UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(Mark One)
|X| ANNUAL REPORT PURSUANT TO SECTION 13
OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 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/A
PART I Page
Item 1: Business ...................................................................................... 2 - 26
Item 2: Properties .................................................................................... 27 - 30
Item 3: Legal Proceedings ............................................................................. 31
Item 4: Submission of Matters to a Vote of Security Holders ........................................... 31
PART II
Item 5: Market for Registrant's Common Equity and Related Stockholder Matters ......................... 32
Item 6: Selected Financial Data ....................................................................... 33
Item 7: Management's Discussion and Analysis of Financial Condition
and Results of Operation .................................................................... 34 - 52
Item 7A: Quantitative and Qualitative Disclosures about Market Risk .................................... 53 - 58
Item 8: Financial Statements and Supplementary Data ................................................... 59 - 99
Item 9: Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure ...................................................... 99
PART III
Item 10: Directors and Executive Officers of the Registrant ............................................ 100
Item 11: Executive Compensation ........................................................................ 100
Item 12: Security Ownership of Certain Beneficial Owners and Management ................................ 100
Item 13: Certain Relationships and Related Transactions ................................................ 100 - 103
Item 14: Controls and Procedures ....................................................................... 104
PART IV
Item 15: Exhibits, Financial Statement Schedules and Reports on Form 8-K ............................... 104 - 106
SIGNATURES.................................................................................................... 107
1
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.
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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.
2
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 and a standardized measure value of $104.1 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.
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.
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 partnerships such as Lease Equity Appreciation Fund I,
L.P., an equipment leasing fund and Trapeza CDO I and II, entities that invest
in trust preferred securities of small to mid-size regional banks and their
holding companies.
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(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.
3
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,
Fidelity Leasing, Inc., which, by 2000, held over $600 million in equipment
leasing assets. On August 1, 2000, we sold Fidelity Leasing 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."
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.
4
Appalachian Basin Overview. The Appalachian Basin includes the states of
Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia, West Virginia and
Tennessee. It is the most mature oil and gas producing region in the United
States, having established the first oil production in 1859. In addition, the
Basin is strategically located near the energy consuming regions of the mid-
Atlantic and northeastern United States which has historically resulted in
Appalachian producers selling their natural gas at a premium to the benchmark
price for natural gas on the New York Mercantile exchange. According to the
Energy Information Administration, a branch of the U.S. Department of Energy,
in 2001 there were 22.2 trillion cubic feet, or tcf, of natural gas consumed
in the United States which represented approximately 22.9% of the total energy
used. Additionally, there were approximately 137,000 gas wells in the
Appalachian Basin which represented approximately 37.3% of the total number of
gas wells in the United States. Of those wells, we and our drilling investment
partnerships own interests in approximately 5,000 wells, 85% of which we
operate. The Appalachian Basin accounted for approximately 3.4% of total 2001
domestic natural gas production, or 678 bcf. Furthermore, according to the
Natural Gas Annual 2001, an annual report published by the Energy Information
Administration, Office of Oil and Gas, the Appalachian Basin holds 9.35 tcf of
economically recoverable reserves, representing approximately 5.1% of total
domestic reserves as of December 31, 2001. The 2003 forecast issue of World
Oil magazine predicted that approximately 4,600 gas wells would be drilled in
the Appalachian Basin during 2003, representing approximately 15% of the total
number of wells to be drilled in the United States, and that the average depth
of those 4,600 wells would be approximately 3,100 feet, compared to an
estimated average depth of 5,100 feet for nationwide drilling efforts in 2003.
The American Petroleum Institute has reported that in recent years the
drilling success rate in the Appalachian basin has exceeded 90%. Our success
rates have averaged in excess of 95% over the past 15 years.
Natural Gas and Oil Properties. For information concerning our natural gas
and oil properties including the number of wells in which we have a working
interest, production, reserve 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 physical 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 38% of produced volumes were sold in this manner. For the fiscal
year ending September 30, 2003, we estimate that in excess of 55% of our
produced natural gas volumes will be sold in this manner, leaving the
remaining 45% 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, $14.3 million and
$9.7 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.
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.
5
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.
6
Major Customers. During fiscal 2002 and 2001, gas sales to First Energy
Solutions Corporation 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.
7
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, SR Real Estate Investors, L.P., which is
currently in the offering stage.
8
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.
9
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.
10
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(25) Office Pennsylvania Shawmut Bank(9) 1993 $ 10,549,861 $ 1,700,000
014(10) Office Washington, D.C. Nomura/Cargill/Eastdil Realty(10) 1995 21,811,605 14,300,000
020(24) 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
U.S. Dept. of Housing and Urban
024 Multifamily Pennsylvania 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(12) Single User/ Minnesota Prudential Insurance, Alpha Petroleum
Retail 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) 1996 1,628,955 1,900,000
018 Single User/ California Emigrant Savings Bank/ Walter R.
Retail 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
=========== ===========
11
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) Receivable(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
===================== ============ ============ ============ ============
12
- ---------------
(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.
(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 $3.9 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 as follows:
Loan Number Seller Successor
----------- ----------- ---------
Loan 005.................... People's Bank Shawmut Bank
Loan 017.................... Triester Elkins West K. Corp. Triester Investments
Loan 035.................... Jefferson Bank Hudson United Bank
(10) The borrower, Washington Properties Limited Partnership, is a limited
partnership in which Edward E. Cohen, our Chairman, Chief Executive
Officer and President, Jonathan Z. Cohen, our Chief Operating Officer,
Executive Vice President and director, Scott F. Schaeffer, our former
Vice Chairman and Executive Vice President, and Adam Kauffman, the
president of Brandywine Construction & Management are equal limited
partners.
(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 7, 13 and 17, A. Kaufman is the general partner
of the borrower and, with respect to loan 29, he is the president of
the sole general partner of the borrower. With respect to loans 26 and
35, Mr. Kauffman is the sole shareholder of the general partner of the
borrower.
(13) From 1993 to 1997, S. Schaeffer served as the general partner of the
seller, Castine Associates.
(14) The borrower, New 1521 Associates, is a limited partnership formed in
1991. The general partner, New 1521 G.P., Inc., is a corporation of
which A. Kauffman is the sole shareholder. E. Cohen, and his wife,
Betsy Z. Cohen, beneficially own a 49% limited partnership interest in
the partnership and A. Kauffman owns a 24.75% limited partnership
interest.
(15) Senior lien interest sold subject to our standby repurchase commitment
or our obligation to substitute a performing loan upon default.
(16) The borrower, Evening Star Associates, is a limited partnership in
which one of our subsidiaries, Resource Properties, Inc., is the sole
shareholder of ES GP, Inc., the sole general partner of the borrower.
