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: 333-112653
ATLAS AMERICA, INC.
-------------------
(Exact name of registrant as specified in its charter)
DELAWARE 51-0404430
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or
organization)
311 ROUSER ROAD 15108
MOON TOWNSHIP, PA Zip Code
(Address of principal executive offices)
Registrant's telephone number, including area code: 412-262-2830
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 Exchange Act Rule 12b-2) of the Act. Yes [ ] No [X]
The aggregate market value of the voting common stock 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 $0 since prior to May 10, 2004 the registrant was a wholly-owned
subsidiary.
The number of outstanding shares of the registrant's common stock on December 1,
2004 was 13,333,333 shares.
DOCUMENTS INCORPORATED BY REFERENCE
[None]
[THIS PAGE INTENTIONALLY LEFT BLANK]
ATLAS AMERICA, INC. AND SUBSIDIARIES
INDEX TO ANNUAL REPORT
ON FORM 10-K
PART I Page
Item 1: Business.................................................................... 3 - 22
Item 2: Properties.................................................................. 23 - 26
Item 3: Legal Proceedings........................................................... 27
Item 4: Submission of Matters to a Vote of Security Holders......................... 27
PART II
Item 5: Market for Registrant's Common Equity and Related Stockholder Matters
and Issuer Purchases of Equity Securities................................ 28
Item 6: Selected Financial Data..................................................... 29 - 30
Item 7: Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................................... 31 - 43
Item 7A: Quantitative and Qualitative Disclosures About Market Risk.................. 44 - 47
Item 8: Financial Statements and Supplementary Data................................. 48 - 86
Item 9: Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure..................................................... 87
Item 9A: Controls and Procedures..................................................... 87
Item 9B: Other Information........................................................... 87
PART III
Item 10: Directors and Executive Officers of the Registrant.......................... 88 - 91
Item 11: Executive Compensation...................................................... 91 - 94
Item 12: Security Ownership of Certain Beneficial Owners and Management.............. 94 - 95
Item 13: Certain Relationships and Related Transactions.............................. 96 - 101
Item 14: Principal Accountant Fees and Services...................................... 102
PART IV
Item 15: Exhibits, Financial Statement Schedules and Reports on Form 8-K............. 103 - 104
SIGNATURES.................................................................................................. 105
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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. 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. 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 an energy company engaged primarily in the development and
production of natural gas and, to a lesser extent, oil in the western New York,
eastern Ohio and western Pennsylvania region of the Appalachian Basin for our
own account and for investors through the offering of tax-advantaged investment
programs. We have been involved in the energy industry since 1968. We began to
expand our operations at the end of fiscal 1998 when we acquired The Atlas
Group, Inc. and a year later when we acquired Viking Resources Corporation, both
energy finance and production companies. We also wholly-own Atlas Pipeline
Partners GP, LLC, the general partner of Atlas Pipeline Partners, L.P. (NYSE:
APL) which owns a 2% general partner interest and 1,641,026 subordinated units
constituting a 22% limited partner interest. Atlas Pipeline owns and operates
approximately 3,300 miles of natural gas pipelines in New York, Ohio, Oklahoma,
Pennsylvania and Texas and a gas processing facility in Oklahoma.
As of or during the year ended September 30, 2004:
o proved reserves net to our interest grew to 155.8 billion cubic
feet of natural gas equivalents, or bcfe, 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 we manage for our 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 we 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 we had, either directly or through our sponsored drilling
partnerships, interests in 5,755 gross wells, including royalty
and overriding royalty interests in 628 wells, as compared to
interests in 5,274 gross wells, including royalty and overriding
royalty interests in 601 wells, at September 30, 2003. We operate
approximately 84% of the wells in which we have interests;
o wells in which we had an interest produced, net to our interest,
approximately 19.9 million cubic feet, or mmcf, of natural gas and
495 barrels, or bbls, of oil per day during fiscal 2004, compared
to 19.1 mmcf of natural gas and 438 bbls of oil per day during the
year ended September 30, 2003;
o the number of wells we drilled, net to both our interest and that
of our sponsored drilling investment partnerships, increased to
450 wells in fiscal 2004 from 282 wells in fiscal 2003. We expect
to drill approximately 650 net wells in fiscal 2005; and
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o distributions we received from Atlas Pipeline increased from $4.2
million in fiscal 2003 to $5.6 million in fiscal 2004
Initial Public Offering. In May 2004, we completed an initial public
offering of 2,645,000 shares of our common stock at a price of $15.50 per common
share. The net proceeds of the offering of $37.0 million, after deducting
underwriting discounts, and costs were distributed to our parent, Resource
America, in the form of a non-taxable dividend. Following the offering, Resource
America continues to own 80.2% of our common stock.
Resource America has advised us that it intends to spin-off its
remaining ownership interest in us to its common stockholders by means of a
tax-free distribution. Resource America has sole discretion if and when to
complete the distribution and its terms, and does not intend to complete the
distribution unless it receives a ruling from the Internal Revenue Service
and/or an opinion from its tax counsel as to the tax-free nature of the
distribution to Resource America and its 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 Resource
America 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 Resource
America's sole discretion, we cannot assure you that the distribution will
occur.
For the proposed distribution of our stock owned by Resource America to
be tax-free to them, Resource America must, among other things, own at least 80%
of all of our voting power at the time of the distribution. Therefore, until
such time that Resource America completes the distribution or informs us that it
will not complete the distribution, we will be limited in our ability to issue
voting securities, non-voting stock or convertible debt without Resource
America's prior consent, and Resource America may be unwilling to give that
consent. In addition, agreements that we entered into with Resource America upon
the closing of our initial public offering prohibit us from making acquisitions
or entering into mergers or other business combinations that would jeopardize
the tax-free status of the distribution.
If the distribution occurs, its principal effects upon us and our
stockholders will be that:
o Resource America will no longer own any of our common stock and,
accordingly, will no longer be in a position to determine the
outcome of corporate actions requiring stockholder approval. These
actions, referred to in "--Risk Factors - Risks Relating to Our
Relationship with Resource America - Our principal stockholder is
in a position to affect our ongoing operations, corporate
transactions and other matters," will be passed upon by our
stockholders existing at the record dates for such matters.
Resource America's rights following the distribution will be
defined by the master separation and distribution agreement, the
tax matters agreement and the transition services agreement
discussed in Item 13: "Certain Relationships and Related
Transactions;"
o the restrictions on our ability to raise capital, dispose of
assets or enter into business combinations pending the
distribution, referred to in "--Risk Factors - Risks Relating to
Our Relationship with Resource America - Our agreements with
Resource America may limit our ability to obtain capital or make
acquisitions," will terminate; and
o the number of our publicly-traded shares will increase by
approximately 10.7 million shares which, we believe, will increase
the liquidity of our shares in public trading. However, sales of
substantial amounts of our common stock in the public markets or
the perception that they might occur could reduce the price our
common stock might otherwise obtain.
4
DRILLING ACTIVITIES
We fund our drilling activities through the sponsorship of drilling
investment partnerships. Although we have been raising capital through drilling
investment partnerships since 1968, the amount of the capital raised through
these partnerships has increased substantially since 1998; we 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). We act as the general
partner of our sponsored drilling investment partnerships and receive both an
interest proportionate to the amount of capital and the value of the properties
we contribute, 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 we undertake depends upon our ability to obtain investor
subscriptions to the partnerships. During fiscal 2004, 2003 and 2002, our
drilling investment partnerships invested $125.0 million, $68.6 million and
$75.5 million, respectively, in drilling and completing wells, of which we
contributed $31.9 million, $15.7 million and $19.7 million, respectively.
We generally structure our drilling investment partnerships so that,
upon formation of a partnership, we contribute leaseholds to it, enter into
drilling and well operating agreements with it and become its general or
managing partner. In addition to providing capital for our drilling activities,
our drilling investment partnerships are a source of fee-based revenue. We drill
all of the partnership wells under "cost plus" contracts for which we are paid
the costs of drilling the wells plus a fee equal to 15% of those costs. We also
act as well operator and partnership manager, for which we receive 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.
Our business strategy for increasing our reserve base includes
acquisitions of undeveloped properties or companies with significant amounts of
undeveloped property. At September 30, 2004, we had $48.3 million available
under our credit facility, which could be employed to finance such acquisitions.
However, as a result of our agreements with Resource America, Inc., our ultimate
parent, relating to its proposed tax-free distribution to its stockholders of
the stock it owns in us, described under "--Initial Public Offering," we will be
limited in our 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 that Resource America completes the spin-off or
informs us that it will not complete the distribution.
PIPELINE OPERATIONS
We conduct our natural gas transportation operations through Atlas
Pipeline. 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 mmcf, 52.7 mmcf and 49.7 mmcf of natural gas in fiscal 2004, 2003 and 2002,
respectively. We also directly own approximately 400 miles of natural gas
gathering systems in Ohio and Pennsylvania.
The subordinated units in Atlas Pipeline are a special class of
ownership under which our right to receive distributions is subordinated to
those of the publicly-held common units. The subordination period is scheduled
to expire on January 1, 2005 unless certain financial tests specified in the
partnership agreement are not met. We expect that these tests will be met. Upon
expiration of the subordination period, our subordinated units will convert to
an equal number of common units.
5
As general partner, we have the right to receive incentive
distributions if Atlas Pipeline exceeds its minimum quarterly distribution
obligations to the common and subordinated units. Once Atlas Pipeline
distributes available cash to all unitholders of the minimum quarterly
distribution of $0.42, it distributes remaining available cash as follows:
o until the common units and subordinated units have received
distributions of $0.10 per unit in excess of the $0.42 minimum
quarterly distribution, available cash is allocated 85% to unit
holders (including to us as a subordinated unit holder) and 15% to
us as a general partner;
o after that additional available cash is allocated 75% to unit
holders and 25% to us as a general partner until the common units
and subordinated units have received distributions of an
additional $0.08 per unit, and
o after that, available cash is allocated 50% to unit holders and
50% to us as a general partner.
We have agreements with Atlas Pipeline that require us to:
o pay gathering fees to Atlas Pipeline for natural gas produced by
us and our 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 us of paying these fees
is offset by the transportation fees paid to us by our drilling
investment partnerships, reimbursements and distributions to us
from Atlas Pipeline and connection costs and other expenses paid
by Atlas Pipeline;
o connect wells owned or controlled by us 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. We have not
been required to provide any construction financing under this
agreement since Atlas Pipeline's inception.
We believe that we comply with all the requirements of these
agreements.
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.
Acquisition of Spectrum Field Services by Atlas Pipeline. In July 2004,
Atlas Pipeline acquired Spectrum Field Services, Inc., or Spectrum, for
approximately $142.4 million, including transaction costs and taxes due as a
result of the transaction. This acquisition significantly increased 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 was a privately owned 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 natural gas liquids, or 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
6
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) 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 million cubic feet, or 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;
o using the $20.0 million of net proceeds received from the sale to
Resource America and us of preferred units in Atlas Pipeline
Operating Partnership; and
o using $22.4 million of the net proceeds from Atlas Pipeline's
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 new credit facility
and to repurchase for $20.4 million the preferred units issued to Resource
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 expense on our statement of
income.
OPERATING SEGMENT INFORMATION
For financial information concerning our operating segments, including
revenues from external customers, profit (loss) and total assets, see Note 13 to
our Notes to Consolidated Financial Statements.
NATURAL GAS AND OIL PROPERTIES
For information concerning our natural gas and oil properties,
including the number of wells in which we have a working interest, reserve and
acreage information, see Item 2: "Properties."
PRODUCTION
For information concerning our natural gas and oil production
quantities, average sales prices and average production costs, see Item 2:
"Properties."
7
NATURAL GAS SALES - APPALACHIAN BASIN
We have a natural gas supply agreement with FirstEnergy Solutions Corp.
for a 10-year term which began on April 1, 1999. Subject to certain exceptions,
FirstEnergy Solutions has a last right of refusal to buy all of the natural gas
produced and delivered by us and our affiliates, including our drilling
investment partnerships, at certain delivery points with the facilities of:
o East Ohio Gas Company, National Fuel Gas Distribution, Columbia of
Ohio, and Peoples Natural Gas Company, which are local
distribution companies; and
o National Fuel Gas Supply, Columbia Gas Transmission Corporation,
Tennessee Gas Pipeline Company, and Texas Eastern Transmission
Company, which are interstate pipelines.
FirstEnergy Solutions is the marketing affiliate of FirstEnergy Corp.
(NYSE: FE), a large regional electric utility based in Akron, Ohio. 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 the guaranty is terminated on 30 days notice.
A portion of our and our drilling investment partnerships' natural gas
is subject to the agreement with FirstEnergy Solutions, with the following
exceptions:
o natural gas we sell 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 wells 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 to us as of
November 30, 2004, we anticipate that we and our affiliates, including our
drilling investment partnerships, will sell approximately 50% of our natural gas
production under the FirstEnergy Solutions agreement. The agreement also permits
us to implement forward sales transactions 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 to two years, and requires the
parties to negotiate a new pricing arrangement at each delivery point for
subsequent periods. If, at the end of any applicable period, the parties cannot
agree to a new price for any delivery point, then we may solicit offers from
third-parties to buy the natural gas for that delivery point. If FirstEnergy
Solutions does not match this price, then we may sell the natural gas to the
third-party. This process is repeated at the end of each contract period, which
is usually one year. We market the remainder of our natural gas, which is
principally located in the Fayette County, PA area, primarily to Colonial
Energy, Inc., UGI Energy Services, and others.
8
Our 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 God, fire, storm, flood,
and explosion, but also includes the permanent closing of the factories of
Carbide Graphite or Duferco Farrell Corporation during the term of FirstEnergy
Solutions' agreements to sell natural gas to them. If these factories were
closed, however, we believe that FirstEnergy Solutions would be able to find
alternative purchasers and would not invoke the force majeure clause.
We expect that natural gas produced from wells drilled in areas of the
Appalachian Basin other than described above will be primarily tied to the spot
market price and supplied to:
o gas marketers;
o local distribution companies;
o industrial or other end-users; and/or
o companies generating electricity.
CRUDE OIL SALES - APPALACHIAN BASIN
Crude oil produced from our wells flows directly into storage tanks
where it is picked up by the oil company, a common carrier, or pipeline
companies acting for the oil company which is purchasing the crude oil. Unlike
natural gas, crude oil does not present any transportation problem. We
anticipate selling any oil produced by our wells to regional oil refining
companies at the prevailing spot market price for Appalachian crude oil in spot
sales.
NATURAL GAS AND NGL SUPPLY AND SALES - SPECTRUM
ChevronTexaco 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 ChevronTexaco's contract
supply approximately 10.0 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 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 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.
9
Spectrum also has a transportation and fractionation contract with Koch
Hydrocarbons, which expires in 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 and continues on a month-to-month basis.
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 we determine that a well is no longer capable of producing natural
gas or oil in economic quantities, we must dismantle the well and restore and
reclaim the surrounding area before we can abandon the well. We contract these
operations to independent service providers to whom we pay a fee. The contractor
will also salvage the equipment on the well, which we then sell in the used
equipment market. Under the partnership agreements of our drilling investment
partnerships, which own the majority of our wells, we are allocated abandonment
costs in proportion to our partnership interest (generally between 27% and 35%)
and are allocated between 65% and 100% of the salvage proceeds. As a
consequence, we generally receive proceeds from salvaged equipment at least
equal to, and typically exceeding, our share of the related costs. See Note 2 of
our 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 we use hedges for our Appalachian Basin natural gas
production. Through our hedges, we seek to provide a measure of stability in the
volatile environment of natural gas prices. These hedges may include purchases
of regulated NYMEX futures and options contracts and non-regulated
over-the-counter futures contracts with qualified counterparties. The futures
contracts are commitments to purchase or sell natural gas at future dates and
generally cover one-month periods for up to 24 months in the future. To assure
that the financial instruments will be used solely for hedging price risks and
not for speculative purposes, we have a committee to assure that all financial
trading is done in compliance with our hedging policies and procedures. We do
not intend to contract for positions that we cannot offset with actual
production.
FirstEnergy Solutions and other third-party marketers to which we sell
gas, such as Colonial Energy, Inc. and UGI Energy Services, also use NYMEX-based
financial instruments to hedge their pricing exposure and make price hedging
opportunities available to us. We enter into forward sales transactions which
are not deemed hedges for accounting purposes because they require firm delivery
of natural gas. Thus, we limit 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.
10
The portion of natural gas that we engage 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 costless collar) changes from time to time. As of
September 30, 2004, our overall forward sales position for the future months
ending March 2006 for our 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 not sold and was subject to market-based pricing.
We implemented approximately 69% of these forward sales through
FirstEnergy Solutions. For information concerning our natural gas hedging, see
Item 7: "Management's Discussion and Analysis of Financial Condition and Results
of Operations--Quantitative and Qualitative Disclosures about Market
Risk--Commodity Price Risk" and Note 5 of our 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, "Accounting for Derivative
Instruments and Hedging Accounting." 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
We contract for drilling rigs and purchase goods and services necessary
for the drilling and completion of wells from a number of drillers and
suppliers, none of which supplies a significant portion of our annual needs.
During fiscal 2004, we faced no shortage of these goods and services. We cannot
predict the duration of the current supply and demand situation for drilling
rigs and other goods and services with any certainty due to numerous factors
affecting the energy industry and the demand for natural gas and oil.
11
MAJOR CUSTOMERS
During fiscal 2004, 2003 and 2002, gas sales to FirstEnergy Solutions
accounted for 11%, 18% and 16%, respectively, of our total revenues. Because
Spectrum has historically sold the majority of its natural gas to two customers,
we expect that in fiscal 2005 they may account for over 10% of our revenues.
COMPETITION
The energy industry is intensely competitive in all of its aspects.
Competition arises not only from numerous domestic and foreign sources of
natural gas and oil but also from other industries that supply alternative
sources of energy. Competition is intense for the acquisition of leases
considered favorable for the development of natural gas and oil in commercial
quantities. Product availability and price are the principal means of
competition in selling oil and natural gas. Many of our competitors possess
greater financial and other resources than ours which may enable them to
identify and acquire desirable properties and market their natural gas and oil
production more effectively than we do. While it is impossible for us to
accurately determine our comparative industry position, we do not consider our
operations to be a significant factor in the industry. Moreover, we also compete
with a number of other companies that offer interests in drilling investment
partnerships. As a result, competition for investment capital to fund drilling
investment partnerships is intense.
Atlas Pipeline's Appalachian Basin operations do not encounter direct
competition in their service areas since we control the majority of the
drillable acreage in each area. However, because its Appalachian Basin
operations principally serve wells drilled by us, Atlas Pipeline is affected by
competitive factors affecting our 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. We may also encounter competition in obtaining drilling
services from third-party providers. Any competition we encounter could delay us
in drilling wells for our sponsored partnerships, and thus delay the connection
of wells to Atlas Pipeline's gathering systems.
As Atlas Pipeline's omnibus agreement with us generally requires us to
connect wells we operate to its system, Atlas Pipeline does not expect any
direct competition in connecting wells drilled and operated by us 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 competitive factors for new well connections 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.
12
MARKETS
The availability of a ready market for natural gas and oil and the
price obtained, depends upon numerous factors beyond our control, as described
in "? Risk Factors - Risks Relating to Our Business." During fiscal 2004, 2003
and 2002, neither Spectrum nor we experienced problems in selling our natural
gas and oil, although prices have varied significantly during and after those
periods.
