<PAGE>
ITEM 7 Financial Statements and Exhibits
As required by SEC Staff Legal Bulletin No. 2 reporting companies
emerging from Bankruptcy are required to file, under cover of Form 8-K,
an audited balance sheet. As of November 4, 1998, the date of the original
filing of the Form 8-K, it was not practical for the Company to provide
the audited balance sheet as required. This filing is an amendment to the
original Form 8-K, which now includes the audited balance sheet.
This amendment was done as soon as this audited balance sheet became
available.
INDEPENDENT AUDITOR'S REPORT
To the Board of Directors and Chapter 11
Trustee of Bonneville Pacific Corporation
Salt Lake City, Utah
We have audited the accompanying consolidated balance sheet of Bonneville
Pacific Corporation (Chapter 11 Debtor) and subsidiaries as of October 31, 1998.
This balance sheet is the responsibility of the Company's management. Our
responsibility is to express an opinion on this consolidated balance sheet based
on our audit.
We conducted our audit in accordance with generally accepted auditing standards.
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the consolidated balance sheet is free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the consolidated balance sheet. An audit also
includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall consolidated balance
sheet presentation. We believe that our audit provides a reasonable basis
for our opinion.
In our opinion, the consolidated balance sheet referred to above presents
fairly, in all material respects, the financial position of Bonneville Pacific
Corporation (Chapter 11 Debtor) and subsidiaries as of October 31, 1998 in
conformity with generally accepted accounting principles.
HEIN + ASSOCIATES LLP
Denver, Colorado
January 5, 1999, except for paragraph 16 of Note 5,
as to which the date is February 11, 1999
BONNEVILLE PACIFIC CORPORATION (CHAPTER 11 DEBTOR)
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
OCTOBER 31, 1998
($ In Thousands, Except Per Share Information)
<TABLE>
<C> c>
PRO FORMA (unaudited)
BALANCE
<C> AFTER AFTER
ACTUAL PLAN PLAN
OCTOBER 31, DEBT DEBT
1998 DISCHARGE DISCHARGE
<S>
ASSETS
<S>
CURRENT ASSETS:
Cash and cash
equivalents $ 163,991 $(156,578) $ 7,413
Restricted Cash 462 - 462
Receivables 4,124 - 4,124
Other Current Assets 231 - 231
Total Current Assets 168,808 (156,578) 12,230
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, at cost,
under the successful efforts
method 32,859 - 32,859
Other property, plant
and equipment 10,042 - 10,042
Accumulated depreciation,
depletion, amortization
and impairment (28,490) - (28,490)
Total Property, Plant
and Equipment 14,411 - 14,411
INVESTMENT AND OTHER ASSETS
Investments in and advances
to affiliated companies, at
cost plus equity in undistributed
earnings 9,744 - 9,744
Other assets 383 - 383
Total Other Assets 10,127 - 10,127
TOTAL ASSETS $193,346 $(156,578) $ 36,768
<FN>
See accompanying notes to this consolidated balance sheet.
</TABLE>
<PAGE>
<TABLE>
<C>
<C>
PRO FORMA (UNAUDITED)
BALANCE
<C> AFTER
ACTUAL PLAN PLAN
OCTOBER 31, DEBT DEBT
<S> 1998 DISCHARGE DISCHARGE
LIABILITIES AND STOCKHOLDERS' DEFICIENCY
LIABILITIES NOT SUBJECT TO COMPROMISE:
<S>
Current liabilities:
Post-petition accounts payable $ 3,134 $ - $ 3,134
Accrued professional fees 4,281 (4,281) -
Other current liabilities 1,139 - 1,139
Total Current liabilities 8,554 (4,281) 4,273
Bank debt 3,900 - 3,900
TOTAL LIABILITIES NOT SUBJECT TO
COMPROMISE 12,454 (4,281) 8,173
SENIOR LIABILITIES SUBJECT TO COMPROMISE:
Pre-petition accounts payable 3,750 ( 3,750) -
Convertible debentures and pre-petition
accrued interest 64,750 (64,750) -
Bank debt and pre-petition accrued
interest 31,512 (31,512) -
Accrued interest 51,556 (51,556) -
Priority claims 7 (7) -
Total senior liabilities subject to
compromise 151,575 (151,575) -
SUBORDINATED LIABILITIES SUBJECT TO COMPROMISE:
Pre-petition selling debentures
claims (Class 5) 5,333 ( 5,333) -
Post-petition selling debentures
claims (Class 6) 6,901 ( 6,901) -
Limited partner claims (Class 7) 721 ( 721) -
Deeply subordinated claims (Class 8) 8,945 ( 8,945) -
Selling stockholders 510(b) claims
(Class 9) 30,852 ( 30,852) -
Cigna claim (Class 10) 11,000 ( 11,000) -
Total subordinated liabilities
subject to compromise 63,752 ( 63,752) -
TOTAL LIABILITIES SUBJECT TO COMPROMISE 215,327 (215,327) -
Total liabilities 227,781 (219,608) 8,173
<FN>
See accompanying notes to this consolidated balance sheet.
