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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(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, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to __________
Commission file number: 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 20, 2002,
was approximately $136.3 million.
The number of outstanding shares of the registrant's common stock on December
20, 2002 was 17,382,000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement for registrant's 2003 Annual Meeting of
Stockholders are incorporated by reference in Part III of this Form 10-K.
[THIS PAGE INTENTIONALLY LEFT BLANK]
RESOURCE AMERICA, INC. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT
ON FORM 10-K
PART I Page
----
Item 1: Business.................................................................................. 3 - 27
Item 2: Properties................................................................................ 28 - 31
Item 3: Legal Proceedings......................................................................... 32
Item 4: Submission of Matters to a Vote of Security Holders....................................... 32
PART II
Item 5: Market for Registrant's Common Equity and Related Stockholder Matters..................... 33
Item 6: Selected Financial Data................................................................... 34 - 35
Item 7: Management's Discussion and Analysis of Financial Condition
and Results of Operation.............................................................. 36 - 53
Item 7A: Quantitative and Qualitative Disclosures about Market Risk................................ 54 - 59
Item 8: Financial Statements and Supplementary Data............................................... 60 - 98
Item 9: Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure................................................ 98
PART III
Item 10: Directors and Executive Officers of the Registrant........................................ 99
Item 11: Executive Compensation.................................................................... 99
Item 12: Security Ownership of Certain Beneficial Owners and Management............................ 99
Item 13: Certain Relationships and Related Transactions............................................ 99
Item 14: Controls and Procedures................................................................... 100
PART IV
Item 15: Exhibits, Financial Statement Schedules and Reports on Form 8-K........................... 100 - 102
SIGNATURES................................................................................................ 103
CERTIFICATIONS............................................................................................ 104 - 105
2
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 FORWARD-LOOKING 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, ADEQUACY OF OUR PROVISION FOR
LOSSES AND ILLIQUIDITY OF OUR PORTFOLIO.
General
We are a proprietary 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, real estate and financial
services sectors. As a proprietary asset manager, we seek to develop investment
entities 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 entity in addition to the
interest resulting from our investments. We managed approximately $1.2 billion
in assets in these sectors at the end of fiscal 2002, as follows:
o $360 million of energy assets (31%)(1),
o $628 million of real estate assets (54%)(2) and
o $169 million of financial service assets (15%)(3).
During fiscal 2002, we continued developing our energy operations,
which account for approximately 81% of our total revenues and 39% of our total
assets. We increased our average financial interests in wells we drilled. As a
result, the number of gross wells we drilled decreased 2% and the number of net
wells increased 5% in fiscal 2002 as compared to fiscal 2001. Moreover, our
production for our account of natural gas increased by 12% and the revenues from
our drilling activities increased by 28%. We have undertaken new initiatives in
real estate finance and financial services by sponsoring a private real estate
investment partnership, a public equipment leasing partnership and two
investment partnerships formed to acquire the trust preferred securities of
small to mid-size regional banks and bank holding companies. These new
investment entities are in their offering stages (except for one of the trust
preferred securities entities which completed its offering in the first quarter
of fiscal 2003). We intend to develop similar programs in the future.
Energy. Our energy operations focus on the development, production and
transportation of natural gas and, to a lesser extent, oil in the Appalachian
Basin. While we have been involved in the energy industry since 1976, we began
to expand our energy operations during fiscal 1999. We have funded our
development and production operations primarily by sponsoring drilling
investment partnerships. Since the beginning of fiscal 1999 through September
30, 2002, we have raised approximately $149.0 million in 13 separate drilling
investment partnerships. During that period, we drilled 815 gross wells in the
Appalachian Basin and completed approximately 99% as producing wells. We, and
our drilling investment partnerships, own interests in approximately 5,000
wells, 85% of which we operate. At September 30, 2002, proved reserves net to
our interest were approximately 134.5 Bcfe (4) with a PV-10 value (5) of $132.5
million. Of these reserves, 92% were natural gas and 71% were classified as
proved developed reserves. At September 30, 2002, we managed an additional 182.6
Bcfe of proved reserves with a PV-10 value of $199.9 million for our drilling
partnerships and others. Of these reserves, 88% are natural gas, substantially
all of which are classified as proved developed reserves. As of September 30,
2002, we had an acreage position of approximately 488,000 gross (407,000 net)
acres, of which 223,000 gross (213,000 net) acres were undeveloped. We have
identified over 400 potential drilling locations on our acreage, of which 276
are classified as proved undeveloped locations.
3
We own 51% of Atlas Pipeline Partners, a publicly held master limited
partnership which trades on the American Stock Exchange. At September 30, 2002,
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 4,100 natural gas wells were connected.
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(1) We value our managed energy assets as the sum of the PV-10 value, as of
September 30, 2002, 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, 2002, of the totals assets of Atlas
Pipeline Partners, L.P., a publicly traded (AMEX: APL) natural gas
pipeline master limited partnership of which we are the general partner
and principal owner.
(2) We value our managed real estate assets as the sum of the amount of our
outstanding loan receivables plus the book value of our interests in
real estate ventures as of September 30, 2002.
(3) We value our financial services assets as the sum of book values of
equipment held by equipment leasing investment partnerships we managed
as of September 30, 2002, and the cost of securities acquired by a
venture which we co-manage that acquired trust preferred securities of
regional banks and bank holding companies.
(4) "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 as the official
temperature and pressure bases of the area in which the reserves are
located.
(5) "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%. These amounts are calculated net of estimated production costs and
future development costs, using prices and costs in effect as of a
certain 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.
Real Estate Finance. We manage for our own account a portfolio of
commercial real estate loans and interests in real properties from which we
receive interest payments and cash distributions. In addition, we sponsored and
are the largest shareholder of RAIT Investment Trust, a publicly-traded real
estate investment trust (NYSE: RAS) that originates or acquires real estate
loans and, to a lesser extent, interests in real properties. As of September 30,
2002, RAIT had a market capitalization and stockholders' equity of $373.6
million and $266.5 million, respectively.
From fiscal 1991 through fiscal 1999, we focused on loan acquisition
and resolution. We have not acquired any new loans since fiscal 1999 although,
as part of our portfolio management activities, we have purchased senior lien
interests relating to properties in which we hold junior lien interests and have
invested in three partnerships involving properties adjacent to a property in
which we have an interest. In fiscal 2002, we decided to pursue development of
our real estate operations through the sponsorship of real estate investment
partnerships. We currently are a sponsor of one private real estate partnership,
which is in the offering stage. This partnership is focused on the purchase of
multifamily apartment buildings. We will provide real estate management and
advisory services to the partnership. We anticipate this fund closing in March
2003.
Financial Services. Our financial services operations currently focus
on managing investment partners that invest in equipment leasing and entities
that invest in trust preferred securities of small to mid-size regional banks
and their holding companies.
We manage equipment leasing assets through a company we acquired in
1995 that acts as the general partner and manager of four public equipment
leasing partnerships. We intend to develop our equipment leasing operations
through the sponsorship of new equipment leasing partnerships. We have sponsored
one public equipment leasing partnership which is currently in the offering
stage. Previously, in 1996, we had started a proprietary equipment leasing
business which, by 2000, held over $600 million in equipment leasing assets. On
August 1, 2000, we sold this business to European American Bank, a subsidiary of
ABN AMRO Bank, N.V., for $583 million, including assumption of debt of $431
million, subject to certain indemnification obligations. For information on the
status of these obligations, refer to "Obligations Relating to Discontinued
Operations.
4
We manage trust preferred securities assets through a limited liability
company of which we are a 50% owner. The limited liability company manages a
trust preferred securities portfolio owned by another limited liability company
that issues collateralized debt obligations secured by that portfolio, as the
"CDO issuer." We also are the 50% owner of the general partner of, and have
invested $2.8 million in a limited partnership that acquired the equity interest
of the CDO issuer. We have co-sponsored, with a third party, a second trust
preferred securities investment similar to the first, which is currently in the
offering stage.
For financial information about our operating segments, see Note 16,
"Operating Segments and Major Customers," to our "Consolidated Financial
Statements". We do not separately report financial information for our financial
services operating segment because it does not represent at least 10% of our
assets, revenues, profits or losses.
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, 2002, we owned proved reserves of approximately 134.5 Bcfe as
compared to 93.3 Bcfe at the beginning of fiscal 1999. As of September 30, 2002:
o We had, either directly or through investment partnerships managed by
us, interests in approximately 5,000 gross wells, including royalty
or overriding royalty interests in 600 wells. We operate 85% of these
wells.
o Wells in which we have an interest produced, net to our interest,
approximately 19,500 Mcf of natural gas and 473 Bbls of oil per day.
o We had an acreage position of approximately 488,000 gross (407,000
net) acres, of which 223,000 gross (213,000 net) acres were
undeveloped.
o We owned and operated, directly or through our Atlas Pipeline
Partners subsidiary, approximately 1,600 miles of gas gathering
systems and pipelines.
Since 1976, we or our predecessors have funded our development and
production 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 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, and receive monthly
operating and administrative fees. In addition, we typically act as the drilling
contractor and operator of the wells drilled by the partnership on a fee basis.
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 $11.7 million.
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." The gathering systems transport the natural
gas to public utility pipelines for delivery to our 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.
5
Appalachian Basin Overview. Natural gas is the second largest energy
source in the United States, after liquid petroleum. The 22.5 trillion cubic
feet, or "Tcf" of natural gas consumed in 2000 represented approximately 23% of
the total energy used in the United States. The Appalachian Basin, in which
substantially all of our wells are located accounted for 3.5% of total 2000
domestic natural gas production, or 658 billion cubic feet, or "Bcf".
Furthermore, according to the Energy Information Administration of the U.S.
Department of Energy, the Appalachian Basin holds 7.9 Tcf of economically
recoverable reserves representing approximately 4.5% of total domestic reserves
as of December 31, 2000. Although the potential to find recoverable quantities
of oil and gas exists at depths below 6,500 feet, the vast majority of wells in
Appalachia produce from depths between 1,000 and 6,500 feet. Companies drilling
at these depths, including us, have historically realized well completion rates
of greater than 90% and well production periods that last longer than 20 years.
The Appalachian Basin is strategically located near the energy consuming
population centers in the Mid-Atlantic and Northeastern United States, which
generally allows Appalachian producers to sell their natural gas at a premium to
the benchmark price for natural gas on the New York Mercantile Exchange.
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 information and acreage, see Item 2,
"Properties-Energy."
Natural Gas Hedging. Pricing for gas and oil production has been
volatile and unpredictable for many years. To hedge exposure to changing natural
gas prices we use both non-financial and financial 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. For the fiscal year ended September 30, 2002, approximately
49% of produced volumes were sold in this manner. For the fiscal year ending
September 30, 2003, we estimate that in excess of 65% of our produced natural
gas volumes will be sold in this manner, leaving the remaining 35% of our
produced volumes to be sold at contract prices in the month produced at spot
market prices. For information concerning our natural gas hedging, see Item 7A,
"Quantitative and Qualitative Disclosures about Market Risk - Energy - Commodity
Price Risk."
Financing Our Drilling Activities. We derive a substantial portion of
our capital resources for drilling operations from our sponsored drilling
partnerships. Accordingly, the amount of development activities we undertake
depends upon our ability to obtain investor subscriptions to the partnerships.
During fiscal 2002, 2001 and 2000 our drilling partnerships invested $75.5
million, $55.1 million and $39.9 million, respectively, in drilling and
completing wells, of which we contributed $19.7 million, $11.7 million and $9.6
million, respectively.
We generally structure our drilling 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.
6
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. In February 2000, we sold substantially all of our
gathering systems to Atlas Pipeline Partners for $16.6 million in cash and
1,641,026 subordinated units of the newly-formed limited partnership. As of
September 30, 2002, our subordinated units constituted a 49% interest in Atlas
Pipeline Partners. Atlas Pipeline Partners GP, LLC, our indirect wholly-owned
subsidiary, is the general partner of Atlas Pipeline Partners and, on a
consolidated basis, has a 2% interest in Atlas Pipeline Partners. Atlas Pipeline
Partners GP manages the activities of Atlas Pipeline Partners using Atlas
America personnel who act as its officers and employees. At September 30, 2002,
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 4,100 natural gas wells were connected.
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 extends until
December 31, 2004 and will continue beyond that date if financial tests
specified in the partnership agreement are not met. Our interest also includes a
right to receive incentive distributions if the partnership meets or exceeds its
minimum quarterly distribution obligations to the common and subordinated units
as follows:
o of the first $.10 per unit available for distribution in excess of
the $.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 $.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.
In connection with our sale of the gathering systems to Atlas Pipeline
Partners, we entered into agreements that require us to do the following:
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
for gathering system extensions and additions, to a maximum of $1.5
million per year, until 2005.
o Pay gathering fees to Atlas Pipeline Partners 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. For the year ended September
30, 2002, these gathering fees averaged $.57 per Mcf.
o Support a minimum quarterly distribution by Atlas Pipeline Partners
to holders of the common units of $.42 per unit, an aggregate of
$1.68 per fiscal year until February 2003. We established a letter of
credit administered by Wachovia Bank to support our obligation. The
face amount of the letter of credit as of September 30, 2002 was
$630,000.
We believe that we comply with all the requirements of these
agreements. We have not been required to provide any construction financing. For
Atlas Pipeline Partner's initial quarter of operations, ending March 31, 2000,
we provided $443,000 of distribution support due to the timing of its cash
receipts. This amount was subsequently repaid by Atlas Pipeline Partners as
provided in its partnership agreement. No distribution support has been required
in any subsequent quarter.
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 substantial number of drillers and suppliers, none of which supplies a
significant portion of our annual needs. During fiscal 2002, 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.
7
Major Customers. During fiscal 2002 and 2001, gas sales to one
purchaser accounted for 13% and 14%, respectively, of total 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 partnerships.
As a result, competition for investment capital to fund drilling 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 2002 and 2001, we experienced no problems in selling our natural gas and
oil, although prices have varied significantly during and after the period.
Governmental Regulation. Our energy business and the energy industry in
general are heavily regulated by federal and state authorities, including
regulation of production, environmental quality and pollution control, and
pipeline construction and operation. The intent of federal and state regulations
generally is to prevent waste, protect rights to produce natural gas and oil
between owners in a common reservoir and control contamination of the
environment. Failure to comply with regulatory requirements can result in
substantial fines and other penalties. We believe that we substantially comply
with applicable regulatory requirements. The following discussion of the
regulations of the United States energy industry does not intend to constitute a
complete discussion of the various statutes, rules, regulations and
environmental orders to which our operations may be subject.
Regulation of Exploration and Production. Many states require permits
for drilling operations, drilling bonds and reports concerning operations, and
impose requirements concerning the location of wells, the method of drilling and
casing wells, the surface use and restoration of properties on which wells are
drilled, the plugging and abandoning of wells and the disposal of fluids used in
connection with operations. Many states also impose conservation requirements,
principally regulating the density of wells which may be drilled and the
unitization or pooling of properties. In this regard, some states allow the
forced pooling or integration of tracts to facilitate exploration while other
states rely primarily or exclusively on voluntary pooling of lands and leases.
In areas where pooling is voluntary, it may be more difficult to form units and,
therefore, more difficult to develop a project if the operator owns less than
100% of the leasehold. In addition, some state conservation laws establish
requirements regarding production rates and related matters. The effect of these
regulations may be to limit the amount we can produce and may limit the number
of wells or the locations at which we can drill. The regulatory burden on the
energy industry increases our costs of doing business and, consequently, affects
our profitability. Since these laws and regulations are frequently expanded,
amended and reinterpreted, we are unable to predict the future cost or impact of
complying with such regulations.
8
Regulation of Pipelines. While natural gas pipelines generally are
subject to regulation by the Federal Energy Regulatory Commission ("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. The
regulation principally involves transportation rates and service conditions
which affect revenues we receive for our natural gas production. Through a
series of initiatives by FERC, the interstate natural gas transportation and
marketing system has been substantially restructured to increase competition. In
particular, in Order No. 636, FERC required that interstate pipelines provide
transportation separate, or "unbundled," from their sales activities, and
required that interstate pipelines provide transportation on an open access
basis that is equal for all natural gas suppliers. Although Order No. 636 does
not directly regulate our production and marketing activities, it does affect
how buyers and sellers gain access to the necessary transportation facilities
and how we and our competitors sell natural gas in the marketplace. Courts have
largely affirmed the significant features of Order No. 636 and the numerous
related orders pertaining to individual pipelines, although some appeals remain
pending and FERC continues to review and modify its regulations regarding the
transportation of natural gas. We cannot predict what actions FERC will take in
the future. However, we do not believe that any action taken will affect us in a
way that materially differs from the way it affects other natural gas producers,
gatherers and marketers.
State-level regulation for pipeline operations, similar to that of
Atlas Pipeline Partners', is through the Public Utility Commission of Ohio, the
New York Public Service Commission and the Pennsylvania Public Utilities
Commission. Atlas Pipeline Partners has been granted an exemption from
regulation by the Public Utility Commission of Ohio, and believes that it is not
subject to New York or Pennsylvania regulation since it does not generally
provide service to the public.
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, 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. Since 1999, we have focused
our real estate finance activities on managing our existing loan portfolio and
have not originated or acquired any new significant real estate loans. As part
of our portfolio management activities, however, we purchased senior lien
interests relating to properties in which we hold junior lien interests and
invested in three partnerships that own properties adjacent to a property in
which we have an interest. As part of the management process or as opportunities
arise, we may sell, purchase or originate portfolio loans or real property
investments in the future. In fiscal 2002, we decided to expand our real estate
operations through the sponsorship of investment partnerships. We sponsored one
such program, which is currently in the offering stage.
9
At September 30, 2002, our loan portfolio consisted of 30 loans with
aggregate outstanding loan balances of $610.0 million. These loans were acquired
at an investment cost of $386.3 million, including subsequent advances. During
each of fiscal 2002, 2001 and 2000, the yield on our loan portfolio investment
was 9%, including gains on the sale of senior lien interests in, and gains, if
any, resulting from proceeds received by us when property owners refinanced
their loans. Gross profit from our real estate finance activities for the same
periods was $10.7 million, $11.8 million and $11.8 million, respectively. For
these purposes, we calculate gross profit as revenues from loan activities minus
costs, including interest, provision for possible losses and less depreciation
and amortization, without allocation of corporate overhead.
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. Before January 1, 1999, we also sought to sell
senior lien interests; since that date, we have sought to structure our senior
lien transactions as financings rather than sales. At September 30, 2002, senior
lien holders held outstanding obligations of $260.7 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.
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 forebearance agreement. Generally, our forbearance agreements
require:
o payment of all revenues from the property into an operating account
controlled by us or our managing agent;
o payment of all property expenses, including debt service, taxes,
operational expenses and maintenance costs, from the operating
account, after our review and approval;
o receipt by us of specified minimum monthly payments;
o retention by us of all cash flow above the minimum monthly payment
and application to accrued but unpaid debt service;
o appointment of a property manager acceptable to us;
o receipt of our approval before concluding any material contract or
commercial lease; and
o submission of monthly cash flow statements and occupancy reports.
We may alter these arrangements in appropriate circumstances. Where a
borrower refinances a portfolio loan or where we acquired a loan subject to
existing senior debt, we may agree that the revenues be paid to an account
controlled by the senior lien holder, with the excess over amounts payable to
the senior lien holder being paid directly to us. As of September 30, 2002,
revenues were being paid directly to senior lien holders with respect to loan 7
in the table under "Loan Status." Where Brandywine Construction & Management,
Inc., a property manager affiliated with us manages the property, we may direct
that property revenues be paid to Brandywine Construction & Management as our
managing agent. As of September 30, 2002, revenues were being paid to Brandywine
Construction & Management with respect to loans 25 and 30 in the table under
"Loan Status." Where we believe that operating problems with respect to an
underlying property have been substantially resolved, we may permit the borrower
to retain revenues and pay property expenses directly. As of September 30, 2002,
we permitted borrowers with respect to loans 24, 31, 32, 41 and 50 in the table
under "Loan Status" to do so.
As a result of the requirement that borrowers retain a property
management firm acceptable to us, Brandywine has assumed responsibility for
supervisory and, in many cases, day-to-day management of the underlying
properties with respect to substantially all of our portfolio loans as of
September 30, 2002. 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.
10
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."
When we refinance or sell a senior lien interest, the forbearance
agreement typically will remain in effect, subject to any modifications required
by the refinance lender or senior lien holder.
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 at 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. 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.
Refinancings. In borrower refinancings, we reduce the amount
outstanding on our loan by the amount of the net refinancing proceeds received
by us and either convert the outstanding balance of the original note into the
stated principal amount of an amended note on the same terms as the original
note, or retain the original loan obligation as paid down by the amount of
refinance proceeds we receive. The interest rate on the refinancing is typically
less than the interest rate on our retained interest.
Before January 1, 1999, we sought to sell senior lien interests in our
loans. Although we made a strategic decision to structure our transactions after
such date as financings, we retain the right to sell a senior interest in a loan
where it is economically advantageous to do so. When we sell a senior lien
interest, the outstanding balance of our loan at the time of sale remains
outstanding including, as a part of that balance, the amount of the senior lien
interest. Thus, our remaining interest effectively "wraps around" the senior
lien interest.
As of September 30, 2002, senior lien interests with an aggregate
balance of $10.6 million relating to six portfolio loans obligate us, in the
event of a default on a loan, to replace the loan with a performing loan.
After a refinancing or sale 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 a similar device. As
of September 30, 2002, we have six retained interests aggregating $31.3 million
and constituting 17%, by carried cost of investment, of our loan portfolio, that
are not secured by a lien on the underlying property.
Loan Status. The following table sets forth information about our
portfolio loans, grouped by the type of property underlying the loans, as of
September 30, 2002.
