form10_q.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
Form
10-Q
[X] QUARTERLY
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
For
the quarterly period ended June 30, 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
File No. 1-15973
NORTHWEST
NATURAL GAS COMPANY
(Exact
name of registrant as specified in its charter)
Oregon
|
93-0256722
|
(State
or other jurisdiction of
incorporation
or organization)
|
(I.R.S.
Employer
Identification
No.)
|
220
N.W. Second Avenue, Portland, Oregon 97209
(Address
of principal executive offices) (Zip Code)
Registrant’s
telephone number, including area code: (503) 226-4211
Indicate by check mark whether
the registrant: (1) has filed all reports required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90
days. Yes [ X ] No [ ]
Indicate by 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 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
definitions of “large accelerated filer,” “accelerated filer,” and “smaller
reporting company” in Rule 12b-2 of the Exchange Act.
|
|
Large
accelerated filer [ X ]
|
Accelerated filer [ ]
|
Non-accelerated filer [ ]
|
Smaller reporting company
[ ]
|
Indicate by check mark whether
the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes [ ] No [ X ]
At July
31, 2009, 26,513,188 shares of the registrant’s Common Stock (the only class of
Common Stock) were outstanding.
NORTHWEST NATURAL GAS COMPANY
For the
Quarterly Period Ended June 30, 2009
|
|
|
|
PART
I. FINANCIAL INFORMATION
|
|
|
|
Page Number
|
|
|
1
|
|
|
|
Item
1.
|
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3
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4
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6
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7
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Item
2.
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22
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Item
3.
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43
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Item
4.
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44
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|
|
PART
II. OTHER INFORMATION
|
|
|
|
|
Item
1.
|
|
45
|
|
|
|
Item
1A.
|
|
45
|
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|
|
Item
2.
|
|
45
|
|
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|
Item
4.
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|
46
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Item
5.
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46
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Item
6.
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46
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47
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Statements
and information included in this report that are not purely historical are
forward-looking statements within the “safe harbor” provisions and meaning of
Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act).
Forward-looking statements include any statement other than a statement of
purely historical fact, but are not limited to, statements concerning plans,
objectives, goals, business and financial strategies, future events or
performance or operational efficiencies, trends, cyclicality and the seasonality
of our business, growth, capitalization, company ratings, development of
projects, future cost of gas or our ability to manage such costs, customer
rates, gains or losses from our share of gas costs that are less than or more
than the gas costs embedded in customer rates, acquisition of new gas supplies,
workforce levels, cost reduction efforts, estimated expenditures, budgets,
capital and construction costs, and future cash flows, costs of compliance,
impact of accounting policies and standards, potential efficiencies, impacts of
new laws and regulations, projected obligations and liabilities under retirement
plans, adequacy of and shift in mix of gas supplies, and adequacy of accruals
and regulatory deferrals. Such statements are expressed in good faith
and we believe have a reasonable basis; however, each forward-looking statement
involves uncertainties and is qualified in its entirety by reference to the
following important factors, among others, that could cause our actual results
to differ materially from those projected, including:
|
·
|
prevailing
state and federal governmental policies and regulatory actions with
respect to allowed rates of return, industry and rate structure, timely
and adequate regulatory recovery of deferred costs, including, but not
limited to, purchased gas cost and investment recovery, acquisitions and
dispositions of assets and facilities, operation and construction of plant
facilities, present or prospective wholesale and retail competition,
changes in laws and regulations including but not limited to tax laws and
policies, changes in and compliance with environmental and safety laws,
regulations, policies and orders, and laws, regulations and orders with
respect to the maintenance of pipeline integrity, including regulatory
allowance or disallowance of costs based on regulatory prudency
reviews;
|
|
·
|
economic
factors that could cause a severe downturn in the economy, in particular
the economies of Oregon and Washington, thus affecting demand for natural
gas;
|
|
·
|
unanticipated
customer growth or decline and changes in market demand caused by changes
in demographic or customer consumption
patterns;
|
|
·
|
the
creditworthiness of customers, suppliers and financial derivative
counterparties;
|
|
·
|
market
conditions and pricing of natural gas relative to other energy
sources;
|
|
·
|
sufficiency
of our liquidity position and unanticipated changes that may affect our
liquidity or access to capital markets, including volatility in the credit
markets and financial services
sector;
|
|
·
|
capital
market conditions, including their effect on financing costs, the fair
value of pension assets and pension and other postretirement benefit
costs;
|
|
·
|
application
of the Oregon Public Utility Commission rules interpreting Oregon
legislation intended to ensure that utilities do not collect more income
taxes in rates than they actually pay to government
entities;
|
|
·
|
weather
conditions, natural phenomena including earthquakes or other geohazard
events, and other pandemic events;
|
|
·
|
competition
for retail and wholesale customers and our ability to remain price
competitive;
|
|
·
|
our
ability to access sufficient gas supplies and our dependence on a single
pipeline transportation company for natural gas
transmission;
|
|
·
|
property
damage associated with a pipeline safety incident, as well as risks
resulting from uninsured damage to our property, intentional or
otherwise;
|
|
·
|
financial
and operational risks, estimates and projections relating to business
development and investment activities, including the Gill Ranch
underground gas storage facility and Palomar
pipeline;
|
|
·
|
unanticipated
changes in interest rates, foreign currency exchange rates or in rates of
inflation;
|
|
·
|
changes
in estimates of potential liabilities relating to environmental
contingencies or in timely and adequate regulatory or insurance recovery
for such liabilities;
|
|
·
|
unanticipated
changes in future liabilities and legislation relating to employee benefit
plans, including changes in key
assumptions;
|
|
·
|
our
ability to transfer knowledge of our aging workforce and maintain a
satisfactory relationship with the union that represents a majority of our
workers;
|
|
·
|
potential
inability to obtain permits, rights of way, easements, leases or other
interests or other necessary authority to construct pipelines, develop
storage or complete other system expansions and the timing of such
projects;
|
|
·
|
federal,
state or other regulatory actions related to climate change;
and
|
|
·
|
legal
and administrative proceedings and
settlements.
