FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the quarterly period ended December 31, 2002
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission File number 0-14183
ENERGY WEST INCORPORATED
------------------------------------------------------
(Exact name of registrant as specified in its charter)
Montana 81-0141785
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1 First Avenue South, Great Falls, Mt. 59401
---------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (406)-791-7500
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 checkmark whether the registrant is an accelerated filer (as defined
in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date.
Class Outstanding at February 11, 2003
(Common stock, $.15par value) 2,591,360 shares
ENERGY WEST INCORPORATED
INDEX TO FORM 10-Q
Page No.
Part I - Financial Information
Item 1 - Financial Statements
Condensed Consolidated Balance Sheets as of
December 31, 2002, December 31, 2001, and June 30, 2002 1
Condensed Consolidated Statements of Operations -
three months and six months ended December 31, 2002 and 2001 2
Condensed Consolidated Statements of Cash Flows -
six months ended December 31, 2002 and 2001 3
Notes to Condensed Consolidated Financial Statements 4-8
Item 2 - Management's Discussion and Analysis of
Financial Condition and Results of Operations 9-21
Item 3 - Quantitative and Qualitative Disclosures about Market Risk 21-22
Item 4 - Controls and Procedures 22
Part II Other Information
Item 1 - Legal Proceedings 23
Item 2 - Changes in Securities 24
Item 3 - Defaults upon Senior Securities 24
Item 4 - Submission of Matters to a Vote of Security Holders 24
Item 5 - Other Information 24
Item 6 - Exhibits and Reports on Form 8-K 25-29
Signatures
Item 1. Financial Statements
FORM 10Q
ENERGY WEST INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
December 31 December 31 June 30
2002 2001 2002
(Unaudited) (Unaudited) (Unaudited)
-------------------------------------------------------
Current assets
Cash and cash equivalents $ 1,369,661 $ 562,592 $ 367,657
Accounts receivable (net) 12,512,040 14,010,028 8,244,239
Derivative assets 2,689,964 5,862,665 2,867,717
Natural gas and propane inventories 2,281,048 7,502,315 5,640,660
Materials and supplies 514,478 654,337 593,674
Prepayments and other 518,461 600,709 445,652
Deferred tax assets 395,811 931,147
Deferred purchase gas costs 3,776,358
Prepaid income tax payments 1,676,502 241,416
-------------------------------------------------------
Total current assets 21,957,965 33,210,420 19,090,746
-------------------------------------------------------
Notes receivable 3,300 3,300
Property, plant and equipment, net 37,822,628 34,648,397 36,518,908
Deferred charges 1,907,770 2,092,310 1,935,263
Other assets 292,380 367,860 320,830
-------------------------------------------------------
Total assets $ 61,980,743 $ 70,322,287 $ 57,869,047
=======================================================
Capitalization and liabilities
Current liabilities:
Lines of credit $ 10,642,078 $ 14,220,869 $ 3,500,000
Current portion of long term-debt 507,147 470,000 502,072
Accounts payable 7,933,012 6,039,244 7,413,693
Income tax payable 1,005,975
Deferred tax liabilities 233,631
Derivative liabilities 412,073 6,057,940
Refundable cost of gas purchases 115,158 2,024,159
Accrued and other current liabilities 5,117,111 5,489,248 5,453,304
-------------------------------------------------------
Total current liabilities 24,726,579 32,510,932 19,899,203
-------------------------------------------------------
Long-term liabilities:
Deferred tax liabilities 4,430,306 3,937,944 4,043,038
Deferred investment tax credits 365,937 386,999 376,468
Other long-term liabilities 2,354,254 2,161,640 1,910,571
-------------------------------------------------------
Total 7,150,497 6,486,583 6,330,077
Long-term debt 15,280,750 15,776,000 15,367,424
Stockholders' equity
Preferred stock -- $.15 par value
Authorized -- 1,500,000 shares
Outstanding -- none
Common stock
Authorized -- 3,500,000 shares
Outstanding -- 2,590,672 shares
at December 31, 2002; 2,565,590
shares at December 31, 2001;
2,573,046 at June 30, 2002 388,608 384,855 385,964
Capital in excess of par value 5,022,397 4,791,890 4,863,113
Retained earnings 9,411,912 10,372,027 11,023,266
-------------------------------------------------------
Total stockholders' equity 14,822,917 15,548,772 16,272,343
-------------------------------------------------------
Total capitalization 30,103,667 31,324,772 31,639,767
-------------------------------------------------------
Total capitalization and liabilities $ 61,980,743 $ 70,322,287 $ 57,869,047
=======================================================
The accompanying notes are an integral part of these condensed
financial statements.
1
FORM 10Q
ENERGY WEST INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Three Months Ended Six Months Ended
Second Quarter and Year-To-Date
December 31 December 31
2002 2001 2002 2001
(Unaudited) (Unaudited) (Unaudited) (Unaudited)
-----------------------------------------------------------------------
Revenues:
Natural gas operations $ 9,559,804 $ 12,182,489 $ 12,615,179 $ 17,021,177
Propane operations 4,001,494 2,729,164 5,331,644 3,835,400
Gas and electric-wholesale 11,307,459 11,547,103 19,361,370 22,410,649
Pipeline 69,534 153,278
-----------------------------------------------------------------------
Total revenues 24,938,291 26,458,756 37,461,471 43,267,226
-----------------------------------------------------------------------
Expenses:
Gas & propane purchased 9,225,480 10,951,131 11,736,590 14,970,519
Gas and electric-wholesale 10,694,588 10,792,058 18,343,395 20,880,721
Distribution, general and administrative 3,650,973 2,496,537 6,380,567 4,781,110
Maintenance 128,057 116,458 292,608 211,699
Depreciation and amortization 551,974 515,287 1,110,275 1,029,481
Taxes other than income 216,026 229,917 438,578 406,315
-----------------------------------------------------------------------
Total operating expenses 24,467,098 25,101,388 38,302,013 42,279,845
-----------------------------------------------------------------------
Operating income (loss) 471,193 1,357,368 (840,542) 987,381
Non-operating income 84,050 77,527 162,020 162,032
Interest expense:
Long-term debt 291,452 299,096 584,064 599,252
Lines of credit 113,972 204,243 208,460 280,921
-----------------------------------------------------------------------
Total interest expense 405,424 503,339 792,524 880,173
-----------------------------------------------------------------------
Income (loss) before income tax benefit 149,819 931,556 (1,471,046) 269,240
Income tax expense (benefit) 29,008 309,012 (571,282) 80,042
-----------------------------------------------------------------------
Net income (loss) $ 120,811 $ 622,544 $ (899,764) $ 189,198
=======================================================================
Earnings (loss) per common share:
Basic and diluted earnings (loss) per common share $ 0.05 $ 0.25 $ (0.35) $ 0.07
Weighted average common shares outstanding:
Basic 2,579,948 2,528,572 2,579,948 2,528,572
Diluted 2,579,948 2,538,707 2,579,948 2,538,707
The accompanying notes are an integral part of these condensed
financial statements.
2
FORM 10Q
ENERGY WEST INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended
December 31
2002 2001
(Unaudited) (Unaudited)
--------------------------------
Cash flow from operating activities:
Net income (loss) $ (899,764) $ 189,198
Adjustment to reconcile net income (loss) to net cash flows
used in operating activities
Depreciation and amortization, including deferred charges and
financing costs 1,159,980 1,124,509
Gain on sale of property, plant & equipment (25,420)
Deferred gain on sale of assets (11,814) (11,814)
Investment tax credit - net (10,531) (10,531)
Deferred income taxes - net 922,604 (295,243)
Change in operating assets and liabilities
Accounts receivable - net (4,267,801) (3,678,625)
Derivative assets 177,753 (2,417,804)
Natural gas and propane inventories 3,359,612 (2,734,769)
Prepayments and other (72,809) (199,567)
Recoverable/refundable cost of gas purchases (1,909,001) 3,047,862
Accounts payable (1,480,681) (3,265,876)
Derivative liabilities 412,073 2,136,586
Other assets and liabilities (374,587) (837,202)
--------------------------------
Net cash used in operating activities (2,994,966) (6,978,696)
Cash flow used in investing activities:
Construction expenditures (2,442,498) (2,684,962)
Proceeds from sale of property, plant & equipment 41,468
Collection of long-term notes receivable 3,300 134,627
Customer advances for construction 22,460
Proceeds from (repayments of) contributions in aid of constructions 20,948 (1,854)
--------------------------------
Net cash used in investing activities (2,395,790) (2,510,721)
Cash flow from financing activities:
Repayment of long-term debt (81,599) (100,000)
Proceeds from lines of credit 22,154,697 30,761,025
Repayment of lines of credit (15,012,619) (20,326,145)
Sale of common stock 91,575
Dividends on common stock (667,719) (595,113)
--------------------------------
Net cash provided by financing activities 6,392,760 9,831,342
--------------------------------
Net increase in cash and cash equivalents 1,002,004 341,925
Cash and cash equivalents at beginning of year 367,657 220,667
--------------------------------
Cash and cash equivalents at end of period $ 1,369,661 $ 562,592
================================
The accompanying notes are an integral part of these condensed
financial statements.