E. Cohen, B. Cohen, D. Gideon Cohen, our former President, Chief
Operating Officer and director, and S. Schaeffer are limited partners
of Evening Star Associates.
13
(17) The borrower, Commerce Place Associates, LLC, is a limited liability
company whose manager is a corporation of which S. Schaeffer, is the
sole shareholder, officer and director. Messrs. E. Cohen, D. Cohen,
Schaeffer and Kauffman are equal limited partners of an entity,
Brandywine Equity Investors, L.P., that owns approximately 30% of the
borrower.
(18) Our subsidiary, Resource Press Building Manager, Inc., is the manager
of the borrower, Resource/Press Building Realty, LLC.
(19) We acquired a first mortgage loan at face value from RAIT Investment
Trust. The loan is secured by a property in which we have held a
subordinated interest since 1991.
(20) The borrower, Deerfield Partners, L.P., is a limited partnership. S.
Schaeffer is the president of the general partner, Deerfield Beach GP,
Inc. Messrs. E. Cohen, D. Cohen, Schaeffer, and Kauffman are equal
limited partners of Brandywine Equity Investor, L.P., the limited
partner of borrower.
(21) E. Cohen and B. Cohen beneficially own a 40% limited partnership
interest in the borrower, Pasadena Industrial Associates. A. Kauffman
is the general partner of the borrower.
(22) Consists of a series of notes becoming due yearly through December 31,
2016.
(23) In May 1999, we borrowed $875,000 from Castine Associates, a limited
partnership in which Messrs. E. Cohen and Schaeffer 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) The property is owned by EJGB, LLC, a limited liability company in
which D. Cohen owns a 94% interest.
(25) The borrower, Granite GEC (Pittsburgh), L.L.C., is a limited liability
company. D. Cohen owns 79% of Odessa Real Estate Management, Inc., the
assistant managing member of the borrower.
(26) The borrower, St. Cloud Associates, is a limited partnership of which
A. Kauffman is the sole general partner.
14
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 Payment Principal Payment Average Monthly
Average Monthly on Debt Service on on Debt Service Cash Flow
Loan Cash Flow Refinancing or on 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
========== ========== ======== ========
- ---------------
(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.
15
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, including 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%.
16
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 Lease
Equity Appreciation Fund I, L.P., a 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.
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
line of credit. Credit availability is based on the value of the assets
pledged as security and was $18.0 million as of September 30, 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.
17
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.
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.
18
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
Atlas America's net income from and after April 1, 2002 plus $5.0 million. In
addition, Atlas America is permitted to repay intercompany debt to us only up
to the amount of our federal income tax liability attributable to Atlas
America and accrued interest on the original notes and the new notes. 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.
19
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.
20
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:
Investor Relations
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.
21
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.
22
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.
23
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.
24
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.
25
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.
26
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.
Average
Production Average Sales Price Production
---------------------- -------------------- Cost per
Fiscal Year
----------- Oil (Bbls) Gas (Mcf) per Bbl per Mcf(3) 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) Production costs include labor to operate the wells and related equipment,
repairs and maintenance, materials and supplies, property taxes, severance
taxes, insurance, gathering charges and production overhead.
(3) Our average sales price before the effects of hedging was $3.57, $5.13 and
$3.28 for the fiscal years ending in 2002, 2001 and 2000, respectively.
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.
27
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.
Undeveloped
Developed Acreage 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
28
Present Activities. As of December 1, 2002, we were in the process of
drilling 13 gross (3.6 net) wells.
Delivery Commitments. We are not obligated to provide fixed quantities of
oil in the future. At our option, we from time to time make short-term
delivery commitments for a portion of our natural gas. See "-Quantitative and
Qualitative Disclosures of Market Risk-Energy-Commodity Price Risk."
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.
29
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
======== ======== ========
Standardized measure of discounted future cash flows
(in thousands)(4)............................................................................. $104,126 $ 98,712 $ 98,599
======== ======== ========
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.
(4) "Standardized measure of discounted future cash flows" means the future net
cash flows from proved reserves less a 10% discount. The difference between
this amount and the total PV-10 value shown below is attributable to
estimated income taxes.
30
ITEM 3. LEGAL PROCEEDINGS
We are a defendant, 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. Also named as defendants in
the suit are Edward E. Cohen, Michael L. Staines, Steven J. Kessler, Nancy J.
McGurk, Carlos C. Campbell, Andrew M. Lubin, Alan D. Schreiber and John S.
White, our executive officers and directors; Daniel G. Cohen and Scott F.
Schaeffer, former executive officers and directors, and Grant Thornton, LLP,
our independent auditor. 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, Lloyd's of London, has refused to
contribute the remaining $2.0 million. We believe Lloyd'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.
31
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.
32
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.
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
33
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:
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.
34
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 and exploration........................................................................ $ 8,264 $ 7,846 $ 8,339
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) (2)............................................................................. 19,499 17,377 17,596
Oil (Bbls/day).................................................................................... 473 486 535
Average sales prices:
Gas (per Mmcf) (2) (3)............................................................................ $ 3.56 $ 5.04 $ 3.15
Oil (per Bbl)..................................................................................... $ 20.45 $ 25.56 $ 24.50
Production costs (4):
As a percent of sales............................................................................. 23% 16% 29%
Per Mcfe.......................................................................................... $ .82 $ .84 $ .95
- ---------------
(1) Excludes sales of residual gas and sales to landowners.
(2) As used in this discussion, "Mcf" and Mmcf" means thousand cubic feet and
million cubic feet; "Mcfe" and Mmcfe" means thousand cubic feet equivalent
and million cubic feet equivalent, and "Bbls" means barrels. Bbls are
converted to Mcfs equivalent using the ratio of 6 Bbls to one Mcf.
(3) Our average sales price before the effects of hedging was $3.57, $5.13 and
$3.28 for the years ended 2002, 2001 and 2000, respectively.
(4) Production cots include labor to operate the wells and related equipment,
repairs and maintenance, materials and supplies, property taxes, severance
taxes, insurance, gathering charges and production overhead.
35
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, have 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.
36
Results of Operations: Energy - (Continued)
Year Ended September 30, 2002 Compared to Year Ended September 30, 2001 -
(continued)
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.
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 aggregate production costs and exploration costs increased $418,000
(5%) to $8.3 million in fiscal 2002 from $7.8 million in fiscal 2001 as a
result of an increase in the number of wells in which we have an interest and
transportation expenses associated with the increased volumes we produced to
our interest.
Our non-direct expenses were $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.
37
Results of Operations: Energy - (Continued)
Year Ended September 30, 2002 Compared to Year Ended September 30, 2000 --
(continued)
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.
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 incurred in fiscal 2000 associated with our
acquisition of Viking Resources in August 1999.
