Attached files
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 September 30, 2009
or
[ ]
Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934
For the
transition period from ______ to _______
Commission
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Exact
name of registrant as specified in its charter;
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IRS
Employer
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||
File
Number
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State
or other jurisdiction of incorporation or
organization
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Identification No.
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001-14881
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MIDAMERICAN
ENERGY HOLDINGS COMPANY
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94-2213782
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(An
Iowa Corporation)
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666
Grand Avenue, Suite 500
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Des
Moines, Iowa 50309-2580
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515-242-4300
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N/A
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(Former
name, former address and former fiscal year, if changed since last
report)
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Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes T No ¨
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes ¨ No ¨
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting company. See
the definition of “large accelerated filer,” “accelerated filer” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
Large
accelerated filer ¨
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Accelerated
filer ¨
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Non-accelerated
filer T
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Smaller
reporting company ¨
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).
Yes ¨ No T
All of
the shares of common equity of MidAmerican Energy Holdings Company are privately
held by a limited group of investors. As of October 31, 2009, 74,859,001
shares of common stock were outstanding.
TABLE OF
CONTENTS
PART
I - FINANCIAL INFORMATION
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PART
II - OTHER INFORMATION
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2
PART
I
Financial
Statements
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REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
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 and subsidiaries (the “Company”) as of September 30, 2009,
and the related consolidated statements of operations for the three-month and
nine-month periods ended September 30, 2009 and 2008, and of cash flows and
changes in equity for the nine-month periods ended September 30, 2009 and
2008. These interim financial statements are the responsibility of the Company’s
management.
We
conducted our reviews in accordance with the standards of the Public Company
Accounting Oversight Board (United States). A review of interim financial
information consists principally of applying analytical procedures and making
inquiries of persons responsible for financial and accounting matters. It is
substantially less in scope than an audit conducted in accordance with the
standards of the Public Company Accounting Oversight Board (United States), 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 reviews, we are not aware of any material modifications that should be made
to such consolidated interim 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 the standards of the Public Company
Accounting Oversight Board (United States), the consolidated balance sheet of
MidAmerican Energy Holdings Company and subsidiaries as of December 31,
2008, and the related consolidated statements of operations, shareholders’
equity, and cash flows for the year then ended prior to retrospective adjustment
for the adoption of new accounting guidance related to noncontrolling interest in
a subsidiary, included in Accounting Standards Codification Topic 810 (not
presented herein); and in our report dated February 27, 2009, we expressed
an unqualified opinion on those consolidated financial statements. We also
audited the adjustments described in Note 2 that were applied to
retrospectively adjust the December 31, 2008 consolidated balance sheet of
MidAmerican Energy Holdings Company and subsidiaries (not presented herein). In
our opinion, such adjustments are appropriate and have been properly applied to
the previously issued consolidated balance sheet in deriving the accompanying
retrospectively adjusted consolidated balance sheet as of December 31,
2008.
/s/
Deloitte & Touche LLP
Des
Moines, Iowa
November 6,
2009
3
MIDAMERICAN
ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS (Unaudited)
(Amounts
in millions)
As
of
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||||||||
September 30,
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December 31,
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|||||||
2009
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2008
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|||||||
ASSETS
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||||||||
Current
assets:
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||||||||
Cash
and cash equivalents
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$ | 744 | $ | 280 | ||||
Trade
receivables, net
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1,078 | 1,310 | ||||||
Inventories
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581 | 566 | ||||||
Derivative
contracts
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141 | 227 | ||||||
Investments
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10 | 1,505 | ||||||
Other
current assets
|
575 | 529 | ||||||
Total
current assets
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3,129 | 4,417 | ||||||
Property,
plant and equipment, net
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30,432 | 28,454 | ||||||
Goodwill
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5,076 | 5,023 | ||||||
Regulatory
assets
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2,044 | 2,156 | ||||||
Derivative
contracts
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58 | 97 | ||||||
Investments
and other assets
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3,251 | 1,294 | ||||||
Total
assets
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$ | 43,990 | $ | 41,441 |
The
accompanying notes are an integral part of these consolidated financial
statements.
4
MIDAMERICAN
ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS (Unaudited) (continued)
(Amounts
in millions)
As
of
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||||||||
September 30,
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December 31,
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|||||||
2009
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2008
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|||||||
LIABILITIES
AND EQUITY
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||||||||
Current
liabilities:
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||||||||
Accounts
payable
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$ | 821 | $ | 1,240 | ||||
Accrued
interest
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345 | 340 | ||||||
Accrued
property, income and other taxes
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302 | 561 | ||||||
Derivative
contracts
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132 | 183 | ||||||
Short-term
debt
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120 | 836 | ||||||
Current
portion of long-term debt
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128 | 421 | ||||||
Current
portion of MEHC subordinated debt
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234 | 734 | ||||||
Other
current liabilities
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683 | 578 | ||||||
Total
current liabilities
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2,765 | 4,893 | ||||||
Regulatory
liabilities
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1,558 | 1,506 | ||||||
Derivative
contracts
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401 | 546 | ||||||
MEHC
senior debt
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5,371 | 5,121 | ||||||
MEHC
subordinated debt
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423 | 587 | ||||||
Subsidiary
debt
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13,709 | 12,533 | ||||||
Deferred
income taxes
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5,420 | 3,949 | ||||||
Other
long-term liabilities
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1,815 | 1,829 | ||||||
Total
liabilities
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31,462 | 30,964 | ||||||
Commitments
and contingencies (Note 12)
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||||||||
Equity:
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MEHC
shareholders’ equity:
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||||||||
Common
stock - 115 shares authorized, no par value, 75 shares issued and
outstanding
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- | - | ||||||
Additional
paid-in capital
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5,453 | 5,455 | ||||||
Retained
earnings
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6,495 | 5,631 | ||||||
Accumulated
other comprehensive income (loss), net
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303 | (879 | ) | |||||
Total
MEHC shareholders’ equity
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12,251 | 10,207 | ||||||
Noncontrolling
interests
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277 | 270 | ||||||
Total
equity
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12,528 | 10,477 | ||||||
Total
liabilities and equity
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$ | 43,990 | $ | 41,441 |
The
accompanying notes are an integral part of these consolidated financial
statements.
5
MIDAMERICAN
ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS (Unaudited)
(Amounts
in millions)
Three-Month
Periods
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Nine-Month
Periods
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|||||||||||||||
Ended
September 30,
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Ended
September 30,
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|||||||||||||||
2009
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2008
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2009
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2008
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Operating
revenue:
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Energy
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$ | 2,429 | $ | 2,910 | $ | 7,448 | $ | 8,675 | ||||||||
Real
estate
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312 | 330 | 764 | 913 | ||||||||||||
Total
operating revenue
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2,741 | 3,240 | 8,212 | 9,588 | ||||||||||||
Operating
costs and expenses:
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Energy:
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Cost
of sales
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875 | 1,315 | 2,818 | 3,949 | ||||||||||||
Operating
expense
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598 | 561 | 1,908 | 1,766 | ||||||||||||
Depreciation
and amortization
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313 | 264 | 916 | 824 | ||||||||||||
Real
estate
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294 | 329 | 748 | 923 | ||||||||||||
Total
operating costs and expenses
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2,080 | 2,469 | 6,390 | 7,462 | ||||||||||||
Operating
income
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661 | 771 | 1,822 | 2,126 | ||||||||||||
Other
income (expense):
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Interest
expense
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(316 | ) | (340 | ) | (957 | ) | (998 | ) | ||||||||
Capitalized
interest
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12 | 14 | 30 | 37 | ||||||||||||
Interest
and dividend income
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8 | 16 | 36 | 47 | ||||||||||||
Other,
net
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41 | 19 | 119 | 59 | ||||||||||||
Total
other income (expense)
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(255 | ) | (291 | ) | (772 | ) | (855 | ) | ||||||||
Income
before income tax expense and equity income
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406 | 480 | 1,050 | 1,271 | ||||||||||||
Income
tax expense
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39 | 149 | 211 | 378 | ||||||||||||
Equity
income
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(21 | ) | (24 | ) | (49 | ) | (33 | ) | ||||||||
Net
income
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388 | 355 | 888 | 926 | ||||||||||||
Net
income attributable to noncontrolling interests
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12 | 5 | 24 | 14 | ||||||||||||
Net
income attributable to MEHC
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$ | 376 | $ | 350 | $ | 864 | $ | 912 |
The
accompanying notes are an integral part of these consolidated financial
statements.
6
MIDAMERICAN
ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS (Unaudited)
(Amounts
in millions)
Nine-Month
Periods
|
||||||||
Ended
September 30,
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||||||||
2009
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2008
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|||||||
Cash
flows from operating activities:
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Net
income
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$ | 888 | $ | 926 | ||||
Adjustments
to reconcile net income to net cash flows from operating
activities:
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||||||||
Gain
on other items, net
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(4 | ) | (24 | ) | ||||
Depreciation
and amortization
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929 | 838 | ||||||
Stock-based
compensation
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123 | - | ||||||
Changes
in regulatory assets and liabilities
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28 | (31 | ) | |||||
Provision
for deferred income taxes
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700 | 440 | ||||||
Other,
net
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(39 | ) | (17 | ) | ||||
Changes
in other operating assets and liabilities, net of effects from
acquisition:
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||||||||
Trade
receivables and other assets
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293 | 91 | ||||||
Derivative
collateral, net
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93 | (100 | ) | |||||
Trading
securities
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499 | - | ||||||
Contributions
to pension and other postretirement benefit plans, net
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(74 | ) | (94 | ) | ||||
Accounts
payable and other liabilities
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(453 | ) | (24 | ) | ||||
Net
cash flows from operating activities
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2,983 | 2,005 | ||||||
Cash
flows from investing activities:
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||||||||
Capital
expenditures
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(2,592 | ) | (2,678 | ) | ||||
Acquisition,
net of cash acquired
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- | (308 | ) | |||||
Purchases
of available-for-sale securities
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(483 | ) | (177 | ) | ||||
Proceeds
from sales of available-for-sale securities
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242 | 179 | ||||||
Proceeds
from investments
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1,000 | 393 | ||||||
Purchase
of Constellation Energy 8% preferred stock
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- | (1,000 | ) | |||||
Other,
net
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(13 | ) | 22 | |||||
Net
cash flows from investing activities
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(1,846 | ) | (3,569 | ) | ||||
Cash
flows from financing activities:
|
||||||||
Proceeds
from MEHC senior and subordinated debt
|
250 | 1,649 | ||||||
Repayments
of MEHC senior and subordinated debt
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(667 | ) | (1,167 | ) | ||||
Proceeds
from subsidiary debt
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992 | 1,498 | ||||||
Repayments
of subsidiary debt
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(383 | ) | (997 | ) | ||||
Purchases
of subsidiary debt
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- | (216 | ) | |||||
Net
repayments of MEHC revolving credit facility
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(216 | ) | - | |||||
Net
(repayments of) proceeds from subsidiary short-term debt
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(506 | ) | 274 | |||||
Net
payment of hedging instruments
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- | (99 | ) | |||||
Net
purchases of common stock
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(123 | ) | - | |||||
Other,
net
|
(23 | ) | (22 | ) | ||||
Net
cash flows from financing activities
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(676 | ) | 920 | |||||
Effect
of exchange rate changes
|
3 | (3 | ) | |||||
Net
change in cash and cash equivalents
|
464 | (647 | ) | |||||
Cash
and cash equivalents at beginning of period
|
280 | 1,178 | ||||||
Cash
and cash equivalents at end of period
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$ | 744 | $ | 531 |
The
accompanying notes are an integral part of these consolidated financial
statements.
7
MIDAMERICAN
ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CHANGES IN EQUITY (Unaudited)
(Amounts
in millions)
MEHC
Shareholders’ Equity
|
||||||||||||||||||||||||||||
Accumulated
|
||||||||||||||||||||||||||||
Other
|
||||||||||||||||||||||||||||
Additional
|
Comprehensive
|
|||||||||||||||||||||||||||
Common
|
Paid-in
|
Retained
|
Income
(Loss),
|
Noncontrolling
|
Total
|
|||||||||||||||||||||||
Shares
|
Stock
|
Capital
|
Earnings
|
Net
|
Interests
|
Equity
|
||||||||||||||||||||||
Balance,
January 1, 2008
|
75 | $ | - | $ | 5,454 | $ | 3,782 | $ | 90 | $ | 256 | $ | 9,582 | |||||||||||||||
Net
income
|
- | - | - | 912 | - | 14 | 926 | |||||||||||||||||||||
Other
comprehensive loss
|
- | - | - | - | (305 | ) | - | (305 | ) | |||||||||||||||||||
Contributions
|
- | - | - | - | - | 33 | 33 | |||||||||||||||||||||
Distributions
|
- | - | - | - | - | (37 | ) | (37 | ) | |||||||||||||||||||
Other
equity transactions
|
- | - | 1 | - | - | 1 | 2 | |||||||||||||||||||||
Balance,
September 30, 2008
|
75 | $ | - | $ | 5,455 | $ | 4,694 | $ | (215 | ) | $ | 267 | $ | 10,201 | ||||||||||||||
Balance,
January 1, 2009
|
75 | $ | - | $ | 5,455 | $ | 5,631 | $ | (879 | ) | $ | 270 | $ | 10,477 | ||||||||||||||
Net
income
|
- | - | - | 864 | - | 24 | 888 | |||||||||||||||||||||
Other
comprehensive income
|
- | - | - | - | 1,182 | - | 1,182 | |||||||||||||||||||||
Stock-based
compensation
|
- | - | 123 | - | - | - | 123 | |||||||||||||||||||||
Exercise
of common stock options
|
1 | - | 25 | - | - | - | 25 | |||||||||||||||||||||
Common
stock purchases
|
(1 | ) | - | (148 | ) | - | - | - | (148 | ) | ||||||||||||||||||
Contributions
|
- | - | - | - | - | 23 | 23 | |||||||||||||||||||||
Distributions
|
- | - | - | - | - | (53 | ) | (53 | ) | |||||||||||||||||||
Other
equity transactions
|
- | - | (2 | ) | - | - | 13 | 11 | ||||||||||||||||||||
Balance,
September 30, 2009
|
75 | $ | - | $ | 5,453 | $ | 6,495 | $ | 303 | $ | 277 | $ | 12,528 |
The
accompanying notes are an integral part of these consolidated financial
statements.
8
MIDAMERICAN
ENERGY HOLDINGS COMPANY AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(1)
|
General
|
MidAmerican
Energy Holdings Company (“MEHC”) is a holding company that owns subsidiaries
principally engaged in energy businesses (collectively with its subsidiaries,
the “Company”). MEHC is a consolidated subsidiary of Berkshire Hathaway Inc.
(“Berkshire Hathaway”). The balance of MEHC’s common stock is owned by Mr.
Walter Scott, Jr. (along with family members and related entities), a member of
MEHC’s Board of Directors, and Mr. Gregory E. Abel, a member of MEHC’s Board of
Directors and MEHC’s President and Chief Executive Officer. As of
September 30, 2009, Berkshire Hathaway, Mr. Scott (along with family
members and related entities) and Mr. Abel owned 89.5%, 9.7% and 0.8%,
respectively, of MEHC’s voting common stock.
The
Company’s operations are organized and managed as eight distinct platforms:
PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which primarily
consists of MidAmerican Energy Company (“MidAmerican Energy”)), Northern Natural
Gas Company (“Northern Natural Gas”), Kern River Gas Transmission Company (“Kern
River”), CE Electric UK Funding Company (“CE Electric UK”) (which primarily
consists of Northern Electric Distribution Limited (“Northern Electric”) and
Yorkshire Electricity Distribution plc (“Yorkshire Electricity”)), CalEnergy
Generation-Foreign (which owns a majority interest in the Casecnan project in
the Philippines), CalEnergy Generation-Domestic (which owns interests in
independent power projects in the United States) and HomeServices of America,
Inc. (collectively with its subsidiaries, “HomeServices”). Through these
platforms, MEHC owns and operates an electric utility company in the Western
United States, an electric and natural gas utility company in the Midwestern
United States, two interstate natural gas pipeline companies in the United
States, two electricity distribution companies in Great Britain, a diversified
portfolio of independent power projects and the second largest residential real
estate brokerage firm in the United States.
The
unaudited Consolidated Financial Statements have been prepared in accordance
with accounting principles generally accepted in the United States of America
(“GAAP”) for interim financial information and the United States Securities and
Exchange Commission’s rules and regulations for Form 10-Q and
Article 10 of Regulation S-X. Accordingly, they do not include all of the
disclosures required by GAAP for annual financial statements. Management
believes the unaudited Consolidated Financial Statements contain all adjustments
(consisting only of normal recurring adjustments) considered necessary for the
fair presentation of the Consolidated Financial Statements as of
September 30, 2009 and for the three- and nine-month periods ended
September 30, 2009 and 2008. Certain amounts in the prior period
Consolidated Financial Statements have been reclassified to conform to the
current period presentation. Such reclassifications did not impact previously
reported operating income, net income attributable to MEHC or retained earnings.
The results of operations for the three- and nine-month periods ended
September 30, 2009 are not necessarily indicative of the results to be
expected for the full year. The Company has evaluated subsequent events through
November 6, 2009, which is the date the unaudited Consolidated Financial
Statements were issued.
The
preparation of the unaudited Consolidated Financial Statements in conformity
with GAAP requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expenses during the period.
Actual results may differ from the estimates used in preparing the unaudited
Consolidated Financial Statements. Note 2 of Notes to Consolidated
Financial Statements included in the Company’s Annual Report on Form 10-K
for the year ended December 31, 2008 describes the most significant
accounting policies used in the preparation of the Consolidated Financial
Statements. There have been no significant changes in the Company’s assumptions
regarding significant accounting estimates and policies during the nine-month
period ended September 30, 2009.