11
Fiscal Value
Year Outstanding of Property
Loan Type of Loan Loan Underlying
Number Property Location Seller/Originator Acquired Receivable(1) Loan (2)
------ -------- -------- ----------------- -------- ------------- ----------
Office Properties
005 Office Pennsylvania Shawmut Bank (9) 1993 $ 10,549,861 $ 1,700,000
014 Office Washington,
D.C. Nomura/Cargill/Eastdil Realty (10) 1995 21,811,605 14,300,000
020 Office New Jersey Cargill/Eastdil Realty (10) 1996 8,543,846 4,700,000
026 (12) Office Pennsylvania The Metropolitan Fund/First Trust Bank 1997 10,897,041 4,700,000
029 (12) Office Pennsylvania Castine Associates, L.P. (13) 1997 9,685,101 4,075,000
035 (12) (14) Office Pennsylvania Hudson United Bank (9) 1997 2,798,354 2,900,000
036 Office North Carolina Union Labor Life Insurance Co. 1997 5,786,070 4,150,000
044 (16) Office Washington,
D.C. Dai-Ichi Kangyo Bank 1998 112,068,860 98,500,000
046 Office Pennsylvania First Union Bank (9) 1998 6,000,000 5,300,000
049 (17) Office Maryland Bre/Maryland 1998 110,406,241 99,000,000
053 (18) Office Washington,
D.C. Sumitomo Bank, Limited 1999 132,211,326 86,700,000
------------ ------------
Office Totals $430,758,305 $326,025,000
------------ ------------
Multifamily Properties
001 (19) Multifamily Pennsylvania Alpha Petroleum Pension Fund 1991&99 $ 10,817,964 $ 5,500,000
015 Condo/Multifamily North Carolina First Bank/ SouthTrust Bank 1995&97 5,859,330 5,917,000
022 Multifamily Pennsylvania FirsTrust FSB 1996 6,311,117 5,200,000
024 Multifamily Pennsylvania U.S. Dept. of Housing and Urban Development 1996 3,242,364 3,800,000
028 Condo/Multifamily North Carolina First Bank/South Trust Bank 1997 585,454 498,500
031 Multifamily Connecticut John Hancock Mutual Life Ins. Co. 1997 12,145,530 12,500,000
032 Multifamily New Jersey John Hancock Mutual Life Ins. Co. 1997 14,029,158 14,300,000
034 Multifamily Pennsylvania Resource America, Inc. 1997 477,148 650,000
037 (20) Multifamily Florida Howe, Soloman & Hall Financial, Inc. 1997 7,754,166 3,550,000
041 Multifamily Connecticut J.E. Roberts Companies 1998 20,974,000 22,600,000
050 Multifamily Illinois J.E. Roberts Companies 1998 55,327,984 24,000,000
------------ ------------
Multifamily Totals $137,524,215 $ 98,515,500
------------ ------------
Commercial Properties
007 Single User/Retail Minnesota Prudential Insurance, Alpha Petroleum
Pension Fund 1993 $ 5,772,632 $ 2,300,000
013 (12)(21) Single
User/Commercial California California Federal Bank 1994 2,627,761 2,700,000
017 (12)(22) Single User/Retail West Virginia Triester Investments (9)
Emigrant Savings Bank/Walter R. 1996 1,628,955 1,900,000
018 Single User/Retail California Samuels & Jay Furman 1996 3,207,264 6,800,000
033 Single User/Retail Virginia Brambilla, LTD 1997&99 5,068,593 2,700,000
------------ ------------
Commercial Totals $ 18,305,205 $ 16,400,000
------------ ------------
Hotel Properties
025 Hotel/Commercial Georgia Bankers Trust Co. 1997 $ 8,475,535 $ 10,172,500
030 Hotel Nebraska CNA Insurance 1997 13,962,666 6,300,000
------------ ------------
Hotel Totals $ 22,438,201 $ 16,472,500
------------ ------------
Other Loan Receivable (24)
Condo/Multifamily Pennsylvania Resource America, Inc. 2001 $ 1,009,600 $ N/A
------------ ------------
Other Loan Receivables Total $ 1,009,600 $ N/A
------------ ------------
Balance as of September 30, 2002 $610,035,526 $457,413,000
============ =============
12
Maturity
Resource America's of Loan/
Ratio of Cost Net Interest in Expiration of
Cost of of Investment to Third Party Net Carried Cost Outstanding Loan Forbearance
Investment(3) Appraised Value Liens(4) Investment(5) of Investment(6) Receivables (7) Agreement(8)
- ------------- --------------- ------------ ------------- ---------------- ------------------ --------------
$ 1,746,910 103% $ - $ 1,746,910 $ 1,909,093 $ 10,549,861 10/07/02
12,577,052 88% 6,142,737 6,090,052 8,223,645 15,668,868 11/30/98(11)
3,329,628 71% 2,284,683 767,628 2,321,920 6,259,163 02/07/01(11)
2,879,651 61% 2,021,829 647,958 2,539,253 8,875,213 09/30/03
3,109,074 76% - 484,074 3,898,569 9,685,101 07/01/02(11)
1,845,970 64% 1,687,372(15) 95,970 979,880 1,110,982 09/25/02(11)
3,089,740 74% 1,684,057(15) 1,339,740 2,337,719 4,102,013 12/31/11
95,589,983 97% 66,530,920 21,472,128 36,062,577 45,537,940 08/01/08
4,093,597 77% - 4,093,597 4,172,509 6,000,000 09/30/14
90,576,248 91% 58,416,000 30,576,248 38,655,862 51,990,241 04/01/11
80,236,411 93% 63,923,149 15,236,411 23,014,794 68,288,176 01/15/06
------------ ------------ ------------ ------------ ------------
$299,074,264 $202,690,747 $ 82,550,716 $124,115,821 $228,067,558
------------ ------------ ------------ ------------ ------------
$ 5,841,392 106% $ - $ 5,841,392 $ 6,056,579 $ 10,817,964 08/01/21
2,275,408 38% 2,861,608 (724,592) 2,712,999 2,997,722 03/23/09
2,471,782 48% 3,343,363 (963,218) 974,815 2,967,754 05/03/29
2,743,296 72% 2,373,444 424,546 775,554 868,920 11/01/22
451,511 91% - 451,511 484,345 585,454 03/23/09
4,788,642 38% 8,977,893 (4,586,358) 1,384,044 3,167,637 10/14/14
7,404,156 52% - 1,404,156 12,291,391 14,029,158 09/01/05
415,700 64% - 415,700 471,179 477,148 10/01/02
2,868,614 81% - 2,868,614 3,346,231 7,754,166 06/01/10
14,736,584 65% 13,655,075 636,584 7,289,442 7,318,925 01/01/09
19,916,397 83% 14,987,960 4,566,397 9,572,492 40,340,024 09/30/09
------------ ------------ ------------ ------------ ------------
$ 63,913,482 $ 46,199,343 $ 10,334,732 $ 45,359,071 $ 91,324,872
------------ ------------ ------------ ------------ ------------
$ 1,544,709 67% $ 1,796,036 $ (554,291) $ 1,044,472 $ 3,976,596 12/31/14
1,704,549 63% 2,273,000(15) (543,451) 130,415 354,761 12/21/04
906,542 48% 960,958(15) (93,458) 643,087 667,997 12/31/16
2,584,498 38% 1,969,000 615,498 1,135,780 1,238,264 12/01/00(11)
2,478,353 92% 1,571,279(15) 678,353 1,161,072 3,497,314 02/01/21
------------ ------------ ------------ ------------ ------------
$ 9,218,651 $ 8,570,273 $ 102,651 $ 4,114,826 $ 9,734,932
------------ ------------ ------------ ------------ ------------
$ 7,263,020 71% $ 875,000(23) $ 6,388,020 $ 8,425,668 $ 7,600,535 12/31/15
5,845,737 93% 2,400,000(15) 3,445,737 4,516,621 11,562,666 09/30/02(11)
------------ ------------ ------------ ------------ ------------
$ 13,108,757 $ 3,275,000 $ 9,833,757 $ 12,942,289 $ 19,163,201
------------ ------------ ------------ ------------ ------------
$ 1,009,600 N/A $ N/A $ 1,009,600 $ 1,009,600 $ 1,009,600 09/28/06
------------ ------------ ------------ ------------ ------------
$ 1,009,600 $ N/A $ 1,009,600 $ 1,009,600 $ 1,009,600
------------ ------------ ------------ ------------ ------------
$386,324,754 $260,735,363 $103,831,456 $187,541,607 $349,300,163
============ ============ ============ ============ ============
13
(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,
2002.
(2) We generally obtain appraisals on each of the properties underlying our
portfolio loans at least once every three years. Accordingly, except
with respect to loan 35, appraisal dates range from 1999 through 2002.
(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,
2002.
(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 $3.5 million.
(7) Consists of the amount set forth in the column "Outstanding Loan
Receivable" less senior lien interests at September 30, 2002.
(8) With respect to loans 5, 13, 18, 20, 26, 29 and 35, the date given is
the expiration date of the related forbearance agreement. For the
remaining loans, the date given is for the maturity of our interest in
the loan.
(9) Successor by merger to the seller.
(10) Seller was a partnership of these entities.
(11) Although these forbearance agreements have expired by their term, we
continue to forbear from exercising our remedies since we believe we
receive all of the economic benefit from the properties without having
to incur the expense of foreclosure.
(12) With respect to loans 13, 17 and 26, the president of Brandywine
Construction & Management is the general partner of the borrower and
with respect to loan 29, he is the general partner for the sole limited
partner of the borrower. With respect to loan 35, he is the president
of the general partner of the borrower.
(13) From 1993 to 1997, one of our former executive officers who is also a
former director served as the general partner of the seller.
(14) The borrower is a limited partnership formed in 1991. The general
partner is the president of Brandywine Construction & Management; our
chairman and his wife beneficially own a 49% limited partnership
interest in the partnership and a former director beneficially owns a
1% limited partnership interest.
(15) Senior lien interest sold subject to the right of the holder to require
us to substitute a performing loan, upon default.
(16) The borrower is a limited partnership whose general partner, a former
director, is the president and a director.
(17) The borrower is a limited liability company whose manager is a
corporation of which a former director is the sole shareholder, officer
and director. Our chairman, two of our former directors and the
president of Brandywine Construction & Management are equal limited
partners of an entity that owns approximately 30% of the borrower.
(18) One of our subsidiaries is the manager of the borrower.
(19) We acquired a first mortgage loan at face value from RAIT. The loan is
secured by property in which we have held a subordinate interest since
1991.
(20) The borrower is a limited partnership of which a former director is the
president of the general partner and our chairman, two of our former
directors and the president of Brandywine Construction & Management are
equal limited partners.
(21) Our chairman and his wife beneficially own a 40% limited partnership
interest in the borrower.
14
(22) Consists of a series of notes becoming due yearly through December 31,
2016.
(23) In May 1999, we borrowed $875,000 from a limited partnership in which
our chairman and a former director beneficially own a 22% limited
partnership interest. The loan is secured by a first priority lien on
loan 25. Accordingly, the debt is included in the cost of investment
carried on our books.
(24) In September 2001, we sold a wholly-owned subsidiary to Brandywine
Construction & Management for $4.0 million. Of the $4.0 million we
received, $3.0 million consisted of cash and $1.0 million was in the
form of a non-recourse note, bearing interest at 8% per year and due in
September 2006.
15
The following table sets forth average monthly cash flow (deficit) from
the properties underlying our portfolio loans, average monthly debt service
payable to senior lienholders and refinance lenders, average monthly cash flow
(deficit) with respect to our retained interest and cash flow coverage (the
ratio of cash flow from the properties to debt service payable on senior lien
interests) for the three months ended September 30, 2002. The loans are grouped
by the type of property underlying the loans.
Average Monthly Average Monthly
Interest Principal
Payment on Debt Payment on Debt Average Monthly
Average Monthly Service on Service on Cash Flow
Loan Cash Flow Refinancing or Refinancing or (Deficit) after Cash Flow
Number from Property(1) Senior Lien Interests Senior Lien Interests Debt Service Coverage
------ ---------------- --------------------- --------------------- --------------- ---------
Office
- ------
005 $ 1,337 $ - $ - $ 1,337 N/A
014 88,881 44,510 18,223 26,148 1.42
020 42,254 17,903 1,624 22,727 2.16
026 31,666 17,694 3,906 10,066 1.47
029 26,459 - - 26,459 N/A
035 24,176 14,408 1,494 8,274 1.52
036 32,182 14,396 1,506 16,280 2.02
044 605,007 389,013 67,088 148,906 1.33
046 40,810 - - 40,810 N/A
049 504,639 378,000 72,000 54,639 1.12
053 822,568 662,671 37,923 121,974 1.17
---------- ---------- -------- --------
Office Totals $2,219,979 $1,538,595 $203,764 $477,620 1.27
========== ========== ======== ========
Multifamily
- -----------
001 $ 30,040 $ - $ - $ 30,040 N/A
015&028(2) 23,336 19,995 3,680 (339) 0.99
022 32,134 22,045 2,623 7,466 1.30
024 25,926 15,804 2,158 7,964 1.44
031 81,517 60,034 10,901 10,582 1.15
032 84,583 - - 84,583 N/A
034 3,932 - - 3,932 N/A
037 28,430 - - 28,430 N/A
041 136,667 86,115 13,490 37,062 1.37
050 155,385 100,854 11,137 43,394 1.39
---------- ---------- -------- --------
Multifamily Totals $ 601,950 $ 304,847 $ 43,989 $253,114 1.73
========== ========== ======== ========
Commercial
- ----------
007 $ 20,400 $ 14,423 $ 5,977 $ - 1.00
013 34,271 11,365 - 22,906 3.02
017 10,690 8,142 945 1,603 1.18
018(3) 26,443 13,034 - 13,409 2.03
033 21,940 14,258 5,084 2,598 1.13
---------- ---------- -------- --------
Commercial Totals $ 113,744 $ 61,222 $ 12,006 $ 40,516 1.55
========== ========== ======== ========
Hotel
- -----
025 $ 76,494 $ 7,292 $ - $ 69,202 10.49
030 - 12,300 - (12,300) N/A
---------- ---------- -------- --------
Hotel Totals $ 76,494 $ 19,592 $ - $ 56,902 3.90
========== ========== ======== ========
Other Loan Receivables
- ----------------------
$ 20,641 $ - $ - $ 20,641 N/A
---------- ---------- -------- --------
Other Totals $ 20,641 $ - $ - $ 20,641
========== ========== ======== ========
Totals $3,032,808 $1,924,256 $259,759 $848,793 1.39
========== ========== ======== ========
16
- --------------
(1) "Cash flow" as used in this table is that amount equal to the revenues
from property operations less operating expenses, including real estate
and other taxes pertaining to the property and its operations, and
before depreciation, amortization and capital expenditures.
(2) The properties underlying loans 15 and 28 are different condominium
units in the same building and, accordingly, are combined for cash flow
purposes.
(3) Includes one-twelfth of an annual payment of $120,000 received in
December of each year.
Investments in Real Estate Ventures. In fiscal 1999, we became the
owner of a hotel property in Savannah, Georgia as a result of receiving a
deed-in-lieu of foreclosure. Our carrying cost in this property was $4.3 million
at September 30, 2002. Also in fiscal 1999, the borrower with respect to an
office property and parking garage in Philadelphia, Pennsylvania in which we
have our executive offices, exercised its right to satisfy its loan by paying us
$29.6 million in cash and giving us 50% equity interests in the two properties.
Our carrying cost in these properties was $10.1 million at September 30, 2002.
In fiscal 2002, we invested in three limited partnerships which purchased
properties adjacent to these properties. Our carrying cost for the partnership
interests was $2.7 million at September 30, 2002.
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 flow, which include amounts realizable from the underlying
property, on a quarterly basis. Changes to projected cash flow 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 and sales of senior lien interests,
totaled $165.2 million, $150.7 million and $156.5 million at September 30, 2002,
2001 and 2000, 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. If we determine that 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.
Allowance for Possible Losses. For the year ended September 30, 2002,
we recorded a provision for possible losses of $1.5 million, a write-down of
$559,000 on one loan, which was subsequently sold, increasing our allowance for
possible losses at September 30, 2002 to $3.5 million.
Depending on the structure of the transaction, we can recognize a gain
or loss on the sale of a senior lien interest in a loan. We calculate the gain
or loss by allocating our cost basis between the portion of the loan sold and
the portion retained based upon fair values on the date of sale. Gains resulting
from the refinancing of a property by its owners arise only when the financing
proceeds exceed the carried cost of our investment in the loan. We credit to
income any gain recognized on a sale of a senior lien interest, or a refinancing
at the time of the sale or refinancing.
Sponsorship of Real Estate Investment Trust. We are the sponsor and a
7.9% shareholder, as of September 30, 2002, of RAIT, a real estate investment
trust that began operations in January 1998. RAIT acquires or originates
commercial real estate loans in situations that generally do not conform to the
underwriting standards of institutional lenders or sources that provide
financing through securitization. To a lesser extent, RAIT acquires interests in
real properties. For a description of certain relationships between RAIT and us,
you should read Part III, Item 13, of this report and Note 4, "Certain
Relationships and Related Party Transactions-Relationship with RAIT" in the
Notes to Consolidated Financial Statements. Following the end of fiscal 2002, we
have reduced our interest in RAIT to 7.0%.
17
Financial Services
Our financial services operations currently focus on managing equipment
leasing investment partnerships and entities that invest in the trust preferred
securities of small to mid-size regional banks and bank holding companies and
debt securities collateralized by these trust preferred securities..
We manage equipment leasing partnerships through LEAF Financial
Corporation, formerly F.L. Partnership Management, a wholly-owned subsidiary. At
September 30, 2002, LEAF managed, and acted as the general partner of four
public equipment leasing partnerships that had a net investment of approximately
$22.1 million in equipment leasing assets, principally computer systems and
related peripheral equipment. LEAF receives management fees, expense
reimbursements and, as general partner, an interest in cash distributions from
the partnerships. These partnerships commenced their liquidation periods at
various times between December 1995 and December 1998. LEAF intends to sponsor
new equipment leasing partnerships and currently is the sponsor of one such
public partnership which is in its offering stage.
We own a 50% interest in Trapeza Funding, LLC, an entity that acts as
the general partner of Trapeza Partners L.P., ("Trapeza Partners"), which
sponsored and invested in the equity interests of Trapeza CDO I, LLC, an issuer
of collateralized debt obligations. The collateralized debt obligations are
supported by a pool of trust preferred securities issued by trusts affiliated
with, and whose preferred securities are guaranteed by, banks and other
financial institutions. We also own a 50% interest in Trapeza Capital
Management, LLC, the collateral manager of Trapeza CDO. We will receive
collateral management fees from Trapeza CDO and administrative fees for managing
Trapeza Partners, in addition to the return on our limited partner investment.
We will also receive a 20% carried interest in the limited partnership. In June
2002, Trapeza Partners raised $27.4 million from investors, including $2.8
million from us and a like amount from the other owner of Trapeza Funding. In
November 2002, Trapeza CDO sold $330.0 million of its collateralized debt
obligations. In addition to making an equity investment in the limited
partnership, we provided it with a $5.0 million bridge loan to facilitate the
CDO issuer's purchase of trust preferred securities. We have developed a second
investment partnership to sponsor and purchase equity interests in another
newly-created CDO issuer, which is in its offering stage. We may develop similar
investment partnerships in the future.
Obligations Relating to Discontinued Operations
On August 1, 2000, we sold our small ticket equipment leasing
subsidiary, Fidelity Leasing, 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 until March 31,
2004 as security for our indemnification obligations to the purchasers.
The successor in interest to the purchaser, has made a series of claims
totaling $19.0 million with respect to our indemnification obligations and
representations. In addition, the successor has indicated it will have
significant additional claims with respect to future credit losses that are
covered by the indemnification. While we have disputed these claims, in the
first quarter of fiscal 2003 we entered into substantive settlement negotiations
with the successor. In December 2002, we agreed in principle to the monetary
terms of a non-executed "Term Sheet for Proposed Settlement Agreement" with the
successor. The ultimate settlement is subject to negotiation of a definitive
settlement agreement, which the Company and the successor will seek to complete
on or before December 31, 2002. The Company believes that the terms of any
ultimate settlement will not be materially different from the most recent
proposed agreement as further described.
18
The terms of the proposed agreement would release us and the successor
from certain terms and obligations of the original purchase agreements,
including many of the terms of our non-competition agreement, and claims arising
from circumstances known at the settlement date. In addition, we would (i)
release to the successor the $10.0 million in escrow, previously referred to;
(ii) pay the successor $6.0 million; (iii) guarantee that the successor will
receive payments of $1.2 million from a note, secured by FLI lease receivables,
delivered to us at the close of the FLI sale previously referred to; and (iv)
deliver 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. The liability
relating to the cash payment and the notes is recorded in our consolidated
financial statements as liabilities on assets held for disposal. We recorded a
loss from discontinued operations, net of taxes, of $9.4 million in connection
with this settlement.
Credit Facilities and Senior Notes
Credit Facilities. 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, 2002, $6.4 million was outstanding on this note which matures on April 1,
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.
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 2004. 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
lines of credit. Credit availability is based on the value of the assets pledged
as security and was $18.0 million as of September 30, 2002, 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 2004. 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 500,000 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, 2002, 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, none of
which has been drawn. The facility is secured by our pledge of 520,000 of our
RAIT common shares. Credit availability is 50% of the value of those shares, and
was $5.0 million at September 30, 2002. Loans bear interest, at our election, at
either the prime rate reported in The Wall Street Journal or specified London
Interbank Offered Rates, or 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
2004, 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.
Through our real estate subsidiaries, we have a $10.0 million term loan
with The Marshall Group, formerly Miller and Schroeder Investment Corp. The loan
bears interest at the three month LIBOR rate plus 350 basis points (5.6% at
September 30, 2002), adjusted annually. Principal and interest are payable
monthly based on a five-year amortization schedule maturing on October 31, 2006.
The loan is secured by our interest in the capital stock of 11 real estate
subsidiaries and the portfolio loans and real estate held by those subsidiaries.
The loan prohibits mergers by the subsidiaries and prohibits the subsidiaries,
other than Resource Properties, Inc., our principal real estate subsidiary, from
incurring additional recourse debt. We are required to maintain a specified net
worth, a ratio of recourse debt to net worth and a ratio of cash flow from
pledged collateral to participations under the loan. At September 30, 2002, $7.9
million is outstanding under this loan.
19
In July 2002, our principal energy subsidiary, Atlas America, entered
into a $75.0 million credit facility administered by Wachovia Bank. 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 $45.0 million at September 30, 2002. Up to $10.0 million
of the borrowings under the facility may be in the form of standby letters of
credit. A letter of credit in the original amount of $1.3 million was issued to
Atlas Pipeline Partners under this facility to replace a prior letter of credit
securing our obligation to support, through February 2003, minimum quarterly
distributions by Atlas Pipeline Partners to holders of its common units. The
letter of credit, which has reduced, by its terms, to $630,000, expires in
February 2003. Borrowings under the facility are secured by the assets of Atlas
America and its subsidiaries, including the stock of Atlas America's
subsidiaries and interests in Atlas Pipeline Partners and its general partner.
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, 2002, borrowings under the Wachovia credit facility
bore interest at rates ranging from 3.54% to 5.0%.
The Wachovia credit facility requires Atlas America to maintain a
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 Atlas America to us, on a cumulative basis, to 50% of the
Atlas America's net income from and after April 1, 2002 plus federal income
taxes, amounts necessary to pay interest on our Senior Notes and $5.0 million.
The facility terminates in July 2005, when all outstanding borrowings must be
repaid. We used this credit facility to pay off our previous revolving credit
facility at PNC Bank ("PNC"). At September 30, 2002, $45.0 million was
outstanding under this facility.
Our equipment leasing subsidiary has a $10.0 million warehouse line of
credit with National City Bank of Pennsylvania. We are the guarantor of that
facility. The facility is secured by a pledge of our subsidiary's assets and by
the equipment, equipment leases and proceeds thereof financed by the facility,
and terminates in June 2003. Loans under the facility bear interest, at our
election, at either the National City Bank prime rate plus 1.0% or adjusted
LIBOR plus 3.0%, with the LIBOR adjustment being similar to that in the Wachovia
Bank facility. The facility requires our subsidiary to maintain a specified net
worth and specified interest coverage and debt to net worth ratios. The facility
limits dividends our subsidiary may pay, mergers, sales of assets by our
subsidiary and the terms of equipment leases that may be financed under the
facility. At September 30, 2002, $2.4 million had been drawn under the facility
at an average rate of 4.81%.
Atlas Pipeline Partners has a $10.0 million revolving credit facility
administered by PNC 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 October 2003 and bears interest,
at Atlas Pipeline Partners' election, at the base rate plus the applicable
margin or the euro rate plus the applicable margin.
20
As used in the facility agreement, the base rate is the higher of:
o PNC 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 200 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, 2002, $5.6 million was outstanding under this
facility at an average interest rate of 3.27%.
Senior Notes Our 12% senior notes are unsecured general obligations
with interest payable only until maturity on August 1, 2004. The senior notes
are not subject to mandatory redemption except upon a change in control, as
defined in the indenture governing the senior notes, when the noteholders have
the right to require us to redeem the senior notes at 101% of their principal
amount plus accrued interest. There is no sinking fund for the senior notes. At
our option, we may redeem the senior notes in whole or in part on or after
August 1, 2002 at a price of 106% of principal amount (through July 31, 2003)
and 103% of principal amount (through July 31, 2004), plus accrued interest to
the date of redemption. At September 30, 2002, $65.3 million of these notes were
outstanding.
The indenture governing the senior notes contains covenants that, among
other things, require us to maintain certain levels of net worth (generally, an
amount equal to $200.0 million plus a cumulative 25% of our consolidated net
income less an adjustment based upon the principal amount of senior notes we
repurchase) and liquid assets (generally, an amount equal to 100% of required
interest payments for the next succeeding interest payment date); and limit our
ability to:
o incur indebtedness, but excluding secured indebtedness used to
acquire assets or refinance acquisitions;
o pay dividends or make other distributions in excess of 25% of our
aggregate consolidated net income, offset by 100% of any consolidated
losses, on a cumulative basis;
o engage in specified transactions with affiliates;
o dispose of subsidiaries;
o create liens and guarantees with respect to pari passu or junior
indebtedness;
o enter into any arrangement that would restrict our subsidiaries to
make dividend and other payments to us except in connection with
specified indebtedness;
o merge, consolidate or sell all or substantially all of our assets;
o incur additional indebtedness if our "leverage ratio" exceeds 2.0 to
1.0; or
o incur pari passu or junior indebtedness with a maturity date prior to
that of the senior notes.
As defined by the indenture, the leverage ratio is the ratio of all
indebtedness to our consolidated net worth. The indenture excludes from
indebtedness considered in calculating the leverage ratio debt used to acquire
assets, obligations to repurchase loans or other financial assets sold by us,
guarantees of either of the foregoing, non-recourse debt and certain securities
issued by securitization entities, as defined in the indenture. At September 30,
2002, we believe that we comply with the indenture covenants.
Employees
As of September 30, 2002, we employed 249 persons: 25 in general
corporate, 193 in energy, 24 in equipment leasing partnership management and
seven in real estate finance.
21
Where you can find more information
The periodic reports we file with the SEC are available on our website
at www.resourceamerica.com promptly after we file them with the SEC. In
addition, we will provide you with copies of any of these reports, without
charge, upon request made to:
Michael S. Yecies
Chief Legal Officer
Resource America, Inc.
1845 Walnut St., Suite 1000
Philadelphia, PA 19103
(215) 546-5005
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 as well as interest costs relating to some of the senior
lien interests encumbering our portfolio loans. This could have material adverse
effects, including reduction of net revenues for both our energy and real
estate finance 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. Natural gas and oil prices we
received in fiscal 2002 were significantly lower than the average prices we
received during fiscal 2001 while prices we have received thus far in fiscal
2003 have been higher than the average prices we received in fiscal 2002. 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.
22
The volatility of the energy markets caused by these and other factors
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;
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.
The energy business involves operating hazards such as 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, any
of which 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.
Moreover, 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 income,
the value of our assets or otherwise have a material adverse effect on our
business, financial condition and results of operations.
Although wells we drill are generally to formations that have a high
probability of resulting in commercially productive natural gas and oil
reservoirs, the amount of recoverable 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.
23
The estimates of our proved natural gas and oil reserves and future net
revenues from those reserves are based 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.
The rate of production from natural gas and oil properties declines as
reserves are depleted. 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. We cannot assure you that
we will have sufficient cash flow or cash available from other sources to expand
our reserve base.
