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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 2004
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 (I.R.S. Employer
of incorporation or organization) Identification No.)
1845 WALNUT STREET 19103
SUITE 1000 Zip Code
PHILADELPHIA, PA
(Address of principal executive offices)
Registrant's telephone number, including area code: 215-546-5005
Securities registered pursuant to Section 12(b) of the Act: None
Title of each class Name of each exchange on which registered
- ------------------- -----------------------------------------
None 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. [ ]
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 on the closing price of such stock on the last business
day of the registrant's most recently completed second fiscal quarter March 31,
2004 was approximately $287.8 million.
The number of outstanding shares of the registrant's common stock on December 1,
2004 was 17,506,600 shares.
DOCUMENTS INCORPORATED BY REFERENCE
[None]
[THIS PAGE INTENTIONALLY LEFT BLANK]
RESOURCE AMERICA, INC. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT
ON FORM 10-K
Page
PART I
Item 1: Business.................................................................. 3 - 31
Item 2: Properties................................................................ 31 - 34
Item 3: Legal Proceedings......................................................... 35
Item 4: Submission of Matters to a Vote of Security Holders....................... 35
PART II
Item 5: Market for Registrant's Common Equity and Related Stockholder Matters..... 36
Item 6: Selected Financial Data................................................... 37
Item 7: Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................. 38 - 63
Item 7A: Quantitative and Qualitative Disclosures About Market Risk................ 64 - 67
Item 8: Financial Statements and Supplementary Data............................... 68 - 126
Item 9: Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................... 127
Item 9A: Controls and Procedures................................................... 127
Item 9B: Other Information......................................................... 127
PART III
Item 10: Directors and Executive Officers of the Registrant........................ 128 - 130
Item 11: Executive Compensation.................................................... 130 - 134
Item 12: Security Ownership of Certain Beneficial Owners and Management............ 135 - 136
Item 13: Certain Relationships and Related Transactions............................ 137 - 138
Item 14: Principal Accountant Fees and Services.................................... 139
PART IV
Item 15: Exhibits, Financial Statement Schedules and Reports on Form 8-K........... 140 - 141
SIGNATURES...................................................................................... 142
PART I
ITEM 1. BUSINESS
THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS REGARDING EVENTS
AND FINANCIAL TRENDS WHICH MAY AFFECT OUR FUTURE OPERATING RESULTS AND FINANCIAL
POSITION. SUCH STATEMENTS ARE SUBJECT TO RISKS AND UNCERTAINTIES THAT COULD
CAUSE OUR ACTUAL RESULTS AND FINANCIAL POSITION TO DIFFER MATERIALLY FROM THOSE
ANTICIPATED IN SUCH STATEMENTS. FOR OUR BUSINESS GENERALLY, THESE RISKS INCLUDE
THE PROBABILITY OF OUR SPIN-OFF OF OUR ENERGY OPERATIONS AND OUR PLANS AND
EXPECTATIONS FOR THE OPERATIONS THAT WE WILL RETAIN FOLLOWING THE SPIN-OFF. IN
OUR ENERGY BUSINESS, THESE RISKS INCLUDE THE NEED FOR ADDITIONAL CAPITAL AND
ABILITY TO RAISE THAT CAPITAL FROM INVESTORS IN OUR DRILLING PROGRAMS, RISKS
ASSOCIATED WITH EXPLORING, DEVELOPING AND OPERATING NATURAL GAS AND OIL WELLS,
AND FLUCTUATIONS IN THE MARKET FOR NATURAL GAS AND OIL. IN REAL ESTATE, THESE
RISKS INCLUDE RISKS OF THE MARKETABILITY OF REAL ESTATE PROGRAMS, LOAN DEFAULTS,
THE ADEQUACY OF OUR PROVISION FOR LOSSES AND THE ILLIQUIDITY OF OUR LOAN
PORTFOLIO. IN OUR EQUIPMENT LEASING AND STRUCTURED FINANCE BUSINESSES, THESE
RISKS INCLUDE THE EFFECTS OF FLUCTUATIONS IN INTEREST RATES AND THE
MARKETABILITY OF EQUIPMENT LEASING AND COLLATERALIZED DEBT OBLIGATION PROGRAMS.
FOR A MORE COMPLETE DISCUSSION OF THE RISKS AND UNCERTAINTIES TO WHICH WE ARE
SUBJECT, SEE "RISK FACTORS" IN THIS ITEM 1.
GENERAL
We are a specialized asset management company that uses industry
specific expertise to generate and administer investment opportunities for our
own account and for outside investors in the structured finance, equipment
leasing, real estate and energy sectors. As a specialized asset manager, we seek
to develop investment funds 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 funds 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 funds in addition
to the interest resulting from our investment. We managed approximately $4.2
billion in assets at the end of fiscal 2004, as follows:
o $ 2.6 billion of structured finance assets (63%); (1)
o $ 0.2 billion of equipment leasing assets (4%); (2)
o $ 0.4 billion of real estate assets (10%); (3) and
o $ 1.0 billion of energy assets (23%). (4)
- -----------------------
(1) We value our structured finance assets as the acquisition cost of
securities acquired by CDO issuers which we co-manage that acquired trust
preferred securities of regional banks and bank holding companies and the
acquisition cost of asset-backed securities acquired by us.
(2) We value our equipment leasing assets as the sum of the book values of
equipment held by us, an equipment leasing venture and an investment
partnership which we managed as of September 30, 2004.
(3) We value our managed real estate assets as the sum of the amount of our
outstanding loan receivables, including the loans underlying the assets and
liabilities consolidated pursuant to Financial Accounting Standards Board
Interpretation 46 as revised, or FIN 46R, plus the book value of our
interests in real estate and the sum of the book values of real estate and
other assets held by real estate investment partnerships we managed as of
September 30, 2004.
3
In fiscal 2004, in order to enhance shareholder value, we determined to
reorganize our company into two independent companies, with our company
continuing its asset management business in structured finance, equipment
leasing and real estate and our subsidiary, Atlas America, Inc. (NASDAQ: ATLS),
separately continuing the energy business. We took the first step in that
process in May 2004 with an initial public offering of common stock by Atlas
America and its use of the $37.0 million of net proceeds to pay us a non-taxable
dividend. We expect to complete the spin-off in fiscal 2005 by distributing our
remaining shares in Atlas America to our stockholders. However, we have sole
discretion if and when to complete the distribution and to determine its terms,
and do not intend to complete the distribution unless we receive a ruling from
the Internal Revenue Service and/or an opinion from our tax counsel as to the
tax-free nature of the distribution to us and our stockholders for U.S. federal
income tax purposes. The Internal Revenue Service requirements for tax-free
distributions of this nature are complex and the Internal Revenue Service has
broad discretion, so there is significant uncertainty as to whether we will be
able to obtain such a ruling. Because of this uncertainty and the fact that the
timing and completion of the distribution is in our sole discretion, we cannot
assure you that the distribution will occur. Pending completion of the spin-off,
we will continue to consolidate Atlas America's assets, liabilities and
operations with ours.
Following the spin-off, our continuing operations will use the
specialized asset management platform we have developed to sponsor and manage
public and private investment funds and their assets, focusing on the following:
o structured finance, principally funds issuing collateralized debt
obligations, or CDOs, backed by two principal asset classes;
- trust preferred securities of banks, bank holding companies and
insurance companies; and
- asset-backed securities or ABS.
o leasing small and mid-ticket business-essential equipment to small
to mid-size businesses; and
o real estate, principally investment partnerships focused on the
acquisition and management of multi-family apartment complexes.
We anticipate that our revenues following the spin-off will consist
principally of fees paid to us in connection with the formation of our
investment funds (including structuring, sales, acquisition and debt placement
fees) and on-going management and administration fees for our services in
managing our sponsored funds and their assets. We also expect to invest in our
sponsored funds, receiving incentive interests as well as a share of
distributions based upon the amount of our investment.
STRUCTURED FINANCE
We have co-sponsored, structured and currently co-manage seven CDO
issuers holding approximately $2.4 billion in bank and bank holding company
trust preferred securities. We have begun to expand and diversify our operations
by developing CDOs consisting of ABS.
- -----------------------
(4) We value our managed energy assets as the sum of the PV-10 (5) values, as
of September 30, 2004, 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, 2004, of the total assets of Atlas Pipeline
Partners, L.P.
(5) "PV-10 value" means, in accordance with guidelines of the Securities and
Exchange Commission, or SEC, the estimated future net cash flow to be
generated from the production of proved reserves discounted to present
value using an annual discount rate of 10%. This amount is calculated net
of estimated production costs and future development costs, using prices
and costs in effect as of a specified date, without escalation and without
giving effect to non-property or non-production related expenses such as
general administrative expenses, debt service or future income tax expense,
or to depreciation, depletion and amortization.
4
We own a 50% interest in an entity that manages five collateral pools
of trust preferred CDO issuers and a 33.33% interest in another entity that
manages one collateral pool of trust preferred CDO issuers. We also own a 50%
interest in the general partners of the limited partnerships that own the equity
interest of five of the Trapeza CDO issuers (known as the Trapeza Partnerships
and Structured Finance Fund). We also have invested as a limited partner in each
of these limited partnerships.
In June 2004, we formed a wholly-owned subsidiary, Ischus Capital
Management, LLC, to pursue development of and leverage our expertise in managing
CDO issuers. Ischus focuses on selecting, managing and investing in ABS. We
expect to form additional CDO issuers in other asset classes.
We derive revenues from our CDO operations through management and
administration fees. We also receive distributions on amounts we invest in the
limited partnerships. Management fees vary by CDO issuer, but have ranged from
between 0.25% and 0.60% of the collateral securities owned by the CDO issuers.
These fees are also shared with our co-sponsors. The fees are payable monthly or
semi-annually, as long as we continue as the collateral manager of the CDO
issuer. Our interest in distributions from the CDO issuers varies with the
amount of our investment in a particular limited partnership and with the terms
of our general partnership interest. In four of the partnerships, we have
incentive distribution interests. As of September 30, 2004, our investment in
limited partnership interests in the limited partnerships that own the equity of
the CDO issuers was $8.5 million.
We acquire collateral securities for our CDO issuers principally in
transactions with the issuers of those securities. We fund the initial
acquisition of the collateral securities through a warehouse credit facility
prior to the closing of a CDO issuer's offering. After the closing, the CDO
issuer acquires these collateral securities with the proceeds it receives from
the issuance of CDOs.
As part of the structuring process, we are responsible for the
evaluation of securities proposed for inclusion in the collateral pool by
originators. We analyze the creditworthiness of identified issuers and their
securities through a credit committee made up of individuals with expertise in
the asset classes to be acquired by the CDO issuer. Because CDOs must be rated
by one or more rating agencies in order for them to be eligible for many of the
institutional investors to whom they are marketed, the credit committees apply
rating agency standards when evaluating collateral securities for inclusion in a
CDO issuer's pool and then provide us with a recommendation on whether to
include or exclude the collateral from the pool.
EQUIPMENT LEASING
We operate our equipment leasing asset management business through our
subsidiary, LEAF Financial Corporation. LEAF Financial manages all aspects of
the equipment leasing process, from the origination of leases to the
end-of-lease asset disposition. After origination, LEAF Financial typically
transfers the leases either to investment partnerships sponsored by LEAF or to
third-party programs, with LEAF continuing to manage and service the lease
assets. Some leases are retained for its own account. LEAF Financial focuses on
originating small and mid-ticket equipment leases through strategic marketing
alliances and other program relationships with equipment vendors, commercial
banks and other financial institutions. The targeted lessees are small and
medium-sized companies across a wide array of industries. The primary leasing
transaction size is under $2.0 million with an average size between $50,000 and
$100,000. The equipment leased includes a wide array of business-essential
equipment, including general office, medical practice, energy and climate
control, and industrial equipment.
5
The following table sets forth certain information related to our
lessee's businesses and the concentration of our equipment on our leases under
management as of September 30, 2004, as a percentage of our total managed
portfolio:
LESSEE BUSINESS EQUIPMENT UNDER LEASE
--------------- ---------------------
Health Services 25% Industrial Equipment 14%
Personal Services 9% Software 9%
Business Services 8% Computer Systems 8%
Automotive Dealers 5% Medical Equipment 8%
Automotive Repair 5% Lasers 5%
Professional services 4% Machine Tools 5%
Wholesale Trade 3% Dry Cleaning 4%
Other Categories 41% Other Equipment Types 47%
--- ---
100% 100%
=== ===
We have sponsored two public equipment leasing partnerships, one of
which is in the operating stage and the other of which is in the pre-offering
stage. The operating investment partnership, Lease Equity Appreciation Fund I,
commenced operations in March 2003 and completed its offering period in August
2004, having raised $17.1 million of capital from investors. LEAF Financial
manages $47.6 million in leases for LEAF Fund I at September 30, 2004. LEAF
Financial received organization expense reimbursements, sales commissions and
acquisition fees in connection with the partnership's formation and receives
subordinated management fees and a general partner's interest for managing the
partnership and its assets. The pre-offering stage investment partnership, Lease
Equity Appreciation Fund II, expects its offering period will commence in
January 2005. LEAF Financial is the general partner of both investment
partnerships.
At the time we acquired LEAF Financial in 1995, it acted as the general
partner of a series of public equipment leasing partnerships. These partnerships
began their liquidation periods at various times commencing in December 1995.
The last four of these partnerships were liquidated in March 2004.
In April 2003, LEAF Financial entered into a Purchase, Sale and
Contribution Agreement with certain subsidiaries of Merrill Lynch, or ML. In
accordance with the these, we may sell and ML will purchase up to $300.0 million
of leases originated by us. LEAF earns fees from the sale of equipment leases to
ML and for servicing the ongoing portfolio.
During the years ended September 30, 2004 and 2003, LEAF originated
$149.5 million and $49.0 million in leases, respectively. As of September 30,
2004 and 2003, LEAF managed lease portfolios of $164.8 million and $63.0
million, respectively.
REAL ESTATE
General. Our real estate operations involve:
o the sponsorship and management of real estate investment
partnerships, which is the current focus of our real estate
operations; and
o the management and resolution of a portfolio of real estate loans
and property interests that we acquired at various times between
1991 and 1999.
6
Real Estate Investment Partnerships. We have sponsored two real estate
investment partnerships since 2003 which have raised a total of $25.3 million.
These partnerships, SR Real Estate Investors, L.P. and SR Real Estate Investors
II, L.P., acquired six multi-family apartment complexes. The aggregate
investment in the properties by both programs, including debt financing, was
$92.8 million. The combined market value of real estate controlled by both
programs is $106.7 million including minority interests owned by third parties.
We received acquisition and debt placement fees from the partnerships in their
acquisition stage, and receive management fees and distributions on our general
partner interests in their operational stage. We manage both the investment
partnerships as well as the properties.
Loan and Property Interest Portfolio. In addition to our real estate
investment partnerships, we also have a portfolio of real estate loans and
property interests. Between fiscal 1991 and 1999, our real estate operations
focused on the purchase of commercial real estate loans at discounts to their
outstanding loan balances and the appraised value of their underlying
properties. As a consequence of our ownership and management and resolution of
some of these loans, we have acquired direct and indirect property interests.
Since fiscal 1999, we have focused on managing and resolving our existing
portfolio. However, we may sell, purchase or originate portfolio loans or real
property investments in the future as part of our management process or as
opportunities arise. During fiscal 2004, we reduced the number of loans in our
portfolio through the repayment of seven loans and the restructuring of two
loans. We have retained interests in the properties underlying the restructured
loans. For information concerning the composition and status of our portfolio
and real estate loans and property interests, see "- Loan Status - Portfolio
Loans," " - Loan Status - Loans Held as FIN 46 Entities' Assets" and "-
Investments in Real Estate Owned."
Loan Status - Portfolio Loans. The following table sets forth
information about loans we hold in our portfolio, excluding loans consolidated
into our financial statements as a result of the adoption of FIN 46, as of
September 30, 2004 (in thousands):
Fiscal Appraised
Year Outstanding Value of
Type of Loan Loan Property Cost of
Loan Number Property Location Acquired Receivable(1) Loan(2) Investment(3)
- ----------- -------- -------- -------- ------------- ------- -------------
035(09)(10) Office Pennsylvania 1997 $ 2,915 $ 2,900 $ 3,512
041 Multifamily Connecticut 1998 21,265 23,500 14,737
013(09)(13) Single User/
Commercial California 1994 2,454 3,290 1,751
Single User/
018 Retail California 1996 3,647 6,990 2,865
-------- -------- --------
Single User Total 6,101 10,280 4,616
-------- -------- --------
Washington,
044 (11) Office DC 1998 29,626 21,705 9,848
Office Pennsylvania 2003 1,350 - 1,350
-------- -------- --------
Other Total 30,976 21,705 11,198
-------- -------- --------
Balance as of September 30, 2004 $ 61,257 $ 58,385 $ 34,063
======== ======== ========
Net Interest in
Carried Outstanding
Third Party Net Cost of Loan
Loan Number Liens(4) Investment(5) Investment(6) Receivables(7)
- ----------- -------- ------------- ------------- --------------
035 (09)(10) $ - $ 1,762 $ 2,627 $ 2,915
041 13,351 637 8,218 7,914
013 (09)(13) 2,273 (497) 67 181
018 1,967 896 1,279 1,680
-------- -------- -------- --------
4,240 399 1,346 1,861
-------- -------- -------- --------
044 (11) - 9,848 10,525 29,626
- 1,350 1,350 1,350
-------- -------- -------- --------
- 11,198 11,875 30,976
-------- -------- -------- --------
Balance as of September 30, 2004 $ 17,591 $ 13,996 $ 24,066 $ 43,666
======== ======== ======== ========
7
Loan status - Loans Held as FIN 46 Entities' Assets. The following
table sets forth information about loans consolidated into our financial
statements as a result of the adoption of FIN 46 as of September 30, 2004 (in
thousands):
Fiscal Appraised
Year Outstanding Value of
Type of Loan Loan Property Cost of
Loan Number Property Location Acquired Receivable(1) Loan(2) Investment(3)
- ----------- -------- -------- -------- ------------- ------- -------------
005 (8) Office Pennsylvania 1993 $ 13,218 $ 1,350 $ 2,295
029 Office Pennsylvania 1997 10,681 4,075 3,289
049 (12) Office Maryland 1998 117,804 93,000 95,254
-------- -------- --------
Office Total 141,703 98,425 100,838
-------- -------- --------
Condo/ 1995 &
015/028 Multifamily North Carolina 1997 7,644 3,000 2,789
032 Multifamily New Jersey 1997 15,339 11,000 7,404
050 Multifamily Illinois 1998 58,920 26,800 20,014
-------- -------- --------
Multifamily Total 81,903 40,800 30,207
-------- -------- --------
Single
007 (9)(14) User/
Retail Minnesota 1993 6,401 2,300 1,490
Single
User/
017 (9) Retail West Virginia 1996 1,784 1,600 904
-------- -------- --------
Single User Total 8,185 3,900 2,394
-------- -------- --------
Hotel/
025 Commercial Georgia 9,343 10,173 7,278
-------- -------- --------
Balance as of September 30, 2004 $241,134 $153,298 $140,717
======== ======== ========
Net Interest in
Carried Outstanding
Third Party Net Cost of Loan
Loan Number Liens(4) Investment(5) Investment(6) Receivables(7)
- ----------- -------- ------------- ------------- --------------
005 (8) $ - $ 2,295 $ 900 $ 13,218
029 - 3,289 3,199 10,681
049 (12) 56,616 35,254 35,476 61,188
-------- -------- -------- --------
56,616 40,838 39,575 85,087
-------- -------- -------- --------
015/028 2,758 (211) 292 4,886
032 - 7,404 11,097 15,339
050 14,694 4,664 7,106 44,226
-------- -------- -------- --------
17,452 11,857 18,495 64,451
-------- -------- -------- --------
007 (9)(14)
1,607 (609) 545 4,794
017 (9) 899 (95) 618 885
-------- -------- -------- --------
2,506 (704) 1,163 5,679
-------- -------- -------- --------
025 - 6,403 7,710 9,343
-------- -------- -------- --------
Balance as of September 30, 2004 $ 76,574 $ 58,394 $ 66,943 $164,560
======== ======== ======== ========
The following table reconciles the carried cost of investment for our
FIN 46 loans at September 30, 2004 (in thousands).
Assets held for sale...................................................................... $ 102,963
Liabilities associated with assets held for sale.......................................... (65,300)
FIN 46 entities' assets, net.............................................................. 30,567
Real estate owned and classified as held for sale, net of related debt.................... (1,287)
----------
Balance at September 30, 2004 - carried cost of investment................................ $ 66,943
==========
(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, 2004.
(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 refinancing.
(4) Represents the amount of the senior lien interests at September 30, 2004.
(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 refinancing 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 $989,000. For loans held as FIN 46
entities' assets, the carried cost represents our investment adjusted to
reflect the requirements of FIN 46.
(7) Consists of the amounts set forth in the column "Outstanding Loan
Receivable" less amounts in the column "Third Party Liens" at September 30,
2004.
8
(8) The borrower, Granite GEC (Pittsburgh), L.L.C., is a limited liability
company. Daniel G. Cohen, the son of Edward E. Cohen, our chairman, and the
brother of Jonathan Z. Cohen, our chief executive officer, owns 79% of
Odessa Real Estate Management, Inc., the assistant managing member of the
borrower.
(9) With respect to loans 7 and 17, Adam Kaufman, the president, chief
executive officer of Brandywine Construction and Management, Inc. (which
provides us with property management services and in which our chairman
holds a minority interest) 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 loan 35, Mr. Kauffman is the sole shareholder of
the general partner of the borrower. See Note 5 of our Notes to
Consolidated Financial Statements.
(10) The borrower, New 1521 Associates, is a limited partnership formed in 1991.
The general partner, New 1521 G.P., Inc., is a corporation of which Mr.
Kauffman is the sole shareholder. E. Cohen, and his wife, Betsy Z. Cohen,
beneficially own a 49% limited partnership interest in the partnership and
Mr. Kauffman owns a 24.75% limited partnership interest.
(11) The borrower, D. Cohen, is the Class B Limited Partner of Evening Star
Associates; the loan is guaranteed by The Avenue All Stars Limited
Partnership, the Class C Limited Partner of Evening Star Associates.
(12) The borrower, Commerce Place Associates, LLC, is a limited liability
company whose manager is a corporation of which Mr. Schaeffer, is the sole
shareholder, officer and director. Messrs. E. Cohen, D. Cohen, Schaeffer
and Kauffman are equal limited partners of an entity, Brandywine Equity
Investors, L.P., that owns approximately 30% of the borrower.
(13) E. Cohen and B. Cohen beneficially own a 40% limited partnership interest
in the borrower, Pasadena Industrial Associates. Mr. Kauffman is the
general partner of the borrower.
(14) The borrower, St. Cloud Associates, is a limited partnership of which Mr.
Kauffman is the sole general partner.
Management of Loan Portfolio and FIN 46 Entities' Assets. We seek to
reduce the amount of our capital invested in portfolio loans, including five
investments treated as FIN 46 entities' assets, and to enhance our returns,
through borrower refinancing of the properties underlying our loans. At
September 30, 2004, senior lien holders on these properties, including FIN 46
assets, held outstanding obligations of $94.2 million. Pursuant to agreements
with most borrowers, we generally retain the excess of operating cash flow after
required debt service on senior lien obligations as debt service on the
outstanding balance of our loans.
After a refinancing of a senior lien interest, our retained interest
will usually be secured by a subordinate lien on the property. In some
situations, however, our retained interest may not be formally secured by a
mortgage because of conditions imposed by the senior lender. In these
situations, we may be protected by a judgment lien, an unrecorded deed-in-lieu
of foreclosure, the borrower's covenant not to further encumber the property
without our consent, a pledge of the borrower's equity or similar devices. As of
September 30, 2004, we have eight retained interests aggregating $53.3 million
and constituting 59%, by carried cost of investment, of our loan portfolio and
FIN 46 assets that are not secured by a lien on the underlying property. As of
September 30, 2004, senior lien interests with an aggregate balance of $6.0
million relating to three portfolio loans obligate us, in the event of a default
on a loan, to replace the loan with a performing loan.
Because the loans in our portfolio typically were not performing in
accordance with their original terms when we acquired them, they generally are
subject to forbearance agreements that defer foreclosure or other action so long
as the borrower meets the terms of the forbearance agreement. These terms are
generally designed to give us control over the operations and cash flow of the
underlying properties, subject to the rights of senior lien holders. We may
permit a borrower to obtain management control of a property's cash flow where
we believe that operating problems have been substantially resolved.
9
Our forbearance agreements require borrowers to retain a property
management firm acceptable to us. As a result, Brandywine Construction &
Management, Inc., a property manager affiliated with us, has assumed
responsibility for supervisory and, in many cases, day-to-day management of the
underlying properties with respect to substantially our entire loan portfolio as
of September 30, 2004. In six instances, the president of Brandywine
Construction & Management, or an entity affiliated with him, has also acted as
the general partner, president or trustee of the borrower.
The minimum payments required under a forbearance agreement are
normally materially less than the debt service payments called for by the
original terms of the loan. The difference between the minimum required payments
under the forbearance agreement and the payments called for by the original loan
terms continues to accrue. However, except for amounts we recognize as accretion
of discount, we do not recognize the accrued but unpaid amounts as revenue until
actually paid. For a discussion of how we account for accretion of discount, you
should read "Real Estate-Accounting for Discounted Loans."
At the end of a forbearance agreement, the borrower must pay the loan
in full. The borrower's ability to do so, however, will depend upon a number of
factors, including prevailing conditions of the underlying property, the state
of real estate and financial markets generally and as they pertain to the
particular property, and general economic conditions. If the borrower does not
or cannot repay the loan, we anticipate it will seek to sell the property
underlying the loan or otherwise liquidate the loan. If the borrower is
unsuccessful, we may foreclose on the underlying property. Alternatively, where
we already control all of the cash flow and other economic benefits from the
property, or where we believe that the cost of foreclosure is more than any
benefit we could obtain from foreclosure, we may continue our forbearance.
Investments in Real Estate Owned. As part of the process of resolving
our loans, we may foreclose on a property underlying a loan or accept a
deed-in-lieu of foreclosure. In addition, when we restructure a loan, we may
retain an ownership interest in the underlying property or in an entity owning
the property. We had two restructurings in fiscal 2004, three in fiscal 2003 and
one in fiscal 2002. Moreover, in fiscal 2002 we invested in three limited
partnerships which acquired properties adjacent to a property in which we had
received a 50% interest in satisfaction of another portfolio loan in June 1999.
These adjacent properties were sold in March 2004.
Accounting for Discounted Loans. We accrete the difference between our
cost basis in a portfolio loan and the sum of projected cash flows from the loan
into interest income over the estimated life of the loan using the interest
method, which results in a level rate of interest over the life of the loan. We
review projected cash flows, which include amounts realizable from the
disposition of the underlying property, on a quarterly basis. Changes to
projected cash flows reduce or increase the amounts accreted into interest
income over the remaining life of the loan.
We record our investments in real estate loans at cost, which is
discounted 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 refinancing, totaled $19.6 million, $56.0 million and $165.2 million
at September 30, 2004, 2003 and 2002, respectively. We review the carrying value
of each of our loans quarterly to determine whether it is greater than the sum
of the future projected cash flows. Because of our knowledge of the underlying
properties, our monitoring of and influence over their respective operating
budgets and, for most properties, management of the property by our affiliate,
Brandywine Construction & Management, we believe that we can reasonably estimate
the amount and timing of our probable collections from the underlying
properties. For a discussion of our involvement with the properties underlying
our loans, see "Real Estate-Management of Loan Portfolio and FIN 46 Entities'
Assets." If we determine that the carrying value is greater, we provide an
appropriate allowance through a charge to operations. In establishing our
allowance for possible losses, we also consider the historic performance of our
loan portfolio, characteristics of the loans and their underlying properties,
industry statistics and experience regarding losses in similar loans, payment
history on specific loans as well as general economic conditions in the United
States, in the borrower's geographic area or in the borrower's or its tenants'
specific industries.
10
Allowance for Possible Losses. In determining an allowance for possible
losses related to our real estate assets, we consider general and local economic
conditions, neighborhood values, competitive overbuilding, casualty losses and
other factors which may affect the value of loans. The value of our real estate
assets may also be affected by factors such as the cost of compliance with
regulations and liability under applicable environment laws, changes in interest
rates and the availability of financing. Income from a property will be reduced
if a significant number of tenants are unable to pay rent or if available space
cannot be rented on favorable terms. In addition, we continuously monitor
collections and payments from our borrowers and maintain an allowance for
estimated losses based upon our historical experience and our knowledge of
specific borrower collection issues identified. We reduce our investment in real
estate assets by an allowance for amounts that may become unrealizable in the
future. Such allowance can be either specific to a particular loan, venture or
asset or general to all loans and assets.
ENERGY
General. Atlas America is engaged in the sponsorship of drilling
investment partnerships and the development, production and transportation of
natural gas and, to a lesser extent, oil in the western New York, eastern Ohio
and western Pennsylvania region of the Appalachian Basin and in the
transportation and sale of natural gas and natural gas liquids, or NGLs, in the
south central Oklahoma and north Texas region of the Mid-continent Basin area.
As of or during the fiscal year ended September 30, 2004:
o proved reserves net to Atlas America's interest grew to 155.8 bcfe
(1) at September 30, 2004 from 144.4 bcfe at September 30, 2003, and
the PV-10 value of these reserves grew to $320.4 million from $191.4
million. During the same period, proved reserves Atlas America
manages for its drilling investment partnerships and others grew to
209.4 bcfe from 187.8 bcfe, and the PV-10 value of these reserves
grew to $457.1 million from $273.5 million;
o as of September 30, 2004, Atlas America had an acreage position of
approximately 483,600 gross (433,200 net) acres, of which 249,800
gross (236,000 net) acres were undeveloped as compared to 431,200
gross (379,000 net) acres, of which 205,400 gross (190,500 net) were
undeveloped, at September 30, 2003;
o as of September 30, 2004, Atlas America had, either directly or
through its sponsored drilling partnerships, interests in
approximately 5,755 gross wells, including royalty and overriding
royalty interests in approximately 628 wells, as compared to
interests in approximately 5,300 gross wells, including royalty and
overriding royalty interests in over 600 wells, at September 30,
2003. Atlas America operates approximately 84% of the wells in which
it has interests;
o wells in which Atlas America had an interest produced, net to its
interest, approximately 19,900 mcf(1) of natural gas and 495
barrels, or bbls(1) of oil per day during fiscal 2004, compared to
19,100 mcf of natural gas and 438 bbls of oil per day during fiscal
2003;
o the number of wells Atlas America drilled, net to both its interest
and that of its sponsored drilling investment partnerships,
increased to 450 wells in fiscal 2004 from 282 wells in fiscal 2003.
Atlas America expects to drill approximately 650 net wells in fiscal
2005; and
- ---------------------------
(1) "mcfe," "mmcfe" and "bcfe" mean thousand cubic feet equivalent, million
cubic feet equivalent and billion cubic feet equivalent, respectively.
Natural gas volumes are converted to barrels, or "bbls," of oil equivalent
using the ratio of six thousand cubic feet, or "mcf" of natural gas to one
bbl of oil and are stated at the official temperature and pressure bases of
the area in which the reserves are located.
o as of September 30, 2004, Atlas America owned and operated,
principally through its minority-owned subsidiary, Atlas Pipeline
Partners, L.P., approximately 3,700 miles of natural gas gathering
systems, as compared to approximately 1,600 miles at September 30,
2003.
Atlas America funds its drilling activities through the sponsorship of
drilling investment partnerships. Although it have been raising capital through
drilling investment partnerships since 1968, the amount of the capital raised
through these partnerships has increased substantially since 1998. Atlas America
raised $111.9 million and $75.1 million in calendar 2004 and 2003, respectively
(historically our fund-raising cycle has been on a calendar year basis). Atlas
America acts as the general partner of its sponsored drilling investment
partnerships and receives both an interest proportionate to the amount of
capital and the value of the properties it contributes, typically 25 to 28%, and
a carried interest, typically 7%, both of which are subordinated to specified
returns to the investor partners for the first five years of distributions.
Accordingly, the amount of development activities Atlas America undertakes
depends upon its ability to obtain investor subscriptions to the partnerships.
During fiscal 2004, 2003 and 2002, Atlas America's drilling investment
partnerships invested $125.0 million, $68.6 million and $75.5 million,
respectively, in drilling and completing wells, of which it contributed $31.9
million, $15.7 million and $19.7 million, respectively.
Atlas America generally structures its drilling investment partnerships
so that, upon formation of a partnership, Atlas America contributes leaseholds
to it, enters into a drilling and well operating agreement with it and becomes
its general or managing partner. In addition to providing capital for Atlas
America's drilling activities, its drilling investment partnerships are a source
of fee-based revenue. Atlas America drills all of the partnership wells under
"cost plus" contracts for which it is paid the costs of drilling the wells plus
a fee equal to 15% of those costs. Atlas America also acts as well operator and
partnership manager, for which it receives monthly operating fees of
approximately $275 per well, approximately $187 net of our interest, and monthly
administrative fees of approximately $75 per well, approximately $51 net of our
interest.
Atlas America's business strategy for increasing its reserve base
includes acquisitions of undeveloped properties or companies with significant
amounts of undeveloped property. At September 30, 2004, Atlas America had $48.3
million available under its credit facility which could be employed to finance
such acquisitions. However, as a result of agreements with us relating to our
proposed spin-off of it, Atlas America is limited in its ability to issue voting
securities, non-voting securities or convertible debt and in making acquisitions
or entering into mergers or other business combinations that would jeopardize
the tax-free status of the distribution until such time as we complete or
terminate the spin-off.
Atlas Pipeline. We conduct our natural gas transportation operations
through Atlas Pipeline, whose common units are publicly traded (NYSE: APL). As
of September 30, 2004, Atlas Pipeline owned approximately 3,300 miles of
intrastate gathering systems located in New York, Ohio, Oklahoma, Pennsylvania
and Texas to which approximately 5,200 natural gas wells were connected. Atlas
Pipeline's gathering systems had an average daily throughput of 63.5 million
cubic feet, or mmcf, 52.7 mmcf and 49.7 mmcf of natural gas in fiscal 2004, 2003
and 2002, respectively. Atlas America also directly owns approximately 400 miles
of natural gas gathering systems in Ohio and Pennsylvania, whose throughputs are
not material.
Atlas Pipeline Partners GP, LLC, is an indirect wholly-owned subsidiary
of Atlas America and general partner of Atlas Pipeline. On a consolidated basis,
it has a 2% general partner interest in Atlas Pipeline. In addition, Atlas
Pipeline Partners GP owns 1,641,026 subordinated units of Atlas Pipeline,
constituting a 22% limited partner interest in it. Atlas Pipeline Partners GP
manages the activities of Atlas Pipeline using Atlas America personnel who act
as its officers and employees.
12
The subordinated units in Atlas Pipeline are a special class of
interest under which Atlas America's right to receive distributions is
subordinated to those of the publicly-held common units. The subordination
period is scheduled to expire on January 1, 2005 provided certain financial
tests specified in the partnership agreement are met. We expect that these tests
will be met. Upon expiration of the subordination period, Atlas America's
subordinated units will convert to an equal number of common units.
The incentive distribution rights are as follows:
o until the common units and subordinated units have received
distributions of $.10 per unit in excess of the $0.42 minimum
quarterly distribution, distributable cash is allocated, 85% to unit
holders (including to Atlas America as a subordinated unit holder)
and 15% to Atlas America as a general partner;
o after that, additional available cash is allocated 75% to unit
holders and 25% to Atlas America as a general partner until the
common units and subordinated units have received distributions of
$0.08 per unit; and
o after that, available cash is allocated 50% to unit holders and 50%
to Atlas America as a general partner.
Atlas America has agreements with Atlas Pipeline that require it to do
the following:
o pay gathering fees to Atlas Pipeline for natural gas produced by
Atlas America and its drilling investment partnerships and gathered
by the gathering systems equal to the greater of $0.35 per mcf
($0.40 per mcf in certain instances) or 16% of the gross sales price
of the natural gas transported. For the years ended September 30,
2004, 2003 and 2002, these gathering fees averaged $0.88, $0.75 and
$0.57 per mcf, respectively. The cost to Atlas America of paying
these fees is offset by the transportation fees paid to it by its
drilling investment partnerships, reimbursements and distributions
to it from Atlas Pipeline and connection costs and other expenses
paid by Atlas Pipeline;
o connect wells owned or controlled by Atlas America that are within
specified distances of Atlas Pipeline's gathering systems to those
gathering systems; and
o provide stand-by construction financing to Atlas Pipeline, at its
request, for gathering system extensions and additions, to a maximum
of $1.5 million per year, until January 2005. Atlas America has not
been required to provide any construction financing under this
agreement since Atlas Pipeline's inception.
Atlas America believes that it complies with all the requirements of
these agreements.
In April 2004 and July 2004, Atlas Pipeline completed public
offerings of 750,000 and 2,100,000 common units, respectively. The net proceeds
after underwriting discounts, commissions and costs were $25.2 million and $67.5
million, respectively.
13
Acquisition of Spectrum Field Services by Atlas Pipeline. In July 2004,
Atlas Pipeline acquired Spectrum Field Services for approximately $142.4
million, including transaction costs and taxes due as a result of the
transaction. This acquisition significantly increases Atlas Pipeline's size and
diversifies the natural gas supply basins in which it operates and the natural
gas midstream services it provides to its customers. Spectrum is a natural gas
gathering and processing company headquartered in Tulsa, Oklahoma. Spectrum's
business includes gathering natural gas from oil and gas wells and processing
this raw natural gas into merchantable natural gas, or residue gas, by
extracting NGLs and removing impurities. Spectrum's principal assets consist of
a gas processing plant in Velma, Oklahoma and approximately 1,100 miles of
active and 760 miles of inactive natural gas gathering pipelines in south
central Oklahoma and north Texas. Spectrum has approximately 600 active purchase
and gathering contracts. Of these, approximately 80% (by volume) are percentage
of proceeds, or POP, contracts. Under its POP purchasing arrangements, Spectrum
purchases natural gas at the wellhead, processes the natural gas by extracting
NGLs and removing impurities and sells the residue gas and NGLs at market-based
prices, remitting to producers a contractually determined percentage of the sale
proceeds. Unlike "keep whole" contracts, which require the processor to bear the
economic risk (called the processing margin risk) such that the aggregate
proceeds from the sale of the processed natural gas and NGLs could be less than
the amount that the processor paid for the unprocessed natural gas, POP
contracts protect the processor against processing margin risk. The remaining
20% of Spectrum's purchase and gathering contracts are fixed fee, under which
Spectrum receives a fee for gathering, compressing, treating and processing
natural gas. During fiscal 2004, Spectrum processed an average of 55.1 mmcf per
day of natural gas and produced an average of 5,917 bbls per day of NGLs. The
majority of Spectrum's natural gas supply is from relatively long-lived,
mid-continent casinghead gas production.
Atlas Pipeline financed the Spectrum acquisition, including
approximately $4.2 million of transaction costs, as follows:
o borrowing $100.0 million under the term loan portion of its $135.0
million senior secured term loan and revolving credit facility
administered by Wachovia Bank, National Association (for a
description of this credit facility, see "-Credit Facilities");
o using the $20.0 million of net proceeds received from its sale to
Atlas America and us of preferred units in Atlas Pipeline Operating
Partnership; and
o using $22.4 million of the net proceeds from its April 2004 common
unit offering.
Atlas Pipeline used a portion of the net proceeds of its July 2004
offering to repay $40.0 million of the borrowings under its credit facility and
to repurchase for $20.4 million the preferred units it issued to Atlas America
and us.
Alaska Pipeline Terminated Acquisition. In September 2003, Atlas
Pipeline entered into an agreement with SEMCO Energy, Inc. to purchase all of
the stock of Alaska Pipeline Company. In order to complete the acquisition,
Atlas Pipeline needed the approval of the Regulatory Commission of Alaska. The
Regulatory Commission initially approved the transaction, but on June 4, 2004 it
vacated its order of approval based upon a motion for clarification or
reconsideration filed by SEMCO. On July 1, 2004, SEMCO sent Atlas Pipeline a
notice purporting to terminate the transaction. Atlas Pipeline believes SEMCO
caused the delay in closing the transaction and breached its obligations under
the acquisition agreement. Atlas Pipeline is currently pursuing its remedies
under the acquisition agreement. In connection with the acquisition, subsequent
termination and current legal action, Atlas Pipeline incurred $3.0 million of
costs, which are shown as terminated acquisition costs and are included in our
energy expenses on our statement of operations. See Item 7, "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Results of Operations - Energy."
Natural Gas and Oil Properties. For information concerning Atlas
America's natural gas and oil properties, including the number of wells in which
it has a working interest, as well as reserve and acreage information, see Item
2, "Properties."
14
Production. For information concerning Atlas America's natural gas and
oil production quantities, average sales prices and average production costs,
see Item 2: "Properties."
Natural Gas Sales - Appalachian Basin. Atlas America has a natural gas
supply agreement with FirstEnergy Solutions Corp. for a 10-year term which began
on April 1, 1999. Subject to certain exceptions, FirstEnergy Solutions has a
last right of refusal to buy all of the natural gas produced and delivered by
Atlas America and its affiliates, including its drilling investment
partnerships, at certain delivery points with the facilities of:
o East Ohio Gas Company, National Fuel Gas Distribution, Columbia of
Ohio, and Peoples Natural Gas Company, which are local distribution
companies; and
o National Fuel Gas Supply, Columbia Gas Transmission Corporation,
Tennessee Gas Pipeline Company, and Texas Eastern Transmission
Company, which are interstate pipelines.
FirstEnergy Solutions is the marketing affiliate of FirstEnergy Corp.
(NYSE: FE), a large regional electric utility based in Akron, Ohio. FirstEnergy
Corp. has guaranteed the monetary obligations of FirstEnergy Solutions to a
maximum of $15.0 million through March 31, 2005, and thereafter on a monthly
basis unless terminated on 30 days notice.
A portion of Atlas America's drilling investment partnerships' natural
gas is subject to the agreement with FirstEnergy Solutions, with the following
exceptions:
o natural gas sold to Warren Consolidated, an industrial end-user and
direct delivery customer;
o natural gas that at the time of the agreement was already dedicated
for the life of the well to another buyer;
o natural gas that is produced by a company which was not an affiliate
of ours at the time of the agreement;
o natural gas sold through interconnects established subsequent to the
agreement;
o natural gas that is delivered to interstate pipelines or local
distribution companies other than those described above; and
o natural gas that is produced from well(s) operated by a third-party
or subject to an agreement under which a third-party was to arrange
for the gathering and sale of the natural gas.