9
(2)
|
New
Accounting Pronouncements
|
In
September 2009, the Financial Accounting Standards Board (the “FASB”) issued
Accounting Standards Update (“ASU”) No. 2009-12 (“ASU No. 2009-12”),
which amends FASB Accounting Standards Codification (“ASC”) Topic 820,
“Fair Value Measurements and Disclosures” (“ASC Topic 820”). ASU No. 2009-12
allows, as a practical expedient, for the net asset value provided by the
investee entity to be an applicable fair value measurement, if the net asset
value was calculated within the provisions of ASC Topic 946, “Financial Services
– Investment Companies.” Investments within the scope of this update are
investments valued at net asset value that do not have a readily determinable
fair value and have all the following attributes: (i) the investment company’s
primary business activity involves investing its assets, usually in the
securities of other entities not under common management, for current income,
appreciation, or both; (ii) ownership in the investment company is represented
by units of investments, such as shares of stock or partnership interests, to
which proportionate shares of net assets can be attributed; (iii) the funds of
the investment company’s owners are pooled to avail owners of professional
investment management and (iv) the investment company is the primary reporting
entity. Classification within the fair value hierarchy of a fair value
measurement of an investment that is measured at net asset value requires
judgment, which includes consideration of the entity’s ability to redeem its
investment at net asset value at the measurement date. If the entity does not
have the ability to redeem the investment at net asset value at the measurement
date, the length of time until the investment can be redeemed shall be
considered. This guidance also requires disclosures, by major category of
investments, about the attributes of the investments. This guidance is effective
for the first reporting period, including interim periods, ending after December
15, 2009. The Company is currently evaluating the impact of adopting this
guidance on its consolidated financial results and disclosures included within
Notes to Consolidated Financial Statements.
In August
2009, the FASB issued ASU No. 2009-05, which amends ASC Topic 820. ASU
No. 2009-05 clarifies how to measure the fair value of a liability for
which a quoted price in an active market for the identical liability is not
available. In such a circumstance, an entity is required to measure fair value
using one or more of the following valuation techniques: (i) quoted
price of the identical liability when traded as an asset, (ii) quoted
prices for similar liabilities or similar liabilities when traded as assets or
(iii) another valuation technique that is consistent with fair value
principles, such as an income approach or a market approach. This guidance also
clarifies that both a quoted price in an active market for the identical
liability at the measurement date and the quoted price for the identical
liability when traded as an asset in an active market when no adjustments to the
quoted price of the asset are required are Level 1 fair value measurements.
When estimating the fair value of a liability, an entity is not required to
include a separate input or adjustment relating to the existence of a
restriction that prevents the transfer of the liability. This guidance is
effective for the first reporting period, including interim periods, beginning
after its August 2009 issuance. The Company is currently evaluating the
impact of adopting this guidance on its disclosures included within Notes to
Consolidated Financial Statements.
In
June 2009, the FASB issued authoritative guidance that requires a primarily
qualitative analysis to determine if an enterprise is the primary beneficiary of
a variable interest entity. This analysis is based on whether the
enterprise has (i) the power to direct the activities of the variable interest
entity that most significantly impact the entity’s economic performance and (ii)
the obligation to absorb losses of the entity or the right to receive benefits
from the entity that could potentially be significant to the variable interest
entity. In addition, enterprises are required to more frequently reassess
whether an entity is a variable interest entity and whether the enterprise is
the primary beneficiary of the variable interest entity. Finally, the guidance
for consolidation or deconsolidation of a variable interest entity is amended
and disclosure requirements about an enterprise’s involvement with a
variable interest entity are enhanced. This guidance is effective as of the
beginning of the first annual reporting period that begins after
November 15, 2009, for interim periods within that first annual reporting
period and for interim and annual reporting periods thereafter, with early
application prohibited. The Company is currently evaluating the impact of
adopting this guidance on its consolidated financial results and disclosures
included within Notes to Consolidated Financial Statements.
In
April 2009, the FASB issued authoritative guidance (included in ASC
Topic 825, “Financial Instruments”) that requires publicly
traded companies to include the annual fair value disclosures required for all
financial instruments, as defined by GAAP, in interim financial statements. The
Company adopted this guidance on April 1, 2009 and included the required
disclosures within Notes to Consolidated Financial Statements.
10
In
April 2009, the FASB issued authoritative guidance (included in ASC
Topic 320, “Investments – Debt and Equity Securities”) that amends
current other-than-temporary impairment guidance for debt securities to require
a new other-than-temporary impairment model that shifts the focus from an
entity’s intent to hold the debt security until recovery to its intent, or
expected requirement, to sell the debt security. In addition, this guidance
expands the already required annual disclosures about other-than-temporary
impairment for debt and equity securities, requires companies to include these
expanded disclosures in interim financial statements and addresses whether an
other-than-temporary impairment should be recognized in earnings, other
comprehensive income or some combination thereof. The Company adopted this
guidance on April 1, 2009. The adoption did not have a material impact on
the Company’s consolidated financial results and disclosures included within
Notes to Consolidated Financial Statements.
In
April 2009, the FASB issued authoritative guidance (included in ASC
Topic 820) that clarifies the determination of fair value when a market is
not active and if a transaction is not orderly. In addition, this guidance
amends previous GAAP to require disclosures in interim and annual
periods of the inputs and valuation techniques used to measure fair value
and a discussion of changes in valuation techniques and related inputs, if any,
during the period and defines “major categories” consistent with those described
in previously existing GAAP. The Company adopted this guidance on April 1,
2009. The adoption did not have a material impact on the Company’s consolidated
financial results and disclosures included within Notes to Consolidated
Financial Statements.
In
December 2008, the FASB issued authoritative guidance (included in ASC
Topic 715, “Compensation – Retirement Benefits”) that requires enhanced
disclosures about plan assets of defined benefit pension and other
postretirement benefit plans to enable investors to better understand how
investment allocation decisions are made and the major categories of plan
assets. In addition, this guidance requires disclosure of the inputs and
valuation techniques used to measure fair value and the effect of fair value
measurements using significant unobservable inputs on changes in plan assets and
establishes disclosure requirements for significant concentrations of risk
within plan assets. This guidance is effective for fiscal years ending after
December 15, 2009, with early application permitted. The Company is
currently evaluating the impact of adopting this guidance on its disclosures
included within Notes to Consolidated Financial Statements.
In March
2008, the FASB issued authoritative guidance (included in ASC Topic 815,
“Derivatives and Hedging”) that requires enhanced disclosures about derivative
instruments and hedging activities to enable investors to better understand how
and why an entity uses derivative instruments and their effects on an entity’s
financial results. The Company adopted this guidance on January 1, 2009 and
included the required disclosures within Notes to Consolidated Financial
Statements.
In
December 2007, the FASB issued authoritative guidance (included in ASC
Topic 810, “Consolidation”) that establishes accounting and reporting
standards for the noncontrolling interest in a subsidiary and for the
deconsolidation of a subsidiary. The Company adopted this guidance on
January 1, 2009. As a result, the Company has presented noncontrolling
interests as a separate component of equity on the Consolidated Balance Sheets.
Previously, these amounts were reported as minority interest and preferred
securities of subsidiaries within the mezzanine section on the Consolidated
Balance Sheets. Also, the Company has presented net income attributable to
noncontrolling interests separately on the Consolidated Statements of
Operations. Previously, these amounts were reported as minority interest and
preferred dividends of subsidiaries on the Consolidated Statements of
Operations.
11
(3)
|
Property,
Plant and Equipment, Net
|
Property,
plant and equipment, net consist of the following (in millions):
As
of
|
|||||||||
Depreciable
|
September 30,
|
December 31,
|
|||||||
Life
|
2009
|
2008
|
|||||||
Regulated
assets:
|
|||||||||
Utility
generation, distribution and transmission system
|
5-85
years
|
$ | 35,084 | $ | 32,795 | ||||
Interstate
pipeline assets
|
3-67
years
|
5,710 | 5,649 | ||||||
40,794 | 38,444 | ||||||||
Accumulated
depreciation and amortization
|
(13,155 | ) | (12,456 | ) | |||||
Regulated
assets, net
|
27,639 | 25,988 | |||||||
Non-regulated
assets:
|
|||||||||
Independent
power plants
|
10-30
years
|
677 | 681 | ||||||
Other
assets
|
3-30
years
|
607 | 547 | ||||||
1,284 | 1,228 | ||||||||
Accumulated
depreciation and amortization
|
(494 | ) | (430 | ) | |||||
Non-regulated
assets, net
|
790 | 798 | |||||||
Net
operating assets
|
28,429 | 26,786 | |||||||
Construction
in progress
|
2,003 | 1,668 | |||||||
Property,
plant and equipment, net
|
$ | 30,432 | $ | 28,454 |
Substantially
all of the construction in progress as of September 30, 2009 and
December 31, 2008 relates to the construction of regulated
assets.
(4)
|
Regulatory
Matters
|
The
following are updates to regulatory matters based upon material changes that
occurred subsequent to December 31, 2008.
Rate
Matters
Kern
River Rate Case
In
March 2006, Kern River received an initial decision from the presiding
administrative law judge in Kern River’s 2004 general rate case filed in
April 2004. In October 2006, the Federal Energy Regulatory Commission
(“FERC”) issued an order that modified certain aspects of the administrative law
judge’s initial decision, including changing the allowed return on equity from
9.34% to 11.2% and granting Kern River an income tax allowance. In
April 2008, the FERC issued an order, consistent with its policy statement,
granting Kern River’s request for rehearing to include master limited
partnerships in the proxy group for determining the allowed rate of return on
equity.
In
September 2008, Kern River filed an Offer of Settlement and Stipulation
(“Settlement”) that was supported or not opposed by a majority of the long-term
shippers on Kern River’s system. In January 2009, the FERC issued an order
rejecting the Settlement. The FERC found the Settlement would result in unjust
and unreasonable rates and ordered Kern River to file compliance rates based on
an allowed return on equity of 11.55%. Certain shippers filed timely requests
for rehearing of the January 2009 order. Pursuant to the January 2009
order, Kern River made the compliance filing in March 2009, which was
revised in September 2009. Comments and protests on Kern River’s March 2009
and September 2009 compliance filings have been submitted and a decision from
the FERC is expected in late 2009 or early 2010.
12
Oregon
Senate Bill 408 (“SB 408”)
SB 408 requires PacifiCorp and
other large regulated, investor-owned utilities that provide electric or natural
gas service to Oregon customers to file an annual report each October with the
Oregon Public Utility Commission (the “OPUC”) comparing income taxes collected
and income taxes paid, as defined by the statute and its administrative rules.
PacifiCorp’s amended filing for the 2006 tax year indicated that PacifiCorp paid
$35 million more in income taxes than was collected in rates from its
retail customers. In April 2008, the OPUC approved the recovery of
$27 million of this deficiency over a one-year period beginning
June 1, 2008 with the remainder deferred until a later period, with
interest to accrue at PacifiCorp’s authorized rate of return. In
April 2009, the OPUC approved recovery of the remaining balance, including
interest, and also approved recovery of the under collected income tax balance,
including interest, associated with PacifiCorp’s 2007 tax report. In
April 2009, PacifiCorp recorded a $20 million regulatory asset
representing the balance to be collected from its Oregon retail customers for
its 2006 and 2007 tax reports. The amounts are being collected over a one-year
period beginning June1,
2009.
The
OPUC’s April 2008 order on PacifiCorp’s 2006 tax report is being challenged
by the Industrial Customers of Northwest Utilities (“ICNU”), which filed a
petition in May 2008 with the Court of Appeals of the State of Oregon (the “Court of Appeals”)
seeking judicial review of the April 2008 order. In March 2009, a
notice of withdrawal of the April 2008 order was filed with the Court of
Appeals by the OPUC. In May 2009, the OPUC issued an order on reconsideration,
which supplemented and affirmed its April 2008 order. In June 2009, ICNU
continued its challenge of the April 2008 order by filing an amended
petition for judicial review with the Court of Appeals to include the
May 2009 order. PacifiCorp believes the outcome of these proceedings will
not have a material impact on its consolidated financial results.
In
October 2009, PacifiCorp filed its tax report for 2008 under SB 408.
PacifiCorp’s filing for the 2008 tax year indicated that PacifiCorp paid
$38 million more in income taxes than was collected in rates from its
retail customers. PacifiCorp has not recorded a regulatory asset related to the
2008 tax report.
(5)
|
Fair
Value Measurements
|
The
carrying amounts of the Company’s cash, certain cash equivalents, receivables,
payables, accrued liabilities and short-term borrowings approximate fair value
because of the short-term maturity of these instruments. The Company has various
financial assets and liabilities that are measured at fair value in the
Consolidated Financial Statements using inputs from the three levels of the fair
value hierarchy. A financial asset or liability classification within the
hierarchy is determined based on the lowest level input that is significant to
the fair value measurement. The three levels are as follows:
|
·
|
Level
1 – Inputs are unadjusted quoted prices in active markets for identical
assets or liabilities that the Company has the ability to access at the
measurement date.
|
|
·
|
Level
2 – Inputs include quoted prices for similar assets or liabilities in
active markets, quoted prices for identical or similar assets or
liabilities in markets that are not active, inputs other than quoted
prices that are observable for the asset or liability and inputs that are
derived principally from or corroborated by observable market data by
correlation or other means (market corroborated
inputs).
|
|
·
|
Level
3 – Unobservable inputs reflect the Company’s judgments about the
assumptions market participants would use in pricing the asset or
liability since limited market data exists. The Company develops these
inputs based on the best information available, including its own
data.
|
13
The
following table presents the Company’s assets and liabilities recognized in the
Consolidated Balance Sheet and measured at fair value on a recurring basis as of
September 30, 2009 (in millions):
Input
Levels for Fair Value Measurements
|
||||||||||||||||||||
Description
|
Level
1
|
Level
2
|
Level
3
|
Other(1)
|
Total
|
|||||||||||||||
Assets(2):
|
||||||||||||||||||||
Commodity
derivatives
|
$ | 7 | $ | 440 | $ | 36 | $ | (284 | ) | $ | 199 | |||||||||
Investments
in available-for-sale securities:
|
||||||||||||||||||||
Money
market mutual funds(3)
|
603 | - | - | - | 603 | |||||||||||||||
Debt
securities
|
68 | 81 | 40 | - | 189 | |||||||||||||||
Equity
securities
|
2,084 | 8 | - | - | 2,092 | |||||||||||||||
$ | 2,762 | $ | 529 | $ | 76 | $ | (284 | ) | $ | 3,083 | ||||||||||
Liabilities:
|
||||||||||||||||||||
Commodity
derivatives
|
$ | (7 | ) | $ | (456 | ) | $ | (369 | ) | $ | 303 | $ | (529 | ) | ||||||
Interest
rate derivative
|
- | (4 | ) | - | - | (4 | ) | |||||||||||||
$ | (7 | ) | $ | (460 | ) | $ | (369 | ) | $ | 303 | $ | (533 | ) |
(1)
|
Primarily
represents a net cash collateral receivable of $19 million and
netting under master netting arrangements.
|
(2)
|
Does
not include investments in either pension or other postretirement benefit
plan assets.
|
(3)
|
Amounts
are included in cash and cash equivalents, other current assets and
investments and other assets on the Consolidated Balance Sheet. The fair
value of these money market mutual funds approximates
cost.
|
The
following table presents the Company’s assets and liabilities recognized in the
Consolidated Balance Sheet and measured at fair value on a recurring basis as of
December 31, 2008 (in millions):
Input
Levels for Fair Value Measurements
|
||||||||||||||||||||
Description
|
Level
1
|
Level
2
|
Level
3
|
Other(1)
|
Total
|
|||||||||||||||
Assets(2):
|
||||||||||||||||||||
Commodity
derivatives
|
$ | 2 | $ | 549 | $ | 136 | $ | (363 | ) | $ | 324 | |||||||||
Investments
in available-for-sale securities:
|
||||||||||||||||||||
Money
market mutual funds(3)
|
202 | - | - | - | 202 | |||||||||||||||
Debt
securities
|
45 | 117 | 37 | - | 199 | |||||||||||||||
Equity
securities
|
171 | 6 | - | - | 177 | |||||||||||||||
Investments
in trading securities - Equity
|
499 | - | - | - | 499 | |||||||||||||||
$ | 919 | $ | 672 | $ | 173 | $ | (363 | ) | $ | 1,401 | ||||||||||
Liabilities:
|
||||||||||||||||||||
Commodity
derivatives
|
$ | (55 | ) | $ | (632 | ) | $ | (505 | ) | $ | 469 | $ | (723 | ) | ||||||
Interest
rate derivative
|
- | (6 | ) | - | - | (6 | ) | |||||||||||||
$ | (55 | ) | $ | (638 | ) | $ | (505 | ) | $ | 469 | $ | (729 | ) |
(1)
|
Primarily
represents a net cash collateral receivable of $129 million and
netting under master netting arrangements.
|
(2)
|
Does
not include investments in either pension or other postretirement benefit
plan assets.
|
(3)
|
Amounts
are included in cash and cash equivalents, other current assets and
investments and other assets on the Consolidated Balance Sheet. The fair
value of these money market mutual funds approximates
cost.
|
14
When
available, the fair value of derivative contracts is determined using unadjusted
quoted prices for identical contracts on the applicable exchange in which the
Company transacts. When quoted prices for identical contracts are not available,
the Company uses forward price curves derived from market price quotations, when
available, or internally developed and commercial models, with internal and
external fundamental data inputs. Market price quotations are obtained from
independent energy brokers, exchanges, direct communication with market
participants and actual transactions executed by the Company. Market price
quotations for certain major electricity and natural gas trading hubs are
generally readily obtainable for the first six years; therefore, the Company’s
forward price curves for those locations and periods reflect observable market
quotes. Market price quotations for other electricity and natural gas trading
hubs are not as readily obtainable for the first six years. Given that limited
market data exists for these contracts, as well as for those contracts that are
not actively traded, the Company uses forward price curves derived from internal
models based on perceived pricing relationships to major trading hubs that are
based on significant unobservable inputs. Refer to Note 6 for further discussion
regarding the Company’s risk management and hedging activities.
The
Company’s investments in money market mutual funds and debt and equity
securities are accounted for as either available-for-sale or trading securities
and are stated at fair value. When available, a readily observable quoted market
price or net asset value of an identical security in an active market is used to
record the fair value. In the absence of a quoted market price or net asset
value of an identical security, the fair value is determined using pricing
models or net asset values based on observable market inputs and quoted market
prices of securities with similar characteristics. The fair value of the
Company’s investments in auction rate securities, where there is no current
liquid market, is determined using pricing models based on available observable
market data and the Company’s judgment about the assumptions, including
liquidity and nonperformance risks, which market participants would use when
pricing the asset.