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 partnerships such as ours, including deductions for intangible drilling
costs and depletion deductions. If changes to federal tax laws reduce or
eliminate these benefits, our ability to raise capital funds through our
drilling partnerships could be materially impaired.
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 and, as a result, we may
lack technological information or expertise available to other bidders. 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
equal to the greater of $0.35 per Mcf ($0.40 per Mcf in certain instances) or
16% of the purchase price of the natural gas transported. Many of our
transportation arrangements with our existing drilling partnerships require them
to pay us lesser fees. For the years ended September 30, 2002, 2001 and 2000,
the differences between the amount we paid to Atlas Pipeline and the amount we
received from our drilling programs were $10.8 million, $13.1 million and $5.2
million, respectively.
24
We currently serve as the managing general partner of 84 energy
partnerships. As general partner, we are 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 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.
Laws affecting the industry are under constant review, 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.
Risks Relating to Our Real Estate and Financial Services Businesses
The primary or sole source of recovery for our real estate loans is
typically the real property underlying these loans. 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. Although we generally control cash
flow from the properties underlying our loans and, where appropriate, have made
financial accommodations to take into account the operating conditions of the
underlying properties, 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
proceedings, including, bankruptcy, reorganization or foreclosure proceedings.
Our loans 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 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 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.
Operating and other expenses of properties, particularly significant expenses
such as real estate taxes 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 were, acquired as junior lien obligations
or were converted from senior lien obligations to junior lien obligations, as a
result of borrower or senior lien refinancing. Subordinate loans carry a greater
credit risk, including a substantially greater risk of nonpayment of interest or
principal, than senior lien financing. In the event a loan is foreclosed, we
will be entitled to share only in the net foreclosure proceeds after the payment
to all senior lenders. It is therefore possible that we will not recover the
full amount of a foreclosed loan or of our unrecovered investment in the loan.
25
At September 30, 2002, our allowance for possible losses was $3.5
million (1.7%) of the book value of our real estate loans and ventures. You
should not assume 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 our allowance for losses. Losses in excess of our allowance for
losses, or an increase in our provision for losses, could materially reduce our
earnings.
Our loans 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 lender or, if we assume ownership or management, as an owner or operator.
Many environmental laws impose liability regardless of whether we know of, or
are responsible for, the contamination. In addition, if we arrange for the
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 and may materially limit use of contaminated
properties. In addition, future laws or more stringent interpretations or
enforcement policies with respect to existing environmental requirements 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, 2002, 2001 and 2000, accretion of discount was $3.2
million, $5.9 million, and $5.8 million, respectively. Under generally accepted
accounting principles, the amount of income we accrete on a loan equals the
difference between our cost basis in the loan and the sum of the projected cash
flows from the property underlying the loan, net to our interest. 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 investment plus the amount of the
accreted discount, we will recognize an immediate charge to our allowance for
losses or, if that amount is insufficient, our statement of operations.
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, 2002, the participations as to which we had standby commitments
had aggregate outstanding balances of $10.6 million. At September 30, 2002, we
also were contingently liable under guarantees of $2.2 million in mortgage loan
receivables connected with a discontinued operation and contingently liable
under guarantees of $905,000 in standby letters of credit issued in connection
with Atlas Pipeline Partners and our lease of office space in New York City.
In addition, we obtained senior lien financing with respect to loans
15, 22, 44, 49, and 53 in the table under "Loan Status". 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.
26
We believe that none of the foregoing standby commitments or guarantees
must be included in our consolidated financial statements based on our
assessment 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;
o defaults under and acceleration of the maturity of our senior notes
or our other indebtedness; and
o prohibitions on additional borrowings under our credit lines.
In addition, if we become liable under one or more of the foregoing
commitments or contingencies, 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.
We are involved in a dispute with the purchaser of our former
proprietary equipment leasing subsidiary, as discussed in "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Obligations Relating to Discontinued Operations." We are in discussions with the
purchaser to settle that dispute. The amount of the final settlement, if any,
may significantly exceed the amount we have reserved. If the settlement does
exceed the reserve amount, the excess will be a charge against our earnings.
We currently serve as the general partner of five public equipment
leasing partnerships, including one in the offering stage, a private real estate
investment partnership in the offering stage and two private 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 a as general
partner. As a general partner, we are contingently liable for the obligations of
these partnerships to the extent that their obligations cannot be repaid from
partnership assets or insurance proceeds.
27
ITEM 2. PROPERTIES
We maintain our executive office, real estate finance, and financial
services operations in Philadelphia, Pennsylvania under a lease for 15,300
square feet. This lease, which expires 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 2,100 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 rent
other field offices in New York, Ohio and Pennsylvania on a month-to-month
basis. We lease another field office in Ohio and one in Pennsylvania 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.
We lease 10,300 square feet of office space in Pittsburgh,
Pennsylvania, which is subleased to Optiron Corporation, an energy technology
company in which we own a 10% interest. This lease expires in April 2003.
Energy
Production. The following table sets forth the quantities of our
natural gas and oil production, average sales prices, average production costs
per equivalent unit of production and average exploration 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 Mcfe (1) (2)
- ----------- ---------- --------- ------- ------- ------------
2002.......................... 172,750 7,117,276 $20.45 $3.56 $.82
2001.......................... 177,437 6,342,667 $25.56 $5.04 $.84
2000.......................... 195,974 6,440,154 $24.50 $3.15 $.95
- --------------------------
(1) Oil production is converted to Mcfe at the rate of six Mcf per Bbl.
(2) Lifting costs include labor to operate the wells and related equipment,
repairs and maintenance, materials and supplies, property taxes,
insurance and gathering charges.
Productive wells. The following table sets forth information as of
September 30, 2002 regarding productive natural gas and oil wells in which we
have a working interest:
Number of Productive Wells
--------------------------
Gross (1) Net (1)
--------- -------
Oil wells.................................................................... 264 215
Gas wells.................................................................... 4,225 2,295
------ ------
Total................................................................... 4,489 2,510
====== ======
- --------------------------
(1) Includes our equity interest in wells owned by 84 investment
partnerships for which we serve as general partner and various joint
ventures. Does not include our royalty or overriding interests in 601
other wells.
28
Developed and Undeveloped Acreage. The following table sets forth
information about our developed and undeveloped natural gas and oil acreage as
of September 30, 2002. The information in this table includes our equity
interest in acreage owned by drilling partnerships sponsored by us.
Developed Acreage Undeveloped Acreage
-------------------- -------------------
Gross Net Gross Net
----- --- ----- ---
Arkansas..................................... 2,560 403 - -
Kansas....................................... 160 20 - -
Kentucky..................................... 924 462 12,952 6,476
Louisiana.................................... 1,819 206 - -
Mississippi.................................. 40 3 - -
New York..................................... 20,439 15,620 11,975 11,975
Ohio......................................... 141,031 108,866 70,895 67,459
Oklahoma..................................... 4,323 468 - -
Pennsylvania................................. 87,873 67,103 119,959 119,959
Texas........................................ 4,520 329 - -
Utah......................................... 160 37 7,073 1,189
West Virginia................................ 1,077 539 - 5,492
Wyoming...................................... - - 80 80
------- ------- ------- -------
264,926 194,056 222,934 212,630
======= ======= ======= =======
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 $490,300 in fiscal 2002 to maintain our leases.
We believe that we hold good and indefeasible title to our 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 completed for 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
- ----------- ----- --- ----- --- ----- --- ----- ---
2002............. - - - - 246.0 78.7 6 2.0
2001............. - - 1.0 .18 256.0 76.6 1 .27
2000............. - - 1.0 .20 155.0 41.2 3 .80
Present Activites. As of December 1, 2002, we were in the process of
drilling 13 gross (3.6 net) wells.
Delivery Commitments. We are not, nor are the partnerships and joint
ventures we manage, obligated to provide any fixed quantities of oil or gas in
the future under existing contracts.
29
Natural Gas and Oil Reserve Information. 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 SEC 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,
-------------------------------------
2002 2001 2000
------- ------- -------
Natural gas (per Mcf)............................................... $ 3.80 $ 3.81 $ 4.49
Oil (per Bbl)....................................................... $ 26.76 $ 19.60 $ 26.84
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 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.
30
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 deducted operating costs, development costs and production-related
and ad valorem taxes in arriving at the estimated future cash flows. We made no
provision for income taxes, and based 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 17
of the Notes to Consolidated Financial Statements.
Proved Natural Gas and Oil Reserves
-----------------------------------
At September 30,
----------------------------------
2002 2001 2000
---- ---- ----
Natural gas reserves (Mmcf) (1):
Proved developed reserves............................................ 83,996 80,249 74,333
Proved undeveloped reserves.......................................... 39,226 37,868 38,810
-------- -------- --------
Total proved reserves of natural gas................................. 123,222 118,117 113,143
======== ======== ========
Oil reserves (Mbbl) (2):
Proved developed reserves............................................ 1,846 1,735 1,767
Proved undeveloped reserves.......................................... 32 66 -
-------- -------- --------
Total proved reserves of oil......................................... 1,878 1,801 1,767
======== ======== ========
Total proved reserves (Mmcfe) (3)................................. 134,490 128,923 123,745
======== ======== ========
PV-10 estimate of cash flows of proved reserves (in thousands):
Proved developed reserves............................................ $120,260 $109,288 $122,852
Proved undeveloped reserves.......................................... 12,209 17,971 17,929
-------- -------- --------
Total PV-10 estimate................................................. $132,469 $127,259 $140,781
======== ======== ========
- ------
(1) "Mmcf" means a million cubic feet.
(2) "Mbbl" means a thousand barrels.
(3) "Mmcfe" means a million cubic feet equivalent. Oil production is converted
to Mcfe at the rate of six mcf per barrel.
31
ITEM 3. LEGAL PROCEEDINGS
We are a defendant, together with certain of our officers and directors
and our independent auditor, Grant Thornton LLP, in consolidated actions that
were instituted on October 14, 1998 in the U.S. District Court for the Eastern
District of Pennsylvania by stockholders, putatively on their own behalf and as
class actions on behalf of similarly situated stockholders, who purchased shares
of our common stock between December 17, 1997 and February 22, 1999. The
consolidated amended class action complaint seeks damages in an unspecified
amount for losses allegedly incurred as the result of misstatements and
omissions allegedly contained in our periodic reports and a registration
statement filed with the SEC. We have agreed to settle this matter for a maximum
of $7.0 million plus approximately $1.0 million in costs and expenses, of which
$6.0 million will be paid by two of our directors' and officers' liability
insurers. We have agreed to the settlement to avoid the potential of costly
litigation, which would have involved significant time of senior management. A
third insurer has refused to contribute the remaining $2.0 million. We believe
the insurer's refusal is wrongful and intend to bring an action against it. To
the extent that the amount of our recovery, if any, net of our costs and
expenses, is less than $2.0 million, the plaintiffs have agreed to reduce their
settlement amount by 50% of the difference between $2.0 million and the recovery
amount, to a maximum of $1.0 million if we recover nothing. We have charged
operations $1.0 million in the fiscal year ended September 30, 2002 in relation
to this settlement, if we are successful in receiving reimbursement from our
third insurer, future operations will be benefited.
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 believe the complaint is without merit and are defending ourselves
vigorously.
We are a defendant in an action filed in the U.S. District Court for
the District of Oregon by the former chairman of TRM Corporation, who has since
died, and his children. Our chief executive officer and a former director also
have been named as defendants. The plaintiffs' claims for breach of contract,
fraud and promissory estoppel are based on an alleged oral agreement to purchase
one million shares of plaintiffs' stock in TRM Corporation for $13.0 million.
Plaintiffs seek actual damages of at least $12.0 million, plus punitive damages
in an unspecified amount. We believe the complaint is without merit and are
defending ourselves vigorously.
We are also 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
Not applicable.
32
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Our common stock is quoted on the Nasdaq Stock 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 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
Fiscal 2001
- -----------
Fourth Quarter............................................................................. $ 12.90 $ 7.55
Third Quarter.............................................................................. $ 13.81 $ 9.31
Second Quarter............................................................................. $ 12.38 $ 10.00
First Quarter.............................................................................. $ 11.63 $ 7.47
As of November 15, 2002, there were 17,409,000 shares of common stock
outstanding held by 635 holders of record.
We have paid regular quarterly cash dividends on our common stock (as
adjusted for stock splits dividends) of $.03 per share 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. For a description of these restrictions, see Item 1 "Business -
Credit Facilities and Senior Notes."
For information concerning common stock authorized for issuance under
our stock options and other equity compensation plans concerning options
outstanding under these plans, see Note 8 to our consolidated financial
statements.
33
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 Operation" 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, 2002, 2001 and 2000, and at September 30, 2002 and 2001 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, 1999 and 1998 and at
September 30, 2000, 1999 and 1998 from our consolidated financial statements for
those periods audited by Grant Thornton LLP but not included in this report.
34
ITEM 6. SELECTED FINANCIAL DATA - (Continued)
For the Years Ended September 30,
----------------------------------------------------------------------------
2002 2001 2000 1999 1998
---------------- -------------- --------------- -------------- -------------
(in thousands, except per share data)
Income statement data:
Revenues:
Energy............................................ $ 97,912 $ 94,806 $ 70,552 $ 55,093 $ 6,734
Real estate finance............................... 16,582 16,899 18,649 45,907 55,834
Interest and other................................ 6,269 6,601 11,460 8,525 7,263
----------- --------- ---------- --------- ----------
Total revenues................................. $ 120,763 $ 118,306 $ 100,661 $ 109,525 $ 69,831
=========== ========= ========== ========= ==========
Income from continuing operations before
income taxes and cumulative effect of a
change in accounting principle................. $ 11,772 $ 20,410 $ 7,882 $ 35,775 $ 41,127
Provision for income taxes........................ 3,414 6,327 2,401 11,262 13,123
----------- --------- ---------- --------- ----------
Income from continuing operations before
cumulative effect of a change in accounting
principle...................................... 8,358 14,083 5,481 24,514 28,004
----------- --------- ---------- --------- ----------
Net (loss) income.............................. $ (3,309) $ 9,829 $ 18,165 $ 18,460 $ 27,611
=========== ========= ========== ========= ==========
Net (loss) income per common share-basic:
From continuing operations before discontinued
operations and cumulative effect of change
in accounting principle........................ $ .48 $ .78 $ .24 $ 1.10 $ 1.67
=========== ========= ========== ========= ==========
Net (loss) income per common share-basic....... $ (.19) $ .55 $ .78 $ .83 $ 1.65
=========== ========= ========== ========= ==========
Net (loss) income per common share-diluted:
From continuing operations before discontinued
Operations and cumulative effect of change
in accounting principle........................ $ .47 $ .76 $ .23 $ 1.07 $ 1.62
=========== ========= ========== ========= ==========
Net (loss) income per common share-diluted..... $ (.19) $ .53 $ .76 $ .81 $ 1.60
=========== ========= ========== ========= ==========
Cash dividends per common share................... $ .13 $ .13 $ .13 $ .13 $ .13
=========== ========= ========== ========= ==========
Balance sheet data:
Total assets...................................... $ 467,498 $ 466,464 $ 507,831 $ 540,132 $ 415,561
Long-term debt (including current maturities)..... $ 155,510 $ 150,131 $ 134,932 $ 234,028 $ 140,280
Stockholders' equity.............................. $ 233,539 $ 235,459 $ 281,215 $ 263,789 $ 236,478
35
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Overview
Since fiscal 1999, our energy operations have become an increasingly
significant aspect of our company. This results not only from our acquisitions
of energy companies and energy assets, but also from the sale of our proprietary
small ticket leasing business in fiscal 2000 and our decision, also, in fiscal
2000, to focus our real estate finance operations on managing our existing
portfolio rather than acquiring new real estate loans. In fiscal 2002, we began
to pursue expansion of our financial services and real estate operations through
sponsorship of investment partnerships. Neither our financial services nor our
real estate investment partnerships constituted a material portion of our
business at September 30, 2002. We show the expansion of our energy operations
over the past three years in the following tables, which we have restated to
reflect the sale of our proprietary small ticket equipment leasing business in:
Revenues as a Percent of Total Revenues (1)
Years Ended September 30,
-----------------------------------
2002 2001 2000
---- ---- ----
Energy ................................................................ 81% 80% 71%
Real estate finance.................................................... 14% 14% 19%
Assets as a Percent of Total Assets (2)
Years Ended September 30,
-----------------------------------
2002 2001 2000
---- ---- ----
Energy ................................................................ 39% 38% 29%
Real estate finance.................................................... 44% 44% 40%
- -------------
(1) The balance (5% in 2002, 6% in 2001 and 10% in 2000) is attributable to
revenues derived from corporate assets not attributable to a specific
industry segment.
(2) The balance (17% in 2002, 18% in 2001 and 31% in 2000) is attributable to
corporate assets not attributable to a specific industry segment.
36
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 2002, 2001 and
2000:
Years Ended September 30,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
Revenues:
Production.......................................................... $ 28,916 $ 36,681 $ 25,231
Well drilling....................................................... 55,736 43,464 31,869
Well services....................................................... 7,871 8,946 8,682
Transportation...................................................... 5,389 5,715 4,770
----------- ----------- -----------
$ 97,912 $ 94,806 $ 70,552
=========== =========== ===========
Costs and expenses:
Production.......................................................... $ 6,693 $ 6,185 $ 7,229
Exploration......................................................... 1,571 1,661 1,110
Well drilling....................................................... 48,443 36,602 25,806
Well services....................................................... 3,938 4,151 3,772
Transportation...................................................... 2,052 2,001 2,842
Non-direct.......................................................... 7,753 9,376 7,619
----------- ----------- -----------
$ 70,450 $ 59,976 $ 48,378
=========== =========== ===========
Years Ended September 30,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
Revenues (in thousands):
Gas (1)............................................................. $ 25,359 $ 31,945 $ 20,286
Oil................................................................. $ 3,533 $ 4,535 $ 4,802
Production volumes:
Gas (Mcf/day)(1).................................................... 19,499 17,377 17,596
Oil (Bbls/day)...................................................... 473 486 535
Average sales prices:
Gas (per Mmcf)...................................................... $ 3.56 $ 5.04 $ 3.15
Oil (per Bbl)....................................................... $ 20.45 $ 25.56 $ 24.50
Production costs:
As a percent of sales............................................... 23% 16% 29%
Per Mcfe............................................................ $ .82 $ .84 $ .95
(1) Excludes sales of residual gas and sales to landowners.
37
Results of Operations: Energy - (Continued)
Our well drilling revenues and expenses represent the billing and costs
associated with the completion of 242, 234 and 168 net wells for partnerships
sponsored by Atlas America in fiscal 2002, 2001 and 2000, respectively. The
following table sets forth information relating to these revenues and costs and
expenses during the periods indicated:
Years Ended September 30,
-------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Average revenue per well.................................................. $ 230 $ 186 $ 190
Average cost per well..................................................... 200 156 154
---------- ---------- ---------
Average gross profit per well............................................. $ 30 $ 30 $ 36
========== ========== ==========
Gross profit margin....................................................... 7,293 6,862 6,063
========== ========== ==========
Gross margin percent...................................................... 13% 16% 19%
========== ========== ==========
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. Although natural gas
prices were lower in fiscal 2002 than in fiscal 2001, the prices we have
received for our natural gas sold, subsequent to year end, has increased to over
$4.00 per mcf. As a result, if current market conditions persist, we believe
that our natural gas production revenues will be higher in fiscal 2003 than in
fiscal 2002. Natural gas volume increases are attributable to volumes associated
with 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.
Although oil prices were lower in fiscal 2002 than in fiscal 2001, the prices we
have received for our oil sold, subsequent to year end, has increased to an
average of $25.00 per barrel through November 2002. 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 have targeted gas reserves.
Our well drilling gross profit increased $431,000 in fiscal 2002 from
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 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. Both the revenue and cost per well
are affected by changes in oil and gas prices and competition for drilling
equipment and services. We have continued to enter into drilling contracts after
our fiscal year end with gross margin rates of 13% and expect to obtain that
margin through fiscal 2003.
Our well services revenues decreased $1.1 million (12%) primarily as a
result of a decrease in gas marketing revenues due to the continuing decrease of
marketing activities for third parties in fiscal 2002. This decrease was
partially offset by an increase in fee income due to an increase in the number
of wells we operate as a result of new partnership wells drilled during fiscal
2002 and 2001. Our well service expenses decreased 5% in fiscal 2002 as compared
to the prior year. The decrease in fiscal 2002 also resulted from our decreased
gas marketing activities, partially offset by an increase in labor costs due to
an increase in the number of wells we service. Although we sold our gas
marketing subsidiary in fiscal 2000, we maintained a small in-house marketing
function in fiscal 2001, such activities were greatly decreased in fiscal 2002.
We expect fiscal 2003 marketing levels to be in line with fiscal 2002, while we
believe in fiscal 2003, fee income will increase due the addition of
partnerships wells we drill and operate.
38
Results of Operations: Energy - (Continued)
Our transportation revenues, which derive from our natural gas
transportation agreements with 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.
While we continue to seek production efficiencies and reduce 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
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 $7.8 million in fiscal 2002, a decrease of
$1.6 million (17%) 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
earn 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.
Year Ended September 30, 2001 Compared to Year Ended September 30, 2000
Our natural gas revenues were $31.9 million in fiscal 2001, an increase
of $11.7 million (57%) from $20.3 million in fiscal 2000. The increase was due
to a 60% increase in the average sales price of natural gas partially offset by
a 1% decrease in production volumes. The $11.7 million increase in gas revenues
consisted of $12.2 million attributable to price increases, partially offset by
$491,000 attributable to volume decreases.
Our oil revenues were $4.5 million in fiscal 2001, a decrease of
$267,000 (6%) from $4.8 million in fiscal 2000. The decrease resulted from a 9%
decrease in production volumes, partially offset by a 4% increase in the average
sales price of oil. The $267,000 decrease in oil revenues consisted of $474,000
attributable to volume decreases partially offset by $207,000 attributable to
price increases.
Our well drilling gross profits increased $799,000 (13%) in fiscal
2001 as compared to fiscal 2000, as result of an increase in the number of wells
drilled ($1.9 million), partially offset by a decrease in the gross profit per
well ($1.1 million), during fiscal 2001 as compared to fiscal 2000. The average
revenue per well decreased $4,000 (2%), while the average cost per well
increased $2,000 (1%) in fiscal 2001 as compared to fiscal 2000, respectively.
The increase in the number of wells drilled resulted from an increase in the
funds we were able to obtain from investors for our drilling partnerships. Both
the revenue and cost per well are affected by changes in oil and gas prices and
competition for drilling equipment and services.
Well services revenues increased $264,000 (3%) to $8.9 million from
$8.7 million in fiscal 2000 as a result of an increase in the number of wells we
operate. The increase in the number of wells resulted from new partnership wells
drilled during fiscal 2001. This increase was partially offset by a decrease in
gas marketing revenues, associated with the sale of our gas marketing subsidiary
and a reduction of our activities in this area. Our well service expenses
increased $379,000 (10%) to $4.2 million in fiscal 2001 as compared to $3.8
million in fiscal 2000. The increase in fiscal 2001 resulted from an increase in
labor costs due to the increase in the number of wells we service.
39
Results of Operations: Energy - (Continued)
Year Ended September 30, 2001 Compared to Year Ended September 30, 2000 -
(Continued)
Our transportation revenues increased slightly due to volumes
associated with the additional wells drilled and pipelines acquired. Our
transportation expenses decreased $841,000 (30%) in fiscal 2001 as a result of
certain maintenance and repair costs associated with our acquisition of Viking
Resources in fiscal 2000.
Our production costs decreased $1.0 million (14%) to $6.2 million in
fiscal 2001 from $7.2 million in fiscal 2000. Average production costs decreased
$.11 (12%) to $.84 per Mcf in fiscal 2001 from $.95 per Mcf in fiscal 2000. The
decrease in fiscal 2001 as compared to fiscal 2000 reflects efficiencies we
realized through our consolidation of field operations subsequent to various
acquisitions.
Our exploration costs were $1.7 million in fiscal 2001, an increase of
$551,000 (50%) from $1.1 million in fiscal 2000. This increase was due to
increased personnel and operating expenses resulting from our increased drilling
activities.
Our non-direct expenses were $9.4 million in fiscal 2001, an increase
of $1.8 million (23%) from $7.6 million in fiscal 2000. These expenses increased
in part due to increased operations in our energy division and the transfer of
personnel and their related payroll costs from corporate general and
administrative to energy non-direct. In addition, costs and expenses associated
with our public pipeline subsidiary, Atlas Pipeline Partners, increased $567,000
in part due to a full year of operations in fiscal 2001. Also, syndication
expenses and outside services expenses increased $229,000 during fiscal 2001 as
the amount of funds raised for our drilling partnerships and related drilling
and servicing activities increased.
Depletion of oil and gas properties as a percentage of oil and gas
revenues was 17% in fiscal 2001 compared to 23% in fiscal 2000. 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 prices caused depletion as a percentage of oil and
gas revenues to decrease.
Results of Operations: Real Estate Finance
During fiscal 2002, we continued to focus on managing our existing
portfolio of real estate loans rather than on acquiring new real estate loans.