3
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
December 31, 2002
NOTE 1 - BASIS OF PRESENTATION
The accompanying unaudited condensed consolidated financial statements
of Energy West Incorporated (the Company) and its subsidiaries have been
prepared in accordance with accounting principles generally accepted in the
United States of America for interim financial information and with the
instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do
not include all of the information and footnotes required by generally accepted
accounting principles for complete financial statements. In the opinion of
management, all adjustments (consisting of normal recurring accruals) considered
necessary for a fair presentation have been included. Operating results for the
six month period ended December 31, 2002 are not necessarily indicative of the
results that may be expected for the fiscal year ending June 30, 2003. The
financial statements should be read in conjunction with the audited consolidated
financial statements and footnotes thereto included in the Company's annual
report on Form 10-K for the fiscal year ended June 30, 2002.
The Company's reporting segments are: Natural Gas Operations, Propane
Operations, Energy Marketing and Wholesale Operations and Pipeline Operations.
To reflect recent management and business changes, the Company realigned its
reporting segments effective July 1, 2002. The Company's wholly owned
subsidiary, Energy West Development, Inc. (EWD), owns a renovated pipeline
located in Wyoming and Montana. An application is pending with the Federal
Energy Regulatory Commission (FERC) seeking approval for EWD to begin operations
of this pipeline as a transmission pipeline. The revenue and expenses associated
with this transmission pipeline will be included in the "Pipeline Operations"
segment for financial reporting purposes. EWD also owns a gathering system
pipeline in Wyoming. The revenue and expenses associated with this gathering
system pipeline were reported as part of the "Energy Marketing and Wholesale
Operations" segment for periods prior to fiscal 2003. Beginning with fiscal
2003, such revenue and expenses are reported as part of the "Pipeline
Operations" segment. Also beginning with fiscal 2003, the operations of a
regulated propane distribution system located in Cascade, Montana is reported
as part of the "Natural Gas Operations" segment. The Cascade, Montana system was
reported as part of the Company's "Propane Operations" segment prior to fiscal
2003. Segment information for prior periods has been restated to reflect the
realignment of the Company's reporting segments.
NOTE 2 -- DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY
Management of Risks Related to Derivatives--The Company and its
subsidiaries are subject to certain risks related to changes in certain
commodity prices and risks of counter-party performance. The Company has
established certain policies and procedures to manage such risks. The Company
has a Risk Management Committee (RMC), comprised of Company officers to oversee
the Company's risk management program as defined in its risk management policy.
The purpose of the risk management program is to minimize adverse impacts on
earnings resulting from volatility of energy prices, counter-party credit risks,
and other risks related to the energy commodity business. The RMC is overseen by
the Audit Committee of the Company's Board of Directors.
General--From time to time the Company or its subsidiaries may use
financial derivative contracts to mitigate the risk of commodity price
volatility related to firm commitments to purchase and sell natural gas or
electricity. The Company may use such arrangements to protect its profit margin
on future obligations to deliver quantities of a commodity at a fixed price.
Conversely, such arrangements may be used to hedge against future market price
declines where the Company or a subsidiary enters into an obligation to purchase
a commodity at a fixed price in the future. The Company accounts for such
financial instruments in accordance with Statement of Financial Accounting
Standard (SFAS) 133, Accounting for Derivative Instruments and Hedging
Activities, as amended by SFAS 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities.
4
In accordance with SFAS 133, contracts that do not qualify as normal
purchase and sale contracts must be reflected in the Company's financial
statements at fair value, determined as of the date of the balance sheet. This
accounting treatment is also referred to as "mark-to-market" accounting.
Mark-to-market accounting treatment can result in a disparity between reported
earnings and realized cash flow, because changes in the value of the financial
instrument are reported as income or loss even though no cash payment may have
been made between the parties to the contract. If such contracts are held to
maturity, the cash flow from the contracts, and their hedges, is realized over
the life of the contract.
Quoted market prices for natural gas derivative contracts of the
Company or its subsidiaries generally are not available. Therefore, to determine
the fair value of natural gas derivative contracts, the Company uses internally
developed valuation models that incorporate independently available current and
historical pricing information.
During the third quarter of fiscal 2002, Energy West Resources, Inc. (EWR)
terminated its existing derivative contracts with Enron Canada Corporation
(ECC), a subsidiary of Enron Corp. Most of these contracts were commodity swaps
that EWR had entered into to mitigate the effects of fluctuations in the market
price of natural gas. The derivative contracts with ECC were entered into at
various times in order to lock in margins on certain contracts under which EWR
had commitments to other parties to sell natural gas at fixed prices (the
"Future Supply Agreements"). EWR made the decision to terminate these ECC
contracts because of concerns relating to the bankruptcy of Enron Corp. At the
date of termination, the market price of natural gas was substantially lower
than the price had been when EWR entered into the contracts, resulting in a net
amount due from EWR to ECC of approximately $5,400,000. EWR paid this amount to
ECC upon the termination of the contracts, and thereby discharged the liability
related to the contracts. The costs related to such termination were reflected
in the Company's consolidated statement of income as adjustments to gas
purchased for the fiscal year ended June 30, 2002.
At the time the Company terminated the ECC derivative contracts, the
Company entered into new gas purchase contracts (the "Future Purchase
Agreements") at prices much lower than those provided for under the ECC
contracts. The Future Purchase Agreements and the Future Supply Agreements
continue to be valued on a mark-to market basis. As of December 31, 2002, these
agreements were reflected on the Company's consolidated balance sheet as
derivative assets and liabilities at an approximate fair value as follows:
Assets Liabilities
----------- -----------
Contracts maturing during fiscal 2003: $ 447,068 $ 103,836
Contracts maturing during fiscal 2004 and 2005: 1,445,714 126,565
Contracts maturing during 2006 and 2007: 615,789 84,002
Contracts maturing from fiscal 2008 and beyond: 181,393 97,670
----------- ----------
Total $ 2,689,964 $ 412,073
During the first six months of fiscal 2003, the Company did not enter into
any new contracts that would be accounted for using mark-to-market accounting
under SFAS 133.
Natural Gas Operations--In the case of the Company's regulated divisions,
gains or losses resulting from the derivative contracts are subject to deferral
under regulatory procedures approved by the public service regulatory
commissions of the States of Montana, Wyoming and Arizona. Therefore, related
derivative assets and liabilities are offset with corresponding regulatory
liability and asset amounts included in "Recoverable Cost of Gas Purchases",
pursuant to SFAS 71, Accounting for the Effects of Certain Types of Regulation.
5
NOTE 3 -- INCOME TAXES
Income tax benefit differs from the amount computed by applying the
federal statutory rate to pre-tax income (loss) as demonstrated in the following
table:
Three Months Ended Six Months Ended
December 31 December 31
-------------------- ------------------------
2002 2001 2002 2001
------- -------- --------- -------
Income tax expense (benefit) at statutory rates - 34%...... $51,899 $316,729 ($497,734) $91,542
State tax expense (benefit), net of federal tax benefit.... 33 21,789 (37,382) 871
Amortization of deferred investment tax credits............ (5,265) (5,265) (10,531) (10,532)
Other...................................................... (17,659) (24,241) (25,635) (1,839)
------- -------- --------- -------
Total income tax expense (benefit)......................... $29,008 $309,012 ($571,282) $80,042
NOTE 4 -- CONTINGENCIES
ENVIRONMENTAL CONTINGENCY
The Company owns property on which it operated a manufactured gas plant
from 1909 to 1928. The site is currently used as an office facility for Company
field personnel and storage location for certain equipment and materials. The
coal gasification process utilized in the plant resulted in the production of
certain by-products, which have been classified by the federal government and
the State of Montana as hazardous to the environment.
Several years ago the Company initiated an assessment of the site to
determine if remediation of the site was required. That assessment resulted in a
submission of a proposed remediation plan to the Montana Department of
Environmental Quality (MDEQ) in 1994. The Company has worked with the MDEQ since
that time to obtain the data that would lead to a remediation action acceptable
to the MDEQ. In the summer of 1999 the Company received final approval from the
MDEQ for its plan for remediation of soil contaminants. The Company has
completed its remediation of soil contaminants and in April of 2002 received a
closure letter from MDEQ approving the completion of such remediation program.