The
following table reconciles the beginning and ending balances of the Company’s
assets and liabilities measured at fair value on a recurring basis using
significant Level 3 inputs for the three-month periods ended
September 30 (in millions):
2009
|
2008
|
|||||||||||||||
Commodity
|
Debt
|
Commodity
|
Debt
|
|||||||||||||
Derivatives
|
Securities
|
Derivatives
|
Securities
|
|||||||||||||
Beginning
balance
|
$ | (360 | ) | $ | 38 | $ | (232 | ) | $ | 61 | ||||||
Changes
included in earnings(1)
|
(3 | ) | - | 38 | - | |||||||||||
Changes
in fair value recognized in other comprehensive income
|
(1 | ) | 2 | - | (6 | ) | ||||||||||
Changes
in fair value recognized in net regulatory assets
|
(2 | ) | - | (200 | ) | - | ||||||||||
Purchases,
sales, issuances and settlements
|
33 | - | 48 | - | ||||||||||||
Ending
balance
|
$ | (333 | ) | $ | 40 | $ | (346 | ) | $ | 55 |
(1)
|
Changes
included in earnings are reported as operating revenue in the Consolidated
Statements of Operations. Net unrealized gains (losses) included in
earnings for the three-month periods ended September 30, 2009 and
2008, related to commodity derivatives held at September 30, 2009 and
2008, totaled $(3) million and $32 million,
respectively.
|
15
The
following table reconciles the beginning and ending balances of the Company’s
assets and liabilities measured at fair value on a recurring basis using
significant Level 3 inputs for the nine-month periods ended
September 30 (in millions):
2009
|
2008
|
|||||||||||||||
Commodity
|
Debt
|
Commodity
|
Debt
|
|||||||||||||
Derivatives
|
Securities
|
Derivatives
|
Securities
|
|||||||||||||
Beginning
balance
|
$ | (369 | ) | $ | 37 | $ | (311 | ) | $ | 73 | ||||||
Changes
included in earnings(1)
|
16 | - | 16 | - | ||||||||||||
Changes
in fair value recognized in other comprehensive income
|
- | 3 | 1 | (18 | ) | |||||||||||
Changes
in fair value recognized in net regulatory assets
|
32 | - | (66 | ) | - | |||||||||||
Purchases,
sales, issuances and settlements
|
11 | - | 14 | - | ||||||||||||
Net
transfers into or out of Level 3
|
(23 | ) | - | - | - | |||||||||||
Ending
balance
|
$ | (333 | ) | $ | 40 | $ | (346 | ) | $ | 55 |
(1)
|
Changes
included in earnings are reported as operating revenue in the Consolidated
Statements of Operations. Net unrealized gains (losses) included in
earnings for the nine-month periods ended September 30, 2009 and
2008, related to commodity derivatives held at September 30, 2009 and
2008, totaled $12 million and $11 million,
respectively.
|
The
Company’s long-term debt is carried at cost in the Consolidated Financial
Statements. The fair value of the Company’s long-term debt has been estimated
based upon quoted market prices, where available, or at the present value of
future cash flows discounted at rates consistent with comparable maturities with
similar credit risks. The carrying amount of the Company’s variable-rate
long-term debt approximates fair value because of the frequent repricing of
these instruments at market rates. The following table presents the carrying
amount and estimated fair value of the Company’s long-term debt (in
millions):
As
of September 30, 2009
|
As
of December 31, 2008
|
|||||||||||||||
Carrying
|
Carrying
|
|||||||||||||||
Amount
|
Fair
Value
|
Amount
|
Fair
Value
|
|||||||||||||
Long-term
debt
|
$ | 19,865 | $ | 21,660 | $ | 19,396 | $ | 19,396 |
(6)
|
Risk
Management and Hedging Activities
|
The
Company is exposed to the impact of market fluctuations in commodity prices,
interest rates and foreign currency exchange rates. The Company is principally
exposed to electricity and natural gas commodity price risk through MEHC’s
ownership of PacifiCorp and MidAmerican Energy (the “Utilities”) as the
Utilities have an obligation to serve retail customer load in their regulated
service territories. MidAmerican Energy also provides nonregulated retail
natural gas and electricity services in competitive markets. The Utilities’ load
and generation assets represent substantial underlying commodity positions.
Exposures to commodity prices consist mainly of variations in the price of fuel
to generate electricity, wholesale electricity that is purchased and sold and
natural gas supply for regulated and nonregulated retail customers. Electricity
and natural gas prices are subject to wide price swings as supply and demand for
these commodities are impacted by, among many other unpredictable items,
changing weather, market liquidity, generation plant availability, customer
usage, storage, and transmission and transportation constraints. Interest rate
risk exists on variable-rate debt, commercial paper and future debt issuances.
Additionally, the Company is exposed to foreign currency exchange rate risk from
its business operations and investments in Great Britain. The Company does not
engage in a material amount of proprietary trading activities.
Each of
the Company’s business platforms has established a risk management process that
is designed to identify, assess, monitor, report, manage and mitigate each of
the various types of risk involved in its business. To mitigate a portion of its
commodity risk, the Company uses commodity derivative contracts, including
forward contracts, futures, options, fixed price and basis swaps and other
agreements, to effectively secure future supply or sell future production
generally at fixed prices. The Company manages its interest rate risk by
limiting its exposure to variable interest rates and by monitoring market
changes in interest rates. The Company may from time to time enter into interest
rate derivative contracts, such as interest rate swaps or locks, to effectively
modify the Company’s exposure to interest rate risk. The Company does not hedge
all of its commodity price and interest rate risks, thereby exposing the
unhedged portion to the risks and benefits of spot-market price
movements.
16
There
have been no significant changes in the Company’s significant accounting
policies related to derivatives. Refer to Notes 2 and 5 for additional
information on derivative contracts.
The
following table, which excludes contracts that qualify for the normal purchases
or normal sales exemption afforded by GAAP, summarizes the fair value of the
Company’s derivative contracts, on a gross basis, and reconciles those amounts
to the amounts presented on a net basis on the Consolidated Balance Sheet as of
September 30, 2009 (in millions):
Balance
Sheet Locations
|
||||||||||||||||||||
Derivative
Assets
|
Derivative
Liabilities
|
|||||||||||||||||||
Current
|
Noncurrent
|
Current
|
Noncurrent
|
Total
|
||||||||||||||||
Not
Designated as Hedging Contracts(1)(2):
|
||||||||||||||||||||
Commodity
assets
|
$ | 334 | $ | 105 | $ | 23 | $ | 3 | $ | 465 | ||||||||||
Commodity
liabilities
|
(91 | ) | (39 | ) | (187 | ) | (386 | ) | (703 | ) | ||||||||||
Total
|
243 | 66 | (164 | ) | (383 | ) | (238 | ) | ||||||||||||
Designated
as Hedging Contracts(1):
|
||||||||||||||||||||
Commodity
assets
|
4 | - | 13 | 1 | 18 | |||||||||||||||
Commodity
liabilities
|
(5 | ) | - | (76 | ) | (48 | ) | (129 | ) | |||||||||||
Interest
rate liability
|
- | - | - | (4 | ) | (4 | ) | |||||||||||||
Total
|
(1 | ) | - | (63 | ) | (51 | ) | (115 | ) | |||||||||||
Total
derivatives
|
242 | 66 | (227 | ) | (434 | ) | (353 | ) | ||||||||||||
Cash
collateral receivable (payable)
|
(101 | ) | (8 | ) | 95 | 33 | 19 | |||||||||||||
Total
derivatives - net basis
|
$ | 141 | $ | 58 | $ | (132 | ) | $ | (401 | ) | $ | (334 | ) |
(1)
|
Derivative
contracts within these categories are subject to master netting
arrangements and are presented on a net basis in the Consolidated Balance
Sheet.
|
(2)
|
The
majority of the Company’s commodity derivatives not designated as hedging
contracts are recoverable from customers in regulated rates and as of
September 30, 2009, a net regulatory asset of $245 million was
recorded related to the net derivative liabilities of
$238 million.
|
Not
Designated as Hedging Contracts
For the
Company’s commodity derivatives not designated as hedging contracts, the settled
amount is generally recovered from customers in regulated rates. Accordingly,
the net unrealized gains and losses associated with interim price movements on
contracts that are accounted for as derivatives and probable of recovery in
rates are recorded as net regulatory assets. The following table reconciles the
beginning and ending balances of the Company’s net regulatory assets and
summarizes the pre-tax gains and losses on commodity derivative contracts
recognized in net regulatory assets, as well as amounts reclassified to earnings
(in millions):
Three-Month
|
Nine-Month
|
|||||||
Period
Ended
|
Period
Ended
|
|||||||
September 30,
2009
|
September 30,
2009
|
|||||||
Beginning
balance
|
$ | 247 | $ | 446 | ||||
Changes
in fair value recognized in net regulatory assets
|
15 | (182 | ) | |||||
Gains
reclassified to earnings - operating revenue
|
74 | 243 | ||||||
Losses
reclassified to earnings - cost of sales
|
(91 | ) | (262 | ) | ||||
Ending
balance
|
$ | 245 | $ | 245 |
17
For the
Company’s commodity derivatives not designated as hedging contracts and for
which changes in fair value are not recorded as a net regulatory asset or
liability, unrealized gains and losses are recognized on the Consolidated
Statements of Operations as operating revenue for sales contracts and as cost of
sales and operating expense for purchase contracts and electricity and natural
gas swap contracts. The following table summarizes the pre-tax gains (losses)
included within the Consolidated Statements of Operations associated with the
Company’s derivative contracts not designated as hedging contracts and not
recorded as a net regulatory asset or liability (in millions):
Three-Month
|
Nine-Month
|
|||||||
Period
Ended
|
Period
Ended
|
|||||||
September 30,
2009
|
September 30,
2009
|
|||||||
Commodity
derivatives:
|
||||||||
Operating
revenue
|
$ | (2 | ) | $ | 22 | |||
Cost
of sales
|
6 | (5 | ) | |||||
Operating
expense
|
(1 | ) | - | |||||
Total
|
$ | 3 | $ | 17 |
Designated
as Hedging Contracts
The
Company uses derivative contracts accounted for as cash flow hedges to hedge
electricity and natural gas commodity prices for delivery to nonregulated
customers, spring operational sales, natural gas storage and other transactions.
The Company’s derivative contracts designated as fair value hedges were not
significant as of September 30, 2009.
The
following table reconciles the beginning and ending balances of the Company’s
accumulated other comprehensive loss (pre-tax) and summarizes pre-tax gains and
losses on derivative contracts designated and qualifying as cash flow hedges
recognized in other comprehensive income (“OCI”), as well as amounts
reclassified to earnings during the three-month period ended September 30,
2009 (in millions):
Commodity
|
Interest Rate
|
|||||||||||
Derivatives
|
Derivative
|
Total(1)
|
||||||||||
Beginning
balance
|
$ | 104 | $ | 4 | $ | 108 | ||||||
Losses
recognized in OCI
|
34 | - | 34 | |||||||||
Losses
reclassified to earnings – revenue
|
(1 | ) | - | (1 | ) | |||||||
Losses
reclassified to earnings - cost of sales
|
(30 | ) | - | (30 | ) | |||||||
Ending
balance
|
$ | 107 | $ | 4 | $ | 111 |
(1)
|
Certain
derivative contracts, principally interest rate locks, have settled and
the fair value at the date of settlement remains in accumulated other
comprehensive income (loss) and is amortized to earnings over the
remaining life of the respective long-term
debt.
|
The
following table reconciles the beginning and ending balances of the Company’s
accumulated other comprehensive loss (pre-tax) and summarizes pre-tax gains and
losses on derivative contracts designated and qualifying as cash flow hedges
recognized in OCI, as well as amounts reclassified to earnings during the
nine-month period ended September 30, 2009 (in millions):
Commodity
|
Interest Rate
|
|||||||||||
Derivatives
|
Derivative
|
Total(1)
|
||||||||||
Beginning
balance
|
$ | 83 | $ | 6 | $ | 89 | ||||||
Losses
(gains) recognized in OCI
|
109 | (2 | ) | 107 | ||||||||
Losses
reclassified to earnings – revenue
|
(2 | ) | - | (2 | ) | |||||||
Losses
reclassified to earnings - cost of sales
|
(83 | ) | - | (83 | ) | |||||||
Ending
balance
|
$ | 107 | $ | 4 | $ | 111 |
(1)
|
Certain
derivative contracts, principally interest rate locks, have settled and
the fair value at the date of settlement remains in accumulated other
comprehensive income (loss) and is amortized to earnings over the
remaining life of the respective long-term
debt.
|
18
Realized
gains and losses on all hedges and hedge ineffectiveness are recognized in
income as operating revenue or cost of sales and operating expense depending
upon the nature of the item being hedged. For the three- and nine-month periods
ended September 30, 2009 and 2008, hedge ineffectiveness was insignificant.
As of September 30, 2009, the Company had cash flow hedges with expiration
dates extending through December 2022 and $51 million of pre-tax net
unrealized losses are forecasted to be reclassified from accumulated other
comprehensive loss into earnings over the next twelve months as contracts
settle.
Derivative Contract
Volumes
The
following table summarizes the net notional amounts of outstanding derivative
contracts with fixed price terms that comprise the mark-to-market
values (in millions):
Unit
of
|
As
of
|
||||
Measure
|
September 30, 2009
|
||||
Commodity
contracts:
|
|||||
Electricity
sales
|
Megawatt
hours
|
(20 | ) | ||
Natural
gas purchases
|
Decatherms
|
262 | |||
Fuel
purchases
|
Gallons
|
4 | |||
Interest
rate derivative – variable to fixed swap
|
Australian
dollars
|
59 |
Credit
Risk
PacifiCorp
and MidAmerican Energy extend unsecured credit to other utilities, energy
marketers, financial institutions and other market participants in conjunction
with wholesale energy supply and marketing activities. Credit risk relates to
the risk of loss that might occur as a result of nonperformance by
counterparties on their contractual obligations to make or take delivery of
electricity, natural gas or other commodities and to make financial settlements
of these obligations. Credit risk may be concentrated to the extent that one or
more groups of counterparties have similar economic, industry or other
characteristics that would cause their ability to meet contractual obligations
to be similarly affected by changes in market or other conditions. In addition,
credit risk includes not only the risk that a counterparty may default due to
circumstances relating directly to it, but also the risk that a counterparty may
default due to circumstances involving other market participants that have a
direct or indirect relationship with the counterparty.
PacifiCorp
and MidAmerican Energy analyze the financial condition of each significant
wholesale counterparty before entering into any transactions, establish limits
on the amount of unsecured credit to be extended to each counterparty and
evaluate the appropriateness of unsecured credit limits on an ongoing basis. To
mitigate exposure to the financial risks of wholesale counterparties, PacifiCorp
and MidAmerican Energy enter into netting and collateral arrangements that may
include margining and cross-product netting agreements and obtaining third-party
guarantees, letters of credit and cash deposits. Counterparties may be assessed
interest fees for delayed payments. If required, PacifiCorp and MidAmerican
Energy exercise rights under these arrangements, including calling on the
counterparty’s credit support arrangement. Based on the Company’s policies and
risk exposures related to credit, it does not anticipate a material adverse
effect on its consolidated financial results as a result of counterparty
nonperformance.
Collateral
and Contingent Features
In
accordance with industry practice, certain derivative contracts contain
provisions that require MEHC’s subsidiaries, principally PacifiCorp and
MidAmerican Energy, to maintain specific credit ratings from one or more of the
major credit rating agencies on their unsecured debt. These derivative contracts
may either specifically provide bilateral rights to demand cash or other
security if credit exposures on a net basis exceed specified rating-dependent
threshold levels (“credit-risk-related contingent features”) or provide the
right for counterparties to demand “adequate assurance” in the event of a
material adverse change in the subsidiary’s creditworthiness. These rights can
vary by contract and by counterparty. As of September 30, 2009, these
subsidiary’s credit ratings from the three recognized credit rating agencies
were investment grade.
The
aggregate fair value of the Company’s derivative contracts in liability
positions with specific credit-risk-related contingent features totaled
$544 million as of September 30, 2009, for which the Company had
posted collateral of $128 million. If all credit-risk-related contingent
features for derivative contracts in liability positions had been triggered as
of September 30, 2009, the Company would have been required to post
$230 million of additional collateral. The Company’s collateral
requirements could fluctuate considerably due to market price volatility,
changes in credit ratings or other factors.
19
(7)
|
Investments
|
In
January 2009, the Company received $1 billion, plus accrued interest,
in full satisfaction of the 14% Senior Notes from Constellation Energy Group,
Inc. (“Constellation Energy”). During the first six
months of 2009, the Company sold 19.9 million shares of Constellation
Energy common stock for $536 million, or an average price of
$26.93 per share, and recognized gains totaling $37 million, which are
included in other, net on the Consolidated Statements of
Operations.
In
September 2008, MEHC reached a definitive agreement with BYD Company
Limited (“BYD”) to purchase 225 million shares, representing approximately
a 10% interest in BYD, at a price of Hong Kong (“HK”) $8 per share or
HK$1.8 billion (approximately $232 million). Established in 1995, BYD
is a Hong Kong listed company with two main businesses: technology, including
rechargeable batteries, chargers and cell phone design and assembly, and
automobiles. BYD has seven production bases in Guangdong, Beijing, Shanghai and Xi’an and has offices
in the United States, Europe, Japan, South Korea, India, Taiwan, Hong Kong and
other regions. BYD has over 130,000 employees. The purchase was approved by an
affirmative vote of the holders of two-thirds of the outstanding shares of BYD
at an extraordinary general meeting held on December 3, 2008. The
investment was made on July 30, 2009. MEHC’s investment in BYD is accounted
for as an available-for-sale security with changes in fair value recognized in
accumulated other comprehensive income. The fair value of $1.854 billion as
of September 30, 2009 compared to the acquisition cost of
$232 million resulted in a pre-tax unrealized gain of $1.622 billion
as of September 30, 2009.
(8)
|
Recent
Debt Transactions
|
In
July 2009, MEHC issued $250 million of its 3.15% Senior Notes due
July 15, 2012. The net proceeds are being
used for general corporate purposes.
In
January 2009, PacifiCorp issued $350 million of its 5.5% First
Mortgage Bonds due January 15, 2019 and $650 million of its 6.0% First
Mortgage Bonds due January 15, 2039. The net proceeds were used to repay
short-term debt and are being used to fund capital expenditures and for
general corporate purposes.