GOVERNMENTAL REGULATION
Regulation of Production. The production of natural gas and oil is
subject to regulation under a wide range of local, state and federal statutes,
rules, orders and regulations. Federal, state and local statutes and regulations
require permits for drilling operations, drilling bonds and reports concerning
operations. All of the states in which we own and operate properties have
regulations governing conservation matters, including provisions for the
unitization or pooling of oil and natural gas properties, the establishment of
maximum allowable rates of production from oil and natural gas wells, the
regulation of well spacing, and plugging and abandonment of wells. The effect of
these regulations is to limit the amount of natural gas and oil that we can
produce from our wells and to limit the number of wells or the locations at
which we can drill, although we can apply for exemptions 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's individual gathering systems perform 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.
13
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 if
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 we
will not be affected in any way that materially differs from the effects on our
competitors.
Environmental and Safety Regulation. Under the Comprehensive
Environmental Response, Compensation and Liability Act, the Toxic Substances
Control Act, the Resource Conservation and Recovery Act, the Oil Pollution Act
of 1990, the Clean Air Act, and other federal and state laws relating to the
environment, owners and operators of wells producing natural gas or oil, and
pipelines, can be liable for fines, penalties and clean-up costs for pollution
caused by the wells or the pipelines. Moreover, the owners' or operators'
liability can extend to pollution costs from situations that occurred prior to
their acquisition of the assets. Natural gas pipelines are also subject to
safety regulation under the Natural Gas Pipeline Safety Act of 1968 and the
Pipeline Safety Act of 1992 which, among other things, dictate the type of
pipeline, quality of pipeline, depth, 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 we will be required in the near future to
expend amounts that are material in relation to our revenues by reason of
environmental laws and regulations, but since these laws and regulations change
frequently, we cannot predict the ultimate cost of compliance.
CREDIT FACILITIES
Our Credit Facility. We have a $75.0 million credit facility
administered by Wachovia Bank, National Association. The revolving credit
facility is guaranteed by our subsidiaries. Up to $10.0 million of the
borrowings under the facility may be in the form of standby letters of credit.
Borrowings under the facility are secured by our assets, including the stock of
our 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 our election:
o the base rate plus the applicable margin; or
o the adjusted London Interbank Offered Rate, or 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 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;
14
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 interest rate
of 4.1%.
The Wachovia credit facility requires us to maintain a 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. In
addition, the facility limits sales, leases or transfers of assets and the
incurrence of additional indebtedness. The facility limits the dividends payable
by us to 50% of our cumulative net income from January 1, 2004 to the date of
determination plus $5.0 million and prohibits us 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, we 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.
Atlas Pipeline Credit Facility. Concurrently with the completion of the
Spectrum acquisition, in July 2004, Atlas Pipeline entered into a $135.0 million
senior secured term loan and revolving credit facility administered by Wachovia
Bank that replaced its $20.0 million facility. The facility originally included
a $35.0 million four year revolving line of credit, which can 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 are 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. The applicable margin for the
revolving line of credit is as follows:
o where its leverage ratio, that is, the ratio of its debt to
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;
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.
15
The applicable margin for the term loan is 0.75% 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 that it makes
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.
EMPLOYEES
As of September 30, 2004, we employed 227 persons.
RISK FACTORS
Statements made by us in written or oral form to various persons,
including statements made in filings with the SEC that are not strictly
historical facts, are "forward-looking" statements that are based on current
expectations about our business and assumptions made by management. These
statements are subject to risks and uncertainties that exist in our operations
and business environment that could result in actual outcomes and results that
are materially different than predicted. The following includes some, but not
all, of those factors or uncertainties:
General
Interest rate increases will increase our interest costs. See Item 7A,
"Quantitative and Qualitative Disclosures about Market Risk." This could have
material adverse effects on us, including reduction of our net income.
Our business strategy depends upon our ability to obtain capital
through the sponsorship of investment programs 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 programs, our ability to increase our
managed assets and revenues will be limited and our profitability may decline.
Subsidiaries of ours currently serve as general partner of 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.
16
Risks Relating to Our Business
Natural gas and oil prices are volatile. A substantial decrease in
prices, particularly natural gas prices, would decrease our revenues and the
value of our natural gas and oil properties and could make it more difficult for
us to obtain financing for our drilling operations through drilling investment
partnerships. Our future financial condition and results of operations, and the
value of our natural gas and oil properties, will depend upon market prices for
natural gas and oil. Natural gas and oil prices historically have been volatile
and will likely continue to be volatile in the future. Prices we have received
during our past three fiscal years for our 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
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 us because:
o price decreases will reduce the amount of cash flow available to
us for drilling and production operations and for our capital
contributions to our drilling investment partnerships;
o price decreases may make it more difficult to obtain financing for
our drilling and development operations through sponsored drilling
investment partnerships, borrowings or otherwise;
o price decreases may make some reserves uneconomic to produce,
reducing our reserves and cash flow; and
o price decreases may cause the lenders under our credit facility to
reduce our borrowing base because of lower revenues or reserve
values, reducing our liquidity and, possibly, requiring mandatory
loan repayment.
Further, oil and gas prices do not necessarily move in tandem. Because
approximately 92% of our proved reserves are currently natural gas reserves, we
are more susceptible to movements in natural gas prices.
17
Drilling wells is highly speculative. The amount of recoverable natural
gas and oil reserves may vary significantly from well to well. While our average
estimated ultimate recovery from our wells is 150 mmcfe per well, recoverable
natural gas from individual wells ranges up to 1.556 bcfe. We 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 us 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, we have recently experienced an increase
in the cost of tubular steel as a result of rising steel prices which will
increase well costs. Further, our 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.
Any one or more of the factors discussed above could reduce or delay
our receipt of drilling and production revenues, thereby reducing our earnings
and could reduce revenues in one or more of our drilling investment
partnerships, which may make it more difficult to finance our drilling
operations through sponsorship of future partnerships.
Properties that we acquire may not produce as projected, and we may be
unable to identify liabilities associated with the properties or obtain
protection from sellers against them. As part of our business strategy, we
continually seek acquisitions of gas and oil properties. We completed two such
acquisitions in fiscal 2001, one from Kingston Oil Corporation and one from
American Refining and Exploration Company, and have 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.
Our assessment will not necessarily reveal all existing or potential
problems, nor will it permit us to become familiar enough with the properties to
assess fully their capabilities and deficiencies. With respect to properties on
which there is current production, we 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. We may not be able to obtain or recover on contractual
indemnities from the seller for liabilities that it created. We 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 our
expectations.
18
Estimates of proved reserves are uncertain and, as a result, revenues
from production may vary significantly from our expectations. We base our
estimates of our proved natural gas and oil reserves and future net revenues
from those reserves upon analyses that rely upon various assumptions, including
those required by the U.S. 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, in our case, assumptions concerning natural gas prices, 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, taxes, development
expenses, operating expenses, availability of funds and quantities of
recoverable natural gas and oil reserves may vary substantially from our
estimates or estimates contained in the reserve reports referred to elsewhere in
this report. Our properties also may be susceptible to hydrocarbon drainage from
production by other operators on adjacent properties. In addition, our 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 our
control.
At September 30, 2004, approximately 30% of our estimated proved
reserves were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling operations. The reserve
data assumes that we will obtain the necessary capital and conduct these
operations successfully which, for the reasons discussed elsewhere in this
section, may not occur.
If we cannot replace reserves, our revenues and production will
decline. Our proved reserves will decline as reserves are produced unless we
acquire or lease additional properties containing proved reserves, successfully
develop new or existing properties or identify additional formations with
primary or secondary reserve opportunities on our properties. If we are not
successful in expanding our reserve base, our future natural gas and oil
production and drilling activities, the primary source of our energy revenues,
will decrease. Our ability to find and acquire additional reserves depends on
our generating sufficient cash flow from operations and other sources of
capital, principally our sponsored drilling investment partnerships, all of
which are subject to the risks discussed elsewhere in this subsection.
If we are unable to acquire assets from others or obtain capital funds
through our drilling investment partnerships, our revenues may decline. The
growth of our energy operations has resulted from both our acquisition of energy
companies and assets and from our ability to obtain capital funds through our
sponsored drilling investment partnerships. If we are unable to identify
acquisitions on acceptable terms, or cannot obtain sufficient capital funds
through sponsored drilling investment partnerships, we may be unable to increase
or maintain our inventory of properties and reserve base, or be forced to
curtail drilling, production or other activities. This would result in a decline
in our revenues.
Changes in tax laws may impair our ability to obtain capital funds
through our drilling investment partnerships. Under current federal tax laws,
there are tax benefits to investing in drilling investment partnerships such as
those we sponsor, including deductions for intangible drilling costs and
depletion deductions. Changes to federal tax laws that reduce or eliminate these
benefits may make investment in our drilling investment partnerships less
attractive and, thus, reduce our ability to obtain funding from this significant
source of capital funds. A recent change to federal tax law that may affect us
is 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 our drilling
investment partnerships relatively less attractive than investments in assets
likely to yield capital gains or qualifying dividends.
19
Competition in the oil and natural gas industry is intense, which may
hinder our ability to acquire gas and oil properties and companies and to obtain
capital. We operate in a highly competitive environment for acquiring properties
and other natural gas and oil companies and attracting capital through our
drilling investment partnerships. We also compete with the exploration and
production divisions of public utility companies for natural gas and oil
property acquisitions. Our 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 our financial or personnel resources permit. Moreover, our
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 we do. We may not be able to
compete successfully in the future in acquiring prospective reserves and raising
additional capital.
We could incur losses from our arrangements for transporting natural
gas. We pay transportation fees, which are based on natural gas sales prices, to
Atlas Pipeline for natural gas transported for our drilling investment
partnerships and certain unaffiliated producers. An increase in natural gas
prices would increase the fees we pay to Atlas Pipeline which could exceed the
transportation fees paid to us, reimbursements and distributions to us from our
general and limited partner interests in Atlas Pipeline, and connection costs
and other expenses paid by Atlas Pipeline.
We may be exposed to financial and other liabilities as the general
partner in drilling investment partnerships. We currently serve as the managing
general partner of 87 drilling investment partnerships and will be the general
partner of new drilling investment partnerships that we sponsor. As general
partner, we are contingently liable for the obligations of these partnerships to
the extent that partnership assets or insurance proceeds are insufficient.
We are subject to complex laws that can affect the cost, manner or
feasibility of doing business. Exploration, development, production and sales of
natural gas and oil are subject to extensive federal, state and local
regulations. We discuss our regulatory environment in more detail in
"-Governmental Regulation." We 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 our operations and subject us to
administrative, civil and criminal penalties. Other regulations may limit our
operations. For example, "frost laws" prohibit drilling and other heavy
equipment from using certain roads during winter, a principal drilling season
for us, which may delay us in drilling and completing wells. Moreover,
governmental regulations could change in ways that substantially increase our
costs, thereby reducing our return on invested capital, revenues and net income.
Our operations may incur substantial liabilities to comply with
environmental laws and regulations. Our 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 our 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 us
to make significant expenditures to maintain compliance or could restrict our
methods or times of operation. Under these environmental laws and regulations,
we 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
our operations in more detail under "-Governmental Regulation-Environmental and
Safety Regulation."
20
Pollution and environmental risks generally are not fully insurable. We
may elect to self-insure if we believe that insurance, although available, is
excessively costly relative to the risks presented. The occurrence of an event
that is not covered, or not fully covered, by insurance could reduce our
revenues and the value of our assets.
Well blowouts, pipeline ruptures and other operating and environmental
problems could result in substantial losses to us. 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 us. The occurrence of any of those hazards could result in
substantial losses to us, 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.
We may be required to write-down the carrying value of our proved
properties; any such write-down would be a charge to our earnings. We may be
required to write-down the carrying value of our natural gas and oil properties
when natural gas and oil prices are low. In addition, write-downs may occur if
we have:
o downward adjustments to our estimated proved reserves;
o increases in our estimates of development costs; or
o deterioration in our exploration and development results.
The unavailability or high cost of additional drilling rigs, equipment,
supplies, personnel and oil field services could delay our exploration and
development plans and decrease net revenues from drilling operations. Shortages
of drilling rigs, equipment, supplies or personnel could delay our development
and exploration plans, thereby reducing our revenues from drilling operations
and delaying our receipt of production revenues from wells we planned to drill.
Moreover, increased costs, whether due to shortages or other causes, will reduce
the number of wells we can drill for existing drilling investment partnerships
and, by making our drilling investment partnerships less attractive as
investments, may reduce the amount of financing for drilling operations we can
obtain from them. This may reduce our revenues not only from drilling operations
but also, if fewer wells are drilled, from production of natural gas and oil.
Risks Relating to Our Relationship with Resource America
Our principal stockholder is in a position to affect our ongoing
operations, corporate transactions and other matters. Our principal stockholder,
Resource America, owns 80.2% of our outstanding shares of common stock. As a
result, Resource America is able to determine the outcome of all corporate
actions requiring stockholder approval. For example, Resource America may
control decisions with respect to:
o the election and removal of directors;
o mergers or other business combinations involving us;
o future issuances of our common stock or other securities; and
o amendments to our certificate of incorporation and bylaws.
Any exercise by Resource America of its control rights may be in its
own best interest which may not be in the best interest of our other
stockholders and our company. Resource America's ability to control our company
may also make investing in our stock less attractive. These factors in turn may
have an adverse affect on the price of our common stock. Resource America's
control rights will continue until it distributes its remaining ownership
interest in us to its common stockholders or otherwise disposes of it. While
Resource America intends to make the distribution, it is not obligated to do so.
See "- Resource America may not complete its intended distribution of its
holdings of our common stock, which would result in its continued control of
us."
21
Potential conflicts may arise between us and Resource America that may
not be resolved in our favor. The relationship between us and Resource America
may give rise to conflicts of interest with respect to, among other things,
transactions and agreements among us and Resource America, issuances of
additional voting securities and the election of directors. When the interests
of Resource America diverge from our interests, Resource America may exercise
its substantial influence and control over us in favor of its own interests over
our interests.
Our agreements with Resource America are not the result of arm's-length
negotiations. In connection with our initial public offering, we entered into
agreements with Resource America which govern various transactions between us
and our ongoing relationship, including registration rights, tax separation and
indemnification. All of these agreements were entered into while we were a
wholly-owned subsidiary of Resource America, and were negotiated in the overall
context of our initial public offering and the proposed distribution by Resource
America of its interest in us to its stockholders. These agreements were not
negotiated at arm's-length. Accordingly, certain rights of Resource America,
particularly the rights relating to the number of demand and piggy-back
registration rights that Resource America has, the assumption by us of the
registration expenses related to the exercise of these rights and our
indemnification of Resource America for any tax liabilities it may incur
relating to the distribution to the extent those liabilities are caused by our
actions, may be more favorable to it than if they had been the subject of
independent negotiation. We and Resource America and its other affiliates may
enter into other material transactions and agreements from time to time in the
future which also may not be deemed to be independently negotiated.
Our agreements with Resource America may limit our ability to obtain
capital, make acquisitions or effect other business combinations. Our business
strategy anticipates future acquisitions of natural gas and oil properties and
companies. Any acquisition that we undertake could be subject to our ability to
access capital from outside sources on acceptable terms through the issuance of
our common stock or other securities. However, for the proposed distribution of
Resource America's common stock in us to its stockholders to be tax-free to
them, Resource America must, among other things, own at least 80% of all of our
voting power at the time of the distribution. Therefore, until such time that
Resource America informs us that it will not complete the distribution, which
will be at Resource America's discretion, we will be limited in our ability to
issue voting securities, non-voting stock or convertible debt without Resource
America's prior consent, and Resource America may be unwilling to give that
consent. In addition, our agreements with Resource America prohibit us from
making acquisitions or entering into mergers or other business combinations that
would jeopardize the tax-free status of the distribution.
Resource America may not complete its intended distribution of its
holdings of our common stock, which would result in its continued control of us.
Resource America intends to distribute to its stockholders all of our common
stock it owns. However, Resource America is not obligated to make the
distribution at any particular time, or at all, and, as a result, the
distribution may not occur at any particular time, or at all. Resource America
has advised us that it does not intend to complete the distribution unless it
receives a ruling from the Internal Revenue Service and/or an opinion from its
tax counsel as to the tax-free nature of the distribution to Resource America
and its stockholders for U.S. federal income tax purposes. Because the Internal
Revenue Service requirements for tax-free distributions of this nature are
complex and the Internal Revenue Service has broad discretion, there is
significant uncertainty as to whether Resource America will be able to obtain
such a ruling.
Unless and until the distribution occurs, we will face the risks
discussed in this report relating to Resource America's control of us and
potential conflicts of interest between Resource America and us. If the
distribution is delayed or not completed at all, the liquidity of shares of our
common stock in the market may be constrained for as long as Resource America
continues to hold a significant position in our stock. A lack of liquidity in
the market for our common stock may adversely affect our stock price.
22
ITEM 2. PROPERTIES
OFFICE PROPERTIES
We own a 24,000 square foot office building in Moon Township,
Pennsylvania, a 17,000 square foot field office and warehouse facility in
Jackson Center, Pennsylvania and an office in Deerfield, Ohio. We lease a 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 2009. 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
through July 2005. In addition, we lease other field offices in Ohio and New
York on a month-to-month basis. We anticipate that we will enter into subleases
with Resource America for the office space we currently use in Philadelphia, PA
and New York City, NY.
PRODUCTIVE WELLS
The following table sets forth information as of September 30, 2004
regarding productive natural gas and oil wells in which we have a working
interest:
Number of productive wells
--------------------------
Gross (1) Net (1)
--------- -------
Oil wells..................................................................... 341 271
Gas wells..................................................................... 4,786 2,494
------ ------
Total.................................................................... 5,127 2,765
====== ======
- ----------------
(1) Includes our 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.
PRODUCTION
The following table sets forth the quantities of our natural gas and
oil production, average sales prices and average production costs per equivalent
unit of production for the periods indicated.
Average production
Production Average sales price cost per
Period Oil (bbls) Gas (mcf) per bbl per mcf (1) mcfe (2)
- ------ ---------- --------- ------- ----------- --------
Fiscal 2004................... 181,021 7,285,281 $32.85 $5.84 $.87
Fiscal 2003................... 160,048 6,966,899 $26.91 $4.92 $.84
Fiscal 2002................... 172,750 7,117,276 $20.45 $3.56 $.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.
23
DEVELOPED AND UNDEVELOPED ACREAGE
The following table sets forth information about our developed and
undeveloped natural gas and oil acreage as of September 30, 2004. The
information in this table includes our interest in acreage owned by drilling
investment partnerships sponsored by us.
Developed acreage Undeveloped acreage
------------------------- ------------------------
Gross Net Gross Net
-------- ------- --------- --------
Arkansas...................................... 2,560 403 - -
Kansas........................................ 160 20 - -
Kentucky...................................... 924 462 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 our developed acreage generally have terms that extend
for the life of the wells, while the leases on our undeveloped acreage have
terms that vary from less than one year to five years. We paid rentals of
approximately $592,000 in fiscal 2004 to maintain our leases.
We believe that we hold good and indefeasible title to our producing
properties, in accordance with standards generally accepted in the natural gas
industry, subject to exceptions stated in the opinions of counsel employed by us
in the various areas in which we conduct our activities. We do not believe that
these exceptions detract substantially from our use of any property. As is
customary in the natural gas industry, we conduct only a perfunctory title
examination at the time we acquire a property. Before we commence drilling
operations, we conduct an extensive title examination and we perform curative
work on defects that we deem significant. We have obtained title examinations
for substantially all of our managed producing properties. No single property
represents a material portion of our holdings.