In fiscal 2002 and 2001 we sold eight portfolio loans, took a non-recourse note
as partial proceeds on the sale of one loan, acquired senior lien interests in
each of two loans in which we had previously held only subordinate interests and
acquired senior lien interests in four other loans. These transactions were
primarily directed at simplifying our loan portfolio, improving our lien
seniority and increasing our interest income.
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,
-----------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Revenues:
Interest.......................................................... $ 9,907 $ 9,251 $ 11,229
Accreted discount (net of collection of interest)................. 3,212 5,923 5,802
Gains on resolutions of loans and loan payments in excess
of the carrying value of loans.................................. 2,398 1,612 1,443
Net rental and fee income......................................... 1,065 113 175
----------- ----------- -----------
$ 16,582 $ 16,899 $ 18,649
=========== =========== ===========
Cost and expenses...................................................... $ 2,423 $ 1,504 $ 3,256
=========== =========== ===========
40
Results of Operations: Real Estate Finance - (Continued)
Year Ended September 30, 2002 Compared to Year Ended September 30, 2001
Revenues from our real estate finance operations decreased $317,000
(2%) from $16.9 million in fiscal 2001 to $16.6 million in fiscal 2002. We
attribute these changes to the following:
o A decrease in interest and accreted discount of $2.1 million (14%) in
fiscal 2002 as compared to fiscal 2001, primarily resulting from the
following:
- The sale of three and five loans in fiscal 2002 and fiscal 2001,
respectively, which decreased interest income by $3.6 million in
fiscal 2002 as compared to fiscal 2001. We anticipate that the
sale of loans in fiscal 2002 will further decrease accretion
in fiscal 2003 as compared to fiscal 2002 by approximately $1.2
million.
- The completion of accretion on five loans, which decreased
interest income by $510,000 in fiscal 2002 as compared to fiscal
2001. We anticipate that the completion of accretion on these
loans will further reduce accretion by approximately $1.5 million
in fiscal 2003 as compared to fiscal 2002.
- An increase of $612,000 in our accretion due to increases in our
estimated cash flows relating to several properties. These
increases resulted from improvements in general economic
conditions in the areas in which these properties are located,
which enabled the properties to obtain increased current rents or
occupancy rates and thus increased our estimates of cash flows
from these properties.
- An increase in interest income of $1.4 million resulting from the
purchase of senior lien interests in loans in fiscal 2001 in which
we previously held subordinated interests.
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.
- In fiscal 2002, 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 loans having an 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 in net rental and fee income of $952,000 to $1.1 million
in fiscal 2002 from $113,000 in fiscal 2001. This increase primarily
resulted from an increase of $1.0 million in our equity earnings in
one real estate joint venture in which we own a 50% equity interest
and receipt of a consulting fee of $300,000 from another real estate
joint venture in which we own a 25% equity interest.
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 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. The one real estate partnership we sponsored in fiscal
2002 is in its offering phase and, as a consequence, did not generate fees or
other revenues for us.
41
Results of Operations: Real Estate Finance - (Continued)
Year Ended September 30, 2001 Compared to Year Ended September 30, 2000
Revenues from our real estate finance operations decreased $1.7 million
(9%), from $18.6 million in fiscal 2000 to $16.9 million in fiscal 2001. We
attribute the decrease primarily to the following:
o A decrease of $1.9 million (11%) in interest income resulting from
the following:
- The repayment of two loans by two borrowers, one in October 1999
and one in July 2000 of approximately $59.6 million, which
decreased interest income by $1.9 million during fiscal 2001
compared to fiscal 2000.
- The sale of six loans, one in December 1999, one in June 2000, one
in March 2001, two in June 2001 and one in July 2001, which
decreased interest income by $863,000 during fiscal 2001 compared
to fiscal 2000.
- The completion of accretion of discount in fiscal 2001 on eight
loans as to which $1.4 million in accretion had been taken in
fiscal 2000, as compared to $448,000 of accretion in fiscal 2001,
which decreased interest income by $948,000.
- The non-cash loss and decrease in service fees were offset by an
increase of $1.9 million in accretion of discount on eight loans
in fiscal 2001 compared to fiscal 2000.
o A decrease of $62,000 (35%) in net rental and fee income during
fiscal 2001, to $113,000 from $175,000 in fiscal 2000. The decrease
primarily resulted from the following:
- An increase of $524,000 in a non-cash loss on one real estate
venture. The loss resulted from depreciation and other non-cash
charges allocated to our interest in an investment we account for
on the equity method.
- A decrease of $20,000 in service fees.
- This non-cash loss and decrease in service fees were partially
offset by a one-time service fee of $190,000 received from a real
estate venture in which we own a 50% interest, an increase of
$68,000 in rental income from another real estate venture and
income of $224,000 associated with another joint venture which we
account for using the equity method.
o An increase of $169,000 (12%) in gains on sales of loans from $1.4
million in fiscal 2000 to $1.6 million in fiscal 2001, resulting
primarily from the following:
- The sales of five loans in fiscal 2001, having aggregate book
values of $23.6 million for $25.1 million, resulting in gains of
$1.5 million as compared to the sales of three loans in fiscal
2000, having aggregate book values of $11.1 million, for $12.4
million, resulting in gains of $1.3 million.
- The repayment of two loans in fiscal 2001, having aggregate book
values of $130,000, for $225,000, resulting in gains of $95,000 as
compared to the repayment of four loans in fiscal 2000, having
aggregate book values of $299,000, for $440,000, resulting in
gains of $141,000.
Costs and expenses of our real estate finance operations decreased $1.8
million (54%) to $1.5 million in the year ended September 30, 2001. The decrease
was primarily due to a reduction in staff resulting from our decision in fiscal
2000 to concentrate our real estate finance activities on managing our existing
loan portfolio.
42
Results of Operations: Other Revenues, Costs and Expenses
Our interest and other income was $6.3 million in fiscal 2002, a
decrease of $332,000 (5%) as compared to $6.6 million fiscal 2001. The following
table sets forth information relating to interest and other income during the
periods indicated:
Years Ended September 30,
----------------------------------------
2002 2001 2000
---------- ---------- ----------
(in thousands)
Interest income........................................................... $ 1,242 $ 3,199 $ 8,610
Dividend income........................................................... 3,276 2,170 1,705
Gains (losses) on sales of property and equipment......................... 315 (54) 179
Other..................................................................... 1,436 1,286 966
---------- ---------- ----------
$ 6,269 $ 6,601 $ 11,460
========== ========== ==========
Year Ended September 30, 2002 Compared to Year Ended September 30, 2001
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. Dividend income from
RAIT increased due to the purchase in December 2001 of an additional 125,000
RAIT shares; additionally, the amount of dividends declared by RAIT increased.
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.
Our general and administrative expenses increased $1.5 million (26%) to
$7.1 million in fiscal 2002, from $5.6 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 our senior notes during fiscal 2002 and 2001,
which reduced interest by $1.2 million in fiscal 2002 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.
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 the current fiscal
year and an increase in the general allowance for possible losses, offset by the
recovery 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, as described in Item 3, "Legal Proceedings." To the
extent that our actual cost is less than the provision, it will reduce our
expenses in the future.
We own 51% of the limited 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 own more than 50% 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 $2.6 million for the twelve months ended
September 30, 2002, as compared to $4.1 million for the twelve months 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 2001.
43
Results of Operations: Other Revenues, Costs and Expenses - (Continued)
Our effective tax rate decreased to 29% in fiscal 2002 as compared to
31% in fiscal 2001 as a result of a decrease in the amortization of goodwill in
fiscal 2002 as compared fiscal 2001. We adopted SFAS 142 on October 1, 2001,
which eliminates the amortization of goodwill, and replaced it with a
requirement that goodwill be assessed periodically for impairment and an expense
recognized to the extent of any impairment not previously recognized.
Year Ended September 30, 2001 Compared to Year Ended September 30, 2000
Our interest and other income was $6.6 million in fiscal 2001, a
decrease of $4.9 million (42%) from $11.5 million in fiscal 2000. The decrease
in fiscal 2001 primarily resulted from a decrease in interest income of $5.4
million (63%), most of which was attributable to lower invested balances due to
the use of excess cash received from the sale of our equipment leasing
subsidiary in August 2000. Dividend income increased $465,000 primarily as a
result of our purchase of an additional 475,000 shares of RAIT in fiscal 2001.
Other expenses, which are netted in this line item, decreased $790,000 in fiscal
2001 due to non-recurring charges in the prior year.
Our general and administrative expenses were $5.7 million in fiscal
2001, a decrease of $2.2 million (28%) from $7.9 million in fiscal 2000. The
decrease primarily resulted from decreases in pension expense and salary and
benefits or $2.4 million as we redeployed certain personnel and their related
payroll costs to energy operations from general and administrative costs.
Our depreciation, depletion and amortization expense was $11.0 million
in fiscal 2001, an increase of $1.2 million (12%) from $9.9 million in fiscal
2001. This increase primarily resulted from an increase in the depletable basis
of our oil and gas properties due to the additional capitalized costs associated
with drilling and acquisitions in fiscal 2001.
Our interest expense was $14.7 million in fiscal 2001, a decrease of
$3.9 million (21%) from $18.6 million in fiscal 2000. This decrease primarily
resulted from our repurchase of our senior notes during fiscal 2001, which
reduced interest expense by $2.9 million for fiscal 2001 as compared to fiscal
2000. In addition, a reduction in borrowings and lower rates for our energy
related borrowings decreased interest expense by $1.2 million in fiscal 2001 and
2000. These decreases were partially offset by an increase in interest expense
in our real estate operations due to increased borrowings.
Our provision for possible losses was $863,000 in fiscal 2001, a net
decrease of $73,000 (8%) from $936,000 in fiscal 2000, resulting primarily from
the following:
o In energy, we recorded a provision for possible losses against
receivables in the amount of $263,000, associated with the bankruptcy
filing of an energy customer.
o In real estate, we recorded a provision on one loan in the amount of
$328,000 in fiscal 2000. We subsequently sold the loan in fiscal 2001
at no further loss.
Our minority interest in Atlas Pipeline Partners' earnings was $4.1
million for fiscal 2001 as compared to $2.1 million for fiscal 2000, an increase
of $2.0 million (99%). The increase was the result of an increase in Atlas
Pipeline Partners' net income, resulting from the increase in the average sales
price of natural gas in fiscal 2001, as well as the effect of a full year of
operations in fiscal 2001.
Our effective tax rate increased to 31% in fiscal 2001 as compared to
30% in fiscal 2000 as a result of an increase in pre-tax earnings coupled with a
consistent level of permanent differences between book and taxable income.
44
Discontinued Operations and Cumulative Effect of Change in Accounting Principle
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 investment accounted for by the equity
method, resulted in the presentation of Optiron as a discontinued operation for
the three years ended September 30, 2002. 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 cumulative effect of change in accounting principle relates to our
equity method of accounting for Optiron prior to our decision to dispose of it.
Optiron adopted SFAS 142 on January 1, 2002, and as a result of this adoption,
Optiron realized an impairment and write-down on their 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.
On August 1, 2000, we sold our small ticket equipment leasing
subsidiary, Fidelity Leasing, 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 until March 31,
2004 as security for our indemnification obligations to the purchasers.
The successor in interest to the purchaser, has made a series of claims
totaling $19.0 million with respect to our indemnification obligations and
representations. In addition, the successor has indicated it will have
significant additional claims with respect to future credit losses that are
covered by the indemnification. While we have disputed these claims, in the
first quarter of fiscal 2003, we entered into substantive settlement
negotiations with the successor. In December 2002, we agreed in principle to the
monetary terms of a non-executed "Term Sheet for Proposed Settlement Agreement"
with the successor. The ultimate settlement is subject to negotiation of a
definitive settlement agreement, which the Company and the successor will seek
to complete on or before December 31, 2002. The Company believes that the terms
of any ultimate settlement will not be materially different from the most recent
proposed agreement as described below.
The terms of the proposed agreement would release us and the successor
from certain terms and obligations of the original purchase agreements,
including many of the terms of our non-competition agreement, and claims arising
from circumstances known at the settlement date. In addition, we would (i)
release to the successor the $10.0 million in escrow previously referred to;
(ii) pay the successor $6.0 million; (iii) guarantee that the successor will
receive payments of $1.2 million from a note, secured by FLI lease receivables,
delivered to us at the close of the FLI sale previously referred to; and (iv)
deliver 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. The liability
relating to the cash payment and the notes is recorded in our consolidated
financial statements as liabilities on assets held for disposal. We recorded a
loss from discontinued operations, net of taxes, of $9.4 million in connection
with this settlement.
45
Liquidity and Capital Resources
General. Since fiscal 2000, our major sources of liquidity have been
the proceeds of the sale of our proprietary equipment leasing subsidiary, funds
generated by operations, funds raised from investor partnerships relating to our
energy operations and resolutions of real estate loans and borrowings under our
existing energy and real estate finance credit facilities. We have employed
these funds principally in the expansion of our energy operations, the
repurchase of our common stock and the acquisition of senior lien interests. The
following table sets forth our sources and uses of cash for the periods
indicated:
Years Ended September 30,
-------------------------------------------
2002 2001 2000
----------- ----------- ------------
(in thousands)
Provided by continuing operations...................................... $ 6,827 $ 19,271 $ 15,386
(Used in) provided by investing activities............................. (24,864) (28,233) 175,273
Used in financing activities........................................... (3,477) (58,385) (77,358)
Used in discontinued operations........................................ (1,398) (1,112) (28,698)
----------- ----------- -----------
(Decrease) increase in cash and cash equivalents....................... $ (22,912) $ (68,459) $ 84,603
=========== =========== ===========
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 $4.6 million, a decrease
of $21.3 million from $25.9 million at September 30, 2001 primarily as a result
of our use of the proceeds received from the sale of equipment leasing
subsidiary. Our long-term debt (including current maturities) to total capital
ratio at September 30, 2002 was 40% as compared to 39% at September 30, 2001.
Cash provided by operations is an important source of short-term
liquidity for us. It is directly affected by changes in the price of natural gas
and oil and interest rates as well as our ability to raise funds for our
drilling investment partnerships and the strength of the market for rentals of
the types of properties secured by our real estate loans.
Cash flows from operating activities. Net cash provided by operating
activities decreased $12.4 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 LEAF 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.
o Offsetting these decreases in operating cash flow was an increase of
$10.1 million due to greater amounts owed and paid for income taxes
through fiscal 2001 as compared to fiscal 2002.
46
Liquidity and Capital Resources - (Continued)
Cash flows from investing activities. Net cash used in our investing
activities decreased $3.4 million in fiscal 2002 as compared to fiscal 2001. Our
investing activities primarily consisted of capital expenditures for
developmental drilling and expansion of Atlas Pipeline Partners' gas gathering
facilities and investments in our real estate loans and ventures. The decrease
in fiscal 2002, was due to the expected decrease of $2.4 million 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 and ventures. Payments received on real estate
investments and ventures 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 was primarily due to our repurchase of $54.7 million of our common
stock as a result of our dutch tender offer in fiscal 2001.
Year Ended September 30, 2001 Compared to Year Ended September 30, 2000
We had $48.6 million in cash and cash equivalents on hand at September
30, 2001 as compared to $117.1 million at September 30, 2000, a decrease of
$68.5 million. Our ratio of earnings to fixed charges was 2.7 to 1.0 in the
fiscal year ended September 30, 2001 as compared to 1.5 to 1.0 in the fiscal
year ended September 30, 2000.
Our working capital at September 30, 2001 was $25.9 million, a decrease
of $51.5 million from $77.4 million at September 30, 2000 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, 2001 was 39% as compared to 32% at September 30, 2000.
Cash flows from operating activities. Net cash provided by our
operating activities increased $3.9 million in fiscal 2001 as compared to fiscal
2000 primarily as a result of the following:
o In energy, operating net income, including minority interest,
increased cash flow by $10.7 million in fiscal 2001, primarily as a
result of a 60% increase in the average price we received for our
natural gas.
o Collections of interest decreased cash flow by $4.5 million in fiscal
2001, primarily due to the repayment of accrued interest upon
borrower refinancings of two loans in fiscal 2000. The repayment of
accrued interest upon borrower refinancings vary from transaction to
transaction and therefore create significant variations in our
collections from period to period.
o Changes in the amount of our accounts receivable and accounts payable
and other liabilities increased cash flow by $3.5 million in fiscal
2001, primarily as a result of increases in our production receivable
due to a greater prices expected to be received for our gas, offset
by increases in our account payable due to more wells being drilled
in fiscal 2001 and the timing of the related payments.
o Interest income decreased $5.7 million in fiscal 2001 primarily as a
result of interest income received in fiscal 2000 from our
discontinued leasing subsidiary.
Cash used in investing activities. Net cash used in our investing
activities increased $203.5 million in fiscal 2001 as compared to fiscal 2000
primarily as a result of the following:
o The receipt in fiscal 2000 of $126.3 million from the sale of our
equipment leasing operations.
o Investments in real estate loans and ventures and principal payments
on notes receivable increased cash flows used by $71.6 million in
fiscal 2001 and compared to fiscal 2000 as a result of the purchase
of two loan participations in fiscal 2001 and the repayment of a loan
in fiscal 2000.
47
Liquidity and Capital Resources - (Continued)
Cash used in financing activities. Net cash flows used in our financing
activities decreased $19.0 million in fiscal 2001 as compared to fiscal 2000
primarily as a result of the following:
o Net borrowings under our credit agreements increased cash flow by
$94.0 million in fiscal 2001 as compared to fiscal 2000. In energy,
borrowings increased by approximately $41.9 million, while in real
estate finance, we repaid indebtedness of $58.9 million with the
proceeds received from a borrower financing in fiscal 2000.
o We used $57.8 million in cash in fiscal 2001 to repurchase shares of
our common stock in a dutch auction tender offer.
o We received net proceeds totaling $15.3 million in fiscal 2000 from
the initial public offering of Atlas Pipeline Partners.
Capital Requirements
During fiscal 2002, our capital requirements related primarily to our
investments in our drilling partnerships. In fiscal 2002, we invested
approximately $21.3 million in our drilling partnerships and pipeline extensions
as compared to $14.1 million in fiscal 2001. In fiscal 2002, we funded these
capital expenditures through cash on hand, borrowings under our credit
facilities, and from operations. We, through our energy subsidiaries, have
established two credit facilities with banks to facilitate the funding of our
capital expenditures. In December 2002, we obtained an increase in our borrowing
base on our Wachovia credit facility to $52.5 million. We also anticipate
obtaining a larger credit facility to fund our expansion of Atlas Pipeline's gas
gathering systems.
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 our development. These expenditures are dependent upon the level of
funds raised through investment partnerships. We have budgeted to raise up to
$60.0 million in fiscal 2003 through drilling partnerships which we sponsor. 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 the Company's 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 locate outside capital.
We have entered into certain off-balance sheet financing arrangements.
These financing arrangements are primarily related to commitments associated
with loans we hold in our real estate finance segment. We have made certain
other guarantees on behalf of our subsidiaries. The guarantees relate primarily
to senior lien financing with respect to five loans. The senior lien loans are
with recourse only to the properties securing them, subject to certain standard
exceptions, which we have guaranteed. We believe that the likelihood we would be
required to make payments under the guarantees is remote, please refer to the
tables under "Contractual Obligations and Commercial Commitments."
48
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 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 2002, we received an average of $3.56 per Mcf of natural
gas and $20.45 per barrel of oil after hedging as compared to $5.04 per Mcf of
natural gas and $25.56 per Bbl of oil after hedging in fiscal 2001. However, in
the first quarter of fiscal 2003, the natural gas and oil prices we have
currently received have increased over the average prices we received in fiscal
2002.
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, 2002, 2001 and 2000, we paid dividends
of $2.3 million, $2.4 million and $3.1 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, including but not limited to restrictions which may be
imposed pursuant to the indenture under which our senior notes were issued.
49
Contractual Obligations and Commercial Commitments
The following tables set forth our obligations and commitments as of
September 30, 2002.
Payments Due By Period
(in thousands)
------------------------------------------------------------------
Contractual cash obligations: Less than 1 - 3 4 - 5 After 5
Total 1 Year Years Years Years
-------------- -------------- --------------- ------------ -------------
Long-term debt........................... $ 155,510 $ 4,320 $ 148,745 $ 2,445 $ -
Capital lease obligations................ - - - - -
Operating leases......................... 4,835 1,517 2,062 1,256 -
Unconditional purchase obligations....... - - - - -
Other long-term obligations.............. - - - - -
----------- ----------- ----------- ----------- ---------
Total contractual cash obligations....... $ 160,345 $ 5,837 $ 150,807 $ 3,701 $ -
=========== =========== =========== =========== =========
Amount of Commitment Expiration Per Period
(in thousands)
------------------------------------------------------------------
Other commercial commitments: Less than 1 - 3 4 - 5 After 5
Total 1 Year Years Years Years
-------------- -------------- --------------- ------------ -------------
Lines of credit........................ $ 17,422 $ 7,609 $ 9,395 $ 418 $ -
Standby letter of credit............... 1,260 1,260 - - -
Guarantees............................. 2,168 90 2,078 - -
Standby replacement commitments........ 10,577 2,728 7,849 - -
Other commercial commitments........... 195,075 2,296 61,345 4,162 127,272
----------- ----------- ------------ ---------- ----------
Total commercial commitments........... $ 226,502 $ 13,983 $ 80,667 $ 4,580 $ 127,272
=========== =========== ============ ========== ==========
Critical Accounting Policies
The discussion and analysis of our financial condition and results of
operations are based upon our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States. The preparation of these financial statements requires us to make
estimates and judgments that affect the reported amounts of our assets,
liabilities, revenues and cost 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. For a detailed
discussion on the application of these and other accounting policies, see Note 2
of the "Notes to Consolidated Financial Statements" in Item 8 of this report.
50
Accounts Receivable and Investments in Real Estate Loans and Allowance for
Possible Losses.
Each of our business segments engages in credit extension, monitoring,
and collection. In energy, we also perform ongoing credit evaluations of our
customers and adjust credit limits based upon payment history and the customer's
current credit worthiness, as determined by our review of our customer's credit
information. We extend credit on an unsecured basis to many of our energy
customers.
We continuously monitor collections and payments from our
borrowers/customers and maintain a provision for estimated losses based upon our
historical experience and any specific borrower/customer collection issues that
we identify. We reduce accounts and loans receivable by an allowance for amounts
that may become uncollectible in the future. Such allowances can be either
specific to a particular borrower/customer or general to all borrowers/customers
in each of our two business segments. As of September 30, 2002 and 2001, we had
accounts and notes receivable and investments in real estate loans of $202.4
million and $206.4 million, net of an allowance for possible losses of $ $3.5
million and $2.5 million, respectively. We believe our allowance for possible
losses is adequate at September 30, 2002. However, an adverse change in the
facts and circumstances with regard to one of our larger loans could cause us to
experience a loss in excess of our allowance. At September 30, 2002, our credit
evaluations have indicated that we had no need for an allowance for possible
losses for our oil and gas receivables.
We believe the level of 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, 2002. We cannot guarantee that we will continue to
experience the same loss rates that we have experienced in the past since
adverse changes in the oil and gas and real estate markets, or changes in the
liquidity or financial position of our borrowers/customers, could have a
material adverse effect on the collectibility of our receivables and our future
operating results. If losses exceed established allowances, our results of
operation and financial condition may be adversely affected.
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.
51
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. Given 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 and there can be no assurance that such impairments will not be
required in the future. Any such impairment may affect or cause a reduction in
our energy credit facilities.
Business Combinations
Our energy operations have grown substantially through the acquisitions
of several companies. These acquisitions were accounted for using the purchase
method of accounting. Recent accounting pronouncements require that all future
acquisitions be accounted for using the purchase method.
Under the purchase method, the acquiring company adds to its balance
sheet the estimated fair values of the acquired company's assets and
liabilities. Any excess of the purchase price over the fair values of the
tangible and intangible net assets acquired is recorded as goodwill. 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. There can be no assurance that
we may not incur an impairment in association with this goodwill or its related
assets in the future.
There are various assumptions made by us in determining the fair values
of an acquired company's assets and liabilities. The most significant
assumptions, and the ones requiring the most judgment, involve the estimated
fair values of the oil and gas properties acquired. To determine the fair values
of these properties, we prepare estimates of oil and natural gas reserves. These
estimates are based on work performed by our engineers and outside petroleum
reservoir consultants. The judgments associated with the estimation of reserves
are described earlier in this section. We then calculate the fair value of the
estimated reserves acquired in a business combination based on our estimates of
future oil and natural gas prices. We base our estimates of future prices on our
analysis of pricing trends. We apply our estimates of future prices to the
estimated reserve quantities acquired to arrive at estimates of future net
revenues. For estimated proved reserves, we then apply an appropriate discount
of the future net revenues to derive a fair value for such reserves. We also
apply these same general principles in arriving at the fair value of unproved
reserves acquired in a business combination. We generally classify these
unproved reserves as either probable or possible reserves. Because of their very
nature, probable and possible reserve estimates are less precise than those of
proved reserves. Generally, in our business combinations, the determination of
the fair values of oil and gas properties requires more judgment than the
estimates of fair values for other acquired assets and liabilities. A decrease
in these fair values could affect our future borrowing ability.
