SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): MARCH 15, 1995
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BANGOR HYDRO-ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
MAINE 0-505 01-0024370
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(State of Incorporation) (Commission File No.) (IRS Employer ID No.)
33 STATE STREET, BANGOR, MAINE 04401
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (207-945-5621)
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CURRENT REPORT, FORM 8-K DATE OF REPORT
BANGOR HYDRO-ELECTRIC COMPANY MARCH 15, 1995
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ITEM 5. OTHER EVENTS
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As the Company has discussed in prior reports and public communications,
increasing competition in the electric utility industry has caused the
Company to rethink its traditional business strategy and to formulate new
plans to ensure its long term success. Among the matters considered is the
likelihood that the Company's ability to implement future rate increases
through traditional, rate-of-return regulation sufficient to ensure
satisfactory profitability will be increasingly limited by competitive
forces. The Company believes that greater flexibility to adjust its prices
and increase its sales in competitive energy service markets is essential to
future profitability. The Company's strategy has also included an effort to
reduce the impact of the high-cost contracts for the purchase of power from
non-utility independent power producers with whom the Company was required to
contract in the 1980's.
In recent weeks, there have been developments in the Company's
initiatives for increased pricing flexibility and for reducing the burden of
contractual commitments to high-cost, non-utility independent power producers
that are expected to have a favorable impact on the Company's competitive
position and future financial success, but that present shorter-term
financial and operational challenges.
CHANGES IN REGULATION
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As discussed in the earlier reports, the Company believes that if public
and regulatory policies were adjusted to permit the active pursuit of greater
sales, the price that could be charged in a competitive environment, while
lower than many of the Company's current rates, would recover more than the
marginal cost of providing the service. The Company also believes that, at
such lower prices, there is a significant potential for increased business.
To the extent the Company is successful in expanding its market share with
competitive rates, the increased revenue in excess of marginal cost will
enhance earnings and offset the need for rate increases.
Under traditional regulatory policies, the Company has had only limited
authority to adjust its prices to meet the competition. Competitive price
initiatives have been evaluated and approved by the Maine Public Utilities
Commission ("MPUC") on a case-by-case basis. For example, for several years
the Company has been allowed to sell interruptible energy to two major
customers at significantly reduced rates, thereby retaining load that
otherwise would have been lost and providing an incentive to add new load.
More recently, the Company has been negotiating on an individual basis
with customers that have demonstrated that, without rate relief, they will
curtail their purchases from the Company. In early 1994, the MPUC authorized
the Company to enter into a five-year contract (terminable by the customer
with two years' notice) for the supply of power to one of the Company's
largest firm industrial customers at reduced rates. The Company also has on
file with the MPUC an approved tariff that establishes procedures on a
limited basis for the negotiation and implementation of individual rate
discounts necessary to retain or attract load. Several smaller rate
contracts have been approved pursuant to that procedure. The impact of these
efforts to date has been that sales have been retained that could have
otherwise been lost and, to some extent, sales have increased to some
customers. However, to date the sales increases resulting from these pricing
strategies have not offset the revenue reduction that results from the lower
prices. Moreover, the operation of the fuel cost adjustment mechanism and
the mandated accounting for fuel expense and revenue has caused the benefits
from these strategies to be more weighted in favor of the Company's customers
than its shareholders.
Therefore, even though the Company has had some success in retaining
customers with the limited pricing flexibility that had been afforded by the
MPUC, the Company believed that more flexibility was necessary in order to
more effectively meet the demands of competition in a timely manner.
Procedural obstacles and the lack of clear standards for evaluating proposed
rate reductions have hindered the Company's ability to react quickly and
flexibly to competitive threats. Because of this need for greater
flexibility, the Company proposed to the MPUC a new "Alternative Marketing
Plan" (or "AMP") in July of 1994. The AMP proposal included a plan for
allowing increased flexibility to offer reduced prices and develop related
marketing programs, a commitment to attempt to cap electric rates at current
levels for an extended period, the elimination of fuel cost accounting and
the fuel adjustment clause, the elimination of seasonal rate differentials
and an understanding about the method of amortizing the cost of any future
buyout of high-cost purchased power contracts.
On February 14, 1995, the MPUC issued an order approving many aspects of
the Company's AMP proposal. The plan, as approved, while imposing greater
restrictions on pricing flexibility than the Company would have preferred,
should permit greater opportunities for the Company to meet the challenges of
competition over the long term. Specifically, the MPUC established the
following guidelines for the reduction of rates with limited regulatory
oversight:
1. For existing customer classes, the Company may offer reduced rates
with a price floor at the Company's long-term marginal cost plus 10% as
long as the rate structure of the class is maintained within specified
limits. Rates that meet the criteria will take effect automatically
after a 30-day notice period. If a proposed reduction does not meet the
criteria, the MPUC may suspend its effectiveness but will make a
decision within four months of the initial filing date.
