13 - HEDGING ACTIVITIES

The Company, through its energy subsidiaries, from time to time enters
into natural gas futures and option contracts to hedge its exposure to changes
in natural gas prices. At any point in time, such contracts may include
regulated New York Mercantile Exchange ("NYMEX") futures and options contracts
and non-regulated over-the-counter futures contracts with qualified
counterparties. NYMEX contracts are generally settled with offsetting positions,
but may be settled by the delivery of natural gas.

The Company formally documents all relationships between hedging
instruments and the items being hedged, including the Company's risk management
objective and strategy for undertaking the hedging transactions. This includes
matching the natural gas futures and options contracts to the forecasted
transactions. The Company assesses, both at the inception of the hedge and on an
ongoing basis, whether the derivatives are highly effective in offsetting
changes in the fair value of hedged items. Historically these contracts have
qualified and been designated as cash flow hedges and recorded at their fair
values. Gains or losses on future contracts are determined as the difference
between the contract price and a reference price, generally prices on NYMEX.
Such gains and losses are charged or credited to accumulated other comprehensive
income (loss) and recognized as a component of sales revenue in the month the
hedged gas is sold. If it is determined that a derivative is not highly
effective as a hedge or it has ceased to be a highly effective hedge, due to the
loss of correlation between changes in gas reference prices under a hedging
instrument and actual gas prices the Company will discontinue hedge accounting
for the derivative and subsequent changes in fair value for the derivative will
be recognized immediately into earnings.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 13 - HEDGING ACTIVITIES - (Continued)

At September 30, 2003, the Company had no open natural gas futures
contracts related to natural gas sales and accordingly, had no unrealized loss
or gain related to open NYMEX contracts at that date. Its net unrealized gain
was approximately $316,600 at September 30, 2002. The Company recognized a loss
of $1.1 million, $59,000 and $599,000 on settled contracts covering natural gas
production for the years ended September 30, 2003, 2002 and 2001, respectively.
The Company recognized no gains or losses during the three year period ended
September 30, 2003 for hedge ineffectiveness or as a result of the
discontinuance of cash flow hedges.

Although hedging provides the Company some protection against falling
prices, these activities could also reduce the potential benefits of price
increases, depending upon the instrument.

NOTE 14 - DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE

Discontinued Operations

In June 2002, the Company adopted a plan to dispose of Optiron
Corporation, an energy technology company in which the Company owned 50% and
reduced its interest in Optiron to 10% through a sale to current management
which was completed in September 2002. In connection with the sale, the Company
forgave $4.3 million out of the $5.9 million of indebtedness owed by Optiron.
The remaining $1.6 million of indebtedness was retained by the Company in the
form of a promissory note secured by all of Optiron's assets and by the common
stock of Optiron's 90% shareholder. The note bears interest at the prime rate
plus 1% payable monthly; an additional 1% will accrue until the maturity date of
the note in 2022.

Under the terms of the plan of disposal, Optiron was obligated to pay
to the Company 10% of Optiron's revenues if such revenues exceeded $2.0 million
in the twelve month period following the closing of the transaction. As a
result, Optiron became obligated to pay the Company $295,000. This payment is
due in March 2004.

In accordance with SFAS No. 144, the results of operations have been
prepared under the financial reporting requirements for discontinued operations,
pursuant to which, all historical results of Optiron are included in the results
of discontinued operations rather than the results of continuing operations for
all periods presented.

Summarized operating results of the discontinued Optiron operations are
as follows:

Years Ended September 30,
-----------------------------------------
2003 2002 2001
---------- ----------- -----------
(in thousands)

Loss from discontinued operations before income taxes........................ $ - $ (553) $ (1,493)
Income tax benefit........................................................... - 193 463
---------- ---------- ----------
Loss from discontinued operations............................................ $ - $ (360) $ (1,030)
========== ========== ==========

Income (loss) on disposal of discontinued operations before
income taxes............................................................... $ 295 $ (1,971) $ -
Income tax (provision) benefit............................................... (103) 690 -
---------- ---------- ----------
Income (loss) on disposal of discontinued operations......................... $ 192 $ (1,281) $ -
========== ========== ==========

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 14 - DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE - (Continued)

On August 1, 2000, the Company sold its small ticket equipment leasing
subsidiary, Fidelity Leasing, Inc., to European American Bank and AEL Leasing
Co., Inc., subsidiaries of ABN AMRO Bank, N.V. The Company received total
consideration of $152.2 million, including repayment of indebtedness of Fidelity
Leasing to the Company; the purchasers also assumed approximately $431.0 million
in debt payable to third parties and other liabilities. Of the $152.2 million
consideration, $16.0 million was paid by a non-interest bearing promissory note.
The promissory note was payable to the extent that payments were made on a pool
of Fidelity Leasing lease receivables and refunds were received with respect to
certain tax receivables.

In addition, $10.0 million was placed in escrow as security for the
Company's indemnification obligations to the purchasers, in connection with the
sale. Accordingly, FLI is reported as a discontinued operation for the years
ended September 30, 2002 and 2001. The Consolidated Financial Statements reflect
the operations of FLI as discontinued operations in accordance with APB Opinion
No. 30, "Reporting the Effects of Disposal of a Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions" ("APB
No. 30").

The successor in interest to the purchaser, made a series of claims
with respect to the Company's indemnification obligations and representations
which were settled in December 2002. Under the settlement, the Company and the
successor were released from certain terms and obligations of the original
purchase agreements, including many of the terms of the Company's
non-competition agreement, and from claims arising from circumstances known at
the settlement date. In addition, the Company (i) released to the successor the
$10.0 million in escrow previously referred to; (ii) paid the successor $6.0
million; (iii) guaranteed that the successor will receive payments of $1.2
million from a note, secured by FLI lease receivables, delivered to the Company
at the close of the FLI sale; and (iv) delivered two promissory notes to the
successor, each in the principal amount of $1.75 million, bearing interest at
the two-year treasury rate plus 500 basis points, due on December 31, 2003 and
2004, respectively. The Company recorded a loss from discontinued operations,
net of taxes, of $9.4 million in connection with the settlement.

Summarized operating results of the discontinued FLI operations are as
follows:

Years Ended September 30,
----------------------------------------
2003 2002 2001
---------- ----------- ----------
(in thousands)

(Loss) gain on disposal before income taxes.................................. $ - $ (14,460) $ (5,200)
Income tax benefit (provision)............................................... - 5,061 1,976
---------- ---------- ----------
(Loss) gain on disposal of discontinued operations........................... $ - $ (9,399) $ (3,224)
========== ========== ==========

The assets and liabilities of four of the entities that were
consolidated under the provisions of FIN 46 in the quarter ended September 30,
2003 have been classified as held for sale in accordance with the Company's
intent to sell its interest in the real estate loans underlying those assets and
liabilities. In addition, the Company foreclosed on one property in which it
held a loan and has classified this property as held for sale.

Summarized operating results of the Company's real estate operations
held for sale are as follows:

Years Ended September 30,
----------------------------------------
2003 2002 2001
--------- ----------- ----------
(in thousands)

Income on discontinued operations before income taxes........................ $ 1,584 $ - $ -
Income tax provision......................................................... (554) - -
---------- ---------- ----------
Income from discontinued operations.......................................... $ 1,030 $ - $ -
========== ========== ==========

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 14 - DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE - (Continued)

Summarized results of the discontinued operations Optiron, FLI and real
estate are:

Years Ended September 30,
-----------------------------------------
2003 2002 2001
--------- ---------- -----------
(in thousands)

Income (loss) from discontinued operations................................... $ 1,030 $ (360) $ (1,030)
Gain (loss) on disposal of discontinued operations........................... 192 (10,680) (3,224)
---------- ----------- -----------
Total discontinued income (loss) ............................................ $ 1,222 $ (11,040) $ (4,254)
========== =========== ===========

Cumulative Effect of Change in Accounting Principle

Optiron adopted SFAS 142 on January 1, 2002, the first day of its
fiscal year. Optiron performed the evaluation of its goodwill required by SFAS
142 and determined that it was impaired due to uncertainty associated with the
on-going viability of the product line with which the goodwill was associated.
This impairment resulted in a cumulative effect adjustment on Optiron's books of
$1.9 million before tax. The Company recorded in its second fiscal quarter of
fiscal 2002 year-end, which correlated to Optiron's first quarter, its share of
this cumulative effect adjustment in the same manner.

As described in Note 3, the Company recorded a $13.9 million cumulative
effect adjustment for a change in accounting principle upon the adoption of FIN
46.

NOTE 15 - SETTLEMENT OF LAWSUITS

The Company settled an action filed in the U.S. District Court for the
District of Oregon by the former chairman of TRM Corporation and his children.
The Company's chief executive officer and a former director and officer also had
been named as defendants. The plaintiffs' claims were for breach of contract and
fraud. The Company recorded a charge of $1.2 million, including related legal
fees, in the fiscal year ended September 30, 2003. The Company has made a claim
under its directors' and officers' insurance policy in connection with this
settlement.

The Company was a defendant in a class action complaint by stockholders
who purchased shares of the Company's common stock between December 17, 1997 and
February 22, 1999. Damages were sought in an unspecified amount for losses
allegedly incurred as the result of misstatements and omissions allegedly
contained in the Company's periodic reports and a registration statement filed
with the SEC. To avoid the potential of costly litigation, which would have
involved significant time of senior management, the Company settled this matter
for a maximum of $7.0 million plus approximately $1.0 million in costs and
expenses, of which $6.0 million was paid by two of the Company's directors' and
officers' liability insurers. The Company is seeking to obtain the balance of
$2.0 million through an action against a third insurer who refused to
participate in the settlement. The plaintiffs have agreed to reduce by 50% the
amount by which the $2.0 million exceeds any recovery from the insurer. The
Company charged operations $1.0 million in the fiscal year ended September 30,
2002, the amount of its maximum remaining exposure. If the Company is successful
in receiving reimbursement from the third insurer, future operations will be
benefited.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 16 - OPERATIONS OF ATLAS PIPELINE

In February 2000, the Company's natural gas gathering operations were
sold to Atlas Pipeline in connection with a public offering by Atlas Pipeline of
1,500,000 common units. The Company received net proceeds of $15.3 million for
the gathering systems, and Atlas Pipeline issued to the Company 1,641,026
subordinated units constituting a 51% combined general and limited partner
interest in Atlas Pipeline. A subsidiary of the Company is the general partner
of Atlas Pipeline and has a 2% partnership interest on a consolidated basis.

