UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON D.C. 20549
FORM 10-Q
[X] Quarterly Report Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2001
[ ] Transition Report Pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
For the transition period from ____________ to___________.
Commission File No. 0-25551
MIDAMERICAN ENERGY HOLDINGS COMPANY
(Exact name of registrant as specified in its charter)
Iowa 94-2213782
------------------------------ ----------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
666 Grand Avenue, Des Moines, IA 50309
---------------------------------------- ----------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (515) 242-4300
--------------
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 require-
ments for the past 90 days.
Yes X No
------- -------
All of the shares of MidAmerican Energy Holdings Company are held by a
limited group of private investors. As of August 14, 2001, 9,281,087 shares of
common stock were outstanding.
MIDAMERICAN ENERGY HOLDINGS COMPANY
FORM 10-Q
TABLE OF CONTENTS
Part I: Financial Information
Page No.
ITEM 1. Financial Statements
Independent Accountants' Report........................... 1
Consolidated Balance Sheets............................... 2
Consolidated Statements of Operations..................... 3
Consolidated Statements of Cash Flows..................... 4
Notes to Consolidated Financial Statements................ 5
ITEM 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations.......... 14
Part II: Other Information
ITEM 1. Legal Proceedings......................................... 29
ITEM 2. Changes in Securities and Use of Proceeds................. 30
ITEM 3. Defaults on Senior Securities............................. 30
ITEM 4. Submission of Matters to a Vote of Security Holders....... 30
ITEM 5. Other Information......................................... 30
ITEM 6. Exhibits and Reports on Form 8-K.......................... 31
Signatures .......................................................... 32
Exhibit Index .......................................................... 33
INDEPENDENT ACCOUNTANTS' REPORT
Board of Directors and Shareholders
MidAmerican Energy Holdings Company
Des Moines, Iowa
We have reviewed the accompanying consolidated balance sheet of MidAmerican
Energy Holdings Company (successor to MidAmerican Energy Holdings Company
(Predecessor), referred to as "MEHC (Predecessor)") and subsidiaries (the
"Company") as of June 30, 2001, and the related consolidated statements of
operations for the three-month and six-month periods ended June 30, 2001 for the
Company; for the period January 1, 2000 to March 13, 2000 for MEHC
(Predecessor); for the period March 14, 2000 to June 30, 2000 for the Company;
and for the three-month period ended June 30, 2000 for the Company; and the
related consolidated statements of cash flows for the six-month period ended
June 30, 2001 for the Company; for the period January 1, 2000 to March 13, 2000
for MEHC (Predecessor); and for the period March 14, 2000 to June 30, 2000 for
the Company. These financial statements are the responsibility of the Company's
management.
We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures to
financial data and of making inquiries of persons responsible for financial and
accounting matters. It is substantially less in scope than an audit conducted in
accordance with auditing standards generally accepted in the United States of
America, the objective of which is the expression of an opinion regarding the
financial statements taken as a whole. Accordingly, we do not express such an
opinion.
Based on our review, we are not aware of any material modifications that
should be made to such consolidated financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheet of the
Company as of December 31, 2000, and the related consolidated statements of
operations, shareholders' equity, and cash flows for the period January 1, 2000
to March 13, 2000 for MEHC (Predecessor) and for the period March 14, 2000 to
December 31, 2000 for the Company (not presented herein); and in our report
dated January 18, 2001 (March 27, 2001 as to Notes 17 and 19.A.), we expressed
an unqualified opinion on those consolidated financial statements. In our
opinion, the information set forth in the accompanying consolidated balance
sheet as of December 31, 2000 is fairly stated, in all material respects, in
relation to the consolidated balance sheet from which it has been derived.
DELOITTE & TOUCHE LLP
Des Moines, Iowa
August 6, 2001
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands)
As of
------------------------------------
June 30, December 31,
2001 2000
---------------- ----------------
(Unaudited)
Assets
Current Assets:
Cash and cash equivalents............................ $ 41,315 $ 38,152
Restricted cash and short-term investments........... 36,914 42,129
Marketable securities............................... 51,965 5,419
Accounts receivable.................................. 606,560 903,469
Inventory........................................... 60,000 81,943
Other current assets................................. 103,123 91,365
------------ -------------
Total Current Assets............................... 899,877 1,162,477
Property, plant, contracts and equipment, net........... 5,318,836 5,348,647
Excess of cost over fair value of net assets
acquired, net......................................... 3,617,892 3,673,150
Regulatory assets....................................... 223,356 240,934
Long-term restricted cash and investments............... 2,574 48,747
Nuclear decommissioning trust fund and other
marketable securities................................. 161,338 202,227
Equity investments...................................... 259,634 246,466
Deferred charges, other investments and other assets.... 822,202 758,003
------------ -------------
Total Assets............................................ $ 11,305,709 $ 11,680,651
============ =============
Liabilities and Shareholders' Equity
Current Liabilities:
Accounts payable..................................... $ 429,505 $ 656,356
Accrued interest.................................... 130,578 107,726
Accrued taxes....................................... 106,207 125,645
Other accrued liabilities............................ 263,984 250,975
Short-term debt..................................... 102,262 251,656
Current portion of long-term debt.................... 232,448 438,978
------------ -------------
Total Current Liabilities.......................... 1,264,984 1,831,336
Other long-term accrued liabilities..................... 950,835 976,030
Parent company debt..................................... 1,832,221 1,829,971
Subsidiary and project debt............................. 3,527,601 3,398,696
Deferred income taxes................................... 969,296 945,028
------------ -------------
Total Liabilities.................................... 8,544,937 8,981,061
------------ -------------
Deferred income......................................... 84,708 79,489
Minority interest....................................... 13,359 11,491
Company-obligated mandatorily redeemable
preferred securities of subsidiary trusts............ 787,561 786,523
Subsidiary-obligated mandatorily redeemable
preferred securities of subsidiary trusts............ 100,000 100,000
Preferred securities of subsidiary...................... 131,771 145,686
Commitments and contingencies (Note 8)
Shareholders' Equity:
Zero coupon convertible preferred stock -
authorized 50,000 shares, no par value,
34,563 shares issued and outstanding................. - -
Common stock - authorized 60,000 shares, no
par value; 9,281 shares issued and outstanding....... - -
Additional paid in capital.............................. 1,553,073 1,553,073
Retained earnings....................................... 155,401 81,257
Accumulated other comprehensive loss, net............... (65,101) (57,929)
------------ -------------
Total Shareholders' Equity........................... 1,643,373 1,576,401
------------ -------------
Total Liabilities and Shareholders' Equity.............. $ 11,305,709 $ 11,680,651
============ =============
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands)
(Unaudited)
MEHC
(Predecessor)
Three Months Six Months March 14, 2000 January 1,2000
Ended June 30, Ended Through Through
2001 2000 June 30, 2001 June 30, 2000 March 13,2000
----- ---- ------------- ------------- -------------
Revenues:
Operating revenue...................... $1,184,747 $1,123,233 $2,779,952 $1,332,706 $1,049,523
Interest and other income.............. 38,186 29,441 55,871 33,807 13,033
---------- ---------- ----------- ---------- ----------
Total revenues............................ 1,222,933 1,152,674 2,835,823 1,366,513 1,062,556
---------- ---------- ----------- ---------- ----------
Costs and expenses:
Cost of sales.......................... 641,798 612,280 1,671,807 722,294 561,386
Operating expense...................... 284,406 273,087 550,909 324,193 219,303
Depreciation and amortization.......... 121,551 120,129 237,767 142,439 97,278
Interest expense....................... 120,676 124,726 242,354 148,024 101,330
Less interest capitalized.............. (23,646) (27,048) (52,133) (30,694) (15,516)
Loss on non-recurring item............. - - - - 7,605
----------- ----------- ----------- ---------- ----------
Total costs and expenses.................. 1,144,785 1,103,174 2,650,704 1,306,256 971,386
----------- ----------- ----------- ---------- ----------
Income before provision for income taxes.. 78,148 49,500 185,119 60,257 91,170
Provision for income taxes................ 19,870 11,516 54,215 13,817 31,008
----------- ----------- ----------- ---------- ----------
Income before minority interest........... 58,278 37,984 130,904 46,440 60,162
Minority interest......................... 27,445 26,935 52,156 31,955 8,850
----------- ----------- ----------- ---------- ----------
Income before cumulative effect of change
inaccounting principle................ 30,833 11,049 78,748 14,485 51,312
Cumulative effect of change in accounting
principle, net of tax................. - - (4,604) - -
----------- ----------- ------------ ---------- ----------
Net income available to common
shareholders........................... $ 30,833 $ 11,049 $ 74,144 $ 14,485 $ 51,312
=========== =========== =========== ========== ==========
</table>
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
(Unaudited)
MEHC
(Predecessor)
Six March 14, 2000 January 1, 2000
Months Through Through
Ended June 30, March 13,
June 30, 2001 2000 2000
------------- -------------- ---------------
Net income........................................................... $ 74,144 $ 14,485 $ 51,312
Adjustments to reconcile to net cash flows from
operating activities:
Cumulative effect of change in accounting principle, net of tax...... 4,604 - -
Depreciation and amortization........................................ 187,778 112,595 83,097
Amortization of excess of cost over fair value of
net assets acquired............................................... 49,989 29,844 14,181
Amortization of deferred financing costs and other costs............. 10,799 7,656 4,075
Provision for deferred income taxes.................................. 34,885 (4,938) 7,735
Undistributed earnings on equity investments......................... (17,290) (11,218) (3,459)
Changes in other items:
Accounts receivable and other current assets...................... 316,236 82,015 440
Accounts payable, accrued liabilities, deferred income
and other......................................................... (265,793) (151,906) 13,702
----------- ---------- ----------
Net cash flows from operating activities............................. 395,352 78,533 171,083
----------- ---------- ----------
Cash flows from investing activities:
Purchase of MEHC (Predecessor) net of cash acquired................. - (2,048,266) -
Purchase of marketable securities.................................... - (15,326) (8,251)
Proceeds from sale of marketable securities.......................... - 21,800 12,562
Acquisition of realty companies...................................... (29,963) - -
Capital expenditures relating to operating projects.................. (151,553) (94,880) (44,355)
Construction and other development costs............................. (43,299) (73,225) (56,450)
Philippine-construction in progress.................................. (40,197) (15,284) (22,736)
Change in restricted investments..................................... 46,173 32,140 48,788
Change in other assets............................................... 27,680 (18,739) 15,568
----------- ---------- ---------
Net cash flows from investing activities............................. (191,159) (2,211,780) (54,874)
----------- ---------- ---------
Cash flows from financing activities:
Proceeds from issuances of common and preferred stock................ - 1,428,024 -
Proceeds from issuance of trust preferred securities................. - 454,772 -
Net repayment of short- debt......................................... (145,722) (56,387) (118,718)
Repayment of subsidiary and project debt............................. (250,937) (56,574) (3,135)
Repayment of parent company debt..................................... - (4,225) -
Redemption of preferred trust securities of subsidiaries............. - (19,686) -
Proceeds from subsidiary and project debt............................ 206,158 87,421 -
Change in restricted investments-debt service........................ 5,215 30,197 (6,033)
Other................................................................ (15,988) (3,247) (615)
----------- ---------- ---------
Net cash flows from financing activities............................. (201,274) 1,860,295 (128,501)
----------- ---------- ---------
Effect of exchange rate changes on cash.............................. 244 (621) (424)
----------- ---------- ---------
Net increase (decrease) in cash and cash equivalents............... 3,163 (273,573) (12,716)
Cash and cash equivalents at beginning of period................... 38,152 303,611 316,327
----------- ---------- ---------
Cash and cash equivalents at end of period........................... $ 41,315 $ 30,038 $ 303,611
=========== ========== =========
Interest paid, net of amount capitalized............................. $ 167,370 $ 155,437 $ 35,057
=========== ========== =========
Income taxes paid.................................................... $ 52,114 $ 61,495 $ -
=========== ========== =========
The accompanying notes are an integral part of these financial statements.