Based on the most recent monthly production data available as of
November 30, 2004, Atlas America anticipates that it and its affiliates,
including its drilling investment partnerships, will sell approximately 50% of
their natural gas production under the FirstEnergy Solutions agreement. The
agreement also permits Atlas America to implement gas price hedges through
FirstEnergy Solutions, as described below under "--Natural Gas Hedging -
Appalachian Basin."
The agreement established an indexed price formula for each of the
delivery points during an initial period of one or two years, and requires the
parties to negotiate a new pricing arrangement at each delivery point for
subsequent periods. If, at the end of any applicable period, the parties cannot
agree to a new price for any delivery point, then Atlas America may solicit
offers from third-parties to buy the natural gas for that delivery point. If
FirstEnergy Solutions does not match this price, then Atlas America may sell the
natural gas to the third-party. This process is repeated at the end of each
contract period which is usually one year. Atlas America markets the remainder
of its natural gas, which is principally located in the Fayette County, PA area,
primarily to Colonial Energy, Inc. and UGI Energy Services and possibly others.
15
The pricing arrangements with FirstEnergy Solutions and the other third
parties are tied to the New York Mercantile Exchange, or NYMEX, monthly futures
contract price, which is reported daily in The Wall Street Journal. The total
price received for gas is a combination of the monthly NYMEX futures price plus
a negotiated fixed premium.
The agreement with FirstEnergy Solutions may be suspended for force
majeure, which means generally such things as an act of nature, fire, storm,
flood, and explosion, but also includes the permanent closing of the factories
of Carbide Graphite or Duferco Farrell Corporation during the term of
FirstEnergy Solutions' agreements to sell natural gas to them. If these
factories were closed, however, Atlas America believes that FirstEnergy
Solutions would be able to find alternative purchasers and would not invoke the
force majeure clause.
Atlas America expects that natural gas produced from its wells, other
than described above, will be primarily tied to the spot market price and
supplied to:
o gas marketers;
o local distribution companies;
o industrial or other end-users; and/or
o companies generating electricity.
Crude Oil Sales - Appalachian Basin. Crude oil produced from Atlas
America's wells flows directly into storage tanks where it is picked up by the
oil company, a common carrier, or pipeline companies acting for the oil company
which is purchasing the crude oil. Unlike natural gas, crude oil does not
present any transportation problem. Atlas America anticipates selling any oil
produced by its wells to regional oil refining companies at the prevailing spot
market price for Appalachian crude oil in spot sales.
Natural Gas and NGL Purchases and Sales - Spectrum. Chevron Texaco is
Spectrum's largest supplier of natural gas under a contract that has a
life-of-lease or 10-year term expiring in 2010 with a year-to-year renewal
provision. The 236 wells under Chevron Texaco's contract supply approximately 10
mmcf per day to the Spectrum system. Spectrum retains a weighted average of 47%
of the NGL revenues and a weighted average of 10% of the residue gas revenues
from sales of this gas. Spectrum's remaining natural gas contracts have varying
terms: the latest expiration date is 2008, with a few scheduled to terminate in
2005. The term of others has expired, but the producers continue to sell the
natural gas under the year-to-year renewal provisions.
In February 2004, Spectrum entered into a contract with Zinke & Trumbo
to gather and process natural gas from a new development northwest of Duncan,
Oklahoma. In March 2004, Spectrum completed a 29-mile, large-diameter
high-pressure trunkline to connect this new gas supply. The Duncan line is
currently delivering nine mmcf of natural gas per day.
Spectrum sells its NGL production to Koch Hydrocarbons at the Velma gas
plant under an agreement that is renewed monthly. Spectrum has the right to
elect (on a monthly basis) whether the NGLs are sold into the Mont Belvieu or
Conway markets. NGLs are priced at the average monthly Oil Price Information
Service price for the selected market. In addition, this agreement provides for
a fee which is based upon the Houston Ship Channel spot-gas price and fluctuates
monthly between $0.0125 and $0.015 per gallon for deliveries to Mont Belvieu.
Spectrum has a transportation and fractionation contract, also with
Koch Hydrocarbons, which expires January 2006. Condensate is collected at both
at the Velma gas plant and in the Velma gathering system and sold for Spectrum's
account to SemGroup, L.P. under an agreement with a primary term which expired
on November 30, 2004. The agreement continues on a month-to-month basis.
16
Spectrum sells natural gas to purchasers at the tailgate of the Velma
gas plant. During the year ended December 31, 2003, ONEOK Energy Marketing and
Trading accounted for 85% of Spectrum's residue natural gas sales and Tenaska
Marketing Ventures accounted for 15% of such sales. Spectrum currently sells the
majority of its residue natural gas at the average of ONEOK Gas Transmission and
Southern Star Central first-of-month indices as published in Inside FERC, with
the remainder being sold on a NYMEX basis, less a fixed basis differential.
Dismantlement, Restoration, Reclamation and Abandonment Costs. When
Atlas America determines that a well is no longer capable of producing natural
gas or oil in economic quantities, it must dismantle the well and restore and
reclaim the surrounding area before it can abandon the well. Atlas America
contracts these operations to independent service providers to whom it pays a
fee. The contractor will also salvage the equipment on the well, which Atlas
America then sells in the used equipment market. Under its drilling agreements,
Atlas America is allocated abandonment costs in proportion to its partnership
interest (generally between 27% and 35%) and is allocated between 65% and 100%
of the salvage proceeds. As a consequence, Atlas America generally receives
revenues from salvaged equipment at least equal to, and typically exceeding, its
share of the related costs. See Note 2 of the Notes to Consolidated Financial
Statements, "- Asset Retirement Obligations."
Natural Gas Hedging - Appalachian Basin. Pricing for natural gas and
oil production has been volatile and unpredictable for many years. To limit
exposure to changing natural gas prices, from time to time Atlas America used
hedges for its Appalachian Basin natural gas production. Through its hedges,
Atlas America seeks to provide a measure of stability in the volatile
environment of natural gas prices. These hedges may include purchases of
regulated NYMEX futures and options contracts and non-regulated over-the-counter
futures contracts with qualified counterparties. The futures contracts are
commitments to purchase or sell natural gas at future dates and generally cover
one-month periods for up to 24 months in the future. To assure that the
financial instruments will be used solely for hedging price risks and not for
speculative purposes, Atlas America has a committee to assure that all financial
trading is done in compliance with its hedging policies and procedures. Atlas
America does not intend to contract for positions that it cannot offset with
actual production. FirstEnergy Solutions and other third-party marketers to
which Atlas America sells gas, such as Colonial Energy, Inc. and UGI Energy
Services, also use NYMEX-based financial instruments to hedge their pricing
exposure and make price hedging opportunities available to Atlas America.
Forward Sales. Atlas America also enters into forward sales
transactions which are not deemed hedges for accounting purposes because they
require firm delivery of natural gas. Thus, Atlas America limits these
arrangements to much smaller quantities than those projected to be available at
any delivery point. The price paid by FirstEnergy Solutions, Colonial Energy,
Inc., UGI Energy Services, and any other third-party marketers for certain
volumes of natural gas sold under these sales agreements may be significantly
different from the underlying monthly spot market value.
The portion of natural gas that Atlas America engages in forward sales
and the manner in which it is sold (e.g., fixed pricing, floor and/or floor
price with a cap, which we refer to as a costless collar) changes from time to
time. As of September 30, 2004, Atlas America's overall forward sales position
for the future months ending March 2006 for its natural gas production was
approximately as follows:
o 48% was sold with a fixed price;
o 1% was sold with a floor price and/or costless collar price; and
o 51% was sold subject to market-based pricing.
17
Atlas America implemented approximately 69% of these forward sales
through FirstEnergy Solutions. For information concerning Atlas America's
natural gas hedging, see Item 7A, "Quantitative and Qualitative Disclosures
about Market Risk--Commodity Price Risk," and Note 14 of the Notes to
Consolidated Financial Statements.
Natural Gas and NGL Hedging - Spectrum. Spectrum also uses hedges to
limit its exposure to changing natural gas and NGL prices. These hedges include
floating-for-fixed swaps and collars. In a floating-for-fixed swap, Spectrum
sells future production to the counterparty at a fixed price and agrees to
purchase production from the counterparty at a price that will be established on
the date of hedge settlement by reference to a specified index price. In a
collar, Spectrum purchases a put option for specified production quantities
while simultaneously selling a call option on the same amount of production.
These hedges cover periods of up to two years from the date of the hedge. To
insure that these financial instruments will be used solely for hedging price
risks and not for speculative purposes, Spectrum has established a hedging
committee to review its hedges for compliance with its hedging policies and
procedures. In addition, Spectrum does not enter into a hedge where it cannot
offset the hedge with physical residue natural gas or NGL sales.
The portion of residue natural gas and NGLs that Spectrum hedges and
the manner in which it is hedged changes from time to time. As of September 30,
2004, Spectrum's hedging position for future months through December 31, 2006
for its residue and NGL production was approximately as follows:
o 36% was hedged under floating-for-fixed swaps;
o 8% was hedged with collars; and
o 56% was not hedged and was subject to market-based pricing.
Spectrum recognizes gains and losses from the settlement of its hedges
in revenue when it sells the associated physical residue natural gas or NGLs.
Any gain or loss realized as a result of hedging is substantially offset in the
market when Spectrum sells the physical residue natural gas or NGLs. All of
Spectrum's hedges are characterized as cash flow hedges as defined in Statement
of Financial Accounting Standards No. 133. Spectrum determines gains or losses
on open and closed hedging transactions as the difference between the hedge
price and the physical price. This mark-to-market uses daily closing NYMEX
prices when applicable and an internally generated algorithm for hedged
commodities that are not traded on a market.
Availability of Oil Field Services. Atlas America contracts for
drilling rigs and purchases goods and services necessary for the drilling and
completion of wells from a number of drillers and suppliers, none of which
supplies a significant portion of its annual needs. During fiscal 2004, Atlas
America faced no shortage of these goods and services. We cannot predict the
duration of the current supply and demand situation for drilling rigs and other
goods and services with any certainty due to numerous factors affecting the
energy industry and the demand for natural gas and oil.
Major Customers. During fiscal 2004, 2003 and 2002, gas sales to
FirstEnergy Solutions accounted for 11%, 18% and 16%, respectively, of our
energy revenues. Because Spectrum has historically sold its natural gas to two
principal customers, we expect that in fiscal 2005 they may account for over 10%
of our energy revenues.
18
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. Product availability and price are the principal means of
competition in selling oil and natural gas. Competition also is intense for the
acquisition of leases considered favorable for the development of natural gas
and oil in commercial quantities. Moreover, Atlas America may encounter
competition in obtaining drilling services from third party providers. Any
competition it encounters could delay it in drilling wells for its investment
partnerships. Many of Atlas America's competitors possess greater financial and
other resources than it does which may enable them to identify and acquire
desirable properties and market their natural gas and oil production more
effectively than Atlas America does. While it is impossible for us to accurately
determine Atlas America's comparative industry position, we do not consider its
operations to be a significant factor in the industry. Moreover, Atlas America
also competes with a number of other companies that offer interests in drilling
investment partnerships. As a result, competition for investment capital to fund
drilling investment partnerships is intense.
Atlas Pipeline's Appalachian Basin operations do not encounter direct
competition in their service areas since Atlas America controls the majority of
the drillable acreage in each area. However, because its Appalachian Basin
operations principally serve wells drilled by Atlas America, Atlas Pipeline is
affected by competitive factors affecting Atlas America's ability to obtain
properties and drill wells, which affects Atlas Pipeline's ability to expand
their gathering systems and to maintain or increase the volume of natural gas
they transport and, thus, their transportation revenues. Atlas America may also
encounter competition in obtaining drilling services from third-party providers.
Any competition Atlas America encounters could delay Atlas America in drilling
wells for its sponsored partnerships, and thus delay the connection of wells to
Atlas Pipeline's gathering systems.
Atlas Pipeline's omnibus agreement with Atlas America generally
requires Atlas America to connect wells it operates to Atlas Pipeline's system.
Atlas Pipeline does not expect any direct competition in connecting wells
drilled and operated by Atlas America in the future. In addition, Atlas Pipeline
occasionally connects wells operated by third parties.
In its southern Oklahoma and north Texas service area, Spectrum
competes for the acquisition of well connections with several other
gathering/servicing operations. These operations include plants operated by Duke
Energy Field Services, ONEOK Field Services and Enogex. Spectrum believes that
the principal factors upon which competition for new well connections is based
are:
o the price received by an operator for its production after deduction
of allocable charges, principally the use of the natural gas to
operate compressors; and
o responsiveness to a well operator's needs.
If Spectrum cannot compete successfully, it may be unable to obtain new
well connections and, possibly, could lose wells already connected to its
system.
19
Markets. The availability of a ready market for natural gas and oil,
and the price obtained, depends upon numerous factors beyond Atlas America's
control, as described in "- Risk Factors - Risks Relating to Our Energy
Business." During fiscal 2004, 2003 and 2002, neither Atlas America nor Spectrum
experienced any problems in selling its natural gas and oil, although prices
have varied significantly during and after those periods.
Regulation of Production. The production of natural gas and oil is
subject to a wide range of local, state and federal statutes, rules, orders and
regulations. Federal, state and local statutes and regulations require permits
for drilling operations, drilling bonds and reports concerning operations. All
of the states in which Atlas America owns and operates properties have
regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum allowable rates of production from oil and natural gas wells, drilling
operations, well spacing, and plugging and abandonment of wells. The effect of
these regulations is to limit the amount of natural gas and oil that Atlas
America can produce from its wells and to limit the number of wells or the
locations at which it can drill, although it can apply for exceptions to such
regulations or to have reductions in well spacing. Moreover, each state
generally imposes a production or severance tax with respect to the production
and sale of oil, natural gas and NGLs within its jurisdiction.
The failure to comply with these rules and regulations can result in
substantial penalties. Our competitors in the oil and natural gas industry are
subject to the same regulatory requirements and restrictions that affect our
operations.
Regulation of Transportation and Sale of Natural Gas. Natural gas
pipelines generally are subject to regulation by the Federal Energy Regulatory
Commission, or FERC, under the Natural Gas Act of 1938. However, because Atlas
Pipeline performs primarily a gathering function as opposed to the
transportation of natural gas in interstate commerce, we believe that it is not
subject to regulation under the Natural Gas Act. However, Atlas Pipeline
delivers a significant portion of the natural gas it transports to interstate
pipelines subject to FERC regulation. In the past, the federal government has
regulated the prices at which natural gas could be sold. While sales by
producers of natural gas can currently be made at uncontrolled market prices,
Congress could reenact price controls in the future. Deregulation of wellhead
natural gas sales began with the enactment of the Natural Gas Policy Act. In
1989, Congress enacted the Natural Gas Wellhead Decontrol Act. The Decontrol Act
removed all Natural Gas Act and Natural Gas Policy Act price and non-price
controls affecting wellhead sales of natural gas effective January 1, 1993.
Since 1985, the FERC has endeavored to make natural gas
transportation more accessible to natural gas buyers and sellers on an open and
non-discriminatory basis. The FERC has stated that open access policies are
necessary to improve the competitive structure of the interstate natural gas
pipeline industry and to create a regulatory framework that will put natural gas
sellers into more direct contractual relations with natural gas buyers by, among
other things, unbundling the sale of natural gas from the sale of transportation
and storage services. Beginning in 1992, the FERC issued Order No. 636 and a
series of related orders to implement its open access policies. As a result of
the Order No. 636 program, the marketing and pricing of natural gas have been
significantly altered. The interstate pipelines' traditional role as wholesalers
of natural gas has been eliminated and replaced by a structure under which
pipelines provide transportation and storage service on an open access basis to
others who buy and sell natural gas. Although the FERC's orders do not directly
regulate natural gas producers, they are intended to foster increased
competition within all phases of the natural gas industry.
20
In 2000, the FERC issued Order No. 637 and subsequent orders, which
imposed a number of additional reforms designed to enhance competition in
natural gas markets. Among other things, Order No. 637 revised the FERC's
pricing policy by waiving price ceilings for short-term released capacity for a
two-year experimental period, and effected changes in FERC regulations relating
to scheduling procedures, capacity segmentation, penalties, rights of first
refusal and information reporting. Most pipelines' tariff filings to implement
the requirements of Order No. 637 have been accepted by the FERC and placed into
effect. While most major aspects of Order No. 637 have been upheld on judicial
review, certain issues such as capacity segmentation and right of first refusal
were remanded to the FERC for further action. The FERC recently issued an order
affirming Order No. 637. We cannot predict what action the FERC will take on
these matters in the future, or whether the affected parties will seek, or the
FERC's actions will survive further judicial review.
Intrastate natural gas transportation is subject to regulation by state
regulatory agencies. The basis for intrastate regulation of natural gas
transportation and the degree of regulatory oversight and scrutiny given to
intrastate natural gas pipeline rates and services varies from state to state.
Insofar as regulation by a particular state will generally affect all intrastate
natural gas shippers within the state on a comparable basis, we believe that
Atlas Pipeline will not be affected in any way that materially differs from the
effects on its competitors.
Environmental and Safety Regulation. Under the Comprehensive
Environmental Response, Compensation and Liability Act, the Toxic Substances
Control Act, the Resource Conservation and Recovery Act, the Oil Pollution Act
of 1990, the Clean Air Act, and other federal and state laws relating to the
environment, owners and operators of wells producing natural gas or oil, and
pipelines, can be liable for fines, penalties and clean-up costs for pollution
caused by the wells or the pipelines. Moreover, the owners' or operators'
liability can extend to pollution costs from situations that occurred prior to
their acquisition of the assets. Natural gas pipelines are also subject to
safety regulation under the Natural Gas Pipeline Safety Act of 1968 and the
Pipeline Safety Act of 1992 which, among other things, dictate the type of
pipeline, quality of pipeline, depth, and methods of welding and other
construction-related standards. State public utility regulators have either
adopted federal standards or promulgated their own safety requirements
consistent with the federal regulations.
We do not anticipate that Atlas America or Atlas Pipeline will be
required in the near future to expend amounts that are material in relation to
our respective revenues by reason of environmental laws and regulations, but
since these laws and regulations change frequently, we cannot predict the
ultimate cost of compliance.
CREDIT FACILITIES
Atlas America has a $75.0 million credit facility administered by
Wachovia Bank, National Association. The revolving credit facility is guaranteed
by Atlas America's subsidiaries and us as long as we continue to own more than
80% of Atlas America. Up to $10.0 million of the borrowings under the facility
may be in the form of a standby letters of credit. Borrowings under the facility
are secured by the assets of Atlas America and its subsidiaries, including the
stock of Atlas America's subsidiaries. At September 30, 2004, $25.0 million was
outstanding under this facility.
Loans under the facility bear interest at one of the following two
rates, at Atlas America's election:
o the base rate plus the applicable margin; or
o the adjusted London Interbank Offered Rate, or LIBOR, plus the
applicable margin.
21
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 Board of Governors of the Federal
Reserve System 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, 2004, borrowings under the Wachovia credit facility
bore interest at rates ranging from 3.59% to 5.0%, with an average rate of 4.1%.
The Wachovia credit facility requires Atlas America to maintain
specified net worth and specified ratios of current assets to current
liabilities and debt to earnings before interest, taxes, depreciation, depletion
and amortization, or EBITDA, and requires us to maintain a specified interest
coverage ratio as long as we continue to own more than 80% of Atlas America. 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 50% of its cumulative net income from January 1, 2004 to the
date of determination plus $5.0 million and prohibits Atlas America from
declaring or paying a dividend during an event of default under the facility or
if the dividend would cause an event of default. As of September 30, 2004, Atlas
America would be permitted to pay dividends of $13.1 million under these
restrictions. The facility terminates in March 2007, when all outstanding
borrowings must be repaid.
Concurrently with the completion of the Spectrum acquisition in July
2004, Atlas Pipeline entered into a new $135.0 million senior secured term loan
and revolving credit facility administered by Wachovia Bank that replaced its
existing $20.0 million facility. The facility originally included a $35.0
million four year revolving line of credit which could be increased by an
additional $40.0 million under certain circumstances and a $100.0 million five
year term loan. Upon the completion of its July 2004 public offering, Atlas
Pipeline repaid $40.0 million of the $100.0 million term loan it had borrowed in
order to complete the acquisition of Spectrum. In August 2004, the revolving
credit lenders under the revolving credit portion of the facility agreed to
increase the amount available under the revolving credit portion to $75.0
million. Up to $5.0 million of the facility may be used for standby letters of
credit. Borrowings under the facility will be secured by a lien on and security
interest in all of Atlas Pipeline's property and that of its subsidiaries and by
the guaranty of each of its subsidiaries. The credit facility bears interest at
one of two rates, elected at Atlas Pipeline's option:
o the base rate plus the applicable margin; or
o the adjusted LIBOR plus the applicable margin.
The base rate for any day equals the higher of the federal funds rate
plus 1/2 of 1% or the Wachovia Bank prime rate. Adjusted LIBOR is LIBOR divided
by 1.00 minus the percentage prescribed by the Board of Governors of the Federal
Reserve System for determining the reserve requirement for euro currency
funding. The applicable margin for the revolving line of credit is as follows:
o where its leverage ratio, that is, the ratio of Atlas Pipeline's
debt to earnings before income, taxes, depreciation and
amortization, or EBITDA, is less than or equal to 2.5, the
applicable margin is 1.00% for base rate loans and 2.00% for LIBOR
loans;
o where its leverage ratio is greater than 2.5 but less than or equal
to 3.0, the applicable margin is 1.25% for base rate loans and 2.25%
for LIBOR loans;
22
o where its leverage ratio is greater than 3.0 but less than or equal
to 3.5, the applicable margin is 1.75% for base rate loans and 2.75%
for LIBOR loans; and
o where its leverage ratio is greater than 3.5, the applicable margin
is 2.25% for base rate loans and 3.25% for LIBOR loans.
The applicable margin for the term loan is .75% higher for both base
rate loans and LIBOR loans.
The credit facility requires Atlas Pipeline to maintain a ratio of
funded debt to EBITDA of not more than 4.25 to 1.0, reducing to 4.0 to 1.0 on
December 31, 2004 and 3.5 to 1.0 on June 30, 2005 and an interest coverage ratio
of not less than 3.0 to 1.0. In addition, Atlas Pipeline will be required to
prepay the term loan with the net proceeds of any asset sales or issuances of
debt. With respect to any issuances of equity, it will be required to repay the
term loan from the proceeds of such issuances to the extent its ratio of funded
debt to EBITDA exceeds 3.5 to 1.0. Atlas Pipeline is required to pay down
$750,000 in principal on the outstanding balance of the term loan quarterly. Any
prepayments of principal with proceeds from asset or equity sales will be
credited pro rata against this repayment obligation.
The credit agreement contains covenants customary for loans of this
size, including restrictions on incurring additional debt and making material
acquisitions, and a prohibition on paying distributions to Atlas Pipeline's
unitholders if an event of default occurs. The events which constitute an event
of default are also customary for loans of this size, including payment
defaults, breaches of Atlas Pipeline's representations or covenants contained in
the credit agreement, adverse judgments against it in excess of a specified
amount, and a change of control of its general partner.
Through our real estate subsidiaries, we have an $18.0 million line of
credit with Sovereign Bank. The facility bears interest at the prime rate
reported in The Wall Street Journal and expires in July 2005. Advances under
this facility must be used to acquire real property, loans on real property or
to reduce indebtedness on property loans. The facility is secured by the
interest of our subsidiaries in assets they acquire using advances under the
line of credit. Credit availability is based on the value of the assets pledged
as security and was $18.0 million as of September 30, 2004, none 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.
LEAF Financial entered into revolving credit facilities with National
City Bank and Commerce Bank that have an aggregate borrowing limit of $35.0
million. Each facility bears interest at LIBOR plus 300 basis points at the time
of borrowing. Borrowings under the facilities are secured by an assignment of
the leases being financed and the underlying equipment being leased. Repayment
of both facilities has been guaranteed by us. The facility with National City
Bank expires on April 30, 2005. At September 30, 2004, $8.5 million was
outstanding on this facility at interest rates ranging from 4.1% to 4.8% with an
average rate of 4.3% during fiscal 2004. The facility with Commerce Bank expires
on November 30, 2005. At September 30, 2004, $9.6 million was outstanding on
this facility at interest rates ranging from 4.1% to 4.7% with an average
interest rate of 4.4% during fiscal 2004.
EMPLOYEES
As of September 30, 2004, we employed 332 persons: 227 in energy, 64 in
equipment leasing, 14 in real estate, eight in structured finance and 19
corporate employees.
23
RISK FACTORS
General
Interest rate increases will increase our interest costs. See Item 7A,
"Quantitative and Qualitative Disclosures about Market Risk." This could have
material adverse effects on us, including reduction of net income for our
structured finance, equipment leasing, real estate and energy operations.
Our business strategy in structured finance, equipment leasing and real
estate and Atlas America's strategy in energy, depends upon our ability to
obtain capital through the sponsorship of investment funds which, in turn,
depends upon a number of factors discussed in this section and elsewhere in this
report. If we are unable to raise capital through these funds, our ability to
increase our managed assets and revenues will be limited and our profitability
may decline.
Subsidiaries of ours currently serve as general partners of two public
equipment leasing partnerships, including one in the pre-offering stage, three
private real estate investment partnerships, including one in the offering
stage, seven private investment partnerships that have invested and will invest
in CDO issuers, one of which is in the offering stage, 87 drilling investment
partnerships and Atlas Pipeline. We intend to develop further investment
partnerships for which our subsidiaries will act as general partner. As a
general partner, each subsidiary is contingently liable for the obligations of
these partnerships to the extent that their obligations cannot be repaid from
partnership assets or insurance proceeds.
Risks Relating to Our Structured Finance, Equipment Leasing and Real Estate
Operations
We account for our investment in the Trapeza CDO programs, described in
"Business-Structured Finance," under the equity method of accounting.
Accordingly, we recognize our percentage share of any income or loss of these
entities. Because the Trapeza entities are investment companies for accounting
purposes, such income or loss includes a "mark-to-market" adjustment to reflect
the net changes in value, including unrealized appreciation or depreciation, in
investments and swap agreements. Such value will be impacted by changes in the
underlying quality of the Trapeza entities' investments, and by changes in
interest rates. To the extent that the Trapeza entities' investments are
securities with a fixed rate of interest, increases in interest rates will
likely cause the value of the investments to fall and decreases in interest
rates will likely cause the value of the investments to rise. The Trapeza
entities' various interest rate hedges and swap agreements will also change in
value with changes in interest rates. In addition, as the equity interests that
we hold in the Trapeza CDO issuers are terminated, we obtain a return of capital
only after all payments are made on the CDOs. If there are defaults on the
collateral securities held by the Trapeza CDO issuers, our distributions and
return of capital upon liquidation may be reduced or eliminated. Accordingly,
our income or loss from our Trapeza investments, and from future similar CDO
issuer investments, may be volatile.
The primary or sole source of recovery for our real estate loans and
property interests is typically the underlying real property. Accordingly, the
value of our loans and property interests depends upon the value of that real
property. Many of the properties underlying our portfolio loans, while income
producing, do not generate sufficient revenues to pay the full amount of debt
service required under the original loan terms or have other problems. There may
be a higher risk of default with these loans as compared to conventional loans.
Loan defaults will reduce our current return on investment and may require us to
become involved in expensive and time-consuming bankruptcy, reorganization or
foreclosure proceedings.
24
Our loans, including those treated in our consolidated financial
statements as FIN 46 assets and liabilities, typically provide payment
structures other than equal periodic payments that retire a loan over its
specified term, including structures that defer payment of some portion of
accruing interest, or defer repayment of principal, until loan maturity. Where a
borrower must pay a loan balance in a large lump sum payment, its ability to
satisfy this obligation may depend upon its ability to obtain suitable
refinancing or otherwise to raise a substantial cash amount, which we do not
control. In addition, lenders can lose their lien priority in many
jurisdictions, including those in which our existing loans are located, to
persons who supply labor or materials to a property. For these and other
reasons, the total amount which we may recover from one of our loans may be less
than the total amount of the carrying value 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 estate properties may also be affected by factors
such as the cost of compliance with, and liability under environmental laws,
changes in interest rates and the availability of financing. Income from a
property will be reduced if a significant number of tenants are unable to pay
rent or if available space cannot be rented on favorable terms. Operating and
other expenses of properties, particularly significant expenses such as real
estate taxes, insurance and maintenance costs, generally do not decrease when
revenues decrease and, even if revenues increase, operating and other expenses
may increase faster than revenues.
Many of our portfolio loans, including those treated in our
consolidated financial statements as FIN 46 assets and liabilities, are junior
lien obligations. Subordinate lien financing poses a greater credit risk,
including a substantially greater risk of nonpayment of interest or principal,
than senior lien financing. If we or any senior lender forecloses on a loan, we
will be entitled to share only in the net foreclosure proceeds after payment to
all senior lenders. It is therefore possible that we will not recover the full
amount of a foreclosed loan or the amount of our unrecovered investment in the
loan.
At September 30, 2004, our allowance for possible losses was $989,000,
which represents 2.1% of the book value of our investments in real estate loans
and property interest. We cannot assure you that this allowance will prove to be
sufficient to cover future losses, or that future provisions for losses will not
be materially greater than those we have recorded to date. Losses that exceed
our allowance for losses, or cause an increase in our provision for losses,
could materially reduce our earnings.
The loans in our portfolio, including those treated in our consolidated
financial statements as FIN 46 assets and liabilities, typically do not conform
to standard loan underwriting criteria. Many of our loans are subordinate loans.
As a result, our loans are relatively illiquid investments. We may be unable to
vary our portfolio in response to changing economic, financial and investment
conditions.
The existence of hazardous or toxic substances on a property will
reduce its value and our ability to sell the property in the event of a default
in the loan it underlies. Contamination of a real property by hazardous
substances or toxic wastes not only may give rise to a lien on that property to
assure payment of the cost of remediation, but also can result in liability to
us as a lender, or, if we assume ownership or management, as an owner or
operator, for that cost regardless of whether we know of, or are responsible
for, the contamination. In addition, if we arrange for disposal of hazardous or
toxic substances at another site, we may be liable for the costs of cleaning up
and removing those substances from the site, even if we neither own nor operate
the disposal site. Environmental laws may require us to incur substantial
expenses to remediate contaminated properties and may materially limit use of
these properties. In addition, future laws or more stringent interpretations or
enforcement policies with respect to existing laws may increase our exposure to
environmental liability.
25
Our income from our loans includes accretion of discount, which is a
non-cash item. For a discussion of accretion of discount, see "Business - Real
Estate- Accounting for Discounted Loans." For the years ended September 30,
2004, 2003 and 2002, accretion of discount, net of collection of interest, was
$1.9 million, $2.0 million and $3.2 million, respectively. We accrete income on
a loan to a maximum amount equal to the difference between our cost basis in the
loan and the present value of the estimated cash flows from the property
underlying the loan. If the actual cash flows from the property are less than
our estimates, or if we reduce our estimates of cash flows, our earnings may be
adversely affected. Moreover, if we sell a loan, or foreclose upon and sell the
underlying property, and the amount we receive is less than the amount of our
carrying cost, we will recognize an immediate charge to our allowance for losses
or, if that amount is insufficient to absorb the shortfall and provide for
possible losses on remaining real estate investments, our statement of
operations.
In addition, the property owners have obtained senior lien financing
with respect to eight loans, including three treated as FIN 46 entities' assets.
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.
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, 2004, the participations as to which we had standby commitments
had aggregate outstanding balances of $6.0 million. At September 30, 2004, we
also were contingently liable under guarantees of $730,000 in mortgage loan
receivables connected with a discontinued operation and contingently liable
under guarantees of $4.0 million in standby letters of credit issued in
connection with Atlas America's, Atlas Pipeline's and our lease of office space
in New York City.
Risks Relating to Our Energy Business
Until we spin-off Atlas America, our future financial condition and
results of operations, and the value of our natural gas and oil properties, will
depend to a significant extent upon the market prices Atlas America receives for
its natural gas and oil. Natural gas and oil prices historically have been
volatile and will likely continue to be volatile in the future. Prices Atlas
America has received during its past three fiscal years for its natural gas have
ranged from a high of $6.16 per mcf in the quarter ended June 30, 2004 to a low
of $3.39 per mcf in the quarter ended December 31, 2001. Prices for natural gas
and oil are dictated by supply and demand. The factors affecting supply include:
o the availability of pipeline capacity;
o domestic and foreign governmental regulations and taxes;
o political instability or armed conflict in oil producing regions or
other market uncertainties; and
26
o the ability of the members of the Organization of Petroleum
Exporting Countries to agree to and maintain oil prices and
production controls.
The factors affecting demand include:
o weather conditions;
o the price and availability of alternative fuels;
o the price and level of foreign imports; and
o the overall economic environment.
These factors and the volatility of the energy markets make it
extremely difficult to predict future oil and gas price movements with any
certainty. Price fluctuations can materially adversely affect Atlas America
because:
o price decreases will reduce the amount of cash flow available to it
for drilling and production operations and for its capital
contributions to its drilling investment partnerships;
o price decreases may make it more difficult to obtain financing for
Atlas America's drilling and development operations through
sponsored drilling investment partnerships, borrowing or otherwise;
o price decreases may make some reserves uneconomic to produce,
reducing Atlas America's reserves and cash flow; and
o price decreases may cause the lenders under Atlas America's credit
facility to reduce its borrowing base because of lower revenues or
reserve values, reducing its liquidity and, possibly, requiring
mandatory loan repayment.
Further, oil and gas prices do not necessarily move in tandem. Because
approximately 92% of Atlas America's proved reserves are currently natural gas
reserves, it is more susceptible to movements in natural gas prices.
The amount of recoverable natural gas and oil reserves may vary
significantly from well to well. While the average estimated ultimate recovery
from Atlas America's wells is 150 mmcfe per well, recoverable natural gas from
individual wells ranges up to 1.556 bcfe. Atlas America may drill wells that,
while profitable on an operating basis, do not produce sufficient net revenues
to return a profit after drilling, operating and other costs are taken into
account. The geologic data and technologies available do not allow Atlas America
to know conclusively before 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. For example, Atlas America has in recent years
experienced increases in the cost of tubular steel as a result of rising steel
prices which will increase well costs. Further, Atlas America's drilling
operations may be curtailed, delayed or cancelled as a result of many factors,
including:
o title problems;
o environmental or other regulatory concerns;
o costs of, or shortages or delays in the availability of, oil field
services and equipment;
o unexpected drilling conditions;
o unexpected geological conditions;
o adverse weather conditions; and
o equipment failures or accidents.
27
Any one or more of the factors discussed above could reduce or delay
Atlas America's receipt of drilling and production revenues, thereby reducing
its earnings and could reduce revenues in one or more of its drilling investment
partnerships, which may make it more difficult for it to finance its drilling
operations through sponsorship of future partnerships.
As part of Atlas America's business strategy, Atlas America continually
seeks acquisitions of gas and oil properties and companies. It completed two
property acquisitions in fiscal 2001, one from Kingston Oil Corporation and one
from American Refining and Exploration Company, and has acquired two oil and gas
companies, Viking Resources in fiscal 1999 and The Atlas Group in fiscal 1998,
that owned substantial natural gas and oil properties. The successful
acquisition of natural gas and oil properties requires assessment of many
factors, which are inherently inexact and may be inaccurate, including the
following:
o future oil and natural gas prices;
o the amount of recoverable reserves;
o future operating costs;
o future development costs,
o costs and timing of plugging and abandoning wells; and
o potential environmental and other liabilities.
Atlas America's assessment will not necessarily reveal all existing or
potential problems, nor will it permit it to become familiar enough with the
properties to assess fully their capabilities and deficiencies. With respect to
properties on which there is current production, Atlas America may not inspect
every well, platform or pipeline in the course of our due diligence. Inspections
may not reveal structural and environmental problems such as pipeline corrosion
or groundwater contamination. Atlas America may not be able to obtain or recover
on contractual indemnities from the seller for liabilities that the seller
created. Atlas America may be required to assume the risk of the physical
condition of the properties in addition to the risk that the properties may not
perform in accordance with its expectations.
Atlas America bases its estimates of proved natural gas and oil
reserves and future net revenues from those reserves upon analyses that rely
upon various assumptions, including those required by the Securities and
Exchange Commission, as to natural gas and oil prices, taxes, development
expenses, capital expenses, operating expenses and availability of funds. Any
significant variance in these assumptions, and, with respect to Atlas America's,
assumptions concerning natural gas prices, could materially affect the estimated
quantity of its reserves. As a result, Atlas America's estimates of its proved
natural gas and oil reserves are inherently imprecise. Actual future production,
natural gas and oil prices, taxes, development expenses, operating expenses,
availability of funds and quantities of recoverable natural gas and oil reserves
may vary substantially from its estimates or estimates contained in the reserve
reports referred to elsewhere in this report. Atlas America's properties also
may be susceptible to hydrocarbon drainage from production by other operators on
adjacent properties. In addition, its proved reserves may be revised downward or
upward based upon production history, results of future exploration and
development, prevailing natural gas and oil prices, governmental regulation and
other factors, many of which are beyond its control.
At September 30, 2004, approximately 30% of Atlas America's estimated
proved reserves were undeveloped. Recovery of undeveloped reserves generally
requires significant capital expenditures and successful drilling operations.
The reserve data assumes that Atlas America will obtain the necessary capital
and conduct these operations successfully which, for the reasons discussed
elsewhere in this section, may not occur.
28
Atlas America's proved reserves will decline as reserves are produced
unless it acquires or leases additional properties containing proved reserves,
successfully develops new or existing properties or identifies additional
formations with primary or secondary reserve opportunities on its properties. If
it is not successful in expanding its reserve base, its future natural gas and
oil production and drilling activities, the primary source of its energy
revenues, will decrease. Atlas America's ability to find and acquire additional
reserves depends on its generating sufficient cash flow from operations and
other sources of capital, principally sponsored drilling investment
partnerships, all of which are subject to the risks discussed elsewhere in this
subsection.
The growth of Atlas America's energy operations has resulted from both
its acquisition of energy companies and assets and from its ability to obtain
capital funds through its sponsored drilling investment partnerships. If Atlas
America is unable to identify acquisitions on acceptable terms, or cannot obtain
sufficient capital funds through sponsored drilling investment partnerships, it
may be unable to increase or maintain its inventory of properties and reserve
base, or be forced to curtail drilling, production or other activities. This
would result in a decline in its revenues. Agreements between us and Atlas
America included to preserve the tax-free nature of the proposed spin-off of
Atlas America impose material limitations on its ability to complete
acquisitions until after the spin-off, as described in "-Energy-General."
Under current federal tax laws, there are tax benefits to investing in
drilling investment partnerships such as those Atlas America sponsors, including
deductions for intangible drilling costs and depletion deductions. Changes to
federal tax laws that reduce or eliminate these benefits may make investment in
Atlas America's drilling investment partnerships less attractive and, thus,
reduce its ability to obtain funding from this significant source of capital
funds. Atlas America may be affected by the Jobs and Growth Tax Relief
Reconciliation Act of 2003, which reduced the maximum federal income tax rate on
long-term capital gains and qualifying dividends to 15% through 2008. These
changes may make investment in its drilling investment partnerships relatively
less attractive than investments in assets likely to yield capital gains or
qualifying dividends.
Atlas America operates in a highly competitive environment for
acquiring properties and other natural gas and oil companies and attracting
capital through drilling investment partnerships. Atlas America also competes
with the exploration and production divisions of public utility companies for
natural gas and oil property acquisitions. Atlas America's competitors may be
able to pay more for natural gas and oil properties and to evaluate, bid for and
purchase a greater number of properties than Atlas America's financial or
personnel resources permit. Moreover, Atlas America's competitors for investment
capital may have better track records in their programs, lower costs or better
connections in the securities industry segment that markets oil and gas
investment programs than it does. Atlas America may not be able to compete
successfully in the future in acquiring prospective reserves and raising
additional capital.
Atlas America pays transportation fees, which are based on natural gas
sales prices, to Atlas Pipeline for natural gas produced by Atlas America's
drilling investment partnerships and certain unaffiliated producers. An increase
in natural gas prices would increase the fees Atlas America pays to Atlas
Pipeline which could exceed the aggregate of the transportation fees paid to
Atlas America, reimbursements and distributions to Atlas America from its
general and limited partner interests in Atlas Pipeline, and connection costs
and other expenses paid by Atlas Pipeline.
29
Exploration, development, production, transportation and sales of
natural gas and oil are subject to extensive federal, state and local
regulations. We discuss this regulatory environment in more detail in "- Energy
- - Regulation of Production" and "-Energy - Regulation of Transportation and Sale
of Natural Gas." Atlas America may be required to make large expenditures to
comply with these regulations. Failure to comply with these regulations may
result in the suspension or termination of Atlas America's operations and
subject it to administrative, civil and criminal penalties. Other regulations
may limit its operations. For example, "frost laws" prohibit drilling and other
heavy equipment from using certain roads during winter, a principal drilling
season for it, which may delay it in drilling and completing wells. Moreover,
governmental regulations could change in ways that substantially increase Atlas
America's costs, thereby reducing its return on invested capital, revenues and
net income.
Atlas America's natural gas and oil operations are subject to stringent
federal, state and local laws and regulations relating to the release or
disposal of materials into the environment or otherwise relating to
environmental protection. These laws and regulations may require the acquisition
of a permit before drilling commences, restrict the types, quantities, and
concentration of substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands, and other
protected areas, and impose substantial liabilities for pollution resulting from
Atlas America's operations. Failure to comply with these laws and regulations
may result in the assessment of administrative, civil, and criminal penalties,
incurrence of investigatory or remedial obligations, or the imposition of
injunctive relief. Changes in environmental laws and regulations occur
frequently, and any changes that result in more stringent or costly waste
handling, storage, transport, disposal or cleanup requirements could require
Atlas America to make significant expenditures to maintain compliance or could
restrict our methods or times of operation. Under these environmental laws and
regulations, Atlas America could be held strictly liable for the removal or
remediation of previously released materials or property contamination
regardless of whether we were responsible for the release or if our operations
were standard in the industry at the time they were performed. We discuss the
environmental laws that affect Atlas America's operations in more detail under
"- Environmental and Safety Regulation."
Pollution and environmental risks generally are not fully insurable.