The Company and its consultants continue their work with the MDEQ relating to
the remediation plan for water contaminants.
As of December 31, 2002, the costs incurred by the Company in
evaluating and beginning the remediation have totaled approximately $1,964,000.
On May 30, 1995, the Company received an order from the Montana Public Service
Commission (MPSC) allowing for the recovery of the costs associated with the
evaluation and remediation of the site through a surcharge on customer bills. As
of December 31, 2002, the recovery mechanism had generated approximately
$1,393,000. The Company expects to recover the full amount expended through the
surcharge. The MPSC's decision calls for ongoing review by the MPSC of any costs
incurred. The Company will submit a report for review by the MPSC when the water
contaminants remediation plan is approved by the MDEQ. Future costs are not
estimable at this time.
LEGAL PROCEEDINGS
EWR currently is involved in a lawsuit with PPL Montana, LLC (PPLM)
which is pending in the United States District Court for the District of
Montana. The lawsuit was filed on July 2, 2001, and involves a wholesale
electricity supply contract between EWR and PPLM dated March 17, 2000 and a
confirmation letter thereunder dated June 13, 2000 (together, the "Contract").
EWR received substantial imbalance payments as a result of the amount of power
that it scheduled and purchased from PPLM under the Contract. PPLM claims that,
as a result of EWR's scheduling under the Contract, PPLM was deprived of the
fair market value of energy which PPLM contends it could have subsequently sold.
PPLM estimates the fair
6
market value of the excess energy scheduled by EWR to be approximately $18.0
million. EWR denies that it breached the Contract, and contends that, in any
event, PPLM did not sustain any damages. Trial in the case began in December,
2002, and the court is expected shortly to issue a ruling on liability. If the
court rules that EWR breached the Contract, additional trial proceedings would
be required to determine the amount of damages, if any, that PPLM is entitled to
recover from EWR. Any final order of the court will be subject to appeal by the
non-prevailing party. The Company believes that it has established adequate
reserves with respect to the litigation with PPLM; however, there can be no
assurance that any liability will not exceed such reserves. A liability in
excess of the recorded reserves could have a material adverse effect on the
Company and its financial condition.
By letter dated August 30, 2002, the Montana Department of Revenue
(DOR) notified the Company that the DOR's property tax audit of the Company for
the period January 1, 1997 through and including December 31, 2001 had
concluded. The notification stated that the DOR had determined that the Company
had willfully under-reported its personal property and that additional property
taxes and penalties should be assessed. The Company estimates that if the
additional assessment stands, it would owe approximately $3.9 million in
additional property taxes and penalties. The Company believes it has valid
defenses to the assessment of tax and penalties and plans to vigorously contest
the proposed assessment.
In the event that any tax deficiency related to the DOR assessment is
imposed on the Company, the Company will seek to recover the portion of such
deficiency related to regulated property through the rate making process with
the MPSC. No assurance can be given as to whether the Company will recover all
or part of such deficiency, and any related interest charges, through rates. The
Company does not anticipate that any penalty would be recoverable through rates.
Because of the uncertainties related to the DOR notification, the Company has
not been able to determine a range of potential losses; accordingly, no reserve
has been recorded. An adverse outcome in the matter, including the imposition of
penalties or failure of the Company to obtain relief through the rate making
process, could have a material adverse effect on the Company and its financial
condition.
In addition to the legal proceedings discussed above, from time to time
the Company is involved in litigation relating to claims arising from its
operations in the normal course of business none of which the Company believes
is material to the Company's business or financial condition. The Company
utilizes various risk management strategies, including maintaining liability
insurance against certain risks, employee education and safety programs and
other processes intended to reduce liability risk.
7
NOTE 5 -- OPERATIONS BY LINE OF BUSINESS
Three Months Ended Six Months Ended
December 31 December 31
---------------------------------- -----------------------------------
2002 2001 2002 2001
Gross Margin (Operating
Revenue Less Gas and Power
Purchased):
Natural Gas Operations $3,014,314 $2,822,674 $4,453,791 $4,298,819
Propane Operations 1,321,504 1,137,848 1,756,442 1,587,239
Energy Marketing &
Wholesale 612,871 755,045 1,017,975 1,529,928
Pipeline Operations 69,534 153,278
---------------------------------- -----------------------------------
$5,018,223 $4,715,567 $7,381,486 $7,415,986
---------------------------------- -----------------------------------
Operating Income (Loss):
Natural Gas Operations $830,834 $779,109 $126,863 $421,705
Propane Operations 419,293 223,485 (8,227) (142,138)
Energy Marketing &
Wholesale (791,800) 355,233 (1,022,795) 709,071
Pipeline Operations 12,866 (459) 63,617 (1,257)
---------------------------------- -----------------------------------
$471,193 $1,357,368 ($840,542) $987,381
---------------------------------- -----------------------------------
Net Income (Loss):
Natural Gas Operations $386,738 $342,899 ($231,192) ($6,098)
Propane Operations 230,317 89,503 (43,708) (179,139)
Energy Marketing &
Wholesale (504,176) 191,575 (663,471) 376,768
Pipeline Operations 7,932 (1,433) 38,607 (2,333)
---------------------------------- -----------------------------------
$120,811 $622,544 ($899,764) $189,198
---------------------------------- -----------------------------------
NOTE 6 -- NEW ACCOUNTING PRONOUNCEMENTS
In June 2001, the Financial Accounting Standards Board (FASB) issued
SFAS 141, Business Combinations, and SFAS 142, Goodwill and Other Intangible
Assets. SFAS 141 establishes accounting and reporting standards for business
combinations. SFAS 141 is effective for business combinations initiated after
June 30, 2001. SFAS 142 establishes accounting and reporting standards for
goodwill and intangible assets, requiring impairment testing for goodwill and
intangible assets, and the elimination of periodic amortization of goodwill and
certain other intangibles. The Company adopted the provisions of SFAS 142 on
July 1, 2002. Management has determined that there is no current impact of SFAS
141 or 142 on the financial statements of the Company.
In June 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations, which requires asset retirement obligations to be recognized when
they are incurred and recorded as liabilities. The Company adopted this
statement effective July 1, 2002, and has recorded an estimated asset retirement
obligation on its Condensed Consolidated Balance Sheet in "Other long-term
liabilities", and in "Property, plant and equipment". The asset retirement
obligation of $363,750 represents the Company's estimated future liability as of
December 31, 2002, to plug and abandon existing oil and gas wells owned by EWR.
EWR will depreciate the asset amount and increase the liability over the
estimated useful life of these assets. EWR purchased these wells in the fourth
quarter of fiscal year 2002, and the cumulative affect of adopting this
statement was not material. In the future, the Company may have other asset
retirement obligations arising from its business operations. The majority of
the Company's assets consist of transmission and distribution assets and have
indeterminate useful lives, therefore, potential liabilities cannot be
estimated at this time.
8
In August 2001, the FASB issued SFAS 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS 144 addresses accounting and reporting
for the impairment or disposal of long-lived assets, including the disposal of a
segment of business. The Company adopted SFAS 144 on July 1, 2002. Management
has determined there is no current impact of SFAS 144 on the consolidated
financial statements of the Company.
In April 2002, the FASB issued SFAS 145, Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement eliminates the required classification of gain or
loss on extinguishment of debt as an extraordinary item of income and states
that such gain or loss be evaluated for extraordinary classification under the
criteria of Accounting Principles Board No. 30 "Reporting Results of
Operations." This statement also requires sale-leaseback accounting for certain
lease modifications that have economic effects that are similar to
sale-leaseback transactions, and makes various other technical corrections to
existing pronouncements. The Company adopted SFAS 145 on July 1, 2002, and has
determined there is no current impact of SFAS 145 on the consolidated financial
statements of the Company.
In June 2002, the FASB issued SFAS 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement nullifies Emerging Issues Task
Force (EITF) Issue No. 94-3, Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring). This statement requires that a liability for
a cost associated with an exit or disposal activity be recognized when the
liability is incurred rather than the date of an entities commitment to an exit
plan. The provisions of SFAS 146 are effective for exit or disposal activities
that are initiated after December 31, 2002. Management has not determined the
impact, if any, that SFAS 146 will have on consolidated financial statements of
the Company.
ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
The foregoing Management's Discussion and Analysis and other portions
of this report on Form 10-Q contain various "forward looking statements" within
the meaning of Section 27A of the Securities Act of 1933, as amended, and
Sections 21E of the Securities Exchange Act of 1934, as amended, which represent
the Company's expectations or beliefs concerning future events. Forward-looking
statements such as "anticipates," "believes," "expects," "planned," "scheduled"
or similar expressions and statements regarding operating capital requirements
and similar statements that are not historical are forward looking statements
that involve risks and uncertainties. Although the Company believes these
forward-looking statements are based on reasonable assumptions, statements made
regarding future results are subject to a number of assumptions, uncertainties
and risks that could cause future results to be materially different from the
results stated or implied in this document.