Our properties are subject to royalty, overriding royalty and other
outstanding interests customary in the industry. Our properties are also subject
to burdens such as liens incident to operating agreements, taxes, development
obligations under natural gas and oil leases, farm-out arrangements and other
encumbrances, easements and restrictions. We do not believe that any of these
burdens will materially interfere with our use of our properties.
24
DRILLING ACTIVITY
The following table sets forth information with respect to the number
of wells in which we have 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 1
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 our estimated
proved natural gas and oil reserves as of the dates indicated. All of our
reserves are located in the United States. We base our estimates relating to our
proved natural gas and oil reserves and future net revenues of natural gas and
oil reserves upon reports prepared by Wright & Company, Inc, energy consultants.
In accordance with SEC guidelines, we make 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 are held constant
throughout the life of the properties. We based our estimates of proved reserves
upon the following weighted average prices:
Years ended September 30,
-------------------------------------
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 are projections based on engineering data. There are uncertainties
inherent in the interpretation of this data as well as the projection of future
rates of production and the timing of development expenditures. Reservoir
engineering is a subjective process of estimating underground accumulations of
natural gas and oil that cannot be measured in an exact way and the accuracy of
any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. Reserve reports of other
engineers might differ from the reports of our consultants, Wright & Company.
Results of drilling, testing and production subsequent to the date of the
estimate may justify revision of this estimate. Future prices received from the
sale of natural gas and oil may be different from those estimated by Wright &
Company in preparing its reports. The amounts and timing of future operating and
development costs may also differ from those used. Accordingly, the reserves set
forth in the following tables ultimately may not be produced and the proved
undeveloped reserves may not be developed within the periods anticipated. You
should not construe the estimated PV-10 values as representative of the fair
market value of our proved natural gas and oil properties. PV-10 values are
based upon projected cash inflows, which do not provide for changes in natural
gas and oil prices or for the escalation of expenses and capital costs. The
meaningfulness of these estimates depends upon the accuracy of the assumptions
upon which they were based.
25
We evaluate natural gas reserves at constant temperature and pressure.
A change in either of these factors can affect the measurement of natural gas
reserves. We deduct operating costs, development costs and production-related
and ad valorem taxes in arriving at the estimated future cash flows. We base the
estimates on operating methods and conditions prevailing as of the dates
indicated. We cannot assure you that these estimates are accurate predictions of
future net cash flows from natural gas and oil reserves or their present value.
For additional information concerning our natural gas and oil reserves and
estimates of future net revenues, see note 15 of our 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:
Fiscal Remaining
2005 successive years Total
---- ---------------- -----
Natural gas (mmcf)........................................ 9,098 133,035 142,133
Oil (mbbl)................................................ 172 2,103 2,275
26
ITEM 3. LEGAL PROCEEDINGS
One of our subsidiaries, Resource Energy, Inc., together with Resource
America, 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 us. The complaint alleges that we are not paying
landowners the proper amount of royalty revenues 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 results of operations.
ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders during the
quarter ended September 30, 2004.
27
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 "ATLS." The following table sets forth the high and low sale prices, as
reported by Nasdaq, on a quarterly basis since our initial public offering in
May 2004.
HIGH LOW
---- ---
FISCAL 2004
Fourth Quarter.......................................................................... $ 21.90 $ 18.08
Third Quarter (since May 11, 2004)...................................................... $ 22.81 $ 16.75
As of December 1, 2004, there were 13.3 million shares of common stock
outstanding held by two holders of record.
Since May 11, 2004, the date of our initial public offering, we have
not paid any cash dividends on our common stock.
For information concerning common stock authorized for issuance under
our stock incentive plan, see Note 8 of our Notes to Consolidated Financial
Statements.
28
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data as of and for
the fiscal years ended September 30, 2000 through 2004. We derived the financial
data as of September 30, 2004 and 2003 and for the years ended September 30,
2004, 2003 and 2002 from our financial statements, which were audited by Grant
Thornton LLP, independent accountants, and are included in this report. We
derived the financial data as of September 30, 2002, 2001 and 2000 and for the
years ended September 30, 2001 and 2000 from our financial statements, which
were audited by Grant Thornton LLP, and are not included in this report.
Years Ended September 30,
-------------------------------------------------------------------
2004 2003 2002 2001 2000
---- ---- ---- ---- ----
(in thousands, except per share data)
INCOME STATEMENT DATA:
Revenues:
Well drilling.................................. $ 86,880 $ 52,879 $ 55,736 $ 43,464 $ 31,869
Gas and oil production......................... 48,526 38,639 28,916 36,681 25,231
Gathering, transmission and processing......... 36,252 5,901 5,389 5,715 4,770
Well services.................................. 8,430 7,634 7,585 7,403 6,962
Other.......................................... 768 636 1,670 2,626 2,428
--------- --------- --------- --------- ---------
Total revenues................................ 180,856 105,689 99,296 95,889 71,260
Costs and expenses:
Well drilling.................................. 75,548 45,982 48,443 36,602 25,806
Gas and oil production and exploration......... 8,838 8,485 8,264 7,846 8,339
Gathering, transmission and processing......... 27,870 2,444 2,052 2,001 2,842
Well services.................................. 4,399 3,774 3,747 2,961 2,444
General and administration..................... 6,076 6,532 6,957 10,829 8,947
Depreciation, depletion and amortization....... 14,700 11,595 10,836 10,782 9,781
Interest....................................... 2,881 1,961 2,200 1,714 2,898
Terminated acquisition......................... 2,987 - - - -
Minority interest in Atlas Pipeline
Partners, L.P................................ 4,961 4,439 2,605 4,099 2,058
--------- --------- --------- --------- ---------
Total costs and expenses.......................... 148,260 85,212 85,104 76,834 63,115
--------- --------- --------- --------- ---------
Income from continuing operations before income
taxes and cumulative effect of change in
accounting principle........................... 32,596 20,477 14,192 19,055 8,145
Provision for income taxes........................ 11,409 6,757 4,683 6,613 3,300
--------- --------- --------- --------- ---------
Income from continuing operations
before cumulative effective of change in
accounting principle........................... 21,187 13,720 9,509 12,442 4,845
Income (loss) from discontinued operation, net of
taxes.......................................... - 192 (1,641) (1,030) (673)
Cumulative effect of change in accounting
principle, net of taxes........................ - - (627) (1) - -
--------- --------- --------- --------- ---------
Net income........................................ $ 21,187 $ 13,912 $ 7,241 $ 11,412 $ 4,172
========= ========= ========= ========= =========
Basic and diluted net income per share............ $ 1.81 $ 1.30 $ .68 $ 1.07 $ .39
========= ========= ========= ========= =========
29
As of and for the Years Ended September 30,
---------------------------------------------------------------
2004 2003 2002 2001 2000
---- ---- ---- ---- ----
(in thousands, except operating data)
OPERATING DATA:
Net annual production volumes:
Natural gas (mmcf) (2).......................... 7,285 6,967 7,117 6,343 6,440
Oil (mbbls)..................................... 181 160 173 177 196
Total (mmcfe)...................................... 8,371 7,927 8,154 7,407 7,616
Average sales price:
Natural gas (per mcf) (3)....................... $ 5.84 $ 4.92 $ 3.56 5.04 $ 3.15
Oil (per bbl)................................... $ 32.85 $ 26.91 $ 20.45 $ 25.56 $ 24.50
OTHER FINANCIAL INFORMATION:
Net cash provided by operating activities.......... $ 57,314 $ 49,174 $ 5,452 $ 36,190 $ 17,157
Capital expenditures............................... $ 41,162 $ 28,029 $ 21,291 $ 14,050 $ 10,935
EBITDA (4)......................................... $ 50,177 $ 34,033 $ 27,228 $ 31,551 $ 20,824
BALANCE SHEET DATA:
Total assets....................................... $ 421,497 $ 232,388 $ 192,614 $ 199,785 $ 158,503
========= ========= ========= ========= =========
Debt............................................... $ 85,640 $ 31,194 $ 49,505 $ 43,284 $ 23,506
========= ========= ========= ========= =========
Stockholders' equity............................... $ 91,003 $ 87,511 $ 73,366 $ 66,347 $ 54,925
========= ========= ========= ========= =========
_______________________________
(1) Represents write-down of goodwill, net of taxes, by our former technology
subsidiary in connection with its adoption of SFAS 142.
(2) Excludes sales of residual gas and sales to landowners.
(3) Our average sales price before the effects of financial hedging was $5.84,
$5.08, $3.57, $5.13 and $3.15 for the years ended 2004, 2003, 2002, 2001
and 2000, respectively.
(4) We define EBITDA as earnings before interest, taxes, depreciation,
depletion and amortization. EBITDA is not a measure of performance
calculated in accordance with accounting principles generally accepted in
the United States, or GAAP. Although not prescribed under GAAP, we believe
the presentation of EBITDA is relevant and useful because it helps our
investors to understand our operating performance and makes it easier to
compare our results with other companies that have different financing and
capital structures or tax rates. EBITDA should not be considered in
isolation of, or as a substitute for, net income as an indicator of
operating performance or cash flows from operating activities as a measure
of liquidity. EBITDA, as we calculate it, may not be comparable to EBITDA
measures reported by other companies. In addition, EBITDA does not
represent funds available for discretionary use. The following reconciles
EBITDA to our income from continuing operations for the periods indicated.
Years Ended September 30,
--------------------------------------------------------------
2004 2003 2002 2001 2000
---- ---- ---- ---- ----
(in thousands)
Income from continuing operations.................. $ 21,187 $ 13,720 $ 9,509 12,442 4,845
Plus interest expense.............................. 2,881 1,961 2,200 1,714 2,898
Plus income taxes.................................. 11,409 6,757 4,683 6,613 3,300
Plus depreciation, depletion and amortization...... 14,700 11,595 10,836 10,782 9,781
--------- --------- --------- --------- ---------
EBITDA............................................. $ 50,177 $ 34,033 $ 27,228 $ 31,551 $ 20,824
========= ========= ========= ========= =========
30
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
OVERVIEW OF YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002
During the year ended September 30, 2004, our operations continued to
grow as we increased our total assets, revenues, number of wells drilled, number
of wells operated and total reserves.
We finance our drilling operations principally through funds raised
from investors in our public and private drilling investment partnerships. The
$107.7 million raised in fiscal 2004 represented a 63% increase over the $66.1
million raised in fiscal 2003 and a 162% increase from the $41.1 million raised
in fiscal 2002.
Our gross revenues depend, to a significant extent, on the price of
natural gas and oil which can fluctuate significantly. We seek to balance this
volatility with the more stable net income from our well drilling and well
servicing operations which are principally fee-based. Our well drilling
operation's gross margin was $11.3 million, $6.9 million and $7.3 million for
the years ended September 30, 2004, 2003 and 2002, respectively. Our well
services gross margin was $4.0 million, $3.9 million and $3.8 million for the
years ended September 30, 2004, 2003 and 2002, respectively.
Our business strategy for increasing our reserve base includes
acquisitions of undeveloped properties or companies with significant amounts of
undeveloped property. However, as a result of our agreements with Resource
America, our ultimate parent, relating to its proposed tax-free distribution to
its stockholders of the stock it owns in us, described in Item 1: "Business -
General - Initial Public Offering," we will be limited in our 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 that Resource
America completes the spin-off or informs us that it will not complete the
distribution. At September 30, 2004, we had $48.3 million available under our
credit facility, which could be employed to finance such acquisitions.
Our financial condition and results of operations during the fiscal
2004 are affected by initiatives taken by Atlas Pipeline Partners, L.P. In April
and July 2004, Atlas Pipeline completed public offerings of 750,000 and
2,100,000 of its common units, realizing $25.2 million and $67.5 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.
In July 2004, Atlas Pipeline acquired Spectrum for approximately $142.4
million, including transaction costs and the payment of taxes due as a result
of the transaction. This acquisition significantly increased 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 was a
privately owned 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 natural gas liquids, or 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.
31
RESULTS OF OPERATIONS
The following table sets forth information relating to our production
revenues, production volumes, sales prices, production costs and depletion for
our operations during the periods indicated:
Years Ended September 30,
----------------------------------------
2004 2003 2002
---- ---- ----
Production revenues (in thousands):
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............................................................... $ .87 $ .84 $ .82
Depletion per equivalent mcfe............................................ $ 1.22 $ 1.01 $ .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 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.
Our well drilling revenues and costs and expenses incurred represent
the billings and costs associated with the completion of wells for drilling
investment partnerships we sponsored. The following table sets forth information
relating to these revenues, costs, margins and wells 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
========== ========== ==========
32
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 $34.2 million in fiscal 2003. The increase was due to
a 19% increase in the average sales price of natural gas and a 4% 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 the year ended
September 30, 2004, an increase of $4.4 million (64%) from $6.9 million in the
year ended September 30, 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 "Liabilities associated with drilling
contracts" includes $26.5 million of funds raised in our drilling investment
partnerships in fiscal 2004 that have 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.
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 was 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 these revenues
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 from 18% in fiscal 2003 to 15% in fiscal 2004 as a
result of an increase in our average sales price which more than offset the
slight increase in production costs per mcfe.
Our exploration costs were $1.5 million in the year ended September 30,
2004, a decrease of $166,000 (10%) from fiscal 2003. We attribute the decrease
in fiscal 2004 as compared to the prior period is principally due 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.
33
Our gathering, transmission and processing expenses were $27.9 million,
of which $25.5 million was associated with the operations of Spectrum which was
acquired on July 16, 2004. 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 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 general and administrative 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. The decrease in the year ended September 30, 2004 as compared to
the prior year period is attributable principally to the following:
o general and administrative expense reimbursements from our
investment partnerships increased by $4.8 million as we continue
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 employees in anticipation
of our spin-off from our parent;
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 general and administrative expenses increased $484,000 due to the
acquisition of Spectrum on July 16, 2004; and
o directors fees increased $251,000 due to our initial public
offering and our anticipated spin-off from Resource America.
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.
34
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 is a result of the
natural production decline inherent in the life of a well. We did not offset the
decline through the addition of new wells, as substantially all of the wells we
have drilled during the past several years have targeted natural gas reserves.
Our well drilling gross margin was $6.9 million in the year ended
September 30, 2003, a decrease of $396,000 (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 the year ended September 30,
2003, an increase of $144,000 (9%) from fiscal 2002. The increase in fiscal 2003
as compared to the prior period was attributable to expenditures for lease costs
of $275,000 which were charged to operations upon our decision to discontinue
drilling on certain leases.
Our gathering, transmission and processing expenses increased 19% in
the year ended September 30, 2003, as compared to the similar prior year period.
This increase resulted from an increase in compressor expenses due to the
addition of more compressors and increased compressor lease rates. Compressors
were added to increase the transportation capacity of our gathering systems.
Our general and administrative expenses were $6.5 million in fiscal
2003, a decrease of $425,000 (6%) from $6.9 million in fiscal 2002. These
expenses include, among other things, salaries and benefits not allocated to a
specific energy activity, costs of running our energy corporate office,
partnership syndication activities and outside services. These expenses were
partially offset by reimbursements we received for costs we incurred in our
partnership management and drilling activities, resulting from an increase in
the number of wells we drilled and managed during the year as compared to the
prior year. Reimbursements received by us related to our drilling activities
increased $470,000 in year ended September 30, 2003 as compared to the year
ended September 30, 2002. In addition, we more closely allocated direct costs
associated with our other energy activities to those activities, thereby
reducing general and administrative 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 variance
from period to period is directly attributable to changes in our oil and gas
reserve quantities, product prices and changes in the depletable cost basis of
oil and gas. Higher gas and oil prices caused depletion as a percentage of oil
and gas revenues to decrease in fiscal 2003 as compared to fiscal 2002.
35
OTHER REVENUES AND COSTS AND EXPENSES
Year Ended September 30, 2004 Compared to Year Ended September 30, 2003
Our interest expense was $2.9 million in fiscal 2004, an increase of
$920,000 (47%) from $2.0 million in fiscal 2003. This increase resulted
primarily from an increase in outstanding borrowings in fiscal 2004 as compared
to fiscal 2003 due to funds borrowed by Atlas Pipeline for the acquisition of
Spectrum.
Our terminated acquisition costs are related to Atlas Pipeline's
agreement to acquire 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
on our income statement.
At September 30, 2004, we own 24% of the partnership interests in Atlas
Pipeline through both our general partner interest and the subordinated units.
During the year ended September 30, 2004, our ownership interest in Atlas
Pipeline decreased from 39% to 24% as the result of the completion by Atlas
Pipeline of secondary offerings of its common units in April and July 2004.
Because we control the operations of Atlas Pipeline, 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's earnings was $5.0
million for the year ended September 30, 2004, as compared to $4.4 million for
the year ended September 30, 2003, an increase of $522,000 (12%). This increase
was the result of an increase in the percentage interest of public unitholders
and an increase in Atlas Pipeline's net income, principally caused by increases
in transportation rates received. Atlas Pipeline's transportation rates vary, to
a significant extent, with the prices of natural gas which, on average, were
higher in fiscal 2004 than fiscal 2003.
Our effective tax rate increased to 35% in fiscal 2004 as compared to
33% in fiscal 2003 as a result of a reduction in statutory depletion benefits
relative to increased net income.
OTHER REVENUES, COSTS AND EXPENSES
Year Ended September 30, 2003 Compared to Year Ended September 30, 2002
Our other revenue was $636,000 in fiscal 2003, a decrease of $1.0
million (62%) as compared to $1.7 million in fiscal 2002. Interest income
decreased $466,000 (68%) to $220,000 in fiscal 2003 from $686,000 in fiscal
2002. This decrease was the result of a decrease in funds invested as well as in
the interest rates earned on those funds. In addition, gains associated with the
sales of gas and oil assets decreased $397,000 (97%) to $14,000 in fiscal 2003
from $411,000 in fiscal 2002. This decrease was the result of the sale in fiscal
2002 of certain gas and oil assets which were not located within the Appalachian
Basin and thus did not fit our business model. No such sales occurred in fiscal
2003.
Our interest expense was $2.0 million in fiscal 2003, a decrease of
$239,000 (11%) from $2.2 million in fiscal 2002. This decrease resulted
primarily from decreases in short-term interest rates and decreases in
outstanding borrowings in fiscal 2003 as compared to fiscal 2002.
36
During the year ended September 30, 2003, our ownership interest in
Atlas Pipeline decreased from 51% to 39% as the result of the completion by
Atlas Pipeline of an offering of its common units. Because we control the
operations of Atlas Pipeline, 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's earnings was $4.4 million for the year
ended September 30, 2003, as compared to $2.6 million for the year ended
September 30, 2002, an increase of $1.8 million (70%). This increase was the
result of an increase in Atlas Pipeline's net income, principally caused by
increases in transportation volumes and rates received, and the increase in the
percentage interest of public unitholders. Atlas Pipeline's transportation rates
vary, to a significant extent, with the prices of natural gas which, on average,
were higher in fiscal 2003 than fiscal 2002.
DISCONTINUED OPERATION
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 years ended
September 30, 2003 and 2002. We had held a 50% equity interest in Optiron; as a
result of the disposition, we currently hold a 10% equity interest.