Atlas America may elect to self-insure if it believes 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
Atlas America's revenues and the value of its assets.
Well blowouts, cratering, explosions, uncontrollable flows of natural
gas, oil or well fluids, fires, formations with abnormal pressures, pipeline
ruptures or spills, pollution, releases of toxic gas and other environmental
hazards and risks are inherent operating hazards for Atlas America. The
occurrence of any of those hazards could result in substantial losses to it,
including liabilities to third parties or governmental entities for damages
resulting from the occurrence of any of those hazards and substantial
investigation, litigation and remediation costs.
Atlas America may be required to write-down the carrying value of its
natural gas and oil properties when natural gas and oil prices are low. In
addition, write-downs may occur if Atlas America has:
o downward adjustments to its estimated proved reserves;
o increases in its estimates of development costs; or
o deterioration in its exploration and development results.
30
Shortages of drilling rigs, equipment, supplies or personnel could
delay Atlas America's development and exploration plans, thereby reducing
revenues from drilling operations and delaying receipt of production revenues
from wells it planned to drill. Moreover, increased costs, whether due to
shortages or other causes, will reduce the number of wells Atlas America can
drill for existing drilling investment partnerships and, by making its drilling
investment partnerships less attractive as investments, may reduce the amount of
financing for drilling operations obtainable from them. This may reduce revenues
not only from drilling operations but also, if fewer wells are drilled, from
production of natural gas and oil.
ITEM 2. PROPERTIES
OFFICE PROPERTIES
We maintain our executive office, real estate, equipment leasing and
certain structured finance operations in Philadelphia, Pennsylvania under leases
for 19,000 square feet. These leases, which expire in May 2008, contain
extension options through 2033 and are in an office building in which we have a
50% equity interest. We maintain a 3,200 square foot office and a 3,700 square
foot office in New York City, New York under lease agreements that expire in
June 2008 and August 2005, respectively. Offices for our energy and structured
finance operations are maintained at the New York locations.
We own a 24,000 square foot office building in Pittsburgh,
Pennsylvania, a 17,000 square foot field office and warehouse facility in
Jackson Center, Pennsylvania and a field office in Deerfield, Ohio. We lease one
1,400 square foot field office in Ohio under a lease expiring in 2009 and one
4,600 square foot field office in Pennsylvania under a lease expiring in 2005.
In addition, we lease other field offices in Ohio and New York on a
month-to-month basis. We also rent 9,300 square feet of office space in
Uniontown, Ohio under a lease expiring in February 2006 and 8,000 square feet of
office space in Tulsa, Oklahoma under a lease expiring in July 2005. All of
these properties are used for our energy operations.
ENERGY PROPERTIES
Productive wells. The following table sets forth information as of
September 30, 2004 regarding productive natural gas and oil wells in which Atlas
America has a working interest.
Number of Productive Wells
--------------------------
Gross (1) Net (1)
--------- -------
Oil wells....................................... 341 271
Gas wells....................................... 4,786 2,494
----- -----
5,127 2,765
===== =====
- -----------------------
(1) Includes our equity interest in wells owned by 87 drilling investment
partnerships for which we serve as general partner and various joint
ventures. Does not include our royalty or overriding interests in 628
wells.
31
Production. The following table sets forth the quantities of Atlas
America's natural gas and oil production, average sales prices and average
production costs per equivalent unit of production for the periods indicated.
Average
Production Average sales price production
--------------------------- ----------------------- costs per
Period Oil (bbls) Gas (mcf) per bbl per mcf (1) mcfe (2)
- ------ ---------- --------- ------- ----------- ----------
Fiscal 2004.................... 181,021 7,285,281 $32.85 $5.84 $0.87
Fiscal 2003.................... 160,048 6,966,899 $26.91 $4.92 $0.84
Fiscal 2002.................... 172,750 7,117,276 $20.45 $3.56 $0.82
- -------------------------
(1) Average sales price before the effects of financial hedging was $5.84,
$5.08 and $3.57 for fiscal 2004, 2003 and 2002, respectively.
(2) Production costs include labor to operate the wells and related equipment,
repairs and maintenance, materials and supplies, property taxes, severance
taxes, insurance, gathering charges and production overhead.
Developed and Undeveloped Acreage. The following table sets forth
information about Atlas America's developed and undeveloped natural gas and oil
acreage as of September 30, 2004. The information in this table includes Atlas
America's equity interest in acreage owned by drilling investment partnerships
sponsored by it.
Developed acreage Undeveloped acreage
---------------------- -----------------------
Gross Net Gross Net
------- ------- ------- -------
Arkansas...................................... 2,560 403 - -
Kansas........................................ 160 20 - -
Kentucky...................................... 924 462 9,710 4,855
Louisiana..................................... 1,819 206 - -
Mississippi................................... 40 3 - -
Montana....................................... - - 2,650 2,650
New York...................................... 20,183 15,919 37,365 37,365
North Dakota.................................. 639 96 - -
Ohio.......................................... 115,576 96,781 39,547 36,038
Oklahoma...................................... 4,323 468 - -
Pennsylvania.................................. 81,961 81,961 149,613 149,613
Texas......................................... 4,520 329 - -
West Virginia................................. 1,078 539 10,806 5,403
Wyoming....................................... - - 80 80
------- ------- ------- -------
233,783 197,187 249,771 236,004
======= ======= ======= =======
The leases for developed acreage generally have terms that extend for
the life of the wells, while the leases on undeveloped acreage have terms that
vary from less than one year to five years. Atlas America paid rentals of
approximately $592,000 in fiscal 2004 to maintain its leases.
We believe that Atlas America holds good and indefeasible title to its
producing properties, in accordance with standards generally accepted in the
natural gas industry, subject to exceptions stated in the opinions of counsel
employed by it in the various areas in which it conducts its activities. We do
not believe that these exceptions detract substantially from Atlas America's use
of any property. As is customary in the natural gas industry, Atlas America
conducts only a perfunctory title examination at the time it acquires a
property. Before Atlas America commences drilling operations, it conducts an
extensive title examination and performs curative work on defects that it
believes to be significant. Atlas America has obtained title examinations for
substantially all of its managed producing properties. No single property
represents a material portion of its holdings.
32
Atlas America's properties are subject to royalty, overriding royalty
and other outstanding interests customary in the industry. Its 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 Atlas America's use of its
properties.
Drilling Activity. The following table sets forth information with
respect to the number of wells on which Atlas America has completed drilling
during the periods indicated, regardless of when drilling was initiated.
Development Wells Exploratory Wells
------------------------------------------- ------------------------------------------
Productive Dry Productive Dry
----------------- ----------------- ----------------- -----------------
Fiscal Year Gross Net(1) Gross Net(1) Gross Net(1) Gross Net(1)
- ----------- ----- ------ ----- ------ ----- ------ ----- ------
2004............. 493.0 160.5 11.0 3.8 - - 1.0 1.0
2003............. 295.0 92.9 1.0 0.3 - - - -
2002............. 246.0 78.7 6.0 2.0 - - - -
- -------------------
(1) Includes only our interest in the wells and not those of the other partners
in our drilling investment partnerships.
Natural Gas and Oil Reserves. The following tables summarize
information regarding Atlas America's estimated proved natural gas and oil
reserves as of the dates indicated. All of Atlas America's reserves are located
in the United States. Atlas America based its estimates relating to its proved
natural gas and oil reserves and future net revenues of natural gas and oil
reserves upon reports prepared by Wright & Company, Inc., energy consultants. In
accordance with SEC guidelines, Atlas America made the standardized and 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 were held
constant throughout the life of the properties. Atlas America based its
estimates of proved reserves upon the following weighted average prices:
Years ended September 30,
-------------------------------------
2004 2003 2002
-------- -------- -------
Natural gas (per mcf)............................................... $ 6.91 $ 4.96 $ 3.80
Oil (per bbl)....................................................... $ 46.00 $ 26.00 $ 26.76
Reserve estimates are imprecise and may change as additional
information becomes available. Furthermore, estimates of natural gas and oil
reserves, of necessity, are projections based on engineering data. There are
uncertainties inherent in the interpretation of this data as well as the
projection of future rates of production and the timing of development
expenditures. Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil that cannot be measured in an
exact way and the accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports of our
consultants, Wright & Company. Results of drilling, testing and production
subsequent to the date of the estimate may justify revision of this estimate.
Future prices received from the sale of natural gas and oil may be different
from those estimated by Wright & Company in preparing its reports. The amounts
and timing of future operating and development costs may also differ from those
used. Accordingly, the reserves set forth in the following tables ultimately may
not be produced and the proved undeveloped reserves may not be developed within
the periods anticipated. You should not construe the estimated pre-tax PV-10
values as representative of the fair market value of Atlas America's 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.
33
Atlas America evaluates natural gas reserves at constant temperature
and pressure. A change in either of these factors can affect the measurement of
natural gas reserves. Atlas America deducts operating costs, development costs
and production-related and ad valorem taxes in arriving at the estimated future
cash flows. Atlas America makes no provision for income taxes, and bases 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 21 of the Notes to Consolidated
Financial Statements.
Proved natural gas and oil reserves
at September 30,
---------------------------------------
2004(1) 2003 2002
--------- --------- ---------
Natural gas reserves (mmcf):
Proved developed reserves.............................................. 95,788 87,760 83,996
Proved undeveloped reserves............................................ 46,345 45,533 39,226
--------- --------- ---------
Total proved reserves of natural gas................................... 142,133 133,293 123,222
========= ========= =========
Oil reserves (mbbl):
Proved developed reserves.............................................. 2,126 1,825 1,846
Proved undeveloped reserves............................................ 149 30 32
--------- --------- ---------
Total proved reserves of oil........................................... 2,275 1,855 1,878
========= ========= =========
Total proved reserves (mmcfe).......................................... 155,782 144,423 134,490
========= ========= =========
Standardized measure of discounted future cash flows
(in thousands)......................................................... $ 232,998 $ 144,351 $ 104,126
========= ========= =========
PV-10 estimate of cash flows of proved reserves (in thousands):
Proved developed reserves.............................................. $ 265,516 $ 164,617 $ 120,260
Proved undeveloped reserves............................................ 54,863 26,802 12,209
--------- --------- ---------
Total PV-10 estimate................................................... $ 320,379 $ 191,419 $ 132,469
========= ========= =========
- ---------------
(1) Projected natural gas and oil volumes for each of fiscal 2005 and the
remaining successive years are:
Remaining
2005 successive years Total
------ ---------------- -------
Natural gas (mmcf)........................................ 9,098 133,035 142,133
Oil (Mbbl)................................................ 172 2,103 2,275
34
ITEM 3. LEGAL PROCEEDINGS
We are a defendant in a proposed class action originally filed in
February 2000 in the New York Supreme Court, Chautauqua County, by individuals,
putatively on their own behalf and on behalf of similarly situated individuals,
who leased property to us. The complaint alleges that we are not paying
landowners the proper amount of royalty revenues derived from the natural gas
produced from the wells on leased property. The complaint seeks damages in an
unspecified amount for the alleged difference between the amount of royalties
actually paid and the amount of royalties that allegedly should have been paid.
Plaintiffs were certified as a class in December 2003; an appeal of that
certification is pending. The action is currently in its discovery phase. We
believe the complaint is without merit and are defending ourselves vigorously.
We are also a party to various routine legal proceedings arising out of
the ordinary course of our business. Management believes that none of these
actions, individually or in the aggregate, will have a material adverse effect
on our financial condition or operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the
quarter ended September 30, 2004.
35
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Our common stock is quoted on the Nasdaq National Market under the
symbol "REXI." The following table sets forth the high and low sale prices, as
reported by Nasdaq, on a quarterly basis for our last two fiscal years.
HIGH LOW
--------- ---------
FISCAL 2004
- -----------
Fourth Quarter.......................................................................... $ 24.10 $ 18.10
Third Quarter........................................................................... $ 25.06 $ 18.02
Second Quarter.......................................................................... $ 18.58 $ 14.11
First Quarter........................................................................... $ 15.30 $ 11.59
FISCAL 2003
- -----------
Fourth Quarter.......................................................................... $ 12.50 $ 9.79
Third Quarter........................................................................... $ 11.04 $ 7.86
Second Quarter.......................................................................... $ 9.50 $ 7.52
First Quarter........................................................................... $ 9.50 $ 7.26
As of December 1, 2004, there were 17,506,600 shares of common stock
outstanding held by 454 holders of record.
We have paid regular quarterly cash dividends of $0.033 per common
share commencing with the fourth quarter of fiscal 1995. In the third quarter of
fiscal 2004, we increased the quarterly dividend to $0.05 per common share.
For information concerning common stock authorized for issuance under
our stock option plans and other equity compensation plans and stock options
outstanding under these plans, see Note 11 of the Notes to Consolidated
Financial Statements.
36
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read together with our
consolidated financial statements, the notes to the consolidated financial
statements and "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in Item 7 of this report. We derived the selected
consolidated financial data for each of the years ended September 30, 2004, 2003
and 2002, and at September 30, 2004 and 2003 from our consolidated financial
statements appearing elsewhere in this report, which have been audited by Grant
Thornton LLP, an independent registered public accounting firm. We derived the
selected financial data for the years ended September 30, 2001 and 2000 and at
September 30, 2002, 2001 and 2000 from our consolidated financial statements for
those periods which were audited by Grant Thornton LLP but are not included in
this report.
As of and for the Years Ended September 30,
----------------------------------------------------------------------
2004 2003 2002 2001 2000
----------- ----------- --------- ---------- ---------
(in thousands, except per share data)
INCOME STATEMENT DATA:
Revenues:
Energy......................................... $ 180,352 $ 105,262 $ 97,912 $ 94,806 $ 70,552
Real estate.................................... 18,884 13,678 16,582 16,899 18,649
Equipment leasing.............................. 8,262 4,071 1,246 1,066 -
Equity in earnings of structured finance
investees.................................... 7,343 1,444 185 - -
----------- ----------- --------- ---------- ---------
Total revenues............................... $ 214,841 $ 124,455 $ 115,925 $ 112,771 $ 89,201
=========== =========== ========= ========== =========
Income from continuing operations before
cumulative effects of changes in accounting
principles..................................... $ 21,463 $ 9,878 $ 8,358 $ 14,083 $ 5,841
=========== =========== ========= ========== =========
Net income (loss)................................. $ 18,409 $ (2,915) $ (3,309) $ 9,829 $ 18,165
=========== =========== ========= ========== =========
NET INCOME (LOSS) PER COMMON SHARE-BASIC:
From continuing operations before cumulative
effects of changes in accounting principles.. $ 1.23 $ 0.58 $ 0.48 $ 0.78 $ 0.24
=========== =========== ========= ========== =========
Net income (loss) per common share-basic....... $ 1.06 $ (0.17) $ (0.19) $ 0.55 $ 0.78
=========== =========== ========= ========== =========
NET INCOME (LOSS) PER COMMON SHARE-DILUTED:
From continuing operations before cumulative
effects of changes in accounting principles.. $ 1.17 $ 0.56 $ 0.47 $ 0.76 $ 0.23
=========== =========== ========= ========== =========
Net income (loss) per common share-diluted..... $ 1.01 $ (0.17) $ (0.19) $ 0.53 $ 0.76
=========== =========== ========= ========== =========
Cash dividends per common share................... $ 0.17 $ 0.13 $ 0.13 $ 0.13 $ 0.13
=========== =========== ========= ========== =========
BALANCE SHEET DATA:
Total assets................................... $ 725,706 $ 670,744 $ 467,498 $ 466,464 $ 507,831
Debt........................................... $ 129,334 $ 177,955 $ 155,510 $ 150,131 $ 134,932
Stockholders' equity........................... $ 257,915 $ 227,454 $ 233,539 $ 235,459 $ 281,215
37
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW
General. While our fiscal 2004, 2003 and 2002 results reflect the
continued dominant position of our energy operations, the initiatives we began
in fiscal 2003 and continued in fiscal 2004 in our structured finance, equipment
leasing and real estate businesses resulted in material revenue growth for those
operations. In 2004, we also began the process of reorganizing our company into
two independent companies with our company continuing its business of asset
management in structured finance, equipment leasing and real estate and Atlas
America separately continuing the energy business. As part of that process:
o Atlas America completed a public offering of its common stock
in May 2004. The offering of Atlas America's common stock
resulted in net proceeds of $37.0 million which was
distributed to us in a tax free distribution and substantially
enhanced our liquidity; and
o our interest in Atlas America was reduced to 80.2%, with the
public interest in Atlas America now being reflected as a
minority interest in our financial statements.
We anticipate that we will complete the spin-off of Atlas America in
fiscal 2005. Since the spin-off is subject to the completion of several
conditions, principally receipt of a ruling from the Internal Revenue Service as
to the tax-free nature of the proposed spin-off, it may not occur. If the
spin-off does occur, we will no longer consolidate Atlas America's financial
statements with ours and, as a result, our assets, revenues and stockholders'
equity will be substantially reduced.
Our financial condition and results of operations during fiscal 2004
were affected by and, until we spin off Atlas America, will continue to be
affected by initiatives taken by Atlas Pipeline Partners, L.P. In April 2004,
Atlas Pipeline completed a public offering of 750,000 of its common units,
realizing $25.2 million of offering proceeds, net of expenses. The principal
financial effect of the offering was an increase to the minority interest in our
financial statements. On July 16, 2004, Atlas Pipeline acquired Spectrum Field
Services, Inc. at a cost of $142.4 million, including transaction costs and
anticipated taxes. The acquisition was funded partially by debt financing and
partially by the proceeds of the April 2004 offering together with a further
offering completed on July 20, 2004. The latter offering of 2,100,000 common
units raised $67.5 million. The Spectrum acquisition increased Atlas Pipeline's
assets, liabilities, revenues and expenses and, because we consolidate with
Atlas Pipeline, increased ours as well.
Our financial condition in fiscal 2004 was further strengthened by our
repurchase of the remaining $54.0 million of our 12% Senior Notes. As a result
of the premium we offered to effect the repurchase, we recorded a loss on the
transaction of $2.0 million which is included in other income, net in our
consolidated statements of operations. Also as a result of the repurchase, we
reduced our interest expense by $3.5 million in fiscal 2004. In addition to the
12% Senior Notes, we repaid or paid down various real estate and corporate
credit facilities by $40.2 million, further reducing our interest expense.
During fiscal 2004, we continued our program of building the businesses
that we will retain following the planned spin-off. In structured finance, we
increased the amount of assets we managed for issuers of CDOs by $1.3 billion
through our sponsorship of three additional Trapeza CDO issuers. As a result,
our structured finance revenues increased by $5.9 million to $7.3 million in
fiscal 2004 from $1.4 million in fiscal 2003 and $185,000 in fiscal 2002. We
have formed a wholly-owned subsidiary, Ischus Capital Management LLC, to develop
and sponsor CDO issuers holding asset-backed securities. We anticipate that this
will positively impact the amount of assets we manage and our revenues in
succeeding periods.
38
Our equipment leasing revenues grew to $8.3 million for the year ended
September 30, 2004 from $4.1 million for the year ended September 30, 2003. In
fiscal 2004, we originated $149.5 million in leases as compared to $49.0 million
in leases in fiscal 2003, and our leases under management increased to $164.8
million at September 30, 2004 from $63.0 million at September 30, 2003. We
further increased sales and marketing efforts which has lead to new program
agreements with equipment vendors, such as ScanSource Inc, ASAP Software, X-ray
Marketing Associates, Inc, and Cardiometrics Inc., and our $35.0 million
acquisition of a portfolio of leases from Premier Lease Services L.C. We expect
to continue to grow our equipment leasing business by securing additional
equipment vendor programs, such as our recent funding agreement with Gateway
Inc., and the acquisition of equipment leasing companies similar to Premier. Our
business growth is facilitated by our ability to sell lease originations to our
own public equipment leasing funds as well as to a subsidiary of Merrill Lynch.
In real estate, we increased the amount of assets we managed on behalf
of the investment limited partnerships we sponsored to $106.7 million at
September 30, 2004 from $75.7 million at September 30, 2003. As part of our
strategic plan, we are continuing to resolve our real estate loan portfolio
through sales and loan resolutions. In fiscal 2004, we resolved loans with a
book value of $255.4 million, realizing $46.3 million in net proceeds. As a
result, the loans and real estate assets in our loan portfolio decreased from
$580.4 million (principally outstanding loan receivables) at September 30, 2003
to $302.4 million (principally outstanding loan receivables) at September 30,
2004.
Our consolidated financial statements for fiscal 2004 and 2003 reflect
the effect of Financial Accounting Standards Board's, or FASB, Interpretation,
or FIN, 46, "Consolidation of Variable Interest Entities," as amended which we
refer to as FIN 46. As required by FIN 46, we consolidated into our financial
statements for fiscal 2003 and fiscal 2004 certain entities in our real estate
loan business that hold loans acquired at a discount between 1991 and 1999. The
adoption of FIN 46 resulted in a non-cash cumulative effect adjustment of $13.9
million, net of taxes, in the fourth quarter of fiscal 2003. At September 30,
2004, we reported assets and liabilities of $60.6 million and $30.0 million,
respectively, related to these FIN 46 entities, while at September 30, 2003 we
reported assets and liabilities of $78.2 million and $45.2 million,
respectively. In line with our strategic focus of resolving our real estate loan
portfolio, we reported an additional $103.0 million of our FIN 46 assets as
being held for sale along with $65.3 million of associated liabilities at
September 30, 2004. At September 30, 2003, our FIN 46 assets being held for sale
were $222.7 million and the associated liabilities were $141.5 million. For a
more detailed discussion of FIN 46, you should read "- Cumulative Effects of
Changes in Accounting Principles," and Note 3 of the Notes to Consolidated
Financial Statements.
39
The following tables reflect changes to our revenues and assets for the
periods indicated:
REVENUES AS A PERCENT OF TOTAL REVENUES
Years Ended September 30,
-------------------------
2004 2003
---- ----
Energy........................................................................ 84% 85%
Real estate................................................................... 9% 11%
Equipment leasing............................................................. 4% 3%
Equity in earnings of structured finance entities............................. 3% 1%
ASSETS AS A PERCENT OF TOTAL ASSETS
At September 30,
------------------------------
2004 2003
------------ ------------
Energy........................................................................ 54% 35%
Real estate................................................................... 29% 55%
Equipment leasing............................................................. 4% 2%
Structured finance............................................................ 2% 1%
All other (1)................................................................. 11% 7%
- -------------------
(1) Other assets are related to operations which do not meet the definition
of a business segment. For financial information about our operating
segments, see Note 20, Operating Segment Information and Major Customer
Information, of the Notes to Consolidated Financial Statements.
The following is a detailed analysis and discussion of the results of
our energy, real estate, structured finance and equipment leasing operations and
our other revenues, and our costs and expenses.
40
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 2004, 2003 and
2002:
Years Ended September 30,
------------------------------------------
2004 2003 2002
----------- ---------- ---------
(in thousands)
Revenues:
Production.......................................................... $ 48,526 $ 38,639 $ 28,916
Well drilling....................................................... 86,880 52,879 55,736
Well services....................................................... 8,430 7,634 7,585
Gathering, transmission and processing.............................. 36,252 5,901 5,389
Other............................................................... 264 209 286
----------- ---------- ---------
$ 180,352 $ 105,262 $ 97,912
=========== ========== =========
Costs and expenses:
Production.......................................................... $ 7,289 $ 6,770 $ 6,693
Exploration......................................................... 1,549 1,715 1,571
Well drilling....................................................... 75,548 45,982 48,443
Well services....................................................... 4,399 3,774 3,747
Gathering, transmission and processing.............................. 27,870 2,444 2,052
Terminated acquisition.............................................. 2,987 - -
Non-direct.......................................................... 6,074 6,530 7,074
----------- ---------- ---------
$ 125,716 $ 67,215 $ 69,580
=========== ========== =========
Years Ended September 30,
------------------------------------------
2004 2003 2002
----------- ---------- ---------
(dollars in thousand)
Revenues:
Gas (1)............................................................. $ 42,532 $ 34,276 $ 25,359
Oil................................................................. $ 5,947 $ 4,307 $ 3,533
Production volumes:
Gas (mcf/day) (1) (2)............................................... 19,905 19,087 19,499
Oil (bbls/day)...................................................... 495 438 473
Average sales prices:
Gas (per mmcf) (2).................................................. $ 5.84 $ 4.92 $ 3.56
Oil (per bbl)....................................................... $ 32.85 $ 26.91 $ 20.45
Production costs: (3)
As a percent of sales............................................... 15% 18% 23%
Per mcfe............................................................ $ 0.87 $ 0.84 $ 0.82
Depletion per equivalent mcfe....................................... $ 1.22 $ 1.01 $ 0.93
- -------------------
(1) Excludes sales of residual gas and sales to landowners.
(2) Our average sales price before the effects of financial hedging was
$5.84, $5.08 and $3.57 for fiscal 2004, 2003 and 2002, respectively.
(3) Production costs include labor to operate the wells and related
equipment, repairs and maintenance, materials and supplies, property
taxes, severance taxes, insurance, gathering charges and production
overhead.
41
Our energy revenues were $180.4 million in fiscal 2004, as compared to
$105.3 million in fiscal 2003 and $97.9 million in fiscal 2002. The growth in
energy revenues was driven by increases in revenues from Atlas America's well
drilling operations as it substantially increased the amount of funds it raised
from its drilling investment partnerships to $107.7 million in fiscal 2004 as
compared to $66.1 million in fiscal 2003 and $41.1 million in fiscal 2002.
Accordingly, well drilling revenues increased to $86.9 million in fiscal 2004
from $52.9 million in fiscal 2003 and $55.7 million in fiscal 2002. As a result
of Atlas America's increased drilling activity and increased prices for its
natural gas and oil, our production revenues increased to $48.5 million in
fiscal 2004 as compared to $38.6 million in fiscal 2003 and $28.9 million in
fiscal 2002. In addition, as a result of Atlas Pipeline's acquisition of
Spectrum in July 2004, gathering, transmission and processing revenues increased
by $30.4 million.
Our well drilling revenues and expenses represent the billings and
costs associated with the completion of 450, 282 and 242 net wells for drilling
investment partnerships sponsored by Atlas America in fiscal 2004, 2003 and
2002, respectively. The following table sets forth information relating to these
revenues and costs and expenses during the years indicated:
Years Ended September 30
-------------------------------------------
2004 2003 2002
---------- ---------- ----------
(dollars in thousands)
Average drilling revenue per well......................................... $ 193 $ 187 $ 230
Average drilling cost per well............................................ 168 163 200
---------- ---------- ----------
Average drilling gross profit per well.................................... $ 25 $ 24 $ 30
========== ========== ==========
Gross profit margin....................................................... $ 11,332 $ 6,897 $ 7,293
========== ========== ==========
Gross margin percent...................................................... 13% 13% 13%
========== ========== ==========
Net wells drilled......................................................... 450 282 242
========== ========== ==========
Year Ended September 30, 2004 Compared to Year Ended September 30, 2003.
Our natural gas revenues were $42.5 million in fiscal 2004, an increase
of $8.3 million (24%) from $34.3 million in fiscal 2003. The increase was due to
a 19% increase in the average sales price of natural gas and a 5% increase in
production volumes. The $8.3 million increase in natural gas revenues consisted
of $6.4 million attributable to price increases and $1.9 million attributable to
volume increases.
Our oil revenues were $5.9 million in fiscal 2004, an increase of $1.6
million (38%) from $4.3 million in fiscal 2003. The increase resulted from a 22%
increase in the average sales price of oil and a 13% increase in production
volumes. The $1.6 million increase in oil revenues consisted of $951,000
attributable to price increases and $689,000 attributable to volume increases.
Our well drilling gross margin was $11.3 million in fiscal 2004, an
increase of $4.4 million (64%) from $6.9 million in fiscal 2003. During the year
ended September 30, 2004, the increase in gross margin was attributable to an
increase in the number of wells drilled ($4.2 million) and an increase in the
gross profit per well ($204,000). Since our drilling contracts are on a "cost
plus" basis (typically cost plus 15%), an increase in our average cost per well
also results in an increase in our average revenue per well. The increase in our
average cost per well resulted from the increase in the cost of tangible
equipment used on the wells. In addition, it should be noted that the line item
"Liabilities associated with drilling contracts" in our consolidated financial
statements includes $26.5 million of funds raised in our drilling investment
partnerships in fiscal 2004 that had not been applied to drill wells as of
September 30, 2004 due to the timing of drilling operations, and thus had not
been recognized as well drilling revenues. We expect to recognize this amount as
income in fiscal 2005. We have completed our fundraising efforts for calendar
year 2004 with a total of $52.2 million raised after our fiscal year end and,
therefore, we anticipate drilling revenues and related costs to be substantially
higher in fiscal 2005 than in fiscal 2004.
42
Our well services revenues were $8.4 million in fiscal 2004, an
increase of $796,000 (10%) from $7.6 million in fiscal 2003. The increase
resulted from an increase in the number of wells operated due to additional
wells drilled in fiscal 2004.
Our gathering, transmission and processing revenues were $36.3 million,
of which $30.0 million is associated with the operations of Spectrum which was
acquired on July 16, 2004. These revenues reflect two and one half months of
operations in the current year period and, as a result, we expect they will
increase in fiscal 2005.
Our production costs were $7.3 million in fiscal 2004, an increase of
$519,000 (8%) from $6.8 million in fiscal 2003. This increase includes normal
operating expenses and coincides with the increased production volumes we
realized from the increased number of wells we operate. Production costs as a
percent of sales decreased to 15% in fiscal 2004 from 18% in fiscal 2003 as a
result of increases in our average sales prices which more than offset the
slight increase in production costs per mcfe.
Our exploration costs were $1.5 million in fiscal 2004, a decrease of
$166,000 (10%) from fiscal 2003. We attribute the decrease in fiscal 2004 as
compared to the prior year period principally to the following:
o the benefit we received for our contribution of well sites to
our drilling investment partnerships increased $813,000 in
fiscal 2004 as compared to fiscal 2003 as a result of more
wells drilled; which was offset in part by
o $704,000 in dry hole costs we incurred upon making the
determination that a well drilled in an exploratory area of
our operations was not capable of economic production.
Our well services expenses were $4.4 million in fiscal 2004, an
increase of $625,000 (17%) from $3.8 million in fiscal 2003. The increase
resulted from an increase in costs associated with a greater number of wells
operated in fiscal 2004 as compared to fiscal 2003.
Our gathering, transmission and processing expenses were $27.9 million,
of which $25.5 million were associated with the operations of Spectrum. These
costs reflect two and one half months of operations in the current year period
and, as a result, we expect they will increase in fiscal 2005.
Our terminated acquisition costs are related to Atlas Pipeline's
acquisition of Alaska Pipeline Company, which was purportedly terminated in July
2004. These costs consist primarily of legal and professional fees. In September
2003, Atlas Pipeline entered into an agreement with SEMCO Energy, Inc. to
purchase all of the stock of Alaska Pipeline Company. In order to complete the
acquisition, Atlas Pipeline needed the approval of the Regulatory Commission of
Alaska. The Regulatory Commission initially approved the transaction, but on
June 4, 2004 it vacated its order of approval based upon a motion for
clarification or reconsideration filed by SEMCO. On July 1, 2004, SEMCO sent
Atlas Pipeline a notice purporting to terminate the transaction. Atlas Pipeline
believes SEMCO caused the delay in closing the transaction and breached its
obligations under the acquisition agreement. Atlas Pipeline is currently
pursuing its remedies under the acquisition agreement. In connection with the
acquisition, subsequent termination and current legal action, Atlas Pipeline
incurred $3.0 million of costs, which are shown as terminated acquisition costs
in the results of operations - energy table.
Our non-direct expenses were $6.1 million in fiscal 2004, a decrease of
$456,000 (7%) from $6.5 million in fiscal 2003. 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 are partially offset by reimbursements we
receive from our drilling investment partnerships.
43
The decrease in the year ended September 30, 2004 as compared to the
prior year period is attributable principally to the following:
o non-direct expense reimbursements from our investment
partnerships increased by $4.8 million as we continued to
increase the number of wells we drill and manage;
o salaries and wages increased $1.6 million due to an increase
in executive salaries and in the number of our employees in
anticipation of Atlas America's spin-off from us;
o net syndication costs increased $930,000 as we continue to
increase our syndication activities and the drilling funds we
raise in our public and private partnerships;
o legal and professional fees increased $925,000, which includes
the implementation of Sarbanes-Oxley Section 404 compliance
and the filing of two tax returns for 2003 for Atlas Pipeline.
Two tax returns were required as a result of our ownership
percentage in it falling below 50% due to its offering of
common units in May 2003;
o non-direct expenses increased to $484,000 due to the
acquisition of Spectrum on July 16, 2004; and
o directors fees increased $251,000 due to the Atlas America
initial public offering and its anticipated spin-off from us.
Depletion of oil and gas properties as a percentage of oil and gas
revenues was 21% in both fiscal 2004 and fiscal 2003. Depletion was $1.22 per
mcfe in fiscal 2004, an increase of $.21 per mcfe (21%) from $1.01 per mcfe in
fiscal 2003. Higher volumes produced on our new wells in their first year of
production caused depletion per mcfe to increase in fiscal 2004 as compared to
fiscal 2003. The variances from period to period are directly attributable to
changes in our oil and gas reserve quantities, product prices and changes in the
depletable cost basis of our oil and gas properties.
Year Ended September 30, 2003 Compared to Year Ended September 30, 2002
Our natural gas revenues were $34.3 million in fiscal 2003, an increase
of $8.9 million (35%) from $25.4 million in fiscal 2002. The increase was due to
a 38% increase in the average sales price of natural gas partially offset by a
2% decrease in production volumes. The $8.9 million increase in natural gas
revenues consisted of $9.7 million attributable to price increases, partially
offset by $740,000 attributable to volume decreases. Production volumes
decreased because normal production declines in our existing wells were not
offset by the new wells we had drilled in Crawford County, Pennsylvania, since
those wells could not be brought on line until the extension of our Crawford
gathering system had been completed. The Crawford extension was completed in the
fourth quarter of fiscal 2003.
Our oil revenues were $4.3 million in fiscal 2003, an increase of
$774,000 (22%) from $3.5 million in fiscal 2002. The increase resulted from a
32% increase in the average sales price of oil partially offset by a 7% decrease
in production volumes. The $774,000 increase in oil revenues consisted of $1.1
million attributable to price increases partially offset by $342,000
attributable to volume decreases. The decrease in oil volumes was a result of
the natural production decline inherent in the life of a well. We did not offset
the decline through the addition of new wells, as substantially all of the wells
we have drilled during the past several years have targeted natural gas
reserves.
44
Our well drilling gross margin was $6.9 million in the year ended
September 30, 2003, a decrease of $395,000 (5%) from $7.3 million in the year
ended September 30, 2002. During the period, our average cost per well decreased
because we drilled many of them to a shallower formation and, in certain areas
where we have become more active, many of our wells either have not required
fracture stimulation or have needed less equipment than wells we have drilled in
prior years. Since our drilling contracts are on a "cost plus" basis (typically
cost plus 15%), a decrease in our average cost per well also results in a
decrease in our average revenue per well. On the other hand, the decrease in our
average cost per well allowed us to drill more wells with the funds available.
In addition, it should be noted that the line item "Liabilities associated with
drilling contracts" in our consolidated financial statements includes $14.1
million of funds raised in our drilling investment partnerships in fiscal 2003
that had not been applied to drill wells as of September 30, 2003 due to the
timing of drilling operations, and thus had not been recognized as well drilling
revenues.
Our gathering, transmission and processing revenues increased $512,000
(10%) in fiscal 2003 to $5.9 million from $5.4 million in fiscal 2002. The
increase was a result of a 6% increase in natural gas volumes transported by
Atlas Pipeline Partners and an increase in the average prices received for the
natural gas transported, upon which the fees chargeable under a portion of our
transportation arrangements are based.
Our exploration costs were $1.7 million in fiscal 2003, an increase of
$144,000 (9%) from fiscal 2002. The increase in fiscal 2003 as compared to the
prior year period was attributable to expenditures for lease costs of $275,000
which were charged to operations upon our decision to discontinue drilling on
certain leases.
Our gathering, transmission and processing expenses increased 19% in
the year ended September 30, 2003, as compared to the prior year period. This
increase resulted from an increase in compressor expenses due to the addition of
more compressors and increased compressor lease rates. Compressors were added to
increase the transportation capacity of our gathering systems.
Our non-direct expenses were $6.5 million in fiscal 2003, a decrease of
$544,000 (8%) from $7.1 million in fiscal 2002. These expenses include, among
other things, salaries and benefits not allocated to a specific energy activity,
costs of running our energy corporate office, partnership syndication activities
and outside services. These expenses were partially offset by reimbursements we
received for costs we incurred in our partnership management and drilling
activities, resulting from an increase in the number of wells we drilled and
managed during the year as compared to the prior year. Reimbursements received
by us related to our drilling activities increased $470,000 in year ended
September 30, 2003 as compared to the year ended September 30, 2002. In
addition, we more closely allocated direct costs associated with our other
energy activities to those activities, thereby reducing non-direct expenses.
Depletion of oil and gas properties as a percentage of oil and gas
revenues was 21% in fiscal 2003 compared to 26% in fiscal 2002. The variances
from period to period are directly attributable to changes in our oil and gas
reserve quantities, product prices and changes in the depletable cost basis of
our oil and gas properties. Higher gas and oil prices caused depletion as a
percentage of oil and gas revenues to decrease in fiscal 2003 as compared to
fiscal 2002.
45
RESULTS OF OPERATIONS: REAL ESTATE
During fiscal 2004, 2003 and 2002, our real estate operations were
affected by three principal trends or events:
o we continued our program of resolving the loans in our
existing portfolio through repayments, sales, refinancings,
restructurings and foreclosures;
o we sought growth in our real estate business through the
sponsorship of three real estate investment partnerships; and
o in fiscal 2003 we adopted FIN 46.
The principal effects of the first two factors have been to reduce the
number of our real estate loans while increasing our interests in real property
and, as a result of repayments, sales, refinancings and restructurings,
increasing our cash flow from loan resolutions while reducing the amount of our
portfolio of loans and property interests. The principal effect of adopting FIN
46 has been to consolidate in our financial statements the assets and
liabilities of a number of borrowers (although not affecting our creditor-debtor
legal relationship with these borrowers and not causing these assets and
obligations to become our legal assets or obligations).
The following table sets forth information relating to the revenues
recognized and costs and expenses incurred in our real estate operations during
the periods indicated:
Years Ended September 30,
-------------------------------------------
2004 2003 2002
---------- ----------- ----------
(in thousands)
Revenues:
Interest on loans...................................................... $ 984 $ 6,103 $ 9,907
Accreted discount (net of collection of interest) on loans............. 1,909 1,962 3,212
Gains on resolutions of loans and loan payments in excess
of the carrying value of loans...................................... 890 1,024 2,398
Fee income from sponsorship of partnerships............................ 1,466 3,051 -
Rental and other income from properties................................ 517 340 611
FIN 46 revenues........................................................ 11,865 948 -
Equity in earnings of equity investees................................. 1,253 250 454
---------- ----------- ----------
$ 18,884 $ 13,678 $ 16,582
========== =========== ==========
Cost and expenses:
Real estate general and administrative................................. $ 4,571 $ 3,880 $ 2,423
FIN 46 expenses........................................................ 11,265 730 -
---------- ----------- ----------
$ 15,836 $ 4,610 $ 2,423
========== =========== ==========
46
Year Ended September 30, 2004 Compared to Year Ended September 30, 2003
Revenues from our real estate operations increased $5.2 million (38%)
from $13.7 million in fiscal 2003 to $18.9 million in fiscal 2004. We attribute
the increase to the following:
o an increase of $10.9 million in FIN 46 revenues in fiscal 2004
as compared to fiscal 2003. We adopted FIN 46 on July 1, 2003
which resulted in our having to consolidate fourteen entities
as of September 30, 2003. As a result of sales of our
interests and our restructuring of certain of our interests,
we consolidated seven entities under the provisions of FIN 46
as of September 30, 2004. Operations for fiscal 2003 and all
of fiscal 2004 reflect FIN 46 revenues and expenses, as
appropriate;
o an increase of $1.0 million in our share of the operating
results of our unconsolidated real estate investments
accounted for on the equity method in fiscal 2004 as compared
to fiscal 2003. The majority of the increase relates to one
investment and resulted from a change made in the first
quarter of fiscal 2004 in the allocation of net income between
the partners as a result of our preferential cash
distributions; and
o an increase of $177,000 in rental and other income in fiscal
2004 as compared to fiscal 2003. The increase was primarily
the result of three additional months of rental income from
one property.
The increases were partially offset by the following:
o a decrease in interest and accreted discount income of $5.2
million (64%) resulting from the following:
- the transfer of fourteen loans to FIN 46 accounting
treatment as of July 1, 2003 (of which seven loans
still remained as of September 30, 2004), which
decreased interest income by $3.3 million in fiscal
2004 as compared to fiscal 2003;
- the resolution of twelve loans which decreased
interest income by $2.4 million in fiscal 2004 as
compared to fiscal 2003;
- the completion of accretion of discount on one loan,
which decreased interest income by $102,000 in fiscal
2004 as compared to fiscal 2003;
- a decrease in our average rate of accretion,
resulting in a decrease in interest income of $86,000
in fiscal 2004 as compared to fiscal 2003; and
- the conversion of one FIN 46 consolidated entity to a
loan which increased interest income by $676,000 in
fiscal 2004 as compared to fiscal 2003. This resulted
from the partial resolution of the loan, such that we
are no longer the primary beneficiary of the
borrower.
o a decrease of $134,000 in gains on resolutions of loans and
ventures. In fiscal 2004, we resolved four loans having an
aggregate book value of $5.0 million for a net gain of
$13,000. We recognized an additional gain in fiscal 2004 of
$36,000 on one loan which was resolved in fiscal 2003. We also
received $3.4 million for the sale of our investment in one
venture resulting in a gain of $841,000. In fiscal 2003, we
resolved three loans having a book value of $9.7 million for
$10.7 million, recognizing a gain of $1.0 million; and
o a decrease of $1.6 million in fee income in fiscal 2004 as
compared to fiscal 2003. We earned fees for services provided
to the real estate investment partnerships which we sponsored
relating to the purchase and third party financing of two
properties in fiscal 2004 and four properties in fiscal 2003.
These transaction fees totaled $941,000 in fiscal 2004 and
$2.9 million in fiscal 2003. Additionally, we earned
management fees for the properties owned by real estate
investment partnerships which we sponsored totaling $525,000
in fiscal 2004 as compared to $168,000 in fiscal 2003. We
anticipate earning additional fees from our three partnerships
and any future real estate investment partnerships which we
may sponsor.