The Company's subordinated units are a special class of limited
partnership interest in Atlas Pipeline under which its rights to distributions
are subordinated to those of the publicly held common units. The subordination
period extends until December 31, 2004 and will continue beyond that date if
financial tests specified in the partnership agreement are not met. The
Company's general partner interest also includes a right to receive incentive
distributions if the partnership meets or exceeds specified levels of
distributions.

In May 2003, Atlas Pipeline completed a public offering of 1,092,500
common units of limited partner interest. The net proceeds after underwriting
discounts and commissions were approximately $25.2 million. These proceeds were
used in part to repay existing indebtedness of $8.5 million. Atlas Pipeline
intends to use the balance of these proceeds to fund future capital projects and
for working capital. Upon the completion of this offering the Company's combined
general and limited partner interest in Atlas Pipeline was reduced to 39%.
Because the Company, through its general partner interest, controls the
decisions and operations of Atlas Pipeline it is consolidated in the Company's
financial statements.

In connection with the Company's sale of the gathering systems to Atlas
Pipeline, the Company entered into agreements that:

o Require it to provide stand-by construction financing to Atlas
Pipeline for gathering system extensions and additions to a
maximum of $1.5 million per year for five years.

o Require it to pay gathering fees to Atlas Pipeline for natural
gas gathered by the gathering systems equal to the greater of
$.35 per Mcf ($.40 per Mcf in certain instances) or 16% of the
gross sales price of the natural gas transported.

During fiscal 2003, 2002 and 2001, the fee paid to Atlas Pipeline was
calculated based on the 16% rate. Through September 30, 2003, the Company has
not been required to provide any construction financing.

In September 2003, Atlas Pipeline entered into a purchase and sale
agreement with SEMCO Energy, Inc. ("SEMCO") pursuant to which Atlas Pipeline or
its designee will purchase all of the outstanding equity of SEMCO's wholly-owned
subsidiary, Alaska Pipeline Company ("Alaska Pipeline"), which owns an
intrastate natural gas transmission pipeline that delivers gas to metropolitan
Anchorage (the "Acquisition"). The total consideration, payable in cash at
closing, will be approximately $95.0 million, subject to an adjustment based on
the amount of working capital that Alaska Pipeline has at closing.

Consummation of the Acquisition is subject to a number of conditions,
including receipt of governmental and non-governmental consents and approvals
and the absence of a material adverse change in Alaska Pipeline's business.
Among the required governmental authorizations are approval of the Regulatory
Commission of Alaska and expiration, without adverse action, of the waiting
period under the Hart-Scott-Rodino Antitrust Improvements Act. The purchase and
sale agreement may be terminated by either Atlas Pipeline or SEMCO if the
transaction is not consummated by June 16, 2004. The purchase and sale agreement
contains customary representations, warranties and indemnifications.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 16 - OPERATIONS OF ATLAS PIPELINE - (Continued)

As part of the Acquisition, at closing, Alaska Pipeline and ENSTAR
Natural Gas Company ("ENSTAR"), a division of SEMCO which conducts its gas
distribution business in Alaska, will enter into a Special Contract for Gas
Transportation pursuant to which ENSTAR will pay a reservation fee for use of
all of the pipeline's transportation capacity of $943,000 per month, plus $.075
per thousand cubic feet, or mcf, of gas transported, for 10 years. During 2002,
total gas volumes transported on the Alaska Pipeline system averaged 130,000 mcf
per day. SEMCO will execute a gas transmission agreement with Alaska Pipeline
pursuant to which SEMCO will be obligated to make up any difference if the
Regulatory Commission of Alaska reduces the transportation rates payable by
ENSTAR pursuant to the Special Contract.

Further, Alaska Pipeline will enter into an Operation and Maintenance
and Administrative Services Agreement with ENSTAR under which ENSTAR will
continue to operate and maintain the pipeline for at least 5 years for a fee of
$334,000 per month for the first three years. Thereafter, ENSTAR's fee will be
adjusted for inflation.

Atlas Pipeline has received a commitment from Friedman, Billings,
Ramsey Group, Inc. ("FBR") to make a $25.0 million preferred equity investment
in a special purpose vehicle (the "SPV"), to be jointly owned and controlled by
FBR and Atlas Pipeline; such entity will be the acquirer of Alaska Pipeline.
Under the terms of the FBR commitment, Atlas Pipeline will have the right,
during the 18 months following the closing of the Acquisition, to purchase FBR's
preferred equity interest in the SPV at FBR's original cost plus accrued and
unpaid preferred distributions and a premium. If Atlas Pipeline does not
purchase FBR's interest, FBR has the right to require the Company to purchase
this interest. The Company will then have the right to require Atlas Pipeline to
purchase the equity interest from it. Atlas Pipeline intends to make a $24.0
million common equity investment in the SPV which Atlas Pipeline will fund in
part through its existing $20.0 million credit facility. The SPV has received a
commitment from Wachovia Bank, National Association and Wachovia Capital
Markets, LLC for a $50.0 million credit facility to partially finance the
Acquisition. Up to $25.0 million of borrowings under the facility will be
secured by a lien on and security interest in all of the SPV's property. In
addition, upon the earlier to occur of the termination of Atlas Pipeline's
subordination period or the amendment of the restrictions in the partnership
agreement on Atlas Pipeline's incurrence of debt, Atlas Pipeline will guarantee
all borrowings under the facility, securing the guarantee with a pledge of its
interest in the SPV.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 17 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMER INFORMATION

The Company's operations include five reportable operating segments. In
addition to the five reportable operating segments, certain other activities are
reported in the "Other energy" category and "All other" categories. These
operating segments reflect the way the Company manages its operations and makes
business decisions. The leasing segment first met the criteria for reportable
operating segments in the three months ended June 30, 2003, and accordingly, all
prior periods have been restated to reflect these new segments. The Company does
not allocate income taxes to its operating segments. Operating segment data for
the periods indicated are as follows:

Year Ended September 30, 2003 (in thousands):

Production Real
Well and Other Estate All
Drilling Exploration Energy (a) Finance Leasing Trapeza Other Eliminations Total
--------- ----------- ---------- --------- ------- ------- ----- ------------ -----

Revenues from
external customers... $52,879 $ 38,639 $ 14,171 $ 14,424 $ 4,140 $ 1,495 $ 7,271 $ (490) $ 132,529
Interest income......... - - 220 83 71 8 484 (195) 671
Interest expense........ - - 1,961 1,703 916 - 8,707 (195) 13,092
Depreciation,
depletion and
amortization......... - 8,042 3,553 221 196 - 136 - 12,148
Segment profit (loss)... 5,320 21,465 (6,308) 5,188 (2,857) 1,542 (10,020) - 14,330
Other significant
items:
Segment assets....... 7,844 145,614 78,930 371,735 15,668 4,987 46,004 - 670,782

- -----------
(a) Revenues and expenses from segments below the quantitative thresholds are
attributable to two operating segments of the Company. Those segments
include well services and transportation. These segments have never met
any of the quantitative thresholds for determining reportable segments.

Year Ended September 30, 2002 (in thousands):

Revenues from
external customers. $ 55,736 $ 28,916 $ 14,643 $ 16,711 $ 1,388 $ 185 $ 4,058 $ (253) $ 121,384
Interest income....... - - 686 145 145 - 519 (253) 1,242
Interest expense...... - - 2,200 1,790 44 - 9,035 (253) 12,816
Depreciation,
depletion and
amortization....... - 7,550 3,286 135 82 - 108 - 11,161
Segment profit (loss). 6,057 12,708 (5,444) 10,744 518 (15) (12,796) - 11,772
Other significant
items:
Segment assets..... 7,555 119,125 65,935 204,327 10,793 3,085 56,678 - 467,498

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 17 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS - (Continued)

Year Ended September 30, 2001 (in thousands):

Revenues from ........
external customers.. $ 43,464 $ 36,681 $ 15,746 $ 17,117 $ 1,066 $ - $ 4,974 $ (55) $ 118,993
Interest income....... - - 791 140 - - 2,323 (55) 3,199
Interest expense...... - - 1,714 2,961 - - 10,116 (55) 14,736
Depreciation,
depletion and
amortization........ 236 6,148 4,400 132 54 - 68 - 11,038
Segment profit (loss). 6,626 22,687 (10,258) 11,852 397 - (10,894) - 20,410
Other significant items:
Segment assets..... 5,646 102,756 86,127 207,682 390 - 63,863 - 446,464

- -----------
(a) Revenues and expenses from segments below the quantitative thresholds
are attributable to two operating segments of the Company. Those
segments include well services and transportation. These segments have
never met any of the quantitative thresholds for determining reportable
segments.

Operating profit (loss) per segment represents total revenues less
costs and expenses attributable thereto, including interest, provision for
possible losses and depreciation, depletion and amortization, excluding general
corporate expenses.

The Company's natural gas is sold under contract to various purchasers.
For the years ended September 30, 2003, 2002 and 2001, gas sales to First Energy
Solutions Corporation accounted for 14%, 13% and 14%, respectively, of our total
revenues. No other operating segments had revenues from a single customer or
borrower which exceeded 10% of total revenues.