Our production and exploration costs decreased $493,000 (6%) to $7.8
million in fiscal 2001 from $8.3 million 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 offset by
increased personnel and operating expenses resulting from our increased drilling
activities. Average production costs decreased $.11 (12%) to $.84 per Mcf in
fiscal 2001 from $.95 per Mcf in fiscal 2000.
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.
38
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
Equity in earnings (loss) of equity investee...................................................... 454 (329) (219)
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......................................................................... 611 442 394
------- ------- -------
$16,582 $16,899 $18,649
======= ======= =======
Cost and expenses.................................................................................. $ 2,423 $ 1,504 $ 3,256
======= ======= =======
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.
39
Results of Operations: Real Estate Finance (Continued)
Year Ended September 30, 2002 Compared to Year Ended September 30, 2001
o An increase of $786,000 (49%) in gains from resolution of loans and loan
repayments in excess of carrying values in fiscal 2002 as compared to
fiscal 2001, resulting primarily from the following:
- In fiscal 2002, we sold one loan having a book value of $1.0
million to RAIT for $1.8 million, resulting in a gain of
$757,000.
- 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 equity in earnings (loss) of equity investee of $783,000
primarily resulting from an increase in our equity earnings in one real
estate joint venture in which we own a 50% equity interest.
o An increase in net rental and fee income of $169,000 to $611,000 in
fiscal 2002 from $442,000 in fiscal 2001, primarily resulting from the
receipt of a consulting fee from another real estate joint venture in
which we own a 25% equity interest.
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.
40
Results of Operations: Real Estate Finance - (Continued)
Year Ended September 30, 2002 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 An increase of $110,000 (50%) in equity in loss of equity investee
resulting from a non-cash loss associated with depreciation and other
non-cash charges allocated to our interest.
o An increase of $48,000 (12%) in net rental and fee income during fiscal
2001, to $442,000 from $394,000 in fiscal 2000, primarily resulting from
an increase in service fees.
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.
41
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 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.
42
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 replaces 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
of $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.
43
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 Optiron
which adopted SFAS 142 on January 1, 2002, and as a result of this adoption,
realized an impairment and write-down on its books of goodwill associated with
the on-going viability of the product with which the goodwill was associated.
This impairment resulted in a cumulative effect adjustment of $1.9 million on
Optiron's books, and as a result, we recorded our 50% share of this
adjustment.
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.
44
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
======== ======== ========
Our liquidity is affected by national, regional and local economic trends
and uncertainties as well as trends and uncertainties more particular to us,
including natural gas prices, interest rates, our ability to raise funds
through our sponsorship of investment partnerships and the maturity in 2004 of
substantial amounts of debt. While the current favorable natural gas pricing
and interest rate environment have been positive contributors to our
liquidity, and lead us to believe that we will be able to refinance, or renew,
our indebtedness as it matures, there are numerous risks and uncertainties
involved. Factors affecting our liquidity, as well as the risks and
uncertainties relating to our ability to generate this liquidity, are
described in "Risk Factors" and in "-Results of Operations", "-Changes in
Prices and Inflation", and "-Contractual Obligations and Commercial
Commitments."
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 67% as compared to 64% 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.
45
Liquidity and Capital Resources - (Continued)
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.
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 $54.7 million of our common
stock as a result of our dutch auction 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 $64.3 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.
46
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 Partners' 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 our
capital expenditures will vary in the future depending on commodity market
conditions, among others things.
We continuously evaluate acquisitions of gas and oil and pipeline assets. If
we make any acquisitions, we believe we will be required to access outside
capital either through debt or equity placements or through joint venture
operations with other energy companies. There can be no assurance that we will
be successful in our efforts to obtain outside capital.
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."
47
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 as compared to $5.04 per Mcf of
natural gas and $25.56 per Bbl of oil 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.
48
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)
----------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual cash obligations: 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)
----------------------------------------
Less than 1 - 3 4 - 5 After 5
Other commercial commitments: 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 is 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.
49
Accounts Receivable and Investments in Real Estate Loans, Ventures 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
creditworthiness, as determined by our review of our customer's credit
information. We extend credit on an unsecured basis to many of our energy
customers. At September 30, 2002, our credit evaluation have indicated that we
have no need for an allowance for possible losses for our oil and gas
receivables.
In real estate loans and ventures, we consider general and local economic
conditions, neighborhood values, competitive overbuilding, casualty losses and
other factors which may affect the value of our loans and ventures. The value
of loans and ventures may also be affected by factors such as the cost of
compliance with regulations and liability under applicable environmental laws,
changes in interest rates and the availability of financing. Income from a
property will be reduced if a significant number of tenants are unable to pay
rent or if available space cannot be rented on favorable terms. We reduce our
investment in real estate loans and ventures by an allowance for amounts that
may become unrealizable in the future. Such allowance can be either specific
to a particular loan or venture or general to all loans or ventures. As of
September 30, 2002 and 2001, we had investments in real estate loans and
ventures 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 or venture could cause us to experience a loss in excess of our
allowance.
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 and ventures,
could have a material adverse effect on the realization of our receivables,
ventures 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.
50
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.
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.
51
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.
52
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 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.
53
Energy - (Continued)
Our contract with First Energy Solutions Corporation allows us from time to
time to "lock in" the sales 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. Throughout 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 38% of produced volumes were sold in
this manner. For the fiscal year ending September 30, 2003, we estimate in
excess of 53% of our produced natural gas volumes will be sold in this manner,
leaving the remaining 47% 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 production sold is included in 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.
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)
====== ====================== ================== =====================
54
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.
55
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(4)..................... $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.
56
(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.
57
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.
58
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.
/s/ 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.
59
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 ........... 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
Intangible assets ....................................... 9,589 16,851
Other assets ............................................ 19,278 13,162
-------- --------
$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 ESOP loan receivable .............................. (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
60
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
61
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
62
RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED SEPTEMBER 30, 2002, 2001, AND 2000
(in thousands, except share data)
Common Stock Additional Treasury Stock
----------------------------- Paid-In -----------------------------
Shares Amount Capital Shares Amount
------------- ------------- ------------- ------------- -------------
Balance, September 30, 1999 .................... 24,385,279 $244 $221,084 (1,071,432) $(17,002)
Treasury shares issued ......................... (917) 66,450 1,396
Issuance of common stock ....................... 236,683 2 1,194
Purchase of treasury shares .................... (25,000) (172)
Other comprehensive income .....................
Cash dividends ($.13 per share) ................
Repayment of ESOP loan .........................
Net income .....................................
---------- ---- -------- ---------- --------
Balance, September 30, 2000 .................... 24,621,962 $246 $221,361 (1,029,982) $(15,778)
Treasury shares issued ......................... (407) 33,916 804
Issuance of common stock ....................... 318,075 3 2,758
Cancellation of shares issued .................. (153,526) (1,305)
Purchase of treasury shares .................... (6,349,021) (57,801)
Other comprehensive income .....................