(9)
|
Related
Party Transactions
|
As of
September 30, 2009 and December 31, 2008, Berkshire Hathaway and its
affiliates held 11% mandatory redeemable preferred securities due from certain
wholly-owned subsidiary trusts of MEHC of $420 million and
$1.09 billion, respectively. Interest expense on these securities totaled
$13 million and $22 million for the three-month periods ended
September 30, 2009 and 2008, respectively, and $47 million and
$67 million for the nine-month periods ended September 30, 2009 and
2008, respectively. Accrued interest totaled $9 million and
$27 million as of September 30, 2009 and December 31, 2008,
respectively. In January 2009, MEHC repaid the remaining $500 million
to affiliates of Berkshire Hathaway in full satisfaction of the aggregate amount
owed pursuant to the $1 billion of 11% mandatory redeemable trust preferred
securities issued by MidAmerican Capital Trust IV to affiliates of
Berkshire Hathaway in September 2008.
For the
nine-month periods ended September 30, 2009 and 2008, the Company received
net cash payments for income taxes from Berkshire Hathaway totaling
$178 million and $171 million, respectively.
20
(10)
|
Employee
Benefit Plans
|
Domestic
Operations
Combined
net periodic benefit cost for domestic pension and other postretirement benefit
plans included the following components (in millions):
Three-Month
Periods
|
Nine-Month
Periods
|
|||||||||||||||
Ended
September 30,
|
Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Pension:
|
||||||||||||||||
Service
cost
|
$ | 9 | $ | 12 | $ | 26 | $ | 39 | ||||||||
Interest
cost
|
29 | 28 | 85 | 81 | ||||||||||||
Expected
return on plan assets
|
(29 | ) | (29 | ) | (85 | ) | (87 | ) | ||||||||
Net
amortization
|
1 | 2 | 1 | 6 | ||||||||||||
Net
periodic benefit cost
|
$ | 10 | $ | 13 | $ | 27 | $ | 39 |
Other
Postretirement:
|
||||||||||||||||
Service
cost
|
$ | 2 | $ | 3 | $ | 6 | $ | 9 | ||||||||
Interest
cost
|
12 | 11 | 33 | 35 | ||||||||||||
Expected
return on plan assets
|
(11 | ) | (10 | ) | (30 | ) | (32 | ) | ||||||||
Net
amortization
|
3 | 3 | 9 | 12 | ||||||||||||
Net
periodic benefit cost
|
$ | 6 | $ | 7 | $ | 18 | $ | 24 |
Employer
contributions to domestic pension and other postretirement benefit plans are
expected to be $62 million and $33 million, respectively, during 2009.
As of September 30, 2009, $58 million and $25 million of
contributions had been made to domestic pension and other postretirement benefit
plans, respectively.
United
Kingdom Operations
Net
periodic benefit cost for the UK pension plan included the following
components (in millions):
Three-Month
Periods
|
Nine-Month
Periods
|
|||||||||||||||
Ended
September 30,
|
Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Service
cost
|
$ | 3 | $ | 5 | $ | 9 | $ | 16 | ||||||||
Interest
cost
|
22 | 25 | 62 | 77 | ||||||||||||
Expected
return on plan assets
|
(27 | ) | (30 | ) | (77 | ) | (93 | ) | ||||||||
Net
amortization
|
4 | 6 | 11 | 16 | ||||||||||||
Net
periodic benefit cost
|
$ | 2 | $ | 6 | $ | 5 | $ | 16 |
Employer
contributions to the UK pension plan are expected to be £44 million during
2009. As of September 30, 2009, £33 million, or $51 million, of
contributions had been made to the UK pension plan.
21
(11)
|
Income
Taxes
|
Income
tax expense decreased $110 million for the third quarter and
$167 million for the first nine months of 2009 compared to 2008. The
effective tax rates were 10% and 31% for the third quarter of 2009 and 2008,
respectively, and 20% and 30% for the first nine months of 2009 and 2008,
respectively. The decrease in income tax expense was mainly due to
$55 million of income tax benefits recognized in the third quarter of 2009
for the repairs deductions discussed below, lower pre-tax income, favorable
settlement of certain tax contingencies and additional production tax credits.
Additionally, noncurrent net deferred tax liabilities were $5.42 billion as
of September 30, 2009 and $3.949 billion as of December 31, 2008.
The higher noncurrent net deferred tax liabilities were due to unrealized gains
on the BYD investment, increased tax depreciation related to the addition of
wind-powered generating facilities placed in-service during 2008 and 2009, bonus
depreciation taken on 2009 qualified capital expenditures, and the repairs
deduction discussed below.
PacifiCorp
and MidAmerican Energy changed the method by which they determine current income
tax deductions for repairs on certain of their regulated utility assets (the
“repairs deduction”), which results in current deductibility for certain costs
that are capitalized for book purposes. The repairs deduction was computed for
tax years 1998 and forward and was deducted on the 2008 income tax returns.
Iowa, MidAmerican Funding’s largest jurisdiction for rate regulated operations,
requires immediate income recognition of such temporary differences. For the
three- and nine-month periods ended September 30, 2009, the Company’s earnings
reflect $55 million of net tax benefits recognized from these
deductions.
(12)
|
Commitments
and Contingencies
|
Legal
Matters
The
Company is party to a variety of legal actions arising out of the normal course
of business. Plaintiffs occasionally seek punitive or exemplary damages. The
Company does not believe that such normal and routine litigation will have a
material effect on its consolidated financial results. The Company is also
involved in other kinds of legal actions, some of which assert or may assert
claims or seek to impose fines and penalties in substantial amounts and are
described below.
PacifiCorp
In
February 2007, the Sierra Club and the Wyoming Outdoor Council filed a
complaint against PacifiCorp in the federal district court in Cheyenne, Wyoming,
alleging violations of the Wyoming state opacity standards at PacifiCorp’s Jim
Bridger plant in Wyoming. Under Wyoming state requirements, which
are part of the Jim Bridger plant’s Title V permit and are enforceable by
private citizens under the federal Clean Air Act, a potential source of
pollutants such as a coal-fired generating facility must meet minimum standards
for opacity, which is a measurement of light that is obscured in the flue of a
generating facility. The complaint alleges thousands of violations of asserted
six-minute compliance periods and seeks an injunction ordering the Jim Bridger
plant’s compliance with opacity limits, civil penalties of $32,500 per day per
violation and the plaintiffs’ costs of litigation. The court granted a motion to
bifurcate the trial into separate liability and remedy phases. In August 2009,
the court ruled on a number of summary judgment motions by which it
determined that the plaintiffs have sufficient legal standing to proceed with
their complaint and that all other issues raised in the summary judgment motions
will be resolved at trial. The court also set a scheduling conference for
December 2009. PacifiCorp believes it has a number of defenses to the claims.
PacifiCorp intends to vigorously oppose the lawsuit but cannot predict its
outcome at this time. PacifiCorp has already committed to invest at least
$812 million in pollution control equipment at its generating facilities,
including the Jim Bridger plant. This commitment is expected to significantly
reduce system-wide emissions, including emissions at the Jim Bridger
plant.
22
CalEnergy
Generation-Foreign
In
February 2002, pursuant to the share ownership adjustment mechanism in the
CE Casecnan shareholder agreement, MEHC’s indirect wholly owned subsidiary,
CE Casecnan Ltd., advised the minority shareholder of
CE Casecnan, LaPrairie Group Contractors (International) Ltd. (“LPG”) that
MEHC’s indirect ownership interest in CE Casecnan had increased to 100%
effective from commencement of commercial operations. In July 2002, LPG
filed a complaint in the Superior Court of the State of California, City and
County of San Francisco against CE Casecnan Ltd. and MEHC. LPG’s complaint,
as amended, seeks compensatory and punitive damages arising out of
CE Casecnan Ltd.’s and MEHC’s alleged improper calculation of the proforma
financial projections and alleged improper settlement of the Philippine National
Irrigation Administration arbitration. In January 2006, the Superior Court
of the State of California entered a judgment in favor of LPG against CE
Casecnan Ltd. Pursuant to the judgment, 15% of the distributions of CE Casecnan
were deposited into escrow plus interest at 9% per annum. The judgment was
appealed, and as a result of the appellate decision, CE Casecnan Ltd. determined
that LPG would retain ownership of 10% of the shares of CE Casecnan, with the
remaining 5% share to be transferred to CE Casecnan Ltd. subject to certain
buy-up rights under the shareholder agreement. The issues relating to the
exercise of the buy-up right have been decided by the court and in
June 2009, LPG exercised its buy-up rights with respect to the remaining 5%
ownership interest. In October 2009, the court issued a Final Judgment
declaring that LPG was a 15% shareholder, which Final Judgment remains
subject to appeal. The Company intends to vigorously defend and pursue the
remaining claims.
In
July 2005, MEHC and CE Casecnan Ltd. commenced an action against San
Lorenzo Ruiz Builders and Developers Group, Inc. (“San Lorenzo”) in the District
Court of Douglas County, Nebraska, seeking a declaratory judgment as to San
Lorenzo’s right to repurchase 15% of the shares in CE Casecnan. In
January 2006, San Lorenzo filed a counterclaim against MEHC and
CE Casecnan Ltd. seeking declaratory relief that it has effectively
exercised its option to purchase 15% of the shares of CE Casecnan, that it
is the rightful owner of such shares and that it is due all dividends paid on
such shares. Currently, the action is in the discovery phase and a trial has
been set to begin in March 2010. The impact, if any, of this litigation on
the Company cannot be determined at this time. The Company intends to vigorously
defend the counterclaims.
Environmental
Matters
The
Company is subject to federal, state, local and foreign laws and regulations
regarding air and water quality, hazardous and solid waste disposal, protected
species and other environmental matters that have the potential to impact
the Company’s current and future operations. The Company believes it is in
material compliance with current environmental requirements.
Accrued
Environmental Costs
The
Company is fully or partly responsible for environmental remediation at various
contaminated sites, including sites that are or were part of the Company’s
operations and sites owned by third parties. The Company accrues environmental
remediation expenses when the expenses are believed to be probable and can be
reasonably estimated. The quantification of environmental exposures is based on
many factors, including changing laws and regulations, advancements in
environmental technologies, the quality of available site-specific information,
site investigation results, expected remediation or settlement timelines, the
Company’s proportionate responsibility, contractual indemnities and coverage
provided by insurance policies. The liability recorded as of September 30,
2009 and December 31, 2008 was $20 million and $33 million,
respectively, and is included in other current liabilities and other long-term
liabilities on the Consolidated Balance Sheets. Environmental remediation
liabilities that separately result from the normal operation of long-lived
assets and that are legal obligations associated with the retirement of those
assets are separately accounted for as asset retirement
obligations.
Climate Change
In
June 2009, the United States House of Representatives passed the American
Clean Energy and Security Act of 2009 (“Waxman-Markey bill”), introduced by
Representatives Henry Waxman and Edward Markey. In addition to a federal
renewable portfolio standard, which would require utilities to obtain a portion
of their energy from certain qualifying renewable sources, and energy efficiency
measures, the bill requires a reduction in greenhouse gas emissions beginning in
2012, with emission reduction targets of 3% below 2005 levels by 2012; 17% below
2005 levels by 2020; 42% below 2005 levels by 2030; and 83% below 2005 levels by
2050 under a “cap and trade” program. In September 2009, a similar bill was
introduced in the United States Senate by Senators Barbara Boxer and John Kerry,
which would require a reduction in greenhouse gas emissions beginning in
2012 with emission reduction targets consistent with the Waxman-Markey
bill, with the exception of the 2020 target, which requires 20% reductions below
2005 levels. If the Waxman-Markey bill or some other federal comprehensive
climate change bill were to pass both Houses of Congress and be signed into law
by the President, the impact on the Company’s financial performance could be
material and would depend on a number of factors, including the required timing
and level of greenhouse gas reductions, the price and availability of offsets
and allowances used for compliance and the ability of the Company to receive
revenue from customers for increased costs. The new law would likely result in
increased operating costs and expenses, additional capital expenditures and
retirements of existing assets, and may negatively impact demand for
electricity. The Company expects its regulated subsidiaries will be allowed to
recover the costs to comply with climate change requirements.
23
Hydroelectric
Relicensing
PacifiCorp’s
hydroelectric portfolio consists of 47 generating facilities with an
aggregate facility net owned capacity of 1,158 megawatts (“MW”). The FERC
regulates 98% of the net capacity of this portfolio through 16 individual
licenses, which typically have terms of 30 to 50 years. PacifiCorp is
currently actively engaged in the relicensing process with the FERC for its
Klamath hydroelectric system.
In
February 2004, PacifiCorp filed with the FERC a final application for a new
license to operate the 169-MW Klamath hydroelectric system in anticipation of
the March 2006 expiration of the existing license. PacifiCorp is currently
operating under an annual license issued by the FERC and expects to continue
operating under annual licenses until the relicensing process is complete. As
part of the relicensing process, the FERC is required to perform an
environmental review, and in November 2007, the FERC issued its final
environmental impact statement. The United States Fish and Wildlife Service and
the National Marine Fisheries Service issued final biological opinions in
December 2007 analyzing the Klamath hydroelectric system’s impact on endangered
species under a new FERC license consistent with the FERC staff’s recommended
license alternative and terms and conditions issued by the United States
Departments of the Interior and Commerce. These terms and conditions include
construction of upstream and downstream fish passage facilities at the Klamath
hydroelectric system’s four mainstem dams. PacifiCorp will need to obtain water
quality certifications from Oregon and California prior to the FERC issuing
a final license. PacifiCorp currently has water quality applications pending in
Oregon and California.
In
November 2008, PacifiCorp signed a non-binding agreement in principle
(the “AIP”) that laid out a framework for the disposition of PacifiCorp’s
Klamath hydroelectric system relicensing process, including a path toward dam
transfer and removal by an entity other than PacifiCorp no earlier than 2020.
Parties to the AIP are PacifiCorp, the United States Department of the Interior,
the State of Oregon and the State of California. Any transfer of facilities and
subsequent removal are contingent on PacifiCorp reaching a comprehensive final
settlement with the AIP signatories and other stakeholders. As provided in the
AIP, PacifiCorp’s support for a definitive settlement will depend on a variety
of factors, including the protection for PacifiCorp and its customers from
uncapped dam removal costs and liabilities.
The AIP
includes provisions to:
·
|
Perform
studies and implement certain measures designed to benefit aquatic species
and their habitat in the Klamath
Basin;
|
·
|
Support
and implement legislation in Oregon authorizing a customer surcharge
intended to cover potential dam removal;
and
|
·
|
Require
parties to support proposed federal legislation introduced to facilitate a
final agreement.
|
Assuming
a final agreement is reached, the United States government will conduct
scientific and engineering studies and consult with state, local and tribal
governments and other stakeholders, as appropriate, to determine by
March 31, 2012 whether the benefits of dam removal will justify the
costs.
In
addition to signing the AIP, PacifiCorp provided both the United States Fish and
Wildlife Service and the National Marine Fisheries Service an interim
conservation plan aimed at providing additional protections for endangered
species in the Klamath Basin. PacifiCorp is collaborating with both
agencies to implement the plan.
PacifiCorp
has participated in ongoing negotiations since the AIP was signed in
November 2008 to arrive at a draft of the final settlement agreement. The
Klamath settlement parties voted to release in September 2009 a public
review draft of the final settlement agreement, which is consistent with the AIP
framework. The parties will review the draft of the final settlement agreement,
and expect to sign a final settlement agreement by the end of 2009.
24
In
July 2009, Oregon’s governor signed a bill authorizing PacifiCorp to
collect surcharges from its Oregon customers for Oregon’s share of the customer
contribution identified in the AIP for the cost of removing the Klamath River
dams. According to the AIP, the total amount to be collected from PacifiCorp’s
customers is capped at $200 million. Of this amount, up
to $180 million would be collected from PacifiCorp’s Oregon customers
with the remainder to be collected from PacifiCorp’s California customers.
Hydroelectric
relicensing and the related environmental compliance requirements and litigation
are subject to uncertainties. PacifiCorp expects that future costs relating to
these matters will be significant and will consist primarily of additional
relicensing costs, as well as ongoing operations and maintenance expense and
capital expenditures required by its hydroelectric licenses. Electricity
generation reductions may result from the additional environmental requirements.
PacifiCorp had incurred $65 million and $57 million in costs, included
in construction in progress and reflected in property, plant and equipment, net
on the Consolidated Balance Sheets, as of September 30, 2009 and
December 31, 2008, respectively, for ongoing hydroelectric relicensing.
While the costs of implementing new license provisions cannot be determined
until such time as a new license is issued, such costs could be
material.
FERC
Investigation
During 2007,
the Western Electricity Coordinating Council (the “WECC”) audited PacifiCorp’s
compliance with several of the reliability standards developed by the North
American Electric Reliability Corporation (the “NERC”). In April 2008,
PacifiCorp received notice of a preliminary non-public investigation from the
FERC and the NERC to determine whether an outage that occurred in
PacifiCorp’s transmission system in February 2008 involved any violations
of reliability standards. In November 2008, PacifiCorp received preliminary
findings from the FERC staff regarding its non-public investigation into the
February 2008 outage. Also in November 2008, in conjunction with the
reliability standards review, the FERC assumed control of certain aspects of the
WECC’s 2007 audit. PacifiCorp has engaged in discussions with FERC staff
regarding findings related to the WECC audit and the non-public investigation.
However, PacifiCorp cannot predict the impact of the audit or the non-public
investigation on its consolidated financial results at this time.
(13)
|
MEHC
Shareholders’ Equity
|
In March
2009, 703,329 common stock options were exercised having an exercise price of
$35.05 per share, or $25 million. Also in March 2009, MEHC
purchased the shares issued from the options exercised for $148 million. As
a result, the Company recognized $125 million of stock-based compensation
expense, including the Company’s share of payroll taxes, for the nine-month
period ended September 30, 2009, which is included in operating expense on
the Consolidated Statement of Operations.