NOTE 18 - SUPPLEMENTAL OIL AND GAS INFORMATION

Results of operations from oil and gas producing activities:

Years Ended September 30,
------------------------------------------
2003 2002 2001
---------- ----------- ------------
(in thousands)

Revenues..................................................................... $ 38,639 $ 28,916 $ 36,681
Production costs............................................................. (6,770) (6,691) (6,184)
Exploration expenses......................................................... (1,715) (1,573) (1,662)
Depreciation, depletion and amortization..................................... (8,042) (7,550) (6,148)
Income taxes................................................................. (7,519) (4,005) (7,223)
---------- ---------- ----------
Results of operations from oil and gas producing activities.................. $ 14,593 $ 9,097 $ 15,464
========== ========== ==========

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 18 - SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)

Capitalized Costs Related to Oil and Gas Producing Activities. The
components of capitalized costs related to the Company's oil and gas producing
activities are as follows:

At September 30,
------------------------------------------
2003 2002 2001
---------- ----------- ------------
(in thousands)

Proved properties............................................................ $ 844 $ 843 $ 1,861
Unproved properties.......................................................... 563 584 481
Wells and related equipment and facilities................................... 184,175 152,174 126,971
Support equipment and facilities............................................. 2,189 1,422 1,052
Uncompleted wells equipment and facilities................................... 51 51 38
----------- ----------- ----------
187,822 155,074 130,403
Accumulated depreciation, depletion, amortization and
valuation allowances....................................................... (50,170) (41,893) (33,129)
----------- ----------- ----------
Net capitalized costs................................................... $ 137,652 $ 113,181 $ 97,274
=========== =========== ==========

Costs Incurred in Oil and Gas Producing Activities. The costs incurred
by the Company in its oil and gas activities during fiscal years 2003, 2002 and
2001 are as follows:

Years Ended September 30,
-------------------------------------------
2003 2002 2001
---------- ----------- -------------
(in thousands)

Property acquisition costs:
Unproved properties........................................................ $ - $ 9 $ 90
Proved properties.......................................................... $ 224 $ 440 $ 337
Exploration costs.......................................................... $ 1,715 $ 1,573 $ 1,662
Development costs.......................................................... $ 26,721 $ 20,648 $ 20,273

The development costs above for the years ended September 30, 2003,
2002 and 2001 were substantially all incurred for the development of proved
undeveloped properties.

Oil and Gas Reserve Information (Unaudited). The estimates of the
Company's proved and unproved gas reserves are based upon evaluations made by
management and verified by Wright & Company, Inc., an independent petroleum
engineering firm, as of September 30, 2003, 2002 and 2001. All reserves are
located within the United States. Reserves are estimated in accordance with
guidelines established by the Securities and Exchange Commission and the
Financial Accounting Standards Board which require that reserve estimates be
prepared under existing economic and operating conditions with no provisions for
price and cost escalation except by contractual arrangements.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 18 - SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)

Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions, i.e. prices
and costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.

o Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation tests.
The area of a reservoir considered proved includes (a) that portion
delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any; and (b) the immediately adjoining portions not yet
drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the lower
proved limit of the reservoir.

o Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included
in the "proved" classification when successful testing by a pilot
project, or the operation of an installed program in the reservoir,
provides support for the engineering analysis on which the project
or program was based.

o Estimates of proved reserves do not include the following: (a) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reservoirs"; (b) crude oil,
natural gas, and natural gas liquids, the recovery of which is
subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics or economic factors; (c) crude oil,
natural gas and natural gas liquids, that may occur in undrilled
prospects; and (d) crude oil and natural gas, and natural gas
liquids, that may be recovered from oil shales, coal, gilsonite and
other such sources.

Proved developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and operation
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.

There are numerous uncertainties inherent in estimating quantities of
proven reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents estimates only
and should not be construed as being exact. In addition, the standardized
measures of discounted future net cash flows may not represent the fair market
value of the Company's oil and gas reserves or the present value of future cash
flows of equivalent reserves, due to anticipated future changes in oil and gas
prices and in production and development costs and other factors for effects
have not been proved.

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 18 - SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)

The Company's reconciliation of changes in proved reserve quantities is
as follows (unaudited):

Gas Oil
(Mcf) (Bbls)
----------- ----------

Balance September 30, 2000............................................ 113,142,544 1,766,654
Current additions................................................ 19,891,663 68,895
Sales of reserves in-place....................................... (88,068) (61)
Purchase of reserves in-place.................................... 7,159,387 40,881
Transfers to limited partnerships................................ (11,871,230) -
Revisions........................................................ (3,774,259) 102,136
Production....................................................... (6,342,667) (177,437)
----------- ---------
Balance September 30, 2001............................................ 118,117,370 1,801,068
Current additions................................................ 19,303,971 55,416
Sales of reserves in-place....................................... (510,812) (23,676)
Purchase of reserves in-place.................................... 280,594 2,180
Transfers to limited partnerships................................ (6,829,047) (45,001)
Revisions........................................................ (23,057) 260,430
Production....................................................... (7,117,276) (172,750)
----------- ---------
Balance September 30, 2002............................................ 123,221,743 1,877,667
Current additions................................................ 21,131,997 29,394
Sales of reserves in-place....................................... (56,480) (14,463)
Purchase of reserves in-place.................................... 7,294,727 34,472
Transfers to limited partnerships................................ (8,669,521) (31,386)
Revisions........................................................ (2,662,812) 119,038
Production....................................................... (6,966,899) (160,048)
----------- ---------
Balance September 30, 2003............................................ 133,292,755 1,854,674
=========== =========

Proved developed reserves at:
September 30, 2003............................................... 87,760,113 1,825,280
September 30, 2002............................................... 83,995,712 1,846,281
September 30, 2001............................................... 80,249,011 1,735,376

100

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 18 - SUPPLEMENTAL OIL AND GAS INFORMATION - (Continued)

The following schedule presents the standardized measure of estimated
discounted future net cash flows relating to proved oil and gas reserves. The
estimated future production is priced at fiscal year-end prices, adjusted only
for fixed and determinable increases in natural gas and oil prices provided by
contractual agreements. The resulting estimated future cash inflows are reduced
by estimated future costs to develop and produce the proved reserves based on
fiscal year-end cost levels. The future net cash flows are reduced to present
value amounts by applying a 10% discount factor. The standardized measure of
future cash flows was prepared using the prevailing economic conditions existing
at September 30, 2003, 2002 and 2001 and such conditions continually change.
Accordingly such information should not serve as a basis in making any judgment
on the potential value of recoverable reserves or in estimating future results
of operations (unaudited).

Years Ended September 30,
-------------------------------------------
2003 2002 2001
------------ ----------- -----------
(in thousands)

Future cash inflows..................................................... $ 709,401 $ 518,118 $ 485,781
Future production costs................................................. (179,758) (147,279) (126,979)
Future development costs................................................ (72,476) (55,644) (50,953)
Future income tax expense............................................... (125,398) (79,557) (76,584)
----------- ----------- -----------

Future net cash flows................................................... 331,769 235,638 231,265
Less 10% annual discount for estimated timing of cash flows........... (187,434) (131,512) (132,553)
----------- ----------- -----------
Standardized measure of discounted future net cash flows.............. $ 144,335 $ 104,126 $ 98,712
=========== =========== ===========

The future cash flows estimated to be spent to develop proved
undeveloped properties in the years ended September 30, 2004, 2005 and 2006 are
$27.6 million, $29.3 million and $15.6 million, respectively.

The following table summarizes the changes in the standardized measure
of discounted future net cash flows from estimated production of proved oil and
gas reserves after income taxes (unaudited):

Years Ended September 30,
--------------------------------------------
2003 2002 2001
---------- ----------- -------------
(in thousands)

Balance, beginning of year.............................................. $ 104,126 $ 98,712 $ 98,599
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs.............. (31,869) (22,223) (30,496)
Net changes in prices and production costs............................ 44,232 249 (21,530)
Revisions of previous quantity estimates.............................. (229) 3,787 (4,184)
Development costs incurred............................................ 3,689 4,107 4,011
Changes in future development costs................................... (166) (149) (853)
Transfers to limited partnerships..................................... (3,313) (3,970) (4,177)
Extensions, discoveries, and improved recovery less
related costs...................................................... 24,272 12,057 20,716
Purchases of reserves in-place........................................ 1,730 340 7,984
Sales of reserves in-place, net of tax effect......................... (200) (799) (204)
Accretion of discount................................................. 13,247 12,726 14,078
Net changes in future income taxes.................................... (18,740) 203 13,636
Other................................................................. 7,556 (914) 1,132
----------- ----------- -----------
Balance, end of year.................................................... $ 144,335 $ 104,126 $ 98,712
=========== =========== ===========

101

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 19 - QUARTERLY RESULTS (Unaudited)

Dec 31 March 31 June 30 September 30
------ -------- ------- ------------
(in thousands, except per share data)

Year ended September 30, 2003
Revenues............................................... $ 23,387 $ 41,669 $ 30,722 $ 36,751
Costs and expenses..................................... 20,769 37,116 25,775 34,539
---------- ---------- ---------- ----------
Income from continuing operations before taxes and
cumulative effect of change in accounting principle. 2,618 4,553 4,947 2,212
---------- ---------- ---------- ----------
Discontinued operations................................ - - - 1,222
Cumulative effect of change in accounting principle.... - - - (13,881)
---------- ---------- ---------- ----------
Net income (loss)...................................... $ 1,781 $ 3,095 $ 3,486 $ (11,277)
========== ========== ========== ==========

Net income (loss) per common share - basic:
From continuing operations.......................... $ .10 $ .18 $ .20 $ .09
Discontinued operations............................. - - - .07
Cumulative effect of change in accounting
principle......................................... - - - (.81)
---------- ---------- ---------- ------------
Net income (loss) per common share - basic............. $ .10 $ .18 $ .20 $ (.65)
========== ========== ========== ===========

Net income (loss) per common share - diluted:
From continuing operations.......................... $ .10 $ .18 $ .20 $ .07
Discontinued operations............................. - - - .07
Cumulative effect of change in accounting principle. - - - (.79)
---------- ---------- ---------- ----------
Net income (loss) per common share - diluted........... $ .10 $ .18 $ .20 $ (.65)
========== ========== ========== ===========

As described in Note 3, on July 1, 2003, the Company adopted FIN 46,
the consolidation of FIN 46 entities resulted in a $13.9 million after-tax
accounting cumulative effect charge in the Company's fourth fiscal quarter. In
addition, subsequent to adoption, the Company classified certain of these
entities as held for sale, resulting in income from discontinued operations of
$1.2 million in the Company's fourth fiscal quarter.