Cash dividends ($.13 per share) ................
Repayment of ESOP loan .........................
Net income .....................................
---------- ---- -------- ---------- --------
Balance, September 30, 2001 .................... 24,940,037 $249 $223,712 (7,498,613) $(74,080)
Treasury shares issued ......................... (429) 31,537 769
Issuance of common stock ....................... 104,029 1 297
Tax benefit from employee stock option ......... 244
Purchase of treasury shares .................... (156,122) (1,517)
Other comprehensive income .....................
Cash dividends ($.13 per share) ................
Repayment of ESOP loan .........................
Net loss .......................................
---------- ---- -------- ---------- --------
Balance, September 30, 2002 .................... 25,044,066 $250 $223,824 (7,623,198) $(74,828)
========== ==== ======== ========== ========
Accumulated
ESOP Other Totals
Loan Comprehensive Retained Stockholders'
Receivable Income (Loss) Earnings Equity
------------- ------------- ------------- -------------
Balance, September 30, 1999..................................... $(1,488) $(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 95
Net income...................................................... 18,165 18,165
------- ------- ------- --------
Balance, September 30, 2000..................................... $(1,393) $ (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 96
Net income...................................................... 9,829 9,829
------- ------- ------- --------
Balance, September 30, 2001..................................... $(1,297) $ 1,657 $85,218 $235,459
Treasury shares issued.......................................... 340
Issuance of common stock........................................ 298
Tax benefit from employee stock option ......................... 244
Purchase of treasury shares..................................... (1,517)
Other comprehensive income...................................... 4,254 4,254
Cash dividends ($.13 per share)................................. (2,326) (2,326)
Repayment of ESOP loan.......................................... 96 96
Net loss........................................................ (3,309) (3,309)
------- ------- ------- --------
Balance, September 30, 2002..................................... $(1,201) $ 5,911 $79,583 $233,539
======= ======= ======= ========
See accompanying notes to consolidated financial statements
63
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
Equity in (earnings) loss of equity investee................................................ (454) 329 219
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................................. (4,507) 3,674 (6,566)
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
Purchase of RAIT Investment Trust shares..................................................... (1,890) (6,405) -
Increase in other assets..................................................................... (6,193) (3,745) (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
64
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, whose
activities include only exploration and production activities. In accordance
with established practice in the oil and gas industry, the Company also
includes its pro-rata share of income and costs and expenses of the 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).
65
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, net of taxes, of marketable securities and
unrealized hedging gains and losses. Accumulated other comprehensive income is
related to the following:
At September 30,
------------------
2002 2001
------ ------
(in thousands)
Marketable securities - unrealized gains .................... $6,144 $1,669
Unrealized hedging gains (losses) ........................... (233) (12)
------ ------
$5,911 $1,657
====== ======
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 or within twelve months of
completion of drilling if this determination cannot be made. 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 assessment of significant unproved properties for
impairment is on a property-by-property basis. The Company considers whether a
dry hole has been drilled on a portion of the property or in close proximity,
the Company's intentions of further drilling, the remaining lease term of the
property, and its experience in similar fields in close proximity. The Company
assesses unproved properties whose costs are individually insignificant in the
aggregate, this assessment includes considering the Company's experience of
similar situations, the primary lease terms, the average holding period of
66
unproved properties and the relative proportion of such properties on which
proved reserves have been found in the past.
67
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Oil and Gas Properties - (Continued)
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.
Upon the sale or retirement of a complete or partial unit of a proved
property, the cost and related accumulated depletion are eliminated from the
property accounts, and the resultant gain or loss is recognized in the statement
of operations. Upon the sale of an entire interest in an unproved property where
the property had been assessed for impairment individually, a gain or loss is
recognized in the statement of operations. If a partial interest in an unproved
property is sold, any funds received are accounted for as a reduction of the
cost in the interest retained.
On an annual basis, the Company estimates the costs of future dismantlement,
restoration, reclamation, and abandonment of its gas and oil producing
properties. Additionally, the Company estimates the salvage value of equipment
recoverable upon abandonment. At 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.
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.
Investment in RAIT Investment Trust
The Company accounts for its investment in RAIT in accordance with Statement
of Financial Accounting Standard No. 115, "Accounting for Certain Investments
in Debt and Equity Securities." This investment is classified as availablef-
or-sale and as such is carried at fair market value based on market quotes.
Unrealized gains and losses, net of taxes, are reported as a separate component
of stockholders' equity. The cost of securities sold is based on the specific
identification method.
The following table discloses the pre-tax unrealized gains relating to the
Company's investment in RAIT at the periods indicated:
At September 30,
-----------------
2002 2001
------- -------
(in thousands)
Cost ...................................................... $20,268 $18,378
Unrealized gains .......................................... 9,312 2,531
------- -------
Estimated fair value ...................................... $29,580 $20,909
======= =======
68
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Fair Value of Financial Instruments
The Company used the following methods and assumptions in estimating the
fair value of each class of financial instruments for which it is practicable
to estimate fair value.
For cash and cash equivalents, receivables and payables, the carrying
amounts approximate fair value because of the short maturity of these
instruments.
For investments in real estate loans, because each loan is a unique
transaction involving a discrete property, it is impractical to determine
their fair values. However, the Company believes the carrying amounts of the
loans are reasonable estimates of their fair value considering the nature of
the loans and the estimated yield relative to the risks involved.
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.
Environmental Matters
The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. The Company has
established procedures for the ongoing evaluation of its operations, to
identify potential environmental exposures and to comply with regulatory
policies and procedures.
69
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Environmental Matters - (Continued)
The Company accounts for environmental contingencies in accordance with
SFAS No. 5 "Accounting for Contingencies." Environmental expenditures that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations,
and do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are
probable, and the costs can be reasonably estimated. The Company maintains
insurance which may cover in whole or in part certain environmental
expenditures. For the years ended September 30, 2002 and 2001, the Company had
no environmental matters requiring specific disclosure or requiring recording
of a liability.
Revenue Recognition
Energy
The Company conducts certain energy activities through, and a portion of its
revenues are attributable to, sponsored 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 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 as services
are performed for cost-plus contracts. Turnkey contracts are accounted for under
the completed contract method. Contracts are considered substantially complete
when remaining costs and potential risks are insignificant in amount. The
Company determines this on a well-by-well basis to be when the surface equipment
has been installed on the well. For contracts for which revenue is recognized as
services are performed, the Company uses the value added method (contract value
of total work performed at any reporting date) for measuring progress toward the
completion of the drilling contract.
The Company recognizes transportation revenues at the time the natural gas
is delivered to the purchaser.
The Company recognizes field services revenues at the time the services are
performed.