47
Gains on resolutions of loans, ventures and FIN 46 assets (if any) and
the amount of fees received (if any) vary by each transaction and, accordingly,
there may be significant variations in our gains on resolutions and fee income
from period to period.
Costs and expenses of our real estate operations were $15.8 million in
fiscal 2004, an increase of $11.2 million (244%) from $4.6 million in fiscal
2003. We attribute the increase to the following:
o an increase of $10.5 million in FIN 46 expenses for fiscal
2004 as compared to fiscal 2003. We early adopted FIN 46 on
July 1, 2003, which resulted in our consolidating fourteen
entities as of September 30, 2003 and seven entities as of
September 30, 2004 and recording their operations as FIN 46
revenues and expenses for a portion of fiscal 2003 and twelve
months in fiscal 2004;
o an increase of $691,000 in real estate general and
administrative expenses in fiscal 2004, as compared to fiscal
2003. The increase resulted primarily from the following:
- an increase in wages and benefits of $249,000 as a
result of the addition of personnel in our real
estate subsidiary to manage our existing portfolio of
commercial loans and real estate and to expand our
real estate operations through the sponsorship of
real estate investment partnerships offset by a
reduced corporate allocation of executive wages;
- an increase in property management expenses of
$406,000 related to the real estate investment
partnerships;
- an increase in travel costs of $158,000 due to the
increased activity associated with the acquisition
and management of our real estate investment
programs; and
- a decrease in outside services of $122,000 reflecting
additional work performed internally by new
personnel.
Year Ended September 30, 2003 Compared to Year Ended September 30, 2002
Revenues from our real estate operations decreased $2.9 million (18%)
from $16.6 million in fiscal 2002 to $13.7 million in fiscal 2003. We attribute
these changes to the following:
o a decrease in interest income and accreted discount of $5.1
million (38%) in fiscal 2003 as compared to fiscal 2002,
primarily resulting from the following:
- the sale or repayment of three loans in fiscal 2003
which decreased interest income by $1.3 million in
fiscal 2003 as compared to fiscal 2002;
- the completion of accretion of discount on one loan,
which decreased interest income by $1.6 million in
fiscal 2003 as compared to fiscal 2002;
- a decrease in our average accretion rate, resulting
in a decrease in interest income of $84,000 in fiscal
2003 as compared to fiscal 2002; and
- the early adoption of FIN 46 on July 1, 2003 resulted
in our consolidating 14 entities and resulted in a
decrease in interest income of $2.1 million.
o a decrease of $1.4 million (57%) in gains on resolutions of
loans and loan payments in excess of carrying value in fiscal
2003 as compared to fiscal 2002, resulting primarily from the
following:
- in fiscal 2003, we received repayments of $10.7
million on three loans having aggregate book values
of $9.7 million, resulting in gains of $1.0 million;
48
- in fiscal 2002, we sold one loan having a book value
of $1.0 million to RAIT for $1.8 million, resulting
in a gain of $757,000;
- in fiscal 2002, we received repayments of $24.9
million on two loans having an aggregate book value
of $23.3 million, resulting in gains of $1.6 million;
and
o an increase of $3.1 million in fee income in fiscal 2003, as
compared to fiscal 2002. This increase resulted primarily from
fees we earned for services provided to the real estate investment
partnership which we sponsored. These fees relate to the purchase
and third party financing of four partnership properties. We
anticipate earning additional fees from this partnership and any
future real estate investment partnerships which we may sponsor.
Gains on resolutions of loans and loan payments in excess of the
carrying value of loans (if any) and the amount of fees received (if any) vary
from transaction to transaction and there may be significant variations in our
gains on resolutions and fee income from period to period.
Costs and expenses of our real estate operations increased $2.2 million
(90%) from $2.4 million in fiscal 2002 to $4.6 million in fiscal 2003. Primarily
resulting from the following:
o an increase in wages and benefits of $532,000 due to the
addition of personnel in connection with of our sponsorship
and management of our real estate investment partnerships;
o an increase in insurance and professional services fees of
$716,000 due to an increase in insurance rates in general and
additional activity associated with the management of our loan
portfolio and investment partnership; and
o FIN 46 expenses associated with real estate entities
consolidated upon adoption on July 1, 2003 of FIN 46 (see Note
3 of the Notes to Consolidated Financial Statements) increased
$730,000 as fiscal 2003 represents three months of operations.
RESULTS OF OPERATIONS: STRUCTURED FINANCE
The following table sets forth certain information relating to the
revenues recognized and costs and expenses incurred in our structured finance
operations during the periods indicated:
Years Ended September 30,
-------------------------------------------
2004 2003 2002
---------- ----------- ----------
(in thousands)
Equity in earnings of structured finance investees:
Collateral management fees............................................. $ 2,045 $ 242 $ -
Limited partner interests.............................................. 1,121 328 138
General partner interests.............................................. 3,166 874 47
Net interest earned.................................................... 647 - -
Other.................................................................. 364 - -
---------- ----------- ----------
$ 7,343 $ 1,444 $ 185
========== =========== ==========
Costs and expenses......................................................... $ 2,128 $ - $ -
========== =========== ==========
Year Ended September 30, 2004 Compared to Year Ended September 30, 2003
Equity in the earnings of our structured finance investees increased
$5.9 million (409%) to $7.3 million in fiscal 2004 from $1.4 million in fiscal
2003. The increase in fiscal 2004 reflects our equity earnings subsequent to the
completion of offerings by six Trapeza CDO issuers which we had co-sponsored as
of September 30, 2004 as compared to three Trapeza CDO issuers which we had
co-sponsored as of September 30, 2003.
49
Our structured finance expenses were $2.1 million in fiscal 2004. These
expenses represent costs associated with our sponsorship and management of
investment partnerships in the trust preferred and ABS areas. These expenses
include primarily salaries and benefits and legal and professional fees. These
expenses were partially offset by reimbursements of $1.3 million from our
investment partnerships in the fiscal year ended 2004.
Year Ended September 30, 2003 Compared to Year Ended September 30, 2002
Equity in the earnings of our structured finance investees increased
$1.3 million (681%) from $185,000 in fiscal 2002 to $1.4 million in fiscal 2003.
The increase in fiscal 2003 reflects our equity earnings subsequent to the
completion of offerings by three Trapeza CDO issuers which we had co-sponsored
as of September 30, 2003.
RESULTS OF OPERATIONS: EQUIPMENT LEASING
The following table sets forth certain information relating to the
revenues and costs and expenses incurred in our equipment leasing operations
during the periods indicated:
Years Ended September 30,
-------------------------------------------
2004 2003 2002
----------- ---------- ----------
(in thousands)
Revenues:
Leasing revenues................................................... $ 2,597 $ 544 $ 77
Acquisition fees................................................... 2,542 1,012 434
Management fees.................................................... 2,462 2,421 588
Other.............................................................. 661 94 147
----------- ---------- ----------
$ 8,262 $ 4,071 $ 1,246
=========== ========== ==========
Costs and expenses..................................................... $ 8,890 $ 5,883 $ 745
=========== ========== ==========
On June 30, 2004, we acquired a portfolio of small ticket leases with a
value of $35.0 million along with numerous vendor finance relationships as well
as experienced origination personnel from Premier Lease Service L.C.
Year Ended September 2004 Compared to Year Ended September 30, 2003
Our lease originations were $149.5 million in fiscal 2004, an increase
of $100.5 million (205%) from fiscal 2003. Our total lease assets under
management at September 30, 2004 were $164.8 million, an increase of $101.8
million (162%) from fiscal 2003. Our leasing origination growth was facilitated
by our relationships with Merrill Lynch, our investment partnership, and the
Premier portfolio acquisition. This resulted in total revenues from leasing
operations increasing to $8.3 million in fiscal 2004 as compared to $4.1 million
in fiscal 2003, an increase of 103%.
Leasing revenues increased to $2.6 million in fiscal 2004 as compared
to $544,000 in fiscal 2003, a 377% increase, due to the increase in lease
originations. Acquisition fees increased to $2.5 million in fiscal 2004 as
compared to $1.0 million in fiscal 2003, a 151% increase. The increase in lease
originations allowed us to sell a greater volume of leases to our investment
partnership and Merrill Lynch. Management fees were relatively flat in fiscal
year 2004 as compared to fiscal 2003 despite the increase in the lease
portfolios managed. At the time we acquired LEAF Financial in 1995, it acted as
the general partner of a series of public equipment leasing partnerships. We
liquidated the last four of these partnerships in the quarter ended March 31,
2004, and, as a result, the increase of management fees from other sources was
largely offset by the elimination of management fees from this source.
50
Included in other income are gains on lease terminations which vary
from transaction to transaction and can result in significant income variances
from period to period depending upon the termination schedules.
Our equipment leasing expenses were $8.9 million in fiscal year 2004,
an increase of $3.0 million from $5.9 million in fiscal year 2003. Due to the
expansion of our equipment leasing operations, our wages and benefits increased
by $1.1 million and overhead operational expenses increased by $600,000 from
fiscal 2003. In addition, we had previously deferred organization and offering
costs in connection with the fund raising activities of our equipment leasing
investment partnership. The investment partnership reimburses us for these costs
as it sells partnership interests in connection with its public offering. The
offering period for the current equipment leasing investment partnership closed
on August 15, 2004. During the fiscal year ended September 30, 2004, based on
unanticipated circumstances impacting the sale of investment units, we reduced
the amount of offering costs to be reimbursed by a $1.3 million charge to
earnings.
Year Ended September 2003 Compared to Year Ended September 30, 2002
Our equipment leasing revenues were $4.1 million in fiscal 2003, an
increase of $2.8 million from $1.2 million in fiscal 2002, primarily due to the
receipt in fiscal 2003 of management fees and equipment leasing income
associated with our new leasing investment programs.
Our leasing expenses were $5.9 million in fiscal 2003, an increase of
$5.1 million from $745,000 in fiscal 2002, primarily due to expenses associated
with the expansion of our operations in connection with our new leasing
programs.
RESULTS OF OPERATIONS: OTHER COSTS AND EXPENSES AND OTHER INCOME/EXPENSE
Year Ended September 30, 2004 Compared to Year Ended September 30, 2003
Our expenses related to the planned spin-off of Atlas America were $1.7
million for the year ended September 30, 2004. As previously discussed, in May
2004 Atlas America completed an initial public offering of 2,645,000 shares of
its common stock, leaving us with an 80.2% ownership of Atlas America. In
connection with the offering, Edward Cohen became Chairman, Chief Executive
Officer and President of Atlas America and retired as our Chief Executive
Officer. As a result of his retirement, we commenced payments required by the
supplemental employment retirement plan established under his employment
arrangements with us and recorded a charge of $1.4 million to reflect an
actuarial adjustment based upon the acceleration of his retirement date. The
balance of the reorganization expenses consisted of $351,000 of legal fees
incurred in connection with the planned spin-off of Atlas America.
Depreciation, depletion and amortization increased $3.4 million to
$15.6 million in fiscal 2004 from $12.1 million in fiscal 2003. This increase
primarily resulted from the increase in energy properties and equipment related
to the purchase of wells and related equipment due to the expansion of our
drilling efforts in fiscal 2004 and as a result of the acquisition of Spectrum
by Atlas Pipeline.
Our provision for possible losses decreased $1.2 million (65%) to
$642,000 in fiscal 2004 as compared to $1.8 million in fiscal 2003. This
decrease resulted primarily from the decrease in our investments in our real
estate loan portfolio and other real estate assets owned through the repayment
of loans and property resolutions.
51
Our fiscal 2003 provision for a legal settlement of $1.2 million
represents the estimated cost associated with the settlement of an action filed
by the former chairman of TRM Corporation as described in Note 16 of the Notes
to Consolidated Financial Statements. Subsequent to the end of fiscal 2004, our
claim against our insurance company for reimbursement of our costs was settled
for $1.4 million and we anticipate recording our recovery in operations during
the first quarter of fiscal 2005.
Our interest expense in fiscal 2004 decreased by $6.2 million (48%) to
$6.6 million from $12.8 million in fiscal 2003, due principally to the
repurchase $54.0 million of our 12% Senior Notes and repayment of real estate
credit facilities as a result of disposals of real estate loans and assets in
fiscal 2004.
At September 30, 2004, we owned 24% of Atlas Pipeline through both our
general partner interest and our subordinated limited partner units. As general
partner, we control Atlas Pipeline; therefore, 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 earnings was $5.0 million in
the year ended 2004 as compared to $4.4 million in the year ended 2003, an
increase of $522,000 (12%). These increases were the result of an increase in
Atlas Pipeline's net income principally caused by increases in transportation
fees received, the acquisition of Spectrum and an increase in the amount of
Atlas Pipeline's earnings attributable to minority interests as a result of its
May 2003, April 2004 and July 2004 public offerings.
During fiscal 2004 and fiscal 2003, we sold 782,700 and 542,600 shares,
respectively, of RAIT Investment Trust and recorded gains of $9.5 million and
$4.0 million, respectively. Dividend income from RAIT decreased $1.7 million to
$915,000 in fiscal 2004 as a result of these sales. At September 30, 2004, we
owned approximately 110,000 shares of RAIT.
The $2.0 million loss on the early extinguishment of the debt reflects
the write-off of the unamortized discount and issue costs related to the
repurchased 12% Senior Notes. The repurchase of the 12% Senior Notes was
completed in January 2004.
Our effective tax rate increased to 34% in fiscal 2004 as compared to
32% in fiscal 2003 as a result of a reduction in statutory depletion and
tax-exempt interest.
DISCONTINUED OPERATIONS
Year Ended September 30, 2004 Compared to Year Ended September 30, 2003
In November 2000, we disposed of our residential mortgage lending
business, LowCostLoan, Inc. (formerly Fidelity Mortgage Funding, Inc.), which we
refer to as LCL. Accordingly, LCL has been reported as a discontinued operation.
Upon final resolution of certain lease obligations associated with LCL, we
recognized a gain on disposal of $392,000, net of tax, in fiscal 2004.
In fiscal 2004, we also disposed of five real estate investments. Three
investments in real estate loans were disposed by repayments of our loans: one
as a result of a refinancing and two by sales of properties secured by our
loans. In addition, two real estate properties owned by us and classified as
held for sale were sold in fiscal 2004. The gains and losses on the disposal of
these assets were included in gains on disposals of discontinued operations for
fiscal 2004. Operating results of the four real assets classified as held for
sale as of September 30, 2004 are included in losses on discontinued operations.
52
Year Ended September 30, 2003 Compared to Year Ended September 30, 2002
In accordance with SFAS 144 "Accounting for the Impairment or Disposal
of Long Lived Assets," our decision in fiscal 2002 to dispose of Optiron
Corporation, our former energy technology subsidiary, resulted in the
presentation of Optiron as a discontinued operation for the three years ended
September 30, 2003. We had held a 50% interest in Optiron; as a result of the
disposition in September 2002, we currently hold a 10% interest in Optiron.
The plan of disposal required Optiron to pay to us 10% of its revenues
if such revenues exceeded $2.0 million in the twelve month period following the
closing of the transaction. As a result, in fiscal 2003 Optiron became obligated
to pay us $295,000. The payment was made in March 2004.
On August 1, 2000, we sold our small ticket equipment leasing
subsidiary, Fidelity Leasing, Inc., to European American Bank and AEL Leasing
Co., Inc., subsidiaries of ABN AMRO Bank, N.V. We received total consideration
of $152.2 million, including repayment of indebtedness of Fidelity Leasing to
us. Of the $152.2 million consideration, $16.0 million was paid by a
non-interest bearing promissory note. The promissory note was payable to the
extent of payments received from on a pool of Fidelity Leasing lease receivables
and refunds received with respect to certain tax receivables. In addition, $10.0
million was placed in escrow as security for our indemnification obligations to
the purchasers.
The successor in interest to the purchaser made a series of claims with
respect to our indemnification obligations and representations which were
settled in December 2002. Under the settlement, we and the successor were
released from certain terms and obligations of the original purchase agreements
and from claims arising from circumstances known at the settlement date. In
addition, we (i) released to the successor the $10.0 million escrow fund; (ii)
paid the successor $6.0 million; (iii) guaranteed that the successor will
receive payments of $1.2 million from a note, secured by Fidelity Leasing lease
receivables, delivered at the close of the Fidelity Leasing sale; and (iv)
delivered two promissory notes to the successor, each in the principal amount of
$1.75 million, bearing interest at the two-year treasury rate plus 500 basis
points, and due on December 31, 2003 and 2004, respectively. We recorded a loss
from discontinued operations, net of taxes, of $9.4 million in connection with
the settlement.
The assets and liabilities of four entities that were consolidated
under the provisions of FIN 46 in the quarter ended September 30, 2003 were
classified as held for sale in that period in accordance with our intent to sell
our interest in the real estate loans underlying those assets and liabilities.
In addition, we foreclosed on one property in which we held a loan and have
classified this property as held for sale.
CUMULATIVE EFFECTS OF CHANGES IN ACCOUNTING PRINCIPLES
In January 2003 the FASB issued FIN 46, "Consolidation of Variable
Interest Entities." This interpretation changed the method of determining
whether certain entities called variable interest entities or "VIE" should be
included in our consolidated financial statements. The analysis of whether an
entity is a VIE and a result, must be consolidated is based on an analysis of
risks and rewards, not control, and represents a significant and complex
modification of previous accounting principles. Under FIN 46, a VIE is an entity
that has (1) equity that is insufficient to permit the entity to finance its
activities without additional subordinated financial support from other parties,
or (2) equity investors that cannot make significant decisions about the
entity's operations, or that do not absorb the expected losses or receive the
expected residual returns of the entity. A VIE must be consolidated by its
primary beneficiary, which is the party involved with the VIE that has exposure
to a majority of the expected losses or a majority of the expected residual
returns or both. All other entities are evaluated for consolidation in
accordance with SFAS No. 94, "Consolidation of All Majority-Owned Subsidiaries."
53
FIN 46 is applicable to VIEs created after January 31, 2003, and to
VIEs in which an enterprise obtains an interest after that date. For VIEs in
which an enterprise holds an interest that it acquired before February 1, 2003,
FIN 46 is applicable for financial statements issued for the first period ending
after December 15, 2003. For any VIEs that must be consolidated under FIN 46,
the assets, liabilities and non-controlling interest of the VIE are initially
measured at their carrying amounts, as defined in FIN 46, with any difference
between the net amount added to the balance sheet and the value at which the
primary beneficiary carried its interest in the VIE prior to the adoption of FIN
46 being recognized as a cumulative effect of a change in accounting principle.
If determining the carrying amounts is not practicable, the fair value at the
date of adoption may be used to measure the assets, liabilities and
non-controlling interests of the VIE. We have determined that it was not
practicable to determine the carrying values of the VIE's as of the date of the
qualifying event and accordingly, have used the fair values at the date of
adoption, July 1, 2003.
As encouraged by the pronouncement, we early-adopted FIN 46 on July 1,
2003. Consequently, certain entities relating to our real estate business were
consolidated in our financial statements in fiscal 2003. Several factors that
distinguish these entities from others included in our consolidated statements
follow:
o the assets and liabilities, revenues and expenses of the
consolidated VIEs are included in our financial statements.
The investments in real estate loans and accreted interest
income thereon, which were our variable interests in the VIEs,
have been removed from the financial statements;
o we consolidated the VIEs because we determined that we were
the primary beneficiary of these entities within the meaning
of FIN 46; and
o the assets and liabilities of the VIEs that are now included
in our consolidated financial statements are neither our
assets nor our liabilities. Liabilities of the VIE can only be
satisfied from the VIE's assets, not our assets, nor can we
use the VIE's assets to satisfy our obligations.
As of July 1, 2003, the date of adoption, the consolidation of FIN 46
entities resulted in the addition of $296.5 million in assets and $185.5 million
in liabilities to our consolidated balance sheet and in a $13.9 million
after-tax cumulative effect adjustment in our fourth fiscal quarter. In
addition, because we classified certain of our FIN 46 assets as being held for
sale, the operations of those assets were recognized in our consolidated
statements of operations as income (loss) from discontinued operations.
Accordingly, we recognized losses of $3.4 million and income of $896,000 (net of
income taxes) in fiscal 2004 and 2003, respectively.
FIN 46 has been the subject of significant continuing interpretation by
the FASB, and changes to its complex requirements are possible. In December
2003, a revised interpretation was issued, known as FIN 46(R). This revision did
not have an effect on our financial position or results of operations. It is not
possible to conclude whether future changes would be likely to affect the
amounts we have already recorded.
The cumulative effect of change in accounting principle in fiscal 2002
related to Optiron which adopted SFAS 142 on January 1, 2002 and, as a result of
this adoption, realized an impairment and writedown 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.
54
LIQUIDITY AND CAPITAL RESOURCES
General. Our major sources of liquidity have been funds generated by
operations, funds raised and fees earned from investor partnerships, resolutions
of real estate loans, borrowings under our existing energy, real estate, leasing
and corporate credit facilities and the sales of our RAIT Investment Trust
shares. In fiscal 2004, a principal source of liquidity was Atlas America's
payment of dividends to us principally with proceeds from its initial public
offering. We have employed these funds principally in the expansion of our
energy operations, the repurchase of our senior notes, the repayment of our
energy and real estate credit facilities. The following table sets forth our
sources and uses of cash for the periods indicated:
Years Ended September 30,
-----------------------------------------
2004 2003 2002
----------- ----------- -----------
(in thousands)
Provided by continuing operations......................................... $ 44,820 $ 44,696 $ 6,467
Used in investing activities.............................................. (142,002) (13,978) (24,504)
Provided by (used in) financing activities................................ 80,283 (8,012) (3,477)
Provided by (used in) discontinued operations............................. 43,180 (5,624) (1,398)
----------- ----------- -----------
Increase (decrease) in cash and cash equivalents.......................... $ 26,281 $ 17,082 $ (22,912)
=========== =========== ===========
Our liquidity is affected by national, regional and local economic
trends and uncertainties as well as trends and uncertainties more particular to
us, including natural gas prices, interest rates and our ability to raise funds
through our sponsorship of investment partnerships and structured finance
vehicles. While the current favorable natural gas pricing and interest rate
environment have been positive contributors to our liquidity, and lead us to
believe that we will be able to refinance, or renew, our indebtedness as it
matures, there are numerous risks and uncertainties involved. We describe
factors affecting our liquidity, as well as the risks and uncertainties relating
to our ability to generate this liquidity, in Item 1, "Business - Risk Factors"
and in this item in "Results of Operations," "Changes in Prices and Inflation,"
and "Contractual Obligations and Commercial Commitments."
Year Ended September 30, 2004 Compared to Year Ended September 30, 2003
We had $69.1 million in cash and cash equivalents on hand at September
30, 2004 as compared to $42.8 million at September 30, 2003. Our ratio of
earnings (from continuing operations before income taxes, minority interest and
interest expense) to fixed charges was 6.8 to 1.0 in the fiscal year ended
September 30, 2004 as compared to 2.5 to 1.0 in the fiscal year ended September
30, 2003.
Our working capital at September 30, 2004 was $54.5 million, an
increase of $28.3 million from $26.2 million at September 30, 2003. This
increase primarily resulted from the net proceeds from Atlas America's and Atlas
Pipeline's public offerings. Our long-term debt (including current maturities)
to total capital ratio at September 30, 2004 was 50% as compared to 78% at
September 30, 2003.
Cash flows from operating activities. Cash provided by operations is an
important source of short-term liquidity for us. Net cash provided by operating
activities increased $124,000 in fiscal 2004, as compared to fiscal 2003,
primarily due to:
o changes in operating assets and liabilities decreased cash
flows by $23.9 million primarily as a result of an increase in
purchases of lease equipment which will subsequently be sold
to third party equipment leasing programs and trade payables
and deferred revenues on drilling contracts at September 30,
2004 as compared to September 30, 2003, due to the timing of
investor funds raised and the subsequent use of those funds in
our drilling programs;
55
o offsetting this decrease was an increase in deferred taxes of
$10.4 million; and
o gas and oil production net revenues increased $9.5 million
primarily attributable to a 19% increase in the average price
we received for our natural gas production.
Cash flows from investing activities. Net cash used in our investing
activities increased $128.0 million in fiscal 2004 as compared to fiscal 2003,
primarily due to the following:
o cash used in the acquisition of Spectrum was $141.6 million;
and
o an increase in capital expenditures of $14.2 million
associated with the expansion of our energy operations;
o offsetting these items was an increase of $16.4 million in
principal payments on notes receivable and proceeds from sale
of assets; and
o an increase of $8.1 million in net proceeds from the sale of
RAIT Investment Trust shares to $20.2 million in fiscal 2004
as compared to $12.0 million in fiscal 2003.
Cash flows from financing activities. Net cash used in our financing
activities increased $88.3 million in fiscal 2004 as compared to fiscal 2003,
primarily due to the following
o we received proceeds of $129.7 million from public offerings
of Atlas America's common stock and Atlas Pipeline's common
units, an increase of $104.5 million from $25.2 million in
fiscal 2003;
o offsetting this increase was an increase in net repayments of
debt of $12.8 million in fiscal 2004 as compared to fiscal
2003; and
o an increase in dividends paid to minority interest of $3.0
million in fiscal 2004 as compared to fiscal 2003 as a result
of higher earnings and more common units outstanding for Atlas
Pipeline as a result of its April and July 2004 offerings of
common units.
Year Ended September 30, 2003 Compared to Year Ended September 30, 2002
We had $42.8 million in cash and cash equivalents on hand at September
30, 2003 as compared to $25.7 million at September 30, 2002. Our ratio of
earnings (from continuing operations before income taxes, minority interest and
interest expense) to fixed charges was 2.5 to 1.0 in the fiscal year ended
September 30, 2003 as compared to 2.1 to 1.0 in the fiscal year ended September
30, 2002.
Our working capital at September 30, 2003 was $26.2 million, an
increase of $24.1 million from $2.1 million at September 30, 2002. This increase
primarily resulted from the classification of $81.2 million of our FIN 46 assets
(net of related liabilities) as held for sale, partially offset by the
classification of the outstanding $54.0 million principal amount of our senior
notes as current liabilities due to their August 1, 2004 maturity date. Our
long-term debt (including current maturities) to total capital ratio at
September 30, 2003 was 78% as compared to 66% at September 30, 2002.
56
Cash flows from operating activities. Cash provided by operations is an
important source of short-term liquidity for us. Net cash provided by operating
activities increased $38.2 million in fiscal 2003, as compared to fiscal 2002,
primarily due to the following:
o operating assets and liabilities increased $30.1 million
primarily as a result of an increase in deferred revenues on
drilling contracts at September 30, 2003 as compared to
September 30, 2002, due to the timing of investor funds raised
and the subsequent use of those funds in our drilling
programs;
o gas and oil production revenues increased $9.7 million
primarily attributable to a 38% increase in the average price
we received for our natural gas production; and
o offsetting these increases in operating cash flow was a
decrease in collections of interest of $4.1 million associated
with our real estate segment due in part to our adoption of
FIN 46
Cash flows from investing activities. Net cash used in our investing
activities decreased $10.5 million in fiscal 2003 as compared to fiscal 2002,
primarily due to the following:
o a realization of net proceeds of $12.0 million from sale of
RAIT shares in fiscal 2003 as compared to a use of $1.9
million to acquire RAIT shares in fiscal 2002;
o a decrease of $13.9 million in investments in real estate
loans and real property interests in fiscal 2003 as compared
to 2002;
o a decrease of $4.6 million in cash spent on other assets due
principally to investments with the commencement of the
Trapeza entities and our equipment leasing operation in fiscal
2002;
o offsetting these items was a decrease of $15.2 million in
principal payments on notes receivable and proceeds from sale
of assets; and
o an increase in capital expenditures of $6.6 million associated
with the expansion of our energy operations.
Cash flows from financing activities. Net cash used in our financing
activities increased $4.5 million in fiscal 2003 as compared to fiscal 2002,
primarily due to the following
o an increase in net repayments of debt of $28.3 million in
fiscal 2003 as compared to fiscal 2002;
o an increase in purchases of treasury stock of $3.1 million in
fiscal 2003 as compared to fiscal 2002;
o offsetting these increases were net proceeds of $25.2 million
from Atlas Pipeline's public offering in fiscal 2003; and
o an increase in proceeds from issuance of stock of $2.9 million
in fiscal 2003 as compared to fiscal 2002.
CAPITAL REQUIREMENTS
During fiscal 2004, our capital expenditures related primarily to
investments in our drilling investment partnerships and pipeline expansions, in
which we invested $31.9 million and $7.0 million, respectively. During fiscal
2004, we funded capital expenditures through cash on hand, borrowings under our
credit facilities and from operations. We have established two credit facilities
to provide additional funding sources for our capital expenditures.
57
The level of capital expenditures we must devote to our exploration and
production operations depends upon the level of funds raised through our
drilling investment partnerships. We have budgeted to raise up to $138.0 million
in fiscal 2005 through drilling partnerships. During fiscal 2004, we raised
$107.7 million. We believe cash flow from operations and amounts available under
our credit facility will be adequate to fund our contributions to these
partnerships. However, the amount of funds we raise and the level of our capital
expenditures will vary in the future depending on market conditions for natural
gas and other factors.
We continuously evaluate acquisitions of natural gas and oil and
pipeline assets. In order to make any acquisition, 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. We cannot assure
you that we will be successful in our efforts to obtain outside capital.
CHANGES IN PRICES AND INFLATION
Our revenues, the value of our assets, our ability to obtain bank loans
or additional capital on attractive terms and our ability to finance our
drilling activities through drilling investment partnerships have been and will
continue to be affected by changes in oil and gas prices. Natural gas and oil
prices are subject to significant fluctuations that are beyond our ability to
control or predict. During fiscal 2004, we received an average of $5.84 per mcf
of natural gas and $32.85 per bbl of oil as compared to $4.92 per mcf and $26.91
per bbl in fiscal 2003 and $3.56 per mcf and $20.45 per bbl 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, 2004, 2003 and 2002, we paid dividends
of $2.6 million, $2.3 million and $2.3 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.
58
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following tables set forth our obligations and commitments as of
September 30, 2004.
PAYMENTS DUE BY PERIOD
(IN THOUSANDS)
------------------------------------------------------------------
CONTRACTUAL CASH OBLIGATIONS: LESS THAN 1 - 3 4 - 5 AFTER 5
TOTAL 1 YEAR YEARS YEARS YEARS
-------------- -------------- --------------- ------------ -------------
Long-term debt........................... $ 120,847 $ 6,151 $ 43,311 $ 55,080 $ 16,305
Secured revolving credit facilities...... 8,487 8,487 - - -
Capital lease obligations................ - - - - -
Operating leases......................... 3,313 1,400 1,420 491 2
----------- ----------- ------------ ---------- ----------
Total contractual cash obligations....... $ 132,647 $ 16,038 $ 44,731 $ 55,571 $ 16,307
=========== =========== =========== =========== =========
AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
(IN THOUSANDS)
------------------------------------------------------------------
OTHER COMMERCIAL COMMITMENTS: LESS THAN 1 - 3 4 - 5 AFTER 5
TOTAL 1 YEAR YEARS YEARS YEARS
-------------- -------------- --------------- ------------ -------------
Standby letters of credit.............. $ 4,048 $ 4,048 $ - $ - $ -
Guarantees............................. 730 730 - - -
Standby replacement commitments........ 6,009 4,773 1,236 - -
Other commercial commitments........... 275,975 6,262 122,362 63,355 83,996
----------- ----------- ------------ ---------- ----------
Total commercial commitments........... $ 286,762 $ 15,813 $ 123,598 $ 63,355 $ 83,996
=========== =========== ============ ========== ==========
CRITICAL ACCOUNTING POLICIES
The discussion and analysis of our financial condition and results of
operations is based upon our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States of America. The preparation of these financial statements requires
us to make estimates and judgments that affect the reported amounts of our
assets, liabilities, revenues, costs and expenses, and related disclosure of
contingent assets and liabilities. On an on-going basis, we evaluate our
estimates, including those related to bad debts, deferred tax assets and
liabilities, goodwill and identifiable intangible assets, and certain accrued
liabilities. We base our estimates on historical experience and on various other
assumptions that we believe reasonable under the circumstances, the results of
which form the basis for making judgments about the carrying values of assets
and liabilities that are not readily apparent from other sources. Actual results
may differ from these estimates under different assumptions or conditions.
We have identified the following policies as critical to our business
operations and the understanding of our results of operations.
Accounts Receivable, Investments in Lease Assets and Real Estate and Allowance
for Possible Losses.
Through our business segments, we engage in credit extension,
monitoring, and collection.
In equipment leasing, in evaluating our allowance for possible losses,
we consider our contractual delinquencies, economic conditions and trends,
industry statistics, lease portfolio characteristics and management's prior
experience with similar lease assets. At September 30, 2004, our credit
evaluation indicated that we have no need for an allowance for possible losses
for our lease assets.
59
In energy, in evaluating our allowance for possible losses, we perform
ongoing credit evaluations of our customers and adjust credit limits based upon
payment history and the customer's current creditworthiness, as determined by
our review of our customer's credit information. We extend credit on an
unsecured basis to many of our energy customers. At September 30, 2004, our
credit evaluation indicated that we have no need for an allowance for possible
losses for our oil and gas receivables.
In real estate, in evaluating the carrying value of our investments and
our allowance for possible losses, we consider general and local economic
conditions, neighborhood values, competitive overbuilding, casualty losses and
other factors which may affect the value of our loans. The value of our
investments may also be affected by factors such as the cost of compliance with
regulations and liability under applicable environmental laws, changes in
interest rates and the availability of financing. Income from a property will be
reduced if a significant number of tenants are unable to pay rent or if
available space cannot be rented on favorable terms. We reduce our investment in
real estate loans by an allowance for amounts that may become unrealizable in
the future. Such allowance can be either specific to a particular loan or
property or general to all loans or properties. As of September 30, 2004 and
2003, we had investments in real estate loans and real estate of $47.1 million
and $68.9 million, net of an allowance for possible losses of $989,000 and $1.4
million, respectively. We believe our allowance for possible losses is adequate
at September 30, 2004. However, an adverse change in the facts and circumstances
with regard to one of our larger loans or properties could cause us to
experience a loss in excess of our allowance.
We believe that our allowance for possible losses is reasonable based
on our experience and our analysis of the net realizable value of our
receivables at September 30, 2004.
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 U.S. Securities and Exchange
Commission, as to natural gas and oil prices, drilling and operating expenses,
capital expenditures, taxes and availability of funds. Any significant variance
in these assumptions could materially affect the estimated quantity of our
reserves. As a result, our estimates of our proved natural gas and oil reserves
are inherently imprecise. Actual future production, natural gas and oil prices,
revenues, taxes, development expenditures, operating expenses and quantities of
recoverable natural gas and oil reserves may vary substantially from our
estimates or estimates contained in the reserve reports and may affect our
ability to pay amounts due under our credit facilities or cause a reduction in
our energy credit facilities. In addition, our proved reserves may be subject to
downward or upward revision based upon production history, results of future
exploration and development, prevailing natural gas and oil prices, mechanical
difficulties, governmental regulation and other factors, many of which are
beyond our control.
Impairment of Oil and Gas Properties
We review our producing oil and gas properties for impairment on an
annual basis and whenever events and circumstances indicate a decline in the
recoverability of their carrying values. We estimate the expected future cash
flows from our oil and gas properties and compare such future cash flows to the
carrying amount of the oil and gas properties to determine if the carrying
amount is recoverable. If the carrying amount exceeds the estimated undiscounted
future cash flows, we will adjust the carrying amount of the oil and gas
properties to their fair value in the current period. The factors used to
determine fair value include, but are not limited to, estimates of reserves,
future production estimates, anticipated capital expenditures, and a discount
rate commensurate with the risk associated with realizing the expected cash
flows projected. Because of the complexities associated with oil and gas reserve
estimates and the history of price volatility in the oil and gas markets, events
may arise that will require us to record an impairment of our oil and gas
properties. Any such impairment may affect or cause a reduction in our energy
credit facilities.
60
Dismantlement, Restoration, Reclamation and Abandonment Costs
On an annual basis, we estimate the costs of future dismantlement,
restoration, reclamation and abandonment of our natural gas and oil-producing
properties. We also estimate the salvage value of equipment recoverable upon
abandonment. On October 1, 2002 we adopted SFAS 143, as discussed in Note 2 to
our consolidated financial statements. As of September 30, 2004, 2003 and 2002,
our estimate of salvage values was greater than or equal to our estimate of the
costs of future dismantlement, restoration, reclamation and abandonment. A
decrease in salvage values or an increase in dismantlement, restoration,
reclamation and abandonment costs from those we have estimated, or changes in
our estimates or costs, could reduce our gross profit from energy operations.
Goodwill and Other Long-Lived Assets
Goodwill and other intangibles with an indefinite useful life are no
longer amortized, but instead are assessed for impairment annually. We have
recorded goodwill of $37.5 million in connection with several acquisitions of
assets. In assessing impairment of goodwill, we use estimates and assumptions in
estimating the fair value of reporting units. If under these estimates and
assumptions we determine that the fair value of a reporting unit has been
reduced, the reduction can result in an "impairment" of goodwill. However,
future results could differ from the estimates and assumptions we use. Events or
circumstances which might lead to an indication of impairment of goodwill would
include, but might not be limited to, prolonged decreases in expectations of
long-term well servicing and/or drilling activity or rates brought about by
prolonged decreases in natural gas or oil prices, changes in government
regulation of the natural gas and oil industry or other events which could
affect the level of activity of exploration and production companies.
In assessing impairment of long-lived assets other than goodwill, where
there has been a change in circumstances indicating that the carrying amount of
a long-lived asset may not be recoverable, we have estimated future undiscounted
net cash flows from the use of the asset based on actual historical results and
expectations about future economic circumstances, including natural gas and oil
prices and operating costs. Our estimate of future net cash flows from the use
of an asset could change if actual prices and costs differ due to industry
conditions or other factors affecting our performance.
61
Revenue Recognition
Energy. We conduct certain energy activities through, and a portion of
our revenues are attributable to, sponsored energy limited partnerships. These
energy partnerships raise capital from investors to drill gas and oil wells. We
serve as general partner of the energy partnerships and assume customary rights
and obligations for them. As the general partner, we are 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 our general partner interest is recorded when the gas and oil are sold by a
partnership.
We contract with the energy partnerships to drill partnership wells.
The contracts require that the energy partnerships must pay us the full contract
price upon execution. The income from a drilling contract is recognized as the
services are performed. The contracts are typically completed in less than 60
days. On an uncompleted contract, we classify the difference between the
contract payments we have received and contract costs previously incurred as a
current liability.
We recognize gathering, transmission and processing revenues at the
time the natural gas and liquids are delivered.
We recognize well services revenues at the time the services are
performed.
We are entitled to receive management fees according to the respective
partnership agreements. We recognize such fees as income when earned and include
them in energy revenues.
We record the income from the working interests and overriding
royalties of wells in which we own an interest when the gas and oil are
delivered.
Real Estate. We sponsored and manage two real estate partnerships which
were organized to invest in multi-family residential properties. We receive
acquisition fees equal to 1.75% (previously 2%) of the net purchase price of
properties acquired and an additional 1.75% (previously 2%) fee for debt
placement related to the properties acquired. We recognize these fees upon
acquiring the properties and obtaining the related financing. We sponsored a
third real estate partnership in the third quarter of fiscal 2004, which is
still in the offering stage at September 30, 2004.
We also receive a fee equal to 5% of the gross operating revenues from
the partnerships' properties, payable monthly. We recognize this fee as the
partnerships' revenues are earned. Additionally, we receive an annual investment
management fee from the partnerships equal to 1% of the gross offering proceeds
of the partnership for our services. This investment management fee is
recognized ratably over each annual period.
We accrete the difference between our 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. We review projected cash flows, which
include amounts realizable from the underlying properties, on a regular basis.
Changes to projected cash flows, which can be based upon updated property
appraisals, changes to the property and changes to the real estate market in
general, reduce or increase the amounts accreted into interest income over the
remaining life of the loan. We also utilize the cost recovery method for loans
when appropriate under the circumstances.
62
Equipment Leasing. Our lease transactions are generally classified as
direct financing leases in accordance with SFAS No. 13 and its amendments (as
distinguished from sales-type or operating leases). Such leases transfer
substantially all benefits and risks of equipment ownership to the customer.
Unearned lease income, which is recognized as revenue over the term of the lease
by the effective interest method, represents the excess of the total future
minimum lease payments plus the estimated unguaranteed residual value expected
to be realized at the end of the lease term over the cost of the related
equipment. We generally discontinue the recognition of revenue for leases for
which payments are more than 90 days past due. Initial direct costs incurred in
consummating a lease are capitalized as part of the investment in lease
receivables and amortized over the lease term as a reduction in the yield.
Leases not meeting any of the criteria to be classified as direct
financing leases are deemed to be operating leases. Rental income consists
primarily of monthly periodic rentals due under the terms of the leases.
Generally, during the lease terms of existing operating leases, we will not
recover all of the undepreciated cost and related expenses of its rental
equipment and, therefore, we are prepared to remarket the equipment in future
years. Our policy is to review quarterly the expected economic life of its
rental equipment in order to determine the recoverability of its undepreciated
cost. In accordance with accounting principles generally accepted in the United
States, we write down our rental equipment to its estimated net realizable value
when it is probable that its carrying amount exceeds such value and the excess
can be reasonably estimated; gains are only recognized upon actual sale of our
rental equipment.
We receive acquisition fees from certain parties equal to a percentage
of the cost of leased equipment acquired on behalf of these parties as
compensation for acquisition expenses incurred related to the lease acquisition.
These fees are earned at the time of the sale of the related leased equipment to
those parties.
We receive management fees for managing and servicing the leased assets
acquired on behalf of these parties and earn fees at the time the service is
performed. We receive servicing fees ranging from 2% to 6% of gross rental
payments received from certain parties and for others, we receive servicing
fees that average 1% of the managed portfolio balance. In addition, we also
receive fees as a reimbursement of our operating and administrative expenses
incurred to manage the Partnerships.
63
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 risks arising from
changes in interest rates and oil and gas prices. The disclosures are not meant
to be precise indicators of the effects of expected changes in market
conditions, but rather indicators of the effects of reasonably possible changes.
This forward-looking information provides indicators of how we view and manage
our ongoing market risk exposures. All of our market risk sensitive instruments
were entered into for purposes other than trading.