</TABLE>
<PAGE>
<TABLE>
<C>
<C> <C>
PRO FORMA (UNAUDITED)
BALANCE
AFTER
ACTUAL PLAN PLAN
OCTOBER 31, DEBT DEBT
1998 DISCHARGE DISCHARGE
<S>
MINORITY INTEREST IN CONSOLIDATED
SUBSIDIARY COMPANY - - -
<S>
COMMITMENTS AND CONTINGENCIES (Notes 5, 7, and 12)
<S>
STOCKHOLDERS' (DEFICIENCY)
EQUITY:
Preferred stock -
$.01 par value; cumulative;
5,000,000 shares authorized
with $.01 per share
liquidation value; no shares
issued and outstanding - - -
Common stock - $.01 par
value; 50,000,000 shares
authorized; 21,375,000 shares
issued, pro forma 7,227,000
(post reverse split) issued 214 ( 142) 72
Additional Paid-in Capital 127,602 33,131 160,733
Accumulated deficit (154,183) 22,402 (131,781)
Cumulative translation adjustment (429) - (429)
(26,796) 55,391 28,595
Treasury stock - 9,688,000 shares
(-0- pro forma), at cost ( 7,639) 7,639 -
Total Stockholders' (deficiency)
equity (Note 10) ( 34,435) 63,030 28,595
TOTAL LIABILITIES AND STOCKHOLDERS'
(DEFICIENCY) EQUITY $193,346 $ (156,578) $ 36,768
<FN>
See accompanying notes to this consolidated balance sheet.
</TABLE>
<PAGE>
[S]
NOTES TO CONSOLIDATED BALANCE SHEET
NOTE 1 - REORGANIZATION AND LEGAL MATTERS:
Bonneville Pacific Corporation ("BPC"), but none of its partially- or wholly-
owned subsidiaries, filed a voluntary petition for relief under Chapter 11 of
Title 11 of the Federal Bankruptcy Code (the "Code") on December 5, 1991 (the
"petition date"). From the petition date to June 12, 1992, BPC operated as a
Chapter 11 Debtor-in-Possession subject to the jurisdiction of the United
States Bankruptcy Court for the District of Utah, Central Division
(the "Court"). On June 12, 1992, the Court ordered the appointment of
a Chapter 11 Trustee (the "Trustee"). Certain executory contracts and leases
existing at the petition date have been rejected or assumed with the approval
of the Court.
On June 19, 1998, the Trustee filed with the Court the "Trustee's Amended
Chapter 11 Plan for the Estate of Bonneville Pacific Corporation dated
April 22, 1998" (the "Plan"). This Plan was confirmed on August 27, 1998
and was effective on November 2, 1998 (the "Effective Date"). See Note 2
for further discussion of the Plan.
The accompanying consolidated balance sheet has been prepared in accordance
with the American Institute of Certified Public Accountants Statement of
Position 90-7 (SOP 90-7) for reporting bankruptcy related items. SOP 90-7
requires BPC to record claims at the amount allowed or the amount estimated
to be allowed as opposed to the amount for which the liabilities are expected
to be settled. SOP 90-7 also requires separate balance sheet classification
for liabilities subject to compromise, and requires disclosure of certain
bankruptcy related items.
The accompanying consolidated pro forma balance sheet reflects adjustments
necessary to record the reorganization of BPC and the issuance of securities
in connection with implementation of the Plan, as if these transactions had
occurred as of October 31, 1998.
<PAGE>
NOTE - 2 CHAPTER 11 PLAN:
The Plan classifies all claims into 11 classes plus administrative claims and
standardizes the way certain claims are calculated. The classes and
treatments, in general are as follows:
<TABLE>
<S>
<C> <C> <C> <C> <C>
Allowed
Amount Amount
of of
Class Type of Claim Claim Settlement Treatment
(in 000's)
(1) Priority Claims $ 7 $ 7 Allowed claim paid in full in cash
at distribution date.
(2) Bank Debt Claims 31,512 31,512 Allowed claim paid in full in cash
at distribution date; post-petition
simple interest at 8.03% per annum
through December 5, 1997 and 8.10%
thereafter.
(3) Trade and Other 3,750 3,750 Allowed claim paid in full in cash
General Unsecured at distribution date; post-petition
Claims simple interest at 5.5% per annum.
(4) Current Debenture 64,750 64,750 Allowed claim paid in full in cash
Claims at distribution date; post-petition
simple interest at 7.32% per annum.
(5) Pre-petition Sell- 5,333 5,333 Claim amount as uniformly calculated
ing debenture Claims by the Trustee allowed and paid in
Plan common stock.
(6) Post-petition Sell- 6,901 6,901 Claim amount as uniformly calculated
ing debenture Claims by the Trustee allowed and paid
in Plan common stock.
(7) Limited Partner 721 721 Claim amount as uniformly calculated
Claims by the Trustee allowed and paid
in Plan common stock.
(8) Deeply Subordinated 8,945 895 10% of allowed claim paid in Plan
Claims common stock.
(9) Equity Claims 30,852 20,202 Allowed claim as uniformly calculated
(For Loss of Value by the Trustee paid in Plan common
on Equity, also known stock with a value estimated to be
as 510(b) equity claims) approximately 65% of the allowed
claim.