102

RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

NOTE 19 - QUARTERLY RESULTS (Unaudited)

Dec 31 March 31 June 30 September 30
----------- ---------- ----------- ------------
(in thousands, except per share data)

Revenues............................................... $ 33,782 $ 34,203 $ 24,727 $ 28,672
Costs and expenses..................................... 29,405 29,250 22,923 28,034
---------- ---------- ---------- ----------
Income from continuing operations before taxes......... 4,377 4,953 1,804 638
---------- ---------- ---------- ----------
Income from continuing operations before cumulative
effect of change in accounting principle............ 2,930 3,313 1,328 787
---------- ---------- ---------- ----------
Net income (loss)...................................... $ 2,189 $ 3,138 $ 6 $ (8,642)
========== ========== ========== ==========

Net income per common share - basic:
Income from continuing operations before
cumulative effect of change in accounting
principle......................................... $ .17 $ .19 $ .08 $ .04
========== ========== ========== ===========
Net income (loss) per common share - basic............. $ .13 $ .18 $ - $ .49
========== ========== ========== ===========

Net income per common share - diluted:
Income from continuing operations before
cumulative effect of change in accounting
principle......................................... $ .17 $ .19 $ .07 $ .04
========== ========== ========== ===========
Net income (loss) per common share - diluted........... $ .12 $ .18 $ - $ .49
========== ========== ========== ===========

As described in Note 14, in June 2002 the Company adopted a plan to
dispose of Optiron. Accordingly, the Company's share of Optiron's operations,
including the cumulative effect of the impairment of goodwill and the write-off
of certain advances to Optiron, has been reported as discontinued operations.
The amount of those charges to discontinued operations approximated $700, $200
and $1,300 in the quarters ended December 2001, March 2002 and June 2002,
respectively. The amount charged to discontinued operations with respect to
Optiron approximated $300 in each of the quarters ended December 2000 and March
2001 and $200 in each of the quarters ended June 2001 and September 2001. Also,
as described in Note 14, the Company sold FLI in August 2000. In the quarters
ended September 30, 2002 and 2001, the Company charged discontinued operations
approximately $9,400 and $3,200, respectively, based upon information that
became available during each of those quarters with regard to claims made by the
buyer with respect to the Company's indemnification obligations and
representations.

103

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Our Chief Executive Officer and Chief Financial Officer have evaluated
our disclosure controls and procedures, (as defined in Rules 13a-14 (c) and
15d-14(c)) within 90 days prior to the filing of this report. Based upon this
evaluation, these officers believe that our disclosure controls and procedures
are effective.

Changes in Internal Controls

There were no significant changes in our internal controls or in other
factors that could significantly affect these controls subsequent to the date of
our last evaluation of our internal controls by our Chief Executive Officer and
Chief Financial Officer.

104

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The Board of Directors is divided into three classes with directors in
each class serving three year terms. Information is set forth below regarding
the principal occupation of each director of the Company. There are no family
relationships among the directors and executive officers of the Company except
that Jonathan Z. Cohen, President, Chief Operating Officer and a director of the
Company, is a son of Edward E. Cohen, Chairman of the Board of Directors and
Chief Executive Officer of the Company.

Names of Directors, Principal Year in Which Service Term to Expire
Occupation and Other Information As Director Began At Annual Meeting
- -------------------------------- ---------------------- -----------------

Andrew M. Lubin, 57, President, Delaware Financial Group, Inc. (a
private investment firm) since 1990. 1994 2004

P. Sherrill Neff, 52, Founder and Managing Partner of Quaker
BioVentures, Inc. (a life sciences venture fund) since 2002. President and Chief
Financial Officer of Neose Technologies, Inc. (a publicly- traded life sciences
company) from 1994 to 2002. Director of Neose
Technologies, Inc. from 1994 to 2003. 1998 2004

Carlos C. Campbell, 66, President of C.C. Campbell and Company (a
management consulting firm) since 1985. Director of PICO Holdings, Inc.
(a publicly-traded diversified holding company) since 1998. Director of
NetWolves Corporation (a publicly-traded information technology company)
since 2003. 1990 2005

Edward E. Cohen, 65, Chairman of the Board of the Company since 1990
and Chief Executive Officer of the Company since 1988. President of the Company
from 2000 to 2003. Chairman of the Managing Board of Atlas Pipeline Partners GP,
LLC ("Atlas Pipeline") (a wholly-owned subsidiary of the Company that is the
general partner of a publicly-traded limited partnership, Atlas Pipeline
Partners, L.P., that owns and operates natural gas pipelines) since its
formation in 1999. Director of TRM Corporation (a publicly-traded consumer
services company) since 1998. Chairman of the Board of Brandywine Construction &
Management, Inc. (a property management
company) since 1994. 1988 2005

Jonathan Z. Cohen, 33, President of the Company since 2003 and Chief
Operating Officer and a Director of the Company since 2002. Executive Vice
President of the Company from 2001 to 2003. Senior Vice President of the Company
from 1999 to 2001. Vice Chairman of the Managing Board of Atlas Pipeline since
its formation in 1999. Vice Chairman and a director of Atlas America, Inc.
("Atlas America") (a wholly-owned subsidiary of the Company) since its
acquisition in 1998. Trustee and Secretary of RAIT Investment Trust ("RAIT") (a
publicly-traded real estate investment trust) since 1997. Vice Chairman of RAIT
since 2003. Chairman of the Board of The Richardson Company (a sales consulting
company) since 1999. 2002 2006

John S. White, 63, Senior Vice President of Royal Alliance
Associates, Inc. (an independent broker/dealer) since 2002. Chief
Executive Officer and President of DCC Securities Corporation (a
securities brokerage firm) from 1989 to 2002. 1993 2006

105

Non-Director Executive Officers

The Board of Directors appoints officers each year at its annual
meeting following the annual stockholders meeting and from time to time as
necessary.

Steven J. Kessler, 60, Senior Vice President and Chief Financial
Officer of the Company since 1997. Vice President-Finance and Acquisitions at
Kravco Company (a national shopping center developer and operator) from 1994 to
1997.

Freddie M. Kotek, 48, Senior Vice President of the Company since 1995.
Chairman of Atlas Resources, Inc. (a wholly-owned subsidiary of the Company)
since 2001 and Chief Executive Officer and President of Atlas Resources since
2002. President of Resource Leasing, Inc. (a wholly-owned subsidiary of the
Company) since 1995. President of Resource Properties, Inc. (a wholly-owned
subsidiary of the Company) from 2000 to 2001. Executive Vice President of
Resource Properties from 1993 to 2000.

Alan F. Feldman, 40, Senior Vice President of the Company since 2002.
President of Resource Properties since 2002. Vice President at Lazard Freres &
Co. (an investment bank) from 1998 to 2002. Executive Vice President at
PREIT-Rubin, Inc., the management subsidiary of Pennsylvania Real Estate
Investment Trust (a publicly-traded real estate investment trust) and its
predecessor, The Rubin Organization, from 1992 to 1998.

Nancy J. McGurk, 48, Vice President of the Company since 1992.
Treasurer and Chief Accounting Officer of the Company since 1989.

Other Significant Employees

The following sets forth certain information regarding other
significant employees of the Company:

Michael L. Staines, 54, Senior Vice President of the Company since
1989. Director of the Company from 1989 to 2000 and Secretary of the Company
from 1989 to 1998. President of Atlas Pipeline since 2001. Chief Operating
Officer and Managing Board Member of Atlas Pipeline since its formation in 1999.
Secretary of Atlas Pipeline from 1999 to 2003.

David E. Bloom, 39, Senior Vice President of the Company since 2001.
President of Resource Capital Partners, Inc. (a wholly-owned subsidiary of the
Company) since 2002. President of Resource Properties, Inc. (a wholly owned
subsidiary of the Company) from 2001 to 2002. Senior Vice President at Colony
Capital, LLC (an international real estate opportunity fund) from 1999 to 2001.
Director at Sonnenblick-Goldman Company (a real estate investment bank) from
1998 to 1999. Attorney at Willkie Farr & Gallagher (an international law firm)
from 1996 to 1998.

Crit S. DeMent, 51, Chairman and Chief Executive Officer of LEAF
Financial Corp. (a wholly-owned subsidiary of the Company) since 2001. President
of the Technology Finance Group of CitiCapital Vendor Finance in 2001. President
of the Small Ticket Group of European American Bank, a division of ABN AMRO,
from 2000 to 2001. President and Chief Operating Officer of Fidelity Leasing,
Inc. (a former wholly-owned subsidiary of the Company) from 1996 to 2000.

Frank P. Carolas, 43, Vice President of the Company since 2001.
Executive Vice President of Atlas America since 2001. Vice President of Atlas
America from 1998 to 2001.

Jeffrey C. Simmons, 44, Vice President of the Company since 2001.
Executive Vice President of Atlas America since 2001. Vice President of Atlas
America from 1998 to 2001.

106

Michael S. Yecies, 36, Vice President, Chief Legal Officer and
Secretary of the Company since 1998. Attorney at Duane Morris LLP (an
international law firm) from 1994 to 1998.