GENERAL
We are exposed to various market risks, principally fluctuating
interest rates and changes in commodity prices. These risks can impact our
results of operations, cash flows and financial position. We manage these risks
through regular operating and financing activities and periodically use
derivative financial instruments such as forward contracts and interest rate cap
and swap agreements.
The following analysis presents the effect on our earnings, cash flows
and financial position as if hypothetical changes in market risk factors
occurred on September 30, 2004. 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, 2004, the amount outstanding under
Atlas America's credit facility had decreased to $25.0 million from $31.0
million at September 30, 2003. The weighted average interest rate for this
facility increased from 2.9% at September 30, 2003 to 4.1% at September 30, 2004
due to a larger portion of our borrowings being at the bank's prime rate and an
increase in short term market interest rates. Holding all other variables
constant, a hypothetical 10% change in the weighted average interest rate would
change our net income by approximately $55,000.
At September 30, 2004, Atlas Pipeline had a $75.0 million four-year
revolving line of credit which can be increased by an additional $40.0 million
under certain circumstances and a $60.0 million five year-term loan, to fund the
expansion of its existing gathering systems and the acquisition of other gas
gathering systems. Atlas Pipeline had $60.0 million drawn on this facility at
September 30, 2004. The weighted average interest rate for borrowings under this
credit facility was 6.0% at September 30, 2004. Holding all other variables
constant, a hypothetical 10% change in the weighted average interest rate would
change our net income by approximately $46,000.
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
limit our exposure to changing natural gas prices, we use hedges. Through our
hedges, we seek to provide a measure of stability in the volatile environment of
natural gas prices. Our risk management objective is to lock in a range of
pricing for expected production volumes.
64
Atlas America does not hold or issue derivative instruments for trading
purposes. Historically, it has entered into financial hedging activities for a
portion of its projected natural gas production. Atlas America recognizes 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 Atlas America delivers the
associated natural gas. Atlas America determines 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. We recognized losses of $1.1
million and $59,000 on settled contracts during the years ended September 30,
2004 and 2003, respectively. Atlas America had no open hedge transactions in
place as of September 30, 2004.
Atlas America also enters into forward sales transactions which are not
deemed hedges for accounting purposes because they require firm delivery of
natural gas. Thus, Atlas America limits these arrangements to much smaller
quantities than those projected to be available at any delivery point. The price
paid by FirstEnergy Solutions, Colonial Energy, Inc., UGI Energy Services, and
any other third-party marketers for certain volumes of natural gas sold under
these sales agreements may be significantly different from the underlying
monthly spot market value.
The portion of natural gas that Atlas America engages in forward sales
and the manner in which it is sold (e.g., fixed pricing, floor and/or floor
price with a cap, which we refer to as a costless collar) changes from time to
time. As of September 30, 2004, Atlas America's overall forward sales position
for the future months ending March 2006 for its natural gas production was
approximately as follows:
o 48% was sold with a fixed price;
o 1% was sold with a floor price and/or costless collar price; and
o 51% was sold subject to market-based pricing.
Atlas America also enters into forward sales transactions, which we
discuss in Item 1, "Business - Energy - Forward Sales."
In our Mid-Continent operations, we are exposed to commodity price
risks as a result of being paid for certain services in the form of commodities
rather than cash. For gathering services, we receive fees or commodities from
the producers to bring the raw natural gas from the wellhead to the processing
plant. For processing services, we receive either fees or commodities as payment
for these services, based on the type of contractual agreement. Based on our
current contract mix, we have a long NGL position and a long natural gas
position. Based upon our portfolio of supply contracts, without giving effect to
hedging activities that would reduce the impact of commodity price decreases, a
decrease of $0.01 per gallon in the price of NGLs and $0.10 per million BTUs in
the average price of natural gas would result in decreases in annual net income
of approximately $227,000 and $146,000, respectively. In addition, a decrease of
$1.00 per barrel in the average price of crude oil would result in a decrease to
annual net income of approximately $46,000.
Our Mid-Continent operations also entered into financial swap
instruments, some of which settled during the three months ended September 30,
2004, that are designated as cash flow hedging instruments in accordance with
SFAS 133. The maturities of the instruments outstanding at September 30, 2004
are less than three years. The swap instruments are contractual agreements to
exchange obligations of money between the buyer and seller of the instruments as
natural gas, NGLs and crude oil volumes during the pricing period are sold. The
swaps are tied to a set fixed price for the seller and floating prices for the
buyer based on specified market index prices at the end of the relevant trading
period. We also enter into offsetting option transactions that fix the price for
the seller within the range of prices established by puts purchased and calls
sold and provide floating prices for the buyer based on specified market index
prices at the end of the relevant trading period. We entered into these
instruments to hedge the residue natural gas, NGLs and condensate sales that we
had forecasted would occur against variability in expected future cash flows
attributable to changes in market prices. For the instruments that were settled
during the year ended September 30, 2004, we recognized a loss of $27,000.
Spectrum entered into several swaps that were designed to hedge NGLs
prices during the three months ended September 30, 2004 that did not meet
specific hedge accounting criteria. Spectrum recognized a loss of $697,000
related to these instruments during the year ended September 30, 2004.
65
As of September 30, 2004, Atlas Pipeline had the following NGLs,
natural gas, and crude oil volumes hedged.
NATURAL GAS LIQUIDS FIXED-PRICE SWAPS
Production Average Fair Value
Period Volumes Fixed Price Liability
---------- --------- ----------- --------------
(calendar year) gallons (per gallon) (in thousands)
2004 2,562,000 $ 0.645 $ (282)
2005 10,584,000 0.537 (2,524)
2006 6,804,000 0.575 (1,030)
---------
$ (3,836)
=========
NATURAL GAS FIXED - PRICE SWAPS
Production Average Fair Value
Period Volumes Fixed Price Liability
---------- --------- ----------- --------------
(calendar year) (MMBTU)(1) (per MMBTU) (in thousands)
2005 960,000 $ 6.165 $ (697)
2006 450,000 5.920 (160)
---------
$ (857)
=========
NATURAL GAS OPTIONS
Production Average Fair Value
Period Option Type Volumes Strike Price Asset (Liability)
---------- ----------- --------- ------------ -----------------
(calendar year) (MMBTU)(1) (per MMBTU) (in thousands)
2004 Puts purchased 150,000 $ 5.700 $ 7
2004 Calls sold 150,000 6.970 (41)
2005 Puts purchased 180,000 5.875 -
2005 Calls sold 180,000 7.110 (145)
--------
$ (179)
========
CRUDE FIXED - PRICE SWAPS
Production Average Fair Value
Period Volumes Fixed Price Liability
---------- --------- ----------- --------------
(calendar year) (barrels) (per barrel) (in thousands)
2006 18,000 $ 38.767 $ (31)
==========
CRUDE OPTIONS
Production Average Fair Value
Period Option Type Volumes Strike Price Liability
---------- ----------- --------- ------------ --------------
(calendar year) (barrels) (per barrel) (in thousands)
2004 Puts purchased 25,000 $ 32.200 $ -
2004 Calls sold 25,000 38.560 (244)
2005 Puts purchased 75,000 30.067 -
2005 Calls sold 75,000 34.383 (846)
2006 Puts purchased 5,000 30.000 -
2006 Calls sold 5,000 34.250 (39)
--------
$ (1,129)
--------
Total $ (6,032)
========
- -------------------
(1) MMBTU means million British Thermal Units.
66
As of September 30, 2004, the fair value of the swap agreements Atlas
Pipeline had entered into in order to convert our market-sensitive floating
price contracts to fixed-price positions resulted in a $6.0 million liability.
REAL ESTATE
Portfolio Loans and Related Senior Liens. We believe that none of the
six loans held in our portfolio as of September 30, 2004 (including loans
treated in our consolidated financial statements as FIN 46 assets and
liabilities) are sensitive to changes in interest rates since:
o the loans are subject to forbearance or other agreements that
require all of the operating cash flow from the properties
underlying the loans, after debt service on senior lien
interests, to be paid to us and thus are not currently being
paid based on the stated interest rates of the loans;
o the senior lien interests are at fixed rates and are thus not
subject to interest rate fluctuation that would affect
payments to us; and
o each loan has significant accrued and unpaid interest and
other charges outstanding to which cash flow from the
underlying property would be applied even if cash flow were to
exceed the interest due, as originally underwritten.
EQUIPMENT LEASING
At September 30, 2004, the amount outstanding on LEAF Financial's
credit facility with National City Bank was $8.5 million at a weighted average
interest rate of 4.3% while the amount outstanding on its $15.0 million credit
facility with Commerce Bank was $9.6 million at a weighted average interest rate
of 4.4%. A hypothetical 10% change in the weighted average interest rates on
these facilities would change our net income by approximately $54,700.
67
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
[THE REMAINDER OF THIS PAGE INTENTIONALLY LEFT BLANK]
68
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Stockholders and Board of Directors
RESOURCE AMERICA, INC.
We have audited the accompanying consolidated balance sheets of Resource
America, Inc. (a Delaware corporation) and subsidiaries as of September 30, 2004
and 2003, 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, 2004. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). 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, 2004 and 2003, and the consolidated
results of their operations and cash flows for each of the three years in the
period ended September 30, 2004, in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 2 to the notes to consolidated financial statements,
effective October 1, 2002, the Company adopted Statement of Financial Accounting
Standards No. 143, Accounting for Asset Retirement Obligations, and changed its
method of accounting for its plugging and abandonment liability related to its
oil and gas wells and associated pipelines and equipment.
As discussed in Note 3 to the notes to consolidated financial statements,
effective July 1, 2003, the Company adopted FASB Interpretation 46,
Consolidation of Variable Interest Entities, and changed its method of
accounting for certain investments in real estate loans.
Our audits were conducted for the purpose of forming an opinion on the basic
financial statements taken as a whole. Schedules I, III and IV are presented for
purposes of additional analysis and are not a required part of the basic
financial statements. These schedules have been subjected to the auditing
procedures applied in the audit of the basic financial statements and, in our
opinion, are fairly stated in all material respects in relation to the basic
financial statements taken as a whole.
/s/ Grant Thornton LLP
Cleveland, Ohio
November 22, 2004
69
RESOURCE AMERICA, INC.
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 2004 AND 2003
2004 2003
-------- --------
(in thousands,
except share data)
ASSETS
Current assets:
Cash and cash equivalents................................................. $ 69,099 $ 42,818
Investments in lease assets............................................... 24,177 6,817
Accounts receivable and prepaid expenses.................................. 31,634 24,012
Assets held for sale...................................................... 102,963 222,677
-------- --------
Total current assets.................................................... 227,873 296,324
Investments in real estate loans and real estate............................. 47,119 68,936
Investment in RAIT Investment Trust.......................................... 3,026 20,511
Property and equipment, net.................................................. 374,192 219,445
Other assets................................................................. 28,593 19,582
Intangible assets, net....................................................... 7,433 8,476
Goodwill, net of accumulated amortization of $4,532.......................... 37,470 37,470
-------- --------
$725,706 $670,744
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt......................................... $ 6,151 $ 60,579
Secured revolving credit facility - equipment leasing..................... 8,487 7,168
Accounts payable.......................................................... 25,413 23,951
Liabilities associated with assets held for sale.......................... 65,300 141,473
Accrued liabilities....................................................... 38,679 14,749
Liabilities associated with drilling contracts............................ 29,375 22,158
-------- --------
Total current liabilities............................................... 173,405 270,078
Long-term debt............................................................... 114,696 110,208
Deferred revenue and other liabilities....................................... 9,263 6,150
Deferred income taxes........................................................ 19,677 12,878
Minority interests........................................................... 150,750 43,976
Commitments and contingencies................................................ - -
Stockholders' equity:
Preferred stock, $1.00 par value: 1,000,000 authorized shares............. - -
Common stock, $0.01 par value: 49,000,000 authorized shares............... 255 255
Additional paid-in capital................................................ 247,865 227,211
Less treasury stock, at cost.............................................. (77,667) (78,860)
Less ESOP loan receivable................................................. (1,127) (1,137)
Accumulated other comprehensive (loss) income............................. (1,575) 5,611
Retained earnings......................................................... 90,164 74,374
-------- --------
Total stockholders' equity.............................................. 257,915 227,454
-------- --------
$725,706 $670,744
======== ========
See accompanying notes to consolidated financial statements
70
RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002
2004 2003 2002
-------- -------- --------
(in thousands, except per share data)
REVENUES
Energy....................................................................... $180,352 $105,262 $ 97,912
Real estate.................................................................. 18,884 13,678 16,582
Equipment leasing............................................................ 8,262 4,071 1,246
Equity in earnings of structured finance investees........................... 7,343 1,444 185
-------- -------- --------
214,841 124,455 115,925
COSTS AND EXPENSES
Energy....................................................................... 125,716 67,215 69,580
Real estate.................................................................. 15,836 4,610 2,423
Equipment leasing............................................................ 8,890 5,883 745
Structured finance........................................................... 2,128 - -
General and administrative................................................... 7,062 6,925 7,889
Atlas America, Inc. planned spin-off......................................... 1,723 - -
Depreciation, depletion and amortization..................................... 15,568 12,148 11,161
Provision for possible losses................................................ 642 1,848 1,393
Provision for legal settlements.............................................. - 1,185 1,000
-------- -------- --------
177,565 99,814 94,191
-------- -------- --------
OPERATING INCOME............................................................. 37,276 24,641 21,734
OTHER INCOME (EXPENSE)
Interest expense............................................................. (6,616) (12,789) (12,740)
Minority interest in Atlas Pipeline Partners, L.P............................ (4,961) (4,439) (2,605)
Other income, net............................................................ 9,670 7,114 5,383
-------- -------- --------
(1,907) (10,114) (9,962)
-------- -------- --------
Income from continuing operations before income taxes, minority interest,
and cumulative effects of changes in accounting principles............... 35,369 14,527 11,772
Provision for income taxes................................................... 12,025 4,649 3,414
-------- -------- --------
Income from continuing operations before minority interest and
cumulative effects of changes in accounting principles................... 23,344 9,878 8,358
Minority interest in Atlas America, Inc., net of taxes....................... (1,881) - -
-------- -------- --------
Income from continuing operations............................................ 21,463 9,878 8,358
(Loss) income on discontinued operations, net of taxes....................... (3,054) 1,088 (11,040)
Cumulative effects of changes in accounting principles, net of taxes......... - (13,881) (627)
-------- -------- --------
NET INCOME (LOSS)............................................................ $ 18,409 $ (2,915) $ (3,309)
======== ======== ========
NET INCOME (LOSS) PER COMMON SHARE - BASIC:
From continuing operations................................................... $ 1.23 $ 0.58 $ 0.48
Discontinued operations...................................................... (0.17) 0.06 (0.63)
Cumulative effects of changes in accounting principles....................... - (0.81) (0.04)
-------- -------- --------
Net income (loss) per common share - basic................................... $ 1.06 $ (0.17) $ (0.19)
======== ======== ========
Weighted average common shares outstanding................................... 17,417 17,172 17,446
======== ======== ========
NET INCOME (LOSS) PER COMMON SHARE - DILUTED:
From continuing operations................................................... $ 1.17 $ 0.56 $ 0.47
Discontinued operations...................................................... (0.16) 0.06 (0.62)
Cumulative effects of changes in accounting principles....................... - (0.79) (0.04)
-------- -------- --------
Net income (loss) per common share - diluted................................. $ 1.01 $ (0.17) $ (0.19)
======== ======== ========
Weighted average common shares............................................... 18,309 17,568 17,805
======== ======== ========
See accompanying notes to consolidated financial statements
71
RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002
2004 2003 2002
------- -------- --------
(in thousands)
Net income (loss)........................................................... $18,409 $ (2,915) $ (3,309)
Other comprehensive (loss) income:
Unrealized gain on investment in RAIT Investment Trust,
net of taxes of $827, $1,040 and $2,305................................ 1,606 2,211 4,475
Less: reclassification adjustment for gains realized in net income (loss),
net of taxes of $3,214 and $1,291...................................... (6,239) (2,744) -
------- -------- --------
(4,633) (533) 4,475
Unrealized holding losses on natural gas futures arising during the period
net of taxes of $1,384, $245 and $118................................ (2,571) (520) (263)
Less: reclassification adjustment for losses realized in net income (loss),
net of taxes of $10, $355 and $17...................................... 18 753 42
------- -------- --------
(2,553) 233 (221)
------- -------- --------
Comprehensive income (loss)................................................. $11,223 $ (3,215) $ 945
======= ======== ========
See accompanying notes to consolidated financial statements
72
RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED SEPTEMBER 30, 2004, 2003, AND 2002
(in thousands, except share data)
Accumulated
Common Stock Additional Treasury Stock ESOP Other
------------------- Paid-In -------------------- Loan Comprehensive
Shares Amount Capital Shares Amount Receivable Income (Loss)
-------------------------------------------------------------------------------------
Balance, September 30, 2001.................. 24,940,037 $ 249 $223,712 (7,498,613) $(74,080) $(1,297) $ 1,657
Treasury shares issued....................... (429) 31,537 769
Issuance of common stock..................... 104,029 1 297
Tax benefit from employee stock options...... 244
Purchase of treasury shares.................. (156,122) (1,517)
Other comprehensive income................... 4,254
Cash dividends ($0.13 per share).............
Repayment of ESOP loan....................... 96
Net loss.....................................
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2002.................. 25,044,066 $ 250 $223,824 (7,623,198) $(74,828) $(1,201) $ 5,911
Treasury shares issued....................... (373) 29,666 622
Issuance of common stock..................... 419,579 5 3,352
Tax benefit from employee stock options...... 408
Purchase of treasury shares.................. (519,968) (4,654)
Other comprehensive loss..................... (300)
Cash dividends ($0.13 per share).............
Repayment of ESOP loan....................... 64
Net loss.....................................
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2003.................. 25,463,645 $ 255 $227,211 (8,113,500) $(78,860) $(1,137) $ 5,611
Treasury shares issued....................... (440) 60,438 1,193
Gain on sale of Atlas America, Inc. shares... 20,360
Issuance of common stock..................... 83,987 613
Tax benefit from employee stock options...... 121
Other comprehensive loss..................... (7,186)
Cash dividends ($0.17 per share).............
Repayment of ESOP loan....................... 10
Net income...................................
- ------------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2004.................. 25,547,632 $ 255 $247,865 8,053,062 $(77,667) $(1,127) $(1,575)
====================================================================================================================================
[RESTUBBED TABLE]
Total
Retained Stockholders'
Earnings Equity
------------------------
Balance, September 30, 2001.................. $ 85,218 $235,459
Treasury shares issued....................... 340
Issuance of common stock..................... 298
Tax benefit from employee stock options...... 244
Purchase of treasury shares.................. (1,517)
Other comprehensive income................... 4,254
Cash dividends ($0.13 per share)............. (2,326) (2,326)
Repayment of ESOP loan....................... 96
Net loss..................................... (3,309) (3,309)
- --------------------------------------------- ---------------------
Balance, September 30, 2002.................. $ 79,583 $233,539
Treasury shares issued....................... 249
Issuance of common stock..................... 3,357
Tax benefit from employee stock options...... 408
Purchase of treasury shares.................. (4,654)
Other comprehensive loss..................... (300)
Cash dividends ($0.13 per share)............. (2,294) (2,294)
Repayment of ESOP loan....................... 64
Net loss..................................... (2,915) (2,915)
- --------------------------------------------- ------------------------
Balance, September 30, 2003.................. $ 74,374 $227,454
Treasury shares issued....................... 753
Gain on sale of Atlas America, Inc. shares... 20,360
Issuance of common stock..................... 613
Tax benefit from employee stock options...... 121
Other comprehensive loss..................... (7,186)
Cash dividends ($0.17 per share)............. (2,619) (2,619)
Repayment of ESOP loan....................... 10
Net income................................... 18,409 18,409
- --------------------------------------------- ------------------------
Balance, September 30, 2004.................. $ 90,164 $257,915
============================================= ========================
See accompanying notes to consolidated financial statements
73
RESOURCE AMERICA, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002
2004 2003 2002
--------- --------- ---------
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss).......................................................... $ 18,409 $ (2,915) $ (3,309)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation, depletion and amortization................................ 15,568 12,148 11,161
Amortization of discount on senior notes and deferred finance costs..... 1,212 1,762 1,095
Provision for possible losses........................................... 642 1,848 1,393
Minority interests...................................................... 6,842 4,439 2,605
Equity in (earnings) loss of equity investees........................... (8,582) (1,683) (639)
Loss (income) on discontinued operations................................ 3,054 (1,088) 11,040
Deferred income taxes................................................... 12,025 1,616 (7,413)
Accretion of discount................................................... (1,909) (1,962) (3,212)
Collection of interest.................................................. 1,853 1,130 5,243
Non-cash compensation................................................... 2,199 250 341
Cumulative effects of changes in accounting principles.................. - 13,881 627
Terminated acquisition.................................................. 2,987 - -
Net gains on asset dispositions......................................... (7,922) (4,775) (2,507)
Property impairments, abandonments and write-downs...................... 2,271 24 24
Changes in operating assets and liabilities................................. (3,829) 20,021 (9,982)
--------- --------- ---------
Net cash provided by operating activities of continuing operations......... 44,820 44,696 6,467
CASH FLOWS FROM INVESTING ACTIVITIES:
Net cash paid in asset acquisitions........................................ (141,564) - -
Capital expenditures....................................................... (42,766) (28,568) (21,967)
Principal payments on notes receivable and proceeds from sale of assets.... 26,441 10,053 25,220
Proceeds from sales (purchases) of RAIT Investment Trust shares............ 20,170 12,044 (1,890)
Increase in other assets................................................... 616 (1,586) (6,008)
Investments in real estate loans and real estate........................... (4,899) (5,921) (19,859)
--------- --------- ---------
Net cash used in investing activities of continuing operations............. (142,002) (13,978) (24,504)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings................................................................. 326,389 96,937 173,753
Principal payments on borrowings........................................... (362,416) (120,135) (168,619)
Net proceeds from public offerings......................................... 129,705 25,182 -
Distributions paid to minority interests of Atlas Pipeline Partners, L.P... (7,271) (4,233) (3,623)
Dividends paid............................................................. (2,619) (2,294) (2,326)
Purchase of treasury stock................................................. - (4,654) (1,517)
Repayment of ESOP loan..................................................... 10 64 96
Increase in other assets................................................... (4,097) (1,812) (1,258)
Proceeds from issuance of stock............................................ 582 2,933 17
--------- --------- ---------
Net cash provided by (used in) financing activities of
continuing operations................................................... 80,283 (8,012) (3,477)
Net cash provided by (used in) discontinued operations..................... 43,180 (5,624) (1,398)
--------- --------- ---------
Increase (decrease) in cash and cash equivalents........................... 26,281 17,082 (22,912)
Cash and cash equivalents at beginning of year............................. 42,818 25,736 48,648
--------- --------- ---------
Cash and cash equivalents at end of year................................... $ 69,099 $ 42,818 $ 25,736
========= ========= =========
See accompanying notes to consolidated financial statements
74
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2004
NOTE 1 - NATURE OF OPERATIONS
Resource America, Inc. (the "Company") is a specialized asset
management company that uses industry specific expertise to generate and
administer investment opportunities for the Company and for outside investors in
the energy, real estate, equipment leasing and structured finance sectors. As a
specialized asset manager, the Company seeks to develop investment vehicles in
which outside investors invest along with the Company and for which the Company
manages the assets acquired pursuant to long-term management and operating
agreements. The Company limits investment vehicles to investment areas where it
owns existing operating companies or has specific expertise.
In energy, through Atlas America, Inc. ("Atlas America") an 80.2% owned
subsidiary, the Company sponsors drilling partnerships, produces and sells
natural gas and, to a significantly lesser extent, oil. The Company finances a
substantial portion of its drilling activities through drilling partnerships it
sponsors. The Company typically acts as the managing general partner of these
partnerships and has a material partnership interest. The Company, through Atlas
Pipeline Partners, L.P. ("Atlas Pipeline"), transports natural gas from wells it
owns and operates and wells owned by others to interstate pipelines and, in some
cases, to end users and operates a natural gas processing facility. Atlas
Pipeline is a master limited partnership in which the Company has a 24%
interest. A subsidiary of the Company is the general partner of Atlas Pipeline.
In real estate, the Company has expanded its real estate operations
through the sponsorship of real estate investment partnerships. It has sponsored
three such investment partnerships, two of which have commenced operations and
the other of which was in the offering stage as of September 30, 2004. The
Company also manages a portfolio of real estate loans and, principally as a
result of loan restructurings or foreclosures, interests in real property.
In equipment leasing, the Company has sponsored two publicly-held
equipment leasing partnerships. The first partnership commenced operations in
March 2003 and the other was in the pre-offering stage as of September 30, 2004.
In April 2003, the Company entered into an agreement with a third party under
which the Company originates equipment leases and sells them to the third party.
In structured finance, the Company has acted as the co-sponsor of seven
issuers of collateralized debt obligations ("CDOs") that invest in trust
preferred securities of banks, bank holding companies and similar financial
institutions. Six of the CDO issuers have commenced operations; the seventh was
in the offering stage as of September 30, 2004. In 2004, a wholly-owned
subsidiary was formed to develop and sponsor CDO issuers holding asset-backed
securities.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
RECLASSIFICATIONS
Certain reclassifications have been made to the fiscal 2003 and fiscal
2002 consolidated financial statements to conform to the fiscal 2004
presentation.
75
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
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 and Atlas America. Through Atlas America, in accordance with
established practice in the oil and gas industry, the Company also includes its
pro-rata share of assets, liabilities, revenues and costs and expenses of the
energy partnerships in which the Company has an interest. In addition,
commencing with the adoption of Financial Accounting Standards Board ("FASB")
Interpretation 46, "Consolidation of Variable Interest Entities" ("FIN 46") on
July 1, 2003, the Company consolidated certain variable interest entities
("VIEs") in which it has determined that it is the primary beneficiary. All
material intercompany transactions have been eliminated.
USE OF ESTIMATES
Preparation of the consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and the disclosure of contingent assets and
liabilities as of the date of the consolidated financial statements and the
reported amounts of revenues and costs and expenses during the reporting period.
Actual results could differ from these estimates.
IMPAIRMENT OF LONG-LIVED ASSETS
The Company reviews its long-lived assets for impairment whenever
events or circumstances indicate that the carrying amount of an asset may not be
recoverable. If it is determined that an asset's estimated future cash flows
will not be sufficient to recover its carrying amount, an impairment charge may
be required to reduce the carrying amount for that asset to its estimated fair
value.
STOCK-BASED COMPENSATION
The Company accounts for its stock option plans in accordance with the
provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees ("APB 25"), and related interpretations. Compensation
expense is recorded on the date of grant only if the current market price of the
underlying stock exceeded the exercise price. The Company adopted the disclosure
requirements of Statement of Financial Accounting Standards ("SFAS") No. 123,
"Accounting for Stock-Based Compensation" ("SFAS 123"), as amended by the
required disclosures SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure."
76
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
STOCK-BASED COMPENSATION - (CONTINUED)
No stock-based employee compensation cost is reflected in net income
(loss), as all options granted under those plans had an exercise price equal to
the market value of the underlying common stock on the date of grant.
SFAS 123 requires the disclosure of pro forma net income (loss) and
earnings (loss) per share as if the Company had adopted the fair value method
for stock options granted after June 30, 1996. Under SFAS 123, the fair value of
stock-based awards to employees is calculated through the use of option pricing
models, even though such models were developed to estimate the fair value of
freely tradable, fully transferable options without vesting restrictions, which
significantly differ from the Company's stock option awards. These models also
require subjective assumptions, including future stock price volatility and
expected time to exercise, which greatly affect the calculated values. The
Company's calculations were made using the Black-Scholes option pricing model
with the following weighted average assumptions: expected life, 10 years, stock
volatility, 23%, 70% and 64% in fiscal 2004, 2003 and 2002, respectively;
risk-free interest rate, 4.1%, 4.0% and 4.4% in fiscal 2004, 2003 and 2002,
respectively; dividends were based on the Company's historical rate.
The following table illustrates the effect on net income (loss) and
earnings per share if the Company had applied the fair value recognition
provisions of SFAS 123 to stock-based employee compensation.
Years Ended September 30,
-------------------------------------------
2004 2003 2002
----------- ------------ ------------
(in thousands, except per share data)
Net income (loss), as reported............................................ $ 18,409 $ (2,915) $ (3,309)
Less total stock-based employee compensation expense determined under
the fair value based method for all awards, net of income taxes........ (2,328) (3,100) (3,464)
----------- ----------- -----------
Pro forma net income (loss)............................................... $ 16,081 $ (6,015) $ (6,773)
=========== =========== ===========
Earnings (loss) per share:
Basic - as reported.................................................... $ 1.06 $ (0.17) $ (0.19)
Basic - pro forma...................................................... $ 0.92 $ (0.35) $ (0.39)
Diluted - as reported.................................................. $ 1.01 $ (0.17) $ (0.19)
Diluted - pro forma.................................................... $ 0.88 $ (0.35) $ (0.39)
77
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
COMPREHENSIVE INCOME (LOSS)
Comprehensive (loss) income includes net income (loss) and all other
changes in the equity of a business during a period from transactions and other
events and circumstances from non-owner sources. These changes, other than net
income (loss), are referred to as "other comprehensive (loss) 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 (loss) income is related to the following:
At September 30,
----------------------
2004 2003
------- ------
(in thousands)
Marketable securities - unrealized gains.................................. $ 978 $5,611
Unrealized hedging losses................................................. (2,553) -
------- ------
$(1,575) $5,611
======= ======
PROPERTY AND EQUIPMENT
Property and equipment consists of the following at the dates
indicated:
At September 30,
-----------------------
2004 2003
-------- --------
(in thousands)
Mineral interests:
Proved properties........................................................ $ 2,544 $ 844
Unproved properties...................................................... 1,002 563
Wells and related equipment.................................................. 184,046 150,657
Pipeline and compression facilities.......................................... 163,302 32,958
Rights-of-way................................................................ 14,702 561
Land, building and improvements.............................................. 7,394 3,984
Support equipment............................................................ 2,902 2,189
Real estate assets - FIN 46.................................................. 60,357 76,137
Other........................................................................ 7,413 5,202
-------- --------
443,662 273,095
Accumulated depreciation, depletion and amortization:
Oil and gas properties................................................... (63,551) (50,170)
Other ................................................................... (5,919) (3,480)
-------- --------
(69,470) (53,650)
-------- --------
$374,192 $219,445
======== ========
78
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
PROPERTY AND EQUIPMENT - (CONTINUED)
OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting.
Accordingly, property acquisition costs, costs of successful exploratory wells,
all development costs, and the cost of support equipment and facilities are
capitalized. Costs of unsuccessful exploratory wells are expensed when such
wells are determined to be nonproductive or, if this determination cannot be
made, within twelve months of completion of drilling. The costs associated with
drilling and equipping wells not yet completed are capitalized as uncompleted
wells, equipment, and facilities. Geological and geophysical costs and the costs
of carrying and retaining undeveloped properties, including delay rentals, are
expensed as incurred. Production costs, overhead and all exploration costs other
than the costs of exploratory drilling are charged to expense as incurred.
The Company assesses unproved and proved properties periodically to
determine whether there has been a decline in value and, if a decline is
indicated, a loss is recognized. The assessment of significant unproved
properties for impairment is on a property-by-property basis. The Company
considers whether a dry hole has been drilled on a portion of, or in close
proximity to, the property, the Company's intentions of further drilling, the
remaining lease term of the property, and its experience in similar fields in
close proximity. The Company assesses in the aggregate unproved properties whose
costs are individually insignificant. This assessment includes considering the
Company's experience with similar situations, the primary lease terms, the
average holding period of unproved properties and the relative proportion of
such properties on which proved reserves have been found in the past.
The Company compares the carrying value of its proved developed gas and
oil producing properties to the estimated future cash flows 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, 2004. If an impairment is indicated, the property costs are
written down to fair value based on the present value of estimated cash flows of
the property.
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.
79
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
PROPERTY AND EQUIPMENT - (CONTINUED)
DEPRECIATION, DEPLETION AND AMORTIZATION
The Company amortizes proved gas and oil properties, which include
intangible drilling and development costs, tangible well equipment and leasehold
costs, on the unit-of-production method using the ratio of current production to
the estimated aggregate proved developed gas and oil reserves.
The Company computes depreciation on property and equipment, other than
gas and oil properties, using the straight-line method over the estimated
economic lives, which range from three to 50 years.
ASSET RETIREMENT OBLIGATIONS
Effective October 1, 2002, the Company adopted SFAS No. 143,
"Accounting for Asset Retirement Obligations," which requires the Company to
recognize an estimated liability for the plugging and abandonment of its oil and
gas wells and associated pipelines and equipment. Under SFAS 143, the Company
must currently recognize a liability for future asset retirement obligations if
a reasonable estimate of the fair value of that liability can be made. The
present values of the expected asset retirement costs are capitalized as part of
the carrying amount of the long-lived asset. SFAS 143 requires the Company to
consider estimated salvage value in the calculation of depreciation, depletion
and amortization. Consistent with industry practice, historically the Company
had determined the cost of plugging and abandonment on its oil and gas
properties would be offset by salvage values received. The adoption of SFAS 143
resulted in (i) an increase of total liabilities because retirement obligations
are required to be recognized, (ii) an increase in the recognized cost of assets
because the retirement costs are added to the carrying amount of the long-lived
assets and (iii) a decrease in depletion expense, because the estimated salvage
values are now considered in the depletion calculation.
The estimated liability is based on historical experience in plugging
and abandoning wells, estimated remaining lives of those wells based on reserve
estimates, external estimates as to the cost to plug and abandon the wells in
the future, and federal and state regulatory requirements. The liability is
discounted using an assumed credit-adjusted risk-free interest rate. Revisions
to the liability could occur due to changes in estimates of plugging and
abandonment costs or remaining lives of the wells, or if federal or state
regulators enact new plugging and abandonment requirements.
The adoption of SFAS 143 as of October 1, 2002 resulted in a cumulative
effect adjustment to record (i) a $1.9 million increase in the carrying values
of proved properties, (ii) a $1.5 million decrease in accumulated depletion and
(iii) a $3.4 million increase in non-current plugging and abandonment
liabilities. The cumulative and pro forma effects of the application of SFAS 143
were not material to the Company's consolidated statements of operations.
The Company has no assets legally restricted for purposes of settling
asset retirement obligations. Except for the item previously referenced, the
Company has determined that there are no other material retirement obligations
associated with tangible long-lived assets.
80
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
ASSET RETIREMENT OBLIGATIONS - (CONTINUED)
A reconciliation of the Company's liability for well plugging and
abandonment costs for the years ended September 30, 2004 and 2003 is as follows
(in thousands):
September 30,
---------------------
2004 2003
------ ------
Asset retirement obligations, beginning of period......................... $3,131 $ -
Adoption of SFAS 143...................................................... - 3,380
Liabilities incurred...................................................... 1,724 93
Liabilities settled....................................................... (58) (52)
Revision in estimates..................................................... (205) (494)
Accretion expense......................................................... 296 204
------ ------
Asset retirement obligations, end of period............................... $4,888 $3,131
====== ======
The above accretion expense is included in depreciation, depletion and
amortization in the Company's consolidated statements of operations and the
asset retirement obligation liabilities are included in deferred revenue and
other liabilities in the Company's consolidated balance sheets.
INVESTMENT IN RAIT INVESTMENT TRUST
The Company accounts for its investment in RAIT Investment Trust
("RAIT") in accordance with SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities." This investment is classified as available-for-sale
and as such is carried at fair market value based on market quotes. Unrealized
gains and losses, net of taxes, are reported as a separate component of
stockholders' equity. The cost of securities sold is based on the specific
identification method.
The following table discloses the pre-tax unrealized gain relating to
the Company's investment in RAIT at the periods indicated:
September 30,
-------------------
2004 2003
------ -------
(in thousands)
Cost...................................................................... $1,543 $12,260
Unrealized gain........................................................... 1,483 8,251
------ -------
Estimated fair value...................................................... $3,026 $20,511
====== =======
In fiscal 2004, the Company sold 782,700 common shares of RAIT for
$20.2 million and realized gains of $9.5 million. In fiscal 2003, the Company
sold 542,600 common shares of RAIT for $12.0 million and realized gains of $4.0
million (see Note 5).
81
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
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 instrument 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:
At September 30, 2004 At September 30, 2003
--------------------- ---------------------
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
-------- ---------- -------- ----------
(in thousands)
Energy debt.................................................. $ 85,000 $ 85,000 $ 31,194 $ 31,194
Real estate debt............................................. 23,639 23,639 57,089 57,089
Equipment leasing debt....................................... 18,083 18,083 7,168 7,168
Senior debt.................................................. - - 54,027 55,648
Other debt................................................... 2,612 2,612 28,477 28,477
-------- -------- -------- --------
$129,334 $129,334 $177,955 $179,576
======== ======== ======== ========
For all debt except the senior debt, the carrying value approximates
fair value because of the short term maturity of these instruments and the
variable interest rates in the debt agreements. The fair value of the senior
debt was based upon the most recent purchase price of the debt by the Company.
DERIVATIVE INSTRUMENTS
The Company applies the provisions of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 requires
each derivative instrument to be recorded in the balance sheet as either an
asset or liability measured at fair value. Changes in a derivative instrument's
fair value are recognized currently in earnings unless specific hedge accounting
criteria are met.
82
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
CONCENTRATION OF CREDIT RISK
Financial instruments, which potentially subject the Company to
concentrations of credit risk, consist principally of periodic temporary
investments of cash and cash equivalents. 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,
2004, the Company had $75.4 million in deposits at various banks, of which $72.1
million was over the insurance limit of the Federal Deposit Insurance
Corporation. No losses have been experienced on such investments.
ENVIRONMENTAL MATTERS
The Company is subject to various federal, state and local laws and
regulations relating to the protection of the environment. The Company has
established procedures for the ongoing evaluation of its operations, to identify
potential environmental exposures and to comply with regulatory policies and
procedures.
The Company accounts for environmental contingencies in accordance with
SFAS No. 5, "Accounting for Contingencies." Environmental expenditures that
relate to current operations are expensed or capitalized as appropriate.
Expenditures that relate to an existing condition caused by past operations, and
do not contribute to current or future revenue generation, are expensed.
Liabilities are recorded when environmental assessments and/or clean-ups are
probable and the costs can be reasonably estimated. The Company maintains
insurance which may cover in whole or in part certain environmental
expenditures. For the three years ended September 30, 2004, the Company had no
environmental matters requiring specific disclosure or requiring recording of a
liability.
REVENUE RECOGNITION
ENERGY
The Company conducts certain energy activities through, and a portion
of its revenues are attributable to, sponsored energy limited partnerships.
These energy partnerships raise capital from investors to drill gas and oil
wells. The Company serves as general partner of the energy partnerships and
assumes customary rights and obligations for them. As the general partner, the
Company is liable for partnership liabilities and can be liable to limited
partners if it breaches its responsibilities with respect to the operations of
the partnerships. The income from the Company's general partner interest is
recorded when the gas and oil are sold by a partnership.
The Company contracts with the energy partnerships to drill partnership
wells. The contracts require that the energy partnerships must pay the Company
the full contract price upon execution. The income from a drilling contract is
recognized as the services are performed using the percentage of completion
method. The contracts are typically completed in less than 60 days. On an
uncompleted contract, the Company classifies the difference between the contract
payments it has received and the revenues earned as a current liability.
The Company recognizes gathering, transmission and processing revenues
at the time the natural gas and liquids are delivered.
83
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
REVENUE RECOGNITION - (CONTINUED)
ENERGY - (CONTINUED)
The Company recognizes well 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 records the income from the working interests and
overriding royalties of wells in which it owns an interest when the gas and oil
are delivered.
REAL ESTATE
The Company sponsored and manages two real estate partnerships which
were organized to invest in multi-family residential properties. The Company
receives acquisition fees equal to 1.75% (previously 2%) of the net purchase
price of properties acquired and an additional 1.75% (previously 2%) fee for
debt placement related to the properties acquired. The Company recognizes these
fees upon acquiring the properties and obtaining the related financing. The
Company sponsored a third real estate partnership in the third quarter of fiscal
2004, which is still in the offering stage at September 30, 2004.
The Company also receives a fee equal to 5% of the gross operating
revenues from the partnerships' properties, payable monthly. The Company
recognizes this fee as the partnerships' revenues are earned. Additionally, the
Company receives an annual investment management fee from the partnerships equal
to 1% of the gross offering proceeds of the partnership for its services. This
investment management fee is recognized ratably over each annual period.
On its investments in real estate loans, the Company accretes the
difference between its cost basis and the sum of projected cash flows from that
loan into interest income over the estimated life of the loan using the interest
method which recognizes a level interest rate over the life of the loan. The
Company reviews projected cash flows, which include amounts realizable from the
underlying properties, on a regular basis. Changes to projected cash flows,
which can be based upon updated property appraisals, changes to the property and
changes to the real estate market in general, reduce or increase the amounts
accreted into interest income over the remaining life of the loan. The Company
also utilizes the cost recovery method for loans when appropriate under the
circumstances.
84
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
REVENUE RECOGNITION - (CONTINUED)
EQUIPMENT LEASING
The Company's lease transactions are generally classified as direct
financing leases in accordance with SFAS No. 13 and its amendments (as
distinguished from sales-type or operating leases). Such leases transfer
substantially all benefits and risks of equipment ownership to the customer.
Unearned lease income, which is recognized as revenue over the term of the lease
by the effective interest method, represents the excess of the total future
minimum lease payments plus the estimated unguaranteed residual value expected
to be realized at the end of the lease term over the cost of the related
equipment. The Company generally discontinues the recognition of revenue for
leases for which payments are more than 90 days past due. Initial direct costs
incurred in consummating a lease are capitalized as part of the investment in
lease receivables and amortized over the lease term as a reduction in the yield.
Leases not meeting any of the criteria to be classified as direct
financing leases are deemed to be operating leases. Rental income consists
primarily of monthly periodic rentals due under the terms of the leases.
Generally, during the lease terms of existing operating leases, the Company will
not recover all of the undepreciated cost and related expenses of its rental
equipment and, therefore, it is prepared to remarket the equipment in future
years. The Company's policy is to review quarterly the expected economic life of
its rental equipment in order to determine the recoverability of its
undepreciated cost.
The Company receives acquisition fees from certain parties equal to a
percentage of the cost of leased equipment acquired on behalf of these parties
as compensation for acquisition expenses incurred related to the lease
acquisition. These fees are earned at the time of the sale of the related leased
equipment to those parties.