25
(14)
|
Comprehensive
Income and Components of Accumulated Other Comprehensive Loss,
Net
|
Comprehensive
income attributable to MEHC consists of the following components (in
millions):
Three-Month
Periods
Ended
September 30,
|
Nine-Month
Periods
Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Net
income attributable to MEHC
|
$ | 376 | $ | 350 | $ | 864 | $ | 912 | ||||||||
Other
comprehensive income (loss) attributable to MEHC:
|
||||||||||||||||
Unrecognized
amounts on retirement benefits, net of tax of $6, $12, $(8) and
$14
|
13 | 30 | (24 | ) | 36 | |||||||||||
Foreign
currency translation adjustment
|
(73 | ) | (320 | ) | 231 | (304 | ) | |||||||||
Fair
value adjustment on cash flow hedges, net of tax of $3, $(22), $(5) and
$(13)
|
7 | (33 | ) | (6 | ) | (19 | ) | |||||||||
Unrealized
gains (losses) on marketable securities, net of tax of $651, $(4), $653
and $(12)
|
978 | (7 | ) | 981 | (18 | ) | ||||||||||
Total
other comprehensive income (loss) attributable to MEHC
|
925 | (330 | ) | 1,182 | (305 | ) | ||||||||||
Comprehensive
income attributable to MEHC
|
$ | 1,301 | $ | 20 | $ | 2,046 | $ | 607 |
Accumulated
other comprehensive income (loss) attributable to MEHC, net consists of the
following components (in millions):
As
of
|
||||||||
September 30,
|
December 31,
|
|||||||
2009
|
2008
|
|||||||
Unrecognized
amounts on retirement benefits, net of tax of $(164) and
$(156)
|
$ | (425 | ) | $ | (401 | ) | ||
Foreign
currency translation adjustment
|
(215 | ) | (446 | ) | ||||
Fair
value adjustment on cash flow hedges, net of tax of $(8) and
$(3)
|
(13 | ) | (7 | ) | ||||
Unrealized
gains (losses) on marketable securities, net of tax of $637 and
$(16)
|
956 | (25 | ) | |||||
Total
accumulated other comprehensive income (loss) attributable to MEHC,
net
|
$ | 303 | $ | (879 | ) |
26
(15)
|
Segment
Information
|
MEHC’s
reportable segments were determined based on how the Company’s strategic units
are managed. The Company’s foreign reportable segments include CE Electric
UK, whose business is principally in Great Britain, and CalEnergy
Generation-Foreign, whose business is in the Philippines. Intersegment
transactions, including the allocation of goodwill, have been eliminated or
adjusted, as appropriate. Information related to the Company’s reportable
segments is shown below (in millions):
Three-Month
Periods
|
Nine-Month
Periods
|
|||||||||||||||
Ended
September 30,
|
Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Operating
revenue:
|
||||||||||||||||
PacifiCorp
|
$ | 1,146 | $ | 1,245 | $ | 3,278 | $ | 3,395 | ||||||||
MidAmerican
Funding
|
812 | 1,107 | 2,711 | 3,561 | ||||||||||||
Northern
Natural Gas
|
116 | 149 | 477 | 520 | ||||||||||||
Kern
River
|
90 | 126 | 283 | 340 | ||||||||||||
CE Electric UK
|
214 | 245 | 604 | 773 | ||||||||||||
CalEnergy
Generation-Foreign
|
51 | 38 | 107 | 96 | ||||||||||||
CalEnergy
Generation-Domestic
|
9 | 8 | 24 | 23 | ||||||||||||
HomeServices
|
312 | 330 | 764 | 913 | ||||||||||||
Corporate/other(1)
|
(9 | ) | (8 | ) | (36 | ) | (33 | ) | ||||||||
Total
operating revenue
|
$ | 2,741 | $ | 3,240 | $ | 8,212 | $ | 9,588 | ||||||||
Depreciation
and amortization:
|
||||||||||||||||
PacifiCorp
|
$ | 139 | $ | 123 | $ | 414 | $ | 364 | ||||||||
MidAmerican
Funding
|
85 | 61 | 251 | 210 | ||||||||||||
Northern
Natural Gas
|
16 | 15 | 47 | 44 | ||||||||||||
Kern
River
|
24 | 15 | 72 | 58 | ||||||||||||
CE Electric UK
|
44 | 48 | 121 | 138 | ||||||||||||
CalEnergy
Generation-Foreign
|
6 | 6 | 17 | 17 | ||||||||||||
CalEnergy
Generation-Domestic
|
2 | 2 | 6 | 6 | ||||||||||||
HomeServices
|
5 | 4 | 13 | 14 | ||||||||||||
Corporate/other(1)
|
(3 | ) | (6 | ) | (12 | ) | (13 | ) | ||||||||
Total
depreciation and amortization
|
$ | 318 | $ | 268 | $ | 929 | $ | 838 | ||||||||
Operating
income:
|
||||||||||||||||
PacifiCorp
|
$ | 299 | $ | 268 | $ | 796 | $ | 717 | ||||||||
MidAmerican
Funding
|
123 | 159 | 363 | 438 | ||||||||||||
Northern
Natural Gas
|
37 | 95 | 238 | 295 | ||||||||||||
Kern
River
|
54 | 99 | 174 | 244 | ||||||||||||
CE Electric UK
|
109 | 115 | 306 | 399 | ||||||||||||
CalEnergy
Generation-Foreign
|
42 | 30 | 82 | 72 | ||||||||||||
CalEnergy
Generation-Domestic
|
4 | 5 | 12 | 12 | ||||||||||||
HomeServices
|
18 | 1 | 16 | (10 | ) | |||||||||||
Corporate/other(1)
|
(25 | ) | (1 | ) | (165 | ) | (41 | ) | ||||||||
Total
operating income
|
661 | 771 | 1,822 | 2,126 | ||||||||||||
Interest
expense
|
(316 | ) | (340 | ) | (957 | ) | (998 | ) | ||||||||
Capitalized
interest
|
12 | 14 | 30 | 37 | ||||||||||||
Interest
and dividend income
|
8 | 16 | 36 | 47 | ||||||||||||
Other,
net
|
41 | 19 | 119 | 59 | ||||||||||||
Total
income before income tax expense and equity income
|
$ | 406 | $ | 480 | $ | 1,050 | $ | 1,271 |
27
Three-Month
Periods
|
Nine-Month
Periods
|
|||||||||||||||
Ended
September 30,
|
Ended
September 30,
|
|||||||||||||||
2009
|
2008
|
2009
|
2008
|
|||||||||||||
Interest
expense:
|
||||||||||||||||
PacifiCorp
|
$ | 102 | $ | 91 | $ | 310 | $ | 255 | ||||||||
MidAmerican
Funding
|
48 | 52 | 148 | 153 | ||||||||||||
Northern
Natural Gas
|
15 | 17 | 45 | 46 | ||||||||||||
Kern
River
|
14 | 16 | 42 | 52 | ||||||||||||
CE Electric UK
|
39 | 51 | 109 | 148 | ||||||||||||
CalEnergy
Generation-Foreign
|
1 | 2 | 3 | 6 | ||||||||||||
CalEnergy
Generation-Domestic
|
4 | 4 | 12 | 13 | ||||||||||||
HomeServices
|
- | - | - | 1 | ||||||||||||
Corporate/other(1)
|
93 | 107 | 288 | 324 | ||||||||||||
Total
interest expense
|
$ | 316 | $ | 340 | $ | 957 | $ | 998 |
As
of
|
||||||||
September 30,
|
December 31,
|
|||||||
2009
|
2008
|
|||||||
Total
assets:
|
||||||||
PacifiCorp
|
$ | 19,635 | $ | 18,339 | ||||
MidAmerican
Funding
|
10,566 | 10,632 | ||||||
Northern
Natural Gas
|
2,637 | 2,595 | ||||||
Kern
River
|
1,846 | 1,910 | ||||||
CE
Electric UK
|
5,516 | 4,921 | ||||||
CalEnergy
Generation-Foreign
|
482 | 442 | ||||||
CalEnergy
Generation-Domestic
|
582 | 550 | ||||||
HomeServices
|
671 | 674 | ||||||
Corporate/other(1)
|
2,055 | 1,378 | ||||||
Total
assets
|
$ | 43,990 | $ | 41,441 |
(1)
|
The
remaining differences between the segment amounts and the consolidated
amounts described as “Corporate/other” relate principally to intersegment
eliminations for operating revenue and, for the other items presented, to
(i) corporate functions, including administrative costs, interest expense,
corporate cash and investments and related interest income and (ii)
intersegment eliminations.
|
Goodwill
is allocated to each reportable segment included in total assets above. Goodwill
as of December 31, 2008 and the changes for the nine-month period ended
September 30, 2009 by reportable segment are as follows (in
millions):
Northern
|
CE
|
CalEnergy
|
||||||||||||||||||||||||||||||
MidAmerican
|
Natural
|
Kern
|
Electric
|
Generation-
|
Home-
|
|||||||||||||||||||||||||||
PacifiCorp
|
Funding
|
Gas
|
River
|
UK
|
Domestic
|
Services
|
Total
|
|||||||||||||||||||||||||
Goodwill
at December 31, 2008
|
$ | 1,126 | $ | 2,102 | $ | 249 | $ | 34 | $ | 1,050 | $ | 71 | $ | 391 | $ | 5,023 | ||||||||||||||||
Foreign
currency translation
|
- | - | - | - | 73 | - | - | 73 | ||||||||||||||||||||||||
Other
|
- | - | (20 | ) | - | - | - | - | (20 | ) | ||||||||||||||||||||||
Goodwill
at September 30, 2009
|
$ | 1,126 | $ | 2,102 | $ | 229 | $ | 34 | $ | 1,123 | $ | 71 | $ | 391 | $ | 5,076 |
28
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 financial condition and results of operations of
MidAmerican Energy Holdings Company (“MEHC”) and its subsidiaries (collectively,
the “Company”) during the periods included herein. Explanations include
management’s best estimate of the impact of weather, customer growth and other
factors. This discussion should be read in conjunction with the Company’s
historical unaudited Consolidated Financial Statements and Notes to Consolidated
Financial Statements included in Item 1 of this Form 10-Q. The
Company’s actual results in the future could differ significantly from the
historical results.
The
Company’s operations are organized and managed as eight distinct platforms:
PacifiCorp, MidAmerican Funding, LLC (“MidAmerican Funding”) (which
primarily consists of MidAmerican Energy Company (“MidAmerican
Energy”)), Northern Natural Gas Company (“Northern Natural Gas”), Kern River Gas
Transmission Company (“Kern River”), CE Electric UK Funding Company
(“CE Electric UK”) (which primarily consists of Northern Electric
Distribution Limited (“Northern Electric”) and Yorkshire Electricity
Distribution plc (“Yorkshire Electricity”)), CalEnergy Generation-Foreign (which
owns a majority interest in the Casecnan project in the Philippines), CalEnergy
Generation-Domestic (which owns interests in independent power projects in the
United States) and HomeServices of America, Inc. (collectively with its
subsidiaries, “HomeServices”). Through these platforms, MEHC owns and operates
an electric utility company in the Western United States, an electric and
natural gas utility company in the Midwestern United States, two interstate
natural gas pipeline companies in the United States, two electricity
distribution companies in Great Britain, a diversified portfolio of independent
power projects and the second largest residential real estate brokerage firm in
the United States.
Forward-Looking
Statements
This
report contains statements that do not directly or exclusively relate to
historical facts. These statements are “forward-looking statements” within the
meaning of Section 27A of the Securities Act of 1933 and Section 21E
of the Securities Exchange Act of 1934, as amended. Forward-looking statements
can typically be identified by the use of forward-looking words, such as “may,”
“could,” “project,” “believe,” “anticipate,” “expect,” “estimate,” “continue,”
“intend,” “potential,” “plan,” “forecast” and similar terms. These statements
are based upon the Company’s current intentions, assumptions, expectations and
beliefs and are subject to risks, uncertainties and other important factors.
Many of these factors are outside the Company’s control and could cause actual
results to differ materially from those expressed or implied by the Company’s
forward-looking statements. These factors include, among others:
|
·
|
general
economic, political and business conditions in the jurisdictions in which
the Company’s facilities operate;
|
|
·
|
changes
in governmental, legislative or regulatory requirements affecting the
Company or the electric or gas utility, pipeline or power generation
industries;
|
|
·
|
changes
in, and compliance with, environmental laws, regulations, decisions and
policies that could increase operating and capital costs, reduce plant
output or delay plant construction;
|
|
·
|
the
outcome of general rate cases and other proceedings conducted by
regulatory commissions or other governmental and legal
bodies;
|
|
·
|
changes
in economic, industry or weather conditions, as well as demographic
trends, that could affect customer growth and usage or supply of
electricity and gas or the Company’s ability to obtain long-term contracts
with customers;
|
|
·
|
a
high degree of variance between actual and forecasted load and prices that
could impact the hedging strategy and costs to balance electricity and
load supply;
|
|
·
|
changes
in prices and availability for both purchases and sales of wholesale
electricity, coal, natural gas, other fuel sources and fuel transportation
that could have a significant impact on generation capacity and energy
costs;
|
|
·
|
the
financial condition and creditworthiness of the Company’s significant
customers and suppliers;
|
|
·
|
changes
in business strategy or development
plans;
|
29
|
·
|
availability,
terms and deployment of capital, including severe reductions in demand for
investment-grade commercial paper, debt securities and other sources of
debt financing and volatility in the London Interbank Offered Rate, the
base interest rate for MEHC’s and its subsidiaries’ credit
facilities;
|
|
·
|
changes
in MEHC’s and its subsidiaries’ credit
ratings;
|
|
·
|
performance
of the Company’s generating facilities, including unscheduled outages or
repairs;
|
|
·
|
risks
relating to nuclear generation;
|
|
·
|
the
impact of derivative instruments used to mitigate or manage volume, price
and interest rate risk, including increased collateral requirements, and
changes in the commodity prices, interest rates and other conditions that
affect the value of derivative
instruments;
|
|
·
|
the
impact of increases in healthcare costs and changes in interest rates,
mortality, morbidity, investment performance and legislation on pension
and other postretirement benefits expense and funding
requirements;
|
|
·
|
changes
in the residential real estate brokerage and mortgage industries that
could affect brokerage transaction
levels;
|
|
·
|
unanticipated
construction delays, changes in costs, receipt of required permits and
authorizations, ability to fund capital projects and other factors that
could affect future generating facilities and infrastructure
additions;
|
|
·
|
the
impact of new accounting pronouncements or changes in current accounting
estimates and assumptions on financial
results;
|
|
·
|
the
Company’s ability to successfully integrate future acquired operations
into its business;
|
|
·
|
other
risks or unforeseen events, including litigation, wars, the effects of
terrorism, embargoes and other catastrophic events;
and
|
|
·
|
other
business or investment considerations that may be disclosed from time to
time in MEHC’s filings with the United States Securities and Exchange
Commission (the “SEC”) or in other publicly disseminated written
documents.
|
Further
details of the potential risks and uncertainties affecting the Company are
described in MEHC’s filings with the SEC, including Part II, Item 1A and
other discussions contained in this Form 10-Q. The Company undertakes no
obligation to publicly update or revise any forward-looking statements, whether
as a result of new information, future events or otherwise. The foregoing review
of factors should not be construed as exclusive.
Results
of Operations for the Third Quarter and First Nine Months of 2009 and
2008
Overview
Net
income attributable to MEHC for the third quarter of 2009 was $376 million,
an increase of $26 million, or 7%, and for the first nine months of 2009
was $864 million, a decrease of $48 million, or 5%, compared to 2008.
The results for the first nine months of 2009 included an after-tax stock-based
compensation charge of $75 million as a result of the purchase of shares of
common stock that were issued upon the exercise of stock options and an
after-tax gain on the Constellation Energy Group, Inc. (“Constellation Energy”)
common stock investment of $22 million. Excluding the impact of these items, net
income attributable to MEHC increased $5 million, or 1%, for the first nine
months of 2009 compared to 2008. Net income attributable to MEHC for the third
quarter and the first nine months of 2009 compared to 2008 increased due to
higher net income at PacifiCorp, MidAmerican Funding, CalEnergy
Generation-Foreign and HomeServices, partially offset by lower net income at
Northern Natural Gas, Kern River and CE Electric UK.
Net
income was higher at PacifiCorp as a result of lower energy costs, higher rates
approved by regulators and lower income taxes, partially offset by lower retail
volumes and higher depreciation and amortization. MidAmerican Funding’s net
income increased due to income tax benefits of $55 million for repairs
deductions, additional production tax credits and lower maintenance costs as a
result of the storm and flood damage in 2008, partially offset by lower
regulated electric margins of $11 million for the third quarter and
$51 million for the first nine months from lower wholesale revenues and
lower retail volumes and higher depreciation and amortization. Net income was
higher at CalEnergy Generation-Foreign due to higher rainfall and related
revenue earned at the Casecnan project and higher at HomeServices due to lower
operating expenses.
30
Net
income at Northern Natural Gas and Kern River was lower as a result of less
favorable market conditions, a reduction in Kern River’s customer refund
liability in 2008 of $10 million for the third quarter and $22 million
for the first nine months and a $16 million after-tax gain on the sale of
certain non-strategic operating assets at Northern Natural Gas in the third
quarter of 2008. Net income was lower at CE Electric UK due primarily to a
stronger United States dollar that reduced net income $7 million for the
third quarter and $38 million for the first nine months of 2009 compared to
2008.
Segment
Results
The
reportable segment financial information includes all necessary adjustments and
eliminations needed to conform to the Company’s significant accounting policies.
The differences between the segment amounts and the consolidated amounts,
described as “Corporate/other,” relate principally to corporate functions,
including administrative costs and intersegment eliminations.