The Company is entitled to receive management fees according to the
respective Partnership agreements. The Company recognizes such fees as income
when earned and includes them in energy revenues.
The Company sells interests in gas and oil wells and retains a working
interest and/or overriding royalty. The Company records the income from the
working interests and overriding royalties when the gas and oil are sold.
Real Estate Finance
The Company accretes the difference between its cost basis in a real estate
loan and the sum of projected cash flows from that loan into interest income
over the estimated life of the loan using the interest method which recognizes
a level interest rate over the life of the loan. The Company reviews projected
cash flows 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.
70
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Real Estate Finance - (Continued)
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.
Supplemental Cash Flow Information
The Company considers temporary investments with maturity at the date of
acquisition of 90 days or less to be cash equivalents.
Supplemental disclosure of cash flow information:
Years Ended September 30,
----------------------------
2002 2001 2000
------- ------- -------
(in thousands)
Cash paid during the periods for:
Interest........................................................................................... $11,683 $13,976 $17,652
Income taxes paid (refunded)....................................................................... $ 3,243 $13,393 $ (787)
Non-cash activities include the following:
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.
71
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 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
======== ======= =======
Weighted average common shares outstanding - basic................................................ 17,446 17,962 23,413
Dilutive effect of stock option and award plans................................................... 359 474 415
-------- ------- -------
Weighted average common shares - diluted.......................................................... 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-Lived Assets" was issued. SFAS 144 was effective for fiscal years
beginning after December 31, 2001. 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 Company early-adopted SFAS
144 as of October 1, 2001 resulting 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).
72
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Continued)
Recently Issued Financial Accounting Standards - (Continued)
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 resulted in the reclassification of
$180,000 and $1.0 million of pretax gain from extraordinary gain to interest
and other revenues and the reclassification of $56,000 and $367,000 of income
taxes that had been netted against extraordinary gain to provision for income
taxes in 2001 and 2000, respectively, in the consolidated statements 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 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 -- GOODWILL, INTANGIBLE ASSETS AND OTHER ASSETS
Goodwill
On October 1, 2001, the Company early-adopted SFAS 142 "Goodwill and Other
Intangible Assets," which requires that goodwill no longer be amortized, but
instead tested for impairment at least annually. At that time, the Company had
unamortized goodwill of $31.4 million. The 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. All goodwill recorded on the Company's balance sheets
is related to the Company's energy segment.
73
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 3 - GOODWILL, INTANGIBLE ASSETS AND OTHER ASSETS - (Continued)
Goodwill - (Continued)
Changes in the carrying amount of goodwill for the periods indicated are as
follows:
Years Ended September 30,
----------------------------
2002 2001 2000
------- ------- -------
(in thousands)
Goodwill at beginning of period,
(less accumulated amortization of $4,063, $2,612 and $1,452)....................................... $31,420 $28,434 $25,147
Additions to goodwill related to asset acquisitions................................................ 15 4,387 4,497
Amortization expense............................................................................... - (1,451) (1,160)
Atlas Pipeline goodwill amortization, whose fiscal year
began January 1, 2002, at which time it adopted SFAS 142......................................... (22) - -
Leasing platform transferred from goodwill to other assets in
accordance with SFAS 142 (net of accumulated amortization of $587)............................... (331) - -
Syndication network reclassified from other assets
in accordance with SFAS 142 (net of accumulated amortization of $711)............................ 6,389 - -
------- ------- -------
Goodwill at end of period (net of accumulated amortization
of $4,209, $4,063 and $2,612).................................................................... $37,471 $31,420 $28,484
======= ======= =======
Adjusted 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. Adjusted basic income per share from continuing operations for
the years ended September 30, 2001 and 2000 would have been $.84 and $.27,
respectively. Adjusted diluted income per share from continuing operations for
the years ended September 30, 2001 and 2000 would have been $.82 and $.26,
respectively.
Intangible Assets
Partnership management and operating contracts and the Company's equipment
leasing operating system, or leasing platform, were acquired through
acquisitions recorded at fair value on their acquisition dates. The Company
amortizes contracts acquired on a declining balance method over their
respective estimated lives, ranging from five to thirteen years. The leasing
platform is amortized on the straight-line method over its remaining life of six
years. During 2001 an additional $974,000 in management and operating contracts
were acquired whose weighted average amortization period is eight years.
Amortization expense for the years ended September 30, 2002, 2001 and 2000 were
$1.2 million, $1.5 million and $1.3 million, respectively. The aggregate
estimated annual amortization expense is approximately $1.3 million for each of
the succeeding five years.
At September 30,
-----------------
2002 2001
------- -------
(in thousands)
Partnership management and operating contracts ............ $14,343 $21,443
Leasing platform .......................................... 918 -
------- -------
15,261 21,443
Accumulated amortization .................................. (5,672) (4,592)
------- -------
Intangible assets, net .................................... $ 9,589 $16,851
======= =======
74
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 3 - GOODWILL, INTANGIBLE ASSETS AND OTHER ASSETS - (Continued)
Other Assets
The following table provides information about other assets at the dates
indicated.
At September 30,
-----------------
2002 2001
------- -------
(in thousands)
Deferred financing costs, net of accumulative amortization
of $3,742 and $2,674..................................... $ 2,122 $ 1,638
Equity method investments in and advances to Trapeza
entities................................................. 3,085 -
Investments at lower of cost or market .................... 6,137 5,909
Other ..................................................... 7,934 5,615
------- -------
$19,278 $13,162
======= =======
Deferred financing costs are amortized over the terms of the related loans
(two to seven years).
Investments in Trapeza entities are accounted for by the equity method of
accounting because the Company, as a 50% owner of the general partner of these
entities, has the ability to exercise significant influence over their operating
and financial decisions. The Company's combined general and limited partner
interests in these entities range from 16% to 18%.
Investments at the lower of cost or market include non-marketable investments
in entities in which the Company has less than a 20% ownership interest, and in
which it does not have the ability to exercise significant influence. These
investments include approximately 10% of the outstanding shares of The Bancorp,
Inc., a related party as disclosed in Note 4.
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.
75
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (Continued)
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.
76
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
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.
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.
77
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (Continued)
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.
78
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (Continued)
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.
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 by the borrower, a portion of the cash
received is employed to reduce the cumulative accretion of discount included
in the carrying value of the Company's investments in real estate loans.
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
======== ========
79
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 5 - INVESTMENTS IN REAL ESTATE LOANS AND VENTURES - (Continued)
In determining its allowance for possible losses related to its real estate
loans and ventures, the Company considers general and local economic
conditions, neighborhood values, competitive overbuilding, casualty losses and
other factors which may affect the value of loans and its ventures. The value
of loans and ventures may also be affected by factors such as the cost of
compliance with regulations and liability under applicable environment laws,
changes in interest rates and the availability of financing. Income from a
property will be reduced if a significant number of tenants are unable to pay
rent or if available space cannot be rented on favorable terms. In addition,
the Company continuously monitors collections and payments from its borrowers
and maintains an allowance for estimated losses based upon its historical
experience and its knowledge of specific borrower collection issues
identified. The Company reduces its investment in real estate loans and
ventures by an allowance for amounts that may become unrealizable in the
future. Such allowance can be either specific to a particular loan or venture
or general to all loans or ventures.