Such forward-looking statements, as well as other oral and written
forward-looking statements made by or on behalf of the Company from time to
time, including statements contained in the Company's filings with the
Securities and Exchange Commission and its reports to shareholders, involve
known and unknown risks and other factors which may cause the Company's actual
results in future periods to differ materially from those expressed in any
forward-looking statements. Factors that could cause or contribute to such
differences include, but are not limited to: (i) fluctuations in energy
commodity prices, including prices for fuel and purchased power, (ii) the impact
of state and federal laws and regulations, (iii) the possibility that regulators
may not permit the Company to pass through all such increased costs to
customers, (iv) fluctuations in wholesale margins due to uncertainty in the
wholesale propane and power markets, (v) costs and expenses of, and
uncertainties relating to, pending litigation and other disputes, particularly
the litigation with PPLM and the property tax dispute with the DOR, and (vi)
other factors discussed herein, including items under the heading "Risk
Factors."
9
Any such forward looking statement is qualified by reference to these
risk factors. The Company cautions that these risks and factors are not
exclusive. The Company does not undertake to update any forward-looking
statement that may be made from time to time by or on behalf of the Company
except as required by law.
GENERAL BUSINESS DESCRIPTION
The following discussion reflects results of operations of the Company
and its consolidated subsidiaries for the periods indicated.
On July 1, 2002, certain oil and gas gathering system and natural gas
transmission pipeline assets were transferred from EWR to EWD. The results of
operations for these assets are reported under the Pipeline Operations Segment.
The Company's natural gas operations involve the distribution of
regulated natural gas to the public in the Great Falls and West Yellowstone,
Montana and the Cody, Wyoming areas. Also included in the natural gas operations
for reporting purposes is Cascade Gas, a small regulated propane operation. The
results of Cascade Gas had formerly been reported as part of the propane
segment.
The Company's propane operations include the distribution of regulated
propane to the public through an underground propane vapor system in Payson,
Arizona as well as unregulated retail and wholesale propane operations, operated
by its wholly owned subsidiary Energy West Propane, Inc. (EWP). EWP currently
markets propane in Wyoming, Montana, Arizona, Colorado, South Dakota, North
Dakota and Nebraska.
EWR conducts marketing and distribution activities involving the sale
of natural gas and electricity mainly in Montana and Wyoming. EWR also owns
certain producing natural gas reserves in northcentral Montana.
CASH FLOW ANALYSIS
For the six months ended December 31, 2002, the Company, and its
subsidiaries, used $2,995,000 of cash in its operating activities compared to
$6,979,000 for the six months ended December 31, 2001. This decrease in cash
used of $3,984,000 was primarily due to reductions in natural gas and propane
inventory balance of $6,094,000, a change in the Company's market receivable and
liability balances of $871,000, an increase in deferred tax liability related to
recovery of gas costs of $1,218,000, an increase in accounts payable balance of
$1,786,000 and a decrease in other miscellaneous cash paid out of $651,000.
Offsetting these amounts was a reduction in net income of $1,089,000 a
reduction in recoverable gas collections of $4,957,000, and a reduction in
collections on account receivable of $590,000.
Cash used in investing activities was $2,396,000 for the six months
ended December 31, 2002, compared to $2,511,000 for the six months ended
December 31, 2001. This decrease of $115,000 was due to a reduction in
construction expenditures of $243,000 offset by a reduction in long term and
other miscellaneous receivable balances of $128,000.
Cash provided by financing activities was $6,393,000 for the six months
ended December 31, 2002, compared to $9,831,000 for the six months ended
December 31, 2001. This decrease of $3,438,000 was due primarily to a reduction
in short-term borrowing requirements as a result of less cash used in
operations.
Capital expenditures of the Company are primarily for expansion and
improvement of its gas utility properties. To a lesser extent, funds are also
expended to meet the equipment needs of the Company and its operating
subsidiaries and to meet the Company's administrative needs. The Company's
capital expenditures are expected to be approximately $3,300,000 in fiscal year
2003. These capital expenditures are expected to be generally for routine system
expansion and operating needs. The Company continues to evaluate opportunities
to expand its existing business and continues to evaluate new business
opportunities, which could result in additional capital expenditures.
10
LIQUIDITY AND CAPITAL RESOURCES
Special Factors Affecting Cash Flow
The Company's liquidity is subject to certain factors affecting
utilities and suppliers of energy, including government regulation and the
seasonal effects of weather. These factors can significantly affect the
Company's cash flow.
The Company's utility operations are subject to regulation by the
Montana Public Service Commission (MPSC), the Wyoming Public Service Commission
(WYPSC), and the Arizona Corporation Commission (ACC). This regulation plays a
significant role in determining the Company's return on its regulated
operations. The various commissions approve rates that provide an opportunity to
earn a specified rate of return on investment. The Company's tariffs allow the
cost of gas to be passed through to customers. The pass-through may cause some
delay, however, between the time that the gas cost are incurred by the Company
and the time that the Company recovers such costs from customers, which can
adversely, or positively, affect the Company's cash flow in the event of
increases in gas costs.
The business of the Company and its subsidiaries in all reporting
segments is temperature-sensitive. In any given period, sales volumes reflect
the impact of weather, in addition to other factors, with colder temperatures
generally resulting in increased sales by the Company. The Company anticipates
that this sensitivity to seasonal and other weather conditions will continue to
have significant effects on the Company's sales volumes in future periods.
The Company's operating capital needs, as well as dividend payments and
capital expenditures are generally funded through cash flow from operating
activities and short-term borrowing. To the extent cash flow has not been
sufficient to fund capital expenditures, the Company generally borrows
short-term funds. The Company's short-term borrowing requirements vary according
to the seasonal nature of its sales and expenses. The Company has greater need
for short-term borrowing during periods when internally generated funds are not
sufficient to cover all capital and operating requirements, including costs of
gas purchases and capital expenditures. In general, the Company's short-term
borrowing needs for purchases of gas inventory and capital expenditures are
greatest during the summer months and the Company's short-term borrowing needs
for financing of customer accounts receivable are greatest during the winter
months.
At December 31, 2002, the Company had $26,000,000 in bank lines of
credit, of which $10,642,000 had been borrowed, and the Company had open letters
of credit totaling $4,450,000 related to electric and gas purchase contracts.
Based on the amount of borrowings and outstanding letters of credit, at December
31, 2002, the Company had total remaining borrowing capacity of $10,908,000
under its bank lines of credit.
In addition to its bank lines of credit, the Company has outstanding
certain notes and industrial development revenue obligations. The total amount
of such obligations was $15,788,000 and $16,246,000 as of December 31, 2002 and
December 31, 2001, respectively. Under the terms of the long term debt
obligations, the Company is subject to certain restrictions, including
restrictions on total dividends and distributions, senior indebtedness, and
asset sales, and the Company is required to maintain certain financial debt and
interest ratios.
An adverse outcome in the litigation with PPL Montana, LLC (PPLM) or in
the tax dispute with the Montana Department of Revenue DOR could have a material
adverse effect on the Company's consolidated financial statements. See "Part II,
Item 1 -- Legal Proceedings."
RISK FACTORS
The major factors which affect the Company's future results include
general and regional economic conditions, weather, customer retention and
growth, the ability to meet competitive pressures and to contain costs, the
adequacy and timeliness of rate relief, cost recovery and necessary regulatory
approvals, and continued access to capital markets. In addition, changes in the
competitive environment, particularly related to the Company's propane and
energy marketing segments, could have a significant impact on the performance of
the Company.
11
The regulatory structure is in transition. Legislative and regulatory
initiatives, at both the federal and state levels, are designed to promote
competition. Changes in regulation of the gas industry have allowed certain
customers to negotiate their own gas purchases directly with producers or
brokers. To date, the regulatory changes affecting the gas industry have not had
a negative impact on earnings or cash flow of the Company's natural gas
operations.
The Company's regulated natural gas and propane vapor operations
follow SFAS 71 "Accounting for the Effects of Certain Types of Regulation," and
its financial statements reflect the effects of the different rate making
principles followed by the various jurisdictions regulating the Company. The
economic effects of regulation can result in regulated companies recording costs
that have been or are expected to be allowed in the ratemaking process in a
period different from the period in which the costs would be charged to expense
by an unregulated enterprise. When this occurs, costs are deferred as assets in
the balance sheet (regulatory assets) and recorded as expenses in the periods
when those same amounts are reflected in rates. Additionally, regulators can
impose liabilities upon a regulated company for amounts previously collected
from customers and for amounts that are expected to be refunded to customers
(regulatory liabilities). If the Company's natural gas and propane vapor
operations were to discontinue the application of SFAS 71, the accounting impact
would be an extraordinary, non-cash charge to operations that could be material
to the financial position and results of operation of the Company. However, the
Company is unaware of any circumstances or events in the foreseeable future that
would cause it to discontinue the application of SFAS 71.