MIDAMERICAN ENERGY HOLDINGS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General
In the opinion of management of MidAmerican Energy Holdings Company
(successor to MidAmerican Energy Holdings Company (Predecessor), referred to as
"MEHC (Predecessor)") and subsidiaries (collectively referred to as the
"Company"), the accompanying unaudited consolidated financial statements contain
all adjustments (consisting only of normal recurring accruals) necessary to
present fairly the financial position as of June 30, 2001 and the results of
operations for the three and six months ended June 30, 2001 and for the three
months ended June 30, 2000 and for the period March 14, 2000 to June 30, 2000
for the Company and for the period January 1, 2000 to March 13, 2000 for MEHC
(Predecessor) and the related consolidated statements of cash flows for the six
months ended June 30, 2001 and for the period March 14, 2000 to June 30, 2000
for the Company and for the period January 1, 2000 to March 13, 2000 for MEHC
(Predecessor). The results of operations for the three and six months ended June
30, 2001, and for the three months ended June 30, 2000 and the period March 14,
2000 to June 30, 2000 for the Company and for the period January 1, 2000 to
March 13, 2000 for MEHC (Predecessor) are not necessarily indicative of the
results to be expected for the full year.
The consolidated financial statements include the accounts of the Company
and its wholly and majority owned subsidiaries. Other investments and corporate
joint ventures, where the Company has the ability to exercise significant
influence are accounted for under the equity method. Investments where the
Company's ability to influence is limited are accounted for under the cost
method of accounting.
Certain amounts in the 2000 financial statements and supporting note
disclosures have been reclassified to conform to the 2001 presentation. Such
reclassification did not impact previously reported net income or retained
earnings.
Reference is made to the Company's most recently issued annual report on
Form 10-K that included information necessary or useful to the understanding of
the Company's business and financial statement presentations.
2. Property, Plant, Contracts and Equipment
Property, plant, contracts and equipment comprise the following (in thousands):
June 30, December 31,
2001 2000
-------------- --------------
Operating assets:
Utility generation and distribution system......... $ 6,184,998 $ 6,157,482
Independent power plants........................... 931,171 698,069
Power sales agreement.............................. 78,428 82,231
Other assets....................................... 469,867 421,231
------------- -------------
Total operating assets............................. 7,664,464 7,359,013
Less accumulated depreciation and amortization..... (3,456,582) (3,312,019)
------------- -------------
Net operating assets............................... 4,207,882 4,046,994
Mineral and gas reserves and exploration assets,
net............................................ 376,541 373,742
Construction in process:
Casecnan........................................ 428,595 388,398
Zinc recovery project........................... 177,101 166,406
Utility generation and distribution system...... 110,377 141,160
Cordova......................................... - 224,514
Other development............................... 18,340 7,433
------------ ------------
Total.............................................. $ 5,318,836 $ 5,348,647
============ ============
3. Equity Investments
CE Generation, the Company's 50% owned subsidiary, has interests in ten
operating geothermal plants in Imperial Valley, California and three operating
natural gas-fired cogeneration plants in New York, Texas and Arizona. The
following is summarized financial information for CE Generation (in thousands):
Three Months Ended Six Months Ended
June 30, June 30, June 30, June 30,
2001 2000 2001 2000
--------- --------- -------- --------
Revenues $129,405 $112,505 $279,092 $206,975
Income before cumulative
effect of change
in accounting principle 17,372 16,939 37,546 18,905
Net income 17,372 16,939 22,160 18,905
4. Accounting Policy Change
Effective January 1, 2001, the Company has changed its accounting policy
regarding major maintenance and repairs for nonregulated gas projects,
nonregulated plant overhaul costs and geothermal well rework costs to the direct
expense method from the former policy of monthly accruals based on long-term
scheduled maintenance plans for the gas projects and deferral and amortization
of plant overhaul costs and geothermal well rework costs over the estimated
useful lives. The cumulative effect of the change in accounting principle was
$4.6 million, net of taxes of $.7 million.
5. Accounting Pronouncements
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards Nos. 133 and 138 (SFAS 133/138) pertaining to the accounting for
derivative instruments and hedging activities. SFAS 133/138 requires an entity
to recognize all of its derivatives as either assets or liabilities in its
statement of financial position and measure those instruments at fair value. If
the conditions specified in SFAS 133/138 are met, those instruments may be
designated as hedges. Changes in the value of hedge instruments would not impact
earnings, except to the extent that the instrument is not perfectly effective as
a hedge. At January 1, 2001, the Company recognized $55.6 million and $53.3
million of energy-related assets and liabilities, respectively, as being subject
to fair value accounting pursuant to SFAS 133/138, all of which are accounted
for as hedges. Additionally, on January 1, 2001, the Company's portfolio of
preferred stock investments was transferred from the available for sale category
to the trading category, as permitted by SFAS 133. Initial adoption of SFAS
133/138 did not have a material impact on the results of operations for the
Company.
The Financial Accounting Standards Board ("FASB") has approved guidance
that, in general, option contracts and forward contracts with optionality
features cannot qualify for the normal purchases and normal sales exception
under SFAS 133/138 as amended. However, the FASB has also issued guidance that
energy capacity contracts that include certain characteristics of purchased and
written options could qualify as normal purchases and sales as long as certain
criteria are met. The Company has performed a preliminary review of its
contracts with the above characteristics and believes that these contracts are
not subject to the financial reporting requirements of SFAS 133/138. Another
issue, which included tentative guidance as of the filing of the first quarter
2001 Form 10-Q, stated that derivative contracts which do not result in physical
delivery of power because of transmission scheduling, referred to as bookouts,
cannot meet the normal purchases and normal sales exception. This issue was
abandoned by the FASB during the second quarter of 2001.
The FASB's Derivatives Implementation Group continues to identify and
provide guidance on various implementation issues related to SFAS 133/138 that
are in varying stages of review and clearance by the Derivatives Implementation
Group and the FASB. The Company is monitoring the issues being reviewed by the
Derivatives Implementation Group and the FASB to determine what, if any, impact
they may have on the Company's financial statements.
In July 2001, the FASB issued SFAS No. 141, "Business Combinations", and
SFAS No. 142, "Goodwill and Other Intangible Assets" which establish accounting
and reporting for business combinations. SFAS No. 141 requires all business
combinations entered into subsequent to June 30, 2001, to be accounted for using
the purchase method of accounting. SFAS No. 142 provides that goodwill and other
intangible assets with indefinite lives will not be amortized but will be tested
for impairment on an annual basis. These standards are effective for the Company
beginning on January 1, 2002. The Company is evaluating the impact resulting
from the adoption of these standards.
6. Comprehensive Income (Loss)
Comprehensive income (loss) for the three months ended June 30, 2001 and
2000 was $91.1 million and ($33.2) million, respectively. Comprehensive income
for the six months ended June 30, 2001 was $69.4 million, which includes the
transition loss of $3.3 million related to the initial adoption of SFAS 133.
Comprehensive loss for the period March 14, 2000 to June 30, 2000 was ($29.8)
million. Comprehensive income of MEHC (Predecessor) for the period January 1,
2000 to March 13, 2000 was $26.0 million. Comprehensive income differs from net
income due primarily to foreign currency translation adjustments, unrealized
gains and losses from marketable securities, and fair value adjustments of cash
flow hedges.
7. Accounting for Derivatives
MidAmerican Energy
MidAmerican Energy uses a variety of derivative financial instruments to
hedge the effect of price changes on cash flows from expected future physical
transactions (cash flow hedges) and the fair value of physical purchase and sale
commitments (fair value hedges) and to minimize price volatility for regulated
gas purchases. The objective of MidAmerican Energy's hedging program is to
minimize the impact of changing prices for natural gas and electricity on its
cash flows. Instruments used for gas hedging transactions include futures
contracts, swaps and options. Instruments used for electric hedging transactions
include forward contracts and options. Small volumes of derivative financial
instruments are traded from time to time to profit from price arbitrage
opportunities.
Unrealized gains and losses on cash flow hedges of future transactions are
recorded in other comprehensive income. Only hedges that are highly effective in
offsetting the risk of variability in future cash flows are accounted for in
this manner. Future transactions include purchases of gas for resale to
regulated and nonregulated customers, purchases of gas for storage, and
purchases and sales of wholesale electric energy. When the associated hedged
future transaction occurs or if a hedging relationship is no longer appropriate,
the unrealized gains and losses are reversed from other comprehensive income and
recognized in net income. Realized gains on cash flow hedges are recorded in
operating revenues or cost of sales, depending upon the nature of the physical
transaction being hedged.
For the six months ended June 30, 2001, a net gain of $.4 million,
representing the ineffectiveness of cash flow hedges, was reflected in cost of
sales. During the twelve months beginning July 1, 2001, it is anticipated that
all of net unrealized gains (losses) on cash flow hedges presently recorded as
accumulated other comprehensive income will be realized and recorded in
earnings.
Unrealized gains and losses on fair value hedges are recognized in income
as either operating revenues or cost of sales, depending upon the nature of the
item being hedged. Purchase and sales commitments hedged by fair value hedges
are recorded at fair value, with the changes in values also recognized in income
and substantially offsetting the impact of the hedges on earnings. For the six
months ended June 30, 2001, the net income statement impact realized from the
ineffectiveness of fair value hedges was immaterial.
Unrealized gains and losses on derivatives held for trading purposes are
recognized in income each reporting period as operating revenues.
As of June 30, 2001, the following instruments were held as hedges:
Notional Unit of Fair Value
Amount Measure Asset (Liability)
------ ------- -----------------
Natural Gas Futures - Net Short 4,930,000 MMBtu $9,905,000
Natural Gas Swaps 419,000 MMBtu (4,465,000)
Natural Gas Options-Long 950,000 MMBtu (1,676,000)
Natural Gas Options-Short 950,000 MMBtu 1,000
Electricity Forward
Contracts - Net Short 306,000 MWh 588,000
Northern
On March 27, 2001, the New Electricity Trading Arrangements ("NETA") came
into effect and replaced the previous Pooling & Settlement arrangements that had
been in place since 1990. A key feature of NETA is the ability provided to
participants to trade bi-lateral contracts for physical energy delivery under
the new industry governance arrangements set out in the Balancing & Settlement
Code. This is significantly different from the Pooling & Settlement arrangements
that previously existed whereby prices were determined centrally with
participants being required to sell and buy physical energy through the Pool and
use financial instruments in the form of Contracts for Difference ("CfDs") and
Electricity Forward Agreements ("EFAs") to manage risk associated with
volatility of the centrally determined "Pool" price. As a result of NETA, all of
the previous CfD and EFA agreements were replaced with bi-lateral contracts
which fall under the normal purchases and normal sales exception and therefore
are not subject to the financial reporting requirements of SFAS 133/138.