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.
80
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. The interest rates were
3.54% to 5.0% at September 30, 2002.
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 these facilities, respectively.
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.
81
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
82
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%
== == ===
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)
======== ========
83
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 7 - INCOME TAXES - (Continued)
Generally accepted accounting principles require that deferred tax assets be
reduced by a valuation allowance if it is more likely than not that some
portion or all of the deferred tax assets will not be realized. No valuation
allowance was needed at September 30, 2002 and 2001.
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. In September 1998, the Company loaned
$1.3 million to the ESOP, which the ESOP used to acquire 105,000 shares of the
Company's common stock. The ESOP loan receivable (a reduction in stockholders'
equity) is reduced by the amount of any loan principal reduction resulting
from contributions by the Company to the ESOP.
The common stock purchased by the ESOP is held by the ESOP trustee in a
suspense account. On an annual basis, a portion of the common stock is
released from the suspense account 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 available for future issuance
issued upon exercise of Weighted-average exercise under equity compensation plans
Plan category outstanding options, price of outstanding options, excluding securities reflected in
------------- warrants and rights warrants and rights column (a)
-------------------------- ----------------------------- ---------------------------------
Equity compensation plans
approved by security holders.. 2,463,003 $9.50 149,220
Equity compensation plans not
approved by security holders.. 54,495 $ .11 -
--------- ----- -------
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").
84
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
====== ====== ======
85
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.
86
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.
87
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 instrument 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.
88
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.
89
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").
90
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.
91
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 who devoted a
significant portion of his time to the discontinued leasing business. The
other officer was the Company's vice-chairman as well as the president of the
Company's continuing 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.
The Company's subordinated units are a special class of limited partnership
interest in Atlas Pipeline under which its rights to distributions are
subordinated to those of the publicly held common units. The subordination
period extends until December 31, 2004 and will continue beyond that date if
financial tests specified in the partnership agreement are not met. The
Company's general partner interest also includes a right to receive incentive
distributions if the partnership meets or exceeds specified levels of
distributions.
92
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.
NOTE 15 - CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE
Optiron adopted SFAS 142 on January 1, 2002, the first day of its fiscal
year. Optiron performed the evaluation of its goodwill required by SFAS 142
and determined that it was impaired due to uncertainty associated with the on-
going viability of the product line with which the goodwill was associated.
This impairment resulted in a cumulative effect adjustment on Optiron's books
of $1.9 million before tax. The Company 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.
93
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 16 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMER INFORMATION
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
Intercompany interest.......................................................................... (237) (136) (161)
All other (1).................................................................................. 6,269 6,601 11,460
-------- -------- --------
$120,763 $118,306 $100,661
======== ======== ========
Depreciation, depletion and amortization:
Energy......................................................................................... $ 10,836 $ 10,784 $ 9,781
Real estate finance............................................................................ 244 200 195
All other (1).................................................................................. 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
All other (1).................................................................................. (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
All other (1).................................................................................. 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
All other (1).................................................................................. 323 - -
-------- -------- --------
$ 21,967 $ 14,210 $ 11,066
======== ======== ========
- ---------------
(1) Revenue and assets from the Company's financial services subsidiaries are
included in the "All other" categories along with corporate interest and
dividend income. Financial services does not meet the criteria of an
operating segment under SFAS 131.
Operating profit (loss) per segment represents total revenues less costs and
expenses attributable thereto. Expenses include interest expense, provision for
possible losses, general and administrative expenses, and depreciation,
depletion and amortization.
94
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 First Energy
Solutions Corporation 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:
At September 30,
-------------------------------
2002 2001 2000
-------- -------- --------
(in thousands)
Proved properties............................................................................... $126,399 $106,314 $ 85,642
Unproved properties............................................................................. 584 481 386
-------- -------- --------
126,983 106,795 86,028
Accumulated depreciation, depletion, amortization and valuation allowances...................... (36,384) (28,694) (22,386)
-------- -------- --------
Net capitalized costs........................................................................ $ 90,599 $ 78,101 $ 63,642
======== ======== ========
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 $ 55
Proved properties.................................................................................. $ 440 $ 5,844 $ 96
Exploration costs.................................................................................. $ 1,573 $ 1,662 $1,095
Development costs.................................................................................. $20,648 $14,766 $9,682
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.
95
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 made by management
and verified by Wright & Company, Inc., an independent petroleum engineering
firm, as of September 30, 2002, 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.
96
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
97
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.
98
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
NOTE 17 - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) - (Continued)
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
======== ======== ========
99
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)
======= ======= ======= =======
As described in Note 12, in June 2002 the Company adopted a plan to dispose
of Optiron. Accordingly, the Company's share of Optiron's operations,
including the cumulative effect of the impairment of goodwill and the write-
off of certain advances to Optiron, have been reported as discontinued
operations. The amount of those charges to discontinued operations
approximated $700, $200 and $1,300 in the quarters ended December 2001, March
2002 and June 2002, respectively. The amount charged to discontinued
operations with respect to Optiron approximated $300 in each of the quarters
ended December 2000 and March 2001 and $200 in each of the quarters ended June
2001 and September 2001. Also, as described in Note 12, the Company sold FLI
in August 2000. In the quarters ended September 30, 2002 and 2001, the Company
charged discontinued operations approximately $9,400 and $3,200, respectively,
based upon information that became available during each of those quarters
with regard to claims made by the buyer with respect to the Company's
indemnification obligations and representations.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
100
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS OF THE
REGISTRANT
The information required by this item is set forth in our definitive proxy
statement with respect to our 2003 annual meeting of stockholders ("2003 proxy
statement"), which is incorporated herein by this reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is 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 is set forth in our 2003 proxy
statement, which is incorporated herein by this reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In the ordinary course of our business operations, we have ongoing
relationships with several related entities and from time to time have engaged
in transactions with them. We discuss these relationships, and transactions
during fiscal 2001, 2002 and 2003 to date in which we have engaged with
related parties below. We believe that each of the listed transactions between
us and a related party was on terms at least as favorable to us as could have
been obtained in arms's-length negotiations with third parties.