(10) CIGNA Claim 11,000 7,203 Allowed as an $11 million 510(b)
equity claim; claimant to receive
Plan common stock with a value
estimated to be approximately
65% of such claim.
(11) Equity Interests Existing common stock was retained
(Existing common stock) by the interestholders and their
rights in the reorganized debtor
were unaltered.
</TABLE>
<PAGE>
The Plan also provides for a one for four reverse stock split. The split was
effective on November 2, 1998. The above claim amounts do not include accrued
administrative claims in the amount of $4,281,000. These administrative claims
were paid subsequent to October 31, 1998 as allowed by the bankruptcy court on
January 5, 1999. Subsequent to October 31, 1998, BPC paid cash and issued
stock in satisfaction of the above claims as provided for in the Plan.
Pursuant to the Plan, claimants who were to receive less than 100 shares of
Plan common stock (taking into account the reverse stock split) received cash
in lieu of such stock. These cash payments totaled approximately $625,000.
The value of BPC as set forth in the Plan (reorganization value) as of the
date immediately preceding the effective date was greater than the sum of
post-petition liabilities and allowed claims, therefore, the Company did not
qualify for fresh start accounting and it will continue to report its assets
and liabilities at historical cost amounts.
NOTE 3 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Principles of Consolidation - The consolidated balance sheet includes the
accounts of BPC and its majority-owned subsidiaries (collectively referred to
as "the Company"). All significant intercompany balances and transactions have
been eliminated in consolidation. The following majority-owned subsidiaries
had activities during 1998: Bonneville Fuels Corporation ("BFC"), Bonneville
Pacific Services Company, Inc. ("BPSC"), and Bonneville Nevada Corporation
("BNC").
Organization and Nature of Operations - The entity which ultimately became BPC
was initially incorporated in the State of Utah in March 1980, and changed its
state of incorporation to the State of Delaware in June 1986. The Company's
current operations include the ownership of one operational cogeneration
facility, a 50% interest in another cogeneration facility, a cogeneration
operations and management company and an oil and gas company engaged in the
exploration and production of oil and natural gas and in the gathering and
marketing of natural gas and other forms of energy. At October 31, 1998, BPSC
also had an interest in an additional cogeneration facility in the start-up
phase in Mexico.
Cash and Cash Equivalents - The Company considers all highly-liquid investments
with an original maturity of three months or less to be cash equivalents. From
time to time, BPC has had cash and cash equivalents which exceeded the Federal
Deposit Insurance Corporation's insurance limit of $100,000, however, during
the pendency of the reorganization proceedings, the banks have pledged United
States Treasury notes to the US Bankruptcy Trustee, or have obtained a
performance bond to guarantee the liquidity of the deposits.
Use of Estimates in the Preparation of Financial Statements - The preparation
of financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions that affect
the reported amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial statements and the reported
amounts of revenue and expenses during the reporting period. Actual results
could differ from those estimates.
Investment in Partnership - BPC through a wholly-owned subsidiary, BNC, is a
50% general partner in Nevada Cogeneration Associates #1 ("NCA #1").
The investment in NCA #1, accounted for under the equity method, is recorded at
cost, as adjusted for BNC's share of earnings and distributions received.
Oil and Gas Properties - BFC follows the "successful efforts" method of
accounting for its oil and gas properties, all of which are located in the
continental United States. Under this method of accounting, all property
acquisition costs and costs of exploratory and development wells are
capitalized when incurred, pending determination of whether the well has found
proved reserves. If an exploratory well has not found proved reserves, the
costs of drilling the well are charged to expense. The costs of development
wells are capitalized whether productive or nonproductive.
Geological and geophysical costs and the costs of carrying and retaining
undeveloped properties are expensed as incurred. Depreciation and depletion of
capitalized costs for producing oil and gas properties is provided for using
the units-of-production method based upon proved reserves for each field.
In 1997, BFC began to accrue for future plugging, abandonment, and remediation
using the negative salvage value method whereby costs are expensed through
additional depletion expense over the remaining economic lives of the wells.
Management's estimate of the total future costs to plug, abandon, and remediate
BFC's share of all existing wells, including those currently shut-in, is
approximately $3,800,000, net of salvage values. The cumulative total accrued,
as additional accumulated depletion, was $367,000 as of October 31, 1998.
Gains and losses are generally recognized upon the sale of interests in proved
oil and gas properties based on the portion of the property sold. For sales of
partial interests in unproved properties, BFC reflects the proceeds as a
recovery of costs with no gain recognized until all costs have been recovered.
Other Property and Equipment - Depreciation of other property and equipment is
calculated using the straight-line method over the estimated useful lives
(ranging from 3 to 25 years) of the respective assets. The cost of normal
maintenance and repairs is charged to operating expenses as incurred. Material
expenditures which increase the life of an asset are capitalized and
depreciated over the estimated remaining useful life of the asset. When
properties are sold, or otherwise disposed of, the cost of the property and
the related accumulated depreciation or amortization are removed
from the accounts, and any gains or losses are reflected in current operations.