In addition to the factors discussed above, the following are important
factors that could cause actual results to differ materially from any results
projected, forecasted, estimated or budgeted:
o Fluctuating energy commodity prices, including prices for fuel and
purchased power;
o The possibility that regulators may not permit the Company to pass
through all such increased costs to customers;
o Fluctuations in wholesale margins due to uncertainty in the wholesale
propane and power markets;
o Changes in general economic conditions in the United States and
changes in the industries in which the Company conducts business;
o Changes in federal or state laws and regulations to which the Company
is subject, including tax, environmental and employment laws and
regulations;
o The impact of FERC and state public service commission statutes and
regulations, including allowed rates of return, the pace of
deregulation in retail natural gas and electricity markets, and the
resolution of other regulatory matters;
o The ability of the Company and its subsidiaries to obtain governmental
and regulatory approval of various expansion or other projects;
o The costs and effects (including the possibility of adverse outcomes)
of legal and administrative claims and proceedings against the Company
or its subsidiaries, particularly the litigation with PPLM and the
property tax dispute with the DOR;
o Conditions of the capital markets the Company utilizes to access
capital to finance operations;
o The ability to raise capital in a cost-effective way;
o The effect of changes in accounting policies, if any;
o The ability to manage growth of the Company;
o The ability to control costs;
o The ability of each business unit to successfully implement key
systems, such as service delivery systems;
o The ability of the Company and its subsidiaries to develop expanded
markets and product offerings as well as their ability to maintain
existing markets;
o The ability of customers of the energy marketing and trading business
to obtain financing for various projects;
o The ability of customers of the energy marketing and trading business
to obtain governmental and regulatory approval of various projects;
o Future utilization of pipeline capacity, which can depend on energy
prices, competition from alternative fuels, the general level of
natural gas and propane demand, decisions by customers not to renew
expiring natural gas, electricity or propane contracts, and weather
conditions; and
o Global and domestic economic repercussions from terrorist activities
and the government's response thereto.
12
ENERGY WEST INCORPORATED AND SUBSIDIARIES
DECEMBER 31, 2002
QUARTERLY RESULTS OF CONSOLIDATED OPERATIONS
The Company's net income for the second quarter ended December 31, 2002
was $121,000 compared to $623,000 for the second quarter ended December 31,
2001. The decrease in earnings of $502,000 was due to an increase in general and
administration expenses primarily caused by an increase in legal expenses
related to the PPLM litigation.
Gross margin, which is defined as operating revenue less gas purchased,
increased $302,000, from $4,716,000 in the second quarter of fiscal 2002 to
$5,018,000 in the second quarter of fiscal 2003. The majority of this increase
was due to increased margins from the Company's natural gas operations of
$191,000 due to colder temperatures, increased margins of $184,000 from the
Company's propane segment resulting from increased volumes related to the
wholesale and retail propane operations, and an increase in margins from the
recently purchased production properties of $118,000, and an increase in
margins from the pipeline operations of $70,000. Offsetting these increases
in margins was a reduction in margins from the Company's marketing and wholesale
activities of $261,000 due to lower sales of wholesale natural gas and
electricity.
Distribution, general and administrative expenses increased by
$1,154,000 in the second quarter of fiscal 2003 compared to the second quarter
of fiscal 2002 primarily due to increased legal expenses related to the PPLM
litigation (See "Part II, Item 1 -- Legal Proceedings"), operating expenses
associated with the recently developed pipeline operations and the timing of
certain expenses in the natural gas operations.
Depreciation expense increased by $37,000 during the second quarter of
fiscal 2003 compared to the second quarter of fiscal 2002 due to the addition of
various pipeline facilities, depletion of the recently purchased production
properties, and other new capital projects completed during the year.
Interest expense decreased by $98,000 during the second quarter of
fiscal year 2003 compared to the second quarter of fiscal year 2002 due to
reduced corporate borrowings.
SIX MONTHS RESULTS OF CONSOLIDATED OPERATIONS
The Company's net loss for the six months ended December 31, 2002 was
approximately $900,000 compared to net income of $189,000 for the six months
ended December 31, 2001, a decrease of $1,089,000. This decrease in net income
was primarily due to an increase in distribution, general and administration
expenses.
Distribution, general and administrative expenses increased from
$4,781,000 for the six months ended December 31, 2001, to $6,380,000 for the
period ended December 31, 2002. This increase of $1,599,000 is due to increased
legal expenses related to the PPLM litigation, increased expenses related to
recently acquired production properties, increased liability insurance expense
due to higher premiums, and an increase in personnel costs and related employee
benefits expense. Of these factors, the costs of the PPLM litigation were
approximately $1,075,000 in the first six months of fiscal 2003 compared with
approximately $145,000 during the first six months of fiscal 2002, an increase
of $930,000.
Maintenance expense increased from $212,000 for the first six months of
fiscal year 2002, to $293,000 for the first six months of fiscal year 2003. This
increase of $81,000 is due primarily to increased expenses of maintaining the
natural gas facilities in both Montana and Wyoming.
Depreciation expense increased by $81,000 during the first six months
of fiscal 2003 compared to the first six months of fiscal year 2002 due to the
addition of various pipeline facilities, the depletion of EWR's production
properties, and other new capital projects completed during the year.
13
Interest expenses were lower by $87,000 during the first six months of
fiscal year 2003, reducing from $880,000 in fiscal 2002 to $793,000 for the same
period in fiscal year 2003. This reduction was due primarily to reduced
borrowings during the six month period.
Income tax expense reduced from $80,000 for the six month period ending
December 31, 2001, to an income tax benefit of $571,000 for the six month period
ending December 31, 2002. This reduction in income tax expense of $651,000 is
due to the Company's reduced pre-tax income for the six month period ended
December 31, 2002.
RESULTS OF THE COMPANY'S NATURAL GAS OPERATIONS
Three Months Ended Six Months Ended
December 31 December 31
------------------------------------- ------------------------------------
2002 2001 2002 2001
Natural Gas Revenue $9,559,804 $12,182,489 $12,615,179 $17,021,177
Natural Gas Purchased 6,545,490 9,359,815 8,161,388 12,722,358
------------------ ------------------ ------------------- ----------------
Gross Margin 3,014,314 2,822,674 4,453,791 4,298,819
Operating Expenses 2,183,480 2,043,565 4,326,928 3,877,114
------------------ ------------------ ------------------- ----------------
Operating Income 830,834 779,109 126,863 421,705
Other Income 18,404 47,788 47,065 94,561
Interest Expense 250,695 339,735 513,169 569,870
Income Tax Expense (Benefit) 211,805 144,263 (108,049) (47,506)
------------------ ------------------ ------------------- ----------------
Net Natural Gas Income (Loss) $386,738 $342,899 ($231,192) ($6,098)
------------------ ------------------ ------------------- ----------------
QUARTERLY RESULTS FOR NATURAL GAS OPERATIONS
The Natural Gas Operations segment's net income for the second quarter
ended December 31, 2002 was $387,000 compared to net income of $343,000 for the
period ended December 31, 2001. This increase in net income of $44,000 was
primarily due to increased margins resulting from colder temperatures then the
previous year, a general rate increase in the Montana operations and a reduction
in interest expense. These increases were partially offset by an increase in
operating expenses, a reduction in other income and an increase in income tax
expense.
Operating Revenues
The Natural Gas Operations segment's revenues for the second quarter of
fiscal 2003 were $9,560,000 compared to $12,182,000 for the second quarter of
fiscal 2002, a decrease of $2,622,000. The decrease was due primarily to the
elimination of the surcharge approved by the MPSC in March of 2001 for the
recovery of increased gas costs that had been incurred prior to that period. The
increased gas costs was fully recovered by June 2002, thus the elimination of
the surcharge.
Gross Margin
The Natural Gas Operations segment's gross margin increased from
$2,823,000 for the second quarter ended December 31, 2001, to $3,014,000 for the
second quarter ended December 31, 2002. This increase of $191,000 was due to
colder temperatures affecting our Montana and Wyoming locations and a general
rate increase, approved by the MPSC, in the Montana operations.