52
Goodwill and Other Long-Lived Assets
We make estimates regarding the fair value of our reporting units in
assessing potential impairment of goodwill. In addition, we make estimates
regarding future undiscounted cash flows from the future use of other long-lived
assets whenever events or changes in circumstances indicate that the carrying
amount of a long-lived asset may not be recoverable.
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 is realized as 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.
Recently Issued Financial Accounting Standards
Recently FASB issued SFAS 143 and SFAS 144. SFAS 143 establishes
requirements for the accounting for removal costs associated with asset
retirements and SFAS 144 addresses financial accounting and reporting for the
impairment or disposal of long-lived assets. SFAS 143 is effective for fiscal
years beginning after June 15, 2002, with earlier adoption encouraged, and SFAS
144 is effective for fiscal years beginning after December 15, 2001 and interim
periods within those fiscal years. SFAS 143 will require us to record a
liability for our retirement obligations with the related transition adjustment
reported as a cumulative affect of a change in accounting principle. We are
currently assessing the impact of SFAS 143 on our consolidated financial
statements. The adoption of SFAS 144 resulted in the classification of our
investment in Optiron as a discontinued operation.
In May 2002, SFAS 145, "Rescission of FASB Statements No. 4, 44, and
64, Amendment of FASB Statement No. 13, and Technical Corrections" was issued.
SFAS 145 rescinds the automatic treatment of gains and losses from
extinguishments of debt as extraordinary unless they meet the criteria for
extraordinary items as outlined in Accounting Principles Board Opinion No. 30,
"Reporting the Results of Operations, Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions." SFAS 145 also requires sale-leaseback accounting for
certain lease modifications that have economic effects similar to a
sale-leaseback transaction and makes various corrections to existing
pronouncements. The adoption of SFAS 145 did not have a material effect on our
consolidated financial position or results of operations.
In June 2002, the FASB reached a consensus on certain issues raised in
Emerging Issues Task Force ("EITF") Issue No. 02-3. The consensus requires
mark-to-market gains and losses on energy trading contracts to be shown net in
the income statement whether or not these contracts are settled physically as
well as disclosures of gross transaction volumes for contracts that are
physically settled. This provision in EITF Issue 02-3 is effective for financial
statements ending after July 15, 2002, and comparative financial statements will
be reclassified to conform to the new presentation. Additional disclosures such
as types of contracts accounted for as energy trading contracts, reconciliation
of beginning and ending fair values, and descriptions of methods and assumptions
used to estimate fair value are also required. The adoption of EITF No. 02-3 did
not have a material effect on our consolidated financial position or results of
operations.
53
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 the hypothetical changes in market risk factors
occurred on September 30, 2002. 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, 2002, the amount outstanding under
a revolving loan attributable to our energy operations had increased to $43.7
million from $41.2 million at September 30, 2001. The weighted average interest
rate for this facility decreased from 5.67% at September 30, 2001 to 3.86% at
September 30, 2002 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 $200,000.
We have a $10.0 million revolving credit facility to fund the expansion
of Atlas Pipeline Partners' existing gathering systems and the acquisitions of
other gas gathering systems. In the year ended September 30, 2002, we drew $3.5
million under this facility. The balance outstanding as of September 30, 2002
was $5.6 million. At September 30, 2002, the weighted average interest rate was
3.27%. A hypothetical 10% change in the average interest rate applicable to this
debt would result in an immaterial change in our earnings, cash flow and
financial position.
Commodity Price Risk. Our major market risk exposure in commodities is
fluctuations in the pricing of our 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
gas and oil production has been volatile and unpredictable for many years. To
hedge exposure to changing natural gas prices we use both non-financial and
financial 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.
54
Energy - (Continued)
Non-financial hedges allow us from time to time to "lock in" the sale
price for some of our natural gas production volumes to be delivered in either
the current month or in future months, rather than selling those same production
volumes at contract prices in the month produced. Annually, we negotiate with
certain purchasers to deliver a portion of natural gas produced for the upcoming
twelve months. Most of these contracts are indexed based and the price we
receive for our gas changes as the underlying index changes. Through the year,
at our discretion, we are permitted to designate a portion of our negotiated
production volumes to be purchased at the prevailing contract price at that
time, for delivery in either the current month or in future production months.
For the fiscal year ended September 30, 2002, approximately 49% of produced
volumes were sold in this manner. For the fiscal year ending September 30, 2003,
we estimate in excess of 65% of our produced natural gas volumes will be sold in
this manner, leaving the remaining 35% of our produced volumes to be sold at
contract prices in the month produced or at spot market prices. Considering
those volumes already designated for the fiscal year ending September 30, 2003,
and current indices, a theoretical 10% upward or downward change in the price of
natural gas would result in approximately a 6% change in our projected natural
gas revenues.
We periodically enter into financial hedging activities with respect to
a portion of our projected 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.
Effective October 1, 2000, we adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities" (as amended by SFAS 138). As of
September 30, 2002, we had gas hedges in place covering 747,600 dekatherm
maturing through September 2003. We include the fair value of these hedges
($316,600 liability at September 30, 2002) on our balance sheet. "Fair value"
represents the amount that we estimate we would have realized if we had
terminated the hedges on that date. As these contracts qualify and have been
designated as cash flow hedges, we determine gains and losses on them resulting
from market price changes monthly and reflect them in accumulated other
comprehensive income (loss) until the month in which we sell the hedged
production. At that time, the amount included in accumulated other comprehensive
income (loss) related to the sold production is closed to production revenues.
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 2002,
2001 and 2000 were $59,000, $599,000 and $832,000, respectively.
55
We set forth in the following table our natural gas hedge transactions
in place as of September 30, 2002. The total fiscal 2002 hedged natural gas
volumes represent approximately 3% of our fiscal 2002 total gas production. A
10% variation in the market price of natural gas from its levels at September
30, 2002 would not have a material impact on our net assets, net earnings or
cash flows as derived from commodity option contracts.
Open Volumes of Settlement Date Weighted Average Unrealized
Contracts Natural Gas (Dth) Quarter Ended Price Per Dth Losses
--------- ----------------- ------------------ ---------------- ------------
36 100,800 December 2002 $ 3.58 $ (73,500)
59 165,200 March 2003 3.56 (81,100)
105 294,000 June 2003 3.57 (101,900)
67 187,600 September 2003 3.63 (60,100)
--- ------- -----------
267 747,600 $ 3.58 $ (316,600)
=== ======= ======= ===========
Real Estate Finance
Portfolio Loans and Related Senior Liens. The following information is
based on our loans that are not interest rate sensitive. During the year ended
September 30, 2002, our outstanding loans receivable (to our interest) increased
$4.9 million (2%) to $297.3 million in the aggregate and the carried cost of
our loans decreased $4.9 million (3%) to $148.9 million in the aggregate. The
principal balance of related senior lien interests decreased $18.3 million
(8%) to $202.3 million in the aggregate. These changes were principally
attributable to the repayment of four senior lien interests and the resolution
of three loans.
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, 2002 because there were three decreases in the defined
prime rate. This defined rate was the "prime rate" as reported in The Wall
Street Journal (4.75% at September 30, 2002). A hypothetical 10% change in the
average interest rate applicable to these lines of credit would change our net
income by approximately $133,000.
We also have a $10.0 million term loan agreement. The loan bears
interest at the three month LIBOR rate plus 350 basis points, adjusted annually.
Principal and interest is payable monthly based on a five year amortization
schedule maturing on October 31, 2006. At September 30, 2002, $7.9 million was
outstanding on this loan at an interest rate of 5.6%. A hypothetical 10% change
in the average interest rate applicable to this loan would change our net income
by approximately $44,000.
Due to the current interest rate environment, we have been negotiating
with senior lienholders with respect to properties underlying several of our
real estate loans to reduce the senior lien interest rates. In the year ended
September 30, 2002, we negotiated interest rate reductions with three of our
senior lienholders.
Financial Services
In June 2002, LEAF Financial Corporation, our equipment-leasing
subsidiary, entered into a $10.0 million secured revolving credit facility with
National City Bank. The facility is guaranteed by us and has a term of 364 days.
Outstanding loans will bear interest at one of two rates, elected at borrower's
option; (i) the lender's prime rate plus 200 basis points, or (ii) LIBOR plus
300 basis points. As of September 30, 2002, the balance outstanding was $2.4
million at an average interest rate of 4.81%. A hypothetical 10% change in the
average interest rate on this facility would have an immaterial effect on our
earnings, cash flow and financial position.
Other
In June 2002, we established a $5.0 million revolving line of credit
with Commerce Bank. The facility has a term of two years 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, 2002, we had no outstanding borrowings
under this facility.
56
Assets
The following table sets forth information regarding 29 of the 30 loans
held in our portfolio as of September 30, 2002. The presentation, for each
category of information, aggregates the loans by their maturity dates for
maturities occurring in each of the fiscal years 2003 through 2007 and
separately aggregates the information for all maturities arising after the 2007
fiscal year. We do not believe that these loans 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 all 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. For information regarding specific loans,
you should review Item 1 of this report, "Business - Real Estate
Finance - Loan Status," and the tables included in that section.
Portfolio Loans, Aggregated by Maturity Dates,(1) as of and for the Years Ended September 30,
---------------------------------------------------------------------------------------------------
2003(2) 2004 2005 2006 2007 Thereafter Totals
------------- ------------- -------------- ------------- ---------- -------------- ----------------
Outstanding loan
receivable balances (to our
net interest).............. $65,427,265 n/a $14,383,919 $69,297,777 n/a $148,200,961 $297,309,922
Carried cost of investment
(fixed rate)........... $22,097,371 n/a $12,291,391 $24,024,394 n/a $81,296,281 $139,709,437
Average stated interest
rate (fixed rate)...... 10.09% n/a 11.25% 9.53% n/a 10.60%
Carried cost of investment
(variable rate)........ $ 3,898,569 n/a $130,415 n/a n/a $5,147,324 $9,176,308
Average stated interest
rate (variable rate)... 7.40% n/a n/a n/a n/a 4.90%
Average interest payment
rate................. (3) (3) (3) (3) (3) (3)
Third party liens...... $16,505,621 n/a n/a $63,923,149 n/a $121,890,593 $202,319,363
Average interest rate of
senior lien interests
(fixed rate)......... 9.19% n/a n/a n/a n/a 7.29%
- ----------------
(1) Maturity dates of related forbearance agreement or our interest in the
loan.
(2) Includes six loans whose forbearance agreements expired during the
fiscal year ended September 30, 2002, 2001 and 2000. These loans
aggregated $43.3 million of outstanding loan receivables, to our
interest. The carried costs, of the loans were $21.1 million and the
principal balance of the related third party liens was $14.5 million.
We continue to forbear from exercising our remedies with respect to
these loans since we receive all of the economic benefit from the
properties without having to incur the expense of foreclosure.
(3) Pay rates are equal to the net cash flow from the underlying properties
after payments on third party liens and, accordingly, depend upon
future events not determinable as of the date of this report.
57
(4) Maturity dates for third party liens according to the maturity of our
underlying loans are as follows:
Maturity Date of Maturity Dates of
Portfolio Loans Third Party Liens Outstanding Balance
(Fiscal Year Ended (Fiscal Year Ended of Third Party Liens
September 30) September 30) at September 30, 2002
------------------ ------------------ ---------------------
2000(a) 2000 $ 6,142,737
2001(a) 2001 1,969,000
2007 2,284,683
2002(a) 2003 1,687,372
2004 2,400,000
2003 2006 2,021,829
2006 2006 63,923,149
Thereafter 2003 960,958
2003 1,684,057
2004 875,000
2004 1,571,279
2005 2,273,000
2008 66,530,920
2008 2,373,444
2009 8,977,893
2009 2,861,608
2009 3,343,363
2009 13,655,075
2009 14,987,960
2014 1,796,036
---------------
Total $ 202,319,363
===============
- -------------
(a) The forbearance agreements with respect to these loans came due during
the fiscal years ended September 30, 2002, 2001 and 2000. We continue
to forbear from exercising our remedies with respect to these loans
since we believe we receive all of the economic benefit from the
properties without having to incur the expense of foreclosure.
58
The following table sets forth information concerning one of the 30
loans held in our portfolio at September 30, 2002 that we believe may be deemed
to be interest rate sensitive.
Outstanding receivable balance (to our net interest).......... $ 51,990,241
Carried cost of investment.................................... $ 38,655,862
Interest payment rate......................................... Net cash flow from property underlying loan
Stated rate: 10.0%
Third party lien.............................................. $ 58,416,000
Interest rate (third party lien).............................. Stated rate: LIBOR plus 200 basis points;
Current rate: 8.8%
Maturity date (third party lien).............................. 10/01/05
For a discussion of the changes in our loan portfolio, you should read
Item 7 of this report, "Management's Discussion and Analysis of Financial
Condition and Results of Operation: Real Estate Finance."
Corporate Liabilities
The following table sets forth certain information regarding our debt
obligations as of September 30, 2002. For further information regarding our
senior notes and credit facilities, you should read Item 1, "Business - Credit
Facilities and Senior Notes," and Note 6 to the Consolidated Financial
Statements.
Debt Obligations, Aggregated by Maturity Date as of and for the
Years Ended September 30,
-----------------------------------------------------------------------------------------
2003 2004 2005 2006 2007 Total
-------------- -------------- -------------- -------------- -------------- --------------
(dollars in thousands)
Fixed rate.................. $ - $66,211 $ - $ - $ - $66,211
Average interest rate....... - 11.97% - - - -
Variable rate............... $4,320 $36,867 $45,667 $2,041 $404 $89,299
Average interest rate....... 5.15% 4.63% 3.93% 5.6% 5.45% -
Futures Contracts
For information regarding open natural gas futures contracts relating
to natural gas sales at September 30, 2002 and the results of natural gas
hedging during fiscal 2002, 2001 and 2000, you should read Note 10 of the notes
to the consolidated financial statements.
59
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. and subsidiaries as of September 30, 2002 and 2001, 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, 2002. These financial statements and Schedule IV are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements and schedule 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, 2002 and 2001, and
the consolidated results of their operations and cash flows for each of the
three years in the period ended September 30, 2002, in conformity with
accounting principles generally accepted in the United States of America.
As discussed in Notes 3 and 15 to the financial statements, effective
October 15, 2001, the Company changed its method of accounting for goodwill for
the adoption of SFAS No. 142.
As discussed in Note 2, the Company adopted SFAS No. 145 resulting in
the reclassification of net gain from the extinguishment of debt from an
extraordinary item to interest and other in the consolidated statements of
operations.
We have also audited Schedule IV as of September 30, 2002. In our
opinion, this schedule, 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.
Grant Thornton LLP
Cleveland, Ohio
November 22, 2002, except for the sixth through eighth paragraphs of Note 12,
for which the date is December 24, 2002.
60
RESOURCE AMERICA, INC.
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 2002 AND 2001
2002 2001
---------- -----------
(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents................................................. $ 25,736 $ 48,648
Accounts receivable....................................................... 16,060 18,197
Assets held for disposal.................................................. 5,488 7,141
Prepaid expenses.......................................................... 2,696 762
---------- -----------
Total current assets.................................................... 49,980 74,748
Investments in real estate loans and ventures (less allowance for
possible losses of $3,480 and $2,529)..................................... 202,423 206,400
Investment in RAIT Investment Trust.......................................... 29,580 20,909
Property and equipment:
Oil and gas properties and equipment (successful efforts)................. 126,983 106,795
Gas gathering and transmission facilities................................. 28,091 23,608
Other..................................................................... 8,390 7,310
---------- -----------
163,464 137,713
Less - accumulated depreciation, depletion and amortization.................. (44,287) (34,739)
---------- -----------
Net property and equipment................................................ 119,177 102,974
Goodwill..................................................................... 37,471 31,420
Other assets................................................................. 28,867 30,013
---------- -----------
$ 467,498 $ 466,464
========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt......................................... $ 4,320 $ 8,560
Accounts payable.......................................................... 12,378 18,264
Accrued interest.......................................................... 1,760 1,721
Liabilities associated with assets held for disposal...................... 11,317 -
Accrued liabilities....................................................... 9,808 6,255
Estimated income taxes.................................................... 893 288
Deferred revenue on drilling contracts.................................... 4,948 13,770
---------- -----------
Total current liabilities............................................. 45,424 48,858
Long-term debt:
Senior.................................................................... 65,336 66,826
Non-recourse.............................................................. 68,220 62,159
Other..................................................................... 17,634 12,586
---------- -----------
151,190 141,571
Liabilities associated with assets held for disposal......................... 3,144 -
Deferred revenue and other liabilities....................................... 1,074 1,578
Deferred income taxes........................................................ 13,733 18,682
Minority interest............................................................ 19,394 20,316
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................ 250 249
Additional paid-in capital................................................ 223,824 223,712
Less treasury stock, at cost.............................................. (74,828) (74,080)
Less loan receivable from Employee Stock Ownership Plan (ESOP)............ (1,201) (1,297)
Accumulated other comprehensive income.................................... 5,911 1,657
Retained earnings......................................................... 79,583 85,218
---------- -----------
Total stockholders' equity.......................................... 233,539 235,459
---------- -----------
$ 467,498 $ 466,464
========== ===========
See accompanying notes to consolidated financial statements
61
RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED SEPTEMBER 30, 2002, 2001 AND 2000
2002 2001 2000
---------- ---------- ----------
(in thousands, except per share data)
REVENUES
Energy.................................................................... $ 97,912 $ 94,806 $ 70,552
Real estate finance....................................................... 16,582 16,899 18,649
Interest and other........................................................ 6,269 6,601 11,460
---------- ---------- ----------
120,763 118,306 100,661
COSTS AND EXPENSES
Energy.................................................................... 70,450 59,976 48,378
Real estate finance....................................................... 2,423 1,504 3,256
General and administrative................................................ 7,143 5,680 7,894
Depreciation, depletion and amortization.................................. 11,161 11,038 9,872
Interest.................................................................. 12,816 14,736 18,632
Provision for possible losses............................................. 1,393 863 936
Provision for legal settlement............................................ 1,000 - -
Termination charge........................................................ - - 1,753
Minority interest in Atlas Pipeline Partners, L.P......................... 2,605 4,099 2,058
---------- ---------- ----------
108,991 97,896 92,779
---------- ---------- ----------
Income from continuing operations before income taxes..................... 11,772 20,410 7,882
Provision for income taxes................................................ 3,414 6,327 2,401
---------- ---------- ----------
Income from continuing operations ........................................ 8,358 14,083 5,481
---------- ---------- ----------
Discontinued operations:
(Loss) income on discontinued operations, net of income tax benefit
(provision) of $5,944, $2,439 and ($8,266)......................... (11,040) (4,254) 12,684
Cumulative effect of a change in accounting principle, net of taxes of $336 (627) - -
---------- ---------- ----------
Net income (loss)......................................................... $ (3,309) $ 9,829 $ 18,165
========== ========== ==========
Net income (loss) per common share - basic:
From continuing operations................................................ $ .48 $ .78 $ .24
Discontinued operations................................................... (.63) (.23) .54
Cumulative effect of a change in accounting principle..................... (.04) - -
Net income (loss) per common share - basic................................ $ (.19) $ .55 $ .78
========== ========== ==========
Weighted average common shares outstanding................................ 17,446 17,962 23,413
========== ========== ==========
Net income (loss) per common share - diluted:
From continuing operations................................................ $ .47 $ .76 $ .23
Discontinued operations................................................... (.62) (.23) .53
Cumulative effect of a change in accounting principle.....................
(.04) - -
---------- ---------- ----------
Net income (loss) per common share - diluted.............................. $ (.19) $ .53 $ .76
========== ========== ==========
Weighted average common shares............................................ 17,805 18,436 23,828
========== ========== ==========
See accompanying notes to consolidated financial statements
62
RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2002, 2001 AND 2000
2002 2001 2000
---------- ---------- ----------
(in thousands)
Net (loss) income......................................................... $ (3,309) $ 9,829 $ 18,165
Unrealized gain on investment in RAIT Investment Trust,
net of taxes of $2,305, $1,350 and $413................................. 4,475 2,622 788
Unrealized (loss) gain on natural gas futures and option contracts,
net of taxes of $105 and ($5)........................................... (221) 9 -
---------- ---------- ----------
Comprehensive income...................................................... $ 945 $ 12,460 $ 18,953
See accompanying notes to consolidated financial statements
63
RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED SEPTEMBER 30, 2002, 2001, AND 2000
(in thousands, except share data)
Additional
Common Stock Paid-In Treasury Stock ESOP
---------------------------- ------------------------------ Loan
Shares Amount Capital Shares Amount Receivable
---------------------------------------------------------------------------------------
Balance, September 30, 1999............... 24,385,279 $ 244 $ 221,084 (1,071,432) $ (17,002) $ (1,488)
Treasury shares issued.................... (917) 66,450 1,396
Issuance of common stock.................. 236,683 2 1,194
Purchase of treasury shares............... (25,000) (172)
Other comprehensive income................
Cash dividends ($.13 per share)...........
Repayment of ESOP loan.................... 95
Net income................................
- ------------------------------------------------------------------------------------------------------------------------------------
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 option
exercise................................ 244
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)
========== ========== ============= ========== ========== ========
[RESTUBBED TABLE]
Accumulated
Other Totals
Comprehensive Retained Stockholders'
Income (Loss) Earnings Equity
----------------------------------------------
Balance, September 30, 1999............... $ (1,762) $ 62,713 $ 263,789
Treasury shares issued.................... 479
Issuance of common stock.................. 1,196
Purchase of treasury shares............... (172)
Other comprehensive income................ 788 788
Cash dividends ($.13 per share)........... (3,125) (3,125)
Repayment of ESOP loan.................... 95
Net income................................ 18,165 18,165
- ----------------------------------------------------------------------------------------
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 option
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
========= ========= ===========
See accompanying notes to consolidated financial statements
64
RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2002, 2001 AND 2000
2002 2001 2000
---------- ---------- ----------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income......................................................... $ (3,309) $ 9,829 $ 18,165
Adjustments to reconcile net (loss) income to net cash provided by operating
activities:
Depreciation, depletion and amortization............................... 11,161 11,038 9,872
Amortization of discount on senior notes and deferred finance costs.... 1,095 1,005 1,110
Provision for possible losses.......................................... 1,393 863 936
Minority interest in Atlas Pipeline Partners LP........................ 2,605 4,099 2,058
Loss (income) on discontinued operations............................... 11,040 4,254 (12,684)
Deferred income taxes.................................................. (7,413) (885) 5,825
Accretion of discount.................................................. (3,212) (5,923) (5,802)
Collection of interest................................................. 5,243 1,207 5,697
Cumulative effect of change in accounting principle.................... 627 - -
Gain on asset dispositions............................................. (2,507) (1,738) (2,678)
Property impairments and abandonments.................................. 24 207 877
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable and other assets............ (4,961) 4,003 (6,347)
Decrease in accounts payable and other liabilities..................... (4,959) (8,688) (1,643)
---------- --------- ---------
Net cash provided by operating activities of continuing operations........ 6,827 19,271 15,386
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid in asset acquisitions....................................... - (7,875) -
Proceeds from sale of subsidiary.......................................... - - 126,276
Capital expenditures...................................................... (21,967) (14,210) (11,066)
Principal payments on notes receivable.................................... 24,499 29,120 73,259
Proceeds from sale of assets.............................................. 721 490 1,269
(Increase) in other assets................................................ (8,083) (10,150) (8,933)
Investments in real estate loans and ventures............................. (19,859) (25,395) (5,193)
Decrease in other liabilities............................................. (175) (213) (339)
---------- --------- ---------
Net cash(used in) provided by investing activities of
continuing operations.................................................. (24,864) (28,233) 175,273
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings................................................................ 173,753 135,021 104,292
Principal payments on borrowings.......................................... (168,619) (129,272) (192,569)
Net proceeds from Atlas Pipeline Partners L.P. public offering............ - - 15,251
Dividends paid to minority interest of Atlas Pipeline Partners L.P........ (3,623) (3,783) (1,921)
Dividends paid............................................................ (2,326) (2,364) (3,125)
Purchase of treasury stock................................................ (1,517) (57,801) (172)
Repayment of ESOP loan.................................................... 96 96 95
Increase in other assets.................................................. (1,258) (702) (67)
Proceeds from issuance of stock........................................... 17 420 858
---------- --------- ---------
Net cash used in financing activities of continuing operations............ (3,477) (58,385) (77,358)
---------- --------- ---------
Net cash used in discontinued operations.................................. (1,398) (1,112) (28,698)
---------- --------- ---------
(Decrease) increase in cash and cash equivalents.......................... (22,912) (68,459) 84,603
Cash and cash equivalents at beginning of year............................ 48,648 117,107 32,504
---------- --------- ---------
Cash and cash equivalents at end of year.................................. $ 25,736 $ 48,648 $ 117,107
========== ========= =========
See accompanying notes to consolidated financial statements
65
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - NATURE OF OPERATIONS
Resource America, Inc. (the "Company"), a proprietary 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 and financial services sectors. Our financial services
sector did not constitute a material portion of our business at September 30,
2002 or for the three years then ended. In energy, the Company drills for and
sells natural gas and, to a significantly lesser extent, oil in the Appalachin
Basin. Through Atlas Pipeline Partners, L.P. ("Atlas Pipeline"), a majority
owned subsidiary partnership, 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
drilling 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
whose underlying properties are located in the mid atlantic region of the United
States. These loans were, at the time of acquisition, typically troubled loans
purchased at a discount both to their outstanding loan balances and to the
appraised value of their underlying properties. The loans are generally secured
by junior liens on the underlying property. In some instances, the Company's
loans are secured by devices other than a lien on the underlying properties. The
borrowers on the Company's loans typically have entered into agreements
requiring them to pay all of the net cash flow, as defined in the agreements,
from the underlying property to the Company and imposing management controls,
including appointment of Brandywine Construction and Management, Inc., a real
estate manager affiliated with the Company, as property manager or supervisor.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Reclassifications
Certain reclassifications have been made to the fiscal 2001 and fiscal
2000 consolidated financial statements to conform with the fiscal 2002
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. The Company also owns individual interests in the assets, and is
separately liable for its share of liabilities of oil and gas partnerships in
which it has an ownership interest. 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 oil and gas partnerships in which the Company has
an interest. All material intercompany transactions have been eliminated.