At June 30, 2001, CE Electric UK Funding Company had fixed-rate obligations
denominated in U.S. dollars that exposed CE Electric UK Funding Company to
losses in the event of increases in the exchange rate of U.S. dollars to
Sterling pounds. When this obligation was issued, CE Electric UK Funding Company
entered into certain currency rate swap agreements that effectively convert the
U.S. dollar fixed interest rate to a fixed rate in Sterling pounds. At June 30,
2001, these currency rate swap agreements had an aggregate notional amount of
$362 million, which the Company would receive approximately $47.2 million if
terminated.
8. Commitments and Contingencies
Financial Condition of Edison
Southern California Edison ("Edison"), a wholly-owned subsidiary of Edison
International, is a public utility primarily engaged in the business of
supplying electric energy to retail customers in Central and Southern
California, excluding the city of Los Angeles. The Company is aware that there
have been public announcements that Edison's financial condition has
deteriorated as a result of reduced liquidity. Edison's senior unsecured debt
obligations are currently rated Caa2 by Moody's and D by S&P.
Edison failed to pay approximately $119 million due under the Power
Purchase Agreements of indirect subsidiaries of the Company's 50% owned
subsidiary, CE Generation, for power delivered in November and December 2000 and
January, February and March 2001, although the Power Purchase Agreements provide
for billing and payment on a schedule where payments would have normally been
received in early January, February, March, April and May 2001.
On February 21, 2001, the Imperial Valley Projects (excluding Salton Sea
Unit V and CE Turbo), subsidiaries of CE Generation, filed a lawsuit against
Edison in California's Imperial County Superior Court seeking a court order
requiring Edison to make the required payments under the Power Purchase
Agreements. The lawsuit also requested, among other things, that the court order
permit the Imperial Valley Projects to suspend deliveries of power to Edison and
to permit the Imperial Valley Projects to sell such power to other purchasers in
California.
On March 22, 2001, the Superior Court granted the Imperial Valley Projects'
Motion for Summary Adjudication and a Declaratory Judgment ordering that: 1)
under the Power Purchase Agreements, the Imperial Valley Projects have the right
to temporarily suspend deliveries of capacity and energy to Edison, 2) the
Imperial Valley Projects are entitled to resell the energy and capacity to other
purchasers and 3) the interim suspension of deliveries to Edison shall not in
any respect result in the modifications or termination of the Power Purchase
Agreements and the Power Purchase Agreements shall in all respects continue in
full force and effect other than the temporary suspension of deliveries to
Edison.
As a result of the March 22, 2001 Declaratory Judgment, the Imperial Valley
Projects suspended deliveries of energy to Edison and entered into a transaction
agreement with El Paso Merchant Energy, L.P. ("EPME") in which the Imperial
Valley Projects' available power was sold to EPME based on percentages of the
Dow Jones SP-15 Index. On June 18, 2001 the Superior Court terminated the
Imperial Valley Projects' right to resell power pursuant to the Declaratory
Judgment.
On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V
and CE Turbo) entered into Agreements Addressing Renewable Energy Pricing and
Payment Issues with Edison ("Settlement Agreements"). The Settlement Agreements
require Edison make a series of payments to repay the past due balances under
the Power Purchase Agreements (the "stipulated amounts"). The first payment of
approximately $11.6 million, which represented 10% of the stipulated amounts,
was received June 22, 2001. A second partial payment of 10% is payable within 5
days following the MOU Effective Date. The "MOU Effective Date" means the first
day on which both of the following have occurred: (a) all legislation
implementing the Memorandum of Understanding between Edison and the California
Department of Water Resources dated April 9, 2001 ("MOU") or such other
legislation based on the MOU or otherwise, that restores Edison to
creditworthiness has become effective, and (b) the California Public Utilities
Commission ("Commission") has issued all orders that are necessary to implement
the MOU or other mechanisms contained in such legislation based on the MOU or
otherwise which are designed to restore Edison to creditworthiness. The final
payment, representing the remaining stipulated amounts, shall be paid on the 5th
business day after Edison receives proceeds from the financing resulting from
the MOU or other mechanisms contained in such other legislation based on the MOU
or otherwise restore Edison to creditworthiness. In addition to these payments,
Edison is required to make monthly interest payments calculated at a rate of 7%
per annum on the outstanding stipulated amounts. The Settlement Agreements also
provide a revised energy pricing structure, whereby Edison elects to pay the
Imperial Valley Projects a fixed energy price of 5.37 cents/kilowatt hour in
lieu of the Commission-approved SRAC Methodology under the Power Purchase
Agreements, commencing on the first day of the month following the MOU Effective
Date and expiring five years from such date. All other contract terms remain
unchanged.
As a result of the aforementioned Settlement Agreements, the Imperial
Valley Projects resumed power sales to Edison on June 22, 2001. Energy payments
are currently calculated using the SRAC formulas set forth in the Power Purchase
Agreements until the fixed rate period begins.
As a result of Edison's failure to make the payments due under the Power
Purchase Agreements and the recent downgrades of Edison's credit ratings,
Moody's downgraded the ratings for the Salton Sea Funding Corporation (the
"Funding Corporation") Securities to Caa2 (negative outlook) and S&P downgraded
the ratings for the Funding Corporation Securities to BBB- and placed the
Securities on "credit watch negative". Moody's downgraded the ratings for the CE
Generation Securities to B1 from Baa3 (review for possible downgrade). Following
the execution of the Settlement Agreements, Moody's placed the Salton Sea
Funding and CE Generation securities on "credit watch positive".
The Imperial Valley Projects are contractually entitled to receive payments
under the Power Purchase Agreements and Settlement Agreements. However, due to
the uncertainties associated with Edison's financial condition and failure to
pay contractual obligations, CE Generation has established an allowance for
doubtful accounts of approximately $82 million at June 30, 2001.
Minerals Extraction
The Company owns the rights to proprietary processes for the extraction of
minerals from elements in solution in the geothermal brine and fluids utilized
at its Imperial Valley plants. A pilot plant has successfully produced
commercial quality zinc at the Company's Imperial Valley Projects. The Company
intends to sequentially develop facilities for the extraction of manganese,
silver, gold, lead, boron, lithium and other products as it further develops the
extraction technology.
CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company,
is constructing the Zinc Recovery Project which will recover zinc from the
geothermal brine (the "Zinc Recovery Project"). Facilities are being installed
near the Imperial Valley Project's sites to extract a zinc chloride solution
from the geothermal brine through an ion exchange process. This solution will be
transported to a central processing plant where zinc ingots will be produced
through solvent extraction, electrowinning and casting processes. The Zinc
Recovery Project is designed to have a capacity of approximately 30,000 metric
tons per year and is scheduled to commence commercial operations in late 2002.
In September 1999, CalEnergy Minerals LLC entered into a sales agreement whereby
all zinc produced by the Zinc Recovery Project will be sold to Cominco, Ltd. The
initial term of the agreement expires in December 2005.
The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc.
("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering,
procure, construct and manage contract (the "Zinc Recovery Project EPC
Contract"). On June 14, 2001, CalEnergy Minerals, LLC issued notices of default,
termination and demand for payment of damages to Kvaerner under the Zinc
Recovery Project EPC Contract due to failure to meet performance obligations. As
a result of Kvaerner's failure to pay monetary obligations under the Zinc
Recovery Project EPC Contract, CalEnergy Minerals, LLC drew $29.7 million under
the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals, LLC has
entered into a time and materials reimbursable engineer, procure and
construction management contract with AMEC E&C Services, Inc. to complete the
Zinc Recovery Project.
Casecnan
CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE
Casecnan") which at completion of the Casecnan Project is expected to be at
least 70% indirectly owned by the Company, is constructing the Casecnan Project,
a combined irrigation and 150 net MW hydroelectric power generation project (the
"Casecnan Project") located in the central part of the island of Luzon in the
Republic of the Philippines.
CE Casecnan has entered into a fixed-price, date certain, turnkey
engineering, procurement and construction contract to complete the construction
of the Casecnan Project (the "Casecnan Construction Contract"). The work under
the Casecnan Construction Contract is being conducted by a consortium consisting
of Cooperative Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C.
Spa working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and
Colenco Power Engineering Ltd. (collectively, the "Contractor").
On November 20, 1999, the Casecnan Construction Contract was amended to
extend the Guaranteed Substantial Completion Date for the Casecnan Project to
March 31, 2001. This amendment was approved by the lender's independent engineer
under the Casecnan Indenture. In January 2001, CE Casecnan received a new
working schedule from the Contractor that showed a completion date of August 31,
2001. Furthermore, in July 2001, CE Casecnan received new schedule information
from the Contractor which extends the expected Substantial Completion Date for
the Casecnan Project from August 31, 2001 to October 6, 2001.
The receipt of the working schedule does not change the Guaranteed
Substantial Completion Date under the Replacement Contract, and the Contractor
is still contractually obligated either to complete the Casecnan Project by
March 31, 2001 or to pay delay liquidated damages. As a result of receipt of the
working schedule, however, CE Casecnan has sought and obtained from the lender's
independent engineer approval for a revised construction schedule under the
Casecnan Indenture. In connection with the revised schedule, the Company agreed
to make available up to $11.6 million of additional funds under certain
conditions pursuant to a Shareholder Support Letter dated February 8, 2001 (the
"Shareholder Support Letter") to cover additional costs resulting from the
Contractor's schedule delay. As agreed in the Shareholder Support Letter and
assuming payments are received under the bank guaranty supporting the
Contractor's obligation to pay delay liquidated damages prior to October 6,
2001, CE Casecnan believes that the funds available to it are reasonably
expected to be sufficient to fund the costs of reaching completion of the
Casecnan Project. However, due to the delay in completion of the project, CE
Casecnan does not presently expect that it will receive significant operating
revenues from the Casecnan Project prior to November 15, 2001. As a result, CE
Casecnan presently expects that it will have insufficient funds available to it
for purposes of making the principal and interest payments which will become due
on November 15, 2001 on the debt securities issued by CE Casecnan in November
1995 (the "Debt Securities"), unless the Company agrees to fund the expected
shortfall amount which is currently estimated to be approximately $24.6 million.
CE Casecnan has been advised that the willingness of the Company to fund
such November 15, 2001 shortfall will principally depend upon the progress of
the pending arbitration proceedings involving the Contractor, including any
orders issued in the future by the arbitration panel; completion of the Casecnan
Project in substantial compliance with the revised construction schedule; and
performance by the National Irrigation Administration ("NIA") of its obligations
under the Project Agreement. Subject to these same assumptions, CE Casecnan does
not presently expect that any additional funding will be required to be provided
to it by the Company in order for CE Casecnan to make future principal and
interest payments on the Debt Securities following the November 15, 2001
payments.
CE Casecnan's ability to make payments on any of its existing and future
obligations is dependent on NIA's and the Republic of the Philippines' ("RP")
performance of their obligations under the Project Agreement and the Performance
Undertaking, respectively. Except to the extent expressly provided for in the
Shareholder Support Letter, no shareholders, partners or affiliates of CE
Casecnan, including the Company, and no directors, officers or employees of the
Company will guarantee or be in any way liable for payment of CE Casecnan's
obligations. As a result, payment of CE Casecnan's obligations depends upon the
availability of sufficient revenues from CE Casecnan's business after the
payment of operating expenses.
Cordova
Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company, completed construction of a 537 MW gas-fired power
plant in the Quad Cities, Illinois area (the "Cordova Project"). The Cordova
Project became operational June 19, 2001.