The Company receives management fees for managing and servicing the
leased assets acquired on behalf of these parties and earns fees at the time the
service is performed. The Company receives servicing fees ranging from 2% to 6%
of gross rental payments received from certain parties and for others, the
Company receives servicing fees that average 1% of the managed portfolio
balance. In addition, the Company also receives fees as a reimbursement of its
operating and administrative expenses incurred to manage the partnerships.
85
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
OTHER INCOME, NET
The following table details the Company's other income, net:
Years Ended September 30,
---------------------------
2004 2003 2002
------- ------ ------
(in thousands)
Gain on sales of RAIT shares................................................ $ 9,453 $4,036 $ -
Dividend income from RAIT................................................... 915 2,628 3,276
Loss on early extinguishment of debt........................................ (1,955) (303) (76)
Interest income............................................................. 646 671 1,242
Other....................................................................... 611 82 941
------- ------ ------
$ 9,670 $7,114 $5,383
======= ====== ======
SUPPLEMENTAL CASH FLOW INFORMATION
The Company considers temporary investments with a 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,
--------------------------------
2004 2003 2002
-------- ------- -------
(in thousands)
CASH PAID DURING THE YEARS FOR:
Interest.................................................................... $ 6,548 $11,666 $11,683
Income taxes (refunded) paid................................................ (128) (1,067) 3,243
NON-CASH INVESTING AND FINANCING ACTIVITIES INCLUDE THE FOLLOWING:
Real estate received in exchange for notes upon foreclosure on loans........ - 14,235 -
Receipt of a note in connection with the sale of a real estate loan......... - 1,350 -
Tax benefit from employee stock option exercise............................. 121 408 244
Assumption of debt upon foreclosure of real estate loans.................... - 5,560 -
Asset retirement obligations................................................ - 3,380 -
Non-cash compensation....................................................... 2,199 250 341
Common stock issued under stock option plans, net of cash proceeds.......... 32 424 281
DETAILS OF ACQUISITION:
Fair value of assets acquired........................................... $161,603 $ - $ -
Liabilities assumed..................................................... (19,235) - -
-------- ------- -------
Net cash paid......................................................... $142,368 $ - $ -
======== ======= =======
86
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED)
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.
EARNINGS (LOSS) PER SHARE
Basic earnings (loss) per share is determined by dividing net income
(loss) by the weighted average number of shares of common stock outstanding
during the period. Diluted earnings (loss) per share is computed by dividing net
income (loss) by the sum of the weighted average number of shares of common
stock outstanding and dilutive potential shares from the assumed exercise of
stock options and award plans. Dilutive potential shares of common stock consist
of the excess of shares issuable under the terms of various stock option
agreements over the number of such shares that could have been reacquired (at
the weighted average price of shares during the period) with the proceeds
received from the exercise of the options.
The components of basic and diluted earnings (loss) per share for each
year were as follows:
Years Ended September 30,
---------------------------------
2004 2003 2002
------- -------- --------
(in thousands)
Income from continuing operations before minority interest and
cumulative effects of changes in accounting principles.................... $23,344 $ 9,878 $ 8,358
Minority interest in Atlas America, net of taxes............................ (1,881) - -
(Loss) income from discontinued operations, net of taxes.................... (3,054) 1,088 (11,040)
Cumulative effect of changes in accounting principles, net of taxes......... - (13,881) (627)
------- -------- --------
Net income (loss)........................................................... $18,409 $ (2,915) $ (3,309)
======= ======== ========
Weighted average common shares outstanding-basic............................ 17,417 17,172 17,446
Dilutive effect of stock option and award plans............................. 892 396 359
------- -------- --------
Weighted average common shares-diluted...................................... 18,309 17,568 17,805
======= ======== ========
87
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 3 - CONSOLIDATION OF VARIABLE INTEREST ENTITIES
Financial Interpretation 46-R ("FIN 46-R") issued by the FASB in
December 2003 clarified when a company should consolidate variable interest
entities ("VIEs"). FIN 46-R provides guidance as to the definition of a VIE and
requires it to be consolidated by its primary beneficiary, generally the party
having an ownership or other contractual financial interest that is expected to
absorb the majority of the VIE's expected losses. If no party has exposure to
the majority of the VIEs expected losses, the primary beneficiary will be the
party, if any, entitled to receive the majority of the VIEs residual returns.
The primary beneficiary is required to consolidate the VIEs assets, liabilities
and non controlling interest at fair value. The Company early-adopted FIN 46 on
July 1, 2003 and recorded a $13.9 million cumulative effect adjustment for a
change in accounting principle in the fiscal year ended September 30, 2003.
Certain entities relating to the Company's real estate business have
been consolidated in accordance with FIN 46-R. Because of the timing of receipt
of financial information, the Company accounts for these FIN 46 entities on a
one quarter lag. The assets, liabilities, revenues and expenses of the
consolidated VIEs are included in the Company's financial statements where
previously the Company's interests had been recorded as investments in real
estate loans.
The assets and liabilities of the VIEs that are now included in the
consolidated financial statements are not the Company's. The liabilities of the
VIEs will be satisfied from the cash flows of the VIEs' consolidated assets, not
from the assets of the Company, which has no legal obligation to satisfy those
liabilities. The following tables provide supplemental information about assets,
liabilities, revenues and expenses associated with entities consolidated in
accordance with FIN 46-R and not classified as held for sale at the dates
indicated. The assets and liabilities of FIN 46 entities are included in the
balance sheet captions shown below.
September 30,
--------------------
2004 2003
------- -------
(in thousands)
ASSETS:
Cash and cash equivalents.................................................. $ 1,306 $ 1,689
Accounts receivable and prepaid expenses................................... 347 451
------- -------
Total current assets...................................................... 1,653 2,140
Property and equipment, net................................................ 58,897 76,035
Other assets............................................................... 8 72
------- -------
Total assets............................................................. $60,558 $78,247
======= =======
LIABILITIES:
Current portion of long-term debt.......................................... $ 790 $ 1,108
Accounts payable........................................................... 4,036 4,886
Accrued liabilities........................................................ 481 123
------- -------
Total current liabilities................................................ 5,307 6,117
Long-term debt............................................................. 22,849 36,512
Deferred revenue and other liabilities..................................... 1,835 2,555
------- -------
Total liabilities........................................................ $29,991 $45,184
======= =======
88
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 3 - CONSOLIDATION OF VARIABLE INTEREST ENTITIES - (CONTINUED)
For the period
For the July 1, 2003
year ended (date of adoption) to
September 30, September 30,
2004 2003
------------- --------------------
(in thousands)
OPERATING INFORMATION - INCLUDED IN REAL ESTATE:
Revenues............................................................. $ 11,865 $ 948
Costs and expenses:
Operating expenses................................................. 7,290 522
Writedown of property.............................................. 1,345 -
Depreciation and amortization...................................... 1,358 102
Interest........................................................... 1,272 106
----------- ------------
Total costs and expenses......................................... 11,265 730
----------- ------------
Operating income................................................... $ 600 $ 218
=========== ============
The following tables provide supplemental information about assets,
liabilities, revenues and expenses associated with entities that are classified
as held for sale, substantially all of which are consolidated in accordance with
FIN 46. During the year ended September 30, 2004, the Company liquidated its
position in five entities which were classified as held for sale at September
30, 2003.
September 30,
------------------------
2004 2003
-------- --------
(in thousands)
ASSETS:
Cash and cash equivalents.............................................. $ 5,073 $ 3,960
Accounts receivable and prepaid expenses............................... 873 2,988
Property and equipment, net............................................ 89,644 213,026
Other assets........................................................... 7,373 2,703
-------- --------
Total assets......................................................... $102,963 $222,677
======== ========
LIABILITIES:
Mortgage loans on real estate.......................................... $ 58,168 $130,687
Other liabilities...................................................... 7,132 10,786
-------- --------
Total liabilities.................................................... $ 65,300 $141,473
======== ========
Years Ended
September 30,
------------------------
2004 2003
-------- --------
(in thousands)
(LOSS) INCOME FROM FIN 46 DISCONTINUED OPERATIONS (SEE NOTE 15):
Revenues............................................................... $ 13,405 $ 6,087
Expenses............................................................... (13,464) (4,201)
-------- --------
Operating (loss) income................................................ (59) 1,886
Writedown of properties, net........................................... (5,991) -
Gain (loss) on disposals............................................... 749 (500)
Income tax benefit (provision)......................................... 1,855 (490)
-------- --------
(Loss) income from FIN 46 discontinued operations.................... $ (3,446) $ 896
======== ========
89
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 3 - CONSOLIDATION OF VARIABLE INTEREST ENTITIES - (CONTINUED)
The mortgage loans on real estate shown above in which the VIE's are
the debtors are secured by the VIE's underlying properties. Interest rates range
from 4.75% to 8.0% and the loans mature at various dates through 2006. All of
the loans associated with assets held for sale totaling $58.2 million will be
paid within the next fiscal year, if the assets are sold.
NOTE 4 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL
OTHER ASSETS
The following table provides information about other assets at the
dates indicated.
At September 30,
--------------------
2004 2003
------- -------
(in thousands)
Deferred financing costs, net of accumulated amortization of
$1,132 and $5,504..................................................... $ 4,751 $ 2,105
Equity method investments in Trapeza entities............................. 8,483 4,802
Investments in Structured Finance Fund entities........................... 1,065 -
Investments at the lower of cost or market................................ 7,639 6,185
Other..................................................................... 6,655 6,490
------- -------
$28,593 $19,582
======= =======
Deferred financing costs are amortized over the terms of the related
loans.
Investments in Trapeza entities are accounted for using the equity
method 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 13% 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 9% of the outstanding common
shares and approximately 8% of the outstanding preferred shares of The Bancorp,
Inc. ("TBI"), a related party which owns approximately 33% of the The Bancorp
Bank, (NASDAQ: TBBK) a publicly traded company, as disclosed in Note 5.
INTANGIBLE ASSETS
Partnership management and operating contracts and the Company's
equipment leasing operating system, or leasing platform, were acquired through
acquisitions recorded at fair value on their acquisition dates. The Company
amortizes contracts acquired on the declining balance and straight-line methods,
over their respective estimated lives, ranging from five to thirteen years. The
leasing platform is amortized on the straight-line method over seven years.
Amortization expense for the years ended September 30, 2004, 2003 and 2002 was
$1.0 million, $1.1 million and $1.2 million, respectively. The aggregate
estimated annual amortization expense is approximately $900,000 for each of the
succeeding five years.
90
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 4 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL - (CONTINUED)
The following table provides information about intangible assets at the
dates indicated:
At September 30,
-------------------
2004 2003
------- -------
(in thousands)
Partnership management and operating contracts............................. $14,343 $14,343
Leasing platform........................................................... 918 918
------- -------
15,261 15,261
Accumulated amortization................................................... (7,828) (6,785)
------- -------
Intangible assets, net..................................................... $ 7,433 $ 8,476
======= =======
GOODWILL
On October 1, 2001, the Company adopted SFAS No. 142, "Goodwill and
Other Intangible Assets," which requires that goodwill no longer be amortized,
but instead tested for impairment at least annually. The Company performs such
annual evaluations and will reflect the impairment of goodwill, if any, in
operating income in the statement of operations in the period in which the
impairment is indicated. All goodwill recorded on the Company's balance sheets
is related to the Company's energy segments.
NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
In the ordinary course of its business operations, the Company has
ongoing relationships with several related entities:
Relationship with Equipment Leasing Partnerships. In fiscal 2004, 2003
and 2002, the Company received fees from investment partnerships in which it was
general partner of $2.2 million, $2.8 million and $1.0 million, respectively. In
March 2004, the Company acquired $3.7 million of leases at book value from
certain of these equipment leasing investment partnerships which were liquidated
in 2004.
Relationship with Real Estate Investment Partnerships. In fiscal 2004
and 2003, the Company received fees from real estate investment partnerships in
which it was general partner of $1.5 million and $3.1 million, respectively.
Relationship with RAIT. Organized by the Company in 1997, RAIT is a
real estate investment trust in which, as of September 30, 2004, the Company
owned approximately 0.4% of the outstanding common shares of beneficial
interests. Betsy Z. Cohen ("B. Cohen"), the spouse of Edward E. Cohen
("E. Cohen") Chairman of the Board of the Company, is the chief executive
officer of RAIT, and Jonathan Z. Cohen ("J. Cohen"), a son of E. and B. Cohen
and the president, chief executive officer and a director of the Company, is an
officer and a trustee. Scott F. Schaeffer ("Schaeffer"), a former officer and
director of the Company, is RAIT's president and chief operating officer. During
the periods presented, the Company and RAIT engaged in the following significant
transactions.
o In December 2003, RAIT provided the Company a standby commitment
for $10.0 million in bridge financing in connection with the
retirement of the Company's senior debt. RAIT received a $100,000
facilitation fee from the Company in connection with providing
this standby commitment. On January 15, 2004, the Company borrowed
the $10.0 million from RAIT, and on January 21, 2004, the Company
repaid RAIT in full.
91
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (CONTINUED)
o In June 2002, the Company sold a mortgage loan having a book value
of $1.0 million to RAIT for $1.8 million, recognizing a gain of
$757,000. Mr. Schaeffer was an officer and director of the general
partner of the borrower.
Relationship with The Bancorp, Inc. ("TBI"). The Company owns 8.9% of
the outstanding common stock and 7.5% of Series A preferred stock outstanding of
TBI. B. Cohen and Daniel G. Cohen ("D. Cohen") are officers and directors of
TBI. D. Cohen, a son of E. and B. Cohen, is a former officer and director of the
Company.
Relationship with Ledgewood Law Firm ("Ledgewood"). Until April 1996,
E. Cohen was of counsel to Ledgewood. The Company paid Ledgewood $1.7 million,
$1.2 million and $839,000 during fiscal 2004, 2003 and 2002, 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. In connection with his retirement
from the Company in fiscal 2004, E. Cohen is receiving payments from a
Supplemental Employee Retirement Plan ("SERP") (Note 11). The Company has
established two trusts to fund the SERP. The 1999 Trust, a secular trust,
purchased 100,000 shares of the common stock of TBI. The 2000 Trust, a "Rabbi
Trust," holds 45,889 shares of convertible preferred stock of TBI, 77,142 shares
of common stock 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 $720,000 by the 2000 Trust in April 2001 from a corporation of which
E. Cohen is chairman and J. Cohen is the president. The loan balance as of
September 30 2004 was $297,000. 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 secular trust is approximately $1.4 million
at September 30, 2004. This trust and its assets are not included in the
Company's consolidated balance sheets. However, its assets are considered in
determining the amount of the Company's liability under the SERP.
The carrying value of the assets in the 2000 Rabbi Trust is
approximately $3.7 million at September 30, 2004. Its assets are included in
Other Assets in the Company's consolidated balance sheets and the Company's
liability under the SERP has not been reduced by the value of those assets.
Relationship with Cohen Bros & Company. During 2003 and 2002, the
Company purchased 26,450 and 125,095 shares of its common stock at a cost of
$212,100 and $1.1 million through Cohen Bros. & Company. In 2002, the Company
repurchased $1.5 million principal amount of its senior notes at a cost of $1.6
million through Cohen Bros & Company. Cohen Bros. & Company acted as a principal
in the sales to the Company. D. Cohen is the principal owner of the corporate
parent of Cohen Bros. & Company.
92
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (CONTINUED)
Relationship with 9 Henmar. The Company owns a 50% interest in the
Trapeza entities that have sponsored CDO issuers and manage pools of trust
preferred securities acquired by the CDO issuers. The Trapeza entities and CDO
issuers were originated and developed in large part by D. Cohen. The Company
agreed to pay D. Cohen's company, 9 Henmar LLC ("9 Henmar"), 10% of the fees the
Company receives in connection with Trapeza entities one through four and their
management of the trust preferred securities held by the CDO issuers. In fiscal
2004 and 2003, the Company paid 9 Henmar $325,700 and $93,400 in such fees,
respectively.
Relationship with Certain Borrowers. The Company has from time to time
purchased loans in which affiliates of the Company were or have become
affiliates of the borrowers.
In 2002, D. Cohen acquired beneficial ownership of a property on which
the Company had held a loan interest since 1998. In fiscal 2004, the loan was
sold to an affiliate of D. Cohen for $5.4 million and the Company recognized a
gain of $100,000.
In 2000, to protect the Company's interest, the property securing a
loan held by the Company since 1997 was purchased by a limited partnership owned
in equal parts by Messrs. Schaeffer, Adam Kauffman, E. Cohen and D. Cohen. In
September 2003, in furtherance of its position, the Company foreclosed on the
property. In 2004, the property was sold for $5.0 million and the Company
recognized a gain of $824,000, which is recorded in discontinued operations.
In October 2003, the Company recapitalized a loan it acquired in 1998
under a plan of reorganization in bankruptcy for a cost of $95.6 million. At the
time of such acquisition, an order of the bankruptcy court required that legal
title to the property underlying the loan be transferred. To comply with that
order, to maintain control of the property and to protect the Company's
interest, an entity whose general partner is a subsidiary of the Company and
whose limited partners are Messrs. Schaeffer, D. Cohen and E. Cohen (with a 94%
aggregate beneficial interest) assumed title to the property. As part of the
recapitalization, Messrs. E. Cohen and Schaeffer transferred all of their
interests to an unrelated third party and Mr. D. Cohen transferred 16.3% of his
31.3% interest to such third party. They received no consideration from the
unrelated third party, but in consideration for them agreeing to the
recapitalization of the loan, the Company agreed to reimburse them the amount
that they had paid to the Company in 1998 for the interests transferred. Such
payment was $200,000 in the aggregate.
In fiscal 2004, the Company sold a loan to an affiliate of D. Cohen for
$900,000 and realized a loss of $124,000.
93
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 5 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (CONTINUED)
In October 2003, a FIN 46 entity's asset underlying one of the
Company's loans was sold to an entity of which D. Cohen is a shareholder; such
entity was the highest bidder for the property and the Company received $6.6
million in cash and recognized a gain of $78,000. Prior to such sale, the FIN 46
entity's asset had been owned by a partnership in which E. Cohen, D. Cohen and
B. Cohen were limited partners.
Relationship with Brandywine Construction & Management, Inc. ("BCMI").
BCMI manages the properties underlying eleven of the Company's real estate loans
and real estate and FIN 46 assets. Mr. Kauffman, President of BCMI, or an entity
affiliated with him, has also acted as the general partner, president or trustee
of six of the borrowers. E. Cohen, the Company's chairman, is the chairman of
BCMI and holds approximately 8% of its common stock.
Relationship with Lienholder. In 1997, the Company acquired a first
mortgage lien with a face amount of $14.0 million and a book value of $4.5
million on a hotel property owned by a corporation in which, on a fully diluted
basis, J. Cohen and E. Cohen would have a 19% interest. The corporation acquired
the property through foreclosure of a subordinate loan. In May 2003, the Company
acquired this property through further foreclosure proceedings and recorded
write-downs of $2.7 million. In August 2004, the Company listed the property for
sale, recorded a further write-down of $882,000 and classified the property as
held for sale.
NOTE 6 - INVESTMENTS IN LEASE ASSETS
Components of investments in lease assets are as follows:
At September 30,
----------------------
2004 2003
------- -------
(in thousands)
Direct financing leases.............................................. $20,845 $ 6,817
Notes receivable..................................................... 2,822 -
Assets subject to operating leases, net of accumulated
depreciation of $22............................................... 510 -
------- -------
Investments in lease assets....................................... $24,177 $ 6,817
======= =======
The components of the Company's investments in direct financing leases
are as follows:
At September 30,
----------------------
2004 2003
------- -------
(in thousands)
Total future minimum lease payments receivables...................... $25,052 $ 7,982
Initial direct costs, net of amortization............................ 428 122
Unguaranteed residuals............................................... 87 51
Unearned lease income................................................ (4,695) (1,326)
Unearned residual income............................................. (27) (12)
------- -------
Investments in direct financing leases............................ $20,845 $ 6,817
======= =======
94
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 6 - INVESTMENTS IN LEASE ASSETS - (CONTINUED)
Although the lease and note terms extend over many years as indicated
in the table below, the Company routinely sells them to third parties shortly
after origination. The contractual future minimum lease and note payments and
related rental payments expected to be received on non-cancelable direct
financing leases, notes receivable and operating leases for each of the five
succeeding fiscal years ended September 30 and thereafter are as follows (in
thousands):
Direct Financing Notes Operating
Leases Receivable Leases Totals
---------------- ---------- ---------- ---------
2005........................................ $ 6,027 $ 1,643 $ 186 $ 7,856
2006........................................ 5,891 195 179 6,265
2007........................................ 5,056 210 118 5,384
2008........................................ 3,696 170 36 3,902
2009........................................ 2,921 146 13 3,080
Thereafter.................................. 1,461 458 - 1,919
------------- --------- -------- ---------
$ 25,052 $ 2,822 $ 532 $ 28,406
============= ========= ======== =========
NOTE 7 - INVESTMENTS IN REAL ESTATE LOANS AND REAL ESTATE
In real estate, the Company focuses on the sponsorship and management
of real estate investment programs and the management and resolution of its
investments in real estate loans and real estate.
At September 30, 2004 and 2003, the Company held real estate loans
having aggregate face values of $61.3 million and $186.9 million, respectively,
after the removal in fiscal 2003 of loans with $393.6 million in face value
($132.7 million of carrying value) upon the adoption of FIN 46-R, as discussed
in Note 3. Amounts receivable, net of senior lien interests and deferred costs,
were $43.7 million and $96.4 million at September 30, 2004 and 2003,
respectively.
95
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 7 - INVESTMENTS IN REAL ESTATE LOANS AND REAL ESTATE - (CONTINUED)
The following is a summary of the changes in the carrying value of the
Company's investments in real estate loans and real estate for the years ended
September 30, 2004 and 2003.
September 30,
-------------------------
2004 2003
-------- ----------
(in thousands)
Loan balance, beginning of year...................................... $ 40,416 $ 187,542
New loans............................................................ 9,848 1,350
Addition to existing loans........................................... 2,069 4,855
Loan write-downs..................................................... - (1,448)
Loan converted to equity interest.................................... (7,442) -
Net gains on resolution.............................................. 49 -
Accretion of discount (net of collection of interest)................ 1,909 1,962
Loans reclassified per FIN 46 (see Note 3)........................... - (132,312)
Foreclosures transferred to real estate.............................. - (11,404)
Collections of principal............................................. (22,783) (10,129)
-------- ----------
Loan balance, end of year............................................ 24,066 40,416
Real estate ventures................................................. 19,918 14,131
Real estate owned, net of accumulated depreciation of $676
and $640 (see Note 8)............................................. 4,124 15,806
Allowance for possible losses........................................ (989) (1,417)
-------- ----------
Balance, end of year................................................. $ 47,119 $ 68,936
======== ==========
In determining the Company's allowance for possible losses related to
its real estate loans and real estate, the Company considers general and local
economic conditions, neighborhood values, competitive overbuilding, casualty
losses and other factors which may affect the value of loans and real estate.
The value of loans and real estate may also be affected by factors such as the
cost of compliance with regulations and liability under applicable environment
laws, changes in interest rates and the availability of financing. Income from
properties will be reduced if a significant number of tenants are unable to pay
rent or if available space cannot be rented on favorable terms. In addition, the
Company continuously monitors collections and payments from its borrowers and
maintains an allowance for estimated losses based upon its historical experience
and its knowledge of specific borrower collection issues identified. The Company
reduces its investment in real estate loans and real estate by an allowance for
amounts that may become unrealizable in the future. Such allowance can be either
specific to a particular loan or property or general to all loans and real
estate.
96
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 7 - INVESTMENTS IN REAL ESTATE LOANS AND REAL ESTATE - (CONTINUED)
The following is a summary of activity in the Company's allowance for
possible losses related to real estate loans and real estate for the years ended
September 30, 2004 and 2003:
September 30,
---------------------
2004 2003
------- -------
(in thousands)
Balance, beginning of year........................................... $ 1,417 $ 3,480
Provision for possible losses........................................ 550 1,848
Write-offs........................................................... (978) -
Transfers upon foreclosure........................................... - (2,339)
Writedowns associated with foreclosure............................... - (1,572)
------- -------
Balance, end of year................................................. $ 989 $ 1,417
======= =======
NOTE 8 - REAL ESTATE LEASING ACTIVITIES
The following table provides information about the Company's leasing
activities related to real estate owned and properties consolidated under FIN 46
at the dates indicated:
September 30,
---------------------
2004 2003
------- -------
(in thousands)
Land................................................................. $ 3,368 $ 7,191
Leasehold interest................................................... 4,800 4,800
Retail buildings..................................................... 3,854 3,850
Office buildings..................................................... 3,853 9,457
Apartment buildings.................................................. 39,295 53,638
Hotels............................................................... 9,987 14,013
------- -------
65,157 92,949
Less accumulated depreciation........................................ (2,135) (742)
------- -------
$63,022 $92,207
======= =======
Minimum future rental income under non-cancelable operating leases
associated with real estate investments that have terms in excess of one year
for each of the five succeeding fiscal years ended September 30, are as follows:
2005 - $1.2 million; 2006 - $1.0 million; 2007 - $839,000; 2008 - $824,000 and
2009 - $758,000.
97
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 9 - DEBT
Total debt consists of the following at the dates indicated:
At September 30,
---------------------
2004 2003
-------- --------
(in thousands)
Senior debt.......................................................... $ - $ 54,027
Energy:
Revolving credit facility......................................... 25,000 31,000
Term loan......................................................... 60,000 -
Real estate:
Revolving credit facilities....................................... - 18,000
Mortgage loans on real estate - FIN 46............................ 23,639 37,620
Other............................................................. - 1,663
Equipment leasing:
Revolving credit facilities....................................... 18,083 7,168
Other debt........................................................... 2,612 28,477
-------- --------
Total debt........................................................... 129,334 177,955
Less current secured revolving credit facility - leasing............. 8,487 7,168
Less current maturities.............................................. 6,151 60,579
-------- --------
Long-term debt....................................................... $114,696 $110,208
======== ========
Following is a description of borrowing arrangements in place at
September 30, 2004 and 2003:
Senior Debt. In July 1997, the Company issued $115.0 million of 12%
Senior Notes (the "12% Notes") due August 2004. The 12% Notes were retired in
fiscal 2004, resulting in a loss of approximately $2.0 million which is included
in other income, net, in the Company's Consolidated Statements of Operations.
Energy-Revolving Credit Facilities. Atlas America has a $75.0 million
credit facility led by Wachovia Bank, N.A. ("Wachovia"). The revolving credit
facility has a current borrowing base of $75.0 million which may be decreased
subject to a decline in Atlas America's oil and gas reserves. The facility
permits draws based on the remaining proved developed non-producing and proved
undeveloped natural gas and oil reserves attributable to Atlas America's wells
and the projected fees and revenues from operation of the wells and the
administration of energy partnerships. This facility is guaranteed by the
Company as long as it continues to own more than 80% of Atlas America. 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 including 1.6 million
subordinated units in Atlas Pipeline and bears interest at either the base rate
plus the applicable margin or at an adjusted London Interbank Offered Rate
("LIBOR") plus the applicable margin elected at Atlas America's option.
98
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 9 - DEBT - (CONTINUED)
The base rate of any day equals the higher of the federal funds rate
plus 0.50% or the Wachovia prime rate. Adjusted LIBOR is LIBOR divided by 1.00
minus the percentage prescribed by the Federal Reserve Bank Board for
determining the reserve requirement for euro currency funding. The applicable
margin ranges from 0.25% to 0.75% for base rate loans and 1.75% to 2.25% for
LIBOR loans.
The Wachovia credit facility requires Atlas America to maintain
specified net worth and specified ratios of current assets to current
liabilities and debt to earnings before interest, taxes, depreciation, depletion
and amortization ("EBITDA"), and requires the Company to maintain a specified
interest coverage ratio. In addition, the facility limits sales, leases or
transfers of assets and the incurrence of additional indebtedness. The facility
limits the dividends payable by Atlas America to the Company, on a cumulative
basis, to 50% of Atlas America's net income from and after January 1, 2004 plus
$5.0 million. In addition, Atlas America is permitted to repay intercompany debt
to the Company only up to the amount of the Company federal income tax liability
attributable to Atlas America. The facility terminates in March 2007, when all
outstanding borrowings must be repaid. At September 30, 2004 and 2003, $26.7
million and $32.3 million, respectively, were outstanding under this facility,
including $1.7 million and $1.3 milllion, respectively, under letters of credit.
The interest rates ranged from 3.59% to 5.0% at September 30, 2004.
Atlas Pipeline Credit Facility. On July 16, 2004 Atlas Pipeline entered
into a new $135.0 million credit facility which replaced its existing $20.0
million facility. The loan arrangement, for which Wachovia serves as
administrative agent, includes eleven additional lenders. The facility is
comprised of a five-year $60.0 million term loan and a four-year $75.0 million
revolving line of credit which can be increased by an additional $40.0 million
under certain circumstances. No borrowings were outstanding under the revolving
line of credit at September 30, 2004. Up to $5.0 million of the facility may be
used for standby letters of credit. Borrowings under the facility will be
secured by a lien on and security interest in all of Atlas Pipeline's property
and that of its subsidiaries and by the guaranty of each of its subsidiaries.
The credit facility bears interest at the base rate plus the applicable margin
or at adjusted LIBOR plus the applicable margin, elected at Atlas Pipeline's
option. The base rate for any day equals the higher of the federal funds rate
plus 1/2 of 1.00% or the Wachovia prime rate. Adjusted LIBOR is LIBOR divided by
1.00 minus the percentage prescribed by the Board of Governors of the Federal
Reserve System for determining the reserve requirement for euro currency
funding. The applicable margin for the revolving line of credit ranges from 1.0%
to 2.25% for base rate loans and 2.0% to 3.25% for LIBOR loans. The applicable
margin for the term loan is 0.75% higher for both base rate loans and LIBOR
loans.
Atlas Pipeline must prepay the term loan with the net proceeds of any
asset sales or issuances of debt. With respect to any issuances of equity, Atlas
Pipeline will be required to repay the term loan from the proceeds of such
issuances to the extent its ratio of funded debt to EBITDA exceeds 3.5 to 1.0.
Atlas Pipeline will be required to pay down $750,000 in principal on the
outstanding balance of the term loan quarterly, but any prepayments of principal
with proceeds from asset or equity sales will be credited pro rata against this
repayment obligation.
99
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 9 - DEBT - (CONTINUED)
The credit agreement contains covenants customary for loans of this
size, including restrictions on incurring additional debt and making material
acquisitions, and a prohibition on paying distributions to Atlas Pipeline's
unitholders if an event of default occurs. The events, of default are also
customary for loans of this size, including payment defaults, breaches of Atlas
Pipeline's representations or covenants contained in the credit agreement,
adverse judgments against it in excess of a specified amount, and a change of
control of its general partner.
Real Estate-Revolving Credit Facility. The Company has an $18.0 million
revolving line of credit with Sovereign Bank. Interest is payable monthly at The
Wall Street Journal prime rate (4.75% at September 30, 2004) and principal is
due upon expiration in July 2005. Advances under this line are to be utilized to
acquire commercial real estate or interests therein, to fund or purchase loans
secured by commercial real estate or interests, or to reduce indebtedness on
loans or interests which the Company owns or holds. The advances are secured by
the properties related to these funded transactions. At September 30, 2004,
there were no outstanding borrowings and $18.0 million was available under this
line. At September 30, 2003, the entire $18.0 million had been advanced under
this line.
Real Estate-Mortgage Loans on Real Estate - FIN 46. As of September 30,
2004, there are five outstanding first mortgage loans secured by real estate
with outstanding balances totaling $23.6 million. Four of the mortgage loans
require monthly payments of principal and interest at fixed interest rates
ranging from 5.25% to 8.25%. Loan maturities range from April 2006 through July
2014. One loan is payable interest only on a quarterly basis at Wachovia's prime
rate plus 200 basis points (6.75% at September 30, 2004.) The loan matures in
October 2011 when all unpaid interest and principal becomes due.
These mortgage loans are not legal obligations of the Company, however,
they are senior to the FIN 46 entities' obligations to the Company. Loan
payments are paid from the cash flows of these entities whose assets and
liabilities are consolidated in the Company's financial statements.
Equipment Leasing-Revolving Credit Facilities. LEAF Financial
Corporation ("LEAF Financial"), the Company's equipment leasing subsidiary, has
a $15.0 million secured credit facility with Commerce Bank. Outstanding
borrowings bear interest at one of two rates, elected at LEAF Financial's
option; (i) the lender's prime rate plus 240 basis points, or (ii) LIBOR plus
300 basis points. The facility expires in November 2005. As of September 30,
2004, the balance outstanding was $9.6 million at an interest rate of 4.65%. In
addition, LEAF Financial, entered into a $20.0 million secured revolving credit
facility with National City Bank which terminates in April 2005. The Company has
guaranteed this facility. Outstanding loans bear interest at one of two rates,
elected at LEAF Financial's option; (i) the lender's prime rate plus 240 basis
points, or (ii) LIBOR plus 300 basis points. As of September 30, 2004, the
balance outstanding was $8.5 million at an interest rate of 4.65%. Borrowings
under these facilities are collateralized by the leases being financed and the
underlying equipment being leased.
100
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 9 - DEBT - (CONTINUED)
The more significant components of Other Debt are described as follows:
The Company, through certain operating subsidiaries, had a $6.8 million
term note with Hudson United Bank which was repaid in fiscal 2004. At September
30, 2003, $6.4 million was outstanding on this note.
The Company, through certain operating subsidiaries, had a $10.0
million term loan with The Marshall Group which was repaid in fiscal 2004. At
September 30, 2003, $5.8 million had been outstanding on this loan.
The Company has a $5.0 million revolving line of credit with Sovereign
Bank, which was repaid in fiscal 2004. At September 30, 2003, $5.0 million had
been advanced under this line.
The Company maintained a line of credit with Commerce Bank for $5.0
million which was repaid in fiscal 2004. At September 30, 2003, $5.0 million had
been advanced under this line of credit.
During the year ended September 30, 2002, the Company issued
convertible notes payable in the amount of $11,000 to two executive officers of
its subsidiary, LEAF. The notes accrue interest at a rate of 8% per annum, and
mature in 2012. No payment of accrued interest or principal is due until 2007,
at which time accrued interest is due. Thereafter, monthly interest payments are
required until the notes mature. The notes can be converted into 11.5% of the
subsidiary's common stock.
Annual debt principal payments over the next five fiscal years ending
September 30 are as follows (in thousands):
2005............................. $ 14,638
2006............................. 14,386
2007............................. 28,925
2008............................. 3,925
2009............................. 51,155
At September 30, 2004, the Company has complied with all financial
covenants in its debt agreements.
101
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 10 - INCOME TAXES
The following table details the components of the Company's income
taxes from continuing operations for the periods indicated.
Years Ended September 30,
----------------------------------
2004 2003 2002
-------- ------- -------
(in thousands)
Provision (benefit) for income taxes:
Current:
Federal.............................................. $ - $ 341 $ 6,365
State................................................ - 24 (619)
Deferred................................................ 12,025 4,284 (2,332)
-------- ------- -------
$ 12,025 $ 4,649 $ 3,414
======== ======= =======
A reconciliation between the statutory federal income tax rate and the
Company's effective income tax rate is as follows:
Years Ended September 30,
----------------------------------
2004 2003 2002
-------- ------- -------
Statutory tax rate......................................... 35% 35% 35%
Statutory depletion........................................ (1) (2) (4)
Non-conventional fuel and low income housing credits....... - - (3)
Tax-exempt interest........................................ (1) (2) (2)
State income tax........................................... 1 1 3
-------- ------- -------
34% 32% 29%
======== ======= =======
102
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 10 - INCOME TAXES - (CONTINUED)
The components of the net deferred tax liability at the dates indicated
are as follows:
September 30,
--------------------------
2004 2003
--------- ---------
(in thousands)
Deferred tax assets related to:
FIN 46 assets.......................................................... $ 2,884 $ 8,858
Real estate loans and real estate...................................... - 6,480
Statutory depletion carryforward....................................... 566 -
Loss carryforward...................................................... 2,193 -
Stock option exercises................................................. 21 558
Accrued expenses....................................................... 6,381 6,057
Unrealized loss on investments......................................... 1,374 -
Provision for possible losses.......................................... 411 674
--------- ---------
$ 13,830 $ 22,627
========= =========
Deferred tax liabilities related to:
Property and equipment basis differences............................... (28,330) (29,065)
Investments in real estate loans and real estate....................... (4,391) (3,812)
Asset backed securities................................................ (295) -
Unrealized gain on investments......................................... (491) (2,628)
--------- ---------
(33,507) (35,505)
--------- ---------
Net deferred tax liability................................................ $ (19,677) $ (12,878)
========= =========
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, 2004 or 2003.
As of September 30, 2004, the Company had available $1.6 million of
statutory depletion deductions which may be carried forward indefinitely.
As of September 30, 2004, the Company had available $5.5 million of
federal net operating loss carryforward that expires during fiscal 2024.
NOTE 11 - 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.
103
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 11 - BENEFIT PLANS - (CONTINUED)
The common stock purchased by the ESOP is held by the ESOP trustee in a
suspense account. On an annual basis, a portion of the common stock is released
from the suspense account. As of September 30, 2004, there were 301,300 shares
allocated to participants, and 73,500 unallocated shares in the plan.
Compensation expense related to the plan amounted to $216,000, $160,000 and
$182,000 for the years ended September 30, 2004, 2003 and 2002, respectively.
Employee Savings Plan. The Company sponsors an Investment Savings Plan
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, it matched up to 50%. Included in general and
administrative expenses are $356,000, $284,000 and $335,000 for the Company's
contributions for the years ended September 30, 2004, 2003 and 2002,
respectively.
Stock Options. The following table summarizes certain information about
the Company's equity compensation plans (four employee stock option plans and
two non-employee directors plans), in the aggregate, as of September 30, 2004.
- -------------------------------------------------------------------------------------------------------------------------
(a) (b) (c)
- -------------------------------------------------------------------------------------------------------------------------
Number of securities remaining
Number of securities to be available for future issuance
issued upon exercise of Weighted-average exercise under equity compensation plans
outstanding options, price of outstanding excluding securities reflected
Plan category warrants and rights options, warrants and rights in column (a)
- -------------------------------------------------------------------------------------------------------------------------
Equity compensation plans
approved by security
holders 1,836,383 $ 10.01 282,339
- -------------------------------------------------------------------------------------------------------------------------
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 plan.
Options under all plans become exercisable as to 25% of the optioned shares each
year after the date of grant, and expire not later than ten years after the date
of grant.
The 1989 plan, as amended, authorized the granting of up to 1,769,670
shares of the Company's common stock in the form of incentive stock options
("ISO's"), non-qualified stock options and stock appreciation rights ("SAR's").
The 1997 Key Employee Stock Option Plan authorized the granting of up
to 825,000 shares of the Company's common stock in the form of ISO's,
non-qualified stock options and SAR's. In fiscal 2004, 2003 and 2002, options
for 3,000, 0 and 4,000 shares, respectively, were issued under this plan.
104
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 11 - BENEFIT PLANS - (CONTINUED)
The 1999 Key Employee Stock Option Plan authorized the granting of up
to 1,000,000 shares of the Company's common stock in the form of ISO's,
non-qualified stock options and SAR's. No options were issued under this plan
during fiscal 2004 and 2003. In fiscal 2002, options for 62,533 shares were
issued under the plan.
The 2002 Key Employee Stock Option Plan, for which 750,000 shares were
reserved, provides for the issuance of ISO's, non-qualified stock options and
SAR's. No options were issued under this plan during fiscal 2004. In fiscal 2003
and 2002, options for 5,000 and 664,967 shares, respectively, were issued under
this plan.
Transactions for the four employee stock option plans are summarized as
follows:
Years Ended September 30,
--------------------------------------------------------------------------------------
2004 2003 2002
------------------------- ------------------------- --------------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Exercise
Shares Price Shares Price Shares Price
--------- -------- --------- --------- --------- --------
Outstanding - beginning of year.... 1,849,254 $ 10.26 2,375,504 $ 9.86 1,892,447 $ 10.27
Granted......................... 3,000 $ 17.35 5,000 $ 11.50 731,500 $ 8.24
Exercised....................... (81,323) $ 7.18 (385,281) $ 7.61 (222,682) $ 7.93
Forfeited....................... (7,436) $ 9.09 (145,969) $ 10.67 (25,761) $ 11.06
--------- --------- ---------
Outstanding - end of year.......... 1,763,495 $ 10.42 1,849,254 $ 10.26 2,375,504 $ 9.86
========= ======= ========= ======= ========= =======
Exercisable, at end of year........ 1,297,331 $ 10.96 1,053,843 $ 11.29 1,036,006 $ 10.36
========= ======= ========= ======= ========= =======
Available for grant................ 232,124 227,688 86,719
========= ========= =========
Weighted average fair value per
share of options granted
during the year................. $ 7.65 $ 8.07 $ 5.10
======= ======= =======
105
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 11 - BENEFIT PLANS - (CONTINUED)
The following information applies to employee stock options outstanding
as of September 30, 2004:
Outstanding Exercisable
----------------------------------------------- -----------------------------
Weighted
Average Weighted Weighted
Contractual Average Average
Shares Life (Years) Exercise Price Shares Exercise Price
-------- ------------ -------------- ------ --------------
$ 2.73 46,349 1.22 $ 2.73 46,349 $ 2.73
$ 7.47 - $ 7.71 680,500 6.58 $ 7.65 437,250 $ 7.59
$ 9.19 - $ 9.34 223,750 7.78 $ 9.32 105,001 $ 9.33
$ 11.03 - $ 11.50 371,252 6.36 $ 11.06 270,087 $ 11.06
$ 15.50 - $ 17.35 441,644 4.67 $ 15.51 438,644 $ 15.50
--------- ---------
1,763,495 1,297,331
========= =========
Other Plans. In addition to the employee stock option plans, the
stockholders approved the Resource America, Inc. 1997 Non-Employee Director
Deferred Stock and Deferred Compensation Plan for which a maximum of 75,000
units were reserved for issuance, all of which have been issued. The fair value
of the grants awarded (at an average of $13.43 per unit), $1.0 million in total,
has been charged to operations over the vesting period. As of September 30,
2004, 57,000 units (average $13.54 per unit) were outstanding and fully vested.