Use of Estimates
Preparation of the 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 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 (see "Recently Issued Financial Accounting Standards" in Note 2 to these
consolidated financial statements).
66
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Stock-Based Compensation
The Company accounts for its stock option plans in accordance with the
provisions of Accounting Principles Board ("APB") Opinion No. 25, Accounting for
Stock Issued to Employees, 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," and provides pro forma net income
(loss) and pro forma earnings (loss) per share disclosures for employee stock
option grants made as if the fair-value based method defined in SFAS No. 123 had
been applied.
Comprehensive Income
Comprehensive income includes net income 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, are
referred to as "other comprehensive income" and for the Company include changes
in the fair value of marketable securities and unrealized hedging gains and
losses.
Operating Segments
SFAS 131, "Disclosures about Segments of an Enterprise and Related
Information," requires that a public business enterprise report financial and
descriptive information about its reportable operating segments. Operating
segments are components of an enterprise about which separate financial
information is available that is evaluated regularly by the Company's chief
operating decision makers in deciding how to allocate resources and in assessing
performance.
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. 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.
The Company assesses unproved and proved properties periodically to
determine whether there has been a decline in value and, if such decline is
indicated a loss is recognized. The Company compares the carrying value of its
proved developed gas and oil producing properties to the estimated future cash
flow, net of applicable income taxes, 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,
2002.
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 both September 30, 2002 and 2001, the
Company's estimate of equipment salvage values was greater than or equal to the
estimated costs of future dismantlement, restoration, reclamation, and
abandonment.
67
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
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 gas and oil reserves.
The Company computes depreciation of 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.
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.
In fiscal 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." Accordingly, natural gas futures
and option contracts are recorded at fair value in the Company's consolidated
balance sheets.
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.
The following table provides information on other financial
instruments:
Carrying Estimated
Amount Fair Value
-------- ----------
(in thousands)
Energy non-recourse debt..................................................... $ 49,345 $ 49,345
Real estate finance debt..................................................... 33,214 33,214
Senior debt.................................................................. 65,336 67,623
Other debt................................................................... 7,615 7,615
------------- ------------
$ 155,510 $ 157,797
============= ============
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, 2002, the Company
had $26.3 million in deposits at various banks, of which $24.4 million is over
the insurance limit of the Federal Deposit Insurance Corporation. No losses have
been experienced on such investments.
A substantial portion of the Company's real estate loan portfolio and
investment in ventures is secured by properties located in the Washington, D.C.,
Philadelphia, PA and Baltimore, MD metropolitan areas. A decrease in real estate
values for the properties underlying these loans could have an adverse affect on
the value of the portfolio.
68
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Revenue Recognition
Energy Operations
The Company conducts certain energy activities through, and a portion
of its revenues are attributable to, sponsored limited partnerships
("Partnerships"). These Partnerships raise money from investors to drill gas and
oil wells. The Company serves as general partner of the Partnerships and assumes
customary rights and obligations for the Partnerships. 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 also
contracts to drill the gas and oil wells owned by the Partnerships. The income
from a drilling contract relating to a well is recorded upon substantial
completion of the well for turnkey contracts and by percentage of completion for
cost-plus contracts.
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 and property appraisals, which include amounts realizable
from the underlying properties, on a regular basis. Changes to projected cash
flows reduce or increase the amounts accreted into interest income over the
remaining life of the loan.
The Company recognizes gains on the sale of a senior lien interest in a
real estate loan based on an allocation of the Company's cost basis between the
portion of the loan sold and the portion retained based upon the fair value of
those respective portions on the date of sale. Gains 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 cost of the loan financed. The
Company credits any gain recognized on a sale of a senior lien interest or a
refinancing to income at the time of such sale or refinancing.
69
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Cash Flow Statements
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,
----------------------------------------
2002 2001 2000
----------- ---------- ----------
(in thousands)
Interest.................................................................. $ 11,683 $ 13,976 $ 17,652
Income taxes paid (refunded).............................................. $ 3,243 $ 13,393 $ (787)
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 loan....................... $ - $ 460 $ -
Tax benefit from employee stock option exercise........................... $ 244 $ - $ -
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 $ -
========== ========== ==========
Disposal of business:
Other assets received upon disposal of subsidiary..................... $ - $ - $ 25,969
========== ========== ==========
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.
70
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 by
the weighted average number of shares of common stock outstanding during the
period. Earnings (loss) per share - diluted are 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 and warrant 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
and warrants.
The components of basic and diluted earnings (loss) per share for each
year were as follows:
Years Ended September 30,
----------------------------------------
2002 2001 2000
---------- ---------- ----------
(in thousands)
Income (loss) from continuing operations.................................. $ 8,358 $ 14,083 $ 5,481
(Loss) income from discontinued operations................................ (11,040) (4,254) 12,684
Cumulative effect of a change in accounting principle..................... (627) - -
---------- ---------- ----------
Net (loss) income..................................................... $ (3,309) $ 9,829 $ 18,165
========== ========== ==========
Basic average shares of common stock outstanding.......................... 17,446 17,962 23,413
Dilutive effect of stock option and award plans........................... 359 474 415
---------- ---------- ----------
Dilutive average shares of common stock................................... 17,805 18,436 23,828
========== ========== ==========
Recently Issued Financial Accounting Standards
In June 2001, SFAS No. 143, "Accounting for Asset Retirement
Obligations" was issued. SFAS 143 establishes requirements for accounting for
removal costs associated with asset retirements. SFAS 143 is effective for
fiscal years beginning after June 15, 2002 and will require the Company to
record a liability for its retirement obligations with the related transition
adjustment reported as a cumulative effect of a change in accounting principle.
The Company is currently assessing the impact of this standard on its
consolidated financial statements.
In August 2001, SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Live Assets" was issued. SFAS 144 requires that one accounting
model be used for long-lived assets to be disposed of by sale, whether
previously held and used or newly acquired, and broadens the definition of what
constitutes discontinued operations to include more disposal transactions. Under
SFAS 144, assets held for sale that are a component of an entity are included in
discontinued operations and cash flows will be eliminated from the ongoing
operations if the entity does not have any significant continuing involvement in
the operations prospectively. The adoption of SFAS 144 resulted in the
classification of the Company's interest in its partially-owned energy
technology subsidiary, Optiron Corporation ("Optiron"), as a discontinued
operation (See Note 12).
In May 2002, SFAS No. 145, "Rescission of FASB Statements No. 4, 44,
and 64, Amendment of FASB Statement No. 13, and Technical Corrections" was
issued. SFAS 145, which is effective for financial statements issued on or after
May 15, 2002, rescinds the automatic treatment of gains and losses from
extinguishments of debt as extraordinary unless they meet the criteria for
extraordinary items as outlined in Accounting Principles Board Opinion No. 30,
"Reporting the Results of Operations, Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions." SFAS 145 also requires sale-leaseback accounting for
certain lease modifications that have economic effects similar to a
sale-leaseback transaction and makes various corrections to existing
pronouncements. The adoption of SFAS 145 did not have a material effect on the
Company's consolidated financial position or results of operations.
71
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Recently Issued Financial Accounting Standards - (Continued)
In June 2002, the FASB reached a consensus on certain issues raised in
Emerging Issues Task Force ("EITF") Issue No. 02-3. The consensus requires
mark-to-market gains and losses on energy trading contracts to be shown net in
the income statement whether or not these contracts are settled physically as
well as disclosures of gross transaction volumes for contracts that are
physically settled. This provision in EITF Issue 02-3 is effective for financial
statements ending after July 15, 2002, and comparative financial statements will
be reclassified to conform to the new presentation. Additional disclosures such
as types of contracts accounted for as energy trading contracts, reconciliation
of beginning and ending fair values and descriptions of methods and assumptions
used to estimate fair value are also required. The adoption of EITF No. 02-3 did
not have a material effect on the Company's consolidated financial position or
results of operations.
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 Company has not yet adopted
SFAS 146 nor determined the effect of the adoption of SFAS 146 on its
consolidated financial position or results of operations.
NOTE 3 - OTHER ASSETS AND GOODWILL - CHANGE IN ACCOUNTING PRINCIPLE
Other Assets
Other assets consist of intangible assets relating primarily to
partnership management and operating contracts acquired through acquisitions
recorded at fair value on their acquisition dates, investments and deferred
financing costs. The Company amortizes contracts acquired on a declining balance
method, over their respective estimated lives, ranging from five to 30 years.
The Company amortizes deferred financing costs over the terms of the related
loans (two to seven years). The Company amortizes other costs over varying
periods of up to five years.
Years Ended September 30,
-------------------------
2002 2001
---- ----
(in thousands)
Contracts acquired (net of accumulated amortization of $5,038 $ 9,305 $ 16,851
and $4,592)...........................................................
Deferred financing costs, net of accumulative amortization of $3,742
and $2,674............................................................... 2,122 1,931
Investments............................................................... 12,917 8,555
Other..................................................................... 4,523 2,676
---------- ----------
$ 28,867 $ 30,013
========== ==========
72
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 3 - OTHER ASSETS AND GOODWILL - CHANGE IN ACCOUNTING PRINCIPLE -
(Continued)
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 Company has completed the
transitional impairment test required upon adoption of SFAS 142. The
transitional test, 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 income statement in the period in which the impairment
is indicated.
Changes in the carrying amount of goodwill for the year ended September
30, 2002 are as follows:
Year Ended
September 30, 2002
------------------
(in thousands)
Goodwill at September 30, 2001
(less accumulated amortization of $4,063)................................... $ 31,420
Additions to goodwill related to prior year asset acquisitions.................. 15
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 September 30, 2002
(net of accumulated amortization of $4,796)................................. $ 37,471
============
For the years ended September 30, 2001 and 2000, the Company's goodwill
amortization expense was approximately $1.4 million and $1.1 million,
respectively. Pro forma net income from continuing operations for the years
ended September 30, 2001 and 2000 would have been $15.1 million and $6.2
million, respectively, excluding goodwill amortization, net of taxes using the
Company's effective tax rate in fiscal 2001 and 2000 of 31% and 30%,
respectively. Pro forma basic income per share from continuing operations for
the years ended September 30, 2001 and 2000 would have been $.84 and $.27,
respectively. Pro forma diluted income per share from continuing operations for
the years ended September 30, 2001 and 2000 would have been $.82 and $.26,
respectively.
Optiron, which previously was accounted for by the equity method,
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 which correlates
to Optiron's first quarter, its 50% share of this cumulative effect adjustment
in the same manner.
73
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 4 - 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 24 of the Company's real estate loans and
investments in real estate loans and investments in real estate ventures. 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, Chief Executive
Officer and President, is the Chairman and a minority stockholder of BCMI,
holding approximately 8% of BCMI's 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 was comprised of $3.0 million in cash and a $1.0 million
non-recourse note from BCMI, which bears interest, at 8% per annum and is due
September 2006. The Bancorp. Inc. ("TBI") a related party financial institution
provided the first mortgage financing for this sale.
Relationship with RAIT Investment Trust ("RAIT"). Since its
organization by the Company in 1997, the Company has engaged in various
transactions with RAIT. RAIT is a real estate investment trust in which, as of
September 30, 2002, the Company owned approximately 8% of the common shares.
Betsy Z. Cohen ("B. Cohen"), Mr. E. Cohen's spouse, is the Chairman and Chief
Executive Officer of RAIT, and Jonathan Z. Cohen ("J. Cohen"), a son of E. and
B. Cohen and the Chief Operating Officer and a director of the Company, is the
Company's designee as Trustee on RAIT's Board of Trustees. Mr. J. Cohen also
serves as RAIT's Secretary. Scott F. Schaeffer ("Schaeffer"), a former Vice
Chairman and a former officer and director of the Company, is RAIT's President
and Chief Operating Officer.
Since October 1, 1999, the Company and RAIT 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 the president 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 a 25%
interest in a venture. The venture purchased for $18.9 million,
properties adjacent to the office building and garage in which the
Company's executive offices are located and in which the Company owns
a 50% interest.
o In June 2001, the Company sold a $1.6 million first mortgage loan
having a book value of $1.1 million, resulting in a gain of $459,000.
The loan was sold to an unrelated individual who obtained a mortgage
from RAIT to purchase this loan.
o In March 2001, the Company sold a mortgage loan having a book value
of $19.9 million 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 has 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.
o In June 2000, in connection with the refinancing of a loan in which
RAIT held a $4.9 million participation interest, the Company paid to
RAIT a $300,000 termination fee.
o In May 2000, the Company sold 100% of the common stock in a
wholly-owned subsidiary to RAIT for $1.9 million, recognizing a gain
of $273,000.
o In December 1999, the Company sold 100% of the common stock in a
wholly owned subsidiary to RAIT for $9.9 million, recognizing a gain
of $983,000. The subsidiary held a subordinate interest in a loan
which was secured by a retail property located in Centreville, VA.
74
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
September 30, 2002
NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (Continued)
Relationship with TBI. In 1999, the Company acquired 9.7% of the
outstanding shares of TBI for approximately $1.8 million. In 2001, the Company
acquired 70,400 shares of TBI's convertable preferred stock (9.7%) for
approximately $704,000 pursuant to a rights offering to TBI's stockholders. As
of September 30, 2002, the Company had $5.6 million on deposit at TBI. B. Cohen
is the Chief Executive Officer of TBI, and D. Gideon Cohen ("D. Cohen"), a son
of E. and B. Cohen, is the Chairman of TBI. D. Cohen is a former director,
President and Chief Operating Officer of the Company.
Relationship with Ledgewood. Until April 1996, E. Cohen was of counsel
to Ledgewood Law Firm ("Ledgewood"). The Company paid Ledgewood $839,000,
$975,000 and, $1.6 million during fiscal 2002, 2001 and 2000, 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.
Relationship with Retirement Trusts. Pursuant to E. Cohen's employment
contract, upon his retirement, he 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 common
stock of TBI. The 2000 Trust, holds 38,571 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. The loan is secured by the partnership
interests held by the limited partnership, which beneficially owns two
residential apartment buildings. 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 $1.0 million at September 30,
2002. The fair value of the 2000 Trust is approximately $3.6 million at
September 30, 2002 and is included in Other Assets on the Company's Consolidated
Balance Sheets.
In connection with E. Cohen's SERP, the Company entered into a
split-dollar insurance arrangement under which it pays a portion of the premiums
under a life insurance policy with respect to E. Cohen, with reimbursement of
such premiums due upon the occurrence of specified events, including E. Cohen's
death. Under the recently enacted Sarbanes-Oxley Act of 2002, the Company's
future payment of premiums under this arrangement may be deemed to be a
prohibited loan to E. Cohen. Since the next premium payment under this
arrangement is not due until April 2003, the Company has deferred any decision
relating to this arrangement until the application of the Sarbanes-Oxley Act has
been clarified. The Company cannot predict the effect, if any, that cancellation
of the arrangement might entail.
75
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (Continued)
Relationships with Cohen Brothers & Company. During fiscal 2002 and
2001, the Company purchased 125,095 and 67,500 shares of its common stock at a
cost of $1.1 million and $737,000, respectively, from Cohen Brothers & Company.
In 2002, the Company repurchased $1.5 million principal amount of its senior
notes at a cost of $1.6 million. Cohen Brothers acted as a principal in the
sales to the Company. D. Cohen and J. Cohen are the principal owners of the
corporate parent of Cohen Brothers & Company.
Relationships with 9 Henmar. The Company owns a 50% interest in Trapeza
Funding, LLC, and associated entities ("Trapeza") which completed a $330.0
million pooled trust preferred collateralized debt offering ("CDO") in November
2002. The boards of managers of both the governing partnership entity and the
collateral manager entity for Trapeza are composed of four members, of whom
J. Cohen and D. Cohen are the Company appointees to the Board.
Trapeza was 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 it receives through its interest in the general partner of the limited
partnership and the collateral manager of the CDO issuer. In addition, the
Company has reimbursed 9 Henmar $449,000 for fees and expenses, including
overhead, incurred by it in connection with structuring the venture and the
Company's participation in it, developing the pool of trust preferred
securities, consulting with the underwriters and rating agencies and providing
other consulting, managerial and sales services. Subsequent to September 30,
2002, the Company reimbursed $415,000 to 9 Henmar. Through November 2002,
$565,000 of such expenses has been reimbursed to the Company by the CDO issuer.
Relationships with Certain Borrowers. The Company has from time to time
purchased loans in which affiliates of the Company are affiliates of the
borrowers.
In 2000, the property securing a loan held by the Company with a book
value of $3.3 million at September 30, 2002, was purchased by a limited
partnership of whose general partner, Mr. Schaeffer is the president. Messrs.
Schaeffer, Kauffman, E. Cohen and D. Cohen are equal limited partners of the
sole limited partner of the borrower.
At 1998, the Company acquired a defaulted loan in the original
principal amount of $91.0 million. At September 30, 2002, the Company's
receivable was $110.4 million and the book value of the loan was $38.7 million.
In September 2000, in connection with a refinancing and to protect the Company's
interest, a newly formed limited liability company assumed equity title of the
property. Messrs. Schaeffer, Kauffman, E. Cohen and D. Cohen are limited
partners (24.75% each) in an entity which owns approximately 30% of the
borrower. In addition, Mr. Schaeffer has a controlling administrative role with
the borrower.
In 1998, the Company acquired a loan under a plan of reorganization in
bankruptcy. The loan had a book value of $36.1 million at September 30, 2002. An
order of the bankruptcy court required that legal title to the property
underlying the loan be transferred on or before June 30, 1998. In order to
comply with that order, to maintain control of the property and to protect the
Company's interest, Evening Star Associates took title to the property in June
1998. A subsidiary of the Company serves as general partner of Evening Star
Associates and holds a 1% interest; Messrs. Schaeffer, Kauffman, E. Cohen and D.
Cohen purchased a 94% limited partnership interest in Evening Star Associates
for $200,000.
The Company acquired a loan in 1996. In 2002, the beneficial ownership
of the entity holding the interest in the property securing one of the Company's
loans was transferred to D. Cohen. At September 30, 2002, the Company's
receivable was $8.5 million and the book value of the loan was $2.3 million. The
entity holding the interest is entitled to receive 12.5% of any cash flow
received by the Company from the loan.
In 1997, the Company acquired a loan with a face amount of $2.3 million
at a cost of $1.6 million. The loan had a book value of $980,000 at September
30, 2002. The loan is secured by a property owned by a partnership in which
Messrs. Kauffman and E. Cohen and B. Cohen are limited partners (with a 75%
beneficial interest). Ledgewood and BCMI were tenants at such property as of
September 30, 2002.
In 1994, the Company acquired a loan in the original principal amount
of $3.0 million. At September 30, 2002, the Company's receivable was $2.6
million and the book value of the loan was $130,000. The loan is secured by a
property owned by a partnership in which E. Cohen and B. Cohen are limited
partners, with a 40%, beneficial interest.
76
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (Continued)
Relationships with Certain Lienholders. The Company holds 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 2001, the Company sold 100% of the common stock in a wholly-owned
subsidiary that owned subordinate interests in two loans to Messrs. Schaeffer,
Kauffman, D. Cohen and J. Cohen for $2.2 million, recognizing a gain of $7,300.
NOTE 5 - INVESTMENTS IN REAL ESTATE LOANS AND VENTURES
In acquiring real estate loans, the Company focused primarily on the
purchase of income producing loans at a discount from both the face value of
such loans and the appraised value of the properties underlying the 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 $3.2 million, $5.9 million
and $5.8 million during the years ended September 30, 2002, 2001, and 2000,
respectively. As the Company sells senior lien interests or receives funds from
refinancings of its loans, 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.
At September 30, 2002 and 2001, the Company held real estate loans
having aggregate face values of $610.0 million and $617.8 million, respectively.
Amounts receivable, net of senior lien interests and deferred costs,
were $349.3 million and $337.9 million at September 30, 2002 and 2001,
respectively. The following is a summary of the changes in the carrying value of
the Company's investments in real estate loans and ventures for the years ended
September 30, 2002 and 2001.
September 30,
-------------------------
2002 2001
---------- ----------
(in thousands)
Loan balance, beginning of period................................. $ 192,263 $ 185,940
New loans......................................................... - 1,010
Addition to existing loans........................................ 17,185 24,086
Loan write-down................................................... (559) (84)
Accretion of discount (net of collection of interest)............. 3,212 5,923
Collections of principal.......................................... - (1,623)
Cost of loans sold................................................ (24,559) (22,989)
---------- ----------
Loan balance, end of period....................................... 187,542 192,263
Ventures.......................................................... 18,361 16,666
Allowance for possible losses..................................... (3,480) (2,529)
---------- ----------
Balance, loans and ventures, end of period........................ $ 202,423 $ 206,400
========== ==========
77
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 5 - INVESTMENTS IN REAL ESTATE LOANS AND VENTURES - (Continued)
The following is a summary of activity in the Company's allowance for
possible losses related to real estate loans and ventures for the years ended
September 30, 2002 and 2001:
September 30,
------------------------
2002 2001
--------- ----------
(in thousands)
Balance, beginning of year........................................ $ 2,529 $ 2,013
Provision for possible losses..................................... 1,510 600
Write-down........................................................ (559) (84)
---------- ----------
Balance, end of year.............................................. $ 3,480 $ 2,529
========== ==========
NOTE 6 - DEBT
Total debt consists of the following:
September 30,
-------------------------
2002 2001
---------- ----------
(in thousands)
Senior debt....................................................... $ 65,336 $ 66,826
Non-recourse debt:
Energy:
Revolving and term bank loans................................ 49,345 43,284
Real estate finance:
Revolving credit facilities.................................. 18,000 18,000
Other........................................................ 875 875
---------- ----------
Total non-recourse debt.................................... 68,220 62,159
Other debt........................................................ 21,954 21,146
---------- ----------
155,510 150,131
Less current maturities........................................... 4,320 8,560
---------- ----------
$ 151,190 $ 141,571
========== ==========
Following is a description of borrowing arrangements in place at
September 30, 2002 and 2001.
78
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 6 - DEBT - (Continued)
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 an initial borrowing base of
$45.0 million which may be increased 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 the Atlas America's wells and the projected fees and revenues from operation
of the wells and the administration of 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 credit facility contains
financial covenants, including covenants requiring the Company and Atlas America
to maintain specified financial ratios, and imposes the following limits: (a)
the amount of debt that can be incurred cannot exceed specified levels without
the banks' consent; and (b) the energy affiliates may not sell, lease or
transfer property without the banks' consent. This credit facility was used to
pay off the previous energy revolving credit facility at PNC Bank ("PNC"). At
September 30, 2002, $45.0 million was outstanding under this facility, including
$43.7 million in borrowings and $1.3 million under letters of credit at interest
rates ranging from 3.54% to 5.0%.
Atlas Pipeline has a $10.0 million revolving credit facility at PNC. 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 October 2003 and bears interest
at one of two rates, elected at the Partnership'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) PNC 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 leverage ratio from between 150 to 200 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 (i), above. The interest rate
on outstanding borrowings was 3.27% at September 30, 2002. 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
$14.0 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. As of
September 30, 2002 and 2001, $5.6 million and $2.1 million, respectively, was
outstanding under this facility.
Real Estate Finance-Revolving Credit Facilities. 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, 2002, $6.4
million was outstanding on this note. The credit facility bears interest at the
prime rate reported in The Wall Street Journal minus one percent (3.75% at
September 30, 2002) 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 April 1,
2004.
The Company established a $18.0 million revolving line of credit with
Sovereign Bank. Interest is payable monthly at The Wall Street Journal prime
rate (4.75% at September 30, 2002) and principal is due upon expiration in July
2004. 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, 2002 and 2001, $18.0 million had
been advanced under this line.
79
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 6 - DEBT - (Continued)
The Company established a $10.0 million term loan with The Marshall
Group (formerly Miller and Schroeder Investment Corp). Through October 31, 2001,
the loan bore interest at 10.26%. Commencing November 1, 2001, the loan bears
interest at the three month LIBOR rate (2.1% at September 30, 2002) plus 350
basis points, 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, 2002 and 2001, $7.9 million and $9.3 million, respectively, had
been drawn under this loan.