MidAmerican
On July 10, 2001, MidAmerican Energy announced plans to develop and
construct two electric generating plants in Iowa, requiring an investment of
approximately $1.5 billion. Participation by others in a portion of the second
plant is being discussed. The two plants will provide approximately 1,400
megawatts of generating capacity. MidAmerican Energy expects to begin
construction in Spring 2002 on the first project, a 540-megawatt natural
gas-fired combined cycle unit which has an estimated cost of $340 million. It is
anticipated that the first phase of the project will be completed in 2003 with
the remainder being completed in 2005. MidAmerican Energy presently expects that
all utility construction expenditures for the next five years will be met with
the issuance of long-term debt and cash generated from utility operations, net
of dividends. The actual level of cash generated from utility operations is
affected by, among other things, economic conditions in the utility service
territory, weather and federal and state regulatory actions.
9. Segment Information
The Company has identified five reportable business segments principally
based on management structure: CalEnergy Generation-Domestic, CalEnergy
Generation-Foreign (primarily the Philippines), MidAmerican (domestic utility
operations), Northern (foreign utility operations), and HomeServices (real
estate operations). Information related to the Company's reportable operating
segments is shown below (in thousands).
MEHC (Predecessor)
Three Months Six Months March 14, 2000 January 1, 2000
Ended June 30, Ended Through Through
2001 2000 June 30, 2001 June 30, 2000 March 13, 2000
---- ---- ------------- ------------- ---------------
Revenue:
CalEnergy Generation - Domestic $ 18,411 $ 9,955 $ 26,586 $ 9,944 $ 4,520
CalEnergy Generation - Foreign. 52,038 48,632 104,750 58,692 42,726
MidAmerican.................... 614,108 481,477 1,511,185 564,696 447,583
Northern....................... 355,785 477,174 912,602 577,058 499,017
HomeServices................... 180,864 139,175 280,905 160,194 66,880
----------- ---------- ---------- ---------- ------------
Segment revenue................ 1,221,206 1,156,413 2,836,028 1,370,584 1,060,726
Corporate...................... 1,727 (3,739) (205) (4,071) 1,830
---------- ----------- ---------- ---------- ------------
$1,222,933 $1,152,674 $2,835,823 $1,366,513 $ 1,062,556
========== ========== ========== ========== ============
Income before provision for income
taxes:
CalEnergy Generation - Domestic $ 10,015 $ 7,229 $ 14,389 $ 6,854 $ 2,877
CalEnergy Generation - Foreign. 22,714 16,107 45,573 20,293 15,976
MidAmerican.................... 46,717 34,384 123,895 42,612 63,315
Northern....................... 24,581 28,580 96,763 38,193 58,673
HomeServices................... 15,881 12,496 12,612 13,003 (4,929)
---------- --------- ---------- ---------- ------------
Segment operating income....... 119,908 98,796 293,232 120,955 135,912
Corporate...................... (41,760) (49,296) (108,113) (60,698) (44,742)
---------- --------- ---------- ---------- ------------
$ 78,148 $ 49,500 $ 185,119 $ 60,257 $ 91,170
========== ========== ========== ========== ============
June 30, December 31,
2001 2000
------------- -------------
Identifiable assets:
CalEnergy Generation - Domestic.... $ 1,019,827 $ 968,444
CalEnergy Generation - Foreign..... 1,127,271 1,188,445
MidAmerican........................ 5,085,046 5,392,273
Northern........................... 2,829,231 2,929,665
HomeServices....................... 221,701 163,101
----------- -----------
Segment identifiable assets........ 10,283,076 10,641,928
Corporate.......................... 1,022,633 1,038,723
----------- ------------
$11,305,709 $11,680,651
=========== ===========
The remaining differences from the segment amounts to the consolidated
amounts described as "Corporate" relate principally to the corporate functions
including administrative costs, corporate cash and related interest income,
unallocated goodwill and related goodwill amortization, intersegment
eliminations and fair value adjustments relating to acquisitions.
10. Subsequent Event
On August 6, 2001, the Company and Innogy, plc reached an agreement to
exchange Northern's electricity and gas supply and metering business for
Innogy's Yorkshire Electricity distribution business. The transaction is
expected to close in approximately two to three months. The acquisition of
Yorkshire's distribution business by Northern Electric plc will create a company
serving more than 3.6 million customers in the United Kingdom throughout an area
of approximately 10,000 square miles.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
The following is management's discussion and analysis of certain
significant factors that have affected the Company's financial condition and
results of operations during the periods included in the accompanying statements
of operations.
Teton Transaction
On March 14, 2000, the Company and entities representing an investor group
comprised of Berkshire Hathaway Inc., Walter Scott, Jr., a director of the
Company, David L. Sokol, Chairman and Chief Executive Officer of the Company,
and Gregory E. Abel, Chief Operating Officer of the Company closed on a
definitive agreement and plan of merger whereby the investor group acquired all
of the outstanding common stock of the Company (the "Teton Transaction"). As a
result of the Teton Transaction, Berkshire Hathaway, Mr. Scott, Mr. Sokol and
Mr. Abel own approximately 9.7%, 86%, 3% and 1% of the voting stock
respectively.
Business of MEHC
MidAmerican Energy Holdings Company (the "Company" or "MEHC"), is a United
States-based privately owned global energy company with publicly traded fixed
income securities that generates, distributes and supplies energy to utilities,
government entities, retail customers and other customers located throughout the
world. Through its subsidiaries the Company is organized and managed on four
separate platforms: MidAmerican, Northern, CalEnergy Generation and
HomeServices.
MidAmerican
MidAmerican Energy Company ("MidAmerican Energy") is a regulated public
utility principally engaged in the business of generating, transmitting,
distributing and selling electric energy and in distributing, selling and
transporting natural gas. MidAmerican Energy distributes electricity at the
retail level in Iowa, Illinois and South Dakota. It also distributes natural gas
at the retail level in Iowa, Illinois, South Dakota and Nebraska. As of June 30,
2001, MidAmerican Energy had approximately 669,000 retail electric customers and
646,000 retail natural gas customers.
In addition to retail sales, MidAmerican Energy delivers electric energy to
other utilities, marketers and municipalities who distribute it to end-use
customers. These sales are referred to as sales for resale or off-system sales.
It also transports natural gas through its distribution system for a number of
end-use customers who have independently secured their supply of natural gas.
Most of MidAmerican Energy's business is conducted in a rate-regulated
environment and accordingly, many of its decisions as to the source and use of
resources and other strategic matters are evaluated from a utility business
perspective. MidAmerican Energy's operations are seasonal in nature with a
disproportionate percentage of revenues and earnings historically being earned
in the Company's first and third quarters.
Northern
The operations of Northern Electric plc ("Northern"), an indirect wholly
owned subsidiary of the Company, consist primarily of the distribution and
supply of electricity, supply of natural gas and other auxiliary businesses in
the United Kingdom. Northern's operations are seasonal in nature with a
disproportionate percentage of revenues and earnings historically being earned
in the Company's first and fourth quarters.
Northern receives electricity from the national grid transmission system
and distributes it to customers' premises using its network of transformers,
switchgear and cables. Substantially all of the customers in Northern's
authorized area are connected to Northern's network and can only be delivered
electricity through Northern's distribution system, regardless of whether it is
supplied by Northern's own supply business or by other suppliers, thus providing
Northern with distribution volume that is stable from year to year. Northern
charges access fees for the use of the distribution system. The prices for
distribution are controlled by a prescribed formula that limits increases (and
may require decreases) based upon the rate of inflation in the United Kingdom
and other regulatory action.
Northern's supply business primarily involves the bulk purchase of
electricity, previously through a central pool and from March 27, 2001 on
through the New Electricity Trading Agreements ("NETA"), and subsequent resale
to individual customers throughout the U.K. The supply business generally is a
high volume business that tends to operate at lower profitability levels than
the distribution business. As of June 30, 2001, Northern supplied electricity to
approximately 1.1 million customers.
Northern also competes to supply gas inside and outside its authorized
area. As of June 30, 2001, Northern supplied gas to approximately 467,000
customers.
On August 6, 2001, the Company and Innogy, plc reached an agreement to
exchange Northern's electricity and gas supply and metering business for
Innogy's Yorkshire Electricity distribution business. The transaction is
expected to close in approximately two to three months. The acquisition of
Yorkshire's distribution business by Northern Electric plc will create a company
serving more than 3.6 million customers in the United Kingdom throughout an area
of approximately 10,000 square miles.
CalEnergy Generation
The Company indirectly owns the Upper Mahiao, Malitbog and Mahanagdong
Projects (collectively, the "Philippine Projects"), which are geothermal power
plants located on the island of Leyte in the Philippines. For purposes of
consistent presentation, capacity amounts for Upper Mahiao, Malitbog and
Mahanagdong are 119, 216 and 165 net MW, respectively. Each plant possesses an
operating margin that allows for production in excess of the amount listed
above. Utilization of this operating margin is based upon a variety of factors
and can be expected to vary between calendar quarters, under normal operating
conditions.
On June 19, 2001, Cordova Energy Company LLC ("Cordova Energy"), an
indirect wholly owned subsidiary of the Company, commenced operation of a 537 MW
gas-fired power plant in the Quad Cities, Illinois area (the "Cordova Project").
Cordova Energy has entered into a power purchase agreement with a unit of El
Paso Energy Corporation ("El Paso") in which El Paso will purchase all of the
capacity and energy from the project until December 31, 2019. Cordova Energy has
exercised an option under the El Paso Power Purchase Agreement to callback 50%
of the project output for sales to others for the contract years ending on or
prior to May 14, 2004. Cordova Energy subsequently entered into a power purchase
agreement with MidAmerican Energy whereby MidAmerican Energy will purchase 50%
of the capacity and energy from the Cordova Project until May 14, 2004.
The Company has a 50% ownership interest in CE Generation LLC ("CE
Generation") which has interests in ten geothermal plants in the Imperial
Valley, California and three natural gas-fired cogeneration plants. For purposes
of consistent presentation, plant capacity factors for Vulcan, Hoch (Del Ranch),
Turbo, Elmore and Leathers (collectively the "Partnership Projects") are based
on capacity amounts of 34, 38, 10, 38, and 38 net MW, respectively, and for
Salton Sea I, Salton Sea II, Salton Sea III, Salton Sea IV and Salton Sea V
plants (collectively the "Salton Sea Projects") are based on capacity amounts of
10, 20, 50, 40 and 49 net MW, respectively (the Partnership Projects and the
Salton Sea Projects are collectively referred to as the "Imperial Valley
Projects"). Plant capacity factors for Saranac, Power Resources and Yuma
(collectively the "Gas Plants") are based on capacity amounts of 240, 200, and
50 net MW, respectively. Each plant possesses an operating margin that allows
for production in excess of the amount listed above. Utilization of this
operating margin is based upon a variety of factors and can be expected to vary
between calendar quarters, under normal operating conditions.
Due to its 50% ownership interest in CE Generation, the Company accounts
for CE Generation as an equity investment.
HomeServices
The Company owns approximately 83% of HomeServices.Com, Inc.
("HomeServices"), the second largest residential real estate brokerage firm in
the United States based on aggregate closed transaction sides in 2000 for its
various brokerage firm operating subsidiaries. Closed transaction sides mean
either the buy side or sell side of any closed home purchase and is the standard
term used by industry participants and publications to rank real estate
brokerage firms. In addition to providing traditional residential real estate
brokerage services, HomeServices cross sells to its existing real estate
customers preclosing services, such as mortgage origination and title services,
including title insurance, title search, escrow and other closing administrative
services, assists in securing other preclosing and postclosing services provided
by third parties, such as home warranty, home inspection, home security,
property and casualty insurance, home maintenance, repair and remodeling and is
developing various related e-commerce services. HomeServices currently operates
in the following twelve states: Minnesota, Iowa, Arizona, Kansas, Missouri,
Kentucky, Nebraska, Wisconsin, Indiana, Maryland, North Dakota and South Dakota.