Information Concerning the Audit Committee

The Company has a standing Audit Committee. All of the members of the
Audit Committee are independent directors as defined by Nasdaq National Market
standards. The Board of Directors has determined that Mr. Neff is an "audit
committee financial expert" as defined by the regulations of the Securities and
Exchange Commission. The Audit Committee reviews the scope and effectiveness of
audits by the independent accountants, is responsible for the engagement of
independent accountants, and reviews the adequacy of the Company's internal
controls. The Committee held seven meetings during fiscal 2003. Members of the
Committee are Messrs. Lubin (Chairman), Neff and Campbell.

Code of Ethics

The Company has adopted a code of conduct applicable to all directors,
officers and employees that the Company believes meets the definition of a "code
of ethics" set forth in regulations of the Securities and Exchange Commission.
The Company undertakes to provide to any person without charge, upon request, a
copy of such code of conduct. Any such request should be directed to the Company
at its Philadelphia address stated herein, and to the attention of the
Secretary.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires the
Company's officers, directors, and persons who own more than ten percent of a
registered class of the Company's equity securities to file reports of ownership
and changes in ownership with the Securities and Exchange Commission and to
furnish the Company with copies of all such reports.

Based solely on its review of the reports received by it, or written
representations from certain reporting persons that no filings were required for
those persons, the Company believes that, during fiscal year 2003, its officers,
directors and greater than ten percent stockholders complied with all applicable
filing requirements.

107

ITEM 11. EXECUTIVE COMPENSATION

Executive Officer Compensation

The following tables set forth certain information concerning the
compensation paid or accrued during each of the last three fiscal years by the
Company and its subsidiaries to the Company's Chief Executive Officer and each
of the Company's four other most highly compensated executive officers whose
aggregate salary and bonus (including amounts of salary and bonus foregone to
receive non-cash compensation) exceeded $100,000.

Summary Compensation Table

Annual Compensation Long Term Compensation
----------------------------- ----------------------------------------
Awards Payouts
-------------------------- ----------
Restricted Securities All Other
Fiscal Stock Underlying LTIP Compen-
Name and Principal Position Year Salary Bonus(1) Other Awards(2) Options Payouts(3) sation(4)
- --------------------------- ---- ------ -------- ----- -------- -------------- ---------- ------------

Edward E. Cohen 2003 $600,000 $400,000 $ 0 0 0 $ 0 $ 318,769
Chairman & Chief 2002 600,000 500,000 0 2,280 150,000 0 1,108,692
Executive Officer 2001 600,000 450,000 0 0 100,000 0 1,628,325

Jonathan Z. Cohen 2003 350,000 300,000 0 0 0 0 4,990
President & Chief 2002 335,385 200,000 0 2,280 150,000 0 9,846
Operating Officer 2001 282,932 160,000 0 0 45,000 0 9,538

Steven J. Kessler 2003 300,000 150,000 0 0 0 0 6,000
Senior Vice President & 2002 300,000 150,000 0 2,280 30,000 0 11,000
Chief Financial Officer 2001 300,000 150,000 0 0 30,000 0 9,923

Freddie M. Kotek 2003 250,000 200,000 0 0 0 0 6,000
Senior Vice President 2002 248,677 150,000 0 2,280 30,000 0 11,000
2001 200,000 125,000 0 0 30,000 0 10,500

Alan F. Feldman 2003 300,000 100,000 0 0 0 0 0
Senior Vice President 2002(5) 36,923 100,000 50,000 0 200,000 0

(1) Bonuses in any fiscal year are generally based upon the Company's
performance in the prior fiscal year and the individual's contribution
to that performance. From time to time, the Company may award bonuses
in a fiscal year reflecting an individual's performance during that
fiscal year.

(2) Reflects shares awarded under the Company's 1989 Employee Stock
Ownership Plan, valued at the closing price of the Company's common
stock at September 30, 2002. For purposes of this table, all shares are
assumed to be fully vested. Mr. E. Cohen was 100% vested as of
September 30, 1997. Mr. Kotek was 100% vested as of September 30, 2000.
Messrs. J. Cohen and Kessler were 80% vested as of September 30, 2003
and will be fully vested on September 30, 2004. At September 30, 2003,
the number of restricted shares held and the value of those restricted
shares (in the aggregate, and valued at the closing market price of the
Company's common stock on the dates of the respective grants) are: Mr.
E. Cohen -60,775 shares ($123,272); Mr. J. Cohen - 285 shares ($2,280);
Mr. Kessler - 313 shares ($2,488); and Mr. Kotek - 16,017 shares
($55,745). Cash dividends, as and when authorized by the Company's
Board of Directors, have been and will continue to be paid to the Plan
on the restricted shares.

(3) Except for the 1989 Employee Stock Ownership Plan, the stock option
plans and the 401(k) Plan, reported elsewhere in this annual report,
the Company does not have long-term incentive plans or pension or
profit-sharing plans.

108

(4) All such amounts are matching payments made by the Company under the
401(k) Plan, except the amounts set forth for Mr. E. Cohen in 2003,
2002, and 2001 include $314,500, $1,100,000 and $926,800, respectively,
of accrued obligations under a Supplemental Employment Retirement Plan
established by the Company in March 1997 in connection with the
employment agreement between Mr. E. Cohen and the Company.
Additionally, $693,333 of the amount set forth for Mr. E. Cohen in 2001
represents a gross-up payment for taxes in connection with the
Supplemental Employment Retirement Plan. See "Employment Agreements."

(5) Mr. Feldman's salary in 2002 is for the partial fiscal year period from
the inception of his employment with the Company on August 1, 2002
through September 30, 2002. The salary reported for fiscal 2002 was
based on an annual salary rate of $300,000 for fiscal 2002. Mr.
Feldman's bonus in fiscal 2002 was a signing bonus associated with the
inception of his employment with the Company. Mr. Feldman's other
compensation in fiscal 2002 was a relocation expense reimbursement.

Option Grants and Exercises in Last Fiscal Year and Year-End Option Values

The Company did not grant any stock options or stock appreciation
rights to the named executive officers in fiscal 2003.

The following table sets forth the aggregated option exercises during
fiscal 2003, together with the number of unexercised options and their value on
September 30, 2003, held by the executive officers listed in the Summary
Compensation Table. No stock appreciation rights were exercised or held by the
named executive officers in fiscal 2003.

Aggregated Option Exercises In Last Fiscal Year
and Fiscal Year-End Option Values

Number of
Securities Underlying Value of Unexercised
Unexercised In-the-Money
Options at FY-End Options at
Shares Acquired Exercisable/ FY-End Exercisable/
Name On Exercise Value Realized(1) Unexercisable Unexercisable (2)
- ---- ----------- ----------- ------------- ---------------------

Edward E. Cohen 225,000 $ 866,672 287,500/162,500 $195,475/506,725
Jonathan Z. Cohen 30,000 117,356 359,997/185,003 828,931/703,283
Steven J. Kessler 75,000 275,391 47,500/37,500 43,080/105,330
Freddie M. Kotek 0 0 61,995/37,500 312,390/105,330
Alan F. Feldman 0 0 50,000/150,000 126,000/378,000

- ---------------
(1) Value is calculated by subtracting the total exercise price from the
fair market value of the securities underlying the options at the date
of exercise.

(2) Value is calculated by subtracting the total exercise price from the
fair market value of the securities underlying the options at September
30, 2003.

Employment Agreements

Edward E. Cohen serves as the Chairman of the Board of Directors and
Chief Executive Officer of the Company under an employment agreement effective
January 1, 1997. The agreement requires Mr. Cohen to devote as much of his
business time to the Company as is necessary to the fulfillment of his duties,
although it permits him to have outside business interests. The agreement
provides for initial base compensation of $350,000 per year, which may be
increased by the Compensation Committee of the Board based upon its evaluation
of Mr. Cohen's performance. Mr. Cohen is eligible to receive incentive bonuses
and stock option grants in amounts to be determined by the Compensation
Committee of the Board and to participate in all employee benefit plans in
effect during his period of employment.

The agreement has a term of five years and, until notice to the
contrary, the term is automatically extended so that, on any day on which the
agreement is in effect, it has a then-current five year term. The agreement may
be sooner terminated in the event of Mr. Cohen's disability extending for more
than 240 days, death or retirement. Mr. Cohen also has the right to terminate
the agreement upon a change in control or potential change in control of the
Company, and for cause. Otherwise, Mr. Cohen may terminate the agreement upon
180 days' notice.

109

The agreement provides the following termination benefits: (i) upon
termination due to death, Mr. Cohen's estate will receive an amount equal to (a)
five times Average Compensation (defined as the average of the annual total
compensation received by Mr. Cohen in the three most highly compensated years
during the previous nine years of employment), payable over 36 months, plus (b)
to the extent Mr. Cohen has not received 120 months of Supplemental Employment
Retirement Plan ("SERP") benefits, the balance thereof; (ii) upon termination
due to disability, Mr. Cohen will receive a monthly benefit equal to one-twelfth
of the product of (a) Average Compensation and (b) 75%, which will terminate
upon the commencement of retirement benefits; (iii) upon termination by Mr.
Cohen for cause, or upon a change in control or potential change in control, an
amount equal to five times Average Compensation plus continuation of life,
health, accident and disability insurance benefits for a period of 36 months or
until Mr. Cohen reaches age 70; and (iv) upon termination by Mr. Cohen without
cause, an amount equal to 25% of the amount referred to in item (i), above. In
the event that any amounts payable to Mr. Cohen pursuant to items (i) through
(iv), above ("Total Benefits"), become subject to any excise tax imposed under
Section 4999 of the Internal Revenue Code of 1986 (the "Code"), the Company must
pay Mr. Cohen an additional sum such that the net amounts retained by Mr. Cohen,
after payment of excise, income and withholding taxes, shall equal Total
Benefits.