2. The Company may develop rates for new targeted customer classes with
a price floor that depends upon whether the new load is "temporary" (not
expected to continue for an extended period and sensitive to rate
changes that occur after the initial discount) or "permanent" (expected
to continue indefinitely regardless of later rate adjustments). For
temporary load, the floor is short-term marginal cost plus 1.5 cents/kwh
or, under certain circumstances, short-term marginal cost plus 10%. For
permanent load, the floor is long-term marginal cost plus 10%. Rates
that meet the criteria will take effect automatically after a 30-day
notice period.
3. The Company may negotiate special rate contracts with individual
customers, the criteria for which depend upon the length of the contract
and whether the load is temporary or permanent.
a. For short term contracts (up to three years) to supply
temporary load, the floor is short-term marginal cost plus 1.5
cents/kwh. For short term contracts to supply permanent load,
the floor is long-term marginal cost plus 10%. Short term
contracts that meet all criteria will take effect
automatically after a 30-day notice period.
b. For contracts with terms of three to five years, the floor
is long-term marginal cost plus 10%. For contracts with terms
of five to ten years, the floor is long-term marginal cost
plus 25%. Contracts that meet all criteria will take effect
automatically after a 30-day notice period.
c. Contracts with terms over ten years may not be approved
automatically, but the MPUC will review any such proposal
within four months of filing.
4. Any rate reduction that results in permanent load will also be
subjected to certain cost tests, the results of which must be presented
by the Company at the time of filing. If the proposal fails any of the
tests, the Commission may suspend its effectiveness and the MPUC will
review it within four months of filing.
5. The Company may eliminate seasonal rate differentials (requiring
higher charges during winter months than during the remainder of the
year) for certain classes of customers.
6. The total amount of price reductions (the "revenue delta") offered
by the Company under the AMP will be capped at 10% of the Company's
revenues. If the revenue delta approaches the cap, the Company would
have to request authority from the MPUC to offer further discounts.
As proposed by the Company in its AMP proposal, effective January 1,
1995 the MPUC also ordered the elimination of the Fuel Cost Adjustment
("FCA"), a rate mechanism under which the Company has historically been
permitted to adjust retroactively for changes in the cost of fuel for
generation and in certain purchased power costs. The Company proposed the
change because, under traditional regulation, the operation of the FCA has
imposed the burden of rate discounting on utility shareholders while the
benefits have been enjoyed by other utility customers. The Company believed,
therefore, that a business strategy dependent on pricing flexibility would be
effective only if the FCA were eliminated. However, the FCA has allowed the
Company to respond quickly to changes in fuel and purchased power costs (both
increases and decreases) and has reduced the volatility of earnings. Its
elimination may result in increased or decreased earnings solely from changes
in costs over which the Company has no control.
As of January 1, 1995, the Company's collections under the FCA had
exceeded its costs by approximately $3.03 million. With the elimination of
the FCA, the MPUC recognized that there would no longer be a mechanism for
the return of that sum to customers. The MPUC allowed the Company to retain
that overcollection and ordered that the amount be amortized over a period of
three years. That retention and amortization will have a short-term positive
impact on the Company's earnings.
Also as requested by the Company, the MPUC established the recovery and
accounting procedures to be followed in the event the Company negotiates a
buyout of one or more of its contracts for the purchase of power from high-
cost non-utility independent power producers. In the event of a buyout, the
Company may amortize for accounting purposes the costs over the shorter of
the remaining contract life, not considering extension options, or 10 years.
With the elimination of the FCA, reduced fuel cost benefits of any buyout
will inure to the benefit of the Company and may be used to recover the
amortization of the buyout cost. The Company believes that the fuel and
energy cost savings achieved by such a buyout, previously subject to the FCA,
would exceed any costs of such a buyout including carrying costs on the
unamortized balance.
Finally, the MPUC acknowledged with approval the Company's commitment to
attempt to cap existing electric rates at current levels for an extended
period and expressed a desire to formalize the details of such a commitment
by the end of the summer of 1995.
BUYBACK OF PURCHASED POWER CONTRACTS
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The Company has reached an agreement in principle to buy back two
contracts for the purchase of power from operators of biomass-fueled
generating plants located in West Enfield and Jonesboro, Maine. Both power
vendors are high-cost non-utility independent power producers with whom the
Company was required to contract in the 1980's. The power contracts,
identical in their terms and conditions, provide for the purchase of the
entire generation output of each of the facilities. Each plant has a rated
capacity of 24.5 megawatts. Power purchases began in 1986 and are scheduled
under the contracts to continue for a period of approximately 30 years from
the date of the initial purchases.