The plan of disposal required Optiron to pay us 10% of its revenues if
they exceeded $2.0 million in the 12-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.
CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLE
The cumulative effect of change in accounting principle in fiscal 2002
relates to Optiron which adopted SFAS 142 on January 1, 2002, and as a result of
this adoption, realized an impairment and write-down on its books of goodwill
associated with the on-going viability of the product with which the goodwill
was associated. This impairment resulted in a cumulative effect adjustment of
$1.9 million on Optiron's books, and as a result, we recorded our 50% share of
this adjustment.
LIQUIDITY AND CAPITAL RESOURCES
General. We fund our exploration and production operations from a
combination of cash generated by operations, capital raised through drilling
investment partnerships and, if required, use of our credit facility. We fund
our transportation operations, which are conducted through Atlas Pipeline,
through a combination of cash generated by operations, Atlas Pipeline's credit
facility and the sales of Atlas Pipeline's common units. 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 operations............................................ $ 57,314 $ 49,174 $ 5,452
Used in investing activities...................................... (182,084) (28,475) (20,408)
Provided by (used in) financing activities........................ 128,295 (4,249) 2,981
Provided by (used in) discontinued operation...................... 295 - (1,398)
----------- ---------- -----------
Increase (decrease) in cash and cash equivalents.................. $ 3,820 $ 16,450 $ (13,373)
=========== ========== ===========
37
We had $29.2 million in cash and cash equivalents on hand at September
30, 2004, as compared to $25.4 million at September 30, 2003. Our ratio of
earnings from continuing operations before income taxes, minority interest and
interest expense to fixed charges was 14.0 to 1.0 in fiscal 2004 as compared to
13.7 to 1.0 in fiscal 2003. We had working capital deficits of $21.5 million and
$2.2 million at September 30, 2004 and September 30, 2003, respectively. The
decrease in our working capital reflects an increase in our current assets of
$16.9 million, offset by an increase in our current liabilities of $36.2
million. The increase in our current assets is primarily due to an increase in
accounts receivable associated with Spectrum. The increase in our current
liabilities is primarily due to the following:
o an increase in accrued expenses of $14.0 million associated with
natural gas and liquids, ad valorem taxes and hedging liabilities
associated with Spectrum;
o an increase of $7.2 million and $5.4 million in the remaining
amount of our drilling obligations and accrued liabilities related
to our investment partnerships;
o an increase of $6.2 million in our trade accounts payable related
to an increase in drilling activity associated with our drilling
investment partnerships; and
o an increase of $3.3 million in current maturities of long-term
debt related to Atlas Pipeline's borrowings under its credit
facility.
Our long-term debt (including current maturities) was 94% of our total
capital at September 30, 2004 and 36% at September 30, 2003. This increase is
attributable to $60.0 million in borrowings associated with Atlas Pipeline's
acquisition of Spectrum.
In September 2004, the borrowing base under our credit facility was
increased to $75.0 million from $65.0 million. At September 30, 2004, we had
$48.3 million and $72.5 million available on this credit facility and Atlas
Pipeline's credit facility, respectively.
Cash flows from operating activities. Cash provided by operations is an
important source of short-term liquidity for us. It is directly affected by
changes in the price of natural gas and oil, interest rates and our ability to
raise funds from our drilling investment partnerships. Net cash provided by
operating activities increased $8.1 million in fiscal 2004 to $57.3 million from
$49.2 million in fiscal 2003, substantially as a result of the following:
o changes in operating assets and liabilities decreased operating
cash flow by $7.1 million in fiscal 2004, compared to fiscal 2003,
primarily due to payments of accounts payable and accrued
liabilities. Our level of liabilities is dependent upon the
remaining amount of our drilling obligations at any balance sheet
date, which is dependent upon the timing of funds raised through
our drilling investment partnerships;
o an increase in net income before depreciation, depletion and
amortization of $10.4 million in fiscal 2004 as compared to the
prior fiscal year principally a result of higher natural gas
prices and drilling profits;
o an increase in minority interest of $522,000 due to an increase in
Atlas Pipeline's earnings and common units outstanding; and
o non-cash items included in net income which were added back to
cash flows totaled $4.0 million which include $3.0 million of
terminated acquisition costs and $585,000 of losses on derivative
value.
Cash flows from investing activities. Net cash used in our investing
activities increased $153.6 million in fiscal 2004 to $182.1 million from $28.5
million in fiscal 2003 as a result of the following:
o cash used in the acquisition of Spectrum was $141.6 million; and
o capital expenditures increased $13.1 million due to an increase in
the number of wells we drilled.
38
Cash flows from financing activities. Net cash provided by our
financing activities increased $132.5 million in fiscal 2004 to $128.3 million
from cash used of $4.2 million in fiscal 2003, as a result of the following:
o we received proceeds of $37.0 million and $92.7 million from
public offerings of our common stock and Atlas Pipeline's common
units, respectively;
o we made a payment to our parent of $52.1 million in the form of a
non-taxable dividend and received $7.7 million in reimbursements
in fiscal 2004;
o net borrowings increased cash flows by $72.5 million in fiscal
2004, as compared to the prior fiscal year;
o dividends paid to minority interests increased $3.0 million 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; and
o we incurred $3.1 million of debt issuance costs associated with
our new credit facility.
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 facilitate the funding of our capital
expenditures.
We also plan on using borrowings from our credit facility to repay our
current portion of federal income taxes and other net balances due RAI of $10.4
million in fiscal 2005.
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 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. There can be no assurance that
we will be successful in our efforts to obtain outside capital. For a discussion
of limitations on our ability to issue equity or make certain acquisitions or
business combinations, see "-Overview of years ended September 30, 2004, 2003
and 2002."
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.
39
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 year ended September 30, 2004 we paid dividends of $52.1 million
to our Parent. 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.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table summarizes our contractual obligations at September
30, 2004.
Payments Due By Period
(in thousands)
--------------------------------------------------------
Less than 1 - 3 4 - 5 After 5
Contractual cash obligations: Total 1 Year Years Years Years
- ----------------------------- ----- ------ ----- ----- -----
Long-term debt.............................. $ 85,640 $ 3,401 $ 31,203 $ 51,036 $ -
Secured revolving credit facilities......... - - - - -
Operating lease obligations................. 1,184 707 336 139 2
Capital lease obligations................... - - - - -
Unconditional purchase obligations.......... - - - - -
Other long-term obligations................. - - - - -
----------- ----------- ---------- --------- --------
Total contractual cash obligations.......... $ 86,824 $ 4,108 $ 31,539 $ 51,175 $ 2
=========== =========== ========== ========= ========
Payments Due By Period
(in thousands)
-------------------------------------------------------
Other commercial commitments: Less than 1 - 3 4 - 5 After 5
- ----------------------------- Total 1 Year Years Years Years
----- ------ ----- ----- -----
Standby letters of credit................... $ 3,962 $ 3,962 $ - $ - $ -
Guarantees.................................. - - - - -
Standby replacement commitments............. - - - - -
Other commercial commitments................ 2,471 2,471 - - -
----------- ----------- ---------- --------- --------
Total commercial commitments................ $ 6,433 $ 6,433 $ - $ - $ -
=========== =========== ========== ========= ========
40
CRITICAL ACCOUNTING POLICIES
The discussion and analysis of our financial condition and results of
operations are based upon our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States 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 and cost and expenses, and related disclosure of
contingent assets and liabilities. On an on-going basis, we evaluate our
estimates, including those related to the provision for possible losses,
deferred tax assets and liabilities, goodwill and identifiable intangible
assets, and certain accrued liabilities. We base our estimates on historical
experience and on various other assumptions that we believe reasonable under the
circumstances, the results of which form the basis for making judgments about
the carrying values of assets and liabilities that are not readily apparent from
other sources. Actual results may differ from these estimates under different
assumptions or conditions.
We have identified the following policies as critical to our business
operations and the understanding of our results of operations.
Accounts Receivable and Allowance for Possible Losses.
Through our business segments, we engage in credit extension,
monitoring, and collection. 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.
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 SEC, as to natural gas and oil
prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. Any significant variance in these assumptions could
materially affect the estimated quantity of our reserves. As a result, our
estimates of our proved natural gas and oil reserves are inherently imprecise.
Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves may vary substantially from our estimates or
estimates contained in the reserve reports and may affect our ability to pay
amounts due under our credit facilities or cause a reduction in our energy
credit facilities. In addition, our proved reserves may be subject to downward
or upward revision based upon production history, results of future exploration
and development, prevailing natural gas and oil prices, mechanical difficulties,
governmental regulation and other factors, many of which are beyond our control.
41
Impairment of Oil and Gas Properties
We review our producing oil and gas properties for impairment on an
annual basis and whenever events and circumstances indicate a decline in the
recoverability of their carrying values. We estimate the expected future cash
flows from our oil and gas properties and compare such future cash flows to the
carrying amount of the oil and gas properties to determine if the carrying
amount is recoverable. If the carrying amount exceeds the estimated undiscounted
future cash flows, we will adjust the carrying amount of the oil and gas
properties to their fair value in the current period. The factors used to
determine fair value include, but are not limited to, estimates of reserves,
future production estimates, anticipated capital expenditures, and a discount
rate commensurate with the risk associated with realizing the expected cash
flows projected. Because of the complexities associated with oil and gas reserve
estimates and the history of price volatility in the oil and gas markets, events
may arise that will require us to record an impairment of our oil and gas
properties. Any such impairment may affect or cause a reduction in our energy
credit facilities.
Dismantlement, Restoration, Reclamation and Abandonment Costs
On an annual basis, we estimate the costs of future dismantlement,
restoration, reclamation and abandonment of our natural gas and oil-producing
properties. We also estimate the salvage value of equipment recoverable upon
abandonment. On October 1, 2002 we adopted SFAS 143, as discussed in Note 2 to
our consolidated financial statements. As of September 30, 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.
Revenue Recognition
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 we breach our
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.
42
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 using the percentage of completion method. The contracts
are typically completed in less than 60 days. We classify the difference between
the contract payments we have received and the revenue earned as a current
liability, included in liabilities associated with drilling contracts.
We recognize gathering, transmission and processing revenues at the
time the natural gas is delivered to the purchaser.
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 well services revenues.
We record the income from the working interests and overriding
royalties of wells we own an interest in when the gas and oil are delivered.
RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS
In December 2004, the FASB issued Statement No. 123(R) (SFAS 123R)
"Share - Based Payment." SFAS 123R requires that the compensation cost relating
to share-based payment transactions be recognized in financial statements. That
cost will be measured based on the fair value of the equity or liability
instruments issued. SFAS 123R applies to financial statements for interim or
annual periods beginning after June 13, 2005. We are evaluating the impact of
the adoption of 123R.
43
ITEM 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The primary objective of the following information is to provide
forward-looking quantitative and qualitative information about our potential
exposure to market risks. The term "market risk" refers to the risk of loss
arising from adverse changes in interest rates and oil and gas prices. The
disclosures are not meant to be precise indicators of expected future losses,
but rather indicators of reasonable possible losses. This forward-looking
information provides indicators of how we view and manage our ongoing market
risk exposures. All of our market risk sensitive instruments were entered into
for purposes other than trading.
GENERAL
We are exposed to various market risks, principally fluctuating
interest rates and changes in commodity prices. These risks can impact our
results of operations, cash flows and financial position. We manage these risks
through regular operating and financing activities and periodically use
derivative financial instruments such as forward contracts and interest rate cap
and swap agreements.
The following analysis presents the effect on our earnings, cash flows
and financial position as if hypothetical changes in market risk factors
occurred on September 30, 2004. Only the potential impacts of hypothetical
assumptions are analyzed. The analysis does not consider other possible effects
that could impact our business.
Interest Rate Risk. At September 30, 2004, the amount outstanding under
our 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 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 $56,000.
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.
We do not hold or issue derivative instruments for trading purposes.
Historically, we have entered into financial hedging activities for a portion of
our projected natural gas production. We recognize gains and losses from the
settlement of these hedges in gas revenues when the associated production
occurs. The gains and losses realized as a result of hedging are substantially
offset in the market when we deliver the associated natural gas. We determine
gains or losses on open and closed hedging transactions as the difference
between the contract price and a reference price, generally closing prices on
NYMEX. We did not settle any contracts during the year ended September 30, 2004
related to hedging of our natural gas production. We recognized losses of $1.1
million and $59,000 on settled contracts during the years ended September 30,
2003 and 2002, respectively. We had no open hedge transactions related to our
natural gas production in place as of September 30, 2004.
44
FirstEnergy Solutions and other third party marketers to which we sell
gas also use financial hedges to hedge their pricing exposure and make price
hedging opportunities available to us. These transactions are similar to
NYMEX-based futures contracts, swaps and options, but also require firm delivery
of the hedged quantity. Thus, we limit these arrangements to much smaller
quantities than those projected to be available at any delivery point. For the
fiscal year ending September 30, 2005, we estimate in excess of 49% of our
produced natural gas volumes will be sold in this manner, leaving our remaining
production to be sold at contract prices in the month produced or at spot market
prices. We also negotiate with certain purchasers for delivery of a portion of
natural gas we will produce for the upcoming twelve months. The prices under
most of our gas sales contracts are negotiated on an annual basis and are
index-based. Considering those volumes already designated for the fiscal year
ending September 30, 2005, and current indices, a theoretical 10% upward or
downward change in the price of natural gas would result in a change in net
income of approximately $2.5 million.
In Mid-Continent we are exposed to commodity prices 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 either receive 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 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 changes 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 change to annual net income of
approximately $46,000.
In our Mid-Continent business, we entered into certain 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 have floating price
determinants for the buyer priced on certain indices at the end of the relevant
trading period. Options have also been entered that fix the price for the seller
within the puts purchased and calls sold and floating price determinants for the
buyer priced on specified indices 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 NGL
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.
45
As of September 30, 2004, Atlas Pipeline had the following natural gas
liquids, 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)
==========
46
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 our market-sensitive floating
price contracts to fixed-price positions resulted in a $6.0 million liability.
47
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
[THE REMAINDER PAGE INTENTIONALLY LEFT BLANK]
48
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Stockholders and Board of Directors
ATLAS AMERICA, INC.
We have audited the accompanying consolidated balance sheets of Atlas America,
Inc., (a Delaware Corporation) and subsidiaries as of September 30, 2004 and
2003, and the related consolidated statements of income, 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 Atlas America,
Inc. and subsidiaries as of September 30, 2004 and 2003, and the consolidated
results of its 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.
/s/ Grant Thornton LLP
Cleveland, OH
November 22, 2004
49
ATLAS AMERICA, INC.
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30, 2004 AND 2003
2004 2003
---- ----
(in thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents......................................................... $ 29,192 $ 25,372
Accounts receivable .............................................................. 24,113 12,362
Prepaid expenses.................................................................. 2,433 1,131
------------ -----------
Total current assets............................................................ 55,738 38,865
Property and equipment, net.......................................................... 313,091 142,260
Other assets......................................................................... 7,955 5,554
Intangible assets, net............................................................... 7,243 8,239
Goodwill, net of accumulated amortization of $4,532.................................. 37,470 37,470
------------ -----------
$ 421,497 $ 232,388
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term debt................................................. $ 3,401 $ 56
Accounts payable.................................................................. 20,869 14,663
Liabilities associated with drilling contracts.................................... 29,375 22,157
Accrued producer liabilities...................................................... 8,815 -
Accrued liabilities............................................................... 14,767 4,151
------------ -----------
Total current liabilities....................................................... 77,227 41,027
Long-term debt....................................................................... 82,239 31,138
Advances from parent................................................................. 10,413 4,498
Deferred tax liability............................................................... 21,442 21,031
Other liabilities.................................................................... 6,949 3,207
Minority interest.................................................................... 132,224 43,976
Commitments and contingencies........................................................ - -
Stockholders' equity:
Preferred stock, $0.01 par value: 1,000,000 authorized shares.................... - -
Common stock, $0.01 par value: 49,000,000 authorized shares....................... 133 107
Additional paid-in capital........................................................ 75,584 38,619
Accumulated other comprehensive loss.............................................. (2,553) -
Retained earnings................................................................. 17,839 48,785
------------ -----------
Total stockholders' equity...................................................... 91,003 87,511
------------ -----------
$ 421,497 $ 232,388
============ ===========
See accompanying notes to consolidated financial statements
50
ATLAS AMERICA, INC.