Operating Expenses
The Natural Gas Operations segment's operating expenses were $2,183,000
for the second quarter of fiscal 2003 compared to $2,044,000 for the
corresponding period in fiscal 2002. The increase in operating expenses of
$139,000 is due primarily to an increase in number of personnel, increased
property taxes, an increase in
14
general liability insurance expense as a result of increased premiums, increases
in employee benefit costs and increased expenses associated with maintaining the
natural gas facilities in Montana and Wyoming.
Interest Expense
Interest charges allocable to the Company's Natural Gas Operations
segment were $251,000 for the second quarter of fiscal 2003, compared to
$340,000 in the comparable period in fiscal 2002. This decrease of $89,000 is
due mainly to a reduction in overall corporate borrowings.
Income Taxes
Income tax expense increased from $144,000 for the second quarter of
fiscal 2002 to $212,000 for the second quarter of fiscal 2003. The increase in
income tax expense is due to higher taxable income experienced during the second
quarter.
SIX MONTHS RESULTS FOR NATURAL GAS OPERATIONS
Operating Revenues
The Natural Gas Operations segment's revenues for the six months ended
December 31, 2002 was $12,615,000 compared to $17,021,000 for the period ending
December 31, 2001. The decrease of $4,406,000 was due primarily to the
elimination of the surcharge approved by the MPSC in March of 2001 for the
recovery of increased gas costs that had been incurred prior to the approval
date in March of 2001. The increased gas costs was fully recovered by June 2002,
and the surcharge was eliminated.
Gross Margin
The Natural Gas Operations segment's gross margin increased from
$4,299,000 for the six month period ended December 31, 2001, to $4,454,000 for
the six month period ended December 31, 2002. This increase of $155,000 was due
to colder temperatures affecting our Montana and Wyoming locations.
Operating Expenses
The Natural Gas Operations segment's operating expenses were $4,327,000
for the six months ended December 31, 2002, compared with $3,877,000 for the
period ending December 31, 2001. The increase in operating expenses of
$450,000 was due primarily to an increase in number of personnel, increased
overtime related to company maintenance projects and computer system upgrades,
increased property taxes, an increase in general liability insurance expense due
to increased premiums, increases in employee benefit costs and increased
expenses associated with maintaining the natural gas facilities in Montana and
Wyoming.
Interest Expense
Interest expense decreased from $570,000 in the first six months of
fiscal year 2002, to $513,000 for the first six months of fiscal year 2003. This
decrease of $57,000 is due primarily to reduced corporate borrowings.
Income Taxes
Income tax benefits have increased from $48,000 for the six months
ended December 31, 2001, to $108,000 for the six months ended December 31, 2002.
The increase in income tax benefits is due to the reduction in pre-tax income
for the Natural Gas Operations segment for the six month period.
15
RESULTS OF THE COMPANY'S PROPANE OPERATIONS
Three Months Ended Six Months Ended
December 31 December 31
------------------------------------ ----------------------------------
2002 2001 2002 2001
Propane Revenue $4,001,494 $2,729,164 $5,331,644 $3,835,400
Propane Purchased 2,679,990 1,591,316 3,575,202 2,248,161
-------------- -------------- ------------- ------------
Gross Margin 1,321,504 1,137,848 1,756,442 1,587,239
Operating Expenses 902,211 914,363 1,764,669 1,729,377
-------------- -------------- -------------- -------------
Operating Income (Loss) 419,293 223,485 (8,227) (142,138)
Other Income 60,647 36,383 108,436 69,147
Interest Expense 96,220 123,759 193,177 215,771
Income Tax Expense (Benefit) 153,403 46,606 (49,260) (109,623)
-------------- -------------- -------------- -------------
Net Propane Income (Loss) $230,317 $89,503 ($43,708) ($179,139)
-------------- -------------- -------------- -------------
QUARTERLY RESULTS FOR PROPANE OPERATIONS
Operating Revenues and Gross Margin
The Propane Operations segment's revenues for the second quarter of
fiscal 2003 were $4,001,000 compared to $2,729,000 for the second quarter of
fiscal 2002, an increase of $1,272,000. The increase was due mainly to increased
sales prices in the Company's regulated utility operations in Arizona and
increased sales volumes in the Rocky Mountain Fuel wholesale operations. Gross
margins increased by approximately $184,000 due to the increase in sales volumes
related to both the regulated utility and the wholesale operations.
Operating Expenses
The Propane Operations segment's operating expenses were $902,000 for
the second quarter of fiscal 2003 as compared to $914,000 during the same period
in fiscal 2002. The $12,000 decrease in the period was due primarily to a
reduction in corporate overhead expense allocations.
Interest Expense
Interest charges allocable to the Company's Propane Operations segment
were $96,000 for the second quarter of fiscal 2003, compared to $124,000 in the
comparable period in fiscal 2002. This decrease of $28,000 is due mainly to a
reduction in overall corporate borrowings.
Income Taxes
Income taxes increased from $47,000 in the second quarter of fiscal
2002 to $153,000 for the second quarter of fiscal 2003. The increase in income
tax expense is due to higher taxable income experienced during the second
quarter.
16
SIX MONTHS RESULTS FOR PROPANE OPERATIONS
Operating Revenues and Gross Margin
Propane revenues for the first six months of fiscal 2003 were
approximately $5,332,000 compared to approximately $3,835,000 for the first six
months of fiscal 2002, an increase of $1,497,000. This increase is due to
increased sales prices and volumes in the Arizona regulated operations and an
increase in sales volumes in the Rocky Mountain Fuel wholesale operations. Gross
margin for the first six months of fiscal year 2003 increased by $169,000
primarily due to increased pricing and volumes related to both the regulated
utility and wholesale operations.
Operating Expenses
Operating expenses for the first six months of fiscal 2003 were
$1,765,000 compared to $1,729,000 for the first six months of fiscal 2002. This
increase of $36,000 is due primarily to increased general and administration
expenses partially offset by a reduction in general corporate overhead
allocations.
Interest Expense
Interest expense has decreased from $216,000 in the first six months of
fiscal year 2002, to $193,000 for the first six months of fiscal year 2003. This
decrease of $23,000 is due primarily to reduced corporate borrowings.
Income Taxes
State and federal income tax benefits were approximately $110,000 for
the first six months of fiscal 2002 as compared to approximately $49,000 for the
first six months of fiscal 2003 due to lower pre tax loss from the Propane
Operations segment.
RESULTS OF THE ENERGY MARKETING AND WHOLESALE OPERATIONS
Three Months Ended Six Months Ended
December 31 December 31
------------------------------------- ------------------------------------
2002 2001 2002 2001
Marketing Revenue $11,307,459 $11,547,103 $19,361,370 $22,410,649
Purchases 10,694,588 10,792,058 18,343,395 20,880,721
------------------ ------------------ ------------------- ----------------
Gross Margin 612,871 755,045 1,017,975 1,529,928
Operating Expenses 1,404,671 399,812 2,040,770 820,857
------------------ ------------------ ------------------- ----------------
Operating Income (Loss) (791,800) 355,233 (1,022,795) 709,071
Other Income (Expense) 4,050 (5,702) 5,570 (1,438)
Interest Expense 57,614 38,972 84,509 92,325
Income Tax Expense (Benefit) (341,188) 118,984 (438,263) 238,540
------------------ ------------------ ------------------- ----------------
Net Marketing Income (Loss) ($504,176) $191,575 ($663,471) $376,768
------------------ ------------------ ------------------- ----------------
17
QUARTERLY RESULTS FOR ENERGY MARKETING AND WHOLESALE OPERATIONS
Gross Margin
EWR's energy marketing and wholesale operations experienced a reduction
in gross margin of $142,000 during the second quarter of fiscal 2003 compared to
the same period in fiscal 2002. This decrease was due primarily to reductions in
both electricity and natural gas margins resulting from lower sales volumes
which was partially offset by an increase in margins from natural gas production
properties.
Operating Expenses
Operating expenses for EWR's energy marketing and wholesale operations
were $1,405,000 for the second quarter of fiscal 2003 as compared to $400,000
for the same period in fiscal 2002. The increase in operating expenses of
$1,005,000 was due primarily to increased legal costs as a result of the PPLM
litigation, and operating expenses associated with newly acquired natural gas
production properties.
Interest Expense
Interest charges for the second quarter of fiscal 2003 increased by
$18,000 from $39,000 in the second quarter of fiscal 2002 to $57,000 in the
second quarter of fiscal 2003. This increase was due to allocation of a greater
portion of Company debt to EWR due to an increase in EWR's total asset base.
Income Taxes
State and federal income tax expense of EWR's energy marketing and
wholesale operations decreased from $119,000 for the second quarter of fiscal
2002 to an income tax benefit of $341,000 in the second quarter of fiscal 2003,
due to a reduction in pre-tax income from the energy marketing and wholesale
operations.