A
comparison of operating revenue and operating income for the Company’s
reportable segments are summarized as follows (in millions):
Third
Quarter
|
First
Nine Months
|
|||||||||||||||||||||||||||||||
2009
|
2008
|
Change
|
2009
|
2008
|
Change
|
|||||||||||||||||||||||||||
Operating
revenue:
|
||||||||||||||||||||||||||||||||
PacifiCorp
|
$ | 1,146 | $ | 1,245 | $ | (99 | ) | (8 | )% | $ | 3,278 | $ | 3,395 | $ | (117 | ) | (3 | )% | ||||||||||||||
MidAmerican
Funding
|
812 | 1,107 | (295 | ) | (27 | ) | 2,711 | 3,561 | (850 | ) | (24 | ) | ||||||||||||||||||||
Northern
Natural Gas
|
116 | 149 | (33 | ) | (22 | ) | 477 | 520 | (43 | ) | (8 | ) | ||||||||||||||||||||
Kern
River
|
90 | 126 | (36 | ) | (29 | ) | 283 | 340 | (57 | ) | (17 | ) | ||||||||||||||||||||
CE Electric UK
|
214 | 245 | (31 | ) | (13 | ) | 604 | 773 | (169 | ) | (22 | ) | ||||||||||||||||||||
CalEnergy
Generation-Foreign
|
51 | 38 | 13 | 34 | 107 | 96 | 11 | 11 | ||||||||||||||||||||||||
CalEnergy
Generation-Domestic
|
9 | 8 | 1 | 13 | 24 | 23 | 1 | 4 | ||||||||||||||||||||||||
HomeServices
|
312 | 330 | (18 | ) | (5 | ) | 764 | 913 | (149 | ) | (16 | ) | ||||||||||||||||||||
Corporate/other
|
(9 | ) | (8 | ) | (1 | ) | (13 | ) | (36 | ) | (33 | ) | (3 | ) | (9 | ) | ||||||||||||||||
Total
operating revenue
|
$ | 2,741 | $ | 3,240 | $ | (499 | ) | (15 | ) | $ | 8,212 | $ | 9,588 | $ | (1,376 | ) | (14 | ) |
Operating
income:
|
||||||||||||||||||||||||||||||||
PacifiCorp
|
$ | 299 | $ | 268 | $ | 31 | 12 | % | $ | 796 | $ | 717 | $ | 79 | 11 | % | ||||||||||||||||
MidAmerican
Funding
|
123 | 159 | (36 | ) | (23 | ) | 363 | 438 | (75 | ) | (17 | ) | ||||||||||||||||||||
Northern
Natural Gas
|
37 | 95 | (58 | ) | (61 | ) | 238 | 295 | (57 | ) | (19 | ) | ||||||||||||||||||||
Kern
River
|
54 | 99 | (45 | ) | (45 | ) | 174 | 244 | (70 | ) | (29 | ) | ||||||||||||||||||||
CE Electric UK
|
109 | 115 | (6 | ) | (5 | ) | 306 | 399 | (93 | ) | (23 | ) | ||||||||||||||||||||
CalEnergy
Generation-Foreign
|
42 | 30 | 12 | 40 | 82 | 72 | 10 | 14 | ||||||||||||||||||||||||
CalEnergy
Generation-Domestic
|
4 | 5 | (1 | ) | (20 | ) | 12 | 12 | - | - | ||||||||||||||||||||||
HomeServices
|
18 | 1 | 17 | * | 16 | (10 | ) | 26 | * | |||||||||||||||||||||||
Corporate/other
|
(25 | ) | (1 | ) | (24 | ) | * | (165 | ) | (41 | ) | (124 | ) | * | ||||||||||||||||||
Total
operating income
|
$ | 661 | $ | 771 | $ | (110 | ) | (14 | ) | $ | 1,822 | $ | 2,126 | $ | (304 | ) | (14 | ) |
*
|
Not
meaningful
|
PacifiCorp
Operating
revenue decreased $99 million for the third quarter of 2009 compared to
2008 due to a decrease in wholesale and other revenue of $78 million and
unfavorable changes in the fair value of energy sales contracts accounted for as
derivatives of $46 million, partially offset by higher retail revenue of
$25 million. The decrease in wholesale and other revenue was due primarily
to a 39% decrease in average wholesale prices, partially offset by revenue
attributable to PacifiCorp’s majority owned coal mining operations. The increase
in retail revenue was due to higher prices approved by regulators totaling
$35 million, partially offset by a 3% decrease in retail volumes. The
decrease in retail volumes is principally related to lower average customer
usage due to the effect of current economic conditions mainly on industrial
customers in Wyoming and Oregon, partially offset by growth in the average
number of commercial customers. Total retail and wholesale sales volumes
decreased 3%.
31
Operating
income increased $31 million for the third quarter of 2009 compared to 2008
due to lower energy costs of $156 million, partially offset by lower
revenue of $99 million, higher depreciation and amortization of
$17 million due to the addition of new generating facilities and higher
operating expenses of $11 million due primarily to costs attributable to
PacifiCorp’s majority owned coal mining operations. Energy costs were lower due
largely to a 40% decrease in the average cost of purchased electricity, a 13%
decrease in the volume of purchased electricity and favorable changes in the
fair value of energy purchase contracts accounted for as derivatives of
$44 million. The addition of the Chehalis natural gas plant and new wind
generating facilities in the second half of 2008 and the first quarter of 2009,
along with the 3% decrease in overall sales volumes, allowed PacifiCorp to
reduce its need for purchased electricity.
Operating
revenue decreased $117 million for the first nine months of 2009 compared
to 2008 due a decrease in wholesale and other revenue of $124 million,
partially offset by higher retail revenue of $15 million. The decrease in
wholesale and other revenue was due primarily to a 26% decrease in average
wholesale prices, partially offset by revenue attributable to PacifiCorp’s
majority owned coal mining operations. The increase in retail revenue was due to
higher prices approved by regulators totaling $76 million, partially offset
by a 4% decrease in retail volumes. The decrease in retail volumes is
principally related to lower average customer usage due to the effect of current
economic conditions mainly on industrial customers across PacifiCorp’s service
territories and on residential customers in Oregon, partially offset by growth
in the average number of commercial and residential customers mainly in Utah.
Total retail and wholesale sales volumes decreased 3%.
Operating
income increased $79 million for the first nine months of 2009 compared to
2008 due to lower energy costs of $285 million, partially offset by lower
revenue of $117 million, higher depreciation and amortization of
$51 million due to the addition of new generating facilities and higher
operating expenses of $39 million due primarily to costs attributable to
PacifiCorp’s majority owned coal mining operations. Energy costs were lower due
largely to a 38% decrease in the average cost of purchased electricity, a 10%
decrease in the volume of purchased electricity and favorable changes in the
fair value of energy purchase contracts accounted for as derivatives of
$22 million, partially offset by the effects of regulatory cost recovery
adjustment mechanisms of $26 million. The addition of the Chehalis natural
gas plant and new wind generating facilities in the second half of 2008 and the
first quarter of 2009, along with the 3% decrease in overall sales volumes,
allowed PacifiCorp to reduce its need for purchased electricity.
MidAmerican
Funding
MidAmerican
Funding’s operating revenue and operating income are summarized as follows
(in millions):
Third
Quarter
|
First
Nine Months
|
|||||||||||||||||||||||||||||||
2009
|
2008
|
Change
|
2009
|
2008
|
Change
|
|||||||||||||||||||||||||||
Operating
revenue:
|
||||||||||||||||||||||||||||||||
Regulated
electric
|
$ | 451 | $ | 552 | $ | (101 | ) | (18 | )% | $ | 1,286 | $ | 1,527 | $ | (241 | ) | (16 | )% | ||||||||||||||
Regulated
natural gas
|
85 | 192 | (107 | ) | (56 | ) | 591 | 1,043 | (452 | ) | (43 | ) | ||||||||||||||||||||
Nonregulated
and other
|
276 | 363 | (87 | ) | (24 | ) | 834 | 991 | (157 | ) | (16 | ) | ||||||||||||||||||||
Total
operating revenue
|
$ | 812 | $ | 1,107 | $ | (295 | ) | (27 | ) | $ | 2,711 | $ | 3,561 | $ | (850 | ) | (24 | ) | ||||||||||||||
Operating
income:
|
||||||||||||||||||||||||||||||||
Regulated
electric
|
$ | 112 | $ | 148 | $ | (36 | ) | (24 | )% | $ | 272 | $ | 353 | $ | (81 | ) | (23 | )% | ||||||||||||||
Regulated
natural gas
|
(4 | ) | (5 | ) | 1 | 20 | 43 | 43 | - | - | ||||||||||||||||||||||
Nonregulated
and other
|
15 | 16 | (1 | ) | (6 | ) | 48 | 42 | 6 | 14 | ||||||||||||||||||||||
Total
operating income
|
$ | 123 | $ | 159 | $ | (36 | ) | (23 | ) | $ | 363 | $ | 438 | $ | (75 | ) | (17 | ) |
Regulated
electric operating revenue decreased $101 million for the third quarter of
2009 compared to 2008. Wholesale and other revenue decreased $87 million
due to a 43% decrease in average wholesale prices and a 15% decrease in volumes,
resulting from reduced demand for electricity due to the current economic
conditions and mild temperatures. Retail revenue decreased $14 million on
lower volumes of 5% primarily related to mild temperatures experienced
throughout the service territory in 2009. Total retail and wholesale sales
volumes decreased by 9%.
32
Regulated
electric operating income decreased $36 million for the third quarter of
2009 compared to 2008. The lower revenue was largely offset by a decrease in the
cost of energy of $81 million as a result of lower purchased electricity of
$70 million and a lower cost of natural gas of $16 million, which were
both due to lower average costs and volumes. The addition of new wind generating
facilities in 2008 allowed MidAmerican Funding to replace more expensive sources
of electricity. Depreciation and amortization increased $25 million,
primarily due to the addition of new wind and other generating facilities that
increased depreciation and amortization by $14 million and a change in Iowa
revenue sharing. Operating expenses decreased $8 million due largely to
lower maintenance costs as a result of the storm and flood damage in
2008.
Regulated
natural gas operating revenue decreased $107 million for the third quarter
of 2009 compared to 2008 due primarily to a reduction in the average per-unit
cost of gas sold, which was passed on to customers and resulted in lower cost of
sales, and lower sales volumes of 34%, due principally to lower wholesale
volumes as a result of fewer market opportunities due to lower price
spreads.
Nonregulated
and other operating revenue decreased $87 million for the third quarter of
2009 compared to 2008 due to lower gas revenue of $99 million as a result
of a 76% decrease in average prices and a 15% decrease in volumes, partially
offset by higher electric retail revenue of $16 million due to a 12%
increase in volumes, partially offset by a 5% decrease in average prices.
Nonregulated and other operating income decreased $1 million for the third
quarter of 2009 compared to 2008 as lower cost of sales largely offset the lower
revenue.
Regulated
electric operating revenue decreased $241 million for the first nine months
of 2009 compared to 2008. Wholesale and other revenue decreased
$217 million due to a 38% decrease in average wholesale prices and an 11%
decrease in volumes, resulting from reduced demand for electricity due to the
current economic conditions and mild temperatures. Retail revenue decreased
$24 million on lower volumes of 4% primarily related to lower industrial
load and mild temperatures experienced throughout the service territory in 2009.
Total retail and wholesale sales volumes decreased by 7%.
Regulated
electric operating income decreased $81 million for the first nine months
of 2009 compared to 2008. The lower revenue was largely offset by a decrease in
the cost of energy of $196 million as a result of lower purchased
electricity of $157 million and a lower cost of natural gas of
$41 million, which were both due to lower average costs and volumes. The
addition of new wind generating facilities in 2008 allowed MidAmerican Funding
to replace more expensive sources of electricity. Depreciation and amortization
increased $40 million due to the addition of new wind and other generating
facilities. Operating expenses decreased $4 million due largely to lower
maintenance costs as a result of the storm and flood damage in
2008.
Regulated
natural gas operating revenue decreased $452 million for the first nine
months of 2009 compared to 2008 due primarily to a reduction in the average
per-unit cost of gas sold, which was passed on to customers and resulted in
lower cost of sales, and lower sales volumes of 10% as a result of mild weather
experienced throughout the service territory in 2009 and lower wholesale volumes
as a result of fewer market opportunities due to lower price spreads. Regulated
natural gas operating income was flat for the first nine months of 2009 compared
to 2008 as lower cost of sales and operating expenses offset the lower
revenue.
Nonregulated
and other operating revenue decreased $157 million for the first nine
months of 2009 compared to 2008 due to lower gas revenue of $197 million as
a result of a 50% decrease in average prices and a 13% decrease in volumes,
partially offset by higher electric retail revenue of $45 million due to a
7% increase in volumes. Nonregulated and other operating income increased
$6 million for the first nine months of 2009 compared to 2008 due primarily
to higher electric and gas margins.
Northern
Natural Gas
Operating
revenue decreased $33 million for the third quarter and $43 million
for the first nine months of 2009 compared to 2008 due to lower transportation
revenue of $31 million and $41 million, respectively, due to lower
demand caused by less favorable economic conditions, lower natural gas price
spreads and the sale of the Beaver system in 2008. Operating income decreased
$58 million for the third quarter and $57 million for the first nine
months of 2009 compared to 2008 due to lower transportation revenue and a
pre-tax gain on the sale of certain non-strategic operating assets of
$26 million in the third quarter of 2008, partially offset by lower
operating expenses for the first nine months.
33
Kern
River
Operating
revenue decreased $36 million for the third quarter and $57 million
for the first nine months of 2009 compared to 2008 due to lower price spreads
and a reduction in Kern River’s customer refund liability in 2008, which
resulted in lower revenue of $7 million for the third quarter and
$27 million for the first nine months. Operating income decreased
$45 million for the third quarter and $70 million for the first nine
months of 2009 compared to 2008 due to the lower operating revenue and higher
depreciation and amortization of $9 million for the third quarter and
$14 million for the first nine months.
CE
Electric UK
Operating
revenue decreased $31 million for the third quarter of 2009 compared to
2008 due to the impact from the foreign currency exchange rate totaling
$33 million and lower contracting revenue of $7 million, partially
offset by higher distribution revenue. Distribution revenue increased as tariff
rates were increased in April 2009 to bill under-recovered amounts under
the regulatory formula, partially offset by lower volumes of units distributed
due predominantly to the recession, and to a lesser extent the weather.
Operating income decreased $6 million for the third quarter of 2009
compared to 2008 due mainly to the impact from the foreign currency exchange
rate on operating income totaling $16 million, partially offset by the
higher distribution revenue.
Operating
revenue decreased $169 million for the first nine months of 2009 compared
to 2008 due to the impact from the foreign currency exchange rate totaling
$159 million and lower contracting revenue of $19 million, partially
offset by higher distribution revenue of $6 million. Operating income
decreased $93 million for the first nine months of 2009 compared to 2008
due to the impact from the foreign currency exchange rate on operating income
totaling $82 million and higher depreciation and amortization of
$14 million reflecting additional capital expenditures, partially offset by
the higher distribution revenue.
CalEnergy
Generation-Foreign
Operating
revenue increased $13 million and operating income increased
$12 million for the third quarter and operating revenue increased
$11 million and operating income increased $10 million for the first
nine months of 2009 compared to 2008 due to higher rainfall and related variable
water delivery fees earned in 2009 at the Casecnan project.
HomeServices
Operating
revenue decreased $18 million for the third quarter and $149 million
for the first nine months of 2009 compared to 2008 due to declines in average
home sale prices of 9% and 12%, respectively, and a decline in transaction
volumes of 9% for the first nine months of 2009 reflecting the continuing weak
United States housing market. Transaction volumes were up slightly for the third
quarter of 2009. Operating income increased $17 million for the third
quarter and $26 million for the first nine months of 2009 compared to 2008
due to lower commissions, operating expenses and office closure costs, partially
offset by the lower revenue.
Corporate/other
Operating
income decreased $24 million for the third quarter of 2009 compared to 2008
due to higher deferred compensation and captive insurance claims. Operating
income decreased $124 million for the first nine months of 2009 compared to
2008 due mainly to $125 million of stock-based compensation expense,
including the Company’s share of payroll taxes, as a result of the purchase of
common stock issued by MEHC upon the exercise of the last remaining stock
options that had been granted to certain members of management at the time of
Berkshire Hathaway Inc.’s (“Berkshire Hathaway”) acquisition of MEHC in
2000.
34
Consolidated Other Income
and Expense Items
Interest
Expense
Interest
expense is summarized as follows (in millions):
Third
Quarter
|
First
Nine Months
|
|||||||||||||||||||||||||||||||
2009
|
2008
|
Change
|
2009
|
2008
|
Change
|
|||||||||||||||||||||||||||
Subsidiary
debt
|
$ | 212 | $ | 223 | $ | (11 | ) | (5 | )% | $ | 644 | $ | 643 | $ | 1 | - | % | |||||||||||||||
MEHC
senior debt and other
|
85 | 88 | (3 | ) | (3 | ) | 249 | 267 | (18 | ) | (7 | ) | ||||||||||||||||||||
MEHC
subordinated debt - Berkshire Hathaway
|
13 | 22 | (9 | ) | (41 | ) | 47 | 67 | (20 | ) | (30 | ) | ||||||||||||||||||||
MEHC
subordinated debt - other
|
6 | 7 | (1 | ) | (14 | ) | 17 | 21 | (4 | ) | (19 | ) | ||||||||||||||||||||
Total
interest expense
|
$ | 316 | $ | 340 | $ | (24 | ) | (7 | ) | $ | 957 | $ | 998 | $ | (41 | ) | (4 | ) |
Interest
expense decreased $24 million for the third quarter and $41 million
for the first nine months of 2009 compared to 2008 due to debt retirements,
scheduled principal repayments and the impact of the foreign currency exchange
rate of $12 million for the third quarter and $32 million for the
first nine months. The decreases were partially offset by debt issuances in 2009
at MEHC and 2008 and 2009 at PacifiCorp.
Interest
and Dividend Income
Interest
and dividend income decreased $8 million for the third quarter and
$11 million for the first nine months of 2009 compared to 2008 due to less
favorable cash positions in 2009 and dividends in 2008 related to the investment
in Constellation Energy 8% preferred stock.
Other,
Net
Other,
net increased $22 million for the third quarter and $60 million for the
first nine months of 2009 compared to 2008 due to higher earnings on deferred
compensation investments and higher equity allowance for funds used during
construction (“AFUDC”) due primarily to higher average construction in progress
at PacifiCorp, partially offset by lower average construction in progress at
MidAmerican Funding. Additionally, the first nine months of 2009 increased due
to the pre-tax gain on the Constellation Energy common stock investment totaling
$37 million.
Income
Tax Expense
Income
tax expense decreased $110 million for the third quarter and
$167 million for the first nine months of 2009 compared to 2008. The
effective tax rates were 10% and 31% for the third quarter of 2009 and 2008,
respectively, and 20% and 30% for the first nine months of 2009 and 2008,
respectively. The decrease in income tax expense was mainly due to
$55 million of income tax benefits recognized in the third quarter of 2009
for a change in tax accounting method for repairs deductions and the related
regulatory treatment in Iowa, MidAmerican Funding’s largest jurisdiction for
rate regulated operations, which requires immediate income recognition of such
temporary differences, lower pre-tax income, favorable settlement of certain tax
contingencies and additional production tax credits.
Equity
Income
Equity
income increased $16 million for the first nine months of 2009 compared to
2008 due to higher equity earnings at HomeServices related to refinance activity
in its mortgage business and at CE Generation, LLC due mainly to lower fuel
and maintenance costs.
Net
Income Attributable to Noncontrolling Interests
Net
income attributable to noncontrolling interests increased $7 million for
the third quarter and $10 million for the first nine months of 2009
compared to 2008 due mainly to higher earnings attributable to PacifiCorp’s
majority owned coal mining operations.