|
These
forward-looking statements involve risks and uncertainties. We may
make other forward-looking statements from time to time, including statements in
press releases and public conference calls and webcasts. All
forward-looking statements made by us are based on information available to us
at the time the statements are made and speak only as of the date on which such
statement is made. We undertake no obligation to update any
forward-looking statement to reflect events or circumstances after the date on
which such statement is made or to reflect the occurrence of unanticipated
events. New factors emerge from time to time and it is not possible for us to
predict all such factors, nor can we assess the impact of each such factor or
the extent to which any factor, or combination of factors, may cause results to
differ materially from those contained in any forward-looking statement. Some of
these risks and uncertainties are discussed in our 2008 Annual Report on Form
10-K, Part I, Item 1A., “Risk Factors” and Part II, Item 7. and Item 7A.,
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and “Quantitative and Qualitative Disclosures About Market Risk,”
respectively.
NORTHWEST NATURAL GAS COMPANY
PART
I. FINANCIAL INFORMATION
Consolidated
Statements of Income
(Unaudited)
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
Thousands,
except per share amounts
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Operating
revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross
operating revenues
|
|
$ |
149,060 |
|
|
$ |
191,254 |
|
|
$ |
586,415 |
|
|
$ |
578,948 |
|
Less: Cost
of sales
|
|
|
79,388 |
|
|
|
124,010 |
|
|
|
363,562 |
|
|
|
369,930 |
|
Revenue
taxes
|
|
|
3,753 |
|
|
|
4,672 |
|
|
|
14,295 |
|
|
|
14,023 |
|
Net
operating revenues
|
|
|
65,919 |
|
|
|
62,572 |
|
|
|
208,558 |
|
|
|
194,995 |
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operations
and maintenance
|
|
|
30,171 |
|
|
|
25,840 |
|
|
|
64,126 |
|
|
|
54,298 |
|
General
taxes
|
|
|
6,572 |
|
|
|
6,722 |
|
|
|
15,063 |
|
|
|
14,856 |
|
Depreciation
and amortization
|
|
|
15,365 |
|
|
|
17,957 |
|
|
|
30,887 |
|
|
|
35,662 |
|
Total
operating expenses
|
|
|
52,108 |
|
|
|
50,519 |
|
|
|
110,076 |
|
|
|
104,816 |
|
Income
from operations
|
|
|
13,811 |
|
|
|
12,053 |
|
|
|
98,482 |
|
|
|
90,179 |
|
Other
income and expense - net
|
|
|
732 |
|
|
|
1,940 |
|
|
|
1,622 |
|
|
|
2,113 |
|
Interest
charges - net of amounts capitalized
|
|
|
10,006 |
|
|
|
8,933 |
|
|
|
19,376 |
|
|
|
18,363 |
|
Income
before income taxes
|
|
|
4,537 |
|
|
|
5,060 |
|
|
|
80,728 |
|
|
|
73,929 |
|
Income
tax expense
|
|
|
1,451 |
|
|
|
1,763 |
|
|
|
30,279 |
|
|
|
27,464 |
|
Net
income
|
|
$ |
3,086 |
|
|
$ |
3,297 |
|
|
$ |
50,449 |
|
|
$ |
46,465 |
|
Average
common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
26,506 |
|
|
|
26,421 |
|
|
|
26,504 |
|
|
|
26,415 |
|
Diluted
|
|
|
26,607 |
|
|
|
26,571 |
|
|
|
26,603 |
|
|
|
26,564 |
|
Earnings
per share of common stock:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
0.12 |
|
|
$ |
0.12 |
|
|
$ |
1.90 |
|
|
$ |
1.76 |
|
Diluted
|
|
$ |
0.12 |
|
|
$ |
0.12 |
|
|
$ |
1.90 |
|
|
$ |
1.75 |
|
See Notes
to Consolidated Financial Statements.
