UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
Amendment No. 1 to Quarterly Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the quarterly period ended September 30, 1998
Commission File Number 0-23432
RIDGEWOOD ELECTRIC POWER TRUST III
(Exact name of registrant as specified in its charter.)
Delaware, U.S.A. 22-3264565
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
947 Linwood Avenue, Ridgewood, New Jersey 07450-2939
(Address of principal executive offices (Zip Code)
Registrant's telephone number, including area code:
(201) 447-9000
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 [ ]
<PAGE>
PART I. - FINANCIAL INFORMATION
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Dollar amounts in this discussion are rounded to the
nearest $1,000.
Introduction
The Trust carries its investment in the Projects it owns
at fair value and does not consolidate its financial
statements with the financial statements of the Projects.
Revenue is recorded by the Trust as cash distributions
are received from the Projects. Trust revenues may
fluctuate from period to period depending on the operating
cash flow generated by the Projects and the amount of cash
retained to fund capital expenditures.
Results of Operations
<TABLE>
<CAPTION>
Revenues Nine Months Ended September 30, Quarter Ended September 30
1998 1997 1998 1997
<S> <C> <C> <C> <C>
Revenues
On-site Cogeneration: $ 531,000 $ 1,214,000 $ 301,000 $ 716,000
Providence 529,000 683,000 185,000 275,000
San Joaquin 945,000 921,000 569,000 495,000
Byron 475,000 440,000 304,000 277,000
Interest income 64,000 121,000 15,000 55,000
Total $2,544,000 $ 3,379,000 $1,374,000 $1,818,000
</TABLE>
The $835,000 (25%) decrease in total revenues to
$2,544,000 in the first nine months of 1998 from
$3,379,000 in the same period in 1997 is primarily due
to the $681,000 decrease in revenues from the on-site
cogeneration projects and the $154,000 decrease in
revenues from the Providence project. This $681,000
decrease in revenues from the on-site cogeneration
projects primarily reflects the effects of a temporary
shutdown of the Globe plant for major engine maintenance
in 1998, the shutdown of the Rhode Island facility in 1997
and amounts retained by the projects in 1998 to cover
refunds to be made to customers as the result of over-billing
during earlier years of operation of certain of the on-site
cogeneration projects. The overbilling was caused by the
Trust's relying upon improper billing protocols provided by
the prior owner of those projects, EUA Cogenex Corp. and
the major portion of the overbilling was discovered by the
Trust in the course of preparing for the arbitration
proceedings against EUA Cogenex Corp. described at Part II,
Item 1 of this Quarterly Report. The decrease in revenues
from the Providence project reflects an increase in
administrative expenses in 1998 because certain internal
administrative costs are no longer being capitalized after
the completion of an engine addition in 1997.
The decrease in total revenues in the third quarter of 1998
from the third quarter of 1997 was caused by the same factors.
Expenses
The increase in the Trust's expenses by $836,000 from the
nine months ended September 30, 1997 to the same period of
1998 and the decrease of $4,057,000 from the third quarter
of 1997 to the same period of 1998 reflects the timing of
the writedowns of the investment in certain on-site
cogeneration projects. In the third quarter of 1997,
the Trust took a write-down of $3,236,000, primarily
related to the Rhode Island facility. In the second
quarter of 1998, the Trust completed an intensive review
of the remaining projects and determined that a writedown
of its investment by an additional $4,062,000 was necessary.
Other 1998 Trust expenses were comparable to 1997 levels.
Liquidity and Capital Resources
During the first nine months of 1998, the Trust's operating
activities used $388,000 of cash as opposed to providing
$1,575,000 of cash during the same period in 1997. The
change is primarily attributable to lower net income in 1998,
additional investments in new and existing projects, and
costs of the arbitration proceedings against the former
owner of the on-site cogeneration projects. Cash
distributions to shareholders decreased to $1,784,000
in the first nine months of 1998 from $2,483,000 in the
same period in 1997 due to a decrease in the monthly
cash distribution rate in July 1997.
During 1997, the Trust and Fleet Bank, N.A. (the "Bank")
entered into a revolving line of credit agreement, whereby
the Bank provides a three year committed line of credit
facility of $750,000. Outstanding borrowings bear interest
at the Bank's prime rate or, at the Trust's choice, at
LIBOR plus 2.5%. The credit agreement requires the Trust
to maintain a ratio of total debt to tangible net worth of
no more than 1 to 1 and a minimum debt service coverage
ratio of 2 to 1. The credit facility was obtained in order
to allow the Trust to operate using a minimum amount of
cash, maximize the amount invested in Projects and maximize
cash distributions to shareholders. There were no borrowings
under this line of credit in 1998.
In April 1998, the Trust purchased a 500kw facility
(the "Dobbs House project") located near its current Sky
Chefs on-site cogeneration facility in Los Angeles,
California. The total purchase price was approximately
$590,000, including the payment of liabilities that
encumbered the project. The project has a power sales
contract that expires in 2005.