35
Liquidity
and Capital Resources
Each of
MEHC’s direct and indirect subsidiaries is organized as a legal entity separate
and apart from MEHC and its other subsidiaries. Pursuant to separate financing
agreements, the assets of each subsidiary may be pledged or encumbered to
support or otherwise provide the security for its own subsidiary debt. It should
not be assumed that any asset of any subsidiary of MEHC’s will be available to
satisfy the obligations of MEHC or any of its other subsidiaries’ obligations.
However, unrestricted cash or other assets which are available for distribution
may, subject to applicable law, regulatory commitments and the terms of
financing and ring-fencing arrangements for such parties, be advanced, loaned,
paid as dividends or otherwise distributed or contributed to MEHC or affiliates
thereof.
As of
September 30, 2009, the Company’s total net liquidity available was
$6.798 billion. The components of total net liquidity available are as
follows (in millions):
Other
|
||||||||||||||||||||
MidAmerican
|
Reporting
|
|||||||||||||||||||
MEHC
|
PacifiCorp
|
Funding
|
Segments
|
Total(1)
|
||||||||||||||||
Cash
and cash equivalents
|
$ | 321 | $ | 149 | $ | 8 | $ | 266 | $ | 744 | ||||||||||
Available
revolving credit facilities
|
$ | 835 | $ | 1,395 | $ | 654 | $ | 285 | $ | 3,169 | ||||||||||
Less:
|
||||||||||||||||||||
Short-term
borrowings and issuances of commercial paper
|
- | - | - | (120 | ) | (120 | ) | |||||||||||||
Tax-exempt
bond support, letters of credit and other
|
(42 | ) | (258 | ) | (195 | ) | - | (495 | ) | |||||||||||
Net
revolving credit facilities available
|
$ | 793 | $ | 1,137 | $ | 459 | $ | 165 | $ | 2,554 | ||||||||||
Net
liquidity available before Berkshire Equity Commitment
|
$ | 1,114 | $ | 1,286 | $ | 467 | $ | 431 | $ | 3,298 | ||||||||||
Berkshire
Equity Commitment(2)
|
3,500 | 3,500 | ||||||||||||||||||
Total
net liquidity available
|
$ | 4,614 | $ | 6,798 | ||||||||||||||||
Unsecured
revolving credit facilities:
|
||||||||||||||||||||
Maturity
date(3)
|
2009, 2013 | 2012-2013 | 2013 | 2010 | ||||||||||||||||
Largest
single bank commitment as a % of total(4)
|
30 | % | 15 | % | 23 | % | 28 | % |
(1)
|
The
above table does not include unused revolving credit facilities and
letters of credit for investments that are accounted for under the equity
method.
|
(2)
|
On
March 1, 2006, MEHC and Berkshire Hathaway entered into the Berkshire
Equity Commitment pursuant to which Berkshire Hathaway has agreed to
purchase up to $3.5 billion of MEHC’s common equity upon any requests
authorized from time to time by MEHC’s Board of Directors. The proceeds of any
such equity contribution shall only be used for the purpose of (i) paying
when due MEHC’s debt obligations and (ii) funding the general corporate
purposes and capital requirements of MEHC’s regulated subsidiaries. The
Berkshire Equity Commitment expires on February 28,
2011.
|
(3)
|
MEHC had
a $250 million credit facility that was terminated by the Company in
October 2009 and is included in the above table. MidAmerican Energy
had a $250 million credit facility that was terminated by MidAmerican
Energy in the third quarter of 2009 and is excluded from the above
table. For further discussion regarding the Company’s credit facilities,
refer to Note 10 of Notes to Consolidated Financial Statements in
Item 8 of the Company’s Annual Report on Form 10-K for the year
ended December 31, 2008.
|
(4)
|
An
inability of financial institutions to honor their commitments could
adversely affect the Company’s short-term liquidity and ability to meet
long-term commitments.
|
The
Company’s cash and cash equivalents were $744 million as of
September 30, 2009, compared to $280 million as of December 31,
2008. The Company has restricted cash and investments included in other current
assets and investments and other assets on the Consolidated Balance Sheets
totaling $420 million and $395 million as of September 30, 2009
and December 31, 2008, respectively, related to (i) the Company’s debt
service reserve requirements relating to certain projects, (ii) funds held in
trust related to nuclear decommissioning and coal mine reclamation and (iii) unpaid dividends
declared obligations. The debt service funds are restricted by their respective
project debt agreements to be used only for the related project.
36
Operating
Activities
Net cash
flows from operating activities for the nine-month periods ended
September 30, 2009 and 2008 were $2.983 billion and
$2.005 billion, respectively. Operating cash flows for the nine-month
period ended September 30, 2009, include $140 million of net cash
flows related to the Constellation Energy transaction, which is comprised of
$536 million of proceeds received from the sale of Constellation Energy
common stock and $396 million of income tax paid on gains recognized on the
termination of the Constellation Energy merger agreement in December 2008
and the sale of stock in 2009. The remaining increase in operating cash flows
was due to higher income tax receipts, changes in collateral posted for
derivative contracts and working capital, partially offset by the impact from
the foreign currency exchange rate. Income tax receipts were higher due
primarily to lower pre-tax income, the current repairs deduction and additional
production tax credits.
Investing
Activities
Net cash
flows from investing activities for the nine-month periods ended
September 30, 2009 and 2008 were $(1.846) billion and
$(3.569) billion, respectively. In February 2008, the Company received
proceeds from the maturity of a guaranteed investment contract of
$393 million. In September 2008, the Company made a $1.0 billion
investment in Constellation Energy’s 8% preferred stock and acquired Chehalis
Power Generation, LLC for $308 million. In December 2008, MEHC and
Constellation Energy entered into a termination agreement, which resulted in,
among other things, the conversion of the $1.0 billion investment in
Constellation Energy’s 8% preferred stock into $1.0 billion of
14% Senior Notes due from Constellation Energy. In January 2009, the
Company received $1.0 billion, plus accrued interest, in full satisfaction
of the 14% Senior Notes from Constellation Energy. In July 2009, the
Company purchased 225 million shares, representing approximately a 10%
interest, of BYD Company Limited common stock for $232 million. Capital
expenditures decreased $86 million due primarily to lower capital
expenditures in 2009 associated with the construction of wind-powered generating
facilities at MidAmerican Funding, partially offset by higher capital
expenditures at PacifiCorp associated with wind-powered generating facilities,
including payments for wind-powered facilities placed in-service in
December 2008, and transmission system investment.
Capital
Expenditures
Capital
expenditures by reportable segment are summarized as follows (in
millions):
Nine-Month
Periods
|
||||||||
Ended
September 30,
|
||||||||
2009
|
2008
|
|||||||
Capital
expenditures(1):
|
||||||||
PacifiCorp
|
$ | 1,766 | $ | 1,111 | ||||
MidAmerican
Funding
|
348 | 1,104 | ||||||
Northern
Natural Gas
|
140 | 112 | ||||||
CE Electric UK
|
297 | 328 | ||||||
Other
|
41 | 23 | ||||||
Total
capital expenditures
|
$ | 2,592 | $ | 2,678 |
(1)
|
Excludes
amounts for non-cash equity AFUDC.
|
37
The
Company’s capital expenditures relate primarily to PacifiCorp and MidAmerican
Energy. Combined, both utilities’ capital expenditures consisted mainly of the
following for the nine-month periods ended September 30:
2009:
·
|
Transmission
system investment totaling $573 million, including a major segment of
the Energy Gateway Transmission Expansion Project at
PacifiCorp.
|
·
|
The
development and construction of wind-powered generating facilities
totaling $391 million. During 2009, PacifiCorp placed in service
265.5 megawatts (“MW”) of wind-powered generating
facilities.
|
·
|
Emissions
control equipment totaling
$246 million.
|
·
|
Distribution,
generation, mining and other infrastructure needed to serve existing and
expected growing demand totaling
$904 million.
|
2008:
·
|
The
development and construction of wind-powered generating facilities
totaling $1.08 billion.
|
·
|
Emissions
control equipment totaling
$198 million.
|
·
|
Transmission
system investment totaling
$164 million.
|
·
|
Distribution,
generation, mining and other infrastructure needed to serve existing and
expected growing demand totaling
$773 million.
|
Financing
Activities
Net cash
flows from financing activities for the nine-month period ended
September 30, 2009 were $(676) million. Uses of cash totaled
$1.918 billion and consisted mainly of $667 million for repayments of
MEHC subordinated debt, $506 million for net repayments of subsidiary
short-term debt, $383 million for repayments of subsidiary debt,
$216 million for net repayments of the MEHC revolving credit facility and
$123 million for net purchases of common stock. Sources of cash totaled
$1.242 billion and consisted of proceeds from the issuance of subsidiary
debt totaling $992 million and proceeds from the issuance of MEHC senior
debt totaling $250 million.
Net cash
flows from financing activities for the nine-month period ended
September 30, 2008 were $920 million. Sources of cash totaled
$3.421 billion and consisted mainly of proceeds from the issuance of MEHC
senior and subordinated debt totaling $1.649 billion, subsidiary debt
totaling $1.498 billion and the net proceeds from subsidiary short-term
debt totaling $274 million. Uses of cash totaled $2.501 billion and
consisted mainly of $1.213 billion for repayments and purchases of
subsidiary debt, $1.167 billion for repayments of MEHC senior and
subordinated debt and a $99 million net payment of hedging instruments
related to the maturity of United States dollar denominated debt at CE Electric
UK.
Long-term
Debt
In
July 2009, MEHC issued $250 million of its 3.15% Senior Notes due
July 15, 2012. The net proceeds are being used for general corporate
purposes.
In
January 2009, PacifiCorp issued $350 million of its 5.5% First
Mortgage Bonds due January 15, 2019 and $650 million of its 6.0% First
Mortgage Bonds due January 15, 2039. The net proceeds were used to repay
short-term debt and are being used to fund capital expenditures and for general
corporate purposes.
In
January 2009, MEHC repaid the remaining $500 million to affiliates of
Berkshire Hathaway in full satisfaction of the aggregate amount owed pursuant to
the $1 billion of 11% mandatory redeemable trust preferred securities
issued by MidAmerican Capital Trust IV to affiliates of Berkshire Hathaway
in September 2008.
Future Uses of
Cash
The
Company has available a variety of sources of liquidity and capital resources,
both internal and external, including net cash flows from operating activities,
public and private debt offerings, the issuance of commercial paper, the use of
unsecured revolving credit facilities, the issuance of equity and other sources.
These sources are expected to provide funds required for current operations,
capital expenditures, acquisitions, investments, debt retirements and other
capital requirements. The availability and terms under which each subsidiary has
access to external financing depends on a variety of factors, including its
credit rating, investors’ judgment of risk and conditions in the overall capital
market, including the condition of the utility industry in general.
Additionally, the Berkshire Equity Commitment can be used for the purpose of
(i) paying when due MEHC’s debt obligations and (ii) funding the
general corporate purposes and capital requirements of MEHC’s regulated
subsidiaries. Berkshire Hathaway will have up to 180 days to fund any such
request in increments of at least $250 million pursuant to one or more drawings
authorized by MEHC’s Board of Directors. The funding of any such drawing will be
made by means of a cash equity contribution to MEHC in exchange for additional
shares of MEHC’s common stock. The Berkshire Equity Commitment expires on
February 28, 2011.
38
Capital
Expenditures
The
Company has significant future capital requirements. Forecasted capital
expenditures for 2009, which exclude non-cash equity AFUDC, are approximately
$3.4 billion. Capital expenditure needs are reviewed regularly by
management and may change significantly as a result of such reviews, which may
consider, among other factors, changes in rules and regulations, including
environmental and nuclear, changes in income tax laws, general business
conditions, load projections, system reliability standards, the cost and
efficiency of construction labor, equipment and materials, and the cost and
availability of capital.
Forecasted
capital expenditures for 2009 include the following:
·
|
PacifiCorp
expects to spend $524 million for the Energy Gateway Transmission
Expansion Project, which includes the construction of a 135-mile,
double-circuit, 345-kilovolt transmission line to be built between the
Populus substation located in southern Idaho and the Terminal substation
located in the Salt Lake City, Utah area, one of the first major segments
of the project.
|
·
|
Combined,
PacifiCorp and MidAmerican Energy anticipate spending $445 million on
wind-powered generating facilities.
|
·
|
Combined,
PacifiCorp and MidAmerican Energy are projecting to spend
$392 million for emissions control equipment in
2009.
|
·
|
Remaining
amounts are for distribution, transmission, generation, mining and other
infrastructure needed to serve existing and expected growing
demand.
|
The above
estimates also include PacifiCorp’s commitments for investments in emissions
reduction technology resulting from MEHC’s acquisition of PacifiCorp as
discussed further in Note 18 of Notes to Consolidated Financial Statements
in Item 8 of the Company’s Annual Report on Form 10-K. Evaluation and
development efforts are in progress related to additional prospective
wind-powered generating facilities scheduled for completion during and after
2009.
MidAmerican
Energy continues to evaluate additional cost-effective wind-powered generation.
In March 2009, MidAmerican Energy filed with the Iowa Utilities Board for
its approval of a settlement agreement between MidAmerican Energy and the Iowa
Office of Consumer Advocate (“OCA”) in conjunction with MidAmerican Energy’s
ratemaking principles application to construct up to 1,001 MW (nameplate
ratings) of additional wind-powered generation in Iowa through 2012. MidAmerican
Energy has not entered into any material contracts for the development or
construction of new wind-powered generation or the purchase of any related wind
turbines.
The
Company is subject to federal, state, local and foreign laws and regulations
with regard to air and water quality, hazardous and solid waste disposal,
protected species and other environmental matters that have the potential to
impact the Company’s current and future operations. The future costs (beyond
existing planned capital expenditures) of complying with applicable
environmental laws, regulations and rules cannot yet be reasonably estimated but
could be material to the Company. The Company is not aware of any proven,
commercially available technology that eliminates or captures and stores carbon
dioxide emissions from coal-fired and natural gas-fired generating facilities,
and the Company is uncertain when, or if, such technology will be commercially
available. Refer to the “Environmental Regulation” section of Item 1 of the
Company’s Annual Report on Form 10-K for the year ended December 31, 2008,
Note 12 of Notes to Consolidated Financial Statements included in
Item 1 of this Form 10-Q and the “Environmental Regulation” section of
this Form 10-Q for a detailed discussion of environmental matters affecting
the Company.
39
Contractual
Obligations
Subsequent
to December 31, 2008, there were no material changes outside the normal
course of business in contractual obligations from the information provided in
Item 7 of the Company’s Annual Report on Form 10-K for the year ended
December 31, 2008, other than the 2009 debt issuances previously discussed.
Additionally, refer to the “Capital Expenditures” discussion included in
“Liquidity and Capital Resources.”
Regulatory
Matters
In
addition to the updates contained herein regarding updates to regulatory matters
based upon material changes that occurred subsequent to December 31, 2008,
refer to Note 4 of Notes to Consolidated Financial Statements included in
Item 1 of this Form 10-Q for additional regulatory matter
updates.
PacifiCorp
Utah
In
July 2008, PacifiCorp filed a general rate case with the Utah Public
Service Commission (the “UPSC”) requesting an annual increase of
$161 million prior to any consideration of the UPSC’s order in the
2007 general rate case. In September 2008, PacifiCorp filed
supplemental testimony that reflected then-current revenues and other
adjustments based on the August 2008 order in the 2007 general rate case.
The supplemental filing reduced PacifiCorp’s request to $115 million. In
October 2008, the UPSC issued an order changing the test period from the
twelve months ending June 2009 using end-of-period rate base to the
forecast calendar year 2009 using average rate base. In December 2008,
PacifiCorp updated its filing to reflect the change in the test period. The
updated filing proposed an increase of $116 million. In March 2009, a
settlement agreement was filed with the UPSC resolving all remaining revenue
requirement issues resulting in parties agreeing, among other settlement terms,
on an annual increase of $45 million, or an average price increase of 3%,
effective May 8, 2009. In April 2009, the UPSC issued its final order
approving the revenue requirement settlement agreement.
In
March 2009, Utah’s governor signed Senate Bill 75 that provides
additional regulatory tools for the UPSC to use in the rate making process. The
additional tools provided in the legislation allow for single item cost recovery
of major capital investments outside of the general rate case process and allow
for, but do not require, the use of an energy balancing account.
In
March 2009, PacifiCorp filed for an energy cost adjustment mechanism
(“ECAM”) with the UPSC. The filing recommends that the UPSC adopt the ECAM to
recover the difference between base net power costs set in the next Utah general rate case and
actual net power costs. The UPSC has separated the application into two phases
to first address whether the mechanism is in the public interest, and then if it
is found to be in the public interest, determine the type of mechanism that
should be implemented. The public interest phase is scheduled for completion in
January 2010.
In June
2009, PacifiCorp filed a general rate case with the UPSC for an increase of
$67 million, or an average price increase of 5%. If approved, rates will be
effective February 18, 2010. The forecasted test period is the twelve
months ending June 30, 2010.
In June
2009, PacifiCorp filed with the UPSC to increase its demand-side management
(“DSM”) cost recovery mechanism in Utah from an average of 2% of a customer’s
eligible monthly charges to 6%. In August 2009, a settlement agreement was filed
with the UPSC requesting the DSM cost recovery mechanism be adjusted to 5%,
representing an estimated annual increase of $35 million, which would
enable PacifiCorp to continue to fund ongoing DSM programs and to recover
previously incurred DSM expenditures. The UPSC approved the settlement agreement
in August 2009, and the 5% DSM cost recovery mechanism became effective
September 1, 2009.
Oregon
In
March 2009, PacifiCorp made the initial filing for the annual transition
adjustment mechanism (“TAM”) with the Oregon Public Utility Commission (“OPUC”)
for an annual increase of $21 million to recover the anticipated net power
costs for the year beginning January 1, 2010. In August 2009,
PacifiCorp filed a revision to its anticipated net power costs for the TAM,
reflecting a slight decrease in the overall request to $20 million. In
September 2009, PacifiCorp filed a settlement stipulation with the OPUC
reducing the requested increase to $4 million, or an average price increase
of less than 1%. In October 2009, the OPUC issued an order approving the
settlement stipulation. The TAM is subject to updates for the forward price
curve and new contracts in November 2009, at which time the final numbers
will be determined. The expected effective date for the TAM is January 1,
2010.
40
In
April 2009, PacifiCorp filed a general rate case with the OPUC requesting
an annual increase of $92 million. In August 2009, the requested
annual increase was reduced to $83 million. In September 2009,
PacifiCorp filed a settlement stipulation with the OPUC further reducing the
proposed annual increase to $42 million, or an average price increase of
4%. The stipulation agreement also includes three tariff riders to collect an
additional $8 million over a three-year period associated with various cost
initiatives. If approved, rates will be effective February 2,
2010.