CONSOLIDATED STATEMENTS OF INCOME
YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002
2004 2003 2002
---- ---- ----
(in thousands,
except per share data)
REVENUES
Well drilling................................................................ $ 86,880 $ 52,879 $ 55,736
Gas and oil production....................................................... 48,526 38,639 28,916
Gathering, transmission and processing....................................... 36,252 5,901 5,389
Well services................................................................ 8,430 7,634 7,585
Other........................................................................ 768 636 1,670
---------- ---------- -----------
180,856 105,689 99,296
COSTS AND EXPENSES
Well drilling................................................................ 75,548 45,982 48,443
Gas and oil production and exploration....................................... 8,838 8,485 8,264
Gathering, transmission and processing....................................... 27,870 2,444 2,052
Well services................................................................ 4,399 3,774 3,747
General and administrative................................................... 6,076 6,532 6,957
Depreciation, depletion and amortization..................................... 14,700 11,595 10,836
Interest..................................................................... 2,881 1,961 2,200
Terminated acquisition....................................................... 2,987 - -
Minority interest in Atlas Pipeline Partners, L.P............................ 4,961 4,439 2,605
---------- ---------- -----------
148,260 85,212 85,104
---------- ---------- -----------
Income from continuing operations before income taxes and cumulative
effect of change in accounting principle................................. 32,596 20,477 14,192
Provision for income taxes................................................... 11,409 6,757 4,683
---------- ---------- -----------
Income from continuing operations before cumulative effect of
change in accounting principle........................................... 21,187 13,720 9,509
Income (loss) from discontinued operation, net of taxes of $(103) and $883... - 192 (1,641)
Cumulative effect of change in accounting principle, net of taxes of $336.... - - (627)
---------- ---------- -----------
Net income................................................................... $ 21,187 $ 13,912 $ 7,241
========== ========== ===========
NET INCOME (LOSS) PER COMMON SHARE - BASIC:
From continuing operations................................................... $ 1.81 $ 1.28 $ .89
Discontinued operation....................................................... - .02 (.15)
Cumulative effect of change in accounting principle.......................... - - (.06)
---------- ---------- -----------
Net income per common share.................................................. $ 1.81 $ 1.30 $ .68
========== ========== ===========
Weighted average common shares outstanding................................... 11,683 10,688 10,688
========== ========== ===========
NET INCOME (LOSS) PER COMMON SHARE - DILUTED:
From continuing operations................................................... $ 1.81 $ 1.28 $ .89
Discontinued operation....................................................... - .02 (.15)
Cumulative effect of change in accounting principle.......................... - - (.06)
---------- ---------- -----------
Net income per common share.................................................. $ 1.81 $ 1.30 $ .68
========== ========== ===========
Weighted average common shares............................................... 11,684 10,688 10,688
========== ========== ===========
See accompanying notes to consolidated financial statements
51
ATLAS AMERICA, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
YEARS ENDED SEPTEMBER 30, 2004, 2003 AND 2002
2004 2003 2002
---- ---- ----
(in thousands)
Net income.................................................................. $ 21,187 $ 13,912 $ 7,241
Other comprehensive (loss) income:
Unrealized holding losses on hedging contracts, net of tax benefits of
$1,384, $245 and $118..................................................... (2,571) (520) (264)
Less: reclassification adjustment for losses realized in net income,
net of taxes of $10, $355 and $17........................................ 18 753 42
---------- ---------- ----------
(2,553) 233 (222)
---------- ---------- ----------
Comprehensive income........................................................ $ 18,634 $ 14,145 $ 7,019
========== ========== ==========
See accompanying notes to consolidated financial statements
52
ATLAS AMERICA, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
YEARS ENDED SEPTEMBER 30, 2004, 2003, AND 2002
(IN THOUSANDS, EXCEPT SHARE DATA)
Accumulated
Additional Other Total
Common Stock Paid-In Comprehensive Retained Stockholders'
Shares Amount Capital Income (Loss) Earnings Equity
------ ------ ------- ------------- -------- ------
Balance, October 1, 2001 (after
giving retroactive effect to a
106,883.33 for 1 stock split
on February 27, 2004)..................... 10,688,333 $ 107 $ 38,619 $ (11) $ 27,632 $ 66,347
Other comprehensive loss.................... - - - (222) - (222)
Net income.................................. - - - - 7,241 7,241
- ----------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2002................. 10,688,333 $ 107 $ 38,619 $ (233) $ 34,873 $ 73,366
Other comprehensive income.................. - - - 233 - 233
Net income.................................. - - - - 13,912 13,912
- ----------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2003................. 10,688,333 $ 107 $ 38,619 $ - $ 48,785 $ 87,511
Initial public offering, net
of costs................................. 2,645,000 26 36,965 - - 36,991
Dividend to parent.......................... - - - - (52,133) (52,133)
Other comprehensive loss.................... - - - (2,553) - (2,553)
Net income.................................. - - - - 21,187 21,187
- ----------------------------------------------------------------------------------------------------------------------------------
Balance, September 30, 2004................. 13,333,333 $ 133 $ 75,584 $ (2,553) $ 17,839 $ 91,003
========== ======= ============= ========= ========= ===========
See accompanying notes to consolidated financial statements
53
ATLAS 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................................................................. $ 21,187 $ 13,912 $ 7,241
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization................................ 14,700 11,595 10,836
Amortization of deferred finance costs.................................. 704 560 310
Non-cash loss on derivative value....................................... 585 - -
Non-cash compensation on long-term incentive plans...................... 407 - -
Terminated acquisition.................................................. 2,987 - -
(Income) loss on discontinued operation................................. - (192) 1,641
Cumulative effect of change in accounting principle..................... - - 627
Minority interest in Atlas Pipeline Partners, L.P....................... 4,961 4,439 2,605
Gain on asset dispositions.............................................. (39) (14) (411)
Changes in operating assets and liabilities................................ 11,822 18,874 (17,397)
---------- ---------- ----------
Net cash provided by operating activities of continuing operations......... 57,314 49,174 5,452
CASH FLOWS FROM INVESTING ACTIVITIES:
Business acquisition, net of cash acquired................................. (141,564) - -
Capital expenditures....................................................... (41,162) (28,029) (21,291)
Proceeds from sale of assets............................................... 405 182 721
Decrease (increase) in other assets........................................ 237 (628) 162
---------- ---------- ----------
Net cash used in investing activities of continuing operations............. (182,084) (28,475) (20,408)
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings................................................................. 183,532 68,384 159,329
Principal payments on borrowings........................................... (129,319) (86,694) (153,268)
Issuance of Atlas Pipeline Partners, L.P. common units..................... 92,714 25,182 -
Issuance of common stock................................................... 36,991 - -
Dividend to parent......................................................... (52,133) - -
Advances from (payments to) parent......................................... 7,702 (5,755) 1,546
Distributions paid to minority interest of Atlas Pipeline Partners, L.P.... (7,271) (4,233) (3,623)
Increase in other assets................................................... (3,921) (1,133) (1,003)
---------- ---------- ----------
Net cash provided by (used in) financing activities........................ 128,295 (4,249) 2,981
---------- ---------- ----------
Net cash provided by (used by) discontinued operation...................... 295 - (1,398)
---------- ---------- ----------
Increase (decrease) in cash and cash equivalents........................... 3,820 16,450 (13,373)
Cash and cash equivalents at beginning of year............................. 25,372 8,922 22,295
---------- ---------- ----------
Cash and cash equivalents at end of year................................... $ 29,192 $ 25,372 $ 8,922
========== ========== ==========
See accompanying notes to consolidated financial statements
54
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2004
NOTE 1 -- NATURE OF OPERATIONS
Atlas America, Inc. (the "Company" or "AAI and its subsidiaries") was
incorporated in Delaware on September 27, 2000 as a wholly-owned subsidiary of
Atlas Energy Holdings, Inc., which is a subsidiary of Resource America, Inc.
("RAI" or "parent"). RAI is a publicly traded company (NASDAQ: REXI) operating
in the structured finance, equipment leasing, real estate and energy sectors. In
May 2004, the Company completed an initial public offering of 2,645,000 shares
of its common stock at a price of $15.50 per common share including
underwriters' over allotment. The net proceeds of the offering of $37.0 million,
after deducting underwriting discounts and costs, were distributed to RAI in the
form of a non-taxable dividend. The Company trades under the symbol ATLS on the
NASDAQ system. Following the offering, RAI owns approximately 80.2% of the
Company's outstanding common stock.
The Company is an energy company which sponsors drilling partnerships
and 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") (NYSE:
APL), 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. Through its acquisition of Spectrum Field
Services, Inc. ("Spectrum" or "Mid-Continent") in July 2004, Atlas Pipeline
processes and transports natural gas and natural gas liquids ("NGLs") in
Oklahoma and Texas.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the
Company and its subsidiaries, all of which are wholly-owned except for Atlas
Pipeline. In accordance with established practice in the oil and gas industry,
the Company includes its pro-rata share of assets, liabilities, revenues, and
costs and expenses of the energy partnerships in which the Company has an
interest. 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.
RECLASSIFICATIONS
Certain reclassifications have been made to the fiscal 2003 and fiscal
2002 consolidated financial statements to conform to the fiscal 2004
presentation.
55
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
STOCK-BASED COMPENSATION
The Company accounts for its employees' participation in RAI's 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 exceeds 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."
SFAS 123 requires the disclosure of pro forma net income and earnings
per share as if the Company had adopted the fair value method for stock options
granted after June 30, 1996. Under SFAS 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 RAI's stock option awards. These models also require subjective
assumptions, including future stock price volatility and expected time to
exercise, which greatly affect the calculated values. The Company's calculations
were made using the Black-Scholes option pricing model with the following
weighted average assumptions: expected life, 10 years following vesting; stock
volatility, 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 RAI's historical rate.
No stock-based employee compensation cost is reflected in the Company's
net income, as all options granted under the RAI plans in which the Company's
employees participate (see Note 8) had an exercise price equal to the market
value of the underlying common stock on the date of grant. The following table
illustrates the effect on net income 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, as reported................................................... $ 21,187 $ 13,912 $ 7,241
Less total stock-based employee compensation expense
determined under the fair value based method for all awards, net
of income taxes........................................................ (378) (377) (394)
----------- ----------- -----------
Pro forma net income...................................................... $ 20,809 $ 13,535 $ 6,847
=========== =========== ===========
Earnings per share:
Basic and diluted- as reported......................................... $ 1.81 $ 1.30 $ .68
Basic and diluted- pro forma........................................... $ 1.78 $ 1.27 $ .64
56
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
IMPAIRMENT OF LONG-LIVED ASSETS
The Company reviews its long-lived assets for impairment annually or
whenever events or circumstances indicate that the carrying amount of an asset
may not be recoverable. If it is determined that an asset's estimated future
cash flows will not be sufficient to recover its carrying amount, an impairment
charge will be required to reduce the carrying amount for that asset to its
estimated fair value.
EARNINGS PER SHARE
Basic earnings per share are determined by dividing net income by the
weighted average number of shares of common stock outstanding during the period.
Earnings per share - diluted is computed by dividing net income by the sum of
the weighted average number of shares of common stock outstanding and dilutive
potential shares issuable from the 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 per share for the periods
indicated are as follows:
Years Ended September 30,
-----------------------------------------
2004 2003 2002
---- ---- ----
(in thousands)
Income from continuing operations......................................... $ 21,187 $ 13,720 $ 9,509
Income (loss) from discontinued operation, net of taxes................... - 192 (1,641)
Cumulative effect of change in accounting principle,
net of taxes.......................................................... - - (627)
---------- ---------- ----------
Net income................................................................ $ 21,187 $ 13,912 $ 7,241
========== ========== ==========
Weighted average common shares outstanding-basic.......................... 11,683 10,688 10,688
Dilutive effect of stock option and award plans........................... 1 - -
---------- ---------- ----------
Weighted average common shares-diluted.................................... 11,684 10,688 10,688
========== ========== ==========
COMPREHENSIVE INCOME (LOSS)
Comprehensive income (loss) includes net income (loss) and all other
changes in the equity of a business during a period from transactions and other
events and circumstances from non-owner sources. These changes, other than net
income (loss), are referred to as "other comprehensive income (loss)" and for
the Company only includes changes in the fair value, net of taxes, of unrealized
hedging gains and losses.
57
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
RECEIVABLES
In evaluating its allowance for possible losses, the Company performs
ongoing credit evaluations of its customers and adjusts credit limits based upon
payment history and the customer's current creditworthiness, as determined by
the Company's review of its customer's credit information. The Company extends
credit on an unsecured basis to many of its energy customers. At September 30,
2004, the Company's credit evaluation indicated that it has no need for an
allowance for possible losses.
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....................................... 7,213 3,984
Support equipment..................................................... 2,902 2,189
Other................................................................. 4,227 3,365
----------- -----------
379,938 195,121
Accumulated depreciation, depletion and amortization:
Oil and gas properties............................................ (63,551) (50,170)
Other (3,296) (2,691)
----------- -----------
(66,847) (52,861)
----------- -----------
$ 313,091 $ 142,260
=========== ===========
58
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (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 the estimated cash
flows of the property.
Upon the sale or retirement of a complete or partial unit of a proved
property, the cost is eliminated from the property accounts, and the resultant
gain or loss is reclassified to accumulated depletion. 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 statements of
income. 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.
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.
59
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
ASSET RETIREMENT OBLIGATIONS
Effective October 1, 2002, the Company adopted SFAS No. 143,
"Accounting for Asset Retirement Obligations" ("SFAS 143") which requires the
Company to recognize an estimated liability for the plugging and abandonment of
its oil and gas wells and associated pipelines and equipment. Under SFAS 143,
the Company must currently recognize a liability for future asset retirement
obligations if a reasonable estimate of the fair value of that liability can be
made. The present values of the expected asset retirement costs are capitalized
as part of the carrying amount of the long-lived asset. SFAS 143 requires the
Company to consider estimated salvage value in the calculation of 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 income.
The Company has no assets legally restricted for purposes of settling
asset retirement obligations. Except for the item previously referenced, the
Company has determined that there are no other material retirement obligations
associated with tangible long-lived assets.
A reconciliation of the Company's liability for well plugging and
abandonment costs for the periods indicated is as follows:
Years Ended September 30,
-------------------------------
2004 2003
---- ----
(in thousands)
Asset retirement obligations, beginning of year...................... $ 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 year............................ $ 4,888 $ 3,131
========== ========
60
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
ASSET RETIREMENT OBLIGATIONS - (CONTINUED)
The above accretion expense is included in depreciation, depletion and
amortization in the Company's consolidated statements of income and the asset
retirement obligation liabilities are included in other liabilities in the
Company's consolidated balance sheets.
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 secured revolving credit facilities and all other 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.
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.
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 $34.0 million in deposits at various banks, of which $33.2
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.
61
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
REVENUE RECOGNITION
The Company conducts certain energy activities through, and a portion
of its revenues are attributable to, sponsored energy limited partnerships. 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 revenue earned as a current liability.
The Company recognizes gathering, transmission and processing revenues
at the time the natural gas and liquids are delivered.
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 well services 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.
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 FOR:
Interest............................................................ $ 2,114 $ 1,591 $ 1,730
Income taxes (refunded) paid........................................ $ (220) $ 359 $ (301)
NON-CASH INVESTING ACTIVITIES INCLUDE THE FOLLOWING:
Fair value of assets acquired................................... $ 160,799 $ - $ -
Liabilities assumed............................................. (19,235) - -
---------- ---------- ----------
Net cash paid................................................. $ 141,564 $ - $ -
========== ========== ==========
62
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -- (CONTINUED)
INCOME TAXES
The Company is included in the consolidated federal income tax return
of RAI. Income taxes are calculated as if the Company had filed a return on a
separate company basis. 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. Separate
company state tax returns are filed in those states in which the Company is
registered to do business.
NOTE 3 -- 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
$1,080 and $1,091..................................................... $ 4,704 $ 1,548
Investments .............................................................. 2,166 2,974
Other..................................................................... 1,085 1,032
---------- ----------
$ 7,955 $ 5,554
========== ==========
Deferred financing costs are amortized over the terms of the related
loans.
INTANGIBLE ASSETS
Intangible assets consist of partnership management and operating
contracts acquired through acquisitions and 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. 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 $836,000 for each of the succeeding five years.
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
Accumulated amortization.................................................. (7,100) (6,104)
---------- ----------
Intangible assets, net.................................................... $ 7,243 $ 8,239
========== ==========
63
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 3 -- OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL
GOODWILL
On October 1, 2001, the Company adopted SFAS No. 142 ("SFAS 142")
"Goodwill and Other Intangible Assets," which requires that goodwill no longer
be amortized, but instead evaluated for impairment at least annually. The
Company performs such annual evaluation and will reflect the impairment of
goodwill, if any, in operating income in the statements of income in the period
in which the impairment is indicated.
NOTE 4 -- CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
In the ordinary course of its business operations, the Company has
ongoing relationships with several related entities:
Relationship with Company Sponsored Partnerships. The Company conducts
certain activities through, and a substantial portion of its revenues are
attributable to, energy limited partnerships ("Partnerships"). The Company
serves as general partner of the Partnerships and assumes customary rights and
obligations for the Partnerships. As the general partner, the Company is liable
for Partnership liabilities and can be liable to limited partners if it breaches
its responsibilities with respect to the operations of the Partnerships. The
Company is entitled to receive management fees, reimbursement for administrative
costs incurred, and to share in the Partnerships' revenue, and costs and
expenses according to the respective Partnership agreements.
Relationship with RAI. As part of the Company's initial public
offering, it entered into certain separation and distribution agreements with
RAI which contain the key provisions related to the Company's separation from
RAI and the proposed distribution of its shares to RAI's common stockholders.
The advances from RAI represent amounts owed for income taxes, advances
and transactions in the normal course of business. These advances, which are
non-interest bearing, have no repayment terms and are subordinated to the
Company's $75.0 million revolving credit facility (See Note 6).
64
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 4 -- CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (CONTINUED)
The Company reimburses RAI for all direct and indirect costs of
services provided. For the years ended September 30, 2004, 2003 and 2002, such
reimbursements were approximately $1.1 million, $1.4 million, and $1.2 million,
respectively, representing the allocable portion of the personnel costs of RAI
employees, including executives, for time spent on the Company's business.
Relationship with Ledgewood Law Firm ("Ledgewood"). Until April 1996,
Edward E. Cohen ("E. Cohen"), the Company's Chairman of the Board, Chief
Executive Officer and President, was of counsel to Ledgewood. E. Cohen receives
certain debt service payments from Ledgewood related to the termination of his
affiliation with Ledgewood and its redemption of his interest. The Company paid
Ledgewood $490,400, $248,400 and $106,100 during fiscal 2004, 2003 and 2002,
respectively, for legal services rendered to the Company.
NOTE 5 - DERIVATIVE INSTRUMENTS
The Company 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.
65
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 5 - DERIVATIVE INSTRUMENTS - (CONTINUED)
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 these cash flow hedges.
In connection with the acquisition of Spectrum, Atlas Pipeline acquired
and/or entered into certain financial swap instruments, some of which settled
during the year 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, natural gas
liquids 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 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 the year ended
September 30, 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 related to the acquired Spectrum operations
during 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)
=========
66
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 5 - DERIVATIVE INSTRUMENTS - (CONTINUED)
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 liability $ (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 included 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.
67
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 6 -- DEBT
Total debt consists of the following at the dates indicated:
At September 30,
---------------------------
2004 2003
---- ----
(in thousands)
Revolving credit facility............................................ $ 25,000 $ 31,000
Term loan............................................................ 60,000 -
Other debt........................................................... 640 194
---------- ----------
85,640 31,194
Less current maturities.............................................. 3,401 56
---------- ----------
$ 82,239 $ 31,138
========== ==========
Revolving Credit Facility. The Company 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 the Company's oil and gas reserves. The facility permits draws
based on the remaining proved developed non-producing and proved undeveloped
natural gas and oil reserves attributable to the Company's wells and the
projected fees and revenues from operation of its wells and the administration
of energy partnerships. This facility is guaranteed by RAI as long as it
continues to own more than 80% of the Company. Up to $10.0 million of the
facility may be in the form of standby letters of credit. The facility is
secured by the Company'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 the adjusted London Interbank Offered Rate ("LIBOR") plus the
applicable margin elected at the Company's option.
The base rate for 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 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 the Company 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 the Company to RAI, on a cumulative basis, to 50% of the Company's
net income from January 1, 2004 to the date of determination plus $5.0 million.
In addition, the Company is permitted to repay intercompany debt to RAI only up
to the amount of the Company's federal income tax liability. 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 million,
respectively, under letters of credit. The interest rates ranged from 3.59% to
5.0% at September 30, 2004.
68
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 6 -- DEBT - (CONTINUED)
Atlas Pipeline 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 are 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 .50% or the Wachovia prime rate. Adjusted LIBOR is LIBOR divided by 1.0
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 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 .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 must 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 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.
Annual debt principal payments over the next five fiscal years ending
September 30 are as follows (in thousands):
2005.................. $ 3,401
2006.................. 3,120
2007.................. 28,083
2008.................. 3,036
2009.................. 48,000
At September 30, 2004, the Company has complied with all financial
covenants in its debt agreements.
69
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 7 -- INCOME TAXES
The following table details the components of the Company's provision
for 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............................................................. $ 9,070 $ 5,069 $ 5,454
State............................................................... 553 60 39
Deferred............................................................... 1,786 1,628 (810)
---------- ---------- ----------
$ 11,409 $ 6,757 $ 4,683
========== ========== ==========
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) (3)
Non-conventional fuel credit.............................................. - (1) (1)
State income taxes, net of federal tax benefit............................ 1 1 2
--- --- ---
35% 33% 33%
=== === ===
The components of the Company's net deferred tax liability are as
follows:
September 30,
-------------------------
2004 2003
---- ----
(in thousands)
Deferred tax assets related to:
Unrealized loss on hedging contracts................................... $ 1,374 $ -
Accrued liabilities.................................................... 730 434
Statutory depletion carryforward....................................... 566 -
---------- ---------
2,670 434
---------- ---------
Deferred tax liabilities related to:
Property and equipment bases differences............................... (20,138) (15,601)
Other, net............................................................. (3,974) (5,864)
---------- ---------
(24,112) (21,465)
---------- ---------
Net deferred tax liability................................................ $ (21,442) $ (21,031)
========== =========
The Company's liability for its share of federal income taxes payable
is included in advances from parent in the Company's consolidated balance
sheets.