As required by the agreement, the Company has established a SERP for
Mr. Cohen's benefit which will pay to Mr. Cohen, upon retirement after he has
reached Retirement Age (defined by the agreement as age 62), a monthly
retirement benefit equal to 75% of his Average Compensation, less any amounts
payable under any other retirement plan of the Company in which Mr. Cohen
participates. The Company has established two trusts to fund the SERP. The 1999
Trust purchased 100,000 shares of common stock of The Bancorp, Inc. See "Item
13. Certain Relationships and Related Party Transactions." The 2000 Trust holds
42,633 shares of convertible preferred stock of The Bancorp, Inc. and a loan to
a limited partnership of which Edward Cohen and Daniel Cohen, a son of Edward
Cohen and a former officer and director of the Company, own the beneficial
interests. This loan was acquired for its outstanding balance of $720,167 by the
2000 Trust in April 2001 from a corporation of which Edward Cohen is the
Chairman and Jonathan Cohen is the President. In addition, the 2000 Trust
invested $1.0 million in Financial Securities Fund, an investment partnership
which is managed by a corporation of which Daniel Cohen is the principal
shareholder and a director. The fair value of the 1999 Trust is approximately
$1.1 million at September 30, 2003. This trust and its assets are not included
in the Company's consolidated balance sheet. However, its assets are considered
in determining the amount of the Company's liability under the SERP.

For information regarding Mr. Cohen's compensation during each of the
last three fiscal years, see "Item 11. Executive Officer Compensation."

Steven J. Kessler serves as the Senior Vice President and Chief
Financial Officer of the Company under an employment agreement dated October 5,
1999. The agreement provides for initial base compensation of $300,000 per year,
which may be increased by the Compensation Committee of the Board based upon its
evaluation of Mr. Kessler's performance. Mr. Kessler is eligible to receive
incentive bonuses and stock option grants in amounts to be determined by the
Board and to participate in all employee benefit plans in effect during his
period of employment.

The agreement has a term of three years and, until notice to the
contrary, the term is automatically extended so that, on any day on which the
agreement is in effect, it has a then-current three year term. The agreement can
be sooner terminated in the event of Mr. Kessler's disability extending for more
than 240 days or death. Mr. Kessler also has the right to terminate the
agreement upon a change in control of the Company, and for cause. Otherwise, Mr.
Kessler can terminate the agreement upon 180 days' notice.

110

The agreement provides the following termination benefits: (i) upon
termination due to death, Mr. Kessler's estate will receive an amount equal to
three times Average Compensation (defined as the average of the annual total
compensation received by Mr. Kessler in the three most highly compensated years
during the previous nine years of employment) (payable over 36 months); (ii)
upon termination due to disability, Mr. Kessler will receive a monthly benefit
equal to one-twelfth of the product of (a) Average Compensation and (b) 75%; and
(iii) upon termination by Mr. Kessler for cause, or upon a change in control, an
amount equal to three times Average Compensation plus continuation of life,
health, accident and disability insurance benefits for a period of 36 months. In
the event that any amounts payable to Mr. Kessler pursuant to items (i) through
(iii), above ("Total Benefits"), become subject to any excise tax imposed under
Section 4999 of the Code, the Company is required to pay Mr. Kessler an
additional sum such that the net amounts retained by Mr. Kessler, after payment
of excise, income and withholding taxes, shall equal Total Benefits.

The terms of the Company's employment agreement with Jonathan Z. Cohen
as of October 1999 are substantially similar to the terms of the Company's
employment agreement with Mr. Kessler described above, except as follows: Mr. J.
Cohen serves as President, Chief Operating Officer and a director of the
Company; Mr. J. Cohen's initial base compensation is $200,000 per year; Mr. J.
Cohen is expressly permitted to have outside business interests; and Mr. J.
Cohen has the right to terminate the agreement upon a potential change in
control of the Company.

Director Compensation

Effective as of March 2003, each non-employee director of the Company
receives a retainer of $35,000 per year. A total of $109,000 was paid to five
non-employee directors for board service during fiscal 2003, including one
non-employee director, Alan D. Schreiber, who resigned from the Board of
Directors on April 30, 2003.

Each non-employee director of the Company is eligible to participate in
the 2002 Non-Employee Director Deferred Stock and Deferred Compensation Plan
(the "2002 Plan"), which was approved by the Company's stockholders on April 29,
2002. Under the 2002 Plan, non-employee directors ("Eligible Directors") are
awarded Units representing the right to receive one share of Company common
stock for each Unit awarded. Upon becoming an Eligible Director, each Eligible
Director is awarded Units equal to $15,000 divided by the closing price of the
Company's common stock on the date of grant. Eligible Directors are each awarded
additional Units equal to $15,000 divided by the closing price of the Company's
common stock on the date of grant on each anniversary of the date of initial
grant. Units vest on the later of: (i) the fifth anniversary of the date he or
she became an Eligible Director and (ii) the first anniversary of the grant of
those Units, except that Units will vest sooner upon a change in control of the
Company or death or disability of an Eligible Director, provided the Eligible
Director completed at least six months of service. Upon termination of service
by an Eligible Director, the Company will issue shares of Company common stock
equal to the number of vested Units held by the Eligible Director, but all
unvested Units are forfeited. The 2002 Plan provides for the issuance of a
maximum of 75,000 Units and terminates on April 29, 2012, except with respect to
previously awarded grants. As of the date of this annual report, four directors
are deemed to be Eligible Directors, 12,732 Units have been awarded to such
Eligible Directors and 7,540 Units have been forfeited under the 2002 Plan.

Compensation Committee Interlocks and Insider Participation

The Compensation Committee of the Board of Directors consists of
Messrs. Campbell, Neff and White. None of such persons was an officer or
employee of the Company or any of its subsidiaries during fiscal year 2003 or
was formerly an officer of the Company or any of its subsidiaries. No executive
officer of the Company has been a director or executive officer of any entity of
which any member of the Compensation Committee has been a director or executive
officer during fiscal year 2003.

111

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the number and percentage of shares of
common stock owned, as of December 15, 2003, by (a) each person who, to the
knowledge of the Company, is the beneficial owner of more than 5% of the
outstanding shares of common stock, (b) each of the Company's present directors,
(c) each of the Company's executive officers, and (d) all of the Company's
present executive officers and directors as a group. This information is
reported in accordance with the beneficial ownership rules of the Securities and
Exchange Commission under which a person is deemed to be the beneficial owner of
a security if that person has or shares voting power or investment power with
respect to such security or has the right to acquire such ownership within 60
days. Shares of common stock issuable pursuant to options or warrants are deemed
to be outstanding for purposes of computing the percentage of the person or
group holding such options or warrants but are not deemed to be outstanding for
purposes of computing the percentage of any other person. Unless otherwise
indicated in footnotes to the table, each person listed has sole voting and
dispositive power with respect to the securities owned by such person.

Common Stock
--------------------
Amount and Nature of Percent of
Beneficial Owner Beneficial Ownership Class
- ---------------- -------------------- -----------
Directors
- ---------

Carlos C. Campbell........................................................... 16,837 (1)(2) *
Edward E. Cohen.............................................................. 1,798,493 (3)(4)(6)(7)(8)(9) 10.18%
Jonathan Z. Cohen............................................................ 474,013 (3)(4)(6)(7)(10) 2.67%
Andrew M. Lubin.............................................................. 17,197 (1)(2) *
P. Sherrill Neff............................................................. 13,357 (1)(2) *
John S. White................................................................ 17,357 (1)(2) *

Non-Director Executive Officers
- -------------------------------
Steven J. Kessler............................................................ 116,374 (3)(4)(6)(7) *
Freddie M. Kotek............................................................. 135,668 (3)(4)(5)(6)(7) *
Alan F. Feldman.............................................................. 50,000 (6)(7) *
Nancy J. McGurk.............................................................. 102,674 (3)(4)(5)(6)(7) *
All present executive officers and directors as a group (10 persons)......... 2,695,720
(1)(2)(3)(4)(5)(6)(7)(8)(9) .........................14.71%

Other Owners of More Than
5% of Outstanding Shares
- -------------------------
Cobalt Capital Management, Inc.(11).......................................... 1,741,800 10.04%
Dimensional Fund Advisors Inc.(12)........................................... 1,590,571 9.17%
First Financial Fund, Inc.(13)............................................... 959,315 5.53%
Thomson Horstmann & Bryant, Inc.(14)......................................... 949,095 5.47%
Wellington Management Company, LLP(15)....................................... 1,411,720 8.13%
James C. Eigel(16)........................................................... 1,071,977 6.18%

- --------------
* Less than 1%

(1) Includes vested units representing the right to receive one share of
Company common stock per unit granted under the Company's 1997
Non-Employee Directors Deferred Stock and Deferred Compensation Plan in
the following amounts: Mr. Campbell - 15,000 units; Mr. Lubin - 15,000
units; Mr. Neff - 12,000 units; and Mr. White - 15,000 units.

(2) Includes vested units representing the right to receive one share of
Company common stock per unit granted under the Company's 2002
Non-Employee Directors Deferred Stock and Deferred Compensation Plan in
the following amounts: Mr. Campbell - 1,357 units; Mr. Lubin - 1,357
units; Mr. Neff - 1,357 units; and Mr. White - 1,357 units.

112

(3) Includes shares allocated under the Company's 1989 Employee Stock
Ownership Plan in the following amounts: Mr. E. Cohen - 60,775 shares;
Mr. J. Cohen - 285 shares; Mr. Kessler - 313 shares; Mr. Kotek - 16,017
shares; and Ms. McGurk - 10,426 shares, as to which each has voting
power.

(4) Includes shares allocated under the Company's Investment Savings Plan
(the "401(k) Plan") in the following amounts: Mr. E. Cohen - 18,765
shares; Mr. J. Cohen - 11,231 shares; Mr. Kessler - 11,545 shares; Mr.
Kotek - 17,673 shares; and Ms. McGurk - 20,686 shares, as to which each
has voting power.