Impairment of Assets - The Company follows Statement of Financial Accounting
Standards No. 121, Accounting for Impairment of Long-Lived Assets. When facts
and circumstances indicate that the carrying value of an asset is impaired, the
Company estimates the future undiscounted cash flows from that asset and
compares that amount to the carrying value. If it is determined that an
impairment is required, the asset is written down to its fair market value.
Net capitalized costs of oil and gas properties are limited to the aggregate
undiscounted future net revenues related to each field. If the net capitalized
costs exceed the limitation, impairment is provided to reduce the
carrying value of the oil and gas properties to fair market value.
Income Taxes - The Company accounts for income taxes under the liability method
of Statement of Financial Accounting Standards No. 109, Accounting for Income
Taxes (SFAS 109). SFAS 109 requires recognition of deferred tax assets and
liabilities for the expected future tax consequences of events that have been
included in the financial statements or tax returns. Under this method,
deferred tax assets and liabilities are determined based on the difference
between the financial statement and tax basis of assets and liabilities using
enacted tax rates in effect for the year in which the differences are expected
to reverse.
Accounting for Hedged Transactions - In order to mitigate the risk of market
price fluctuations, BFC enters into futures, swaps, and term gas sales
contracts as hedges of commodity prices associated with its oil and gas
production and the purchase and sale of natural gas. Changes in the market
value of futures, swaps, and term gas contracts are deferred until the gain or
loss is recognized on the hedged production or transactions.
Segment Reporting - The Company has adopted FAS 131 Disclosures About Segments
of an Enterprise and Related Information. FAS 131 replaces FAS 14 and utilizes
the "management approach" whereby external financial reporting is aligned with
internal reporting. FAS 131 defines an operating segment as a component of an
enterprise that engages in business activity for which it may earn revenues and
incur expenses, whose operating results are regularly reviewed by the entity's
chief operating decision maker to allocate resources and assess performance,
and for which discrete financial information is available. The Company has
identified the following reportable operating segments: Bonneville Fuels
Corporation, Bonneville Pacific Services Company Inc., and Bonneville Nevada
Corporation.
Impact of Recently Issued Accounting Pronouncements - In June 1998, the
Financial Accounting Standards Board issued No. 133, (SFAS 133), Accounting for
Derivative Instruments and Hedging Activities. This statement is effective for
fiscal years beginning after June 15, 1999. Earlier application is encouraged;
however, the Company does not anticipate adopting SFAS 133 until the fiscal
year beginning January 1, 2000. SFAS 133 requires that an entity recognize
all derivatives as assets or liabilities in the statement of financial position
and measure those instruments at fair value. Although the Company is
currently evaluating SFAS 133, it is not expected to have a material impact on
the financial condition or results of operations of the Company.
NOTE 4 - Impairment of Long-Lived Assets - The analysis of future cash
flows of the Company's oil and gas properties and the related fair value
of those properties by BFC resulted in an impairment charge of $1,600,000
as of October 31, 1998. After the effective date of the Plan, the Company's
newly appointed Board of Directors determined that it would not renew the
contract related to a small cogeneration plant which will now expire
pursuant to its terms in April 1999. The Company also reviewed the carrying
value of the small cogeneration plant in Mexico that is in the start-up
phase and determined that it should be impaired. Consquently, the Company
took impairment charges for the cogeneration assets of approximately $2,541,000
as of October 31, 1998, to reduce the net book value of these assets to their
fair value.
The Company also reviewed the carrying value of a certain parcel
of undeveloped real estate and recorded approximately $150,000 impairment.
NOTE 5 - Investment in NCA#1 Partnership - BPC, through BNC, is a 50% general
partner in the NCA#1 partnership. The remaining 50% is owned by Texaco
Clark County Cogeneration Company ("TCCCC"). The NCA#1 partnership owns
and operates an 85 megawatt electric generating facility (the "Facility")
in Clark County, Nevada. BNC receives a 50% allocation of income (loss),
depreciation expense and other tax benefits from the operations of NCA#1.
In accordance with the partnership agreement, BNC initially received a
66 2/3% share of net cash distributions until such net cash distributions
equaled approximately $18,800,000 (September 1997) at which time BNC's
share of net cash distributions changed to 50%. The NCA#1 partnership
will terminate, unless terminated earlier by partner agreement, on the
latter of April 30, 2023, or the date that NCA#1 elects to cease
operations.
Summary condensed balance sheet data and significant accounting disclosures for
NCA #1 as of October 31, 1998 are as follows:
<TABLE>
<S> <C>
1998
(in 000's)
Assets:
Cash and cash equivalents $ 10,958
Other current assets 4,340
Operating facility and equipment, net 80,093
Other assets 11,510
Total assets $ 106,901
Liabilities and partners'equity:
Project financing loan payable and bonds
payable $ 74,892
Notes and other payables to affiliates 1,473
Other liabilities 5,226
Partners' equity:
Bonneville Nevada 9,744
TCCCC 15,566
Total liabilities and partners' equity $106,901
</TABLE>
The Facility was completed during 1992 and commercial operation began on June
18, 1992. All costs, including interest and field overhead expenses, incurred
prior to commercial operations were capitalized as part of the Facility. The
Facility is being depreciated on a straight-line basis over 30 years.