SIX MONTHS RESULTS FOR ENERGY MARKETING AND WHOLESALE OPERATIONS
Gross Margin
EWR's energy marketing and wholesale operations gross margin decreased
from $1,530,000 for the six months ended December 31, 2001 to $1,018,000 for the
six months ended December 31, 2002. This decrease of $512,000, was due to
decreased gross margins from the sale of natural gas and electricity of
approximately $792,000 partially offset by increased margins from the natural
gas production properties of $280,000.
Operating Expenses
Operating expenses for the energy marketing and wholesale operations
were approximately $2,041,000 for the six months ended December 31, 2002
compared to approximately $821,000 for the period ending December 31, 2001. The
increase of approximately $1,220,000 is due primarily to increased legal costs
related to the PPLM litigation and increased operating expenses related to the
natural gas production properties. The costs of the PPLM litigation were
approximately $1,075,000 during the first six months of fiscal 2003, compared to
approximately $145,000 during the first six months of fiscal 2002.
Interest Expense
Interest expense decreased from approximately $92,000 for the six month
period ended December 31, 2001 to approximately $85,000 for the six months ended
December 31, 2002. This decrease of $7,000 is due to reduced corporate
borrowings.
18
Income Taxes
Income tax expense decreased from $239,000 for the six months ended
December 31, 2001 to an income tax benefit of $438,000 for the six months ended
December 31, 2002 due to the reduction in pre tax income from the energy
marketing and wholesale operations.
RESULTS OF THE COMPANY'S PIPELINE OPERATIONS
Three Months Ended Six Months Ended
December 31 December 31
------------------------------------ ---------------------------------------
2002 2001 2002 2001
Transmission Revenue $69,534 $153,278
Purchases
----------------- ------------------ ------------------- -------------------
Gross Margin 69,534 153,278
Operating Expenses 56,668 459 89,661 1,257
----------------- ------------------ ------------------- -------------------
Operating Income (Loss) 12,866 (459) 63,617 (1,257)
Other Income (Expense) 949 (942) 949 (238)
Interest Expense 895 873 1,669 2,207
Income Tax Expense (Benefit) 4,988 (841) 24,290 (1,369)
----------------- ------------------ ------------------- -------------------
Net Transmission Income (Loss) $7,932 ($1,433) $38,607 ($2,333)
----------------- ------------------ ------------------- -------------------
Pipeline Operations is a new segment for financial reporting purposes.
The results of this segment reflect operation of oil and gas gathering systems
placed into service in fiscal 2002, and transferred from EWR to EWD. For fiscal
year 2002 and prior years EWD consisted primarily of real estate holdings and
incurred minimum expenses. For fiscal year 2003 the revenues reported in the
Pipeline Operations segment consist of gathering revenues related to the
pipeline operations in the Wyoming and Montana areas. Beginning with fiscal
2003, the financial operations of EWD's pipeline assets and real estate holdings
are in the Pipeline Operations segment for financial reporting purposes. The
Company anticipates that EWD will begin operations of a refurbished transmission
pipeline upon receipt of approval from FERC.
CONTRACTS ACCOUNTED FOR AT FAIR VALUE
Management of Risks Related to Derivatives--The Company and its
subsidiaries are subject to certain risks related to changes in certain
commodity prices and risks of counter-party performance. The Company has
established certain policies and procedures to manage such risks. The Company
has a Risk Management Committee (RMC), comprised of Company officers to oversee
the Company's risk management program as defined in its risk management policy.
The purpose of the risk management program is to minimize adverse impacts on
earnings resulting from volatility of energy prices, counter-party credit risks,
and other risks related to the energy commodity business. The RMC is overseen by
the Audit Committee of the Company's Board of Directors.
General--From time to time the Company or its subsidiaries may use
derivative financial contracts to mitigate the risk of commodity price
volatility related to firm commitments to purchase and sell natural gas or
electricity. The Company may use such arrangements to protect its profit margin
on future obligations to deliver quantities of a commodity at a fixed price.
Conversely, such arrangements may be used to hedge against future market price
declines where the Company or a subsidiary enters into an obligation to purchase
a commodity at a fixed price in the future. The Company accounts for such
financial instruments in accordance with SFAS 133, Accounting for Derivative
Instruments and Hedging Activities, as amended by SFAS 138, Accounting for
Certain Derivative Instruments and Certain Hedging Activities.
In accordance with SFAS 133, contracts that do not qualify as normal
purchase and sale contracts must be reflected in the Company's financial
statements at fair value, determined as of the date of the balance sheet. This
accounting treatment is also referred to as "mark-to-market" accounting.
Mark-to-market accounting treatment can result in a disparity between reported
earnings and realized cash flow, because changes in the value of the financial
19
instrument are reported as income or loss even though no cash payment may have
been made between the parties to the contract. If such contracts are held to
maturity, the cash flow from the contracts, and their hedges, are realized over
the life of the contract.
Quoted market prices for natural gas derivative contracts of the
Company or its subsidiaries generally are not available. Therefore, to determine
the fair value of natural gas derivative contracts, the Company uses internally
developed valuation models that incorporate available current and historical
independent pricing information.
During the third quarter of fiscal 2002, EWR terminated its existing
derivative contracts with Enron Canada Corporation (ECC), a subsidiary of Enron
Corp. Most of these contracts were commodity swaps that EWR had entered into to
mitigate the effects of fluctuations in the market price of natural gas. The
derivative contracts with ECC were entered into at various times in order to
lock in margins on certain contracts under which EWR had commitments to other
parties to sell natural gas at fixed prices (the "Future Supply Agreements").
EWR made the decision to terminate these ECC contracts because of concerns
relating to the bankruptcy of Enron Corp. At the date of termination, the market
price of natural gas was substantially lower than the price had been when EWR
entered into the contracts, resulting in a net amount due from EWR to ECC of
approximately $5,400,000. EWR paid this amount to ECC upon the termination of
the contracts, and thereby discharged the liability related to the contracts.
The costs related to such termination were reflected in the Company's
consolidated statement of income as adjustments to gas purchased for the fiscal
year ended June 30, 2002.
At the time the Company terminated the ECC derivative contracts, the
Company entered into new gas purchase contracts (the "Future Purchase
Agreements") at prices much lower than those provided for under the ECC
contracts. The Future Purchase agreements and the Future Supply Agreements
continue to be valued on a mark-to market basis. As of December 31, 2002, these
Agreements were reflected on the Company's consolidated balance sheet as
derivative assets and liabilities at an approximate fair value as follows:
Assets Liabilities
---------- -----------
Contracts maturing during fiscal 2003: $ 447,068 $ 103,836
Contracts maturing during fiscal 2004 and 2005: 1,445,714 126,565
Contracts maturing during 2006 and 2007: 615,789 84,002
Contracts maturing from fiscal 2008 and beyond: 181,393 97,670
---------- ----------
Total $2,689,964 $ 412,073
During the first six months of fiscal 2003, the Company did not enter into
any new contracts that would be accounted for using mark-to-market accounting
under SFAS 133.
Natural Gas Operations--In the case of the Company's regulated divisions,
gains or losses resulting from the derivative contracts are subject to deferral
under regulatory procedures approved by the public service regulatory
commissions of Montana, Wyoming and Arizona. Therefore, related derivative
assets and liabilities are offset with corresponding regulatory liability and
asset amounts included in "Recoverable Cost of Gas Purchases", pursuant to SFAS
71, Accounting for the Effects of Certain Types of Regulation.
RELATED PARTY TRANSACTIONS
The Company has no material related party transactions.
CRITICAL ACCOUNTING POLICIES
The Company believes its critical accounting policies are as follows:
Effects of Regulation--The Company follows SFAS 71, "Accounting for the
Effects of Certain Types of Regulation", and its financial statements reflect
the effects of the different rate making principles followed by the various
jurisdictions regulating the Company. The economic effects of regulation can
result in regulated companies recording costs that have been or are expected to
be allowed in the ratemaking process in a period different from
20
the period in which the costs would be charged to expense by an unregulated
enterprise. When this occurs, costs are deferred as assets in the balance sheet
(regulatory assets) and recorded as expenses in the periods when those same
amounts are reflected in rates. Additionally, regulators can impose liabilities
upon a regulated company for amounts previously collected from customers and for
amounts that are expected to be refunded to customers (regulatory liabilities).
Recoverable/ Refundable Costs of Gas and Propane Purchases--The Company
accounts for purchased-gas costs in accordance with procedures authorized by the
MPSC, the WPSC and the ACC under which purchased gas and propane costs that are
different from those provided for in present rates are accumulated and recovered
or credited through future rate changes.