70
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 7 -- INCOME TAXES -- (CONTINUED)
SFAS No. 109, "Accounting for Income Taxes", requires 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.
NOTE 8 -- BENEFIT PLANS
Stock Incentive Plan. The Company adopted a Stock Incentive Plan in
fiscal 2004 which authorized the granting of up to 1,333,333 shares of the
Company's common stock to employees, affiliates, consultants and directors of
the Company in the form of incentive stock options ("ISOs"), non-qualified stock
options, stock appreciation rights ("SARs"), restricted stock and deferred
units. No stock options, SARs or restricted stock has been issued under the
Plan. In fiscal 2004, 4,835 deferred units were granted to non-employee
directors of the Company. 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 (at an
average price of $15.50 per unit), $75,000 in total, is being charged to
operations over the four-year vesting period.
Under the Plan, on an annual basis, non-employee directors of the
Company are awarded deferred units having a fair market value of $15,000. Each
unit represents the right to receive one share of the Company's common stock
upon vesting. The shares vest one-third on the second anniversary of the grant,
one-third on the third anniversary of the grant and one-third on the fourth
anniversary of the grant, except that no units can vest before the date the
spin-off is completed or abandoned.
The following table summarizes certain information about the Company's
Stock Incentive Plan as of September 30, 2004.
- ------------------------------------------------------------------------------------------------------------------------
(a) (b) (c)
- ------------------------------------------------------------------------------------------------------------------------
Number of securities remaining
Number of securities to be Weighted-average exercise available for future issuance
issued upon exercise of price of outstanding under equity compensation plans
outstanding options, options, warrants excluding securities reflected
Plan category warrants and rights and rights in column (a)
- ------------------------------------------------------------------------------------------------------------------------
Equity compensation plans
approved by security
holders 4,835 $ - 1,328,498
- ------------------------------------------------------------------------------------------------------------------------
71
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 8 -- BENEFIT PLANS - (CONTINUED)
Supplemental Employment Retirement Plan ("SERP"). In May 2004, the
Company entered into an employment agreement with its Chairman of the Board,
Chief Executive Officer and President, Edward E. Cohen, pursuant to which the
Company has agreed to provide him with a SERP and with certain financial
benefits upon termination of his employment. Under the SERP, Mr. Cohen 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 the Company, multiplied by, (c) the amount of years he shall be
employed by the Company commencing upon the effective date of the SERP
agreement, limited to an annual maximum benefit of 65% of his final base salary
and a minimum of 26% of his final base salary. During fiscal 2004, operations
were charged $59,500 with respect to this commitment.
Atlas Pipeline Plan. 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 fiscal 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 fiscal year ended September 30, 2004 was $37.16.
In connection with the acquisition of Atlas in September 1998, RAI
issued options for 120,213 shares at an exercise price of $0.11 per share to
certain employees of the Company who had held options of The Atlas Group, Inc.
before its acquisition by RAI. Options for 33,700 shares remain outstanding and
are exercisable as of September 30, 2004.
RAI BENEFIT PLANS
The Company's employees participate in RAI's employee savings plan and
four employee stock option plans are described as follows:
Employee Savings Plan. RAI 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, RAI 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 $179,000, $164,000 and $202,000 for the Company's contributions for
the years ended September 30, 2004, 2003 and 2002, respectively.
Stock Option Plans. RAI 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 1997 Key Employee Stock Option Plan authorized the granting of up
to 825,000 shares of RAI's common stock in the form of ISOs, non-qualified stock
options and SARs. No options were issued to the Company's employees under this
plan during fiscal 2004 and 2003.
The 1999 Key Employee Stock Option Plan authorized the granting of up
to 1.0 million shares of RAI'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 10,000 shares were issued under this
plan to the Company's employees.
72
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 8 -- BENEFIT PLANS - (CONTINUED)
In April 2002, RAI's stockholders approved the 2002 Key Employee Stock
Option Plan. This plan, for which 750,000 shares were reserved, provides for the
issuance of ISO's, non-qualified stock options and SAR's. Options allocated to
the Company from RAI for the fiscal years 2004, 2003 and 2002 were 645,057, 0
and 75,500 shares, respectively.
Associated with the above RAI plans, in May 2004, as a result of the
Company's initial public offering, 645,057 shares were allocated to the Company
based on which segment the applicable employee was assigned to.
Transactions under RAI's four employee stock option plans in which the
Company's employees participate 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.... 226,447 $ 10.73 281,666 $ 11.55 209,927 $ 12.86
Granted......................... 645,057 (1) $ 10.56 - $ - 75,500 $ 7.91
Exercised....................... (55,698) $ 5.88 - $ - - $ -
Cancelled....................... (15,500) (2) $ 9.85 - $ - - $ -
Forfeited....................... (4,186) $ 10.17 (55,219) $ 14.94 (3,761) $ 11.06
-------- -------- -------- -------- -------- --------
Outstanding - end of year.......... 796,120 $ 10.95 226,447 $ 10.73 281,666 $ 11.55
======== ======== ======== ======== ======== ========
Exercisable, at end of year........ 603,580 $ 11.64 116,224 $ 11.91 97,542 $ 13.97
======== ======== ======== ======== ======== ========
Available for grant................ 232,124 (3) 227,688 (3) 86,719 (3)
======== ======== ========
Weighted average fair value per
share of options granted
during the year................. $ - $ - $ 5.93
======== ======== ========
- ------------------
(1) Represents shares of certain officers allocated to the Company during the
fiscal year as a result of the Company's initial public offering in May
2004.
(2) Represents shares of certain employees transferred to RAI.
(3) Represents shares available under RAI's plans available to eligible
employees of RAI and its subsidiaries, including the Company's.
73
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 8 -- BENEFIT PLANS - (CONTINUED)
The following information applies to employee stock options outstanding
attributable to the Company's employees as of September 30, 2004:
Outstanding Exercisable
--------------------------------------------- ----------------------------
Weighted
Average Weighted Weighted
Range of Contractual Average Average
Exercise prices Shares Life (Years) Exercise Price Shares Exercise Price
- --------------- ------ ------------ -------------- ------ --------------
$ 2.73 46,349 1.22 $ 2.73 46,349 $ 2.73
$ 7.71 - $ 9.19 254,250 7.86 $ 7.73 123,500 $ 7.71
$ 11.03 - $ 11.06 236,877 6.33 $ 11.06 175,087 $ 11.06
$ 15.50 258,644 4.64 $ 15.50 258,644 $ 15.50
--------- ---------
796,120 603,580
========= =========
NOTE 9 -- COMMITMENTS AND CONTINGENCIES
The Company leases office space and equipment under leases with varying
expiration dates through 2014. Rental expense was $1.1 million, $1.6 million and
$1.4 million for the years ended September 30, 2004, 2003 and 2002,
respectively. Future minimum rental commitments for the next five fiscal years
are as follows (in thousands):
2005............................ $ 707
2006............................ 259
2007............................ 77
2008............................ 77
2009............................ 62
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 from the energy partnerships 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 compensation and certain other benefits. The agreements also
provide for severance payments under certain circumstances.
74
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 9 -- COMMITMENTS AND CONTINGENCIES - (CONTINUED)
The Company is a defendant in a proposed class action originally filed
in February 2000 in the New York Supreme Court, Chautauqua County, by
individuals, putatively on their own behalf and on behalf of similarly situated
individuals, who leased property to the Company. The complaint alleges that the
Company is not paying lessors the proper amount of royalty revenues derived from
the natural gas produced from the wells on the leased property. The complaint
seeks damages in an unspecified amount for the alleged difference between the
amount of royalties actually paid and the amount of royalties that allegedly
should have been paid. The Company believes the complaint is without merit and
is defending itself vigorously. The plaintiffs were certified as a class in
December 2003. An appeal of that certification is pending. The action is
currently in its discovery stage.
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 results of operations.
NOTE 10 -- DISCONTINUED OPERATION AND CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE
DISCONTINUED OPERATION
In June 2002, the Company adopted a plan to dispose of its 50% interest
in Optiron Corporation ("Optiron"), an energy technology subsidiary. The Company
subsequently reduced its interest to 10% through a sale to management that 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
$295,200 to the Company in March 2004.
In accordance with SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-lived Assets,", the results of operations have been prepared
under the financial reporting requirements for discontinued operations, pursuant
to which, all historical results of Optiron are included in the results of
discontinued operations rather than the results of continuing operations for all
periods presented.
Summarized operating results of the discontinued Optiron operation are
as follows:
Years Ended September 30,
-----------------------------------------
2004 2003 2002
---- ---- ----
(in thousands)
Loss from discontinued operation before taxes................................ $ - $ - $ (553)
Income tax benefit........................................................... - - 193
---------- ---------- ----------
Loss from discontinued operations............................................ $ - $ - $ (360)
========== ========== ==========
Income (loss) on disposal of discontinued operation before taxes............. $ - $ 295 $ (1,971)
Income tax (provision) benefit............................................... - (103) 690
---------- ---------- ----------
Income (loss) on disposal of discontinued operation.......................... $ - $ 192 $ (1,281)
========== ========== ==========
Total gain (loss) on discontinued operations................................. $ - $ 192 $ (1,641)
========== ========== ==========
75
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 10 -- DISCONTINUED OPERATION AND CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE - (CONTINUED)
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE
Optiron adopted SFAS 142 on January 1, 2002, the first day of its
fiscal year. Optiron performed the evaluation of its goodwill required by SFAS
142 and determined that it was impaired due to uncertainty associated with the
on-going viability of the product line with which the goodwill was associated.
This impairment resulted in a cumulative effect adjustment on Optiron's books of
$1.9 million before tax. The Company recorded its 50% share of this cumulative
effect adjustment in fiscal 2002.
NOTE 11 -- 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.
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.
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.
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.
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, Atlas Pipeline is consolidated in the Company's
financial statements.
76
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 12 -SPECTRUM ACQUISITION BY ATLAS PIPELINE
On July 16, 2004, the Atlas Pipeline acquired Spectrum, 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 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 (Note 6);
o using the $20.0 million of proceeds received from the sale to RAI
and the Company of preferred units in Atlas Pipeline Operating
Partnership; and
o using $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 RAI and the Company
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.
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
allocations are both subject to adjustment.
The results of operations of Spectrum are included in the Company's
consolidated statements of income from July 16, 2004, the date of the
acquisition.
77
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 12 -SPECTRUM ACQUISITION BY ATLAS PIPELINE- (CONTINUED)
The following summarized unaudited pro forma information for the years
ended September 30, 2004 and 2003 assumes that the 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 Pro
As Reported Adjustments Forma
----------- ----------- -----
Revenues...................................................... $ 180,856 $ 91,795 $ 272,651
Net income.................................................... $ 21,187 $ 2,753 $ 23,940
Net income per common share - basic........................... $ 1.81 $ 0.23 $ 2.04
Weighted average common shares outstanding - basic............ 11,683 - 11,683
Net income per common share - diluted......................... $ 1.81 $ 0.23 $ 2.04
Weighted average common shares - diluted...................... 11,684 - 11,684
Year Ended
September 30, 2003
------------------------------------------------
Pro Forma Pro
As Reported Adjustment Forma
----------- ---------- -----
Revenues...................................................... $ 105,689 $ 98,488 $ 204,177
Net income.................................................... $ 13,912 $ 1,412 $ 15,324
Net income per common share - basic........................... $ 1.30 $ .13 $ 1.43
Weighted average common shares outstanding - basic............ 10,688 - 10,688
Net income per common share - diluted......................... $ 1.30 $ .13 $ 1.43
Weighted average common shares - diluted...................... 10,688 - 10,688
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.
78
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 13 -- OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS
The Company's operations include four reportable operating segments. In
addition to the reportable operating segments, certain other activities are
reported in the "Other energy" category. These operating segments reflect the
way the Company manages its operations and makes business decisions.
Mid-Continent and Appalachia are two segments within gathering, transmission and
processing that the Company evaluates separately. 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):
Other
Revenues from Depreciation, significant
external Interest Interest depletion and Segment items:
customers income expense amortization profit (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(a) 9,198 250 2,878 1,744 (8,473) 35,999
-------- --------- ----------- -------- -------- --------
Total $180,856 $ 250 $ 2,881 $ 14,700 $ 32,596 $421,497
======== ========= =========== ======== ======== ========
YEAR ENDED SEPTEMBER 30, 2003 (in thousands):
Revenues from Depreciation, significant
external Interest Interest depletion and Segment items:
customers income expense amortization profit (loss) Segment assets
--------- ------ ------- ------------ ------------- --------------
Well drilling $ 52,879 $ - $ - $ - $ 5,320 $ 7,844
Production and exploration 38,639 - - 8,042 21,280 145,614
Mid- Continent - - - - - -
Appalachia 5,901 - - 1,657 175 30,735
Other(a) 8,270 220 1,961 1,896 (6,298) 48,195
-------- --------- ----------- -------- -------- --------
Total $105,689 $ 220 $ 1,961 $ 11,595 $ 20,477 $232,388
======== ========= =========== ======== ======== ========
YEAR ENDED SEPTEMBER 30, 2002 (in thousands):
Other
Revenues from Depreciation, significant
external Interest Interest depletion and Segment items:
customers income expense amortization profit (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(a) 9,255 686 2,200 1,882 (5,083) 37,951
-------- --------- ----------- -------- -------- --------
Total $ 99,296 $ 686 $ 2,200 $ 10,836 $ 14,192 $192,614
======== ========= =========== ======== ======== ========
- -----------------
(a) Includes revenues and expenses from well services which does not meet the
quantitative threshold for reporting segment information and general
corporate expenses not allocable to any particular segment.
79
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 13 -- OPERATING SEGMENT INFORMATION AND MAJOR CUSTOMERS - (CONTINUED)
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 FirstEnergy
Solutions Corp. accounted for 11%, 18% and 16%, respectively, of total revenues.
No other operating segments had revenues from a single customer which exceeded
10% of total revenues.
NOTE 14 - TERMINATED ALASKA PIPELINE 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. 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
on the Company's statement of income.
NOTE 15 -- 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
========== ========== ==========
80
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 15 -- SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)
Capitalized Costs Related to Oil and Gas Producing Activities. The
components of capitalized costs related to the Company's oil and gas producing
activities are as follows:
At September 30,
-----------------------------------------
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 well 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
=========== =========== ===========
The development costs above 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
Financial Accounting Standards Board which require that reserve estimates be
prepared under existing economic and operating conditions with no provisions for
price and cost escalation except by contractual arrangements.
81
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 15 -- SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)
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
and natural gas, and NGLs, that may be recovered from oil shales,
coal, gilsonite and other such sources.
Proved developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and operation
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
There are numerous uncertainties inherent in estimating quantities of
proven reserves and in projecting future net revenues and the timing of
development expenditures. The reserve data presented represents estimates only
and should not be construed as being exact. In addition, the standardized
measures of discounted future net cash flows may not represent the fair market
value of the Company's oil and gas reserves or the present value of future cash
flows of equivalent reserves, due to anticipated future changes in oil and gas
prices and in production and development costs and other factors for effects
have not been proved.
82
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 15 -- SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED)
The Company's reconciliation of changes in proved reserve quantities is
as follows (unaudited):
Gas Oil
(Mcf) (Bbls)
------------- -------------
Balance September 30, 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
83
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 15 -- 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 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.
84
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 15 -- 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
=========== =========== ===========
85
ATLAS AMERICA, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
SEPTEMBER 30, 2004
NOTE 16 -- QUARTERLY RESULTS (UNAUDITED)
December 31 March 31 June 30 September 30
----------- -------- ------- ------------
(in thousands, except per share data)
YEAR ENDED SEPTEMBER 30, 2004
Revenues......................................... $ 35,859 $ 42,080 $ 32,947 $ 69,970
============ ============ ============ ============
Income from continuing operations before income
taxes......................................... $ 7,528 $ 7,713 $ 6,668 $ 10,687
============ ============ ============ ============
Net income....................................... $ 4,893 $ 5,166 $ 4,182 $ 6,946
============ ============ ============ ============
Net income per common share - basic and diluted.. $ .46 $ .48 $ .35 $ .52
============ ============ ============ ============
December 31 March 31 June 30 September 30
----------- -------- ------- ------------
(in thousands, except per share data)
YEAR ENDED SEPTEMBER 30, 2003
Revenues......................................... $ 18,135 $ 36,474 $ 21,867 $ 29,213
============ ============ ============ ============
Income from continuing operations before
income taxes.................................. $ 3,003 $ 6,348 $ 3,872 $ 7,254
============ ============ ============ ============
Discontinued operation, net of tax............... $ - $ - $ - $ 192
============ ============ ============ ============
Net income....................................... $ 2,012 $ 4,254 $ 2,557 $ 5,089
============ ============ ============ ============
Net income per common share - basic and diluted:
From continuing operations....................
$ .19 $ .40 $ .24 $ .45
Discontinued operation........................ - - - .02
------------ ------------ ------------ ------------
Net income per common share...................... $ .19 $ .40 $ .24 $ .47
============ ============ ============ ============
86
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 are Exchange Commission ("SEC") 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 the disclosure committee of our
parent, 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 is reasonably likely to
materially affect, our internal control over financial reporting during our most
recent fiscal quarter.
ITEM 9B. OTHER INFORMATION
None.
87
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Members of our board of directors serve for terms of one year, or until
their successors are appointed or elected. Information is set forth below
regarding the principal occupation of each of our directors. The following table
sets forth information regarding our executive officers and directors:
-------------------------------------------------------------------------------------------------------------------
NAME AGE POSITION
---- --- --------
-------------------------------------------------------------------------------------------------------------------
Edward E. Cohen 65 Chairman, Chief Executive Officer and President
-------------------------------------------------------------------------------------------------------------------
Jonathan Z. Cohen 34 Vice Chairman
-------------------------------------------------------------------------------------------------------------------
Frank P. Carolas 45 Executive Vice President
-------------------------------------------------------------------------------------------------------------------
Freddie M. Kotek 49 Executive Vice President and Chief Financial Officer
-------------------------------------------------------------------------------------------------------------------
Jeffrey C. Simmons 46 Executive Vice President
-------------------------------------------------------------------------------------------------------------------
Michael L. Staines 55 Executive Vice President
-------------------------------------------------------------------------------------------------------------------
Nancy J. McGurk 49 Senior Vice President and Chief Accounting Officer
-------------------------------------------------------------------------------------------------------------------
Carlton M. Arrendell 42 Director
-------------------------------------------------------------------------------------------------------------------
William R. Bagnell 41 Director
-------------------------------------------------------------------------------------------------------------------
Donald W. Delson 53 Director
-------------------------------------------------------------------------------------------------------------------
Nicholas A. DiNubile 52 Director
-------------------------------------------------------------------------------------------------------------------
Dennis A. Holtz 64 Director
-------------------------------------------------------------------------------------------------------------------
EDWARD E. COHEN has been the Chairman of our board of directors, our
Chief Executive Officer and President since our formation in September 2000. He
has been Chairman of the board of directors of Resource America since 1990 and
was its Chief Executive Officer from 1988 until May 2004, and President from
September 2000 until October 2003. In addition, Mr. Cohen has been Chairman of
the managing board of Atlas Pipeline Partners GP, LLC since its formation in
November 1999, a director of TRM Corporation (a publicly-traded consumer
services company) since June 1998 and Chairman of the Board of Brandywine
Construction & Management, Inc. (a property management company) since 1994. Mr.