Expenditures for maintenance, repairs and minor renewals are charged to expense
as incurred, and expenditures for additions and improvements are capitalized.
The facility requires significant maintenance every 25,000 and 50,000 operating
hours. The expected cost of this maintenance is accrued using a straight-line
method over the respective periods. Due to fluctuations in the extent of
repairs, prices and changes in the timing of the scheduled events, the estimated
costs of these events can differ from actual costs incurred. All legal and
financing fees associated with NCA #1's project financing loan and bonds
payable including the cost of subsequent amendments were deferred and are being
amortized over the terms of the financing.
In July 1991, NCA #1 entered into a Construction Loan, Term Loan and
Reimbursement Agreement (the "Agreement") with several banks to finance the
majority of the construction costs of the Facility. In April 1993, the loan
was converted to a term loan of $63,938,000. The debt is scheduled to be
reduced on dates and by amounts as specified in the Agreement through October
2007, unless terminated earlier as provided for in the Agreement. The
Agreement places certain restrictions on cash accounts, capital distributions
and permitted investments. The Agreement is collateralized by substantially all
of the assets of NCA #1, as well as BNC's interest in the NCA #1 partnership.
The amount outstanding under the Agreement bears interest at a market rate plus
a margin. NCA #1 has entered into interest rate swap agreements with
commercial banks to reduce the exposure to higher interest rates. If the
variable interest exceeds the fixed rate established by the swap agreements,
NCA #1 could be exposed to the risk of higher interest costs in the event of
nonperformance by the commercial banks. The weighted average interest rate,
inclusive of the effect of the swap agreements, on the outstanding loan balance
was approximately 7.18% at October 31, 1998.
The bankruptcy of BPC was an event of default, prior to 1996, under a covenant
in the Agreement. This event of default gave the lenders the right to call the
loan and to require redemption of the tax-exempt bonds at any time. During
1996, the Partnership amended the Loan and Reimbursement Agreement which became
effective October 30, 1996, therein waiving the event of default regarding
BPC's bankrupt status. The amendment also reduced the lender's margin by 1/4%,
reduced the restricted cash accounts required, and changed the reporting
requirements for the project.
The future minimum payments on the debt outstanding and the letters of credit
supporting the tax-exempt bonds at October 31, 1998, are as follows: November
and December 1998 - $1,124,000; 1999 - $5,138,000; 2000 - $5,689,000; 2001 -
$6,239,000; 2002 - $6,881,000; 2003 - $7,798,812, and for the years thereafter
a total of $14,622,000.
NCA #1 also obtained $27,400,000 of long-term project financing in the form of
variable rate industrial development revenue bonds. BPC and the parent of
TCCCC have guaranteed repayment of these bonds. The bonds are due and payable
on November 1, 2020 and November 1, 2021. The interest rate on the bonds was
approximately 4.42% at October 31, 1998. As set forth in the Plan, BPC has
guaranteed repayment of the industrial revenue bonds. NCA #1 is considering
refinancing these bonds.
NCA #1 has an agreement for long-term power purchases of energy and capacity by
Nevada Power Company (NPC) that terminates on April 30, 2023. NCA #1 is paid
for energy delivered based upon fixed rates, as defined in the agreement,
adjusted annually at 120% of the change in the CPI. NPC also pays NCA #1 for
firm capacity based upon fixed rates, as defined, increased annually by 2%.
During 1997, NCA #1 negotiated an amendment to the agreement severely limiting
NPC's curtailment rights in exchange for a price discount of $.25 per megawatt
hour. The amendment was signed on October 3, 1997 and was approved by Nevada
Public Utility Commission subsequent to December 31, 1997. Pursuant to the
amended agreement, upon mutual consent, NCA #1 has the right to release NPC
from its purchase obligation for an agreed upon payment per released megawatt.
NCA #1 also has a long-term process heat sales agreement with Georgia-Pacific
Corporation which terminates on April 30, 2023, or earlier, as defined in the
agreement. NCA #1 has a number of long-term fuel-gas purchase contracts and
transportation contracts with various parties including affiliates of TCCCC.
NCA #1 also has an equipment lease agreement which requires monthly payments of
$24,000 plus sales tax over a 10-year term ending December 31, 2002.
The Facility is operated and maintained by BPSC. BPSC is paid for all costs
incurred in connection with the operation and maintenance of the Facility
including an annual operating fee of $260,000, adjusted annually by the
Consumer Price Index. BPSC also may earn a performance bonus upon meeting
specified operating goals, as defined in the agreement.
NCA #1, under agreements, pays for certain engineering and administrative
expenses and other costs to TCCCC and its subsidiaries. TCCCC may earn a
performance bonus based upon the plant achieving certain operational goals, as
defined in the agreement.
In 1997, the Nevada Legislature passed legislation to restructure the Nevada
electric utility industry. The legislation (AB366) calls for competition to
commence by January 1, 2000. The eventual outcome of these activities and
their potential impact, if any, upon NCA #1 is not known.
Income taxes are not recorded by NCA #1 since the net income or loss allocated
to the partners is included in each partner's respective income tax return.