HomeServices occupies the number one or number two market share position in each
of its major markets based on aggregate closed transaction sides for the year
ended December 31, 2000. HomeServices' major markets consist of the following
metropolitan areas: Minneapolis and St. Paul, Minnesota; Des Moines, Iowa;
Omaha, Nebraska; Kansas City, Kansas; Louisville, Kentucky; Springfield,
Missouri; Tucson, Arizona and Annapolis, Maryland.
Results of Operations for the Quarters Ended June 30, 2001 and 2000:
Operating revenue increased in the second quarter of 2001 to $1,184.7
million from $1,123.2 million for the same period in 2000, a 5.5% increase.
MidAmerican operating revenue increased in the second quarter of 2001 to $600.4
million from $470.1 million for the same period in 2000, primarily due to
increases in volumes and prices of non-regulated gas. Northern's operating
revenue decreased in the second quarter of 2001 to $350.1 million from $470.2
million for the same period in 2000, primarily due to lower volumes and rates of
electricity supplied inside and outside its authorized area partially offset by
higher volumes and rates of external access charges. Operating revenue of
HomeServices increased in the second quarter of 2001 to $180.1 million from
$137.8 million for the same period in 2000, primarily due to acquisitions and
the inclusion of a joint venture which was previously accounted for as an equity
investment.
The following data represents sales from MidAmerican Energy:
Three Months
Ended June 30,
----------------------
2001 2000
---- ----
Electric Retail Sales (GWh)..................... 4,008 3,940
Electric Sales for Resale (GWh)................. 1,890 1,362
Regulated and Non-regulated Gas Supplied
(Thousands of MMBtus)........................ 53,103 31,706
MidAmerican Energy retail electric sales increased in the second quarter
2001 from the second quarter 2000 due to warmer temperatures and non-weather
related sales increases. MidAmerican Energy electric sales for resale increased
in the second quarter as higher production at the Cooper and Neal power plants
increased available sales volumes. MidAmerican Energy regulated and
non-regulated gas supplied increased in the second quarter due to growth in the
non-regulated markets.
The following data represents the supply and distribution operations in the
U.K.:
Three Months
Ended June 30,
------------------------
2001 2000
---- ----
Electricity Supplied (GWh)...................... 4,054 4,691
Electricity Distributed (GWh)................... 4,051 3,790
Gas Supplied (Thousands of MMBtus).............. 8,060 8,721
The decrease in electricity supplied for the three months ended June 30,
2001 from the same periods in 2000 is due to the decrease in supply volumes both
inside and outside the authorized area. The increase in electricity distributed
for the three months ended June 30, 2001 from the same period in 2000 is due to
changes in demand in the authorized area. The decrease in gas supplied in 2001
from 2000 reflects lower volume in the U.K. industrial and commercial markets.
Interest and other income increased in the second quarter of 2001 to $38.2
million from $29.4 million for the same period in 2000, a 29.7% increase. The
increase is primarily due to gains on the sales of Western States Geothermal, an
indirect wholly owned subsidiary of the Company and other investments, partially
offset by lower income from cost and equity investments.
Cost of sales increased in the second quarter of 2001 to $641.8 million
from $612.3 million for the same period in 2000, a 4.8% increase. The increase
is primarily due to higher volumes of non-regulated gas supplied at MidAmerican
and increased cost at HomeServices due to acquisitions and the inclusion of a
joint venture which was previously accounted for as an equity investment,
partially offset by lower costs at Northern due to a decrease in the exchange
rate and lower electricity purchase costs, partially offset by higher gas costs.
Operating expenses increased to $284.4 million in the three months ended
June 30, 2001 from $273.1 million in the same period in 2000. MidAmerican's
operating expenses increased to $165.4 million in 2001 from $157.6 million in
the same period in 2000 primarily due to higher bad debt, pension and Cooper
costs. Northern's operating expenses decreased $15.6 million due primarily to
lower foreign exchange rate and lower bad debt and pension costs. HomeServices'
operating expenses increased $11.9 million due primarily to acquisitions and the
inclusion of a joint venture which was previously accounted for as an equity
investment.
Depreciation and amortization increased $1.5 million to $121.6 million in
the three months ended June 30, 2001 from $120.1 million in the same period in
2000. The increase is primarily due to higher goodwill and purchase accounting
amortization relating to the Teton and HomeServices' acquisitions.
Interest expense, less amounts capitalized, decreased marginally in the
second quarter of 2001 to $97.0 million from $97.7 million for the same period
in 2000. The decreases are due to the lower average outstanding debt balances
and increased capitalized interest at Casecnan, Cordova and Zinc Recovery
Project, partially offset by decreased capitalized interest on the mineral
extraction process.
The provision for income taxes increased in the second quarter of 2001 to
$19.9 million from $11.5 million for the same period in 2000. The increase is
due primarily to higher pretax income.
Minority interest increased marginally in the second quarter of 2001 to
$27.4 million from $26.9 million for the same period in 2000. The increase is
primarily due to the increase in minority interest at HomeServices.
Net income increased in the second quarter of 2001 to $30.8 million from
$11.0 million for the same period in 2000.
Results of Operations for the Six Months Ended June 30, 2001 and the
Periods March 14, 2000 through June 30, 2000, and January 1, 2000 through March
13, 2000:
The following is a discussion of the historical results of the Company for
the six months ended June 30, 2001 and the period March 14, 2000 through June
30, 2000, and of its predecessor (referred to as "MEHC (Predecessor)") for the
period January 1, 2000, through March 13, 2000. Results for the Company include
the results of MEHC (Predecessor) beginning March 14, 2000, in conjunction with
the Teton Transaction. The impact of the transaction is reflected in the
Company's results of operations, predominately minority interest costs on
issuance of Company-obligated mandatorily redeemable preferred securities of
subsidiary trust and the effects of purchase accounting, including goodwill
amortization and fair value adjustments to the carrying value of assets and
liabilities. In order to provide comparability between periods, the Company has
prepared pro forma results as if the Teton Transaction had occurred at the
beginning of each year after giving effect to pro forma adjustments related to
the acquisition, including the issuance of the 11% trust preferred securities.
The discussion therefore will highlight any significant variances on a pro forma
basis from the six months ended June 30, 2000 to the six months ended June 30,
2001.
Pro forma operating revenue for the six months ended June 30, 2001 was
$2,780.0 million compared with $2,382.2 million for the same period in 2000, an
increase of 16.7%. MidAmerican Energy operating revenue increased for the six
months ended June 30, 2001 to $1,489.9 million from $992.7 million for the same
period in 2000, primarily due to increases in volumes and prices of regulated
and non-regulated gas. Northern operating revenue decreased for the six months
ended June 30, 2001 to $906.1 million from $1,068.1 million for the same period
in 2000, primarily due to changes in foreign exchange rates and lower volumes
and rates of electricity supplied. The remaining increase primarily relates to
the increase of revenue at HomeServices due to acquisitions and the inclusion of
a joint venture which was previously accounted for as an equity investment.
The following data represents sales from MidAmerican Energy:
Six Months
Ended June 30,
------------------------------
2001 2000
--------------- -----------
Electricity Retail Sales (GWh)............... 8,029 7,905
Electricity Sales for Resale (GWh)........... 4,391 3,443
Regulated and Non-Regulated Gas Supplied
(Thousands of MMBtus)........................ 123,268 82,571
MidAmerican Energy electric retail sales increased for the six months ended
June 30, 2001 from the same period in 2000 due to more extreme temperatures
partially offset by a decrease in non-weather related sales. Electric sales for
resale increased for the six months ended June 30, 2001 from the same period in
2000 due to higher production at the Cooper and Neal power plants and favorable
market conditions. Regulated and non-regulated gas supplied increased due to
growth in the non-regulated markets for the six months ended June 30, 2001
compared to the same period in 2000.
The following data represents the supply and distribution operations in the
U.K.:
Six Months
Ended June 30,
-------------------------------
2001 2000
------------ ----------
Electricity Supplied (GWh).............. 9,176 9,915
Electricity Distributed (GWh)........... 8,559 8,210
Gas Supplied (Thousands of MMBtus)...... 34,688 25,443
The decrease in electricity supplied for the six months ended June 30, 2001
is due to the decreases in volumes both inside and outside the authorized area.
The increase in electricity distributed for the six months ended June 30, 2001
is due to changes in demand in the distribution area. The increase in gas
supplied in 2001 from 2000 reflects higher volume in the U.K. industrial and
commercial markets.
Pro forma interest and other income for the six months ended June 30, 2001
was $55.9 million compared with $46.8 million for the same period in 2000. The
increase was due primarily to gains on the sales of Western States Geothermal,
an indirect wholly owned subsidiary of the Company and other investments,
partially offset by reduced interest income and lower income from equity
investments.
Pro forma cost of sales for the six months ended June 30, 2001 was $1,671.8
million compared with $1,283.7 million for the same period in 2000, an increase
of 30.2%. The increase relates primarily to increased volumes and prices for
both regulated and non-regulated gas at MidAmerican Energy, and acquisitions at
HomeServices, partially offset by decreased cost of sales at Northern due to a
lower foreign exchange rate and lower electricity volumes and prices.
Pro forma operating expenses for the six months ended June 30, 2001 was
$550.9 million compared with $542.8 million for the same period in 2000. The
increase was primarily due to higher costs at HomeServices due to acquisitions
and the inclusion of a joint venture which was previously accounted for as an
equity investment and higher costs at MidAmerican due to costs related to
Cooper, accounts receivable discounts and bad debts, partially offset by lower
costs at Northern due to lower exchange rate and lower costs related to bad
debt, marketing and pensions.
Pro forma depreciation and amortization for the six months ended June 30,
2001 was $237.8 million compared with $242.5 million for the same period in
2000. This decrease was due to lower depreciation at Northern primarily due to
lower foreign exchange rates, partially offset by higher depreciation at
MidAmerican Energy due to an increase in depreciation rates implemented in 2001
and utility capital expenditures.
Pro forma interest expense, less amounts capitalized, for the six months
ended June 30, 2001 was $190.2 million compared with $204.0 million for the same
period in 2000, a decrease of 7.3%. This decrease is due to lower average
outstanding debt balances, an increase in capitalized interest related to the
construction of Casecnan, Cordova and Zinc Recovery Project and lower foreign
exchange rates at Northern, partially offset by lower capitalized interest on
the mineral extraction process.
The loss on non-recurring item of $7.6 million in the period from January
1, 2000 through March 13, 2000 represents the costs related to the Teton
Transaction.
Pro forma tax expense for the six months ended June 30, 2001 was $54.2
million compared with $40.7 million for the same period in 2000. The increase is
due to higher pre-tax income.
Pro forma minority interest for the six months ended June 30, 2001 was
$52.2 million compared with $51.5 million for the same period in 2000. The
increase is primarily due to increased minority interest at HomeServices.
Pro forma net income for the six months ended June 30, 2001 was $74.1
million compared with $56.4 million for the same period in 2000.
Liquidity and Capital Resources
The Company has available a variety of sources of liquidity and capital
resources, both internal and external. These resources provide funds required
for current operations, construction expenditures, debt retirement and other
capital requirements.