Cohen is the father of Jonathan Z. Cohen.
FRANK P. CAROLAS has been an Executive Vice President since January
2001 and served as a director from January 2002 until February 2004. Mr. Carolas
was a Vice President of Resource America from April 2001 until May 2004, and has
been Executive Vice President--Land and Geology and a director of Atlas
Resources, Inc. (our wholly-owned subsidiary which acts as the managing partner
of our drilling partnerships) since January 2001. Mr. Carolas is a certified
petroleum geologist and has been employed by Atlas Resources and its affiliates
since 1981.
FREDDIE M. KOTEK has been an Executive Vice President and Chief
Financial Officer since February 2004 and served as a director from September
2001 until February 2004. Mr. Kotek was a Senior Vice President of Resource
America from 1995 until May 2004, President of Resource Leasing, Inc. (a
wholly-owned subsidiary of Resource America) from 1995 until May 2004, and has
been Chairman of Atlas Resources since September 2001 and Chief Executive
Officer and President of Atlas Resources since January 2002. Mr. Kotek was
President of Resource Properties, Inc. (a wholly-owned subsidiary of Resource
America) from September 2000 to October 2001 and its Executive Vice President
from 1993 to September 2000.
JEFFREY C. SIMMONS has been an Executive Vice President since January
2001 and was a director from January 2002 until February 2004. Mr. Simmons has
been a Vice President of Resource America from April 2001 until May 2004, and
has been Executive Vice President--Operations and a director of Atlas Resources
since January 2001. Mr. Simmons joined Resource America in 1986 as a senior
petroleum engineer and has served in various executive positions with its energy
subsidiaries since then.
88
MICHAEL L. STAINES has been an Executive Vice President since our
formation. Mr. Staines was a Senior Vice President of Resource America from 1989
until May 2004, a director from 1989 to February 2000 and Secretary from 1989 to
October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP since
January 2001 and its Chief Operating Officer and a member of its Managing Board
since its formation in November 1999.
NANCY J. MCGURK has been our Chief Accounting Officer since January
2001, Senior Vice President since January 2002, and served as our Chief
Financial Officer from January 2001 until February 2004. Ms. McGurk was a Vice
President of Resource America from 1992 until May 2004, and its Treasurer and
Chief Accounting Officer from 1989 until May 2004. Ms. McGurk has been Senior
Vice President of Atlas Resources since January 2002 and Chief Financial Officer
and Chief Accounting Officer since January 2001.
JONATHAN Z. COHEN has been Vice Chairman of our board of directors
since our formation. He has been the Chief Executive Officer of Resource America
since May 2004, President since October 2003 and a director since October 2002.
Before being elected Chief Executive Officer, he served as Resource America's
Chief Operating Officer from April 2002 to May 2004, Executive Vice President
from April 2001 to October 2003 and Senior Vice President from May 1999 to April
2001. Mr. Cohen has been Vice Chairman of the managing board of Atlas Pipeline
Partners GP since its formation in November 1999, a Trustee and Secretary of
RAIT Investment Trust (a publicly-traded real estate investment trust) since
1997 and Vice Chairman since October 2003, and Chairman of the board of
directors of The Richardson Company (a sales consulting company) since October
1999. Mr. Cohen is a son of Edward E. Cohen.
INDEPENDENT DIRECTORS
The following directors have been determined by our board to be
independent directors as defined under NASDAQ rules and the Securities Act.
CARLTON M. ARRENDELL has been a director since February 2004. Mr.
Arrendell has been with Investment Trust Corporation (a consultant to the
trustee of the AFL-CIO Building Investment Trust) since December 1997 and
currently serves as Chief Investment Officer.
WILLIAM R. BAGNELL has been a director since February 2004. Mr. Bagnell
has been involved in the energy industry in various capacities since 1990. He
has been Vice President--Energy for Planalytics, Inc. (an energy industry
software company) since March 2000 and was Director of Sales for Fisher Tank
Company (a national manufacturer of carbon and stainless steel bulk storage
tanks) from September 1998 to January 2000. Before that, he served as Manager of
Business Development for Buckeye Pipeline Partners, L.P. (a refined petroleum
products transportation company) from October 1992 until September 1998. Mr.
Bagnell served as an independent member of the managing board of Atlas Pipeline
Partners GP from its formation in November 1999 until May 2004.
DONALD W. DELSON has been a director since February 2004. Mr. Delson
has over 20 years of experience as an investment banker specializing in
financial institutions. Mr. Delson has been a Managing Director, Corporate
Finance Group, at Keefe, Bruyette & Woods, Inc. since 1997, and before that was
a Managing Director in the Corporate Finance Group at Alex. Brown & Sons from
1982 to 1997. Mr. Delson served as an independent member of the managing board
of Atlas Pipeline Partners GP from June 2003 until May 2004.
NICHOLAS A. DINUBILE has been a director since February 2004. Dr.
DiNubile has been an orthopedic surgeon specializing in sports medicine since
1982. Dr. DiNubile has served as special advisor and medical consultant to the
President's Council on Physical Fitness and as Orthopedic Consultant to the
Philadelphia 76ers basketball team. Dr. DiNubile is also Clinical Assistant
Professor of the Department of Orthopedic Surgery at the Hospital of the
University of Pennsylvania.
DENNIS A. HOLTZ has been a director since February 2004. Mr. Holtz
has maintained a corporate law practice with D.A. Holtz, Esquire & Associates in
Philadelphia and New Jersey since 1988.
89
OTHER KEY EMPLOYEES
JACK L. HOLLANDER, 48, has been Senior Vice President--Direct
Participation Programs since January 2002. Mr. Hollander has also been Senior
Vice President--Direct Participation Programs of Atlas Resources since January
2002, and before that served as Vice President from January 2001 until December
2001. Mr. Hollander practiced law with Rattet, Hollander & Pasternak,
concentrating in tax matters and real estate transactions, from 1990 to January
2001, and served as in-house counsel for Integrated Resources, Inc. (a
diversified financial services company) from 1982 to 1990.
MICHAEL G. HARTZELL, 49, has been Vice President--Land Administration
since January 2002, and before that served as Senior Land Coordinator from
January 1999 to January 2002. Mr. Hartzell served as general manager of one of
our field offices from January 1998 to January 1999. Mr. Hartzell has also
served as Vice President--Land Administration for Atlas Resources since
September 2001. Mr. Hartzell has been employed by Atlas Resources and its
affiliates since 1980.
MARCI F. BLEICHMAR, 34, has been Vice President--Marketing since
February 2004. Ms. Bleichmar has also served as Vice President--Marketing of
Atlas Resources since February 2001. From March 2000 until February 2001, Ms.
Bleichmar was director of marketing for Jacob Asset Management (a mutual fund
manager) and, from March 1998 until March 2000, was an account executive at
Bloomberg Financial Services, L.P. Before that, Ms. Bleichmar had been an
associate on the Derivatives Trading Desk of JPMorgan since 1994.
DONALD R. LAUGHLIN, 56, has been Vice President--Drilling and
Production since January 2002, and before that served as Senior Drilling
Engineer since May 2001. Mr. Laughlin has also served as Vice
President--Drilling and Production for Atlas Resources since September 2001. Mr.
Laughlin has over 30 years experience as a petroleum engineer in the Appalachian
Basin, having been employed by Columbia Gas Transmission Corporation from
October 1995 to May 2001 as a Vice President, Cabot Oil & Gas Corporation from
1989 to 1995 as Manager of Drilling Operations and Technical Services, Doran &
Associates, Inc. (an industrial engineering firm) from 1977 until 1989 as Vice
President--Operations, and Columbia Gas from 1970 to 1977 as Drilling Engineer
and Gas Storage Engineer.
INFORMATION CONCERNING THE AUDIT COMMITTEE
Our board of directors has established a standing audit committee. All
of the members of the audit committee are independent directors as defined by
Nasdaq National Market rules. The members of the audit committee are Messrs.
Arrendell, Bagnell and Delson, with Mr. Arrendell acting as the chairman. Our
board of directors has determined that Mr. Delson 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.
COMPLIANCE WITH SECTION 16(A) OF THE SECURITIES EXCHANGE ACT
Based solely on our review of the reports we have received, or written
representations from certain reporting persons that no filings were required for
those persons, we believe that during fiscal 2004 our executive officers,
directors and greater than 10% stockholders complied with all applicable filing
requirements of Section 16(a) of the Securities Exchange Act.
90
CODE OF ETHICS
We have adopted a code of business conduct and ethics applicable to all
directors, officers and employees. We believe we meet the definition of a code
of ethics under the Securities Act. Our code of business conduct and ethics is
posted on our web site at www.atlasamerica.com.
ITEM 11. EXECUTIVE COMPENSATION
Until the completion of our initial public offering in May 2004, we did
not directly compensate Messrs. E. Cohen and J. Cohen. Rather, Resource America
allocated the compensation of these executive officers between activities on
behalf of us and activities on behalf of Resource America based upon an estimate
of the time spent by such persons on activities for us and for Resource America,
and we reimbursed Resource America for the compensation allocated to us.
Resource America also similarly allocated compensation for Messrs. E. Cohen, J.
Cohen, Carolas and Simmons to Atlas Pipeline. The following table sets forth the
compensation paid or accrued by us to our chief executive officer and each of
our four other most highly compensated executive officers for fiscal 2004.
SUMMARY COMPENSATION TABLE
--------------------------
Long term
Annual Compensation
Compensation ---------------
--------------------- Restricted
Stock All other
Name and principal position Salary Bonus Awards(2) compensation(1)
- --------------------------- ------ ----- ---------- ---------------
Edward E. Cohen
Chairman of the Board,
Chief Executive Officer and President.............. $401,000 $385,000 $209,924 $995,441
Jonathan Z. Cohen
Vice Chairman of the Board......................... $256,400 $192,500 $ 3,363 $561,909
Freddie M. Kotek
Executive Vice President and
Chief Financial Officer............................ $267,500 $250,000 $ 51,564 $ 6,500
Frank P. Carolas
Executive Vice President........................... $192,500 $ 75,000 $ 5,798 $ 81,357
Jeffrey C. Simmons
Executive Vice President........................... $192,500 $ 75,000 $102,083 $ 81,357
__________________
(1) Reflects matching payments Resource America made under its 401(k) Plan and
grants of phantom units under the Atlas Pipeline Long Term Incentive Plan,
except the amount for Mr. E. Cohen includes $59,500 of accrued obligations
under a Supplemental Employment Retirement Plan established by us in May
2004 in connection with an employment agreement between Mr. E. Cohen and
us. 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);
Mr. Carolas - 2,000 phantom units ($74,520); and Mr. Simmons - 2,000
phantom units ($74,520).
(2) Reflects allocations of shares to employee accounts that were made in
fiscal 2004 under Resource America's 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 Resource America's common
stock on the dates of the respective grants. 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 Resource
America's common stock at September 30, 2004 are: Mr. E. Cohen - 73,683
shares ($1,738,182); Mr. J. Cohen - 588 shares ($13,871); Mr. Kotek -
18,431 shares ($434,787); Mr. Carolas - 512 shares ($12,078); and Mr.
Simmons - 27,111 shares ($639,548). Cash dividends, as and when authorized
by Resource America's Board of Directors, have been and will continue to be
paid to the ESOP on the restricted shares.
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OPTION/SARS GRANTS AND EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END
OPTION VALUES
Neither we nor Resource America granted 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 under the Resource America plans described in note 8 of the
notes to consolidated financial statements. 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
Options at FY-End In-the-Money Options at
Shares 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
Freddie M. Kotek 0 0 76,995/22,500 $1,216,243/$332,152
Frank P. Carolas 0 0 21,375/8,125 $253,471/$118,547
Jeffrey C. Simmons 0 0 19,375/8,125 $237,291/$118,547
_________________
(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 AGREEMENT
We have an employment agreement with Edward E. Cohen, who currently
serves as our Chairman, Chief Executive Officer and President. The agreement
requires him to devote such time to us as is reasonably necessary to the
fulfillment of his duties, although it permits him to invest and participate in
outside business endeavors. The agreement provides for initial base compensation
of $350,000 per year, which may be increased by the compensation committee based
upon its evaluation of Mr. Cohen's performance. Mr. Cohen is eligible to receive
incentive bonuses and stock option grants 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 provides for a Supplemental Executive Retirement Plan, or
SERP, pursuant to which Mr. Cohen will receive an annual retirement benefit
equal to the product of:
o 6.5% multiplied by
o his base salary as of the time Mr. Cohen's employment with us
ceases, multiplied by
o the number of years (or portions thereof) which Mr. Cohen is
employed by us.
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The maximum benefit under the SERP is limited to 65% of his final base
salary. The benefit is guaranteed to his estate for 10 years if he should die
before receiving 10 years' of SERP benefits. If there is a change of control
(other than in connection with the proposed spin-off) and his employment with us
is terminated, or if we terminate his employment without cause, then the SERP
benefit will be the greater of the accrued benefit pursuant to the above
formula, or 35% of his final base salary.
The agreement provides the following regarding termination and
termination benefits:
o upon termination of employment due to death, Mr. Cohen's estate
will receive an amount equal to his final base salary multiplied
by the number of years (or portion thereof) that he shall have
worked for us (but not to be greater than 3 years' base salary or
less than one year's base salary);
o we may terminate Mr. Cohen's employment if he is disabled for 180
days consecutive days during any 12-month period. If his
employment is terminated due to disability, he will receive his
base salary and benefits for 3 years, and such 3 year period will
be deemed a portion of his employment term for purposes of
accruing SERP benefits;
o We may terminate his employment without cause upon 30 days'
written notice or upon a change of control after providing at
least 30 days' written notice. He may terminate his employment for
good reason or upon a change in control. Good reason is defined as
a reduction in his base pay, a demotion, a material reduction in
his duties, relocation, his failure to be elected to our board of
directors or a material breach of the agreement by us. If
employment is terminated by us without cause, by Mr. Cohen for
good reason or by either party in connection with a change of
control, he will be entitled to any amounts then owed to him plus
either:
- severance benefits under our then current severance policy, if
any, or;
- if Mr. Cohen signs a release, 36 months of continued health
insurance coverage and a lump sum payment equal to 3 years of
his average compensation (which we define as the average of the
3 highest years of total compensation that he shall have earned
under the agreement, or if the agreement is less than three
years old, the highest total compensation in any year or
portion thereof);
o Mr. Cohen may terminate the agreement without cause with 60 days
notice to us, and if he does so after January 1, 2006, and signs a
release, he will receive a severance benefit equal to one-half of
one year's base salary then in effect; and
o we may terminate his employment for cause (defined as a felony
conviction or conviction of a crime involving fraud, embezzlement
or moral turpitude, intentional and continual failure to perform
his material duties after notice, or violation of confidentiality
obligations) in which case he will receive only accrued amounts
then owed to him.
In the event that any amounts payable to Mr. Cohen upon termination
become subject to any excise tax imposed under Section 4999 of the Internal
Revenue 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,
equals the termination amounts payable, unless Mr. Cohen's employment terminates
because of his death or disability.
DIRECTOR COMPENSATION
Each of our independent directors are paid a monthly retainer of $1,000
and a fee of $1,000 for each board of directors meeting attended. The chairman
of a committee receives an additional monthly retainer of $500 and other
committee members receive an additional monthly retainer of $250. In addition,
each of our directors who are not our employees or employees of Resource America
annually receives deferred units, representing a right to receive a share of our
common stock over a four-year vesting period, in an amount equal to $15,000,
based on the value of our common stock at the time of the award.
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COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Compensation Committee of the Board of Directors consists of
Messrs. Delson, DiNubile and Holtz. There are no Compensation Committee
interlocks.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.
The following table sets forth the number and percentage of shares of our common
stock owned as of held by beneficial owners of 5% or more of our common stock,
by our executive officers and directors and by all of the executive officers and
directors as a group as of December 1, 2004. The address for each director and
executive officer and Resource America is 1845 Walnut Street, Philadelphia,
Pennsylvania 19103.
Common Stock
------------
Amount and Nature of Percent of
BENEFICIAL OWNER Benefical Ownership Class
- ---------------- ------------------- -----
DIRECTORS
Carlton M. Arrendell.................................................... 0 -
William R. Bagnell...................................................... 0 -
Edward E. Cohen......................................................... 63,000 (1) *
Jonathan Z. Cohen....................................................... 42,000 *
Donald W. Delson........................................................ 0 -
Nicholas A. DiNubile.................................................... 0 -
Dennis A. Holtz......................................................... 714 *
NON-DIRECTOR EXECUTIVE OFFICERS
- -------------------------------
Frank P. Carolas........................................................ 714 *
Freddie M. Kotek........................................................ 6,914 *
Jeffrey C. Simmons...................................................... 357 *
Michael L. Staines...................................................... 0 -
Nancy J. McGurk......................................................... 0 -
All executive officers and directors as a group (12 persons)............ 113,699 *
OTHER OWNERS OF MORE THAN
5% OF OUTSTANDING SHARES
- ------------------------
Resource America, Inc................................................... 10,688,333 80.2%
____________
* Less than 1%
(1) Includes 14,950 shares held in an individual retirement account of Betsy
Z. Cohen, Mr. Cohen's wife. Mr. Cohen disclaims beneficial ownership of
these shares.
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EQUITY COMPENSATION PLAN INFORMATION
The following table contains information about our equity compensation
plans as of September 30, 2004:
- --------------------------------------------------------------------------------------------------------------------
(A) (B) (C)
- --------------------------------------------------------------------------------------------------------------------
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)
- --------------------------------------------------------------------------------------------------------------------
Equity compensation
plans approved by
security holders 4,835 $ - 1,328,498
- --------------------------------------------------------------------------------------------------------------------
CHANGE OF CONTROL
As described above in Item 1: "Business - General- Initial Public
Offering," Resource America has advised us that it intends to spin-off its
remaining ownership interest in us to its common stockholders by means of a
tax-free distribution. Resource America has sole discretion if and when to
complete the distribution and its terms, and does not intend to complete the
distribution unless it receives a ruling from the Internal Revenue Service
and/or an opinion from its tax counsel as to the tax-free nature of the
distribution to Resource America and its stockholders for U.S. federal income
tax purposes.
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
In the ordinary course of its business operations, the Company has
ongoing relationships with several related entities:
We conduct certain activities through, and a substantial portion of our
revenue is attributable to, energy limited partnerships ("Partnerships"). We
serve as general partner of the Partnerships and assume customary rights and
obligations for the Partnerships. As the general partner, we are liable for
Partnership liabilities and can be liable to limited partners if we breach our
responsibilities with respect to the operations of the Partnerships. We are
entitled to receive management fees, reimbursement for administrative costs
incurred, and to share in the Partnerships' revenue, and costs and expenses
according to the respective Partnership agreements.
Until April 1996, Edward E. Cohen ("E. Cohen"), our Chairman of the
Board, Chief Executive Officer and President, was of counsel to Ledgewood. E.
Cohen receives certain debt service payments from Ledgewood related to the
termination of his affiliation with Ledgewood and its redemption of his
interest. We paid Ledgewood $490,400, during fiscal 2004, for legal services
rendered to us.
We reimburse RAI for all direct and indirect costs of services
provided. For the year ended September 30, 2004, such reimbursements were
approximately $1.1 million, representing the allocable portion of the personnel
costs of RAI employees, including executives, for time spent on our business.