Relationship with Brandywine Construction & Management. Brandywine
Construction & Management manages the properties underlying 24 of our real
estate loans and investments in real estate loans and investments in real
estate ventures. Adam Kauffman, President of Brandywine Construction &
Management, or an entity affiliated with him, has also acted as the general
partner, limited partner, president or trustee of seven of the borrowers as
follows: New 1521 Associates, President of general partner of borrower;
Headhouse Associates, president of general partner of borrower and general
partner of limited partner of borrower; Skippack SLC Associates, general
partner of borrower; Pasadena Industrial Associates, general partner of
borrower; Elkins West Associates, general partner of borrower; Commerce Place
Associates, LLC, a partner of the owner of the managing partner of the member
of borrower; and St. Cloud Associates, general partner of borrower. Edward E.
Cohen, our Chairman, Chief Executive Officer and President, is the Chairman
and a minority stockholder of Brandywine Construction & Management, holding
approximately 8% of its stock.
In September 2001, we sold Resource Properties XVI Inc., our wholly-owned
subsidiary, to Brandywine Construction & Management for $4.0 million,
recognizing a gain of $356,000. The $4.0 million consideration was comprised
of $3.0 million in cash and a $1.0 million non-recourse note from Brandywine
Construction & Management. The non-recourse note bears interest at 8% per
annum and is due September 2006. As of February 28, 2003, the Company has
received $414,000 of principal payments and $106,000 of interest payments on
the non-recourse note. The Bancorp, Inc., a related party financial
institution provided the first mortgage financing for this sale.
Relationship with RAIT Investment Trust. Since we organized it in 1997, we
have engaged in a number of transactions with RAIT Investment Trust. RAIT
Investment Trust is a real estate investment trust in which, as of March 27,
2003, we owned approximately 5.2% of the common shares. Betsy Z. Cohen, E.
Cohen's spouse, is the Chairman and Chief Executive Officer of RAIT Investment
Trust, and Jonathan Z. Cohen, a son of E. and B. Cohen and our Chief Operating
Officer, Executive Vice President and a director, is our designee as trustee
on RAIT Investment Trust's board. J. Cohen also serves as RAIT Investment
Trust's Secretary. Scott F. Schaeffer, our former Vice Chairman and Executive
Vice President, is RAIT Investment Trust's President and Chief Operating
Officer.
101
Since October 1, 2001, we and RAIT Investment Trust have engaged in the
following transactions:
o In June 2002, we sold a mortgage loan having a book value of $1.0 million
to RAIT Investment Trust for $1.8 million, recognizing a gain of
$757,000. S. Schaeffer was the president and director of the general
partner of the borrower.
o In March 2002, RAIT Investment Trust provided the initial financing,
which has since been repaid, on our 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 our
executive offices are located and in which we own a 50% interest.
Relationship with The Bancorp. As of December 31, 2002, we owned 9.7% of the
common and 7.5% of the voting preferred stock of The Bancorp. B. Cohen is the
Chief Executive Officer of The Bancorp, and D. Gideon Cohen, a son of E. and
B. Cohen, is the Chairman of The Bancorp. D. Cohen is our former President,
Chief Operating Officer and director.
Relationship with Ledgewood Law Firm. Until April 1996, E. Cohen was of
counsel to Ledgewood Law Firm. We paid Ledgewood Law Firm $839,000 during
fiscal 2002 for legal services. E. Cohen receives certain debt service
payments from Ledgewood Law Firm related to the termination of his affiliation
with it 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, which we refer to as the SERP. We have
established two trusts to fund the SERP. The 1999 Trust purchased 100,000
shares of common stock of The Bancorp. The 2000 Trust holds 38,571 shares of
voting preferred stock of The Bancorp 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 our consolidated balance sheet.
In connection with E. Cohen's SERP, we entered into a split-dollar insurance
arrangement under which we pay 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, our future payment of
premiums under this arrangement may be deemed to be a prohibited loan to E.
Cohen. We have suspended premium payments on the policy until we determine an
appropriate course of action. We expect to make our determination before the
premium due date or the end of the 30-day grace period. We cannot predict the
effect, if any, that cancellation of the arrangement might entail.
Relationships with 9 Henmar LLC. We own a 50% interest in Trapeza Funding,
an entity that acts as the general partner of Trapeza Partners and Trapeza
Partners II. Trapeza Partners sponsored and invested in the equity interests
of Trapeza CDO I, an issuer of collateralized debt obligations, and Trapeza
Partners II sponsored and invested in the equity interests of Trapeza CDO II,
also an issuer of collateralized debt obligations. We also own a 50% interest
in Trapeza Capital Management, the collateral manager of Trapeza CDO I and
Trapeza CDO II. Please see "Business-Financial Services" for more detailed
information about these entities. The boards of managers of both Trapeza
Funding and Trapeza Capital Management are composed of four members, of which
J. Cohen and D. Cohen are our appointees.
102
The Trapeza ventures were originated and developed in large part by D.
Cohen. We have agreed to pay his company, 9 Henmar LLC, 10% of the fees and
10% of the distributions we receive through our interest in the Trapeza
general partner and collateral management entities. Through December 31, 2002,
we had not paid 9 Henmar anything under these arrangements. In addition, we
agreed to reimburse 9 Henmar for fees and expenses, including a portion of its
overhead, incurred by it in connection with structuring the Trapeza ventures
and our participation in them, developing the pools of trust preferred
securities, consulting with the underwriters and rating agencies and providing
other consulting, managerial and sales services. Through April 7, 2003, 9
Henmar has been reimbursed $1,300,264 of such expenses, of which $1,246,838
had been reimbursed to us or paid directly by Trapeza Funding, Trapeza Funding
II, Trapeza CDO I or Trapeza CDO II.
Relationships with Cohen Bros. During fiscal 2002, we used Cohen Bros. as an
agent to repurchase 125,095 shares of our common stock and $1.5 million
principal amount of the original notes. Cohen Bros. acted as one of the
placement agents for the sale of Trapeza Partners II limited partner
interests, receiving sales commissions of $117,040. Cohen Bros. was paid at
the same 2% commission rate as unaffiliated placement agents. D. Cohen owns
the corporate parent of Cohen Bros.; until March 2003, J. Cohen was an owner.
Relationships with Certain Borrowers. We have from time to time purchased
loans in which our affiliates are affiliates of the borrowers as set forth
below. Loan numbers refer to the loan numbers set forth in the tables in
"Business-Real Estate Finance-Loan Status."
In 2002, EG JB, LLC, in which D. Cohen owns 94% interest, acquired the the
beneficial ownership of the property securing loan 20, a loan we acquired in
1996. At December 31, 2002, our receivable was $8.6 million and the book value
of the loan was $2.3 million.