(5) Includes shares issuable on exercise of options granted under the
Company's 1989 Key Employee Stock Option Plan in the following amounts:
Mr. Kotek - 29,495 shares; and Ms. McGurk - 33,708 shares.

(6) Includes shares issuable on exercise of options granted under the
Company's 1999 Key Employee Stock Option Plan in the following amounts:
Mr. E. Cohen - 275,000 shares; Mr. J. Cohen - 263,334 shares; Mr.
Feldman - 6,633 shares; Mr. Kessler - 47,500 shares; Mr. Kotek - 32,500
shares; and Ms. McGurk - 17,500 shares.

(7) Includes shares issuable on exercise of options granted under the
Company's 2002 Key Employee Stock Option Plan in the following amounts:
Mr. E. Cohen - 37,500 shares; Mr. J. Cohen - 37,500 shares; Mr. Feldman
- 43,367 shares; Mr. Kessler - 7,500 shares; Mr. Kotek - 7,500 shares;
and Ms. McGurk - 2,500 shares.

(8) Includes 449,516 shares held by a private charitable foundation, of
which Mr. E. Cohen serves as a co-trustee. Mr. E. Cohen disclaims
beneficial ownership of these shares.

(9) Includes 92,500 shares held in trusts for the benefit of Mr. E. Cohen's
spouse and/or children. Mr. E. Cohen disclaims beneficial ownership of
these shares.

(10) Includes 46,250 shares held in a trust of which Mr. J. Cohen is a
co-trustee and co-beneficiary. These shares are also included in the
shares referred to footnote 9 above.

(11) This information is based on Schedule 13G/A filed with the United
States Securities and Exchange Commission on February 14, 2003. The
address for Cobalt Capital Management, Inc. is 237 Park Avenue, Suite
801, New York, New York 10017.

(12) This information is based on Schedule 13G/A filed with the United
States Securities and Exchange Commission on February 13, 2003.
Dimensional Fund Advisors Inc. ("Dimensional"), an investment advisor
registered under Section 203 of the Investment Advisors Act of 1940,
furnishes investment advice to four investment companies registered
under the Investment Company Act of 1940, and serves as investment
manager to certain other commingled group trusts and separate accounts.
These investment companies, trusts and accounts are the "Funds". In its
role as investment advisor or manager, Dimensional possesses voting
and/or investment power over 1,590,571 shares of the Company's common
stock as of December 31, 2002. The Funds own all of these securities.
Dimensional disclaims beneficial ownership of such securities. The
address for Dimensional Fund Advisors Inc. is 1299 Ocean Avenue, 11th
Floor, Santa Monica, California 90401.

(13) This information is based on Schedule 13G/A filed with the United
States Securities and Exchange Commission on February 14, 2003. All
959,315 shares are also included in the shares beneficially owned by
Wellington Management Company, LLP. See footnote 15 below. The address
for First Financial Fund, Inc. is Gateway Center Three, 100 Mulberry
Street, 9th Floor, Newark, New Jersey 07102-7503.

113

(14) This information is based on Schedule 13G/A filed with the United
States Securities and Exchange Commission on January 9, 2003. Includes
479,662 shares as to which sole voting power is claimed and 949,095
shares as to which sole dispositive power is claimed. The address for
Thomson Horstmann & Bryant, Inc. is Park 80 West, Plaza Two, Saddle
Brook, New Jersey 07663.

(15) This information is based on Schedule 13G/A filed with the United
States Securities and Exchange Commission on February 12, 2003.
Includes 273,797 shares as to which shared voting power is claimed and
1,411,720 shares as to which shared dispositive power is claimed.
Includes 959,315 shares beneficially owned by First Financial Fund,
Inc. See footnote 13 above. The address for Wellington Management
Company, LLP is 75 State Street, Boston, Massachusetts 02109.

(16) This information is based on Schedule 13G/A filed with the United
States Securities and Exchange Commission on February 14, 2003.
Includes shares held by nominees. Mr. Eigel's address is 1201 Edgecliff
Place, Cincinnati, Ohio 45206.

114

Equity Compensation Plan Information

The following table summarizes certain information about the Company's
equity compensation plans, in the aggregate, as of September 30, 2003.

- -----------------------------------------------------------------------------------------------------------------------
Number of securities remaining
Number of securities to Weighted-average exercise available for future issuance
be issued upon exercise price of outstanding under equity compensation plans
of outstanding options, options, warrants and (excluding securities reflected
warrants and rights rights in column (a))
- -----------------------------------------------------------------------------------------------------------------------
Plan category (a) (b) (c)
- -----------------------------------------------------------------------------------------------------------------------

Equity compensation plans
approved by security
holders 1,918,986 $ 10.39 288,599
- -----------------------------------------------------------------------------------------------------------------------
Equity compensation plans
not approved by security
holders(1) 36,554 $ 0.11 0
- -----------------------------------------------------------------------------------------------------------------------
Total 1,955,540 $ 10.21 288,599
- -----------------------------------------------------------------------------------------------------------------------

- ---------------
(1) In connection with the acquisition of Atlas America, the Company issued
options for 120,213 shares at an exercise price of $0.11 per share to certain
employees of Atlas America who had held options of Atlas America before its
acquisition by the Company. Options for 36,554 shares remained outstanding and
exercisable as of September 30, 2003.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

In the ordinary course of its business operations, the Company has
ongoing relationships with several related entities:

Relationship with Brandywine Construction & Management, Inc. ("BCMI").
BCMI manages the properties underlying 16 of the Company's real estate loans and
real estate and FIN 46 assets. Adam Kauffman ("Kauffman"), President of BCMI, or
an entity affiliated with him, has also acted as the general partner, president
or trustee of seven of the borrowers. Edward E. Cohen ("E. Cohen"), the
Company's chairman and chief executive officer, is the chairman of BCMI and
holds approximately 8% of its common stock.

In September 2001, the Company sold a wholly-owned subsidiary to BCMI
for $4.0 million, recognizing a gain of $356,000. The $4.0 million consideration
paid to the Company included a $1.0 million non-recourse note from BCMI, which
note BCMI repaid in full to the Company in October 2003.

Relationship with RAIT Investment Trust ("RAIT"). Organized by the
Company in 1997, RAIT is a real estate investment trust in which, as of
September 30, 2003, the Company owned approximately 4% of the shares of
beneficial interests. Betsy Z. Cohen ("B. Cohen"), Mr. E. Cohen's spouse, is the
chief executive officer of RAIT, and Jonathan Z. Cohen ("J. Cohen"), a son of E.
and B. Cohen and the president and chief operating officer and a director of the
Company, is the vice chairman, secretary and a trustee of RAIT. Scott F.
Schaeffer, a former officer and director of the Company, is RAIT's president and
chief operating officer.

In December 2003 RAIT provided the Company a standby commitment to
provide bridge financing in the amount of $10.0 million. RAIT received a
$100,000 facilitation fee from the Company in connection with providing this
standby commitment. On January 15, 2004, the Company borrowed the $10.0 million
from RAIT, and on January 21, 2004, the Company repaid RAIT in full.

Relationship with The Bancorp, Inc. ("TBI"). The Company owns 9.7% of
the outstanding common stock of TBI. B. Cohen and Daniel G. Cohen ("D. Cohen")
are officers and directors of TBI. D. Cohen, a son of E. and B. Cohen, is a
former officer and director of the Company.

115

Relationship with Ledgewood. Until April 1996, E. Cohen was of counsel
to Ledgewood Law Firm ("Ledgewood"). The Company paid Ledgewood $1.2 million
during fiscal 2003 for legal services rendered to the Company. E. Cohen receives
certain debt service payments from Ledgewood related to the termination of his
affiliation with Ledgewood and its redemption of his interest.

Relationship with Retirement Trusts. Upon his retirement, E. Cohen is
entitled to receive payments from a Supplemental Employee Retirement Plan
("SERP"). See "Employment Agreements."

Relationship with Cohen Bros. & Company. During fiscal 2003, the
Company purchased 26,450 shares of its common stock at a cost of $212,100 from
Cohen Bros. & Company. D. Cohen is the principal owner of the corporate parent
of Cohen Bros. & Company.

Relationship with 9 Henmar. The Company owns a 50% interest in the
Trapeza entities that have sponsored collateralized debt obligation issuers
("CDO issuers") and manage pools of trust preferred securities acquired by the
CDO issuers. The Trapeza entities and CDO issuers were originated and developed
in large part by D. Cohen. The Company has agreed to pay his company, 9 Henmar
LLC ("9 Henmar"), 10% of the fees the Company receives in connection with
Trapeza entities one through four and their management of the trust preferred
securities held by the CDO issuers. In fiscal 2003, the Company paid 9 Henmar
$93,400 in such fees. In addition, the Company made advances of $1.4 million in
fiscal 2003 to 9 Henmar for its expenses in connection with originating and
developing the Trapeza entities and the CDO issuers. All of such advances were
reimbursed to the Company by the CDO issuers by September 30, 2003.

Relationship with Certain Borrowers and Purchasers of Real Estate
Loans. The Company has from time to time purchased loans in which affiliates of
the Company were or have become affiliates of the borrowers.

In January 2004, a property underlying one of the Company's loans was
sold to an affiliate of D. Cohen, which was the highest bidder for the property.
In 2002, an entity affiliated with D. Cohen acquired beneficial ownership of
the property and a 12.5% participation interest in a loan the Company held on
that property from an unrelated third party. In connection with the sale of the
property, the Company received proceeds of $2.8 million, of which $250,000
(less than its 12.5% participation interest) was paid to such enity.