The Company's cash and cash equivalents were $41.3 million at June 30, 2001
compared to $38.2 million at December 31, 2000. In addition, the Company
recorded separately restricted cash and investments of $39.5 million and $90.9
million at June 30, 2001 and December 31, 2000, respectively. The restricted
cash balance as of June 30, 2001 is comprised primarily of amounts deposited in
restricted accounts from which the Company will fund the various projects under
construction. Additionally, the Philippine Projects' restricted cash is reserved
for the service of debt obligations.
On March 1, 2001 MidAmerican Funding, LLC retired $200 million of 5.85%
Senior Secured Notes due 2001. On March 19, 2001 MidAmerican Funding, LLC issued
$200 million of 6.75% Senior Secured Notes due March 1, 2011.
Construction
Minerals Extraction
The Company owns the rights to proprietary processes for the extraction of
minerals from elements in solution in the geothermal brine and fluids utilized
at its Imperial Valley plants. A pilot plant has successfully produced
commercial quality zinc at the Company's Imperial Valley Projects. The Company
intends to sequentially develop facilities for the extraction of manganese,
silver, gold, lead, boron, lithium and other products as it further develops the
extraction technology.
CalEnergy Minerals LLC, an indirect wholly owned subsidiary of the Company,
is constructing the Zinc Recovery Project which will recover zinc from the
geothermal brine (the "Zinc Recovery Project"). Facilities are being installed
near the Imperial Valley Project's sites to extract a zinc chloride solution
from the geothermal brine through an ion exchange process. This solution will be
transported to a central processing plant where zinc ingots will be produced
through solvent extraction, electrowinning and casting processes. The Zinc
Recovery Project is designed to have a capacity of approximately 30,000 metric
tons per year and is scheduled to commence commercial operations in 2002. In
September 1999, CalEnergy Minerals LLC entered into a sales agreement whereby
all zinc produced by the Zinc Recovery Project will be sold to Cominco, Ltd. The
initial term of the agreement expires in December 2005.
The Zinc Recovery Project was being constructed by Kvaerner U.S. Inc.
("Kvaerner") pursuant to a date certain, fixed-price, turnkey engineering,
procure, construct and manage contract (the "Zinc Recovery Project EPC
Contract"). On June 14, 2001, CalEnergy Minerals, LLC issued notices of default,
termination and demand for payment of damages to Kvaerner under the Zinc
Recovery Project EPC Contract due to failure to meet performance obligations. As
a result of Kvaerner's failure to pay monetary obligations under the Zinc
Recovery Project EPC Contract, CalEnergy Minerals, LLC drew $29.7 million under
the EPC Contract Letter of Credit on July 20, 2001. CalEnergy Minerals, LLC has
entered into a time and materials reimbursable engineer, procure and
construction management contract with AMEC E&C Services, Inc. to complete the
Zinc Recovery Project.
Casecnan
CE Casecnan Water and Energy Company, Inc., a Philippine corporation ("CE
Casecnan") which at completion of the Casecnan Project is expected to be at
least 70% indirectly owned by the Company, is constructing the Casecnan Project,
a combined irrigation and 150 net MW hydroelectric power generation project (the
"Casecnan Project") located in the central part of the island of Luzon in the
Republic of the Philippines.
CE Casecnan has entered into a fixed-price, date certain, turnkey
engineering, procurement and construction contract to complete the construction
of the Casecnan Project (the "Casecnan Construction Contract"). The work under
the Casecnan Construction Contract is being conducted by a consortium consisting
of Cooperative Muratori Cementisti CMC di Ravenna and Impresa Pizzarotti & C.
Spa working together with Siemens A.G., Sulzer Hydro Ltd., Black & Veatch and
Colenco Power Engineering Ltd. (collectively, the "Contractor").
On November 20, 1999, the Casecnan Construction Contract was amended to
extend the Guaranteed Substantial Completion Date for the Casecnan Project to
March 31, 2001. This amendment was approved by the lender's independent engineer
under the Casecnan Indenture. In January 2001, CE Casecnan received a new
working schedule from the Contractor that showed a completion date of August 31,
2001. Furthermore, in July 2001, CE Casecnan received new schedule information
from the Contractor which extends the expected Substantial Completion Date for
the Casecnan Project from August 31, 2001 to October 6, 2001.
The receipt of the working schedule does not change the Guaranteed
Substantial Completion Date under the Replacement Contract, and the Contractor
is still contractually obligated either to complete the Casecnan Project by
March 31, 2001 or to pay delay liquidated damages. As a result of receipt of the
working schedule, however, CE Casecnan has sought and obtained from the lender's
independent engineer approval for a revised construction schedule under the
Casecnan Indenture. In connection with the revised schedule, the Company agreed
to make available up to $11.6 million of additional funds under certain
conditions pursuant to a Shareholder Support Letter dated February 8, 2001 (the
"Shareholder Support Letter") to cover additional costs resulting from the
Contractor's schedule delay. As agreed in the Shareholder Support Letter and
assuming payments are received under the bank guaranty supporting the
Contractor's obligation to pay delay liquidated damages prior to October 6,
2001, CE Casecnan believes that the funds available to it are reasonably
expected to be sufficient to fund the costs of reaching completion of the
Casecnan Project. However, due to the delay in completion of the project, CE
Casecnan does not presently expect that it will receive significant operating
revenues from the Casecnan Project prior to November 15, 2001. As a result, CE
Casecnan presently expects that it will have insufficient funds available to it
for purposes of making the principal and interest payments which will become due
on November 15, 2001 on the debt securities issued by CE Casecnan in November
1995 (the "Debt Securities"), unless the Company agrees to fund the expected
shortfall amount which is currently estimated to be approximately $24.6 million.
CE Casecnan has been advised that the willingness of the Company to fund
such November 15, 2001 shortfall will principally depend upon the progress of
the pending arbitration proceedings involving the Contractor, including any
orders issued in the future by the arbitration panel; completion of the Casecnan
Project in substantial compliance with the revised construction schedule; and
performance by the National Irrigation Administration ("NIA") of its obligations
under the Project Agreement. Subject to these same assumptions, CE Casecnan does
not presently expect that any additional funding will be required to be provided
to it by the Company in order for CE Casecnan to make future principal and
interest payments on the Debt Securities following the November 15, 2001
payments.
CE Casecnan's ability to make payments on any of its existing and future
obligations is dependent on NIA's and the Republic of the Philippines' ("RP")
performance of their obligations under the Project Agreement and the Performance
Undertaking, respectively. Except to the extent expressly provided for in the
Shareholder Support Letter, no shareholders, partners or affiliates of CE
Casecnan, including the Company, and no directors, officers or employees of the
Company will guarantee or be in any way liable for payment of CE Casecnan's
obligations. As a result, payment of CE Casecnan's obligations depends upon the
availability of sufficient revenues from CE Casecnan's business after the
payment of operating expenses.
Cordova
Cordova Energy Company LLC ("Cordova Energy"), an indirect wholly owned
subsidiary of the Company, completed construction of a 537 MW gas-fired power
plant in the Quad Cities, Illinois area (the "Cordova Project"). The Cordova
Project became operational June 19, 2001.
MidAmerican
On July 10, 2001, MidAmerican Energy announced plans to develop and
construct two electric generating plants in Iowa, requiring an investment of
approximately $1.5 billion. Participation by others in a portion of the second
plant is being discussed. The two plants will provide approximately 1,400
megawatts of generating capacity. MidAmerican Energy expects to begin
construction in Spring 2002 on the first project, a 540-megawatt natural
gas-fired combined cycle unit which has an estimated cost of $340 million. It is
anticipated that the first phase of the project will be completed in 2003 with
the remainder being completed in 2005. MidAmerican Energy presently expects that
all utility construction expenditures for the next five years will be met with
the issuance of long-term debt and cash generated from utility operations, net
of dividends. The actual level of cash generated from utility operations is
affected by, among other things, economic conditions in the utility service
territory, weather and federal and state regulatory actions.
Domestic Rate Matters: Electric
In 1997, pursuant to a rate proceeding before the Iowa Utilities Board,
MidAmerican Energy, the Office of Consumer Advocate and other parties entered
into a pricing plan settlement agreement establishing MidAmerican Energy's Iowa
retail electric rates. That settlement agreement expired on December 31, 2000.
On March 14, 2001, the Office of the Consumer Advocate filed a petition
with the Iowa Utilities Board to reduce Iowa retail electric rates by
approximately $77 million annually. On June 11, 2001, MidAmerican Energy
responded to that petition by filing a request with the Iowa Utilities Board to
increase MidAmerican Energy's Iowa retail electric rates by $51 million
annually. On July 12, 2001, MidAmerican Energy, the Office of Consumer Advocate
and other parties jointly filed a settlement agreement with the Iowa Utilities
Board that, if approved, will freeze the rates in effect on December 31, 2000
through December 31, 2005, and, with modifications, will reinstate the revenue
sharing provisions of the 1997 pricing plan settlement agreement. Under the
proposed settlement agreement, 50% of revenues associated with returns on equity
between 12% and 14%, and 83.33% of revenues associated with returns on equity
above 14%, in each year would be deferred as a regulatory liability to be used
to offset a portion of the cost of future generating plant investments.
MidAmerican Energy has negotiated individual electric contracts with some
of its commercial and industrial customers in Iowa. The negotiated electric
contracts have differing terms and conditions as well as prices. The vast
majority of the contracts expire during the period 2003 through 2005, although
some large customers have contracts extending to 2008. Some of the contracts
have price renegotiation and early termination provisions exercisable by either
party. Prices are set as fixed prices; however, many contracts allow for
potential price adjustments with respect to environmental costs, government
imposed public purpose programs, tax changes, and transition costs. While the
contract prices are fixed (except for the potential adjustment elements), the
costs MidAmerican Energy incurs to fulfill these contracts will vary. On an
aggregate basis the annual revenues under contract are approximately $180
million.
UK Rate Matters
Distribution
Northern charges access fees for the use of the distribution system. Most
revenue of the distribution business is controlled by a distribution price
control formula. The current formula requires that regulated distribution income
per unit is increased or decreased each year by RPI-Xd where RPI reflects the
average of the twelve months' inflation rates recorded for the previous July to
December period and Xd is set at 3%. The formula also takes account of the
changes in system electrical losses, the number of customers connected and the
voltage at which customers receive the units of electricity distributed. The
formula determines the maximum average price per unit of electricity distributed
(in pence per kilowatt hour) which a Public Electricity Supplier ("PES") is
entitled to charge. The price control does not seek to constrain the profits of
a PES from year to year. It is a control on revenue that operates independently
of the PES's costs. During the lifetime of the price control, additional cost
savings therefore contribute directly to profit.
Changes to the formula took effect from April 1, 2000 resulting in a
one-off reduction in allowed income per unit distributed of around 24%. As part
of the review, the Xd factor remains at 3%. The distribution prices allowable
under the current distribution price control formula are expected to be reviewed
by the Office of Gas and Electricity Markets ("Ofgem") at the expiration of the
formula's scheduled five-year duration in 2005. The formula may be reviewed at
other times at the discretion of Ofgem, including in connection with the
proposed Information and Incentive Project (IIP) under which it is proposed that
2% of regulated income will depend upon the performance of the PES's
distribution system as measured by the number and duration of customer
interruptions and upon the level of customer satisfaction monitored by the
regulator.
Supply
In December 1999, Ofgem announced revised electric supply price controls.
Since April 2000, these have been applied to most domestic and small commercial
customers in the below 100kW market of Northern's designated area, and result in
a further lowering of price caps. The new price control applies for two years to
March 2002.