As part of our initial public offering, we entered into a master
separation and distribution agreement with Resource America which contains the
key provisions related to our separation from Resource America and the
distribution of our shares to Resource America's common stockholders. The master
separation and distribution agreement, together with the registration rights
agreement, the tax matters agreement, and the transition services agreement,
govern various interim and ongoing relationships between Resource America and us
following the completion of our initial public offering. As required by the
master separation and distribution agreement, we distributed the net proceeds of
our initial public offering to Resource America in the form of a repayment of
special dividend.
MASTER SEPARATION AND DISTRIBUTION AGREEMENT
Overview. The master separation and distribution agreement contains the
key provisions relating to the separation of our business from Resource
America's other businesses and sets forth certain covenants we have agreed to
until the distribution by Resource America to its stockholders of the shares of
our common stock held by Resource America, which we refer to as the
distribution. Although Resource America intends to complete the distribution, it
has sole discretion to decide to do so, and we do not expect Resource America to
complete the distribution unless it is tax-free to Resource America and its
stockholders. Because the Internal Revenue Service requirements for tax-free
distributions of this nature are complex and the Internal Revenue Service has
broad discretion, Resource America may be unable to obtain such a ruling.
Consequently, we cannot assure you that the distribution will occur, or when it
will occur.
Covenants. We have agreed that, for so long as Resource America
beneficially owns at least 50% of our outstanding common stock, we will:
o not take any action which would limit the ability of Resource
America or its transferee to transfer its shares of our common
stock; and
o not take any actions that could reasonably result in Resource
America being in breach of or in default under any contract or
agreement.
Auditors and Audits; Annual Statements and Accounting. We have agreed
that, for so long as Resource America is required to consolidate our results of
operations and financial position with its own or account for its investment in
our company on the equity method of accounting, we will not change our
independent auditors without Resource America's prior written consent (which
will not be unreasonably withheld), and we will use our best efforts to enable
our independent auditors to complete their audit of our financial statements in
a timely manner so to permit timely filing of Resource America's financial
statements. We have also agreed to provide to Resource America and its
independent auditors all information required for Resource America to meet its
schedule for the filing and distribution of its financial statements and to make
available to Resource America and its independent auditors all documents
necessary for the annual audit of our company as well as access to the
responsible company personnel so that Resource America and its independent
auditors may conduct their audits relating to our financial statements. We have
also agreed to adhere to certain specified Resource America accounting policies
and to notify and consult with Resource America regarding any changes to our
accounting principles and estimates used in the preparation of our financial
statements.
96
Indemnification. Under the master separation and distribution
agreement, we and Resource America will indemnify and release each other as
follows:
o We will indemnify and hold harmless Resource America and its
affiliates and their respective officers, directors, employees,
agents, successors and assigns against any payments, losses,
liabilities, damages, claims and expenses arising out of or
relating to our past, present and future assets, businesses and
operations and other assets, businesses operated or managed by us
or persons previously associated with us.
o Resource America will similarly indemnify us and our affiliates
and our and their respective officers, directors, employees,
agents, successors and assigns for Resource America's past,
present and future assets, businesses and operations, except for
assets, businesses and operations for which we have agreed to
indemnify Resource America.
o We will indemnify Resource America and its affiliates against all
liabilities arising out of any material untrue statements and
omissions in any prospectus and any related registration statement
filed with the SEC relating to our initial public offering or any
other primary offering of our common stock or our other securities
prior to the date of the distribution or other similar
transaction. However, our indemnification of Resource America does
not apply to information relating to Resource America, excluding
information relating to us. Resource America has agreed to
indemnify us for this information.
o Except for the rights and obligations of Resource America and us,
which relate to the agreements between Resource America and us
relating to our initial public offering or the distribution, we
will release Resource America and some of its subsidiaries and
affiliates and their respective officers, directors, employees,
agents, successors and assigns for all losses for any and all past
actions and failures to take actions relating to Resource
America's and our assets, businesses and operations. Resource
America will similarly release us.
o All indemnification amounts will be reduced by any insurance
proceeds and other offsetting amounts recovered by the party
entitled to indemnification.
In addition, the transition services agreement, the registration rights
agreement and the tax matters agreement referred to below provide for
indemnification between us and Resource America relating to the substance of
such agreements.
Access to Information. Under the master separation and distribution
agreement, we and Resource America are obligated to provide each other access to
information as follows:
o subject to applicable confidentiality obligations and other
restrictions, we and Resource America will give each other any
information within each other's possession that the requesting
party reasonably needs to comply with requirements imposed on the
requesting party by a governmental authority, for use in any
proceeding or to satisfy audit, accounting or similar
requirements, or to comply with its obligations under the master
separation and distribution agreement or any ancillary agreement;
o for so long as Resource America is required to consolidate our
results of operations and financial position with its own or
account for its investment in our company on the equity method of
accounting, we will provide to Resource America, at no charge, all
financial and other data and information that Resource America
determines is necessary or advisable in order to prepare its
financial statements and reports or filings with any governmental
authority, including copies of all quarterly and annual financial
information and other reports and documents we intend to file with
the SEC before such filings (as well as final copies upon filing),
and copies of our budgets and financial projections;
97
o we will consult with Resource America regarding the timing and
content of our earnings releases and cooperate fully (and cause
our independent auditors to cooperate fully) with Resource America
in connection with any of its public filings;
o we and Resource America will use reasonable efforts to make
available to each other's past and present directors, officers,
other employees and agents as witnesses in any legal,
administrative or other proceedings in which the other party may
become involved;
o the company providing information, consultant or witness services
under the master separation and distribution agreement will be
entitled to reimbursement from the other for reasonable expenses
incurred in providing this assistance; and
o we and Resource America will each agree to hold in strict
confidence all information concerning or belonging to the other
for a period of up to 3 years.
Employee Matters. Effective as of the closing of our initial public
offering, we hired specified persons who were previously employed by Resource
America and assumed all compensation and employee benefit liabilities relating
to them. All of these people were involved in our business and portions of their
salaries had historically been allocated to us.
The Distribution. The master separation and distribution agreement
provides that Resource America has sole discretion to determine if and when the
distribution will occur and all terms of the distribution. Resource America does
not intend to make the distribution unless it receives:
o a ruling by the Internal Revenue Service and/or an opinion from
its tax counsel that the distribution will qualify as a
reorganization pursuant to which no gain or loss will be
recognized by Resource America or its stockholders for U.S.
federal income tax purposes under Section 355, 368(a)(1)(D) and
related provisions of the Internal Revenue Code; and
o any government approvals and material consents necessary to
consummate the distribution.
It is likely that, in order to obtain a favorable ruling from the
Internal Revenue Service and an opinion of counsel, we will need to reorganize
our current corporate structure by merging into us at least one subsidiary which
has conducted an active business for at least 5 years. We do not believe that
the reorganization will have a material effect on us. Even with such
restructuring, there is significant uncertainty as to whether Resource America
will be able to obtain such a ruling because the Internal Revenue Service
requirements for tax-free distributions of this nature are complex and the
Internal Revenue Service has broad discretion. We are required to cooperate with
Resource America to accomplish the distribution and, at Resource America's
direction, to promptly take any and all actions necessary or desirable to effect
the distribution.
Expenses. In general, Resource America and our company will each be
responsible for our own costs (including all associated third-party costs)
incurred in connection with the transactions contemplated by the master
separation and distribution agreement.
REGISTRATION RIGHTS AGREEMENT
Registration Rights. In the event the distribution is not completed and
Resource America does not divest itself of all of its shares of our common
stock, Resource America could not freely sell all these shares without
registration under the Securities Act or a valid exemption under it.
Accordingly, the registration rights agreement provides Resource America with
registration rights relating to the shares of our common stock which it holds.
These registration rights generally become effective when Resource America
informs us that it no longer intends to complete the distribution. Under the
registration rights agreement, Resource America has the right to require us to
register for offer and sale all or a portion of our common stock held by
Resource America.
98
Demand Rights. Resource America may request registration, which we
refer to as a demand registration, under the Securities Act of all or any
portion of the shares covered by the registration rights agreement and we will
be obligated to register the shares as requested by Resource America. The
maximum number of demand registrations that we are required to effect is 5.
Resource America will designate the terms of each offering effected pursuant to
a demand registration, which may take any form, including a shelf registration,
a convertible registration, or an exchange registration.
We have the right, which may be exercised once in any 12-month period,
to postpone the filing or effectiveness of any demand registration for up to 90
days if our board of directors determines in its good faith judgment that such
registration would reasonably be expected to have a material adverse effect on
any then-active proposals to engage in material transactions.
Piggyback Rights. If we at any time intend to file on our behalf or on
behalf of any of our other security holders a registration statement in
connection with a public offering of any of our securities on a form and in a
manner that would permit the registration for offer and sale of our common stock
held by Resource America, Resource America has the right to include its shares
in that offering.
Expenses. We are responsible for the registration expenses in
connection with the performance of our obligations under the registration rights
provisions in the registration rights agreement. Resource America is responsible
for all of the fees and expenses of counsel to Resource America and any
applicable underwriting discounts or commissions.
Indemnifications. The registration rights agreement contains
indemnification and contribution provisions by us for the benefit of Resource
America and its affiliates and representatives and, in limited situations, by
Resource America for the benefit of us and any underwriters with respect to the
information included in any registration statement, prospectus or related
document.
Transfer. Resource America may transfer shares covered by the
registration rights agreement and the holders of such transferred shares will be
entitled to the benefits of the registration rights agreement, provided that
each such transferee agrees to be bound by the terms of the registration rights
agreement.
Duration. The registration rights under the registration rights
agreement will remain in effect with respect to Resource America's shares of our
common stock until:
o the shares have been sold pursuant to an effective registration
statement under the Securities Act;
o the shares have been sold to the public pursuant to Rule 144 under
the Securities Act (or any successor provision);
o the shares have been otherwise transferred, new certificates for
them not bearing a legend restricting further transfer have been
delivered by our company, and subsequent public distribution of
the shares does not require registration or qualification of them
under the Securities Act or any similar state law;
o the shares have ceased to be outstanding; or
o in the case of shares held by a transferee of Resource America,
when the shares become eligible for sale pursuant to Rule 144(k)
under the Securities Act (or any successor provision).
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TAX MATTERS AGREEMENT
Allocation of Taxes. The tax matters agreement governs the respective
rights, responsibilities, and obligations of Resource America and us after our
initial public offering with respect to tax liabilities and benefits, tax
attributes, tax contests and other matters regarding income taxes, non-income
taxes and related tax returns.
In general, under the tax matters agreement:
o Resource America is responsible for any U.S. federal income taxes
of the affiliated group for U.S. federal income tax purposes of
which Resource America is the common parent. With respect to any
periods beginning after our initial public offering, we are
responsible for any U.S. federal income taxes attributable to us
or any of our subsidiaries.
o Resource America is responsible for any U.S. state or local income
taxes reportable on a consolidated, combined or unitary return
that includes Resource America or one of its subsidiaries, on the
one hand, and us or one of our subsidiaries, on the other hand.
However, in the event that we or one of our subsidiaries are
included in such a group for U.S. state or local income tax
purposes for periods (or portions thereof) beginning after the
date of our initial public offering, we are responsible for our
portion of such income tax liability as if we and our subsidiaries
had filed a separate tax return that included only us and our
subsidiaries for that period (or portion of a period).
o Resource America is responsible for any U.S. state or local income
taxes reportable on returns that include only Resource America and
its subsidiaries (excluding us and our subsidiaries), and we are
responsible for any U.S. state or local income taxes filed on
returns that include only us and our subsidiaries.
o Resource America and we are each responsible for any non-income
taxes attributable to our business for all periods.
Resource America is primarily responsible for preparing and filing any
tax return with respect to the Resource America affiliated group for U.S.
federal income tax purposes and with respect to any consolidated, combined or
unitary group for U.S. state or local income tax purposes that includes Resource
America or any of its subsidiaries. We generally are responsible for preparing
and filing any tax returns that include only us and our subsidiaries.
We generally have exclusive authority to control tax contests with
respect to tax returns that include only us and our subsidiaries. Resource
America generally has exclusive authority to control tax contests related to any
tax returns of the Resource America affiliated group for U.S. federal income tax
purposes and with respect to any consolidated, combined or unitary group for
U.S. state or local income tax purposes that includes Resource America or any of
its subsidiaries.
Disputes arising between Resource America and us relating to matters
covered by the tax matters agreement are subject to resolution through specific
dispute resolution provisions described in the tax matters agreement.
The tax matters agreement also assigns responsibilities for
administrative matters, such as the filing of returns, payment of taxes due,
retention of records and conduct of audits, examinations or similar proceedings.
In addition, the tax matters agreement provides for cooperation and information
sharing with respect to taxes.
100
Preservation of the Tax-free Status of the Distribution. Resource
America and we intend the distribution to qualify as a reorganization pursuant
to which no gain or loss is recognized by Resource America or its stockholders
for federal income tax purposes under Sections 355, 368(a)(1)(D) and related
provisions of the Internal Revenue Code. For the distribution to be tax-free to
Resource America and its stockholders, Resource America must, among other
things, own at least 80% of our voting power and at least 80% of any non-voting
stock at the time of the distribution. Resource America intends to seek a ruling
from the Internal Revenue Service and/or an opinion from its outside tax advisor
to the effect that the distribution will be tax-free to it and its stockholders.
Because the Internal Revenue Service requirements for tax-free distributions of
this nature are complex and the Internal Revenue Service has broad discretion,
Resource America may be unable to obtain such a ruling. If such a ruling is not
obtained, we do not expect Resource America to complete the distribution. We
have agreed to certain restrictions that are intended to preserve the tax-free
status of the distribution, including restrictions on our:
o issuance or sale of stock or other securities (including
securities convertible into our stock but excluding certain
compensatory arrangements); and
o sales of assets outside the ordinary course of business.
We have generally agreed to indemnify Resource America and its
affiliates against any and all tax-related liabilities that may be incurred by
them relating to the distribution to the extent such liabilities are caused by
our actions. This indemnification applies even if Resource America has permitted
us to take an action that would otherwise have been prohibited under the
tax-related covenants as described above.
TRANSITION SERVICES AGREEMENT
The transition services agreement governs the provision by Resource
America to us and by us to Resource America of support services, such as:
o cash management and debt service administration;
o accounting and tax;
o investor relations;
o payroll and human resources administration;
o legal;
o information technology;
o data processing;
o real estate management; and
o other general administrative functions.
We and Resource America will pay each other a fee for these services
equal to our respective costs in providing them. The fee will be payable monthly
in arrears, 15 days after the close of each month. We have also agreed to pay or
reimburse each other for any out-of-pocket payments, costs and expenses
associated with these services.
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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
AUDIT FEES
The aggregate fees billed by our independent auditors, Grant Thornton
LLP, for professional services rendered subsequent to our initial public
offering for the audit of our annual financial statements for the fiscal year
ended September 30, 2004 and for the reviews of the financial statements
included in our Quarterly Reports on Form 10-Q during such fiscal year were
$275,800.
AUDIT-RELATED FEES
The aggregate fees billed by Grant Thornton LLP for audit-related
services were $135,200 for the fiscal year ended September 30, 2004 and
primarily related to services rendered in connection with our initial public
offering.
TAX FEES
Grant Thornton LLP billed no fees for tax services rendered to us for
the fiscal year ended September 30, 2004.
ALL OTHER FEES
Grant Thornton LLP billed no fees for other services rendered to us for
the fiscal year ended September 30, 2004.
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.
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PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS, AND REPORTS ON FORM 8-K.
(A) (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 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
(3) EXHIBITS:
Exhibit No. Description
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3.1 Amended and Restated Certificate of
Incorporation.(1)
3.2 Amended and Restated Bylaws.(1)
10.1 Credit Agreement among Atlas America, Inc.,
Resource America, Inc., Wachovia Bank, National
Association, and other banks party thereto,
dated March 12, 2004.(2)
10.1(a) First Amendment to Credit Agreement, dated July
10, 2004.(3)
10.1(b) Second Amendment to Credit Agreement, dated
September 10, 2004.(4)
10.2 Stock Incentive Plan.(3)
10.3 Credit Agreement among Atlas Pipeline Partners,
L.P., Wachovia Bank, National Association, and
the other parties thereto, dated July 16,
2004.(3)
10.5 Master Separation and Distribution Agreement
between Atlas America, Inc. and Resource
America, Inc. dated May 14, 2004.(3)
10.6 Registration Rights Agreement between Atlas
America, Inc. and Resource America, Inc. dated
May 14, 2004.(3)
10.7 Tax Matters Agreement between Atlas America,
Inc. and Resource America, Inc. dated May 14,
2004.(3)
10.8 Transition Services Agreement between Atlas
America, Inc. and Resource America, Inc. dated
May 14, 2004.(3)
10.9 Employment Agreement for Edward E. Cohen dated
May 14, 2004.(3)
21.1 Subsidiaries of Atlas America, Inc.
31.1 Rule 13(a)-14(a)/15d-14(a) Certification.
31.2 Rule 13(a)-14(a)/15d-14(a) Certification.
32.1 Section 1350 Certification.
32.2 Section 1350 Certification.
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(1) Previously filed as an exhibit to our Form 10-Q for
the quarter ended March 31, 2004.
(2) Previously filed as an exhibit to our registration
statement on Form S-1 on March 17, 2004.
(3) Previously filed as an exhibit to our Form 10-Q for
the quarter ended June 30, 2004.
(4) Previously filed as an exhibit to our Form 8-K dated
September 10, 2004.
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(B) REPORTS ON FORM 8-K
o Item 5, dated July 1, 2004, filed July 1, 2004.
o Item 5, dated July 13, 2004, filed July 14, 2004.
o Items 2 and 7, dated July 16, 2004, filed August 2, 2004.
o Items 8.01 and 9.01, dated August 24, 2004, filed August 26, 2004.
o 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, and the unaudited interim balance sheet as of
March 31, 2004, the unaudited interim statements of operations and
accumulated deficit, comprehensive income (loss), changes in
shareholders' equity and cash flows for each of the three months ended
March 31, 2004 and 2003 and the related notes.
o The unaudited pro forma balance sheet of Atlas America, Inc. as of
March 31, 2004, statement operations for the year ended December 31,
2003 and the three months ended March 31, 2004 and the related notes.
o Items 1.01 and 9.01, dated September 10, 2004, filed September 10, 2004.
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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.
ATLAS AMERICA, INC.
(REGISTRANT)
Date: December 28, 2004 By: /s/ Edward E. Cohen
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Edward E. Cohen
Chairman, 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 in the capacities and on the dates indicated.
/s/ Edward E. Cohen
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Edward E. Cohen Chairman, Chief Executive Officer and President December 28, 2004
/s/ Jonathan Z. Cohen
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Jonathan Z. Cohen Vice Chairman and Director December 28, 2004
/s/ Freddie M. Kotek
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Freddie M. Kotek Executive Vice President and Chief Financial Officer December 28, 2004
/s/ Nancy J. McGurk
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Nancy J. McGurk Senior Vice President and Chief Accounting Officer December 28, 2004
/s/ Carlton M. Arrendell
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Carlton M. Arrendell Director December 28, 2004
/s/ William R. Bagnell
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William R. Bagnell Director December 28, 2004
/s/ Donald W. Delson
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Donald W. Delson Director December 28, 2004
/s/ Nicholas A. DiNubile
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Nicholas A. DiNubile Director December 28, 2004
/s/ Dennis A. Holtz
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Dennis A. Holtz Director December 28, 2004
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