During fiscal 2003, 3,000 units were forfeited and 15,000 units (at an average
of $13.37 per unit) were converted to 15,000 shares of the Company's common
stock and issued to a former director who resigned in April 2003. The plan was
terminated as of April 30, 2002, as provided by the terms of the plan, except
with respect to previously awarded grants. No further grants can be made under
this plan.
In April 2002, the stockholders approved the Resource America, Inc.
2002 Non-Employee Director Deferred Stock and Deferred Compensation Plan for
which a maximum of 75,000 units were reserved for issuance. In fiscal 2004, the
Company issued 3,156 units (at an average of $19.01 per unit) under this plan.
As of September 30, 2004, 15,888 units (at an average of $11.33 per unit) were
outstanding under this plan of which 12,732 units were fully vested. During
fiscal 2003, 7,540 units were forfeited and 1,357 units (at an average of $11.05
per unit) were converted to 1,357 shares of the Company's common stock and
issued to a former director who resigned in April 2003. The fair value of the
grants awarded (at an average of $11.02 per unit), $273,000 in total, has been
charged to operations over the vesting period. As of September 30, 2004, there
were 50,215 units available for issuance under this plan.
Under these plans, non-employee directors of the Company are awarded
units on an annual basis representing the right to receive one share of the
Company's common stock for each unit awarded. In April 2003, the stockholders
approved an amendment to each plan concerning the vesting schedule whereby units
are now vested on the later of the fifth anniversary of the date of becoming an
eligible director and the first anniversary of the grant of units. Units will
vest sooner upon a change of control of the Company or death or disability of a
director, provided the director has completed at least six months of service.
Upon termination of service by a director, all unvested units are forfeited.
106
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 11 - BENEFIT PLANS - (CONTINUED)
Under the supplemental employment retirement plan ("SERP") of E. Cohen,
the Company pays an annual benefit of 75% of his average income during the later
of his lifetime or 10 years from May 2004, the date of his retirement from the
Company to become chief executive officer and president of Atlas America. During
fiscal 2004, 2003 and 2002, operations were charged $1.4 million, $315,000 and
$1.1 million, respectively, with respect to these commitments. The 2004 charge
resulted from an actuarial adjustment based upon the acceleration of his
retirement. In June 2004, the Company commenced making payments to E. Cohen
under his SERP in connection with his retirement. Through September 30, 2004, E.
Cohen has been paid $254,000 under the SERP.
In May 2004, Atlas America entered into an employment agreement with E.
Cohen, pursuant to which Atlas America has agreed to provide him with a SERP and
with certain financial benefits upon termination of his employment. Under the
SERP, he will be paid an annual benefit equal to the product of (a) 6.5%
multiplied by (b) his base salary at the time of his retirement, death or other
termination of employment with Atlas America, multiplied by, (c) the number of
years of employment commencing upon the effective date of the SERP agreement,
limited to an annual maximum benefit of 65% of his final base salary and an
annual minimum benefit of 26% of his final base salary. During fiscal 2004,
operations were charged $59,500 with respect to this commitment.
Atlas America has a Stock Incentive Plan for employees, consultants and
directors of Atlas America and its affiliates, with a maximum of 1,333,333
shares reserved for issuance. In May 2004, 4,835 deferred units representing a
right to receive a share of common stock over a 3-year vesting period (at an
average price of $15.50 per unit) were issued to non-employee directors of Atlas
America under this plan. Units will vest sooner upon a change of control of
Atlas America or death or disability of a grantee, provided the grantee has
completed at least six months of service. Upon termination of service by a
grantee, all unvested units are forfeited. The fair value of the grants awarded
($75,000 in total) will be charged to operations over the vesting period of the
units.
Atlas Pipeline has a Long-Term Incentive Plan for officers and
non-employee managing board members of its general partner and employees of the
general partner, consultants and joint venture partners who perform services for
Atlas Pipeline. During the year ended September 30, 2004, 59,598 phantom units
were granted and 846 units were forfeited, leaving 58,752 phantom units
outstanding as of September 30, 2004. Atlas Pipeline recognized $419,000 in
compensation expense related to these grants and their associated distributions
for the year ended September 30, 2004. The fair market value associated with
these grants was $2.2 million which is amortized into expense over the vesting
period of the units. The weighted average fair value of phantom units granted
for the year ended September 30, 2004 was $37.16.
In connection with the acquisition of The Atlas Group, Inc. in
September 1998, the Company issued options for 120,213 shares at an exercise
price of $0.11 per share to certain employees of The Atlas Group, Inc. who had
held options of The Atlas Group, Inc. before its acquisition by the Company.
Options for 33,700 shares remain outstanding and are exercisable as of September
30, 2004.
107
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 12 - ACQUISITION OF PREMIER LEASE SERVICES, L.C.
On June 30, 2004, LEAF Financial expanded its lease origination
capability and assets under management with the acquisition of certain assets of
Premier Lease Services, L.C. The acquisition included both a portfolio of small
ticket leases with a value of $35.0 million bought on behalf of its investment
partners and numerous vendor finance relationships as well as the right to
utilize certain of their origination personnel.
NOTE 13 - COMMITMENTS AND CONTINGENCIES
The Company leases office space and equipment under leases with varying
expiration dates through 2009. Rental expense was $1.7 million, $2.6 million and
$2.1 million for the years ended September 30, 2004, 2003 and 2002,
respectively. At September 30, 2004, future minimum rental commitments for the
next five fiscal years were as follows (in thousands):
2005.............................. $ 1,400
2006.............................. 823
2007.............................. 597
2008.............................. 428
2009.............................. 63
The Company is the managing general partner of various energy
partnerships, and has agreed to indemnify each investor partner from any
liability that exceeds such partner's share of partnership assets. Subject to
certain conditions, investor partners in certain energy partnerships have the
right to present their interests for purchase by the Company, as managing
general partner. The Company is not obligated to purchase more than 5% to 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 from its energy partnerships to the receipt by investor
partners of cash distributions equal to at least 10% of their subscriptions,
determined on a cumulative basis, in accordance with the terms of the
partnership agreements.
The Company is party to employment agreements with certain executives
that provide for compensation and certain other benefits. The agreements also
provide for severance payments under certain circumstances.
The Company is a defendant in a proposed class action originally filed
in February 2000 in the New York Supreme Court, Chautauqua County, by
individuals, putatively on their own behalf and on behalf of similarly situated
individuals, who leased property to the Company. The complaint alleges that the
Company is not paying landowners 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. Plaintiffs were certified as a class in
December 2003; an appeal of that certification is pending. The action is
currently in its discovery phase. The Company believes the complaint is without
merit and is defending itself vigorously.
108
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 13 - COMMITMENTS AND CONTINGENCIES - (CONTINUED)
Two real estate investment partnerships in which the Company has
general partner interests have obtained senior lien financing with respect to
the six properties they acquired. The senior liens are with recourse only to the
properties securing them subject to certain standard exceptions, which the
Company has guaranteed. These guarantees expire as the related indebtedness is
paid down over the next ten years. In addition, property owners have obtained
senior lien financing with respect to nine of the Company's loans. The senior
liens are with recourse only to the properties securing them subject to certain
standard exceptions, which the Company have guaranteed. These guarantees expire
as the related indebtedness is paid down over the next ten years.
The Company is also a party to various routine legal proceedings
arising out of the ordinary course of its business. Management believes that
none of these actions, individually or in the aggregate, will have a material
adverse effect on the Company's financial condition or operations.
NOTE 14 - DERIVATIVE INSTRUMENTS
The Company, through its energy subsidiaries, from time to time enters
into natural gas futures and option contracts to hedge its exposure to changes
in natural gas prices. At any point in time, such contracts may include
regulated New York Mercantile Exchange ("NYMEX") futures and options contracts
and non-regulated over-the-counter futures contracts with qualified
counterparties. NYMEX contracts are generally settled with offsetting positions,
but may be settled by the delivery of natural gas.
The Company formally documents all relationships between hedging
instruments and the items being hedged, including the Company's risk management
objective and strategy for undertaking the hedging transactions. This includes
matching the natural gas futures and options contracts to the forecasted
transactions. The Company assesses, both at the inception of the hedge and on an
ongoing basis, whether the derivatives are highly effective in offsetting
changes in the fair value of hedged items. Historically these contracts have
qualified and been designated as cash flow hedges and recorded at their fair
values. Gains or losses on future contracts are determined as the difference
between the contract price and a reference price, generally prices on NYMEX.
Such gains and losses are charged or credited to accumulated other comprehensive
income (loss) and recognized as a component of sales revenue in the month the
hedged gas is sold. If it is determined that a derivative is not highly
effective as a hedge or it has ceased to be a highly effective hedge, due to the
loss of correlation between changes in gas reference prices under a hedging
instrument and actual gas prices the Company will discontinue hedge accounting
for the derivative and subsequent changes in fair value for the derivative will
be recognized immediately into earnings.
At September 30, 2004, the Company had no open natural gas futures
contracts related to natural gas sales and accordingly, had no unrealized loss
or gain related to open NYMEX contracts at that date. The Company recognized a
loss of $0, $1.1 million and $59,000 on settled contracts covering natural gas
production for the years ended September 30, 2004, 2003 and 2002, respectively.
The Company recognized no gains or losses during the three year period ended
September 30, 2004 for hedge ineffectiveness or as a result of the
discontinuance of cash flow hedges.
109
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 14 - DERIVATIVE INSTRUMENTS - (CONTINUED)
In connection with acquisition of Spectrum, Atlas Pipeline acquired
and/or entered into certain financial swap instruments, some of which settled
during the three months ended September 30, 2004 that were designated as cash
flow hedging instruments in accordance with SFAS 133. The maturities of the
instruments outstanding at September 30, 2004, are less than three years. The
swap instruments are contractual agreements to exchange obligations of money
between the buyer and seller of the instruments as natural gas, natural gas
liquid and crude oil volumes during the pricing period are sold. The swaps are
tied to a set fixed price for the seller and floating price determinants for the
buyer priced on certain indices at the end of the relevant trading period.
Options have also been entered into that fix the price for the seller within the
puts purchased and calls sold and floating price determinants for the buyer
priced on certain indices at the end of the relevant trading period. Atlas
Pipeline entered into these instruments to hedge the forecasted gas plant
residue, natural gas liquids ("NGLs"), and crude sales to variability in
expected future cash flows attributable to changes in market prices.
Atlas Pipeline acquired and entered into several swaps that were
designed to hedge natural gas liquid prices during the year ended September 30,
2004 that did not meet specific hedge accounting criteria. Atlas Pipeline
recognized a loss of $697,000 related to these instruments during fiscal 2004.
As of September 30, 2004, Atlas Pipeline had the following natural gas
liquids natural gas, and crude oil volumes hedged. Atlas Pipeline
recognized a loss of $27,000 on settled contracts for the year ended September
30, 2004.
NATURAL GAS LIQUIDS FIXED-PRICE SWAPS
Production Average Fair Value
Period Volumes Fixed Price Liability
---------- --------- ----------- --------------
(calendar year) (gallons) (per gallon) (in thousands)
2004 2,562,000 $ 0.645 $ (282)
2005 10,584,000 0.537 (2,524)
2006 6,804,000 0.575 (1,030)
---------
$ (3,836)
=========
NATURAL GAS FIXED - PRICE SWAPS
Production Average Fair Value
Period Volumes Fixed Price Liability
---------- --------- ----------- --------------
(calendar year) (MMBTU)(1) (per MMBTU) (in thousands)
2005 960,000 $ 6.165 $ (697)
2006 450,000 5.920 (160)
---------
$ (857)
=========
NATURAL GAS OPTIONS
Production Average Fair Value
Period Option Type Volumes Strike Price Asset (Liability)
---------- ----------- ------- ------------ -----------------
(calendar year) (MMBTU)(1) (per MMBTU) (in thousands)
2004 Puts purchased 150,000 $ 5.700 $ 7
2004 Calls sold 150,000 6.970 (41)
2005 Puts purchased 180,000 5.875 -
2005 Calls sold 180,000 7.110 (145)
--------
$ (179)
========
110
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 14 - DERIVATIVE INSTRUMENTS - (CONTINUED)
CRUDE FIXED - PRICE SWAPS
Production Average Fair Value
Period Volumes Fixed Price Liability
---------- --------- ----------- --------------
(calendar year) (barrels) (per barrel) (in thousands)
2006 18,000 $ 38.767 $ (31)
========
CRUDE OPTIONS
Production Average Fair Value
Period Option Type Volumes Strike Price Liability
---------- ----------- ------- ------------ -----------------
(calendar year) (barrels) (per barrel) (in thousands)
2004 Puts purchased 25,000 $ 32.200 $ -
2004 Calls sold 25,000 38.560 (244)
2005 Puts purchased 75,000 30.067 -
2005 Calls sold 75,000 34.383 (846)
2006 Puts purchased 5,000 30.000 -
2006 Calls sold 5,000 34.250 (39)
--------
(1,129)
--------
Total $ (6,032)
========
- -----------
(1) MMBTU means Million British Thermal Units.
As of September 30, 2004, the fair value of the swap agreements Atlas
Pipeline had entered into in order to convert its market-sensitive floating
price contracts to fixed-price positions resulted in a $6.0 million liability of
which $4.0 million is expected to be reclassified to earnings in fiscal 2005 and
is included in accrued liabilities on the Company's consolidated balance sheet,
the balance is in other liabilities on the consolidated balance sheet.
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.
111
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 15 - DISCONTINUED OPERATIONS AND CUMULATIVE EFFECTS OF CHANGES IN
ACCOUNTING PRINCIPLES
DISCONTINUED OPERATIONS
In fiscal 2004, the Company disposed of five real estate investments.
Three investments in real estate loans were disposed by repayments of the
Company's loans; one as a result of a refinancing and two by sales of properties
securing by the Company's loans. In addition, two real estate properties owned
by the Company and classified as held for sale were sold in fiscal 2004. The
gains and losses on the disposal of these assets are included in gains on
disposals of discontinued operations for the year ended September 30, 2004.
Operating results of four real assets classified as held for sale as of
September 30, 2004 are included in losses on discontinued operations as well as
the operations of those entities classified as held for sale and sold in fiscal
2004.
Summarized discontinued operating results of the Company's real estate
operations are as follows:
Years Ended September 30,
-----------------------------------------
2004 2003 2002
---------- ---------- ----------
(in thousands)
(Loss) income on discontinued operations before taxes...................... $ (6,050) $ 1,886 $ -
Income tax benefit (provision)............................................. 2,110 (665) -
---------- ---------- ----------
(Loss) income from discontinued operations................................. $ (3,940) $ 1,221 $ -
========== ========== ==========
Years Ended September 30,
-----------------------------------------
2004 2003 2002
---------- ---------- ----------
(in thousands)
Gain (loss) on disposals.................................................. $ 749 $ (500) $ -
Income tax (provision) benefit............................................ (255) 175 -
---------- ---------- ----------
Gain (loss) on disposal of discontinued operations........................ $ 494 $ (325) $ -
========== ========== ==========
In September 1999, the Company adopted a plan to dispose of its
residential mortgage lending business, LowCostLoan, Inc. ("LCL") (formerly
Fidelity Mortgage Funding, Inc.). The business was disposed of in November 2000.
Accordingly, LCL has been reported as a discontinued operation. Upon final
resolution of certain lease obligations associated with LCL, the Company
recognized a gain on disposal in the year ended September 30, 2004. Summarized
results of LCL are as follows:
Years Ended September 30,
-----------------------------------------
2004 2003 2002
---------- ---------- ----------
(in thousands)
Gain on disposal.......................................................... $ 602 $ - $ -
Income tax provision...................................................... (210) - -
---------- ---------- ----------
Gain on disposal of discontinued operations............................... $ 392 $ - $ -
========== ========== ==========
112
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 15 - DISCONTINUED OPERATIONS AND CUMULATIVE EFFECTS OF CHANGES IN
ACCOUNTING PRINCIPLES - (CONTINUED)
In June 2002, the Company adopted a plan to dispose of its 50% interest
in Optiron Corporation ("Optiron"), an energy technology company. The Company
subsequently reduced its interest 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 of the $5.9 million of indebtedness owed by Optiron to the
Company. The remaining $1.6 million of indebtedness was retained by the Company
in the form of a promissory note secured by all of Optiron's assets and by the
common stock of Optiron's 90% shareholder. The note bears interest at the prime
rate plus 1% payable monthly; an additional 1% will accrue until the maturity
date of the note in 2022.
Under the terms of the sale, Optiron was obligated to pay 10% of its
revenues to the Company if such revenues exceeded $2.0 million in the twelve
month period following the closing of the transaction. As a result, Optiron paid
$295,000 to the Company in March 2004.
In accordance with SFAS 144, the results of Optiron's operations have
been reported as discontinued for all periods presented.
Summarized discontinued operating results of Optiron are as follows:
Years Ended September 30,
-----------------------------------------
2004 2003 2002
---------- ---------- ----------
(in thousands)
Loss from discontinued operations before taxes............................. $ - $ - $ (553)
Income tax benefit......................................................... - - 193
---------- ---------- ----------
Loss from discontinued operations.......................................... $ - $ - $ (360)
========== ========== ==========
Income (loss) on disposal of discontinued operations before
income taxes............................................................. $ - $ 295 $ (1,971)
Income tax (provision) benefit............................................. - (103) 690
---------- ---------- ----------
Income (loss) on disposal of discontinued operations....................... $ - $ 192 $ (1,281)
========== ========== ==========
113
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 15 - DISCONTINUED OPERATIONS AND CUMULATIVE EFFECTS OF CHANGES IN
ACCOUNTING PRINCIPLES - (CONTINUED)
In connection with a settlement in fiscal 2002 between the Company and
the successor in interest to the purchaser of the Company's small ticket
equipment leasing subsidiary, Fidelity Leasing, Inc. ("FLI"), the Company and
the successor were released from certain terms and obligations of the original
purchase agreements, including many of the terms of the Company's
non-competition agreement, and from claims arising from circumstances known at
the settlement date. In addition, the Company (i) released to the successor
$10.0 million that had been placed in escrow; (ii) paid the successor $6.0
million; (iii) guaranteed that the successor will receive payments of $1.2
million from a note, secured by FLI lease receivables; and (iv) issued two
promissory notes to the successor, each in the principal amount of $1.75
million, bearing interest at the two-year treasury rate plus 500 basis points,
due on December 31, 2004 and 2003, respectively. The 2003 promissory note was
repaid in accordance with its terms. In fiscal 2002, the Company recorded a loss
from discontinued operations, net of taxes, of $9.4 million in connection with
the settlement.
Summarized discontinued operating results of FLI are as follows:
Years Ended September 30,
-----------------------------------------
2004 2003 2002
---------- ---------- ----------
(in thousands)
Loss on disposal before taxes.............................................. $ - $ - $ (14,460)
Income tax benefit......................................................... - - 5,061
---------- ---------- ----------
Loss on disposal of discontinued operations................................ $ - $ - $ (9,399)
========== ========== ==========
Summarized discontinued operating results of real estate, LCL, Optiron
and FLI are:
Years Ended September 30,
-----------------------------------------
2004 2003 2002
---------- ---------- ----------
(in thousands)
(Loss) income from discontinued operations.................................. $ (6,050) $ 1,886 $ (553)
Income tax benefit (provision).............................................. 2,110 (665) 193
---------- ---------- ----------
(3,940) 1,221 (360)
---------- ---------- ----------
Gain (loss) on disposal of discontinued operations.......................... 1,351 (205) (16,431)
Income tax benefit (provision).............................................. (465) 72 5,751
---------- ---------- ----------
886 (133) (10,680)
---------- ---------- ----------
Total (loss) income on discontinued operations.............................. $ (3,054) $ 1,088 $ (11,040)
========== ========== ==========
114
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 15 - DISCONTINUED OPERATIONS AND CUMULATIVE EFFECTS OF CHANGES IN
ACCOUNTING PRINCIPLES - (CONTINUED)
CUMULATIVE EFFECTS OF CHANGES IN ACCOUNTING PRINCIPLES
As described in Note 3, the Company recorded a $13.9 million cumulative
effect adjustment (net of taxes of $7.5 million) for a change in accounting
principle upon the adoption of FIN 46 in fiscal 2003.
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 Optiron's 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, for which the Company recorded its
50% share ($627,000, net of taxes of $336,000) in fiscal 2002.
NOTE 16 - SETTLEMENT OF LAWSUITS
The Company settled an action filed in the U.S. District Court for the
District of Oregon by the former chairman of TRM Corporation and his children.
The Company's chairman and a former director and officer also had been named as
defendants. The plaintiffs' claims were for breach of contract and fraud. The
Company recorded a charge of $1.2 million, including related legal fees, in the
year ended September 30, 2003. The Company subsequently filed an action against
one of its directors' and officers' liability insurance carriers in connection
with this settlement. In November 2004, the Company settled its action against
the insurance carrier for $1.4 million.
The Company was a defendant in a class action complaint by stockholders
who purchased shares of the Company's common stock between December 17, 1997 and
February 22, 1999. Damages were sought in an unspecified amount for losses
allegedly incurred as the result of misstatements and omissions allegedly
contained in the Company's periodic reports and a registration statement filed
with the SEC. To avoid the potential of costly litigation, which would have
involved significant time of senior management, the Company settled this matter
for a maximum of $7.0 million plus approximately $1.0 million in costs and
expenses, of which $6.0 million was paid by two of the Company's directors' and
officers' liability insurers. The Company is seeking to obtain the balance of
$2.0 million through an action against a third insurer who refused to
participate in the settlement. The plaintiffs have agreed to reduce by 50% the
amount by which the $2.0 million exceeds any recovery from the insurer. The
Company charged operations $1.0 million in the year ended September 30, 2002,
the amount of its maximum remaining exposure. If the Company is successful in
receiving reimbursement from the third insurer, future operations will be
benefited. In November 2004, the court granted the Company's summary judgment
motion as to its breach of contract claim. The Company's damage claim is for
$2.3 million, however, no final agreement as to damages has been reached.
115
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 17 - ATLAS AMERICA PUBLIC OFFERING
In May 2004, Atlas America completed an initial public offering of
2,645,000 shares of its common stock at a price of $15.50 per common share
including the underwriters' over allotment resulting in a $20.4 million gain on
sale reflected as an increase to stockholders' equity based on the excess of
proceeds received over the book value of the interest sold to the public. The
net proceeds of the offering of $37.0 million, after deducting underwriting
discounts and costs, were distributed to the Company in the form of a
non-taxable dividend. Following the offering, the Company continues to own
approximately 80.2% of Atlas America's common stock.
In connection with the offering, E. Cohen became Chairman, Chief
Executive Officer and President of Atlas America and retired as Chief Executive
Officer of the Company. As a result of his retirement and the commencement of
payment of benefits under his SERP, the Company recorded a charge of $1.4
million in fiscal 2004 (see Note 11).
NOTE 18 - OPERATIONS OF ATLAS PIPELINE
In February 2000, the Company's natural gas gathering operations were
sold to Atlas Pipeline in connection with a public offering by Atlas Pipeline of
1,500,000 common units. The Company received net proceeds of $15.3 million for
the gathering systems, and Atlas Pipeline issued to the Company 1,641,026
subordinated units then 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% general partnership interest on a consolidated
basis.
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.
The Company's subordinated units are a special class of limited
partnership interest in Atlas Pipeline under which its rights to distributions
are subordinated to those of the publicly held common units. The subordination
period extends until December 31, 2004 and will continue beyond that date if
financial tests specified in the partnership agreement are not met. The
Company's general partner interest also includes a right to receive incentive
distributions if the partnership meets or exceeds specified levels of
distributions.
In April and July 2004, Atlas Pipeline completed public offerings of
750,000 and 2,100,000 common units, respectively. The net proceeds after
underwriting discounts, commissions and costs were $25.2 million and $67.5
million, respectively. The General Partner simultaneously contributed $535,000
and $1.5 million to the Partnership in order to maintain its 2% general partner
interest in Atlas Pipeline.
In May 2003, Atlas Pipeline completed a public offering of 1,092,500
common units of limited partner interest. The net proceeds after underwriting
discounts and commissions were approximately $25.2 million. These proceeds were
used in part to repay existing indebtedness of $8.5 million.
116
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 18 - OPERATIONS OF ATLAS PIPELINE - (CONTINUED)
Upon the completion of these offerings, the Company's combined general
and limited partner interest in Atlas Pipeline was reduced to 24%. Because the
Company, through its general partner interest, controls the decisions and
operations of Atlas Pipeline, it is consolidated in the Company's financial
statements.
During fiscal 2004, 2003 and 2002, the fee paid to Atlas Pipeline was
calculated based on the 16% rate. Through September 30, 2004, the Company has
not been required to provide any construction financing.
In September 2003, Atlas Pipeline entered into an agreement with SEMCO
Energy, Inc. to purchase all of the stock of Alaska Pipeline Company. In order
to complete the acquisition, Atlas Pipeline needed the approval of the
Regulatory Commission of Alaska. The Regulatory Commission initially approved
the transaction, but on June 4, 2004 it vacated its order of approval based upon
a motion for clarification or reconsideration filed by SEMCO. On July 1, 2004,
SEMCO sent Atlas Pipeline a notice purporting to terminate the transaction.
Atlas Pipeline believes SEMCO caused the delay in closing the transaction and
breached its obligations under the acquisition agreement. Atlas Pipeline is
currently pursuing its remedies under the acquisition agreement. In connection
with the acquisition, subsequent termination and current legal action, Atlas
Pipeline incurred $3.0 million of costs, which are shown as terminated
acquisition costs and are included in our energy expenses.
NOTE 19 -SPECTRUM ACQUISITION BY ATLAS PIPELINE
On July 16, 2004, Atlas Pipeline acquired Spectrum Field Services, Inc.
for approximately $142.4 million, including transaction costs and the payment of
taxes due as a result of the transaction. Spectrum's principal assets include
1,900 miles of natural gas pipelines and a natural gas processing facility in
Velma, Oklahoma.
Atlas Pipeline financed the Spectrum acquisition, including
approximately $4.2 million of transaction costs, as follows:
o borrowed $100.0 million under the term loan portion of its $135.0
million senior secured term loan and revolving credit facility
administered by Wachovia (Note 9);
o used the $20.0 million of proceeds received from the sale to the
Company and Atlas America of preferred units in Atlas Pipeline
Operating Partnership; and
o used $22.4 million of net proceeds from the Atlas Pipeline's April
2004 common unit offering.
On July 20, 2004, Atlas Pipeline used a portion of the July 2004 public
offering to repay $40.0 million of the borrowings under its $135.0 million
credit facility and to repurchase the preferred units from the Company and Atlas
America for $20.4 million.
On March 9, 2004, the Oklahoma Tax Commission ("OTC") filed a petition
against Spectrum alleging that Spectrum underpaid gross production taxes
beginning in June 2000. The OTC is seeking a settlement of $5.0 million plus
interest and penalties. Atlas Pipeline plans on defending itself vigorously. In
addition, under the terms of the Spectrum purchase agreement, $14.0 million has
been placed in escrow to cover the costs of any adverse settlement resulting
from the petition and other indemnification obligations of the purchase
agreement.
117
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 19 -SPECTRUM ACQUISITION BY ATLAS PIPELINE - (CONTINUED)
The acquisition was accounted for using the purchase method of
accounting under SFAS No. 141 "Business Combinations." The following table
presents the allocation of the acquisition costs, including professional fees
and other related acquisition costs, to the assets acquired and liabilities
assumed based on their fair values at the date of acquisition (in thousands):
Cash and cash equivalents.......................................................... $ 804
Accounts receivable................................................................ 18,504
Prepaid expenses................................................................... 649
Property, plant and equipment...................................................... 140,592
Other long-term assets............................................................. 1,054
-----------
Total assets acquired............................................................ 161,603
-----------
Accounts payable and accrued liabilities........................................... (17,552)
Hedging liabilities................................................................ (1,519)
Long-term debt..................................................................... (164)
-----------
Total liabilities assumed........................................................ (19,235)
-----------
Net assets acquired............................................................ $ 142,368
===========
Atlas Pipeline is in the process of evaluating certain estimates made
in the purchase price and related allocations; thus, the purchase price and
allocation are both subject to adjustment.
The results of operations of Spectrum are included in the Company's
consolidated statements of operations from July 16, 2004, the date of
acquisition.
The following summarized unaudited pro forma consolidated statements of
operations information for the years ended September 30, 2004 and 2003 assumes
that the Spectrum acquisition occurred as of October 1, 2002. The Company has
prepared these pro forma financial results for comparative purposes only. These
pro forma financial results may not be indicative of the results that would have
occurred if Atlas Pipeline had completed this acquisition as of the periods
shown below or the results that will be attained in the future. The amounts
presented below are in thousands, except per share amounts:
Year Ended
September 30, 2004
--------------------------------------------
Pro Forma
As Reported Adjustments Pro Forma
----------- ----------- ---------
Revenues........................................................... $ 214,841 $ 90,177 $ 305,018
Income from continuing operations.................................. $ 21,463 $ 2,508 $ 23,971
Net income......................................................... $ 18,409 $ 2,508 $ 20,917
Basic net income per common share.................................. $ 1.06 $ 0.14 $ 1.20
Diluted net income per common share................................ $ 1.01 $ 0.13 $ 1.14
Weighted average number of common shares used for basic net
Income calculation............................................... 17,417 - 17,417
Weighted average number of common shares used for
diluted net income per common share calculation.................. 18,309 - 18,309
118
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 19 -SPECTRUM ACQUISITION BY ATLAS PIPELINE - (CONTINUED)
Year Ended
September 30, 2003
--------------------------------------------
Pro Forma
As Reported Adjustments Pro Forma
----------- ----------- ---------
Revenues......................................................... $ 124,455 $ 98,488 $ 222,943
Income from continuing operations................................ $ 9,878 $ 1,822 $ 11,700
Net income (loss)................................................ $ (2,915) $ 1,822 $ (1,093)
Basic net income (loss) per common share......................... $ (0.17) $ 0.11 $ (0.06)
Diluted net income (loss) per common share....................... $ (0.17) $ 0.11 $ (0.06)
Weighted average number of common shares used for basic
net income (loss) calculation.................................. 17,172 - 17,172
Weighted average number of common shares used for diluted net
income (loss) per common share calculation..................... 17,568 - 17,568
Significant pro forma adjustments include revenues and costs and
expenses for the period prior to Atlas Pipeline's acquisition, interest and
depreciation expense and the elimination of income taxes.
NOTE 20 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMER INFORMATION
The Company's operations include reportable operating segments. In
addition, certain other activities are reported in the "Other energy" category
and "All other" categories. These operating segments reflect the way the Company
manages its operations and makes business decisions. The equipment leasing
segment first met the criteria for reportable operating segments in the three
months ended June 30, 2003 and, accordingly, all prior periods have been
restated to reflect these new segments. The Company does not allocate income
taxes to its operating segments. Operating segment data for the periods
indicated are as follows:
YEAR ENDED SEPTEMBER 30, 2004 (in thousands):
Segment Other
Revenues from Depreciation, operating significant
external Interest Interest depletion and profit items:
customers income expense amortization (loss) Segment assets
------------- -------- -------- ------------- --------- --------------
Well drilling $ 86,880 $ - $ - $ - $ 9,679 $ 8,486
Production and
exploration 48,526 - - 10,319 28,981 185,775
Mid- Continent 30,048 - 3 613 2,069 154,741
Appalachia 6,204 - - 2,024 340 36,496
Other energy(a) 8,694 250 2,878 1,744 (1,135) 6,807
Real estate 18,884 75 1,218 324 2,175 210,827
Equipment leasing 8,262 3 970 534 (1,268) 29,417
Structured finance 7,343 - - 10 5,205 10,418
All other - 1,339 1,618 - (8,770) 82,739
Eliminations - (1,021) (71) - - -
-------- --------- ----------- -------- -------- ----------
Totals $214,841 $ 646 $ 6,616 $ 15,568 $ 37,276 $ 725,706
======== ========= =========== ======== ======== ==========
119
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 20 - OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMER INFORMATION -
(CONTINUED)
YEAR ENDED SEPTEMBER 30, 2003 (in thousands):
Segment Other
Revenues from Depreciation, operating significant
external Interest Interest depletion and profit items:
customers income expense amortization (loss) Segment assets
------------- -------- -------- ------------- --------- --------------
Well drilling $ 52,879 $ - $ - $ - $ 5,317 $ 7,844
Production and
exploration 38,639 - - 8,042 21,463 145,614
Mid- Continent - - - - - -
Appalachia 5,901 - - 1,657 175 30,735
Other energy (a) 7,843 220 1,961 1,896 (505) 48,195
Real estate 13,678 83 1,400 221 6,864 370,046
Equipment leasing 4,071 71 916 196 (2,011) 15,630
Structured finance 1,444 8 - - 1,491 4,987
All other - 484 8,707 136 (8,153) 47,693
Eliminations - (195) (195) - - -
-------- --------- ---------- -------- -------- ----------
Totals $124,455 $ 671 $ 12,789 $ 12,148 $ 24,641 $ 670,744
======== ========= ========== ======== ======== ==========
YEAR ENDED SEPTEMBER 30, 2002 (in thousands):
Segment Other
Revenues from Depreciation, operating significant
external Interest Interest depletion and profit items:
customers income expense amortization (loss) Segment assets
------------- -------- -------- ------------- --------- --------------
Well drilling $ 55,736 $ - $ - $ - $ 6,057 $ 7,555
Production and
exploration 28,916 - - 7,550 12,708 119,125
Mid- Continent - - - - - -
Appalachia 5,389 - - 1,404 510 27,983
Other energy (a) 7,871 686 2,200 1,882 (2,533) 37,951
Real estate 16,582 145 1,790 135 12,404 204,327
Equipment leasing 1,246 145 44 82 421 10,793
Structured finance 185 519 - - (15) 3,085
All other(a) - - 8,959 108 (7,818) 56,679
Eliminations - (253) (253) - - -
-------- --------- -------- -------- -------- ---------
Totals $115,925 $ 1,242 $ 12,740 $ 11,161 $ 21,734 $ 467,498
======== ========= ======== ======== ======== =========
- -----------
(a) Includes revenues and expenses from the Company's well services business
which does not meet the quantitative threshold for reporting segment
information and general corporate expenses not allocable to any particular
segment.
Operating profit (loss) per segment represents total revenues less
costs and expenses attributable thereto, including interest, provision for
possible losses and depreciation, depletion and amortization, excluding general
corporate expenses.
The Company's natural gas is sold under contract to various purchasers.
For the years ended September 30, 2004, 2003 and 2002, gas sales to First Energy
Solutions Corporation accounted for 11%, 18% and 16%, respectively, of our
energy revenues. No other operating segments had revenues from a single customer
or borrower which exceeded 10% of total revenues.
120
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 21 - SUPPLEMENTAL OIL AND GAS INFORMATION
Results of operations from oil and gas producing activities:
Years Ended September 30,
----------------------------------------
2004 2003 2002
---------- ---------- ----------
(in thousands)
Revenues..................................................................... $ 48,526 $ 38,639 $ 28,916
Production costs............................................................. (7,289) (6,770) (6,691)
Exploration expenses......................................................... (1,549) (1,715) (1,573)
Depreciation, depletion and amortization..................................... (10,319) (8,042) (7,550)
Income taxes................................................................. (10,279) (7,519) (4,005)
---------- ---------- ----------
Results of operations from oil and gas producing activities.................. $ 19,090 $ 14,593 $ 9,097
========== ========== ==========
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,
----------------------------------------
2004 2003 2002
---------- ---------- ----------
(in thousands)
Mineral interests:
Proved properties.......................................................... $ 2,544 $ 844 $ 843
Unproved properties........................................................ 1,002 563 584
Wells and related equipment.................................................. 184,046 150,657 124,083
Support equipment............................................................ 2,890 2,185 1,412
Uncompleted wells equipment and facilities................................... 1 51 51
----------- ----------- ----------
190,483 154,300 126,973
Accumulated depreciation, depletion and amortization ........................ (54,086) (43,292) (36,669)
----------- ----------- ----------
Net capitalized costs................................................... $ 136,397 $ 111,008 $ 90,304
=========== =========== ==========
Costs Incurred in Oil and Gas Producing Activities. The costs incurred
by the Company in its oil and gas activities during fiscal years 2004, 2003 and
2002 are as follows:
Years Ended September 30,
----------------------------------------
2004 2003 2002
---------- ---------- ----------
(in thousands)
Property acquisition costs:
Proved properties.......................................................... $ 1,700 $ 412 $ 154
Unproved properties........................................................ 439 - 9
Exploration costs............................................................ 1,549 1,715 1,573
Development costs............................................................ 39,978 28,007 20,934
---------- ---------- ----------
$ 43,666 $ 30,134 $ 22,670
========== ========== ==========
121
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 21 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)
The development costs for the years ended September 30, 2004, 2003 and
2002 were substantially all incurred for the development of proved undeveloped
properties.
Oil and Gas Reserve Information (Unaudited). The estimates of the
Company's proved and unproved gas reserves are based upon evaluations made by
management and verified by Wright & Company, Inc., an independent petroleum
engineering firm, as of September 30, 2004, 2003 and 2002. All reserves are
located within the United States. Reserves are estimated in accordance with
guidelines established by the Securities and Exchange Commission and the FASB
which require that reserve estimates be prepared under existing economic and
operating conditions with no provisions for price and cost escalation except by
contractual arrangements.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and NGLs which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e. prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
o Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation
tests. The area of a reservoir considered proved includes (a) that
portion delineated by drilling and defined by gas-oil and/or
oil-water contacts, if any; and (b) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and
engineering data. In the absence of information on fluid contacts,
the lowest known structural occurrence of hydrocarbons controls
the lower proved limit of the reservoir.
o Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are
included in the "proved" classification when successful testing by
a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on which
the project or program was based.
o Estimates of proved reserves do not include the following: (a) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reservoirs"; (b) crude oil,
natural gas, and NGLs, 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 NGLs, that may occur in undrilled prospects; and (d) crude
oil, natural gas and NGLs that may be recovered from oil shales,
coal, gilsonite and other such sources.
122
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 21 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)
Proved developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and operation
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
There are numerous uncertainties inherent in estimating quantities of
proven reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents estimates only
and should not be construed as being exact. In addition, the standardized
measures of discounted future net cash flows may not represent the fair market
value of the Company's oil and gas reserves or the present value of future cash
flows of equivalent reserves, due to anticipated future changes in oil and gas
prices and in production and development costs and other factors for effects
have not been proved.
The Company's reconciliation of changes in proved reserve quantities is
as follows (unaudited):
Gas Oil
(mcf) (bbls)
------------ ---------
Balance September 30, 2001................................................. 118,117,370 1,801,068
Current additions..................................................... 19,303,971 55,416
Sales of reserves in-place............................................ (510,812) (23,676)
Purchase of reserves in-place......................................... 280,594 2,180
Transfers to limited partnerships..................................... (6,829,047) (45,001)
Revisions............................................................. (23,057) 260,430
Production............................................................ (7,117,276) (172,750)
------------ ---------
Balance September 30, 2002................................................. 123,221,743 1,877,667
Current additions..................................................... 27,440,261 44,868
Sales of reserves in-place............................................ (56,480) (14,463)
Purchase of reserves in-place......................................... 986,463 18,998
Transfers to limited partnerships..................................... (8,669,521) (31,386)
Revisions............................................................. (2,662,812) 119,038
Production............................................................ (6,966,899) (160,048)
------------ ---------
Balance September 30, 2003................................................. 133,292,755 1,854,674
Current additions..................................................... 28,761,902 245,509
Sales of reserves in-place............................................ (3,439) (1,669)
Purchase of reserves in-place......................................... 232,429 4,000
Transfers to limited partnerships..................................... (10,132,616) (29,394)
Revisions............................................................. (2,732,385) 382,613
Production............................................................ (7,285,281) (181,021)
------------ ---------
Balance September 30, 2004................................................. 142,133,365 2,274,712
============ =========
Proved developed reserves at:
September 30, 2002......................................................... 83,995,712 1,846,281
September 30, 2003......................................................... 87,760,113 1,825,280
September 30, 2004......................................................... 95,788,656 2,125,813
123
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 21 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)
The following schedule presents the standardized measure of estimated
discounted future net cash flows relating to proved oil and gas reserves. The
estimated future production is priced at fiscal year-end prices, adjusted only
for fixed and determinable increases in natural gas and oil prices provided by
contractual agreements. The resulting estimated future cash inflows are reduced
by estimated future costs to develop and produce the proved reserves based on
fiscal year-end cost levels and includes the effect on cash flows of the
settlement of asset retirement obligations on gas and oil properties. 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, 2004, 2003 and 2002 and
such conditions continually change. Accordingly, such information should not
serve as a basis in making any judgment on the potential value of recoverable
reserves or in estimating future results of operations (unaudited).
Years Ended September 30,
------------------------------------------
2004 2003 2002
------------ ----------- -----------
(in thousands)
Future cash inflows.......................................................... $ 1,096,047 $ 715,539 $ 518,118
Future production costs...................................................... (227,738) (185,442) (147,279)
Future development costs..................................................... (92,079) (72,476) (55,644)
Future income tax expense.................................................... (227,862) (125,556) (79,557)
------------ ----------- -----------
Future net cash flows........................................................ 548,368 332,065 235,638
Less 10% annual discount for estimated timing of cash flows................ (315,370) (187,714) (131,512)
------------ ----------- -----------
Standardized measure of discounted future net cash flows................... $ 232,998 $ 144,351 $ 104,126
============ =========== ===========
The future cash flows estimated to be spent to develop proved
undeveloped properties in the years ended September 30, 2005, 2006 and 2007 are
$36.0 million, $36.0 million and $20.1 million, respectively.