Under the terms of the NCA #1 Partnership Agreement, at TCCCC's one-time
option, BNC will be required to purchase or cause to be purchased, TCCCC's
ownership interest in NCA #1 at fair market value as determined by an
independent appraisal. TCCCC's one-time option becomes effective on June 18,
2012.
NCA #1 has been in negotiations with the United States Environmental Protection
Agency (the "EPA") regarding emissions from its gas turbine engines.
Subsequent to October 31, 1998, the EPA filed a lawsuit against NCA #1, BNC and
TCCCC, seeking damages of $25,000 per day from a unspecified point in time and
the installation of custom emission controlling equipment. NCA #1, BNC and
TCCCC, the partners to NCA #1, have signed a consent decree prepared by the
U.S. Department of Justice that resolves the above mentioned lawsuit and
requires NCA #1 to pay a $100,000 fine and install the emission controlling
equipment. The decree still requires the signature of the other parties to the
action. The cost of purchasing and installing the equipment and the proposed
fine have been accrued by NCA #1 and are being held in a control account.
NCA#1 believes that it will have no additional liability for the violations
alleged in the above mentioned lawsuit after the consent decree has been
executed and entered in the court.
Subsequent to October 31, 1998, the Nevada Public Utilities Commission gave
tentative approval for the merger of the Company's main customer with another
utility company in Nevada. The ultimate impact, if this merger proceeds, on
NCA #1 is not known at this time.
NOTE 6 - LONG-TERM DEBT:
BFC has an asset-based line-of-credit with a bank which provides for borrowing
up to the borrowing base (as defined). The borrowing base was $11,500,000 at
October 31, 1998. At October 31, 1998, outstanding borrowings amounted to
$3,900,000, with interest at a variable rate that approximated 7.25% at October
31, 1998. BFC has issued letters of credit totaling $3,325,000 which further
reduces the amount available for borrowing under the base. This facility is
collateralized by certain oil and gas properties of BFC and is scheduled to
convert to a term note on July 1, 2001. This term loan is scheduled to have a
maturity of either the economic half life of BFC's remaining reserves on the
date of conversion, or July 1, 2006, whichever is earlier. The borrowing base
is based upon the lender's evaluation of BFC's proved oil and gas reserves,
generally determined semi-annually. The future minimum principal payments
under the term note will be dependent upon the bank's evaluation of BFC's
reserves at that time.
BFC also has an accounts receivable-based credit facility which includes a
revolving line-of-credit with the bank which provides for borrowings up to
$1,500,000. There were no outstanding borrowings under this facility at
October 1998. This facility bears interest at prime (8% at October 31,
1998). This facility is collateralized by certain trade receivables of BFC and
has a maturity date of July 1, 1999.
The credit agreement contains various covenants which prohibit or limit the
subsidiary's ability to pay dividends, purchase treasury shares, incur
indebtedness, repay debt to BPC, sell properties or merge with another entity.
Additionally, BFC is required to maintain certain financial ratios.
BPC's pre-petition debt agreements contain various financial and operational
covenants. While covenants in substantially all of these agreements have been
breached, the related debt was settled as part of the Plan.
See Note 5 for a discussion of long-term debt of NCA #1.
NOTE 7 - COMMITMENTS:
Office Lease - The Company leases office space under noncancellable operating
leases. The total minimum rental commitments at October 31, 1998 are as
follows:
<TABLE>
<C>
($ in 000's)
<S>
Remaining 1998 $ 40
1999 161
2000 124
2001 129
2002 88
$ 542
</TABLE>
NOTE 8 - INCOME TAXES: Long-term deferred tax assets and liabilities are
comprised of the following as of October 31, 1998:
<TABLE>
<C>
<S> ($ in 000's)
Deferred tax assets:
Net operating loss carryforward $ 7,829
Depreciation, depletion, amortization and impairment 1,590
Liabilities recognized for book purposes prior to
realization for tax purposes 14,033
Gross deferred tax assets 23,452
Deferred tax liabilities:
Investment in NCA #1, primarily depreciation,
depletion and amortization 1,787
Net deferred tax asset, before valuation allowance 21,665
Valuation allowance (21,665)
Net deferred tax asset, after valuation allowance $ -
At October 31, 1998, the Company had Federal income tax net operating loss
carryforwards of approximately $22,369,000 which expire from 2010 through 2014.
</TABLE>
<PAGE>
Under Section 382 of the Internal Revenue Code of 1986, as amended, if certain
significant ownership changes occur, there could be an annual limitation on the
amount of net operating loss carryforwards which may be utilized. The Company
may have experienced a change in ownership under these rules prior to December
31, 1997. Consequently, certain net operating loss carryforwards may be
limited. There may be additional limitations due to the confirmation of the
Plan.
NOTE 9 - EMPLOYEE BENEFITS: Employee Stock Ownership Plan - On April 28, 1989,
BPC adopted the Bonneville Pacific Corporation Employee Stock Ownership Plan
(the "ESOP"). The ESOP had an allowed claim against BPC of $984,000 which claim
was distributed to the ESOP participants and was satisfied by the Plan.
The ESOP was terminated in 1997.