In 1998, we acquired loan 49, which was a defaulted loan in the original
principal amount of $91.0 million. At December 31, 2002, our receivable was
$111.9 million and the book value of the loan was $38.9 million. In September
2000, in connection with a refinancing and to protect our interest, Commerce
Place Associates, LLC assumed equity title to the property. Messrs. Schaeffer,
Kauffman, E. Cohen and D. Cohen are limited partners (24.75% each) in
Brandywine Equity Investors, L.P., which owns approximately 19% of Commerce
Place Associates. In addition, S. Schaeffer has a controlling administrative
role with Commerce Place Associates.
In 1998, we acquired loan 44 under a plan of reorganization in bankruptcy.
The loan had a book value of $36.5 million at December 31, 2002. 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 our interest, Evening Star
Associates took title to the property in June 1998. One of our subsidiaries,
ES GP, Inc., 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.
In 1997, we acquired loan 35 with a face amount of $2.3 million at a cost of
$1.6 million. The loan had a book value of $971,000 at December 31, 2002. The
loan is secured by a property owned by New 1521 Associates, a partnership in
which Messrs. Kauffman and E. Cohen and Mrs. B. Cohen are limited partners
(with a 75% beneficial interest). Ledgewood Law Firm and Brandywine
Construction & Management were tenants at such property as of December 31,
2002.
In 1997, we acquired loan 37, which was in the original principal amount of
$6.8 million. At December 31, 2002, our loan receivable was $7.8 million and
the book value of the loan was $3.3 million. The loan is secured by a property
that was acquired in 2000 by Deerfield Partners, L.P., a limited partnership
in which S. Schaeffer is the President of the sole general partner, Deerfield
Beach GP, Inc., and Messrs. E. Cohen, D. Cohen, Schaeffer and Kauffman are
equal limited partners of Brandywine Equity Investors, L.P., the 99% limited
partner of the borrower.
103
In 1995, we acquired loan 14, which was in the original principal amount of
$12.0 million. At December 31, 2002, our receivable was $22.2 million and the
book value of the loan was $8.3 million. The loan is secured by a property
owned by Washington Properties Limited Partnership, a partnership in which
1301 Partners L.P. acquired a 99% limited partnership interest in August 2000.
Messrs. E. Cohen, D. Cohen and A. Kauffman and Mrs. B Cohen are the limited
partners and own all of the capital stock of 1301 GP, Inc., the general
partner.
In 1994, we acquired loan 13, which was in the original principal amount of
$3.0 million. At December 31, 2002, our receivable was $2.5 million and the
book value of the loan was $130,000. The loan is secured by a property owned
by Pasadena Industrial Associates, a partnership in which E. Cohen and B.
Cohen are limited partners with an aggregate 40% beneficial interest.
In 1993, we acquired loan 5, which was the original principal amount of $4.2
million. At December 31, 2002, our receivable was $10.8 million and the book
value of the loan was $1.9 million. The loan was secured by a property
acquired in 1996 by Granite GEC (Pittsburgh), L.L.C. D. Cohen owns 79% of
Odessa Real Estate Management, Inc., the assistant managing member of Granite
GEC, which holds a 1% interest in Granite GEC.
Relationships with Certain Lienholders. In 1997, we acquired loan 30, a
first mortgage loan with a face amount of $14.3 million and a book value of
$4.5 million, secured by a hotel property owned by Charles Rennie Financial,
Inc., in which, on a fully diluted basis, J. Cohen and E. Cohen have a 19%
interest. Charles Rennie Financial acquired the property in 1999 through
foreclosure of a subordinate loan.
In 2001, we sold 100% of the common stock in Resource Properties XLIII,
Inc., our 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.
104
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
105
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.(13)
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.(13)
10.3 Agreement between Resource Financial Fund Management,
Inc. and 9 Henmar LLC, dated October 23, 2002.(13)
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.(13)
10.5 Term Loan Agreement between Resource Properties, Inc.
and Miller & Schroeder Investments Corporation (now
known as 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)
10.10(a) 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)
10.11 Employment Agreement between Steven J. Kessler and
Resource America, Inc. dated October 5, 1999.(1)
10.12 Employment Agreement between Jonathan Z. Cohen and
Resource America, Inc. dated October 5, 1999.(5)
10.13 Employment Agreement between Nancy J. McGurk and
Resource America, Inc. dated October 5, 1999.(1)
10.14 Resource America, Inc. 1989 Key Employee Stock Option
Plan, as amended.(6)
106
10.15 Resource America, Inc. 1997 Key Employee Stock Option
Plan.(7)
10.16 Resource America, Inc. 1997 Non-Employee Director
Deferred Stock and Deferred Compensation Plan.(7)
10.17 Resource America, Inc. 1999 Key Employee Stock Option
Plan.(8)
10.18 Employment Agreement between Edward E. Cohen and
Resource America, Inc.(9)
10.19 Resource America, Inc. Employee Stock Ownership
Plan.(10)
10.20 Resource America, Inc. 2002 Non-Employee Director
Deferred Stock and Deferred Compensation Plan.(11)
10.21 Resource America, Inc. 2002 Key Employee Stock Option
Plan.(12)
12 Statements regarding computation of ratios.(13)
21 Subsidiaries of the registrant.(13)
23 Consent of Wright & Company.(13)
99.1 Certification Pursuant to 302 of the Sarbannes Oxley Act
of 2002.
99.2 Certification Pursuant to 302 of the Sarbannes Oxley Act
of 2002.
99.3 Certification Pursuant to 18 U.S.C. Section 1350, as
Adopted Pursuant to Section 906 of Sarbannes-Oxley Act
of 2002.
99.4 Certification Pursuant to 18 U.S.C. Section 1350, as
Adopted Pursuant to Section 906 of Sarbannes-Oxley Act
of 2002.
(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.
(13) Filed previously as an Exhibit to our Annual Report on Form 10-K for the
year ended September 30, 2002 and by this reference incorporated herein.
107
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)
May 15, 2003 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, May 15, 2003
- ---------------------- President and Chief
EDWARD E. COHEN Executive Officer
/s/ Jonathan Z. Cohen Director, Executive Vice May 15, 2003
- ---------------------- President and Chief
JONATHAN Z. COHEN Operating Officer
/s/ Carlos C. Campbell Director May 15, 2003
- ----------------------
CARLOS C. CAMPBELL
/s/ Andrew M. Lubin Director May 15, 2003
- ----------------------
ANDREW M. LUBIN
/s/ P. Sherrill Neff Director May 15, 2003
- ----------------------
P. SHERRILL NEFF
/s/ Alan D. Schreiber Director May 15, 2003
- ----------------------
ALAN D. SCHREIBER
/s/ John S. White Director May 15, 2003
- ----------------------
JOHN S. WHITE
/s/ Steven J. Kessler Senior Vice President May 15, 2003
- ---------------------- and Chief Financial Officer
STEVEN J. KESSLER
/s/ Nancy J. McGurk Vice President-Finance May 15, 2003
- ---------------------- and Chief Accounting
NANCY J. McGURK Officer
108