In October 2003, the Company recapitalized a loan it acquired in 1998
under a plan of reorganization in bankruptcy for a cost of $95.6 million. At the
time of such acquisition, an order of the bankruptcy court required that legal
title to the property underlying the loan be transferred. To comply with that
order, to maintain control of the property and to protect the Company's
interest, an entity whose general partner is a subsidiary of the Company and
whose limited partners are Messrs. Schaeffer, D. Cohen and E. Cohen (with a 94%
aggregate beneficial interest), assumed title to the property. As part of the
recapitalization, Messrs. E. Cohen and Schaeffer transferred all of their
interests to an unrelated third party for no consideration and D. Cohen
transferred all of his interest (except for a 15% interest, which he retained)
to such third party for no consideration. In consideration for the limited
partners' agreeing to the recapitalization of the loan, the Company agreed to
repay the limited partners the amount that they had paid to the Company in 1998
for the interests transferred in October 2003, without interest. Such payment
was $200,000 in the aggregate.

116

In October 2003 the property underlying one of the Company's loans was
sold to an entity of which D. Cohen is an affiliate of the general partner,
which entity was the highest bidder for the property. Prior to such sale, the
property had been owned by a partnership in which Messrs. E. Cohen, D. Cohen
and Kauffman and Ms. B. Cohen were limited partners. The property was sold for
$343,000 more than the Company's net investment in the property.

In September 2003, the Company foreclosed on a property securing a loan
held by the Company since 1997. In 2000, to protect the Company's interest, the
property was purchased by a limited partnership owned in equal parts by Messrs.
Schaeffer, Kauffman, E. Cohen and D. Cohen.

117

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Audit Fees

The aggregate fees billed by the Company's independent auditors, Grant
Thornton LLP, for professional services rendered for the audit of the Company's
annual financial statements for the fiscal year ended September 30, 2003 and for
the reviews of the financial statements included in the Company's Quarterly
Reports on Form 10-Q during the fiscal year ended September 30, 2003 were
$754,678.

Financial Information Systems Design and Implementation Fees

Grant Thornton LLP billed no fees for professional services rendered to
the Company for information technology services relating to financial
information systems design and implementation for the fiscal year ended
September 30, 2003.

All Other Fees

The aggregate fees billed by Grant Thornton LLP for services rendered
to the Company, other than services described above under "Audit Fees" and
"Financial Information Systems Design and Implementation Fees," for the fiscal
year ended September 30, 2003 were $346,103.

Other Matters

Since Grant Thornton did not provide information technology services to
the Company during fiscal 2003, the Audit Committee was not required to consider
whether the provision of such services impacted their independence. The Audit
Committee did consider whether the provision of the other non-audit services
performed by Grant Thornton is compatible with maintaining Grant Thornton's
independence.

118

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) The following documents are filed as part of this Annual Report on
Form 10-K/A:

1. Financial Statements

Report of Independent Certified Public Accountants
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Statements of Changes in Stockholders' Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements

2. Financial Statement Schedules

Schedule I - Condensed Financial Information of the
Registrant
Schedule III - Investments in Real Estate
Schedule IV - Investments in Mortgage Loans on Real Estate

3. Exhibits

Exhibit No. Description
----------- -----------

3.1 Restated Certificate of Incorporation of Resource America. (1)
3.2 Amended and Restated Bylaws of Resource America. (1)
4.1 Indenture, dated as of July 22, 1997, between Resource America and The Bank of New
York(3)
10.1 Employment Agreement between Edward E. Cohen and Resource America, dated March 11,
1997. (2)
10.2 Revolving Credit Loan Agreement dated July 27, 1999 by and between Resource America
and Sovereign Bank. (4)
10.2(a) Modification of Revolving Credit Loan Agreement dated September 15, 2003. (13)
10.3 Revolving Credit Loan and Security Agreement dated July 27, 1999 by and between
Resource Properties, Inc., Resource Properties 53, Inc., Resource Properties XXIV,
Inc., Resource Properties XL, Inc. and Sovereign Bank(4)
10.3(a) Modification of Revolving Credit Loan and Security Agreement dated March 30, 2000.(4)
10.3(b) Second Modification of Revolving Credit and Loan Agreement dated April 30, 2002.(13)
10.3(c) Third Modification of Revolving Credit and Loan Agreement, dated September 15, 2003.(13)
10.4 Employment Agreement between Steven J. Kessler and Resource America, dated October 5,
1999. (1)
10.5 Employment Agreement between Nancy J. McGurk and Resource America, dated October 5,
1999. (1)
10.5 Employment Agreement between Jonathan Z. Cohen and Resource America, dated October 5,
1999. (4)
10.7 Amended and Restated Loan Agreement, dated December 14, 1999, among Resource
Properties XXXII, Inc., Resource Properties XXXVIII, Inc., Resource Properties II,
Inc., Resource Properties 51, Inc., Resource Properties, Inc., Resource America and
Jefferson Bank (now known as Hudson United Bank). (4)
10.6 Revolving Credit Agreement and Assignment between LEAF Financial Corporation and
National City Bank, and related guaranty from Resource America, dated June 11,
2002.(5)
10.6(a) Amendment to Revolving Credit Agreement dated March 28, 2003.(13)
10.6(b) Second Amendment to Revolving Credit Agreement dated April 1, 2003. (13)
10.7 Credit Agreement among Atlas America, Inc., Resource America, Inc., Wachovia Bank,
National Association, and other banks party thereto, dated July 31, 2002.(5)
10.7(a) First Amendment to Credit Agreement dated September 29, 2003. (13)
10.8 Credit Agreement among Atlas Pipeline Partners, L.P., Wachovia Bank, National
Association, and the other parties thereto, dated December 27, 2002. (6)
10.8(b) Second Amendment to Credit Agreement dated March 28, 2003. (13)
10.8(c) Third Amendment to Credit Agreement dated September 15, 2003. (13)
10.9 Revolving Credit Agreement and Assignment among LEAF Financial Corporation, Lease
Equity Appreciation Fund I, L.P., LEAF Funding, Inc. and Commerce Bank, National
Association dated May 28, 2003. (13)
10.10 Purchase and Sale Agreement between Atlas Pipeline Partners, L.P. and SEMCO Energy,
Inc. dated September 16, 2003. (13)
10.11 1989 Key Employee Stock Option Plan, as amended.(7)
10.12 1997 Key Employee Stock Option Plan.(8)
10.13 1997 Stock Option Plan for Directors.(8)
10.14 1997 Non-Employee Director Stock Option Plan.(8)
10.15 1999 Key Employee Stock Option Plan.(9)
10.16 Employee Stock Ownership Plan.(10)
10.17 2002 Non-Employee Director Deferred Stock and Deferred Compensation Plan.(11)
10.18 2002 Key Employee Stock Option Plan(12)
12.1 Statement re: computation of ratios (13)
21.1 Subsidiaries of Resource America (13)
31.1 Rule 13a-14(a)/15d-14(a) Certifications
31.2 Rule 13a-14(a)/15d-14(a) Certifications
32.1 Section 1350 Certifications
32.2 Section 1350 Certifications

119

(b) Reports on Form 8-K

None

- ----------

(1) Filed previously as an exhibit to our Quarterly Report on Form 10-Q for
the quarter ended December 31, 1999 and by this reference incorporated
herein.
(2) Filed previously as an exhibit to our Quarterly Report on Form 10-Q for
the quarter ended March 31, 1997 and by this reference incorporated
herein.
(3) Filed previously as an exhibit to our Registration Statement on Form S-4
(File No. 333-40231) and by this reference incorporated herein.
(4) Filed previously as an exhibit to our Annual Report on Form 10-K for the
year ended September 30, 2000 and by this reference incorporated herein.
(5) Filed previously as an exhibit to our Annual Report on Form 10-K for the
year ended September 30, 2002 and by this reference incorporated herein.
(6) Filed previously as an exhibit to our Quarterly Report on Form 10-Q for
the quarter ended December 31, 2002 and by this reference incorporated
herein.
(7) Filed previously as an exhibit to our Registration Statement on Form S-1
(File No. 333-03099) and by this reference incorporated herein.
(8) Filed previously as an exhibit to our Quarterly Report on Form 10-Q for
the quarter ended June 30, 1997 and by this reference incorporated herein.
(9) Filed previously as an exhibit to our Definitive Proxy Statement on
Schedule 14A for the 1999 annual meeting of stockholders and by this
reference incorporated herein.
(10) Filed previously as an exhibit to our Annual Report on Form 10-K for the
year ended September 30, 1989 and by this reference incorporated herein.
(11) Filed previously as an exhibit to our Registration Statement on Form S-8
(File No. 333-98507) and by this reference incorporated herein.
(12) Filed previously as an exhibit to our Registration Statement on Form S-8
(File No. 333-98505) and by this reference incorporated herein.

(13) Filed previously as an exhibit to our Annual Report on Form 10-K for the
year ended September 30, 2003 and by this reference incorporated herein.

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SIGNATURES

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

RESOURCE AMERICA, INC. (Registrant)
January 28, 2004 By: /s/ Edward E. Cohen
----------------------------------
Chairman of the Board and
Chief Executive 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 dates indicated.

/s/ Edward E. Cohen Chairman of the Board, January 28, 2004
- -------------------------------------------- and Chief Executive Officer
EDWARD E. COHEN

/s/ Jonathan Z. Cohen Director, President January 28, 2004
- -------------------------------------------- and Chief Operating Officer
JONATHAN Z. COHEN

/s/ Carlos C. Campbell Director January 28, 2004
- --------------------------------------------
CARLOS C. CAMPBELL

/s/ Andrew M. Lubin Director January 28, 2004
- --------------------------------------------
ANDREW M. LUBIN

/s/ P. Sherrill Neff Director January 28, 2004
- --------------------------------------------
P. SHERRILL NEFF

/s/ John S. White Director January 28, 2004
- --------------------------------------------
JOHN S. WHITE

/s/ Steven J. Kessler Senior Vice President January 28, 2004
- -------------------------------------------- and Chief Financial Officer
STEVEN J. KESSLER

/s/ Nancy J. McGurk Vice President-Finance January 28, 2004
- -------------------------------------------- and Chief Accounting Officer
NANCY J. McGURK

121