While the impact of the latest regulatory review varied across companies,
the impact on a standard Northern customer was a price reduction of
approximately 11%.
The supply companies are able to propose and amend the detailed structure
of tariffs, but these must be submitted to Ofgem to ensure their consistency
with the prescribed price caps. Prices are then monitored on an ongoing basis,
and any proposed further amendments must be submitted to Ofgem for review.
In addition to the constraint of regulatory price caps, competitive
pressures from other suppliers are exerted against Northern's tariffs and
contracts.
Beginning on March 27, 2001, the New Electricity Trading Arrangements
("NETA") replaced the Pool with market arrangements more reflective of other
commodities. The bulk of energy settlement under this system occurs either
bilaterally or through power exchanges. Risk mitigation is dependent on the
establishment of effective load forecasting tools, addressing short and
longer-term requirements. In addition, it is expected that new hedging
facilities will be established, although the form of these has yet to be
defined.
On August 6, 2001, the Company and Innogy, plc reached an agreement to
exchange Northern's electricity and gas supply and metering business for
Innogy's Yorkshire Electricity distribution business. The transaction is
expected to close in approximately two to three months. The acquisition of
Yorkshire's distribution business by Northern Electric plc will create a company
serving more than 3.6 million customers in the United Kingdom throughout an area
of approximately 10,000 square miles.
Environmental Matters: Domestic
The U.S. Environmental Protection Agency, or EPA, and state environmental
agencies have determined that contaminated wastes remaining at decommissioned
manufactured gas plant facilities may pose a threat to the public health or the
environment if these contaminants are in sufficient quantities and at sufficient
concentrations as to warrant remedial action.
MidAmerican Energy has evaluated or is evaluating 27 properties which were,
at one time, sites of gas manufacturing plants in which it may be a potentially
responsible party. The purpose of these evaluations is to determine whether
waste materials are present, whether the materials constitute an environmental
or health risk, and whether MidAmerican Energy has any responsibility for
remedial action. MidAmerican Energy's estimate of the probable costs for these
sites as of June 30, 2001, was $24 million. This estimate has been recorded as a
liability and a regulatory asset for future recovery through the regulatory
process.
Although the timing of potential incurred costs and recovery of costs in
rates may affect the results of operations in individual periods, management
believes that the outcome of these issues will not have a material adverse
effect on the Company's financial position or results of operations.
On July 18, 1997, the EPA adopted revisions to the National Ambient Air
Quality Standards for ozone and a new standard for fine particulate matter. In
May 1999, the U.S. Court of Appeals for the District of Columbia Circuit
remanded the standards adopted in July 1997 back to the EPA indicating the EPA
had not expressed sufficient justification for the basis of establishing the
standards and ruling that the EPA has exceeded its constitutionally-delegated
authority in setting the standards. On February 27, 2001, the U.S. Supreme Court
upheld the standards, ruling that the EPA did not exceed its constitutional
delegation of authority in establishing the standard in 1997. The impact of any
new standards on the Company is currently unknown. MidAmerican Energy could
incur increased costs and a decrease in revenues if its generating stations are
located in nonattainment areas.
Environmental Matters: U.K.
The U.K. Government introduced new contaminated land legislation in April
2000 that requires companies to:
o Put in place a program for investigating the company's history to
identify problem sites for which it is responsible;
o make a clear commitment to meeting responsibilities for cleaning up
those sites;
o provide funding to make sure that this can happen; and
o make commitments public.
Northern is in the process of completing the evaluation work on the seven
sites which may be subject to the legislation. A compliance strategy will then
be developed. Exploratory work with an environmental remediation company is
expected to minimize any clean up costs.
The Environmental Protection Act (Disposal of PCB's and other Dangerous
Substances) Regulations 2000 were introduced on May 5, 2000. The regulations
required that transformers containing over 50 parts per million (PPM) be
registered with the Environment Agency by July 31, 2000. Transformers containing
500 PPM were required to be de-contaminated by December 31, 2000. Northern has
registered 62 items above 50 PPM, de-contaminated 4 items and informed the
Environment Agency that it is continuing with its sampling, labeling and
registration program.
Nuclear Decommissioning
Each licensee of a nuclear facility is required to provide financial
assurance for the cost of decommissioning its licensed nuclear facility. In
general, decommissioning of a nuclear facility means to safely remove the
facility from service and restore the property to a condition allowing
unrestricted use by the operator. Based on information presently available, the
Company expects to contribute approximately $41 million during the period 2001
through 2005 to an external trust established for the investment of funds for
decommissioning Quad Cities Station. Approximately 60% of the trust's funds are
now invested in domestic corporate debt and common equity securities. The
remainder is invested in investment grade municipal and U.S. Treasury bonds.
Based on information presently available and assuming a September 2004
shutdown of Cooper, MidAmerican Energy expects to accrue approximately $55
million for Cooper decommissioning during the period 2001 through 2004.
MidAmerican Energy's obligation, if any, for Cooper decommissioning may be
affected by the actual plant shutdown date. In July 1997, the Nebraska Public
Power District filed a lawsuit in United States District of Nebraska naming
MidAmerican Energy as the defendant and seeking a declaration of MidAmerican
Energy's rights and obligations in connection with Cooper nuclear
decommissioning funding. Refer to Part II, Item 1. Legal Proceedings, for
further discussion of the litigation.
Cooper and Quad Cities Station decommissioning costs charged to Iowa
customers are included in base rates, and recovery of increases in those amounts
must be sought through the normal ratemaking process. Cooper decommissioning
costs charged to Illinois customers are recovered through a rate rider on
customer billings.
Development Activity
The Company is actively seeking to develop, construct, own and operate new
energy projects, both domestically and internationally, the completion of any of
which is subject to substantial risk. Development can require the Company to
expend significant sums for preliminary engineering, permitting, fuel supply,
resource exploration, legal, marketing and other expenses in preparation for
competitive bids which the Company may not win or before it can be determined
whether a project is feasible, economically attractive or capable of being
financed. Successful development and construction is contingent upon, among
other things, negotiation on terms satisfactory to the Company of engineering,
construction, fuel supply and sales contracts with other project participants,
receipt of required governmental permits and consents and timely implementation
of construction. There can be no assurance that development efforts on any
particular project, or the Company's development efforts generally, will be
successful.
The financing, construction and development of projects outside the United
States entail significant political and financial risks (including, without
limitation, uncertainties associated with first time privatization efforts in
the countries involved, currency exchange rate fluctuations, currency
repatriation restrictions, political instability, civil unrest and
expropriation) and other structuring issues that have the potential to cause
substantial delays or material impairment of the value of the project being
developed, which the Company may not be fully capable of insuring against. The
uncertainty of the legal environment in certain foreign countries in which the
Company may develop or acquire projects could make it more difficult for the
Company to enforce its rights under agreements relating to such projects. In
addition, the laws and regulations of certain countries may limit the ability of
the Company to hold a majority interest in some of the projects that it may
develop or acquire. The Company's international projects may, in certain cases,
be terminated by a government. Projects in operation, construction and
development are subject to a number of uncertainties more specifically described
in the Company's Form 8-K, dated March 26, 1999, filed with the Securities and
Exchange Commission.
Financial Condition of Edison
Southern California Edison ("Edison"), a wholly-owned subsidiary of Edison
International, is a public utility primarily engaged in the business of
supplying electric energy to retail customers in Central and Southern
California, excluding the city of Los Angeles. The Company is aware that there
have been public announcements that Edison's financial condition has
deteriorated as a result of reduced liquidity. Edison's senior unsecured debt
obligations are currently rated Caa2 by Moody's and D by S&P.
Edison failed to pay approximately $119 million due under the Power
Purchase Agreements of indirect subsidiaries of the Company's 50% owned
subsidiary, CE Generation for power delivered in November and December 2000 and
January, February and March 2001, although the Power Purchase Agreements provide
for billing and payment on a schedule where payments would have normally been
received in early January, February, March, April and May 2001.
On February 21, 2001, the Imperial Valley Projects (excluding Salton Sea
Unit V and CE Turbo), subsidiaries of CE Generation filed a lawsuit against
Edison in California's Imperial County Superior Court seeking a court order
requiring Edison to make the required payments under the Power Purchase
Agreements. The lawsuit also requested, among other things, that the court order
permit the Imperial Valley Projects to suspend deliveries of power to Edison and
to permit the Imperial Valley Projects to sell such power to other purchasers in
California.
On March 22, 2001, the Superior Court granted the Imperial Valley Projects'
Motion for Summary Adjudication and a Declaratory Judgment ordering that: 1)
under the Power Purchase Agreements, the Imperial Valley Projects have the right
to temporarily suspend deliveries of capacity and energy to Edison, 2) the
Imperial Valley Projects are entitled to resell the energy and capacity to other
purchasers and 3) the interim suspension of deliveries to Edison shall not in
any respect result in the modifications or termination of the Power Purchase
Agreements and the Power Purchase Agreements shall in all respects continue in
full force and effect other than the temporary suspension of deliveries to
Edison.
As a result of the March 22, 2001 Declaratory Judgment, the Imperial Valley
Projects suspended deliveries of energy to Edison and entered into a transaction
agreement with El Paso Merchant Energy, L.P. ("EPME") in which the Imperial
Valley Projects' available power was sold to EPME based on percentages of the
Dow Jones SP-15 Index. On June 18, 2001 the Superior Court terminated the
Imperial Valley Projects' right to resell power pursuant to the Declaratory
Judgment.
On June 20, 2001, the Imperial Valley Projects (excluding Salton Sea Unit V
and CE Turbo) entered into Agreements Addressing Renewable Energy Pricing and
Payment Issues with Edison ("Settlement Agreements"). The Settlement Agreements
require Edison make a series of payments to repay the past due balances under
the Power Purchase Agreements (the "stipulated amounts"). The first payment of
approximately $11.6 million, which represented 10% of the stipulated amounts,
was received June 22, 2001. A second partial payment of 10% is payable within 5
days following the MOU Effective Date. The "MOU Effective Date" means the first
day on which both of the following have occurred: (a) all legislation
implementing the Memorandum of Understanding between Edison and the California
Department of Water Resources dated April 9, 2001 ("MOU") or such other
legislation based on the MOU or otherwise, that restores Edison to
creditworthiness has become effective, and (b) the California Public Utilities
Commission ("Commission") has issued all orders that are necessary to implement
the MOU or other mechanisms contained in such legislation based on the MOU or
otherwise which are designed to restore Edison to creditworthiness. The final
payment, representing the remaining stipulated amounts, shall be paid on the 5th
business day after Edison receives proceeds from the financing resulting from
the MOU or other mechanisms contained in such other legislation based on the MOU
or otherwise restore Edison to creditworthiness. In addition to these payments,
Edison is required to make monthly interest payments calculated at a rate of 7%
per annum on the outstanding stipulated amounts. The Settlement Agreements also
provide a revised energy pricing structure, whereby Edison elects to pay the
Imperial Valley Projects a fixed energy price of 5.37 cents/kilowatt hour in
lieu of the Commission-approved SRAC Methodology under the Power Purchase
Agreements, commencing on the first day of the month following the MOU Effective
Date and expiring five years from such date. All other contract terms remain
unchanged.
As a result of the aforementioned Settlement Agreements, the Imperial
Valley Projects resumed power sales to Edison on June 22, 2001. Energy payments
are currently calculated using the SRAC formulas set forth in the Power Purchase
Agreements until the fixed rate period begins.