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, 2002, the Company was
in compliance with such provisions. At September 30, 2002 and 2001, $65.3
million and $66.8 million, respectively, of the 12% Notes were outstanding.
Financial Services Debt. The Company's leasing subsidiary has a $10.0
million warehouse line of credit with National City Bank. The Company is the
guarantor of that facility, which is secured by a pledge of the subsidiary's
assets and by the equipment leases and proceeds thereof financed by the
facility, and terminates in June 2003. Loans under the facility bear interest,
at the Company's election, at either the National City Bank prime rate plus 1.0%
or adjusted LIBOR plus 3.0%, with the LIBOR adjustment being similar to that in
the Wachovia Bank facility. The facility requires the subsidiary to maintain a
specified net worth and specified interest coverage and debt to net worth
ratios. The facility limits dividends the subsidiary may pay, mergers, sales of
assets by the subsidiary and the terms of equipment leases that may be financed
under the facility. At September 30, 2002, $2.4 million had been drawn under the
facility at an average rate of 4.81%.
Other Debt. Other debt includes an amount outstanding under a $5.0
million revolving line of credit with Sovereign Bank, which expires July 2004.
Interest accrues at The Wall Street Journal prime rate (4.75% at September 30,
2002) 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 500,000 common shares of RAIT held by the Company. Credit
availability, which was $5.0 million at September 30, 2002, 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, 2002 and 2001, $5.0 million had
been advanced under this line.
The Company maintains a line of credit with Commerce Bank for $5.0
million, none of which has been drawn. The facility is secured by a pledge of
520,000 RAIT common shares. Credit availability is 50% of the value of those
shares, and was $5.0 million at September 30, 2002. Loans bear interest, at the
Company's election, at either the prime rate reported in The Wall Street Journal
or 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 2004, 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.
Annual debt principal payments over the next five fiscal years ending
September 30 are as follows: (in thousands):
2003.......................... $ 4,320
2004.......................... $ 103,078
2005.......................... $ 45,667
2006.......................... $ 2,041
2007.......................... $ 404
80
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 7 - INCOME TAXES
The following table details the components of the Company's income tax
expense from continuing operations for the fiscal years 2002, 2001 and 2000.
2002 2001 2000
---- ---- ----
(in thousands)
Provision (benefit) for income taxes:
Current:
Federal.............................................................. $ 6,365 $ 6,023 $ -
State................................................................ (619) 158 116
Deferred............................................................... (2,332) 146 2,285
---------- ---------- ----------
$ 3,414 $ 6,327 $ 2,401
========== ========== ==========
For fiscal 2000, there is no current federal tax provision for
continuing operations because of the utilization of the credits and depletion
allowance noted in the table below.
A reconciliation between the statutory federal income tax rate and the
Company's effective income tax rate is as follows:
Years Ended September 30,
-----------------------------------
2002 2001 2000
---- ---- ----
Statutory tax rate........................................................ 35% 35% 35%
Statutory depletion....................................................... (4) (3) (3)
Non-conventional fuel and low income housing credits...................... (3) (3) (12)
Excessive employee remuneration........................................... - 2 2
Goodwill.................................................................. - 1 10
Tax-exempt interest....................................................... (2) (2) (8)
State income tax.......................................................... 3 1 6
-- -- --
29% 31% 30%
== == ==
81
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 7 - INCOME TAXES - (Continued)
The components of the net deferred tax liability are as follows:
September 30,
-------------------------
2002 2001
---------- ----------
(in thousands)
Deferred tax assets related to:
Tax credit carryforwards....................................... $ 28 $ 168
Interest receivable............................................ 688 1,153
Accrued expenses............................................... 7,335 1,977
Provision for possible losses.................................. 1,185 833
---------- ----------
$ 9,236 $ 4,131
========== ==========
Deferred tax liabilities related to:
Property and equipment basis differences....................... (17,447) (19,329)
Investments in real estate ventures............................ (2,491) (2,515)
Unrealized gain on investments................................. (2,899) (854)
ESOP benefits.................................................. (132) (115)
---------- ----------
(22,969) (22,813)
---------- ----------
Net deferred tax liability................................... $ (13,733) $ (18,682)
========== ==========
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, 2002 and 2001.
82
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 8 - 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. The ESOP borrowed $1.2 million to purchase the initial
shares from the Company. The Company obtained a bank loan for the ESOP loan,
which is payable in semiannual installments through February 1, 2003. The ESOP
fully repaid the loan from the Company in August 1996. Both the Company's loan
obligation and the unearned benefits expense (a reduction in stockholders'
equity) will be reduced by the amount of any loan principal payments made by the
Company
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 and allocated to participating employees. As of
September 30, 2002, there were 236,365 shares allocated to participants, which
constituted substantially all of the shares available under the ESOP prior to
the 105,000 shares acquired on September 28, 1998. Compensation expense related
to the plan amounted to $182,200, $151,200 and $140,200 for the years ended
September 30, 2002, 2001 and 2000, 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 $335,200, $363,800, and $209,500 for the
Company's contributions for the years ended September 30, 2002, 2001 and 2000,
respectively.
Stock Options. The following table summarizes certain information about
the Company's equity compensation plans, in the aggregate, as of September 30,
2002.
- -------------------------------- ----------------------------- ------------------------------ ---------------------------------
(a) (b) (c)
- -------------------------------- ----------------------------- ------------------------------ ---------------------------------
Number of securities remaining
Number of securities to be Weighted-average exercise available for future issuance
issued upon exercise of 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 2,463,003 $ 9.50 149,220
approved by security
holders
- -------------------------------- ----------------------------- ------------------------------ ---------------------------------
Equity compensation plans 54,495 $ .11 -
not approved by security
holders
- -------------------------------- ----------------------------- ------------------------------ ---------------------------------
Total 2,517,498 $ 9.30 149,220
- -------------------------------- ----------------------------- ------------------------------ ---------------------------------
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 the 1989, 1997, 1999 and 2002 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. The 1989 plan authorizes 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").
83
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 8 - EMPLOYEE BENEFIT PLANS - (Continued)
In May 1997, stockholders approved the Resource America, Inc. 1997 Key
Employee Stock Option Plan. This plan, for which 825,000 shares were reserved,
provides for the issuance of ISO's, non-qualified stock options and SAR's. In
fiscal 2002, 2001 and 2000, options for 4,000, 55,000 and 93,885 shares were
issued under this plan, respectively. As of September 30, 2002, 90,000 shares,
previously granted to a former officer who continued to serve as a director of
the Company, are fully vested pursuant to a separation agreement. The director
resigned in October, 2002.
In March 1999, stockholders approved the Resource America, Inc. 1999
Key Employee Stock Option Plan. This plan, for which 1,000,000 shares were
reserved, provides for the issuance of ISO's, non-qualified stock options and
SAR's. In fiscal 2002, 2001 and 2000, options for 62,533, 371,000 and 106,115
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 2002, 664,967 shares were issued under this plan.
Transactions for the four employee stock option plans are summarized as
follows:
Years Ended September 30,
-------------------------------------------------------------------------------
2002 2001 2000
----------------------- ----------------------- ------------------------
Weighted Weighted Weighted
Average Average Average
Shares Exercise Price Shares Exercise Price Shares Exercise Price
----- -------------- ------ -------------- ------ ---------------
Outstanding - beginning of year.. 1,892,447 $ 10.27 1,642,967 $ 9.38 1,870,035 $ 9.77
Granted....................... 731,500 $ 8.24 424,000 $ 11.06 200,000 $ 7.49
Exercised..................... (222,682) $ 7.93 (155,947) $ 2.68 (144,568) $ 2.95
Forfeited..................... (25,761) $ 11.06 (18,573) $ 13.33 (282,500) $ 13.96
Outstanding - end of year..... 2,375,504 $ 9.86 1,892,447 $ 10.27 1,642,967 $ 9.38
Exercisable, at end of year...... 1,036,006 $ 10.36 743,213 $ 9.64 560,131 $ 7.10
Available for grant.............. 86,719 42,458 447,885
Weighted average fair value per
share of options granted
during the year............... $ 5.10 $ 8.73 $ 4.93
84
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 8 - EMPLOYEE BENEFIT PLANS - (Continued)
The following information applies to employee stock options outstanding
as of September 30, 2002:
Outstanding Exercisable
--------------------------------------------- --------------------------
Weighted
Average Weighted Weighted
Range of Contractual Average Average
Exercise Prices Shares Life (Years) Exercise Price Shares Exercise Price
- --------------- ------ ------------ -------------- ------ --------------
$ .92 - $ 2.73 105,338 2.58 $ 2.29 105,338 $ 2.29
$ 7.47 - $ 8.08 1,145,500 5.61 $ 7.82 463,001 $ 7.95
$ 9.19 - $ 9.34 240,000 9.73 $ 9.32 - $ -
$ 11.03 - $ 11.06 391,666 8.33 $ 11.06 97,917 $ 11.06
$ 15.50 493,000 6.64 $ 15.50 369,750 $ 15.50
--------- ---------
2,375,504 1,036,006
========= =========
In connection with the acquisition of Atlas, the Company issued options
for 120,213 shares at an exercise price of $.11 per share to certain employees
of Atlas who had held options of Atlas before its acquisition by the Company.
Options for 54,495 shares remain outstanding and are exercisable as of September
30, 2002.
As described in Note 2, the Company accounts for its stock-based awards
using the intrinsic value method in accordance with APB Opinion No. 25.
Accordingly, no compensation expense has been recognized in the financial
statements for these employee stock arrangements.
SFAS No. 123 requires the disclosure of pro forma net income and
earnings 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, 5 or 10 years
following vesting; stock volatility, 64%, 68% and 60% in 2002, 2001 and 2000,
respectively; risk free interest rate, 4.4%, 5.5% and 6.2% in 2002, 2001 and
2000, respectively,, dividends were based on the Company's historical rate. If
the computed fair values of the awards had been amortized to expense over the
vesting period of the awards, pro forma net income would have been $6.7 million
($.38 per share), $7.3 million ($.40 per share) and $16.4 million ($.69 per
share) in fiscal 2002, 2001 and 2000, respectively.
Other Plans. In addition to the various employee stock option plans, in
May 1997, 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 and all of which are issued and
outstanding as of September 30, 2002. The fair value of the grants (average
$14.75 per unit, $1.1 million in total) is being charged to operations over the
five-year vesting period. As of September 30, 2002, no further grants may be
made under this plan. 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 shares were reserved for
issuance. In fiscal 2002, 12,499 units were issued under this plan. The fair
value of the grants ($11.05 per unit, $138,114 in total) is being charged to
operations over the five-year vesting period. As of September 30, 2002, 62,501
units are available for issuance under this plan. Under these plans,
non-employee directors of the Company are awarded units representing the right
to receive one share of the Company common stock for each unit awarded. Units do
not vest until the fifth anniversary of their grant, except that 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.
85
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 9 - COMMITMENTS AND CONTINGENCIES
The Company leases office space and equipment under leases with varying
expiration dates through 2007. Rental expense was $2.1 million, $1.9 million and
$1.6 million for the years ended September 30, 2002, 2001 and 2000,
respectively. At September 30, 2002, future minimum rental commitments for the
next five fiscal years were as follows (in thousands):
2003........................... $ 1,517
2004........................... $ 1,073
2005........................... $ 988
2006........................... $ 765
2007........................... $ 492
The Company is party to employment agreements with certain executives
which provide for compensation and certain other benefits. The agreements also
provide for severance payments under certain circumstances.
The Company is the managing general partner of the Partnerships, and
has agreed to indemnify each investor partner from any liability which exceeds
such partner's share of partnership assets. Management believes that any such
liabilities that may occur will be covered by insurance and, if not covered by
insurance, will not result in a significant loss to the Company.
Subject to certain conditions, investor partners in certain
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 Partnership equal to at least 10% of their agreed subscriptions
determined on a cumulative basis, in accordance with the terms of the
partnership agreement.
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 2002,
2001 and 2000, operations were charged $1.1 million, $927,000 and $2.5 million,
respectively, with respect to these commitments.
The Company is a defendant, together with certain of our officers and
directors and its independent auditor, Grant Thornton LLP, in consolidated
actions that were instituted on October 14, 1998 in the U.S. District Court for
the Eastern District of Pennsylvania by stockholders, putatively on their own
behalf and as class actions on behalf of similarly situated stockholders, who
purchased shares of the Company's common stock between December 17, 1997 and
February 22, 1999. The consolidated amended class action complaint seeks damages
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. The Company has agreed
to settle this matter for a maximum of $7.0 million plus approximately $1.0
million in costs and expenses, of which $6.0 million will be paid by two of the
Company's directors' and officers' liability insurers. The Company agreed to the
settlement to avoid the potential of costly litigation, which would have
involved significant time of senior management. The Company will seek to obtain
the balance of $2.0 million through an action against a third insurer who has
not agreed to participate in the settlement. Plaintiffs have agreed to reduce by
50% the amount by which the $2.0 million exceeds the net recovery from the
insurer. The Company has charged operations $1.0 million in the fiscal year
ended September 30, 2002 in relation to this settlement, if the Company is
successful in receiving reimbursement from its third insurer future operations
will be benefited.
86
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 9 - COMMITMENTS AND CONTINGENCIES - (Continued)
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 are 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.
The Company is a defendant in 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 have been named as defendants. The plaintiffs' claims for breach of
contract and fraud are based on an alleged oral agreement to purchase one
million shares of plaintiffs' stock in TRM Corporation for $13.0 million.
Plaintiffs seek actual damages of at least $12.0 million, plus punitive damages
in an unspecified amount. The Company believes the complaint is without merit
and is defending itself vigorously.
Refer to Note 12 with regard to an expected settlement of claims
associated with the sale of Fidelity Leasing.
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 10 - HEDGING ACTIVITIES
The Company, through its energy subsidiaries, 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.
Effective October 1, 2000, the Company adopted SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (as amended by
SFAS 138). This statement establishes accounting and reporting standards for
derivative instruments and hedging activities. The statement requires that all
derivative financial statements are recognized in the financial statements as
either assets or liabilities measured as fair value. Changes in the fair value
of derivative financial instruments are recognized in income or other
comprehensive income, depending on their classification. Upon adoption of SFAS
133, the Company did not incur any transition adjustments to earnings.
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 fair value of hedged items. When 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 instruments and actual gas prices, the Company will discontinue
hedge accounting for the derivative and further changes in fair value for the
derivative will be recognized immediately into earnings. Any gains or losses
that were accumulated in other comprehensive income (loss) will be recognized in
earnings when the hedged transaction is recognized in earnings.
87
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 10 - HEDGING ACTIVITIES - (Continued)
At September 30, 2002, the Company had 267 open natural gas futures
contracts related to natural gas sales covering 747,600 dekatherm ("Dth") (net
to the Company) maturing through September 2003 at a combined average settlement
price of $3.58 per Dth. The fair value of the open natural gas futures
contracts, $2,995,100 at September 30, 2002, is based on quoted market prices.
As these contracts qualify and have been designated as cash flow hedges, any
gains or losses resulting from market price changes are deferred and recognized
as a component of sales revenues in the month the gas is sold. Gains or losses
on futures contracts are determined as the difference between the contract price
and a reference price, generally prices on NYMEX. The Company's net unrealized
loss related to open NYMEX contracts was approximately $316,600 at September 30,
2002 and its net unrealized gain was approximately $15,000 at September 30,
2001. The unrealized loss of $218,400 net of taxes of $98, 200, at September 30,
2002 has been recorded as a liability in the Company's 2002 Consolidated
Financial Statements and in Stockholders' Equity as a component of Other
Comprehensive Income (loss). The Company recognized a loss of $59,000, $599,000
and $832,000 on settled contracts covering natural gas production for the years
ended September 30, 2002, 2001 and 2000, respectively. As of September 30, 2002,
all of the deferred net losses on derivative instruments included in accumulated
other comprehensive income (loss) are expected to be reclassified to earnings
during the next twelve months. The Company recognized no gains or losses during
the fiscal year ended September 30, 2002 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 11 - ACQUISITIONS
In January 2001, the Company and its consolidated subsidiary, Atlas
Pipeline, acquired certain energy assets of Kingston Oil Corporation for $4.5
million of cash and 88,235 common units of Atlas Pipeline. In March 2001, the
Company and Atlas Pipeline acquired certain energy assets of American Refining
and Exploration Company for $2.0 million of cash and 32,924 common units of
Atlas Pipeline. Atlas Pipeline borrowed $1.4 million under its $10.0 million
revolving credit facility to fund its share of the cash payment. In August 2001,
the Company acquired certain energy assets of Castle Gas Company for $1.4
million. These acquisitions were accounted for under the purchase method of
accounting and, accordingly, the purchase prices were allocated to the assets
acquired based on their fair values at the dates of acquisition. The pro forma
effect of these acquisitions on prior period operations or current year
operations prior to the acquisition dates is not material.
In connection with the acquisition of Atlas in fiscal 1998, certain
indemnity obligations of the seller resulted in the cancellation in fiscal 2001
of 153,500 of the Company's previously issued shares held in escrow.
88
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 12 - DISCONTINUED OPERATIONS
In June 2002, the Company adopted a plan to dispose of Optiron. The
Company has reduced its 50% 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 which is 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.
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,
------------------------------------------
2002 2001 2000
---- ---- ----
(in thousands)
Loss from discontinued operations before income taxes.................. $ (553) $ (1,493) $ (1,132)
Income tax benefit .................................................... 193 463 396
----------- ----------- -----------
Loss from discontinued operations...................................... $ (360) $ (1,030) $ (736)
=========== =========== ===========
Loss on disposal of discontinued operations before income taxes........ $ (1,971) $ - $ -
Income tax benefit .................................................... 690 - -
----------- ----------- -----------
Loss on disposal of discontinued operations............................ $ (1,281) $ - $ -
=========== =========== ===========
In February 2000, the Company adopted a plan to sell FLI and
subsidiaries, its small ticket equipment leasing business. On August 1, 2000,
the Company sold its small ticket equipment leasing subsidiary, Fidelity
Leasing, 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
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 until March 31,
2004 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 three years ended September 30, 2002, 2001 and
2000. The Consolidated Financial Statements reflect the operations of FLI as
discontinued operations in accordance with Accounting Principles Board ("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").
89
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 12 - DISCONTINUED OPERATIONS - (Continued)
The successor in interest to the purchaser, has made a series of claims
totaling $19.0 million with respect to the Company's indemnification obligations
and representations. While the Company has disputed these claims, in the first
quarter of fiscal 2003 the Company entered into substantive settlement
negotiations with the successor. In December 2002, the Company agreed in
principle to the monetary terms of a non-executed "Term Sheet for Proposed
Settlement Agreement" with the successor. The ultimate settlement is subject to
negotiation of a definitive settlement agreement, which the Company and the
successor will seek to complete on or before December 31, 2002. The Company
believes that the terms of any ultimate settlement will not be materially
different from the most recent proposed agreement as described below.
Under the proposed settlement, the Company and the successor would be
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 would (i) release to the successor the $10.0 million in escrow
previously referred to; (ii) pay the successor $6.0 million; (iii) guarantee
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) deliver 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. The liability
of the Company relating to the cash payment and the notes is recorded in the
Company's consolidated financial statements as liabilities on assets held for
disposal. The Company recorded a loss from discontinued operations, net of
taxes, of $9.4 million in connection with the proposed settlement.
Summarized operating results of the discontinued FLI operations are as
follows:
Years Ended September 30,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
Net revenues........................................................... $ - $ - $ 29,552
=========== =========== ===========
Income from discontinued operations before
income taxes........................................................ $ - $ - $ 775
Provision for income taxes............................................. - - (299)
----------- ----------- -----------
Income from discontinued operations.................................... $ - $ - $ 476
=========== =========== ===========
(Loss) gain on disposal before income taxes............................ $ (14,460) $ (5,200) $ 24,259
Income tax benefit (provision)......................................... 5,061 1,976 (9,352)
----------- ----------- -----------
(Loss) gain on disposal of discontinued operations..................... $ (9,399) $ (3,224) $14,907
=========== =========== ===========
On September 28, 1999 the Company adopted a plan to discontinue
LowCostLoan.com, Inc. ("LCL") (formerly Fidelity Mortgage Funding, Inc. , its
residential mortgage lending business. The business was disposed of in November
2000. Accordingly, LCL is reported as a discontinued operation for the year
ended September 30, 2000. The Consolidated Financial Statements reflect the
operations of LCL as discontinued operations in accordance with APB No. 30,
Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary,
Unusual and Infrequently Occurring Events and Transactions.
90
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 12 - DISCONTINUED OPERATIONS - (Continued)
Summarized operating results of the discontinued LCL operations are as
follows:
Years Ended September 30,
------------------------------------------
2002 2001 2000
---------- ----------- -----------
(in thousands)
Loss on disposal before income taxes................................... $ - $ - $ (2,952)
Income tax benefit..................................................... - - 989
----------- ----------- -----------
Loss on disposal of discontinued operations............................ $ - $ - $ (1,963)
=========== =========== ===========
Summarized results of the discontinued Optiron, FLI and LCL operations
are:
Loss from discontinued operations...................................... $ (360) $ (1,030) $ (260)
(Loss) gain on disposal of discontinued operations..................... (10,680) (3,224) 12,944
=========== =========== ===========
$ (11,040) $ (4,254) $ 12,684
=========== =========== ===========
NOTE 13 -TERMINATION CHARGE
As a result of the sale of the Company's equipment leasing operations
on August 1, 2000 and its reduced emphasis on real estate finance, two of the
Company's officers separated from the Company on September 13, 2000. One officer
was the Company's president and chief operating officer and the other was the
Company's vice-chairman as well as the president of the commercial real estate
finance business. Both officers were parties to employment agreements and were
terminated in accordance with the terms of those agreements. Accordingly,
continuing operations were charged $1.8 million and discontinued operations were
charged $2.3 million in the year ended September 30, 2000.
NOTE 14 - PUBLIC OFFERING OF UNITS BY PARTNERSHIP
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.
Because the Company owns more than 50% of Atlas Pipeline, the assets,
liabilities, revenues and costs and expenses of Atlas Pipeline are consolidated
with those of the Company, and the value represented by non-subordinated common
units are shown as a minority interest on the Company's consolidated balance
sheets.
Our subordinated units are a special class of limited partnership
interest in Atlas Pipeline under which our 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. Our general
partner interest also includes a right to receive incentive distributions if the
partnership meets or exceeds specified levels of distributions.
91
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 14 - PUBLIC OFFERING OF UNITS BY PARTNERSHIP
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.
o Require it to support a minimum quarterly distribution by Atlas
Pipeline to holders of non-subordinated units of $.42 per unit (an
aggregate of $1.68 per fiscal year) until February 2003. The Company
has established a letter of credit administered by PNC Bank to
support its obligation. At September 30, 2002 the current face amount
of the letter of credit is $630,000. The required face amount of the
letter of credit is reduced by $630,000 per quarter.
During fiscal 2002 and 2001, the fee paid to Atlas Pipeline was
calculated based on the 16% rate. Through September 30, 2002, the Company has
not been required to provide any construction financing. The Company provided
$443,000 in distribution support due to the lag in cash receipts for the initial
quarter of Atlas Pipeline's operations. No distribution support has been
required for any subsequent quarter.
92
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 15 - CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE
Optiron, previously accounted for by the equity method, 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 has recorded, in its second fiscal quarter which correlates to
Optiron's first quarter, its 50% share of this cumulative effect adjustment in
the same manner.
NOTE 16 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS
The Company operates in two principal industry segments: energy and
real estate finance. Segment data for the years ended September 30, 2002, 2001
and 2000 are as follows:
Years Ended September 30,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
Revenues:
Energy.............................................................. $ 98,149 $ 94,942 $ 70,713
Real estate finance................................................. 16,582 16,899 18,649
Corporate........................................................... 6,269 6,601 11,460
----------- ----------- -----------
$ 121,000 $ 118,442 $ 100,822
=========== =========== ===========
Depreciation, depletion and amortization:
Energy.............................................................. $ 10,836 $ 10,784 $ 9,781
Real estate finance................................................. 244 200 195
Corporate........................................................... 81 54 (104)
----------- ----------- -----------
$ 11,161 $ 11,038 $ 9,872
=========== =========== ===========
Operating profit (loss):
Energy.............................................................. $ 13,322 $ 19,190 $ 8,145
Real estate finance................................................. 5,669 8,000 6,914
Corporate........................................................... (7,219) (6,780) (7,177)
----------- ----------- -----------
$ 11,772 $ 20,410 $ 7,882
=========== =========== ===========
Identifiable assets:
Energy.............................................................. $ 183,693 $ 172,189 $ 154,379
Real estate finance................................................. 204,327 207,682 202,335
Corporate........................................................... 79,478 86,593 151,117
----------- ----------- -----------
$ 467,498 $ 466,464 $ 507,831
=========== =========== ===========
Capital expenditures (excluding assets acquired in business acquisitions):
Energy.............................................................. $ 21,291 $ 14,051 $ 10,936
Real estate finance................................................. 353 159 130
Corporate........................................................... 323 - -
----------- ----------- -----------
$ 21,967 $ 14,210 $ 11,066
=========== =========== ===========
Operating profit (loss) represents total revenues less costs and
expenses attributable thereto, including interest and provision for possible
losses, and less depreciation, depletion and amortization, excluding general
corporate expenses. The information presented above does not eliminate
intercompany transactions of $237,000, $136,000 and $161,000 in the years ended
September 30, 2002, 2001 and 2000, respectively.