Other than investments of available cash in power generation
Projects, obligations of the Trust are generally limited to
payment of the management fee to the Managing Shareholder,
payments for certain accounting and legal services to third
persons and distributions to shareholders of available
operating cash flow generated by the Trust's investments.
The Trust's policy is to distribute as much cash as is
prudent to shareholders. Accordingly, the Trust has not
found it necessary to retain a material amount of working
capital. The amount of working capital retained is further
reduced by the availability of the line of credit facility.
Year 2000 Remediation
The Managing Shareholder and its affiliates began year 2000
review and planning in early 1997. After initial remediation was
completed, a more intensive review discovered additional issues
and the Managing Shareholder began a formal remediation program
in late 1997. The Managing Shareholder has assessed problems,
has a written plan for remediation and is implementing the plan.
The accounting, network and financial packages for the
Ridgewood companies are basically off-the-shelf packages that
will be remediated, where necessary, by obtaining patches or
updated versions. The Managing Shareholder expects that updating
will be complete before the end of the first quarter of 1999 with ample
time for implementation, testing and custom changes to some modifications
made by Ridgewood to those programs. To a large extent, these software
packages would have been upgraded within a three to five year time frame,
even absent the Year 2000 problem. The Managing Shareholder estimates that
the Trust's allocable portion of the cost of upgrades that were accelerated
because of the Year 2000 problem is approximately $600.
The Managing Shareholder has identified two major systems affecting the
Trust that rely on custom-written software, the subscription/investor
relations and investor distribution systems, which maintain individual
investor records and effect disbursement of distributions to Investors. In
late 1998, the Managing Shareholder's outside computer consultant reviewed
the remediation completed for those systems and advised the Managing
Shareholder that material additional work was required for these systems to
work efficiently after 1999. The Managing Shareholder accordingly employed a
new specialist for Year 2000 remediation of those systems and other software
and for information systems support generally. The Managing Shareholder's
plan calls for completion of changes to the distribution system and testing
of that system by the end of the first quarter of 1999 and the Managing
Shareholder believes that this effort is ahead of schedule. The plan also
targets completion by the end of the second quarter of 1999 of minor changes
to the elements of the subscription/investor relations system that will allow
it to handle individual investors' records, and of all testing of those
modifications. Elements of that system used to generate internal sales
reports and other internal reports (but which do not affect investors'
records) will require major remediation. Remediation of the internal report
generating programs is expected to be completed by the end of the third
quarter of 1999 with testing and any additional modifications to be completed
no later than the end of 1999.
The Managing Shareholder is confident that all software systems
necessary to maintain investor records will be remediated and tested well
before the end of 1999. If the systems used to generate internal reports
from the subscription/investor relations system are not remediated by the end
of 1999, the Managing Shareholder is developing a contingency plan to use the
existing systems together with manual entry of data and checking of results
until remediation is complete. The Managing Shareholder has done this in the
past when system problems have occurred and it thus believes that there will
be no material or noticeable effect on the accuracy of its records or
generation of internal reports, although it may experience delays in
generating internal reports of a few days.
Some systems are being remediated using the "sliding window" technique,
in which two digit years less than a threshold number are assumed to be in
the 2000's and higher two digit numbers are assumed to be in the 1900's.
Although this will allow compliance for several years beyond the year
2000, eventually those systems will have to be rewritten again or
replaced. The Managing Shareholder expects that the ordinary course of
system upgrading will eventually cure this problem.
The Trust's share of the incremental cost for Year 2000 remediation of
this custom written software and related items for 1998 and prior years is
estimated at $9,500 and is estimated to be approximately $9,000 for 1999.
Each of the Trust's electric generating facilities is being reviewed
during the first quarter of 1999 by an outside consultant or by Ridgewood Power
Management Corporation personnel to determine if its electronic control systems
contain software affected by the Year 2000 problem or contain embedded
components that contain Year 2000 flaws. The Trust owns small electric
generating facilities that rely on mechanical and analog systems, many of which
are not expected to be vulnerable to Year 2000 problems. The facilities use
personal computers running packaged software for routine recordkeeping and data
logging, which have been upgraded as described above. To date the Trust has
discovered no systems having a material impact on output, environmental
compliance, recordkeeping or any other material impact that have Year 2000
concerns. To date, initial reviews at the Byron and San Joaquin facilities
have not discovered any systems vulnerable to Year 2000 issues. The
Providence and On-Site Cogeneration facilities have not yet been reviewed.
The Trust's share of the estimated costs of the review and of any minor
upgrades or rehabilitation is estimated at less than $25,000.