Employee Qualified 401(k) Retirement Plan - Effective January 1, 1990, BPC
adopted a qualified retirement plan under Sections 401(a) and 401(k) of the
Internal Revenue Code. The Company may match employees' contributions at the
Company's discretion. No company contributions were made in 1998 through
October 31.
Management Retention Program - In 1997, the Court approved a management
retention program in order to retain certain key employees of the subsidiary
companies. The retention program provides for the payment of certain cash
severance benefits upon (a) an employee's termination without cause absent a
change in control, or (b) termination from a change in control. Additionally,
the retention programs provide benefits upon (a) the death of the employee or
(b) the successful confirmation of the Plan. BFC and BPSC accrued $600,000 for
the retention program in 1997.
Subsequent to October 31, 1998, the Board of Directors expanded the program to
include benefits to some additional Company employees.
Stock Options - Subsequent to October 31, 1998, the Company's Board of
Directors approved the issuance of a total of 45,000 options to its outside
directors to purchase common stock at $9.44 per share exercisable over a
10-year period (which share price takes into account the reverse stock split
which was effective on November 2, 1998).
NOTE 10 - STOCKHOLDERS' EQUITY:
Treasury Stock - At the effective date of the Plan, the treasury stock held by
the Company and the Company stock held by the Trustee was cancelled with the
Company now holding such stock as authorized but not issued common stock.
Reverse Stock Split - The Plan provided for a one for four reverse stock
split. This reverse stock split was effective on November 2, 1998.
Shares Issued - Pursuant to the Plan, the Company issued stock in satisfaction
of certain claims. See Note 2 for a discussion of the shares issued. After
the effective date of the Plan and taking into account the reverse stock split,
there were a total of 7,227,000 shares of the Company's stock issued and
outstanding.
NOTE 11 - CONCENTRATIONS OF CREDIT RISK:
Approximately 77% of the Company's accounts receivable at October 31, 1998
result from BFC's crude oil and natural gas sales and/or joint interest
billings to companies in the oil and gas industry. This concentration of
customers and joint interest owners may impact the Company's overall credit
risk, either positively or negatively, since these entities may be similarly
affected by changes in economic or other conditions. In determining whether
or not to require collateral from a customer or joint interest owner, the
Company analyzes the entity's net worth, cash flows, earnings, and credit
ratings. Receivables are generally not collateralized. Historical credit
losses incurred on trade receivables by the Company have been insignificant.
The nature of the power generation business is such that each facility generally
relies on one power or thermal sales agreement with a single electric customer
for substantially all, if not all, of such facility's revenue over the life of
the project. The power and thermal sales agreements are generally long-term
agreements, covering the sale of electricity or thermal energy for initial
terms of 20 or 30 years. However, the loss of any one major power or thermal
sales agreement with any of these customers could have a material adverse
effect on cash flow and, as a result, on results of operations.
Furthermore, each power generation facility may depend on a single or limited
number of entities to purchase thermal energy, or to supply or transport
natural gas to such facility. The failure of any one customer, thermal host,
gas supplier or gas transporter to fulfill its contractual obligations could
have a material adverse effect on a power project's qualifying status under
regulations and on the Company's business and results of operations.
NOTE 12 - FINANCIAL INSTRUMENTS:
Statement of Financial Accounting Standards No. 107 and 127 requires certain
entities to disclose the fair value of certain financial instruments in their
financial statements. Accordingly, management's best estimate is that the
carrying amount of cash, receivables, notes payable, accounts payable,
undistributed revenue, and accrued expenses approximates fair value of these
instruments, other than liabilities subject to compromise, for which the
estimated fair value equals the amount of settlement as discussed in Note 2.
Energy Financial Instruments - BFC uses energy financial instruments and long-
term gas sales contracts to minimize its risk of price changes in the natural
gas and crude oil markets. Energy risk management products used include
commodity futures and options, long-term gas sales contracts, fixed-price
swaps, and basis swaps. Pursuant to company guidelines BFC is to engage in
these activities only as a hedging mechanism against price volatility
associated with pre-existing or anticipated gas or crude oil sales in order to
protect profit margins. As of October 31, 1998, BFC has financial and physical
contracts which hedge 5,835,000 MMbtu's of production through October 2001.
The current market value of the hedging contracts was $(35,000) as of October
31, 1998. This amount is not reflected in the accompanying balance sheet. In
the event energy financial instruments do not qualify for hedge accounting, the
difference between the current market value and the original contract value
would be currently recognized in the statement of operations. In the event
that the energy financial instruments are terminated prior to the delivery of
the item being hedged, the gains and losses at the time of the termination are
deferred until the period of physical delivery. Such deferrals were immaterial
as of October 31, 1998.
NOTE 13 - SEGMENT INFORMATION:
The Company has identified the following segments: BFC, BNC, and BPSC. BFC is
primarily engaged in oil and gas production and energy marketing. BNC owns a
50% interest in NCA #1 which is engaged in cogeneration activities. BPSC is
primarily engaged in providing operational and maintenance services to
cogeneration plants. At October 31, 1998, BPSC also had an interest in an
additional cogeneration facility in the start-up phase in Mexico.
The accounting policies of the segments are the same as those described in the
summary of significant accounting policies. The Company evaluates performance
based on profit or loss from operations before reorganization items and income
taxes.