124
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 21 - SUPPLEMENTAL OIL AND GAS INFORMATION - (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 (unaudited):
Years Ended September 30,
------------------------------------------
2004 2003 2002
------------ ----------- -----------
(in thousands)
Balance, beginning of year................................................... $ 144,351 $ 104,126 $ 98,712
Increase (decrease) in discounted future net cash flows:
Sales and transfers of oil and gas, net of related costs................... (41,237) (31,869) (22,223)
Net changes in prices and production costs................................. 97,161 44,232 249
Revisions of previous quantity estimates................................... 6,265 (229) 3,787
Development costs incurred................................................. 4,838 3,689 4,107
Changes in future development costs........................................ (1,033) (166) (149)
Transfers to limited partnerships.......................................... (9,499) (3,313) (3,970)
Extensions, discoveries, and improved recovery less
related costs........................................................... 54,979 24,272 12,057
Purchases of reserves in-place............................................. 594 1,730 340
Sales of reserves in-place, net of tax effect.............................. (33) (200) (799)
Accretion of discount...................................................... 19,142 13,247 12,726
Net changes in future income taxes......................................... (40,504) (18,749) 203
Estimated settlement of asset retirement obligations....................... (1,757) (3,131) -
Estimated proceeds on disposals of well equipment.......................... 2,055 3,380 -
Other...................................................................... (2,324) 7,332 (914)
----------- ----------- -----------
Balance, end of year......................................................... $ 232,998 $ 144,351 $ 104,126
=========== =========== ===========
125
RESOURCE AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 22 - QUARTERLY RESULTS (UNAUDITED)
December 31, March 31, June 30, September 30,
------------ --------- -------- -------------
(in thousands, except per share data)
YEAR ENDED SEPTEMBER 30, 2004
Revenues............................................... $ 42,304 $ 51,051 $ 40,667 $ 80,819
Operating income....................................... $ 7,992 $ 9,972 $ 6,060 $ 13,252
Income from continuing operations...................... $ 3,823 $ 6,959 $ 3,132 $ 7,549
Net income............................................. $ 3,343 $ 6,162 $ 2,846 $ 6,058
Net income from continuing operations - basic......... $ 0.22 $ 0.40 $ 0.18 $ 0.43
Net income per common share - basic.................... $ 0.19 $ 0.35 $ 0.16 $ 0.36
Net income from continuing operations - diluted........ $ 0.21 $ 0.38 $ 0.17 $ 0.40
Net income per common share - diluted.................. $ 0.19 $ 0.34 $ 0.15 $ 0.32
December 31, March 31, June 30, September 30,
------------ --------- -------- -------------
(in thousands, except per share data)
YEAR ENDED SEPTEMBER 30, 2003
Revenues............................................... $ 22,388 $ 40,540 $ 28,059 $ 33,468
Operating income....................................... $ 4,629 $ 6,358 $ 7,130 $ 6,524
Income from continuing operations...................... $ 1,781 $ 3,095 $ 3,509 $ 1,493
Net income (loss)...................................... $ 1,781 $ 3,095 $ 3,486 $ (11,277)
Net income from continuing operations - basic.......... $ 0.10 $ 0.18 $ 0.21 $ 0.09
Net income (loss) per common share - basic............. $ 0.10 $ 0.18 $ 0.20 $ (0.66)
Net income from continuing operations - diluted........ $ 0.10 $ 0.18 $ 0.20 $ 0.08
Net income (loss) per common share - diluted........... $ 0.10 $ 0.18 $ 0.20 $ (0.64)
As described in Note 3, on July 1, 2003, the Company adopted FIN 46.
The consolidation of FIN 46 entities resulted in a $13.9 million after-tax
accounting cumulative effect charge in the Company's fourth fiscal quarter. In
addition, subsequent to adoption, the Company classified certain of these
entities as held for sale, resulting in income from discontinued operations of
$1.1 million in the Company's fourth fiscal quarter.
126
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures that are designed to
ensure that information required to be disclosed in our Securities Exchange Act
of 1934 reports is recorded, processed, summarized and reported within the time
periods specified in the U.S. Securities and Exchange Commission's rules and
forms, and that such information is accumulated and communicated to our
management, including our Chief Executive Officer and our Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure. In designing and evaluating the disclosure controls and procedures,
our management recognized that any controls and procedures, no matter how well
designed and operated, can provide only reasonable assurance of achieving the
desired control objectives, and our management necessarily was required to apply
its judgment in evaluating the cost-benefit relationship of possible controls
and procedures.
Under the supervision of our Chief Executive Officer and Chief
Financial Officer and with the participation of our disclosure committee, we
have carried out an evaluation of the effectiveness of our disclosure controls
and procedures as of the end of the period covered by this report. Based upon
that evaluation, our Chief Executive Officer and Chief Financial Officer
concluded that our disclosure controls and procedures are effective at the
reasonable assurance level.
There have been no significant changes in our internal controls over
financial reporting that has partially affected, or are reasonably likely to
materially affect, our internal control over financial reporting during our most
recent fiscal year.
ITEM 9B. OTHER INFORMATION
None.
127
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The Board of Directors is divided into three classes with directors in
each class serving three year terms. Information is set forth below regarding
the principal occupation of each of our directors. There are no family
relationships among the directors and executive officers except that Jonathan Z.
Cohen, our President, Chief Executive Officer and a director, is a son of Edward
E. Cohen, the Chairman of our Board of Directors.
NAMES OF DIRECTORS, PRINCIPAL YEAR IN WHICH SERVICE TERM TO EXPIRE
OCCUPATION AND OTHER INFORMATION AS DIRECTOR BEGAN AT ANNUAL MEETING
- -------------------------------- --------------------- -----------------
CARLOS C. CAMPBELL, 67, President of C.C. Campbell and Company (a
management consulting firm) since 1985. Director of PICO Holdings, Inc. (a
publicly-traded diversified holding company) since 1998. Director of NetWolves
Corporation (a publicly-traded information technology company) since 2003. 1990 2005
EDWARD E. COHEN, 65, Chairman of our Board since 1990. Chief Executive
Officer from 1988 to 2004. President from 2000 to 2003. Chairman of the Managing
Board of Atlas Pipeline Partners GP, LLC (a wholly-owned subsidiary of Atlas
America that is the general partner of Atlas Pipeline) since its formation in
1999. Chairman, Chief Executive officer and President of Atlas America (a
publicly-traded energy company that is 80% owned by us) since its formation in
2000. Director of TRM Corporation (a publicly-traded consumer services company)
since 1998. Chairman of the Board of Brandywine Construction & Management, Inc.
(a property management company) since 1994. 1988 2005
JONATHAN Z. COHEN, 34, President since 2003, Chief Executive Officer
since 2004 and a Director since 2002. Chief Operating Officer from 2002 to 2004.
Executive Vice President from 2001 to 2003. Senior Vice President from 1999 to
2001. Vice Chairman of the Managing Board of Atlas Pipeline Partners GP since
its formation in 1999. Vice Chairman and a Director of Atlas America since its
formation in 2000. Trustee and Secretary of RAIT Investment Trust (a
publicly-traded real estate investment trust) since 1997. Vice Chairman of RAIT
since 2003. Chairman of the Board of The Richardson Company (a sales consulting
company) since 1999. 2002 2006
JOHN S. WHITE, 64, Senior Vice President of Royal Alliance Associates,
Inc. (an independent broker/dealer) since 2002. Chief Executive Officer and
President of DCC Securities Corporation (a securities brokerage firm) from 1989
to 2002. 1993 2006
ANDREW M. LUBIN, 58, President, Delaware Financial Group, Inc. (a
private investment firm), since 1990. 1994 2007
P. SHERRILL NEFF, 53, Founder and Managing Partner of Quaker
BioVentures, Inc. (a life sciences venture fund) since 2002. President and Chief
Financial Officer of Neose Technologies, Inc. (a publicly-traded life sciences
company) from 1994 to 2002. Director of Neose Technologies, Inc. from 1994 to
2003. 1998 2007
128
NON-DIRECTOR EXECUTIVE OFFICERS
The Board of Directors appoints officers each year at its annual
meeting following the annual stockholders meeting and from time to time as
necessary.
STEVEN J. KESSLER, 61, Senior Vice President and Chief Financial
Officer since 1997. Vice President-Finance and Acquisitions at Kravco Company (a
national shopping center developer and operator) from 1994 to 1997. Trustee of
GMH Communities Trust (a publicly traded specialty housing real estate
investment trust) since 2004.
ALAN F. FELDMAN, 41, Senior Vice President since 2002. President of
Resource Properties, Inc. (a wholly-owned real estate subsidiary) since 2002.
Vice President at Lazard Freres & Co. (an investment bank) from 1998 to 2002.
Executive Vice President at PREIT-Rubin, Inc., the management subsidiary of
Pennsylvania Real Estate Investment Trust (a publicly-traded real estate
investment trust) and its predecessor, The Rubin Organization, from 1992 to
1998.
OTHER SIGNIFICANT EMPLOYEES
The following sets forth certain information regarding other
significant employees:
DAVID E. BLOOM, 40, Senior Vice President since 2001. President of
Resource Capital Partners, Inc. (a wholly-owned real estate subsidiary) since
2002. President of Resource Properties from 2001 to 2002. Senior Vice President
at Colony Capital, LLC (an international real estate opportunity fund) from 1999
to 2001. Director at Sonnenblick-Goldman Company (a real estate investment bank)
from 1998 to 1999. Attorney at Willkie Farr & Gallagher (an international law
firm) from 1996 to 1998.
CRIT S. DEMENT, 52, Chairman and Chief Executive Officer of LEAF
Financial (a wholly-owned equipment leasing subsidiary) since 2001. President of
the Technology Finance Group of CitiCapital Vendor Finance in 2001. President of
the Small Ticket Group of European American Bank, a division of ABN AMRO, from
2000 to 2001. President and Chief Operating Officer of Fidelity Leasing, Inc. (a
former wholly-owned subsidiary) from 1996 to 2000.
MICHAEL S. YECIES, 37, Vice President, Chief Legal Officer and
Secretary since 1998. Attorney at Duane Morris LLP (an international law firm)
from 1994 to 1998.
INFORMATION CONCERNING THE AUDIT COMMITTEE
Our Board of Directors has a standing Audit Committee. All of the
members of the Audit Committee are independent directors as defined by Nasdaq
National Market rules. The Board of Directors has determined that Mr. Neff is an
"audit committee financial expert" as defined by SEC rules. The Audit Committee
reviews the scope and effectiveness of audits by the independent accountants, is
responsible for the engagement of independent accountants, and reviews the
adequacy of the Company's internal controls. The Committee held four meetings
during fiscal 2004. Members of the Committee are Messrs. Lubin (Chairman), Neff
and Campbell.
129
CODE OF ETHICS
We have adopted a code of business conduct and ethics applicable to all
directors, officers and employees. We will provide to any person without charge,
upon request, a copy of our code of conduct. Any such request should be
directed to us as follows: Resource America, Inc., 1845 Walnut Street, Suite
1000, Philadelphia, PA 19103, Attention: Secretary.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires our
officers, directors and persons who own more than ten percent of a registered
class of our equity securities to file reports of ownership and changes in
ownership with the SEC and to furnish us with copies of all such reports.
Based solely on our review of the reports received by us, or written
representations from certain reporting persons that no filings were required for
those persons, we believe that, during fiscal year 2004, our officers, directors
and greater than ten percent stockholders complied with all applicable filing
requirements, except that one Form 4 with respect to one option exercise was
inadvertently filed late by Nancy McGurk, a former executive officer.
ITEM 11. EXECUTIVE COMPENSATION
EXECUTIVE OFFICER COMPENSATION
The following tables set forth certain information concerning the
compensation paid or accrued during each of the last three fiscal years for our
Chief Executive Officer and each of our four other most highly compensated
executive officers whose aggregate salary and bonus (including amounts of salary
and bonus foregone to receive non-cash compensation) exceeded $100,000.
130
SUMMARY COMPENSATION TABLE
Annual Compensation Long Term Compensation
------------------------------- -------------------------
Awards
-------------------------
Restricted Securities All Other
Fiscal Stock Underlying Compen-
Name and Principal Position Year Salary Bonus(1) Other Awards(2) Options sation(3)
- --------------------------- ------ ------ -------- -------- ---------- ---------- ----------
Edward E. Cohen 2004 $523,077 $600,000 $ 0 $299,265 0 $2,681,846
Chairman, Chief 2003 600,000 400,000 0 1,154 0 318,769
Executive Officer (4) 2002 600,000 500,000 0 797 150,000 1,108,692
Jonathan Z. Cohen 2004 457,692 400,000 0 1,900 0 564,631
President, Chief 2003 350,000 300,000 0 1,154 0 4,990
Executive Officer (4) 2002 335,385 200,000 0 797 150,000 9,846
Steven J. Kessler 2004 300,000 235,000 0 1,963 0 45,260
Senior Vice President & 2003 300,000 150,000 0 1,154 0 6,000
Chief Financial Officer 2002 300,000 150,000 0 797 30,000 11,000
Freddie M. Kotek 2004 267,500 250,000 0 53,377 0 6,500
Senior Vice President (4) 2003 250,000 200,000 0 1,154 0 6,000
2002 248,677 150,000 0 797 30,000 11,000
Alan F. Feldman 2004 317,500 150,000 0 1,900 0 0
Senior Vice President 2003 300,000 100,000 0 0 0 0
2002(5) 36,923 100,000 50,000 0 200,000 0
- -------------
(1) Bonuses in any fiscal year are generally based upon our performance in
the prior fiscal year and the individual's contribution to that
performance. From time to time, we may award bonuses in a fiscal year
reflecting an individual's performance during that fiscal year.
(2) Reflects allocations of shares to employee accounts that were made in
fiscal 2004 under our 1989 Employee Stock Ownership Plan ("ESOP") to
reconcile shares held to shares which should have been allocated to those
accounts in prior years. Share allocations under the ESOP have been
valued at the closing price of our common stock at September 30, 2004,
2003 and 2002, respectively. For purposes of this table, all ESOP shares
are assumed to be fully vested. Mr. E. Cohen was fully vested as of
September 30, 1997. Mr. Kotek was fully vested as of September 30, 2000.
Messrs. J. Cohen and Kessler were fully vested as of September 30, 2004.
Mr. Feldman was not vested as of September 30, 2004. At September 30,
2004, the number of restricted shares held and the value of those
restricted shares (in the aggregate, and valued at the closing market
price of our common stock on the dates of the respective grants) are: Mr.
E. Cohen - 73,683 shares ($424,773); Mr. J. Cohen - 588 shares ($6,416);
Mr. Kessler - 618 shares ($6,687); and Mr. Kotek - 18,431 shares
($110,736). Cash dividends, as and when authorized by our Board of
Directors, have been and will continue to be paid to the ESOP on the
restricted shares.
(3) Reflects matching payments we made under the 401(k) Plan and grants in
2004 of phantom units under the Atlas Pipeline Long Term Incentive Plan.
The amounts set forth for Mr. E. Cohen in fiscal 2004, 2003 and 2002 also
include (i) $1,501,000, $314,500 and $1,100,000, respectively, of accrued
obligations under a Supplemental Employment Retirement Plan established
by us in March 1997 in connection with the employment agreement between
Mr. E. Cohen and the Company and (ii) a $254,000 payment to Mr. E. Cohen
in fiscal 2004 in connection with his Supplemental Employment Retirement
Plan. See "Employment Agreements." The phantom unit grants under the
Atlas Pipeline Long Term Incentive Plan entitle the recipient, upon
vesting, to receive one common unit or its then fair market value in cash
and include distribution equivalent rights. The number of phantom units
held and the value of those phantom units, valued at the closing market
price of Atlas Pipeline common units on the date of the grant, are: Mr.
E. Cohen - 25,000 phantom units ($931,500); Mr. J. Cohen - 15,000 phantom
units ($558,900); and Mr. Kessler - 1,000 phantom units ($37,260).
(4) Mr. E. Cohen was our Chief Executive Officer until his retirement in May
2004 in connection with Atlas America's initial public offering. Mr. J.
Cohen became our Chief Executive Officer immediately following Mr. E.
Cohen's retirement. Mr. Kotek was an executive officer until May 2004,
and he currently is an executive officer of Atlas America.
(5) Mr. Feldman's salary in 2002 is for the partial fiscal year period from
the inception of his employment with us on August 1, 2002 through
September 30, 2002. The salary reported for fiscal 2002 was based on an
annual salary rate of $300,000 for fiscal 2002. Mr. Feldman's bonus in
fiscal 2002 was a signing bonus associated with the inception of his
employment. Mr. Feldman's other compensation in fiscal 2002 was a
relocation expense reimbursement.
131
OPTION/SAR GRANTS AND EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION
VALUES
We did not grant any stock options or stock appreciation rights to the
named executive officers in fiscal 2004.
The following table sets forth the aggregated option exercises during
fiscal 2004, together with the number of unexercised options and their value on
September 30, 2004, held by the executive officers listed in the Summary
Compensation Table. No stock appreciation rights were exercised or held by the
named executive officers in fiscal 2004.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES
Number of
Securities Underlying
Unexercised Value of Unexercised
Shares Options at FY-End In-the-Money Options at
Acquired Exercisable/ FY-End Exercisable/
Name On Exercise Value Realized Unexercisable Unexercisable(1)
- ---- ----------- -------------- ------------- ----------------
Edward E. Cohen 0 $ 0 450,000/0 $5,252,700/$0
Jonathan Z. Cohen 0 0 458,750/86,250 $6,047,137/$1,331,929
Steven J. Kessler 0 0 62,500/22,500 $722,307/$332,152
Freddie M. Kotek 0 0 76,995/22,500 $1,216,243/$332,152
Alan F. Feldman 0 0 100,000/100,000 $1,425,000/$1,425,000
- -----------------
(1) Value is calculated by subtracting the total exercise price from the fair
market value of the securities underlying the options at September 30, 2004.
EMPLOYMENT AGREEMENTS
Edward E. Cohen served as our Chairman of the Board of Directors and
Chief Executive Officer until completion of the initial public offering of Atlas
America in May 2004. Upon completion of the offering, Mr. Cohen retired as our
Chief Executive Officer and became the Chief Executive Officer of Atlas America
and entered into an employment agreement with Atlas America.
Under the employment agreement between us and Mr. Cohen, as a result of
Mr. Cohen's retirement Mr. Cohen became entitled to termination benefits of 25%
of an amount equal to:
o five times Average Compensation (defined as the average of the
annual total compensation received by Mr. Cohen in the three most
highly compensated years during the previous nine years of
employment), payable over 36 months, plus
o to the extent Mr. Cohen has not received 120 months of
Supplemental Employment Retirement Plan ("SERP") benefits, the
balance thereof.
In the event that the foregoing benefits become subject to any excise
tax imposed under Section 4999 of the Internal Revenue Code of 1986 (the
"Code"), we must pay Mr. Cohen an additional sum such that the net amounts
retained by Mr. Cohen, after payment of excise, income and withholding taxes,
shall equal Total Benefits.
As required by the agreement, we had also established a SERP for Mr.
Cohen's benefit which pays Mr. Cohen a monthly retirement benefit equal to 75%
of his Average Compensation, less any amounts payable under any of our other
retirement plans in which Mr. Cohen participates. In June 2004, the SERP
commenced payment to Mr. Cohen and paid him $254,000 in connection with his
retirement. In each of 1999 and 2000, we established a trust to fund the SERP.
The 1999 Trust purchased 100,000 shares of common stock of The Bancorp, Inc. See
"Item 13. Certain Relationships and Related Party Transactions." The 2000 Trust
holds 45,889 shares of convertible preferred stock of The Bancorp, Inc. and a
loan to a limited partnership of which Mr. Cohen and Daniel Cohen, a son of Mr.
Cohen and a former officer and director, 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 Mr. Cohen was the Chairman and Jonathan Cohen
was the President. In addition, the 2000 Trust invested $1.0 million in
Financial Securities Fund, an investment partnership which is managed by a
corporation of which Daniel Cohen is the principal shareholder and a director.
The fair value of the 1999 Trust was approximately $1.4 million at September 30,
2004. This trust and its assets are not included in our consolidated balance
sheet. However, its assets are considered in determining the amount of our
liability under the SERP.
132
The carrying value of the assets in the 2000 Trust is approximately
$3.7 million at September 30, 2004 and, because it is a "Rabbi Trust," its
assets are included in Other Assets in our consolidated balance sheets and our
liability under the SERP has not been reduced by the value of those assets.
Jonathan Z. Cohen currently serves as our Chief Executive Officer,
President and a director under an employment agreement dated October 5, 1999.
The agreement requires Mr. Cohen to devote as much of his business time to us as
necessary to the fulfillment of his duties, although it permits him to have
outside business interests. The agreement provides for initial base compensation
of $200,000 per year, which may be increased by the Compensation Committee of
the Board based upon its evaluation of Mr. Cohen's performance. Mr. Cohen is
eligible to receive incentive bonuses and stock option grants in amounts to be
determined by the Board and to participate in all employee benefit plans in
effect during his period of employment.
The agreement has a term of three years and, until notice to the
contrary, the term is automatically extended so that, on any day on which the
agreement is in effect, it has a then-current three year term. The agreement can
be sooner terminated in the event of Mr. Cohen's disability extending for more
than 240 days or death. Mr. Cohen also has the right to terminate the agreement
upon a change in control or potential change in control and for cause.
Otherwise, Mr. Cohen can terminate the agreement upon 180 days' notice.
The agreement provides the following termination benefits: (i) upon
termination due to death, Mr. Cohen's estate will receive an amount equal to
three times Average Compensation (defined as the average of the annual total
compensation received by Mr. Cohen in the three most highly compensated years
during the previous nine years of employment) (payable over 36 months); (ii)
upon termination due to disability, Mr. Cohen will receive a monthly benefit
equal to one-twelfth of the product of (a) Average Compensation and (b) 75%; and
(iii) upon termination by Mr. Cohen for cause, or upon a change in control or
potential change in control, an amount equal to three times Average Compensation
plus continuation of life, health, accident and disability insurance benefits
for a period of 36 months. In the event that any amounts payable to Mr. Cohen
pursuant to items (i) through (iii), above, which we refer to as Total Benefits,
become subject to any excise tax imposed under Section 4999, we must pay Mr.
Cohen an additional sum such that the net amounts retained by Mr. Cohen, after
payment of excise, income and withholding taxes, shall equal Total Benefits.
The terms of our employment agreement with Steven J. Kessler as of
October 1999 are substantially similar to the terms of our employment agreement
with Mr. J. Cohen, described above, except as follows: Mr. Kessler currently
serves as Senior Vice President and Chief Financial Officer, Mr. Kessler's
initial base compensation is $300,000 per year; Mr. Kessler is not expressly
permitted to have outside business interests; and Mr. Kessler does not have the
right to terminate the agreement upon a potential change in control of the
company.
133
DIRECTOR COMPENSATION
Each of our independent directors receives a retainer of $35,000 per
year.
Each of our independent directors is eligible to participate in our
2002 Non-Employee Director Deferred Stock and Deferred Compensation Plan. Under
the 2002 Plan, non-employee directors are awarded units representing the right
to receive one share of our common stock for each unit awarded. Upon becoming a
director, each independent director receives units equal to $15,000 divided by
the closing price of our common stock on the date of grant. Independent
directors receive an additional unit award equal to $15,000 divided by the
closing price of our common stock on the date of grant on each anniversary of
the date of initial grant. Units vest on the later of: (i) the fifth anniversary
of the date the recipient became a director and (ii) the first anniversary of
the grant of those units, except that units will vest sooner upon a change in
control or death or disability of the recipient provided that he or she
completed at least six months of service. Upon termination of service, vested
units will become issued common stock, but all unvested units are forfeited. The
2002 Plan provides for the issuance of a maximum of 75,000 units and terminates
on April 29, 2012, except with respect to previously awarded grants. As of the
date of this annual report, we have four independent directors. 15,888 units
have been awarded to such directors.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Compensation Committee of the Board of Directors consists of
Messrs. Campbell, Neff and White. None of such persons was an officer or
employee of ours or any of our subsidiaries during fiscal 2004 or was formerly
an officer of ours or any of our subsidiaries. None of our executive officers
has been a director or executive officer of any entity of which any member of
the Compensation Committee has been a director or executive officer during
fiscal year 2004.
134
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the number and percentage of shares of
common stock owned, as of December 1, 2004, by (a) each person who, to our
knowledge, is the beneficial owner of more than 5% of the outstanding shares of
common stock, (b) each of our present directors, (c) each of the executive
officers named in the Summary Compensation Table in Item 11, and (d) all of the
named executive officers and directors as a group. This information is reported
in accordance with the beneficial ownership rules of the Securities and Exchange
Commission under which a person is deemed to be the beneficial owner of a
security if that person has or shares voting power or investment power with
respect to such security or has the right to acquire such ownership within 60
days. Shares of common stock issuable pursuant to options or warrants are deemed
to be outstanding for purposes of computing the percentage of the person or
group holding such options or warrants but are not deemed to be outstanding for
purposes of computing the percentage of any other person. Unless otherwise
indicated in footnotes to the table, each person listed has sole voting and
dispositive power with respect to the securities owned by such person.
Common Stock
------------------------------
Amount and Nature of Percent of
BENEFICIAL OWNER Beneficial Ownership Class
------------------------------ ----------
DIRECTORS(16)
- -------------
Carlos Campbell........................................................ 18,663 (1)(2) *
Edward E. Cohen........................................................ 1,950,241 (3)(4)(7)(8)(9)(10) 10.86%
Jonathan Z. Cohen...................................................... 574,375 (3)(4)(6)(7)(8)(11) 3.20%
Andrew M. Lubin........................................................ 19,023 (1)(2) *
P. Sherrill Neff....................................................... 15,183 (1)(2) *
John S. White.......................................................... 19,183 (1)(2) *
NON-DIRECTOR EXECUTIVE OFFICERS(16)
- -----------------------------------
Steven J. Kessler...................................................... 133,236 (3)(4)(7)(8) *
Freddie M. Kotek....................................................... 154,485 (3)(4)(5)(7)(8) *
Alan F. Feldman........................................................ 100,081 (3)(7)(8) *
All named executive officers and directors as a group (9 persons)...... 2,938,220 (1)(2)(3)(4)(5)(6)(7)(8)(9)(10) 15.67%
OTHER OWNERS OF MORE THAN
5% OF OUTSTANDING SHARES
- ------------------------
Cobalt Capital Management, Inc. (12)................................... 1,493,907 8.53%
Dimensional Fund Advisors, Inc. (13)................................... 1,479,615 8.45%
Omega Advisors, Inc. (14).............................................. 973,600 5.56%
James C. Eigel (15).................................................... 963,124 5.50%
- --------------
* Less than 1%
(1) Includes vested units representing the right to receive one share of common
stock per unit granted under the 1997 Non-Employee Directors Deferred Stock
and Deferred Compensation Plan in the following amounts: Mr. Campbell -
15,000 units; Mr. Lubin - 15,000 units; Mr. Neff - 12,000 units; and Mr.
White - 15,000 units.
(2) Includes vested units representing the right to receive one share of common
stock per unit granted under the 2002 Non-Employee Directors Deferred Stock
and Deferred Compensation Plan in the following amounts: Mr. Campbell -
3,183 units; Mr. Lubin - 3,183 units; Mr. Neff - 3,183 units; and Mr. White
- 3,183 units.
(3) Includes shares allocated under the Employee Stock Ownership Plan in the
following amounts: Mr. E. Cohen - 73,683 shares; Mr. J. Cohen - 588 shares;
Mr. Feldman - 81 shares; Mr. Kessler - 618 shares; and Mr. Kotek - 18,431
shares, as to which each has voting power.
(4) Includes shares allocated under the Investment Savings Plan, or 401(k) plan,
in the following amounts: Mr. E. Cohen - 20,105 shares; Mr. J. Cohen -
12,537 shares; Mr. Kessler - 13,102 shares; and Mr. Kotek - 19,076 shares,
as to which each has voting power.
(5) Includes 29,495 shares issuable on exercise of options granted under the
1989 Key Employee Stock Option Plan.
(6) Includes 93,885 shares issuable on exercise of options granted under the
1997 Key Employee Stock Option Plan.
135
(7) Includes shares issuable on exercise of options granted under the 1999 Key
Employee Stock Option Plan in the following amounts: Mr. E. Cohen - 300,000
shares; Mr. J. Cohen - 301,115 shares; Mr. Feldman - 13,266 shares; Mr.
Kessler - 55,000 shares; and Mr. Kotek - 40,000 shares.
(8) Includes shares issuable on exercise of options granted under the 2002 Key
Employee Stock Option Plan in the following amounts: Mr. E. Cohen - 150,000
shares; Mr. J. Cohen - 75,000 shares; Mr. Feldman - 86,734 shares; Mr.
Kessler - 15,000 shares; and Mr. Kotek - 15,000 shares.
(9) Includes 449,516 shares held by a private charitable foundation of which
Mr. E. Cohen serves as a co-trustee. Mr. E. Cohen disclaims beneficial
ownership of these shares.
(10) Includes 92,500 shares held in trusts for the benefit of Mr. E. Cohen's
spouse and/or children. Mr. E. Cohen disclaims beneficial ownership of
these shares.
(11) Includes 46,250 shares held in a trust of which Mr. J. Cohen is a
co-trustee and co-beneficiary. These shares are also included in the shares
referred to in footnote 10 above.
(12) This information is based on Form 13F filed with the SEC reporting security
ownership position as of September 30, 2004. The address for Cobalt Capital
Management, Inc. is 237 Park Avenue, Suite 801, New York, New York 10017.
(13) This information is based on Form 13F filed with the SEC reporting security
ownership position as of September 30, 2004. The address for Dimensional
Fund Advisors Inc. is 1299 Ocean Avenue, 11th Floor, Santa Monica,
California 90401.
(14) This information is based on Form 13F filed with the SEC reporting security
ownership position as of September 30, 2004. The address for Omega
Advisors, Inc. is 88 Pine Street, Wall Street Plaza, 31st Floor, New York,
New York 10005.
(15) This information is based on Schedule 13G/A filed with the SEC reporting
security ownership position as of December 31, 2003. Includes shares held
by nominees. Mr. Eigel's address is 1201 Edgecliff Place, Cincinnati, Ohio
45206.
(16) The address for all our directors and officers is 1845 Walnut Street, Suite
1000, Philadelphia, Pennsylvania 19103.
EQUITY COMPENSATION PLAN INFORMATION
The following table summarizes certain information about our
compensation plans, in the aggregate, as of September 30, 2004.
- --------------------------------------------------------------------------------------------------------------------
NUMBER OF SECURITIES REMAINING
NUMBER OF SECURITIES TO WEIGHTED-AVERAGE EXERCISE AVAILABLE FOR FUTURE ISSUANCE
BE ISSUED UPON EXERCISE PRICE OF OUTSTANDING UNDER EQUITY COMPENSATION PLANS
OF OUTSTANDING OPTIONS, OPTIONS, WARRANTS AND (EXCLUDING SECURITIES REFLECTED
PLAN CATEGORY WARRANTS AND RIGHTS RIGHTS IN COLUMN (A))
- --------------------------------------------------------------------------------------------------------------------
(A) (B) (C)
- --------------------------------------------------------------------------------------------------------------------
Equity compensation
plans approved by
security holders 1,836,383 $ 10.01 282,339
136
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In the ordinary course of our business operations, we have ongoing
relationships with several related entities:
Relationship with Equipment Leasing Partnerships. In fiscal 2004 we
received fees from investment partnerships in which we were the general partner
of $2.2 million. In March 2004, we acquired $3.7 million of leases at book value
from certain of these equipment leasing investment partnerships which were
liquidated in 2004.
Relationship with Real Estate Investment Partnerships. In fiscal 2004,
we received fees from real estate investment partnerships in which we were the
general partner of $1.5 million.
Relationship with RAIT. RAIT is a real estate investment trust that we
organized in 1997 and in which we held, as of September 30, 2004, less than 1%
of the outstanding common shares of beneficial interest. Betsy Z. Cohen, Edward
E. Cohen's spouse and our Chairman of the board, is Chief Executive Officer of
RAIT, and Jonathan Z. Cohen, a son of E. and B. Cohen and our President and
Chief Executive Officer and a director, is an officer and a trustee. Scott F.
Schaeffer, a former officer and director, is RAIT's President and Chief
Operating Officer.
In December 2003, RAIT provided us a standby commitment to provide
$10.0 million in bridge financing in connection with the retirement of our
senior debt. RAIT received a $100,000 facilitation fee from us in connection
with providing this standby commitment. On January 15, 2004, we borrowed the
$10.0 million from RAIT and, on January 21, 2004, we repaid RAIT in full.
Relationship with The Bancorp, Inc. We own 8.9% of the outstanding
common stock of The Bancorp, Inc. In 2001, we acquired 70,400 shares of The
Bancorp's convertible preferred stock (7.5%) for approximately $704,000 pursuant
to a rights offering to the Bancorp's stockholders. B. Cohen and D. Cohen are
officers and directors of The Bancorp. D. Cohen, a son of E. and B. Cohen, is a
former officer and director of ours.
Relationship with Certain Borrowers. We have from time to time
purchased loans in which our affiliates were or have become affiliates of the
borrowers.
In 2002, D. Cohen acquired beneficial ownership of a property on which
we had held a loan interest since 1998. In fiscal 2004, the loan was sold to an
affiliate of D. Cohen for $5.4 million and we recognized a gain of $100,000.
In 2000, to protect our interest, the property securing a loan that we
had held since 1997 was purchased by a limited partnership owned in equal parts
by Messrs. Schaeffer, Adam Kauffman, E. Cohen and D. Cohen. In September 2003,
in furtherance of its position, we foreclosed on the property. In 2004, the
property was sold for $5.0 million and we recognized a gain of $824,000, which
is recorded in discontinued operations.
In October 2003, we recapitalized a loan we acquired in 1998 under a
plan of reorganization in bankruptcy for a cost of $95.6 million. At the time of
such acquisition, an order of the bankruptcy court required that legal title to
the property underlying the loan be transferred. To comply with that order, to
maintain control of the property and to protect our interest, an entity whose
general partner is a subsidiary of ours and whose limited partners are Messrs.
Schaeffer, D. Cohen and E. Cohen (with a 94% aggregate beneficial interest)
assumed title to the property. As part of the recapitalization, Messrs. E. Cohen
and Schaeffer transferred all of their interests to an unrelated third party and
Mr. D. Cohen transferred 16.3% of his 31.3% interest to such third party. They
received no consideration from the unrelated third party; however, in
consideration for them agreeing to the recapitalization of the loan, we agreed
to reimburse them the amount that they had paid to us in 1998 for the interests
transferred. Such payment was $200,000 in the aggregate.
137
In October 2003, a FIN 46 entity's asset underlying one of our loans
was sold to an entity of which D. Cohen is a shareholder; such entity was the
highest bidder for the property and we received $6.6 million in cash and
recognized a gain of $78,000. Prior to such sale, the FIN 46 entity's asset had
been owned by a partnership in which Messrs. E. Cohen, D. Cohen and Mrs. B.
Cohen were limited partners.
In 2004, we sold a loan to an affiliate of D. Cohen for $900,000 and
realized a loss of $124,000.
Relationship with Brandywine Construction & Management, Inc. Brandywine
manages the properties underlying eleven of our real estate loans, real property
interests and FIN 46 assets. Mr. Kauffman, President of Brandywine, or an entity
affiliated with him, also acts as the general partner, president or trustee of
six of the borrowers. E. Cohen, our Chairman, is the Chairman of Brandywine and
holds approximately 8% of its common stock.
Relationships with Lienholder. In 1997, we acquired a first mortgage
lien with a face amount of $14.0 million and a book value of $4.5 million on a
hotel property owned by a corporation in which, on a fully diluted basis, J.
Cohen and E. Cohen would have a 19% interest. The corporation acquired the
property through foreclosure of a subordinate loan. In May 2003, we acquired
this property through further foreclosures proceedings and recorded write-downs
of $2.7 million. In August 2004, we listed the property for sale and recorded a
further write-down of $882,000.
Relationship with Ledgewood Law Firm. Until April 1996, E. Cohen was of
counsel to Ledgewood. We paid Ledgewood $1.7 million during fiscal 2004 for
legal services. 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. E. Cohen is entitled to receive
payments from his SERP. See "Employment Agreements."
Relationship with 9 Henmar. We own interests in entities involved as
managers and holders of the equity interests in the Trapeza series of CDO
issuers, which we describe in Item 1 "Business-Structured Finance." The Trapeza
entities and CDO Issuers were originated and developed in large part by D.
Cohen. We have agreed to pay his company, 9 Henmar LLC, 10% of the fees we
receive in connection with the first four Trapeza CDOs. In fiscal 2004, we paid
9 Henmar $325,700 in such fees.
138
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
AUDIT FEES
The aggregate fees billed by our independent auditors, Grant Thornton
LLP, for professional services rendered for the audit of our annual financial
statements for the fiscal years ended September 30, 2004 and 2003 and for the
reviews of the financial statements included in our Quarterly Reports on Form
10-Q during such fiscal years were $607,100 and $754,700, respectively.
AUDIT-RELATED FEES
The aggregate fees billed by Grant Thornton for audit-related services
were $108,400 and $296,6000 for the fiscal years ended September 30, 2004 and
2003, respectively.
TAX FEES
The aggregate fees billed by Grant Thornton for professional services
related to tax compliance, tax advice and tax planning were $76,900 and $49,500
in the fiscal years ended September 30, 2004 and 2003, respectively.
ALL OTHER FEES
The aggregate fees billed by Grant Thornton for products and services
provided to us, other than services described above under "Audit Fees,"
"Audited-Related Fees" and "Tax Fees" for the fiscal years ended September 30,
2004 and 2003 were $0 and $0, respectively.
AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES
The Audit Committee, on at least an annual basis, reviews audit and
non-audit services performed by Grant Thornton, LLP as well as the fees charged
by Grant Thornton, LLP for such services. Our policy is that all audit and
non-audit services must be pre-approved by the Audit Committee. All of such
services and fees were pre-approved during fiscal 2004.
139
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this Annual Report on
Form 10-K:
1. FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at September 30, 2004 and 2003
Consolidated Statements of Operations for the years ended September
30, 2004, 2003 and 2002
Consolidated Statements of Comprehensive Income (Loss) for the years
ended September 30, 2004, 2003 and 2002
Consolidated Statements of Changes in Stockholders' Equity for the
years ended September 30, 2004, 2003 and 2002
Consolidated Statements of Cash Flows for the years ended September
30, 2004, 2003 and 2002
Notes to Consolidated Financial Statements - September 30, 2004
2. FINANCIAL STATEMENT SCHEDULES
Schedule I - Condensed Financial Information of the Registrant
Schedule III - Investments in Real Estate
Schedule IV - Investments in Mortgage Loans on Real Estate
3. EXHIBITS
Exhibit No. Description
----------- -----------
3.1 Restated Certificate of Incorporation of Resource
America. (1)
3.2 Amended and Restated Bylaws of Resource America. (1)
10.1 Master Separation and Distribution Agreement between
Atlas America, Inc. and Resource America, Inc. dated
May 14, 2004. (2)
10.2 Registration Rights Agreement between Atlas America,
Inc. and Resource America, Inc. dated May 14, 2004.
(2)
10.3 Tax Matters Agreement between Atlas America, Inc. and
Resource America, Inc. dated May 14, 2004. (2)
10.4 Transition Services Agreement between Atlas America,
Inc. and Resource America, Inc. dated May 14, 2004.
(2)
10.5 Employment Agreement for Edward E. Cohen dated May
14, 2004. (2)
10.6 Revolving Credit Agreement and Assignment dated as of
May 27, 2004 among Lease Equity Appreciation Fund I,
L.P., LEAF Financial Corporation and Sovereign Bank.
(2)
10.7 Securities Purchase Agreement dated June 10, 2004
among Atlas Pipeline Operating Partnership, L.P.,
Spectrum Field Services, Inc. et al. (3)
10.8 Third Amendment to Revolving Credit Agreement and
Assignment dated June 18, 2004 among LEAF Financial
Corporation, LEAF Funding, Inc. and Commerce Bank,
National Association. (2)
10.8(a) First Amendment to Guaranty of Payment dated June 19,
2004 between Resource America, Inc. and Commerce
Bank, National Association. (2)
10.9 Sixth Amendment to Revolving Credit Agreement and
Assignment dated June 30, 2004 among LEAF Financial
Corporation, LEAF Funding, Inc. and National City
Bank. (2)
10.9(a) First Amendment to Guaranty of Payment dated June 20,
2004 between Resource America, Inc. and National City
Bank. (2)
10.10 Credit Agreement among Atlas America, Inc., Resource
America, Inc., Wachovia Bank, National Association
and the other parties thereto dated March 12, 2004.
10.10(a) First Amendment to Credit Agreement dated July 10,
2004.
10.10(b) Second Amendment to Credit Agreement dated September
10, 2004.
140
10.11 Credit Agreement dated July 16, 2004 among Atlas
Pipeline Partners, L.P., Wachovia Bank, National
Association et al. (2)
21.1 Subsidiaries of Resource America
23.0 Consent of Wright & Company, Inc.
31.1 Rule 13a-14(a)/15d-14(a) Certification
31.2 Rule 13a-14(a)/15d-14(a) Certification
32.1 Section 1350 Certification
32.2 Section 1350 Certification
Reports on Form 8-K
Item 5, dated July 1, 2004, filed July 1, 2004.
Item 2 and 7, dated July 16, 2004, filed August 2, 2004.
Item 9.01, dated July 16, 2004, filed September 7, 2004,
including
o The balance sheets of Spectrum Field Services, Inc. as
of December 31, 2003 and 2002, the related statements
of operations, comprehensive income (loss), changes in
shareholders' equity and cash flows for each of the
three years in the period ended December 31, 2003 and
the related notes, together with the report of the
independent registered public accounting firm.
o The unaudited pro forma balance sheet of Resource
America, Inc. as of March 31, 2004, the related
statements of operations for the year ended September
30, 2003 and the six months ended March 31, 2004 and
the related notes.
- ----------------
(1) Filed previously as an exhibit to our Quarterly Report on Form 10-Q for the
quarter ended December 31, 1999 and by this reference incorporated herein.
(2) Filed previously as an exhibit to our Quarterly Report on Form 10-Q for the
quarter ended June 30, 2004 and by this reference incorporated herein.
(3) Filed previously as an exhibit to our Current Report on Form 8-K filed
August 2, 2004 and by this reference incorporated herein.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
RESOURCE AMERICA, INC. (Registrant)
December 13, 2004 By: /s/ Jonathan Z. Cohen
-------------------------------------
Chief Executive Officer and President
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/ Edward E. Cohen Chairman of the Board December 13, 2004
- -----------------------
EDWARD E. COHEN
/s/ Jonathan Z. Cohen Director, President December 13, 2004
- ----------------------- and Chief Executive Officer
JONATHAN Z. COHEN
/s/ Carlos C. Campbell Director December 13, 2004
- -----------------------
CARLOS C. CAMPBELL
/s/ Andrew M. Lubin Director December 13, 2004
- -----------------------
ANDREW M. LUBIN
/s/ P. Sherrill Neff Director December 13, 2004
- -----------------------
P. SHERRILL NEFF
/s/ John S. White Director December 13, 2004
- -----------------------
JOHN S. WHITE
/s/ Steven J. Kessler Senior Vice President December 13, 2004
- ----------------------- and Chief Financial Officer
STEVEN J. KESSLER
142