The power contracts provide for the purchase of power at prices
consisting of the sum of a fixed component and a variable component. The
Company has the option of requesting that the plants curtail or interrupt
production, in which event payment is limited to the fixed component to the
extent of curtailment or interruption. Because of the availability of less
expensive power from other sources at prices less than the variable component
of the contract rates, the Company has not taken delivery of significant
amounts of electricity under these contracts in recent years and has limited
its payments to the fixed component.
The buyback agreement calls for a cash payment by the Company of $83
million ($41.5 million per plant) and for the Company to assume
responsibility for the remaining debt on the plants in a manner that relieves
the owners of any further obligations on such debt. The balance of the
outstanding debt is expected to be about $79 million in total at the time of
the closing. If the lenders are unwilling to permit the assumption by the
Company of such debt on terms acceptable to the Company and the owners, the
Company would be required to increase the cash portion of the buyback by an
amount sufficient to discharge the owners' debt in order for the buyback to
be accomplished. In addition, the Company will be responsible for costs of
preparing for a closing of the transaction and may incur significant costs in
obtaining the necessary financing. The Company will be obliged to pay some
portion of such costs whether or not a closing occurs.
Financing this transaction will be a significant challenge for the
Company in view of the Company's relatively small size and its existing
capital structure. The Company expects the financing to be accomplished
through a combination of bank borrowings, the possibility of the assumption
of the owners' debt, and the issuance of other debt securities. Such a
financing would increase the Company's leverage substantially and could
temporarily reduce the Company's ability to obtain external financing for
other purposes, although the Company does not believe its external financing
needs will be significant in the next several years.
The buyback agreement is contingent upon a number of conditions
including negotiation of definitive documentation, the ability of the Company
to obtain satisfactory financing arrangements, the securing of necessary
governmental approvals (including approvals from the MPUC and the Federal
Energy Regulatory Commission) and a satisfactory agreement between the
Company and another utility to which the Company is currently reselling a
portion of the electrical output from the plants. The anticipated closing
date is June 1, 1995. After the closing, the Company will have no further
obligation to purchase power from the plants and will not acquire any
ownership interest in them.
IMPLICATIONS FOR DIVIDEND POLICY
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As indicated in prior reports, the Company has recognized that the
infusion of increased competition into the electric utility industry and the
decreased reliance on traditional, rate-of-return regulation will likely
cause changes in policies with respect to the payment of common stock
dividends. The continuity of dividend payments that has been enjoyed in the
past may be less certain, and dividend payment decisions are more likely to
depend to a greater degree upon current profitability and the shorter-term
prospects for growth in earnings.
During 1994, the Company maintained its common dividend payment even
though it became apparent early on that the payout ratio would be high. This
action was consistent with the Company's view that, to the extent possible,
electric utilities in the transition to a more competitive business
environment should attempt to maintain dividend levels and utilize future
earnings growth to evolve to more conservative payout ratios. While the
Company continues to believe that to be an appropriate policy, it also
believes that factors have combined that could likely result in a reduction
of the Company's common dividend in 1995.
As discussed above, the MPUC's decision to allow the Company more
pricing flexibility acknowledged the Company's commitment to attempt to avoid
general rate increases. The MPUC's support for the Company's efforts adds to
the Company's resolve to avoid such rate increases for the near-term future.
Taking this factor in conjunction with generally lower-than-expected growth
in sales and revenues in 1994 and so far in 1995 and the fact that it will
take some time for the newly-granted pricing flexibility to have an impact,
the Company does not believe that its current prospects for earnings can
support a common dividend at the same level as that paid in 1994.
Moreover, the financing of the contract buyback transaction discussed
above may independently affect the Company's ability to maintain common
dividends at the level paid in 1994. Although the Company believes the
buyback transaction is in the best interests of the Company and its
shareholders, and should enhance the Company's prospects for improved
earnings sooner than if the transaction did not occur, the incurrence of the
levels of additional debt necessary in order to accomplish the transaction
could result in the imposition of conditions or covenants in the associated
debt instruments that will be likely to restrict the Company's ability to pay
common dividends at current levels while such debt is outstanding.
The Board of Directors has made no determination as to the timing or
amount of any adjustment of the Company's common dividends.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
BANGOR HYDRO-ELECTRIC COMPANY
/s/ Robert C. Weiser
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Robert C. Weiser
Chief Financial Officer