Wyoming
In
July 2008, PacifiCorp filed a general rate case with the Wyoming Public
Service Commission (the “WPSC”) requesting an annual increase of
$34 million with an effective date of May 24, 2009. Power costs were
excluded from the filing and were addressed separately in PacifiCorp’s annual
power cost adjustment mechanism (“PCAM”) application filed in
February 2009. In October 2008, the general rate case request was
reduced by $5 million, to $29 million, to reflect a change in the
in-service date of the High Plains wind-powered generating facility. In
March 2009, a settlement agreement was filed with the WPSC requesting an
increase in Wyoming rates of $18 million annually, beginning May 24,
2009, for an average overall price increase of 4%. Following public hearings in
March 2009, the WPSC issued a final order approving the stipulation
agreement in May 2009.
In
February 2009, PacifiCorp filed its annual PCAM application with the WPSC.
The PCAM application requested recovery of the difference between actual net
power costs and the amount included in base rates, subject to certain
limitations, for the period December 1, 2007 through November 30,
2008, and establishes for the first time, an adjustment for the difference
between forecasted net power costs and the amount included in base rates for the
period December 1, 2008 through November 30, 2009. In the 2009 PCAM
application, PacifiCorp requested a $2 million reduction to the current
annual surcharge rate based on the results for the twelve-month period ended
November 30, 2008, as well as a $16 million increase to the annual
surcharge rate for the forecasted twelve-month period ending November 30,
2009, resulting in a net increase to the annual surcharge rate of
$14 million on a combined basis. In March 2009, the WPSC approved
PacifiCorp’s motion to implement an interim rate increase of $7 million
effective April 1, 2009 consistent with the interim PCAM increase agreed to
in the 2008 general rate case settlement agreement. In July 2009, a
stipulation agreement was signed by the major participants in the case
requesting that the April 2009 interim rate increase become the permanent
rate for the entire amortization period through March 31, 2010, effectively
reducing the net increase of $14 million sought in the application to
$7 million, or an average price increase of 1%. In August 2009, the
WPSC held a public hearing to consider the stipulation agreement, and after
considering the evidence, the WPSC issued a bench decision approving the
stipulation effective September 1, 2009.
In
October 2009, PacifiCorp filed a general rate case with the WPSC requesting
a rate increase of $71 million. Power costs are included in the general
rate case which reflects increased coal costs and the expiration of low cost
long-term power purchase contracts. The application is based on a test period
ending December 31, 2010. Two regulatory policy issues related to the tax
treatment of equity AFUDC and the accounting for coal stripping costs are
included in the case, which if approved by the WPSC, will reduce the rate
increase by $9 million for an overall increase of $62 million, or an
average price increase of 12%. The application requests a hearing date in
May 2010 and a rate effective date of August 1, 2010.
Washington
In
February 2009, PacifiCorp filed a general rate case with the WUTC for an
annual increase of $39 million. The filing included a request to begin
collection of a deferral for costs associated with the 520 MW Chehalis
natural gas-fired generating plant prior to its inclusion in rate base beginning
in January 2010. The associated costs are estimated at $15 million.
PacifiCorp has proposed to recover these costs through an extension in the
hydroelectric deferral mechanism and thereby not affecting current customer
rates. In August 2009, PacifiCorp filed an all-party settlement agreement
proposing an annual increase of $14 million, or an average price increase
of 5%. The WUTC is expected to make a decision in late 2009. If approved, rates
will be effective January 1, 2010.
41
Idaho
In
September 2008, PacifiCorp filed a general rate case with the Idaho Public
Utilities Commission (the “IPUC”) for an annual increase of
$6 million. In February 2009, a settlement signed by PacifiCorp, the
IPUC staff and intervening parties was filed with the IPUC resolving all issues
in the 2008 general rate case. The agreement stipulates a $4 million
increase, or 3% average price increase, for non-contract retail customers in
Idaho. As part of the stipulation, intervening parties acknowledged that
PacifiCorp’s acquisition of the 520-MW natural gas-fired Chehalis plant was
prudent and the investment should be included in PacifiCorp’s revenue
requirement, and that PacifiCorp has demonstrated that its demand-side
management programs are prudent. The parties also agreed on a base level of net
power costs for any future ECAM calculations. In April 2009, the IPUC
issued an order approving the stipulation effective April 18,
2009.
In
June 2009, an agreement was reached with parties to the ECAM docket
allowing for the implementation of an ECAM to recover the difference between
power costs recovered in rates and actual costs incurred, subject to the
calculation methodology of the mechanism. In September 2009, the IPUC
issued an order approving the ECAM stipulation as filed with an effective date
of July 1, 2009.
CE Electric UK
Distribution
Price Control Review 5
In March
2008, the Office of Gas and Electricity Markets (“Ofgem”) announced the
commencement of its next price control review that is expected to be effective
April 1, 2010. In February and June 2009, CE Electric UK submitted cost
forecasts for Northern Electric and Yorkshire Electricity and has responded to
consultation documents issued by Ofgem throughout the period of the review.
Industry wide and bilateral meetings have been held to discuss current issues
and the cost forecasts. In August 2009, Ofgem issued its initial proposals;
although a number of issues, notably treatment of pension costs and cost of
capital, have not been fully developed. Final proposals are expected to be
issued by Ofgem in late 2009. The impact, if any, of this price review on the
Company cannot be determined at this time.
Environmental
Regulation
In
addition to the updates contained herein, refer to Note 12 of Notes to
Consolidated Financial Statements included in Item 1 of this Form 10-Q
and Item 1 of the Company’s Annual Report on Form 10-K for the year ended
December 31, 2008 for additional information regarding certain
environmental matters affecting PacifiCorp’s and MidAmerican Energy’s
operations.
Climate
Change
As a
result of increased attention to global climate change in the United States,
there are significant future environmental regulations under consideration to
increase the deployment of clean energy technologies and regulate emissions of
greenhouse gases at the state, regional and federal levels. Congress and federal
policy makers are considering climate change legislation and a variety of
national climate change policies, such as the American Clean Energy and Security
Act of 2009 (“Waxman-Markey bill”) discussed in Note 12 of Notes to
Consolidated Financial Statements. In addition, governmental and nongovernmental
organizations and others have become more active in initiating litigation under
existing environmental and other laws.
In
April 2009, the United States Environmental Protection Agency (the “EPA”)
issued a proposed finding, in response to the United States Supreme Court’s 2007
decision in the case of Massachusetts v. EPA, that
under Section 202(a) of the Clean Air Act six greenhouse gases – carbon dioxide,
methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur
hexafluoride – threaten the public health and welfare of current and future
generations. The finding does not include any proposed regulations regarding
greenhouse gas emissions; however, such regulatory or legislative action could
have a significant adverse impact on PacifiCorp’s and MidAmerican Energy’s
current and future fossil-fueled generating facilities. In September 2009,
in anticipation of the regulation of greenhouse gases under Section 202(a) of
the Clean Air Act, the EPA released a proposed greenhouse gas “tailoring” rule
which would require new or modified facilities with increased greenhouse gas
emissions in excess of 25,000 tons per year of carbon dioxide equivalent
emissions to undergo a best available control technology review. In addition,
the proposal would require the incorporation of greenhouse gas emissions under
Title V operating permits.
42
In
September 2009, the United States Court of Appeals for the Second Circuit
(the “Second Circuit”) issued its opinion in the case of Connecticut v. American Electric
Power, which remanded to the lower court a nuisance action by eight
states and the City of New York against five large utility emitters of carbon
dioxide. The United States District Court for the Southern District of New York
(the “Southern District of New York”) dismissed the case in 2005, holding that
the claims that emissions of greenhouse gases from the defendants’ coal-fueled
generating facilities were causing harmful climate change and should be enjoined
as a public nuisance under federal common law presented a “political question”
that the court lacked jurisdiction to decide. The Second Circuit rejected the
Southern District of New York’s conclusion that the plaintiffs’ claims were
barred from consideration as a political question and the Southern District of
New York was not precluded from determining the case on its merits. The Company
cannot predict the outcome of this litigation or its potential impact at this
time.
In
October 2009, a three judge panel in the United States Court of Appeals for
the Fifth Circuit (the “Fifth Circuit”) issued its opinion in the case of Ned Comer, et al. v. Murphy Oil USA,
et al., a putative class action lawsuit against insurance, oil, coal and
chemical companies, based on claims that the defendants’ emissions of greenhouse
gases contributed to global warming that in turn caused a rise in sea levels and
added to the ferocity of Hurricane Katrina, which combined to destroy the
plaintiff’s private property, as well as public property. In 2007, the United
States District Court for the Southern District of Mississippi (the “Southern
District of Mississippi”) had dismissed the case based on the lack of standing
and further held that the claims were barred by the political question doctrine.
The Fifth Circuit reversed the lower court decision and held that the plaintiffs
had standing to assert their public and private nuisance, trespass, and
negligence claims and concluded that the claims did not present a political
question. The case was remanded to the Southern District of Mississippi for
further proceedings with the court noting that it had not determined, and would
leave to the lower court to analyze, whether the alleged chain of causation
satisfies the proximate cause requirement under Mississippi state common
law.
In
October 2009, the United States District Court for the Northern District of
California (the “Northern District of California”) granted the defendants’
motions to dismiss in the case of Native Village of Kivalina v.
ExxonMobil Corporation, et al. The plaintiffs filed their complaint in
February 2008, asserting claims against 24 defendants, including electric
generating companies, oil companies and a coal company, for public nuisance
under state and federal common law based on the defendants’ greenhouse gas
emissions. MEHC was a named defendant in the Kivalina case. The Northern
District of California dismissed all of the plaintiffs’ federal claims, holding
that the court lacked subject matter jurisdiction to hear the claims under the
political question doctrine, and that the plaintiffs lacked standing to bring
their claims. The Northern District of California declined to hear the state law
claims and the case was dismissed with prejudice to their future presentation in
an appropriate state court.
Credit
Ratings
MEHC’s
senior unsecured debt credit ratings are as follows: Moody’s Investors Service,
“Baa1/stable;” Standard & Poor’s, “BBB+/stable;” and Fitch Ratings,
“BBB+/stable.” Debt and preferred securities of MEHC and certain of its
subsidiaries are rated by nationally recognized credit rating agencies. Assigned
credit ratings are based on each rating agency’s assessment of the rated
company’s ability to, in general, meet the obligations of its issued debt or
preferred securities. The credit ratings are not a recommendation to buy, sell
or hold securities, and there is no assurance that a particular credit rating
will continue for any given period of time.
MEHC and
its subsidiaries have no credit rating downgrade triggers that would accelerate
the maturity dates of outstanding debt and a change in ratings is not an event
of default under the applicable debt instruments. The Company’s unsecured
revolving credit facilities do not require the maintenance of a minimum credit
rating level in order to draw upon their availability, but under certain
instances must maintain sufficient covenant tests if ratings drop below a
certain level. However, commitment fees and interest rates under the credit
facilities are tied to credit ratings and increase or decrease when the ratings
change. A ratings downgrade could also increase the future cost of commercial
paper, short- and long-term debt issuances or new credit
facilities.
43
In
accordance with industry practice, certain agreements, including derivative
contracts, contain provisions that require certain of MEHC’s subsidiaries,
principally PacifiCorp and MidAmerican Energy, to maintain specific credit
ratings on their unsecured debt from one or more of the major credit ratings
agencies. These agreements, including derivative contracts, may either
specifically provide bilateral rights to demand cash or other security if credit
exposures on a net basis exceed specified rating-dependent threshold levels
(“credit-risk-related contingent features”) or provide the right for
counterparties to demand “adequate assurance” in the event of a material adverse
change in the subsidiary’s creditworthiness. These rights can vary by contract
and by counterparty. As of September 30, 2009, these subsidiary’s credit
ratings from the three recognized credit rating agencies were investment grade.
If all credit-risk-related contingent features or adequate assurance provisions
for these agreements, including derivative contracts, had been triggered as of
September 30, 2009, the Company would have been required to post
$557 million of additional collateral. The Company’s collateral
requirements could fluctuate considerably due to market price volatility,
changes in credit ratings or other factors. Refer to Note 6 of Notes to
Consolidated Financial Statements included in Item 1 of this Form 10-Q
for a discussion of the Company’s collateral requirements specific to the
Company’s derivative contracts.
New
Accounting Pronouncements
For a
discussion of new accounting pronouncements affecting the Company, refer to
Note 2 of Notes to Consolidated Financial Statements included in
Item 1 of this Form 10-Q.
Critical
Accounting Policies
Certain
accounting policies require management to make estimates and judgments
concerning transactions that will be settled several years in the future.
Amounts recognized in the Consolidated Financial Statements from such estimates
are necessarily based on numerous assumptions involving varying and potentially
significant degrees of judgment and uncertainty. Accordingly, the amounts
currently reflected in the Consolidated Financial Statements will likely
increase or decrease in the future as additional information becomes available.
Estimates are used for, but not limited to, the accounting for the effects of
certain types of regulation, derivatives, impairment of long-lived assets and
goodwill, pension and other postretirement benefits, income taxes and revenue
recognition - unbilled revenue. For additional discussion of the Company’s
critical accounting policies, see Item 7 of the Company’s Annual Report on
Form 10-K for the year ended December 31, 2008. The Company’s critical
accounting policies have not changed materially since December 31,
2008.
Quantitative
and Qualitative Disclosures About Market
Risk
|
For
quantitative and qualitative disclosures about market risk affecting the
Company, see Item 7A of the Company’s Annual Report on Form 10-K for
the year ended December 31, 2008. The Company’s exposure to market risk and
its management of such risk has not changed materially since December 31,
2008. Refer to Note 6 of Notes to Consolidated Financial Statements
included in Item 1 of this Form 10-Q for disclosure of the Company’s
derivative positions as of September 30, 2009.
Controls
and Procedures
|
At the
end of the period covered by this Quarterly Report on Form 10-Q, the Company
carried out an evaluation, under the supervision and with the participation of
the Company’s management, including the Chief Executive Officer (principal
executive officer) and the Chief Financial Officer (principal financial
officer), of the effectiveness of the design and operation of the Company’s
disclosure controls and procedures (as defined in Rule 13a-15(e) promulgated
under the Securities and Exchange Act of 1934, as amended). Based upon that
evaluation, the Company’s management, including the Chief Executive Officer
(principal executive officer) and the Chief Financial Officer (principal
financial officer), concluded that the Company’s disclosure controls and
procedures were effective to ensure that information required to be disclosed by
the Company in the reports that it files or submits under the Exchange Act is
recorded, processed, summarized and reported within the time periods specified
in the SEC’s rules and forms, and is accumulated and communicated to management,
including the Company’s Chief Executive Officer (principal executive officer)
and Chief Financial Officer (principal financial officer), or persons performing
similar functions, as appropriate to allow timely decisions regarding required
disclosure. There has been no change in the Company’s internal control over
financial reporting during the quarter ended September 30, 2009 that has
materially affected, or is reasonably likely to materially affect, the Company’s
internal control over financial reporting.
44
PART
II
Legal
Proceedings
|
For a
description of certain legal proceedings affecting the Company, refer to
Item 3 of the Company’s Annual Report on Form 10-K for the year ended
December 31, 2008. Refer to Note 12 of Notes to Consolidated Financial
Statements included in Part I, Item 1 of this Form 10-Q for
material developments since December 31, 2008.
Risk
Factors
|
Except as
discussed below, there has been no material change to the Company’s risk factors
from those disclosed in Item 1A of the Company’s Annual Report on
Form 10-K for the year ended December 31, 2008.
Our
regulated businesses are subject to extensive regulations and legislation that
affect their operations and costs. These regulations and laws are complex,
dynamic and subject to change.
In
June 2009, the United States House of Representatives passed the American
Clean Energy and Security Act of 2009 (“Waxman-Markey bill”), introduced by
Representatives Henry Waxman and Edward Markey. In addition to a federal
renewable portfolio standard, which would require utilities to obtain a portion
of their energy from certain qualifying renewable sources, and energy efficiency
measures, the bill requires a reduction in greenhouse gas emissions beginning in
2012, with emission reduction targets of 3% below 2005 levels by 2012; 17% below
2005 levels by 2020; 42% below 2005 levels by 2030; and 83% below 2005 levels by
2050 under a “cap and trade” program. In September 2009, a similar bill was
introduced in the United States Senate by Senators Barbara Boxer and John Kerry,
which would require an initial reduction in greenhouse gas emissions beginning
in 2012 with emission reduction targets consistent with the Waxman-Markey
bill, with the exception of the 2020 target, which requires 20% reduction below
2005 levels. If the Waxman-Markey bill or some other federal comprehensive
climate change bill were to pass both Houses of Congress and be signed into law
by the President, the impact on our financial performance could be material and
would depend on a number of factors, including the required timing and level of
greenhouse gas reductions, the price and availability of offsets and allowances
used for compliance and our ability to receive revenue from customers for
increased costs. The new law would likely result in increased operating costs
and expenses, additional capital expenditures and asset retirements and may
negatively impact demand for electricity. To the extent that our regulated
subsidiaries are not allowed by their regulators to recover or cannot otherwise
recover the costs to comply with climate change requirements, these requirements
could have a material adverse impact on our consolidated financial results.
Additionally, even if such costs are recoverable in rates, if they are
substantial and result in rates increasing to levels that substantially reduce
customer demand, this could have a material adverse impact on our consolidated
financial results.
Unregistered
Sales of Equity Securities and Use of
Proceeds
|
Not
applicable.
Defaults
Upon Senior Securities
|
Not
applicable.
Submission
of Matters to a Vote of Security
Holders
|
Not
applicable.
Other
Information
|
Not
applicable.
Exhibits
|
The
exhibits listed on the accompanying Exhibit Index are filed as part of this
Quarterly Report.
45
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:
November 6, 2009
|
/s/ Patrick J. Goodman
|
Patrick
J. Goodman
|
|
Senior
Vice President and Chief Financial Officer
|
|
(principal
financial and accounting
officer)
|
46
Exhibit No.
|
Description
|
15
|
Awareness
Letter of Independent Registered Public Accounting
Firm.
|
31.1
|
Principal
Executive Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
31.2
|
Principal
Financial Officer Certification Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
32.1
|
Principal
Executive Officer Certification Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
32.2
|
Principal
Financial Officer Certification Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
47