As a result of Edison's failure to make the payments due under the Power
Purchase Agreements and the recent downgrades of Edison's credit ratings,
Moody's downgraded the ratings for the Salton Sea Funding Corporation (the
"Funding Corporation") Securities to Caa2 (negative outlook) and S&P downgraded
the ratings for the Funding Corporation Securities to BBB- and placed the
Securities on "credit watch negative". Moody's had downgraded the ratings for
the CE Generation Securities to B1 from Baa3 (review for possible downgrade).
Following the execution of the Settlement Agreements, Moody's placed the Salton
Sea Funding and CE Generation securities on "credit watch positive".
The Imperial Valley Projects are contractually entitled to receive payments
under the Power Purchase Agreements and Settlement Agreements. However, due to
the uncertainties associated with Edison's financial condition and failure to
pay contractual obligations, CE Generation has established an allowance for
doubtful accounts of approximately $82 million at June 30, 2001.
New Accounting Pronouncements
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards Nos. 133 and 138 (SFAS 133/138) pertaining to the accounting for
derivative instruments and hedging activities. SFAS 133/138 requires an entity
to recognize all of its derivatives as either assets or liabilities in its
statement of financial position and measure those instruments at fair value. If
the conditions specified in SFAS 133/138 are met, those instruments may be
designated as hedges. Changes in the value of hedge instruments would not impact
earnings, except to the extent that the instrument is not perfectly effective as
a hedge. Initial adoption of SFAS 133/138 did not have a material impact on the
results of operations for the Company.
The Financial Accounting Standards Board ("FASB") has approved guidance
that, in general, option contracts and forward contracts with optionality
features cannot qualify for the normal purchases and normal sales exception
under SFAS 133/138 as amended. However, the FASB has also issued guidance that
energy capacity contracts that include certain characteristics of purchased and
written options could qualify as normal purchases and sales as long as certain
criteria are met. The Company has performed a preliminary review of its
contracts with the above characteristics and believes that its contracts are not
subject to the financial reporting requirements of SFAS 133/138. Another issue
which included tentative guidance as of the filing of the first quarter 2001
Form 10-Q, stated that derivative contracts which do not result in physical
delivery of power because of transmission scheduling, referred to as bookouts,
cannot meet the normal purchases and normal sales exception. This issue was
abandoned by the FASB during the second quarter of 2001.
The FASB's Derivatives Implementation Group continues to identify and
provide guidance on various implementation issues related to SFAS 133/138 that
are in varying stages of review and clearance by the Derivatives Implementation
Group and the FASB. The Company is monitoring the issues being reviewed by the
Derivatives Implementation Group and the FASB to determine what, if any, impact
they may have on the Company's financial statements.
In July 2001, the FASB issued SFAS No. 141, "Business Combinations", and
SFAS No. 142, "Goodwill and Other Intangible Assets" which establish accounting
and reporting for business combinations. SFAS No. 141 requires all business
combinations entered into subsequent to June 30, 2001, to be accounted for using
the purchase method of accounting. SFAS No. 142 provides that goodwill and other
intangible assets with indefinite lives will not be amortized but will be tested
for impairment on an annual basis. These standards are effective for the Company
beginning on January 1, 2002. The Company is evaluating the impact resulting
from the adoption of these standards.
Forward-looking Statements
Certain information included in this report contains forward-looking
statements made pursuant to the Private Securities Litigation Reform Act of 1995
("Reform Act"). Such statements are based on current expectations and involve a
number of known and unknown risks and uncertainties that could cause the actual
results and performance of the Company to differ materially from any expected
future results or performance, expressed or implied, by the forward-looking
statements. In connection with the safe harbor provisions of the Reform Act, the
Company has identified important factors that could cause actual results to
differ materially from such expectations, including development and construction
uncertainty, operating uncertainty, acquisition uncertainty, uncertainties
relating to doing business outside of the United States, uncertainties relating
to geothermal resources, uncertainties relating to domestic and international
economic and political conditions and uncertainties regarding the impact of
regulations, changes in government policy, industry deregulation and
competition. Reference is made to all of the Company's SEC filings, including
the Company's Report on Form 8-K dated March 26, 1999, incorporated herein by
reference, for a description of such factors. The Company assumes no
responsibility to update forward-looking information contained herein.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Company is exposed to market risk, including charges in the market
price of certain commodities and interest rates. To manage the price volatility
relating to these exposures, the Company enters into various financial
derivative instruments. Senior management provides the overall direction,
structure, conduct and control of the Company's risk management activities,
including the use of financial derivative instruments, authorization and
communication of risk management policies and procedures, strategic hedging
program guidelines, appropriate market and credit risk limits, and appropriate
systems for recording, monitoring and reporting the results of transactional and
risk management activities.
Refer to Note 7 in Notes to Consolidated Financial Statements for further
discussion of derivatives used to hedge price risk and currency exchange rate
risk.
PART II - OTHER INFORMATION
Item 1 Legal Proceedings.
The Company and its subsidiaries have no material legal proceedings
except for the following:
Southern California Edison
The Imperial Valley Projects have filed a lawsuit seeking a court
order requiring Edison to make the required payments under the
Power Purchase Agreements. See page 25.
Cooper Litigation
On July 23, 1997, the Nebraska Public Power District ("NPPD") filed a
complaint, in the United States District Court for the District of
Nebraska, naming MidAmerican Energy as the defendant and seeking
declaratory judgment as to three issues under the parties' long-term
power purchase agreement for Cooper capacity and energy. More
specifically, the NPPD sought a declaratory judgment in the following
respects:
(1) that MidAmerican Energy is obligated to pay 50% of all costs and
expenses associated with decommissioning Cooper, and that in the
event that NPPD continues to operate Cooper after expiration of
the power purchase agreement (September 2004), MidAmerican Energy
is not entitled to reimbursement of any decommissioning funds it
has paid to date or will pay in the future;
(2) that the current method of allocating transition costs as a part
of the decommissioning cost is proper under the power purchase
agreement; and
(3) that the current method of investing decommissioning funds is
proper under the power purchase agreement.
MidAmerican Energy filed its answer and contingent counterclaims. The
contingent counterclaims filed by MidAmerican Energy are generally as
follows:
(1) that MidAmerican Energy has no duty under the power purchase
agreement to reimburse or pay 50% of the decommissioning costs
unless conditions to reimbursement occur;
(2) that the NPPD has the duty to repay all amounts that MidAmerican
Energy has prefunded for decommissioning in the event the NPPD
operates the plant after the term of the power purchase agreement;
(3) that the NPPD is equitably estopped from continuing to operate the
plant after the term of the power purchase agreement;
(4) that the NPPD has granted MidAmerican Energy an option to con-
tinue taking 50% of the power from the plant;
(5) that the term "monthly power costs" as defined in the power
purchase agreement does not include costs and expenses associated
with decommissioning the plant;
(6) that MidAmerican Energy has no duty to pay for nuclear fuel,
operations and maintenance projects or capital improvements that
have useful lives after the term of the power purchase agreement;
(7) that transition costs are not included in any decommissioning
costs and expenses;
(8) that the NPPD has breached its duty to MidAmerican Energy in
making investments of decommissioning funds;
(9) that reserves in named accounts are excessive and should be
refunded to MidAmerican Energy; and
(10) that the NPPD must credit MidAmerican Energy for payments by
MidAmerican Energy for low-level radioactive waste disposal.
On October 6, 1999, the court rendered summary judgment for the NPPD on the
above-mentioned issue concerning liability for decommissioning (issue one in the
first paragraph above) and the related contingent counterclaims filed by
MidAmerican Energy (issues one, two, three and five in the second paragraph
above). The court referred all remaining issues in the case to mediation, and
cancelled the November 1999 trial date.
MidAmerican Energy appealed the court's summary judgment ruling. On
December 12, 2000, the United States Court of Appeals for the Eighth Circuit
reversed the ruling of the district court and granted summary judgment in favor
of MidAmerican Energy issues one and five in the second paragraph above.
Additionally, it remanded the case for trial on all other claims and
counterclaims.
Since the remand to the District Court from the Eighth Circuit Court of
Appeals, the NPPD has been granted permission, over MidAmerican Energy's
objections, to amend its complaint. The amended complaint asserts that even
though the Eighth Circuit Court of Appeals held that MidAmerican Energy has no
liability under the power purchase agreement to reimburse or pay the NPPD a 50%
share of decommissioning costs unless certain conditions occur, MidAmerican
Energy has unconditional liability for a 50% share based on agreements other
than the power purchase agreement as originally written. The NPPD's post-remand
contentions -- all strongly disputed by MidAmerican Energy -- are that
MidAmerican Energy has unconditional liability for a 50% share of
decommissioning based on any of the following alternative theories: (i) the
parties without written amendment either modified the power purchase agreement
or made a separate agreement that imposes unconditional liability on MidAmerican
Energy for decommissioning costs; (ii) absent unconditional liability for a 50%
share of decommissioning costs, MidAmerican Energy would be unjustly enriched;
(iii) MidAmerican Energy has unconditional liability for a 50% share of
decommissioning costs based on promissory estoppel; or (iv) the NPPD is entitled
to have the power purchase agreement reformed to provide that MidAmerican Energy
has unconditional liability for a 50% share of decommissioning costs.
MidAmerican Energy will strongly dispute at trial these contentions and theories
put forth by the NPPD. Trial in these matters is scheduled to begin on March 4,
2002.
Item 2 Changes in Securities and Use of Proceeds.
Not applicable.
Item 3 Defaults on Senior Securities.
Not applicable.
Item 4 Submission of Matters to a Vote of Security Holders.
Not applicable.
Item 5 Other Information.
Not applicable.
Item 6 Exhibits and Reports on Form 8-K.
(a) Exhibits:
Exhibits Filed Herewith
Exhibit 15 - Awareness Letter of Independent Accountants.
(b) Reports on Form 8-K:
None
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.
MIDAMERICAN ENERGY HOLDINGS COMPANY
-----------------------------------
(Registrant)
Date: August 14, 2001 /s/ Patrick J. Goodman
------------------------------------
Patrick J. Goodman
Senior Vice President &
Chief Financial Officer
EXHIBIT INDEX
Exhibit No. Page No.
- ----------- --------
15 Awareness Letter of Independent Accountants 33
Exhibit 15
AWARENESS LETTER OF INDEPENDENT ACCOUNTANTS
MidAmerican Energy Holdings Company
Des Moines, Iowa
We have made a review, in accordance with standards established by the
American Institute of Certified Public Accountants, of the unaudited
consolidated interim financial information of MidAmerican Energy Holdings
Company and subsidiaries for the period ended June 30, 2001 and for the period
March 14, 2000 to June 30, 2000 for MidAmerican Energy Holdings Company and for
the period January 1, 2000 to March 13, 2000 for MidAmerican Energy Holdings
Company (Predecessor), as indicated in our report dated August 6, 2001; because
we did not perform an audit, we expressed no opinion on that information.
We are aware that our report referred to above, which is included in your
Quarterly Report on Form 10-Q for the quarter ended June 30, 2001, is
incorporated by reference in Registration Statements No. 333-30537, No.
333-45615 and No. 333-62697 on Form S-3.
We also are aware that the aforementioned report, pursuant to Rule 436(c)
under the Securities Act of 1933, is not considered a part of a Registration
Statement prepared or certified by an accountant or a report prepared or
certified by an accountant within the meaning of Sections 7 and 11 of that Act.
DELOITTE & TOUCHE LLP
Des Moines, Iowa
August 14, 2001