Derivatives--The Company accounts for certain derivative contracts that
are used to manage risk in accordance with SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities", as amended by SFAS 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities", which the
Company adopted July 1, 2000.
ITEM 3 -- THE QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is subject to certain market risks, including commodity
price risk (i.e., natural gas and propane prices) and interest rate risk. The
adverse effects of potential changes in these market risks are discussed below.
The sensitivity analyses presented do not consider the effects that such adverse
changes may have on overall economic activity nor do they consider additional
actions management may take to mitigate the Company's exposure to such changes.
Actual results may differ. See the notes to the financial statements for a
description of the Company's accounting policies and other information related
to these financial instruments.
Commodity Price Risk
The Company protects itself against price fluctuations on natural gas
and electricity by limiting the aggregate level of net open positions, which are
exposed to market price changes and through the use of natural gas derivative
instruments. The net open position is actively managed with strict policies
designed to limit the exposure to market risk, and which require at least weekly
reporting to management of potential financial exposure. The risk management
committee has limited the types of financial instruments the company may trade
to those related to natural gas commodities. The Company's results of operations
are significantly impacted by changes in the price of natural gas. During 2002
and 2001, natural gas accounted for 64% and 75% respectively, of the Company's
operating expenses. In order to provide short-term protection against a sharp
increase in natural gas prices, the Company from time to time enters into
natural gas call and put options, swap contracts and purchase commitments. The
Company's gas hedging strategy could result in the Company not fully benefiting
from certain gas price declines.
Interest Rate Risk
The Company's results of operations are affected by fluctuations in
interest rates (e.g. interest expense on debt). The Company mitigates this risk
by entering into long-term debt agreements with fixed interest rates. The
Company's notes payable, however, are subject to variable interest rates. A
hypothetical 10 percent change in market rates applied to the balance of the
notes payable would not have a material effect on the Company's earnings.
Credit Risk
Credit risk relates to the risk of loss that the Company would incur as
a result of non-performance by counterparties of their contractual obligations
under the various instruments with the Company. Credit risk may be concentrated
to the extent that one or more groups of counterparties have similar economic,
industry or other characteristics that would cause their ability to meet
contractual obligations to be similarly affected by changes in market or other
conditions. In addition, credit risk includes not only the risk that a
counterparty may default due to circumstances relating directly to it, but also
the risk that a counterparty may default due to circumstances which relate to
other market participants which have a direct or indirect relationship with such
counterparty. The Company seeks to mitigate credit risk by evaluating the
financial strength of potential counterparties. However, despite mitigation
efforts, defaults by counterparties may occur from time to time. To date, no
such default has occurred.
21
ITEM 4. CONTROLS AND PROCEDURES
The Company's President and Chief Executive Officer, Edward J. Bernica
and the Company's Assistant Vice President and Controller (principal financial
officer) Robert B. Mease have evaluated the Company's internal controls and
disclosure controls systems within 90 days of the filing of this report. Based
on this evaluation, they have concluded that the Company's disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) are
effective as of the date of this Quarterly Report on Form 10-Q to provide
reasonable assurance that the Company can meet its disclosure obligations. As of
the date of this Quarterly Report on Form 10-Q there have not been any
significant changes in internal controls or in other factors that could
significantly affect these controls subsequent to the date of their evaluation,
including any corrective actions with regard to significant deficiencies and
material weaknesses.
22
Form 10-Q
Part II - Other Information
Item 1 LEGAL PROCEEDINGS
EWR currently is involved in a lawsuit with PPL Montana, LLC (PPLM)
which is pending in the United States District Court for the District of
Montana. The lawsuit was filed on July 2, 2001, and involves a wholesale
electricity supply contract between EWR and PPLM dated March 17, 2000 and a
confirmation letter thereunder dated June 13, 2000 (together, the "Contract").
EWR received substantial imbalance payments as a result of the amount of power
that it scheduled and purchased from PPLM under the Contract. PPLM claims that,
as a result of EWR's scheduling under the Contract, PPLM was deprived of the
fair market value of energy which PPLM contends it could have subsequently sold.
PPLM estimates the fair market value of the excess energy scheduled by EWR to be
approximately $18.0 million. EWR denies that it breached the Contract, and
contends that, in any event, PPLM did not sustain any damages. Trial in the case
began in December, 2002, and the court is expected shortly to issue a ruling on
liability. If the court rules that EWR breached the Contract, additional trial
proceedings would be required to determine the amount of damages, if any, that
PPLM is entitled to recover from EWR. Any final order of the court will be
subject to appeal by the non-prevailing party. The Company believes that it has
established adequate reserves with respect to the litigation with PPLM; however,
there can be no assurance that any liability will not exceed such reserves. A
liability in excess of the recorded reserves could have a material adverse
effect on the Company and its financial condition.
By letter dated August 30, 2002, the Montana Department of Revenue
(DOR) notified the Company that the DOR's property tax audit of the Company for
the period January 1, 1997 through and including December 31, 2001 had
concluded. The notification stated that the DOR had determined that the Company
had willfully under-reported its personal property and that additional property
taxes and penalties should be assessed. The Company estimates that if the
additional assessment stands, it would owe approximately $3.9 million in
additional property taxes and penalties. The Company believes it has valid
defenses to the assessment of tax and penalties, and plans to vigorously contest
the proposed assessment.
In the event that any tax deficiency related to the DOR assessment is
imposed on the Company, the Company will seek to recover the portion of such
deficiency related to regulated property through the rate making process with
the Montana Public Service Commission. No assurance can be given as to whether
the Company will recover all or part of such deficiency, and any related
interest charges, through rates. The Company does not anticipate that any
penalty would be recoverable through rates. Because of the uncertainties related
to the DOR notification, the Company has not been able to determine a range of
potential losses; accordingly, no reserve has been recorded. An adverse outcome
in the matter, including the imposition of penalties or failure of the Company
to obtain relief through the rate making process, could have a material adverse
effect on the Company and its financial condition.
In addition to the legal proceedings discussed above, from time to time
the Company is involved in litigation relating to claims arising from its
operations in the normal course of business none of which the Company believes
is material to the Company's business or financial condition. The Company
utilizes various risk management strategies, including maintaining liability
insurance against certain risks, employee education and safety programs and
other processes intended to reduce liability risk.
23
Item 2. Changes in Securities - Not Applicable
Item 3. Defaults upon Senior Securities - Not Applicable
Item 4. Submission of Matters to a Vote of Security Holders
The Company held it's annual shareholder meeting on November 21, 2002.
Those items that were voted on by the shareholders consisted of the election of
corporate directors and the approval of the Energy West Incorporated 2002 Stock
Option Plan.
Those individuals elected to the Company Board of Directors, for a one
year term, and their respective number of votes cast for and withheld are as
follows:
Votes Cast For Votes Withheld
-------------- --------------
Mr. E.W. (Gene) Argo 2,307,038 196,346
Mr. Edward J. Bernica 2,309,038 196,420
Mr. Andrew Davidson 2,278,577 238,734
Mr. David A. Flitner 2,306,538 196,846
Mr. G. Montgomery Mitchell 2,309,038 194,436
Mr. Terry M. Palmer 2,111,894 609,173
Mr. George D. Ruff 2,308,938 194,446
Mr. Richard J. Schulte 2,306,938 196,346
Also approved at the annual meeting was the Energy West Incorporated
2002 Stock Option Plan. The number of votes cast for approval of the plan was
1,062,540 while the number of votes against was 633,840.
Item 5. Other Information - Not Applicable
Item 6. Exhibits and Reports on Form 8-K
A. Exhibits for the quarter ended December 31, 2002.
99.1 Certification of Principal Executive Officer
99.2 Certification of Principal Financial Officer
B. The Company has not filed a Current Report on Form 8-K during the
second quarter ended December 31, 2002.
24
SIGNATURES
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 thereunto duly authorized.
ENERGY WEST INCORPORATED
/s/Edward J. Bernica
- -------------------------------
Edward J. Bernica, President and
Chief Executive Officer
(principal executive officer)
/s/Robert B. Mease
- -------------------------------
Robert B. Mease, Assistant Vice-President
and Controller
(principal financial officer)
Dated February 14, 2003
25
CERTIFICATIONS
I, Edward J. Bernica, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Energy West
Incorporated.
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report.
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: February 14, 2003
/s/ Edward J. Bernica
-------------------------------------
Edward J. Bernica
President and Chief Executive Officer
(principal executive officer)
26
I, Robert B. Mease, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Energy West
Incorporated.
2. Based on my knowledge, this quarterly report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this quarterly report; and
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this quarterly report.
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: February 14, 2003
/s/ Robert B. Mease
---------------------------------------
Robert B. Mease
Assistant Vice President and Controller
(principal financial officer)
27