<TABLE>
<S> <C> <C> <C> <C> <C>
BFC BNC BPSC Corporate Total
($in 000's)
October 31, 1998
Segment assets
actual as of
October 31 $17,358 $13,125 $ 2,464 $160,399 $193,346
</TABLE>
<PAGE>
NOTE 14 - OIL AND GAS PRODUCING ACTIVITIES AS OF OCTOBER 31, 1998:
BFC's oil and gas producing activities are all located in the United States.
The following is certain information with respect to the activities.
<TABLE>
<C>
October 31,
1998
($ in 000's)
<S>
Capitalized Costs Relating to Oil and Gas Properties
Unproved oil and gas properties $ 2,155
Proved oil and gas properties 30,546
Gas gathering system 158
32,859
Accumulated depreciation, depletion, amortization and
impairment (20,031)
Net capitalized costs $ 12,828
Costs Incurred in Oil and Gas Property Acquisition,
Exploration and Development Activities
Acquisition of properties:
Proved $ -
Unproved 202
202
Exploration costs 1,027
Development Costs 3,078
$ 4,307
</TABLE>
NOTE 15 -OIL AND GAS RESERVE INFORMATION AS OF DECEMBER 31, 1997
(UNAUDITED):
The following quantity and value information is based on prices as of December
31, 1997. No price escalations were assumed. Subsequent to December 31, 1997,
however, there have been substantial price declines in oil and gas. As the
Company only performs detailed independent oil and gas reserve evaluations on
an annual basis at year-end (December 31), the information included in this
note does not consider the subsequent price declines nor other factors,
including discoveries and revisions of previous quantity estimates, which have
occurred subsequent to December 31, 1997. The Company did consider these
factors when analyzing the impairment recognized as of October 31, 1998, as
described in Note 4. Operating costs and production taxes were deducted in
determining the quantity and value information. Such costs were estimated
based on current costs and were not adjusted to anticipate increases due to
inflation or other factors. No deductions were made for general overhead,
depreciation and interest.
The determination of oil and gas reserves is based on estimates and is highly
complex and interpretive. The estimates are subject to continuing change as
additional information becomes available and an accurate determination of the
reserves may not be possible for several years after discovery. Reserve
information presented herein (as of December 31, 1997) is based on reports
prepared by an independent petroleum engineer.
Estimated Quantities of Proved Oil and Gas Reserves - The following is a
reconciliation of BFC's interest in net quantities of proved oil and gas
reserves. Proved reserves are the estimated quantities of crude oil and
natural gas which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions. Estimated reserves of oil
(barrels) and natural gas (thousands of cubic feet) as of December 31, 1997
are as follows:
<TABLE>
<S> <C>
For the Year
Ended
December 31,
1997
Gas Oil
Proved developed and undeveloped reserves 23,140 298
Proved developed reserves 22,623 298
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Gas Reserves
Estimated discounted future net cash flows and changes therein were determined
in accordance with Statement of Financial Accounting Standards No. 69. Certain
information concerning the assumptions used in computing the valuation of
proved reserves and their inherent limitations are discussed below. The
Company believes such information is essential for a proper understanding and
assessment of the data presented.
Future cash inflows are computed by applying year-end prices of oil and gas
relating to BFC's proved reserves to the year-end quantities of those reserves.
The assumptions used to compute the proved reserve valuation do not necessarily
reflect BFC's expectations of actual revenues to be derived from those reserves
nor their present worth. Assigning monetary values to the reserve quantity
estimation process does not reduce the subjective and ever-changing nature of
such reserve estimates.
Additional subjectivity occurs when determining present values because the rate
of producing the reserves must be estimated. In addition to subjectivity
inherent in predicting the future, variations from the expected production rate
also could result directly or indirectly from factors outside BFC's control,
such as unintentional delays in development, environmental concerns and changes
in prices or regulatory controls.
The reserve valuation assumes that all reserves will be disposed of by
production. However, if reserves are sold in place, additional economic
considerations also could affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and gas
reserves at the end of the year, based on year-end costs and assuming
continuation of existing economic conditions.
Future income tax expense has not been provided based on the availability of
net operating loss carryforwards and other deductions. The usage of these
carryforwards may be limited based upon a past change in ownership of BPC.
There may be additional limitations on the availability of net operating loss
carryforwards due to the confirmation of the Plan.
A discount rate of 10% per year was used to reflect the timing of the future
net cash flows.
<TABLE>
<C>
December 31
1997
($ in 000's)
<S>
Future cash inflows $ 46,859
Future production and development costs 18,155
28,704
10% annual discount for estimated timing of cash (9,075)
flows
Standardized measure of discounted future net cash 19,629
flows
</TABLE>
SIGNATURES
Pursuant to the requirements of the Securities Act of 1934, the Registrant
has duly caused this report to be signed on its behalf by the undersigned
thereunto duly authorized.
Dated: November 2, 1998 BONNEVILLE PACIFIC CORPORATION
BY: /s/ Clark M. Mower
Clark M. Mower
President
Bonneville Pacific Corporation
(Chapter 11 Debtor) and Subsidiaries
Consolidated Balance Sheet
October 31, 1998