The Managing Shareholder and its affiliates do not significantly rely
on computer input from suppliers and customers and thus are not directly
affected by other companies' Year 2000 compliance. However, if customers'
payment systems or suppliers' systems were adversely affected by year 2000
problems, the Trust could be affected. For example, if the utilities that
purchase the Trust's electricity output were unable to accept electricity
because of system malfunctions or transmission failures caused by Year 2000
non-compliance by them or other persons, the Trust would lose revenues that
could not be recouped at a later date. Similarly, if utility payment systems
were to malfunction, the Trust's revenues might be delayed. Based on
published reports the Trust believes that it is now very unlikely that
utilities will fail to accept electricity for more than a very short time
because of malfunctions caused by the Year 2000 problem. Although the Trust
also believes that utility payment problems are unlikely and, if they occur,
will not exceed a month or two, there can be no assurance that payments to
the Trust will not be interrupted. The Trust has established a line of
credit, described above at "Liquidity and Capital Resources," to cover this
contingency and others. The Trust's non-utility customers are being
contacted during the first quarter of 1999. The Trust anticipates that the
customers will advise it that they do not anticipate that their own Year 2000
problems, if any, will interfere with taking or paying for the Trust's
outputs of electricity or heat, but that they will decline to give any
assurance that they will be able to do so.
The Trust's main supply contingency is the availability of natural gas
from pipelines for fueling engine sets at the Byron, San Joaquin and On-Site
Cogeneration facilities. Accordingly the Trust is exposed to a possible
interruption of gas supply if Year 2000 problems interfere with pipeline
service. There is no reasonably available alternate source of gas and
accordingly an interruption of supply would necessarily close the plants.
Availability of other supplies such as spare parts and consumables may be
affected by Year 2000 problems; the Trust purchases these items from many
different sources, no single one or group of which could have a material effect
on the Trust if it or they were not Year 2000 compliant.
Because the Trust and the Managing Shareholder are extremely small
relative to the size of their utility customers and material suppliers and
are paid or supplied using the same systems as larger companies, requests for
written assurances of compliance from those customers or suppliers are
not cost-effective. Instead, the Managing Shareholder is monitoring industry
trends and compliance and is working to assure the Trust's continued
operations. Similarly, as described above, in most cases there are no cost-
effective contingency measures that can be taken against the major risks to
the Trust that utilities will fail to take or fail to pay for the Trust's
electricity output or that natural gas pipelines will fail to deliver gas as
the result of Year 2000 problems. The Trust believes that in the event that
any embedded components or other systems are found to have Year 2000
problems at its power plants it will be able to remediate them promptly and
before the end of 1999. It is preparing contingency plans to operate the
plants with manual or analog control systems if Year 2000 problems cannot be
remediated. Because the plants are small and use simple technologies (diesel
engines and conventional generators) that are not dependent on computers or
date-sensitive electronics, the Trust believes that it is unlikely that any
facility other than the Providence facility would be unable to operate because
of Year 2000 problems at the facility. The Trust believes that the Providence
facility will also be capable of operation but is awaiting the results of the
systems review.
Based on its internal evaluations and the risks and contexts identified
by the Commission in its rules and interpretations, the Trust believes that
Year 2000 issues relating to its assets and remediation program will not have
a material effect on its facilities, financial position or operations, and
that the costs of addressing the Year 2000 issues will not have a material
effect on its future consolidated operating results, financial condition or
cash flows. However, this belief is based upon current information, and
there can be no assurance that unanticipated problems will not occur or be
discovered that would result in material adverse effects on the Trust.
The Trust is unable to predict reliably what, if anything, will happen
after December 31, 1999 with regard to Year 2000 problems caused by the
inability of other businesses and government agencies to complete Year 2000
remediation. The Trust knows of no specific problems identified by customers
or suppliers that would have a material adverse effect on the Trust.
The reasonable worst case scenario anticipated by the Trust is that the
Byron, San Joaquin and On-Site Cogeneration facilities will be able to operate
on and after January 1, 2000 but that there may be some short-term inability
of their customers to pay promptly. In that event, the Trust's revenues
could be materially reduced for a temporary period and it might have to draw
upon its credit line to fund operating expenses until the utility makes up
any payment arrears. The Trust believes that the Providence facility will
also be capable of operation after January 1, 2000. For purposes of a worst
case scenario it will assume, until the survey of embedded components is
completed, that the Providence facility would not be able to operate after
January 1, 2000 because there might be an embedded component that is not
Year 2000 compliant and the component could not be replaced in time. In
1998, revenues from the Providence Plant comprised about 20% of the Trust's
operating revenues. In addition, the Byron, San Joaquin and On-Site
Cogeneration facilities rely on natural gas pipelines for fuel.
If the pipelines do not function properly because of Year 2000 problems,
these facilities would have to reduce or cease operations, which
would have material adverse effects on the Trust.
<PAGE>
RIDGEWOOD ELECTRIC POWER TRUST III
SIGNATURES
Pursuant to the requirement 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.
RIDGEWOOD ELECTRIC POWER TRUST III
Registrant
March 8, 1999 By /s/ Martin V. Quinn
Date Martin V. Quinn
Senior Vice President and
Chief Financial Officer
(signing on behalf of the
Registrant and as
principal financial
officer)