93
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 16 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS - (Continued)
The Company's natural gas is sold under contract to various purchasers.
For the years ended September 30, 2002 and 2001, gas sales to one purchaser
accounted for 13% and 14%, respectively, of our total revenues. During fiscal
2000, no purchaser accounted for 10% or more of our total revenues. In real
estate finance, no revenues from a single borrower exceeded 10% of total
revenues.
NOTE 17 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Results of operations for oil and gas producing activities:
Years Ended September 30,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
Revenues............................................................ $ 28,916 $ 36,681 $ 25,231
Production costs.................................................... (6,693) (6,185) (7,229)
Exploration expenses................................................ (1,571) (1,661) (1,110)
Depreciation, depletion, and amortization........................... (7,550) (6,148) (6,305)
Income taxes........................................................ (4,005) (7,223) (3,759)
----------- ----------- -----------
Results of operations producing activities.......................... $ 9,097 $ 15,464 $ 6,828
=========== =========== ===========
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:
Years Ended September 30,
-----------------------------------------
2002 2001 2000
---------- ----------- -----------
(in thousands)
Proved properties................................................... $ 124,388 $ 104,888 $ 84,307
Unproved properties................................................. 1,221 855 1,003
Pipelines, equipment and other interests............................ 29,513 24,660 19,493
----------- ----------- -----------
155,122 130,403 104,803
Accumulated depreciation, depletion, amortization
And valuation allowances.......................................... (41,991) (33,089) (26,966)
----------- ----------- -----------
Net capitalized costs........................................... $ 113,131 $ 97,314 $ 77,837
=========== =========== ===========
Costs Incurred in Oil and Gas Producing Activities. The costs incurred
by the Company in its oil and gas activities during fiscal years 2002, 2001 and
2000 are as follows:
Years Ended September 30,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
Property acquisition costs:
Unproved properties............................................... $ 9 $ 353 $ 168
Proved properties................................................. $ 3 $ 5,443 $ 1,017
Exploration costs................................................. $ 1,573 $ 1,662 $ 1,095
Development costs................................................. $ 17,646 $ 17,453 $ 9,422
The development costs above for the years ended September 30, 2002,
2001 and 2000 were substantially all incurred for the development of proved
undeveloped properties.
94
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 17 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued)
Oil and Gas Reserve Information (Unaudited). The estimates of the
Company's proved and unproved gas reserves are based upon evaluations verified
by Wright & Company, Inc., an independent petroleum engineering firm, as of
September 30, 2001 and 2000. 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 provision for price and cost escalation except by
contractual arrangements.
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 arrangement, 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 contracts, 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 which
effects have not been proved.
95
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 17 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued)
The standardized measure of discounted future net cash flows is
information provided for the financial statement user as a common base for
comparing oil and gas reserves of enterprises in the industry.
Gas Oil
----------- ----------
(Mcf) (Bbls)
----------- ----------
Balance September 30, 1999............................................. 108,172,010 1,684,991
Current additions................................................... 32,433,822 16,031
Sales of reserves in-place.......................................... (304,428) (14,200)
Purchase of reserves in-place....................................... 1,047,931 -
Transfers to limited partnerships................................... (25,677,232) -
Revisions........................................................... 3,910,595 275,806
Production.......................................................... (6,440,154) (195,974)
----------- ---------
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
=========== =========
Proved developed reserves at:
September 30, 2002.................................................. 83,995,712 1,846,281
September 30, 2001.................................................. 80,249,011 1,735,376
September 30, 2000.................................................. 74,332,754 1,766,654
96
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 17 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (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 year-end prices, adjusted only for
fixed and determinable increases in natural gas 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 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,
2002, 2001 and 2000 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.
Years Ended September 30,
------------------------------------------
2002 2001 2000
----------- ----------- -----------
(in thousands)
Future cash inflows................................................. $ 518,118 $ 485,781 $ 555,121
Future production costs............................................. (147,279) (126,979) (161,623)
Future development costs............................................ (55,644) (50,953) (46,828)
Future income tax expenses.......................................... (79,557) (76,584) (104,004)
----------- ----------- -----------
Future net cash flows............................................... 235,638 231,265 242,666
Less 10% annual discount for estimated
timing of cash flows............................................ (131,512) (132,553) (144,067)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows............................................. $ 104,126 $ 98,712 $ 98,599
=========== =========== ===========
The future cash flows estimated to be spent to develop proved
undeveloped properties in the years ended September 30, 2003 and 2004 are $28.1
million and $27.5 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.
Years Ended September 30,
-------------------------------------------
2002 2001 2000
----------- ----------- ------------
(in thousands)
Balance, beginning of year............................................. $ 98,712 $ 98,599 $ 58,775
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs............ (22,223) (30,496) (18,002)
Net changes in prices and production costs.......................... 249 (21,530) 41,173
Revisions of previous quantity estimates............................ 3,787 (4,184) 9,580
Development costs incurred.......................................... 4,107 4,011 7,789
Changes in future development costs................................. (149) (853) 138
Transfers to limited partnerships................................... (3,970) (4,177) (11,862)
Extensions, discoveries, and improved
recovery less related costs....................................... 12,057 20,716 23,333
Purchases of reserves in-place...................................... 340 7,984 1,509
Sales of reserves in-place, net of tax effect....................... (799) (204) (293)
Accretion of discount............................................... 12,726 14,078 7,522
Net changes in future income taxes.................................. 203 13,636 (23,757)
Other............................................................... (914) 1,132 2,694
----------- ----------- -----------
Balance, end of year................................................... $ 104,126 $ 98,712 $ 98,599
=========== =========== ===========
97
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 18 - QUARTERLY RESULTS (Unaudited)
Dec 31 March 31 June 30 September 30,
--------- ---------- ---------- -------------
(in thousands, except per share data)
Year ended September 30, 2002
Revenues.................................................. $ 33,782 $ 34,203 $ 24,634 $ 28,144
Costs and expenses........................................ 29,405 29,250 22,830 27,506
--------- --------- ---------- --------
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
========= ========= ========== ========
Year ended September 30, 2001
Revenues.................................................. $ 27,440 $ 34,766 $ 27,629 $ 28,471
Costs and expenses........................................ 21,782 27,586 23,956 24,572
--------- --------- ---------- --------
Income from continuing operations before taxes ........... 5,658 7,180 3,673 3,899
--------- --------- ---------- --------
Income from continuing operations before cumulative
effect of change in accounting principle ............ $ 3,648 $ 4,697 $ 2,386 $ 3,352
Net income (loss)......................................... $ 3,310 $ 4,411 $ 2,231 $ (123)
========= ========= ========== ========
Net income per common share - basic
Income from continuing operations before cumulative
effect of change in accounting principle ............ $ .19 $ .27 $ .14 $ .19
========= ========= ========== ========
Net income (loss) per common share - basic................ $ .17 $ .25 $ .13 $ (.01)
========= ========= ========== ========
Net income per common share - diluted
Income from continuing operations before cumulative
effect of change in accounting principle............. $ .18 $ .26 $ .13 $ .19
========= ========= ========== ========
Net income (loss) per common share - diluted........... $ .17 $ .25 $ .12 $ (.01)
========= ========= ========== ========
Certain adjustments have been made to previously reported amounts to
reflect discontinuation of certain operations. See Note 12.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
98
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS OF
THE REGISTRANT
The information required by this item will be set forth in our
definitive proxy statement with respect to our 2003 annual meeting of
stockholders, to be filed on or before January 28, 2003 ("2003 proxy
statement"), which is incorporated herein by this reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item will be set forth in our 2003
proxy statement, which is incorporated herein by this reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item will be set forth in our 2003
proxy statement, which is incorporated herein by this reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item will be set forth in our 2003
proxy statement, which is incorporated herein by this reference.
99
PART IV
ITEM 14. 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.
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:
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 IV - Mortgage Loans on Real Estate
100
RESOURCE AMERICA, INC. & SUBSIDIARIES
MORTGAGE LOANS ON REAL ESTATE
30-Sep-02
IN 000'S
PERIODIC
INTEREST FINAL MATURITY PAYMENT
DESCRIPTION RATE DATE TERMS
FIRST MORTGAGES
MtRoy Apartment bldg, Pittsburgh, PA Fixed interest rate of 14.5% 08/01/2021 (a)
Red Apartment bldg, PA Fixed interest rate of 14% 10/01/2002 (a)
Sher Office bldg, PA 85% of Prime 09/30/2014 (a)
Concord Condominium units, NC Fixed interest rate of 10% 03/23/2009 (a)
Gran Office bldg, PA Fixed interest rate of 10.6% 02/07/2001 (a)
Deer Apartment bldg, FL Fixed interest rate of 13% 06/01/2010 (a)
Head Office/Retail bldg 90% of prime plus 5% 07/01/2002 (a)
Sea Apartment bldg, NJ Fixed interest rate of 13.25% 09/01/2005 (a)
PRINCIPAL
CARRYING SUBJECT TO
PRIOR FACE AMOUNT AMOUNT OF DELINQUENT INTEREST
LIENS OF MORTGAGES MORTGAGES INTEREST INCOME
MtRoy - 4,500 6,057 - -
Red - 400 471 - 66
Sher - 6,000 4,173 315
Concord - 447 484 -
Gran - 5,400 1,909 - -
Deer - 4,100 3,346 - 320
Head - 3,400 3,899 - -
Sea - 11,615 12,291 - 1,465
RESTUBBED TABLE
PERIODIC
INTEREST FINAL MATURITY PAYMENT
DESCRIPTION RATE DATE TERMS
SECOND LIEN LOANS
StC Retail bldg Fixed interest at 10% 12/31/2014
Pas Industrial bldg, Pasadena, CA 2.75% over the average cost 5/1/2001 (a)
of funds to FSLIC-Insured
savings and loan institutions
1301 Office bldg, Washington, D.C. Fixed interest rate of 12% 11/30/1998 (a)
LM(83) Condominium units, NC Fixed interest rate of 10% 03/31/2002 (a)
Elk Retail bldg Fixed interest at 8.25% 12/31/2016 (a)
Ncal Retail bldg, Northridge, CA Fixed interest rate of 9% 12/01/2000 (a)
Wood Office bldg, Cherry Hill, NJ Fixed interest rate of 9.75% 02/07/2001 (a)
Crafts Apartment bldg, PA Prime + 1% 05/03/2029 (a)
Mill Apartment bldg, PA Fixed interest at 9.28% 11/01/2022 (a)
FW Hotel/Commercial Office, GA Fixed interest rate of 14% 12/31/2015 (a)
Axe Office bldg, PA Fixed interest rate of 12% 09/30/2003 (a)
Redick Hotel, NE Fixed interest rate of 14.5% 09/30/2002 (a)
Win Apartment bldg, CT Fixed interest rate of 15% 10/14/2014 (a)
Rich Retail bldg Fixed interest at 9% 02/01/2021 (a)
1521 Office bldg, PA Fixed interest rate of 9.0% 07/01/2002 (a)
Loewy Office bldg, NC Fixed interest rate of 11.5% 12/31/2011 (a)
Clem Apartment bldg, Ct Fixed interest rate of 7.5% 01/01/2009 (a)
ES Office bldg, Washington, D.C. Fixed interest rate of 15% 08/01/2008 (a)
AB Office bldg, MD Fixed interest rate of 10% 04/01/2011 (a)
Pensacola Apartment bldg, IL Fixed interest rate of 7.5% 09/30/2009 (a)
NP Office bldg, Washington, D.C. Fixed interest rate of 10.64% 01/15/2006 (a)
SS Apartment bldg, PA Fixed interest rate of 8% 09/28/2006 (a)
Sold loans
PRINCIPAL
CARRYING SUBJECT TO
PRIOR FACE AMOUNT AMOUNT OF DELINQUENT INTEREST
LIENS OF MORTGAGES MORTGAGES INTEREST INCOME
StC 1,796 1,776 1,044 - 73
Pas 2,273 3,000 130 - 136
1301 6,143 13,283 8,224 - 617
LM(83) 2,862 2,064 2,713 - 108
Elk 961 1,400 643 - 48
Ncal 1,969 2,271 1,136 - 120
Wood 2,285 4,800 2,321 - 139
Crafts 3,343 2,435 975 - 44
Mill 2,374 3,155 776 - 85
FW 875 5,800 8,426 - 867
Axe 2,022 3,116 2,539 - 328
Redick 2,400 6,005 4,517 - -
Win 8,978 2,973 1,384 - 145
Rich 1,571 3,961 1,161 - 51
1521 1,687 1,150 980 - -
Loewy 1,684 3,500 2,337 - -
Clem 13,655 6,750 7,289 - 546
ES 66,531 100,971 36,063 1,582
AB 58,416 31,000 38,656 1,420
Pensacola 14,988 24,083 9,572 601
NP 63,923 92,000 23,015 2,841
SS 1,010 1,010 75
======== ======== ======== ==== ========
260,736 352,365 187,541 - 11,992
1,126
260,736 352,365 187,541 - 13,118
(a) All net cash flows from the property
(b)Cost for Federal income tax purposes equals
RESOURCE AMERICA, INC. & SUBSIDIARIES
MORTGAGE LOANS ON REAL ESTATE
30-Sep-02
IN 000'S
PERIODIC
INTEREST FINAL MATURITY PAYMENT
DESCRIPTION RATE DATE TERMS
PENNSYLVANIA
MtRoy Apartment bldg, Pittsburgh, PA Fixed interest rate of 14.5% 08/01/2021 (a)
Gran Office bldg, PA Fixed interest rate of 10.6% 02/07/2001 (a)
Crafts Apartment bldg, PA Prime + 1% 05/03/2029 (a)
Mill Apartment bldg, PA Fixed interest at 9.28% 11/01/2022 (a)
Axe Office bldg, PA Fixed interest rate of 12% 09/30/2003 (a)
Head Office/Retail bldg, PA 90% of prime plus 5% 07/01/2002 (a)
1521 Office bldg, PA Fixed interest rate of 9.0% 07/01/2002 (a)
SS Apartment bldg, PA Fixed interest rate of 8.0% 09/28/2006 (a)
Red Apartment bldg, PA Fixed interest rate of 14% 10/01/2002 (a)
Sher Office bldg, PA 85% of Prime 09/30/2014 (a)
NEW JERSEY
Wood Office bldg, Cherry Hill, NJ Fixed interest rate of 9.75% 02/07/2001 (a)
Sea Apartment bldg, NJ Fixed interest rate of 13.25% 09/01/2005 (a)
WASHINGTON, DC
1301 Office bldg, Washington, D.C. Fixed interest rate of 12% 11/30/1998 (a)
ES Office bldg, Washington, D.C. Fixed interest rate of 15% 08/01/2008 (a)
NP Office bldg, Washington, D.C. Fixed interest rate of 10.64% 01/15/2006 (a)
CALIFORNIA
Pas Industrial bldg, Pasadena, CA 2.75% over the average cost 5/1/2001 (a)
Ncal Retail bldg, Northridge, CA Fixed interest rate of 9% 12/01/2000 (a)
ILLINOIS
Pensacola Apartment bldg, IL Fixed interest rate of 7.5% 09/30/2009 (a)
PRINCIPAL
CARRYING SUBJECT TO
PRIOR FACE AMOUNT AMOUNT OF DELINQUENT INTEREST
LIENS OF MORTGAGES MORTGAGES INTEREST INCOME
MtRoy - 4,500 6,057 - -
Gran - 5,400 1,909 - -
Crafts 3,343 2,435 975 - 44
Mill 2,374 3,155 776 - 85
Axe 2,022 3,116 2,539 - 328
Head - 3,400 3,899 - -
1521 1,687 1,150 980 - -
SS - 1,010 1,010 75
Red - 400 471 - 66
Sher - 6,000 4,173 315
Wood 2,285 4,800 2,321 - 139
Sea - 11,615 12,291 - 1,465
1301 6,143 13,283 8,224 - 617
ES 66,531 100,971 36,063 1,582
NP 63,923 92,000 23,015 2,841
Pas 2,273 3,000 130 - 136
Ncal 1,969 2,271 1,136 - 120
Pensacola
RESTUBBED TABLE
PERIODIC
INTEREST FINAL MATURITY PAYMENT
DESCRIPTION RATE DATE TERMS
CONNECTICUT
Win Apartment bldg, CT Fixed interest rate of 15% 10/14/2014 (a)
Clem Apartment bldg, Ct Fixed interest rate of 7.5% 01/01/2009 (a)
NORTH CAROLINA
Concord Condominium units, NC Fixed interest rate of 10% 03/23/2009 (a)
LM(83) Condominium units, NC Fixed interest rate of 10% 03/31/2002 (a)
Loewy Office bldg, NC Fixed interest rate of 11.5% 12/31/2011 (a)
MARYLAND
AB Office bldg, MD ixed interest rate of 10% 04/01/2011 (a)
VIRGINIA
Rich Retail bldg, VA Fixed interest at 9% 02/01/2021 (a)
WEST VIRGINIA
Elk Retail bldg, West Virgina Fixed interest at 8.25% 12/31/2016 (a)
GEORGIA
FW Hotel/Commercial Office, GA Fixed interest rate of 14% 2/31/2015 (a)
FLORIDA
Deer Apartment bldg, FL Fixed interest rate of 13% 06/01/2010 (a)
MINNESOTA
StC Retail bldg, MN Fixed interest at 10% 12/31/2014
NEBRASKA
Redick Hotel, NE Fixed rate of 14.5% 09/30/2002 (a)
Sold loans
PRINCIPAL
CARRYING SUBJECT TO
PRIOR FACE AMOUNT AMOUNT OF DELINQUENT INTEREST
LIENS OF MORTGAGES MORTGAGES INTEREST INCOME
Win 8,978 2,973 1,384 - 145
Clem 13,655 6,750 7,289 - 546
Concord - 447 484 -
LM(83) 2,862 2,064 2,713 - 108
Loewy 1,684 3,500 2,337 - -
AB 58,416 31,000 38,656 1,420
Rich 1,571 3,961 1,161 - 51
Elk 961 1,400 643 - 48
FW 875 5,800 8,426 - 867
Deer - 4,100 3,346 - 320
StC 1,796 1,776 1,044 - 73
Redick 2,400 6,005 4,517 - -
======== ======== ======== ==== =======
260,736 352,365 187,541 - 11,992
1,126
260,736 352,365 187,541 - 13,118
(a) All net cash flows from the property
(b)Cost for Federal income tax purposes equals
Reconciliation of the total carrying amount of real estate loans for the year follows:
Balance at October 1, 2001 $192,263,482
Additions during the period:
New mortgage loans $2,938,624
Amortization of discount 3,211,832
Additions of existing loans 14,246,347 20,396,803
----------------------------
$212,660,285
Deductions during the period:
Collections of principal 0
Cost of mortgages sold 25,118,769 25,118,769
----------------------------
Balance at September 30, 2002 $187,541,516
3. Exhibits
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, as Trustee, with
respect to Resource America's 12% Senior Notes due
2004. (2)
10.1 Revolving Credit Agreement and Assignment between LEAF
Financial Corporation and National City Bank, and
related guaranty from Resource America, Inc. dated June
11, 2002.
10.2 Credit Agreement among Atlas America, Inc., Resource
America, Inc. and the other guarantors party thereto
and Wachovia, National Associate, and other banks party
thereto, dated July 31, 2002.
10.3 Agreement between Resource Financial Fund Management,
Inc. and 9 Henmar LLC, dated October 23, 2002.
10.4 Note from Trapeza Partners, L.P. to Resource America,
Inc., dated October 9, 2002, and related Intercreditor
Agreement between Resource America, Inc. and Financial
Stocks, Inc.
10.5 Term Loan Agreement between Resource Properties, Inc.
and Miller & Schroeder Investments Corporation (now
known at The Marshall Group), dated November 15,
2000. (3)
10.6 Loan Agreement between Atlas Pipeline Partners, L.P.,
PNC Bank National Association, First Union National
Bank (now known as Wachovia) and the banks party
thereto, dated October 26, 2000. (3)
10.7 Stock Purchase Agreement, dated as of May 17, 2000,
among European American Bank, AEL Leasing Co., Inc.,
Resource America, Inc. and FLI Holdings, Inc. (4)
10.8 Amendment to Stock Purchase Agreement, dated August 1,
2000. (5)
10.9 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). (5)
10.10 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.
(5)
10.11 Modification of Revolving Credit Loan and Security
Agreement by and among Resource Properties, Inc.,
Resource Properties 53, Inc., Resource Properties XXIV,
Inc., Resource Properties XL, Inc. and Sovereign Bank,
dated March 30, 2002. (5)
10.12 Employment Agreement between Steven J. Kessler and
Resource America, Inc. dated October 5, 1999. (1)
10.13 Employment Agreement between Jonathan Z. Cohen and
Resource America, Inc. dated October 5, 1999. (5)
101
10.14 Employment Agreement between Nancy J. McGurk and
Resource America, Inc. dated October 5, 1999. (1)
10.15 Resource America, Inc. 1989 Key Employee Stock Option
Plan, as amended. (6)
10.16 Resource America, Inc. 1997 Key Employee Stock Option
Plan. (7)
10.17 Resource America, Inc. 1997 Non-Employee Director
Deferred Stock and Deferred Compensation Plan. (7)
10.18 Resource America, Inc. 1999 Key Employee Stock Option
Plan. (8)
10.19 Employment Agreement between Edward E. Cohen and
Resource America, Inc. (9)
10.20 Resource America, Inc. Employee Stock Ownership Plan.
(10)
10.21 Resource America, Inc. 2002 Non-Employee Director
Deferred Stock and Deferred Compensation Plan. (11)
10.22 Resource America, Inc. 2002 Key Employee Stock Option
Plan. (12)
12 Statements regarding computation of ratios.
21 Subsidiaries of the registrant.
23 Consent of Wright & Company.
(b) Reports on Form 8-K:
During the quarter ended September 30, 2002, the Company filed two
current reports on Form 8-K as follows:
o We filed a Form 8-K dated September 13, 2002 regarding the
private placement offering of $125 million of Senior Notes.
o We filed a Form 8-K dated July 31, 2002 regarding the
termination of the agreement to sell our 100% interest in
Atlas Pipeline Partners GP, LLC to New Vulcan Coal Holdings,
LLC.
- -------------------
(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 Registration Statement on Form
S-4 (Registration No. 333-40231) and by this reference incorporated
herein.
(3) Filed previously as an exhibit to our Quarterly Report on Form 10-Q for
the quarter ended December 31, 2000 and by this reference incorporated
herein.
(4) Filed previously as an exhibit to our Current Report on Form 8-K filed
on May 18, 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, 2000 and by this reference incorporated
herein.
(6) Filed previously as an exhibit to our Registration Statement on Form
S-1 (Registration No. 333-03099) and by this reference incorporated
herein.
(7) 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.
(8) Filed previously as an exhibit to our Definitive Proxy Statement for
the 1999 annual meeting of stockholders and by this reference
incorporated herein.
(9) 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.
(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 (Registration No. 333-98507) and by this reference incorporated
herein.
(12) Filed previously as an exhibit to our Registration Statement on Form
S-8 (Registration No. 333-98505) and by this reference incorporated
herein.
102
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)
December 30, 2002 By: /s/ Edward E. Cohen
-------------------
Chairman of the Board, President
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, December 30, 2002
- ------------------------- President and Chief Executive Officer
EDWARD E. COHEN
/s/ Jonathan Z. Cohen Director, Executive Vice President December 30, 2002
- ------------------------- and Chief Operating Officer
JONATHAN Z. COHEN
/s/ Carlos C. Campbell Director December 30, 2002
- -------------------------
CARLOS C. CAMPBELL
/s/ Andrew M. Lubin Director December 30, 2002
- -------------------------
ANDREW M. LUBIN
/s/ P. Sherrill Neff Director December 30, 2002
- -------------------------
P. SHERRILL NEFF
/s/ Alan D. Schreiber Director December 30, 2002
- -------------------------
ALAN D. SCHREIBER
/s/ John S. White Director December 30, 2002
- -------------------------
JOHN S. WHITE
/s/ Steven J. Kessler Senior Vice President December 30, 2002
- ------------------------- and Chief Financial Officer
STEVEN J. KESSLER
/s/ Nancy J. McGurk Vice President-Finance December 30, 2002
- ------------------------- and Chief Accounting Officer
NANCY J. McGURK
103
CERTIFICATIONS
I, Edward E. Cohen, certify that:
1. I have reviewed this annual report on Form 10-K of Resource America,
Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: December 30, 2002
/s/ Edward E. Cohen
Edward E. Cohen
Chairman of the Board, President and Chief Executive Officer
104
CERTIFICATIONS
I, Steven J. Kessler, certify that:
1. I have reviewed this annual report on Form 10-K of Resource America,
Inc.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and
we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officer and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: December 30, 2002
/s/ Steven J. Kessler
Steven J. Kessler
Senior Vice President and Chief Financial Officer
105
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