NORTHWEST NATURAL GAS COMPANY
PART
I. FINANCIAL INFORMATION
Consolidated
Balance Sheets
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
Plant
and property:
|
|
|
|
|
|
|
|
|
|
Utility
plant
|
|
$ |
2,178,629 |
|
|
$ |
2,091,092 |
|
|
$ |
2,142,988 |
|
Less
accumulated depreciation
|
|
|
670,128 |
|
|
|
637,680 |
|
|
|
659,123 |
|
Utility
plant - net
|
|
|
1,508,501 |
|
|
|
1,453,412 |
|
|
|
1,483,865 |
|
Non-utility
property
|
|
|
84,696 |
|
|
|
72,242 |
|
|
|
74,506 |
|
Less
accumulated depreciation
|
|
|
9,849 |
|
|
|
8,537 |
|
|
|
9,314 |
|
Non-utility
property - net
|
|
|
74,847 |
|
|
|
63,705 |
|
|
|
65,192 |
|
Total
plant and property
|
|
|
1,583,348 |
|
|
|
1,517,117 |
|
|
|
1,549,057 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
31,107 |
|
|
|
5,242 |
|
|
|
6,916 |
|
Accounts
receivable
|
|
|
26,779 |
|
|
|
43,718 |
|
|
|
81,288 |
|
Accrued
unbilled revenue
|
|
|
18,122 |
|
|
|
19,685 |
|
|
|
102,688 |
|
Allowance
for uncollectible accounts
|
|
|
(3,520 |
) |
|
|
(3,013 |
) |
|
|
(2,927 |
) |
Regulatory
assets
|
|
|
89,179 |
|
|
|
5,748 |
|
|
|
147,319 |
|
Fair
value of non-trading derivatives
|
|
|
5,293 |
|
|
|
54,867 |
|
|
|
4,592 |
|
Inventories:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
69,183 |
|
|
|
32,910 |
|
|
|
86,134 |
|
Materials
and supplies
|
|
|
9,681 |
|
|
|
9,959 |
|
|
|
9,933 |
|
Income
taxes receivable
|
|
|
- |
|
|
|
- |
|
|
|
20,811 |
|
Prepayments
and other current assets
|
|
|
26,588 |
|
|
|
11,516 |
|
|
|
24,216 |
|
Total
current assets
|
|
|
272,412 |
|
|
|
180,632 |
|
|
|
480,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments,
deferred charges and other assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
270,044 |
|
|
|
173,321 |
|
|
|
288,470 |
|
Fair
value of non-trading derivatives
|
|
|
289 |
|
|
|
9,218 |
|
|
|
146 |
|
Other
investments
|
|
|
62,315 |
|
|
|
64,276 |
|
|
|
54,132 |
|
Other
|
|
|
16,103 |
|
|
|
11,417 |
|
|
|
5,377 |
|
Total
investments, deferred charges and other assets
|
|
|
348,751 |
|
|
|
258,232 |
|
|
|
348,125 |
|
Total
assets
|
|
$ |
2,204,511 |
|
|
$ |
1,955,981 |
|
|
$ |
2,378,152 |
|
See Notes
to Consolidated Financial Statements.
NORTHWEST NATURAL GAS COMPANY
PART
I. FINANCIAL INFORMATION
Consolidated
Balance Sheets
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Capitalization
and liabilities:
|
|
|
|
|
|
|
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
$ |
336,001 |
|
|
$ |
333,619 |
|
|
$ |
336,754 |
|
Earnings
invested in the business
|
|
|
325,506 |
|
|
|
293,313 |
|
|
|
296,005 |
|
Accumulated
other comprehensive income (loss)
|
|
|
(4,260 |
) |
|
|
(2,483 |
) |
|
|
(4,386 |
) |
Total
common stock equity
|
|
|
657,247 |
|
|
|
624,449 |
|
|
|
628,373 |
|
Long-term
debt
|
|
|
587,000 |
|
|
|
512,000 |
|
|
|
512,000 |
|
Total
capitalization
|
|
|
1,244,247 |
|
|
|
1,136,449 |
|
|
|
1,140,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
payable
|
|
|
90,610 |
|
|
|
67,700 |
|
|
|
248,000 |
|
Long-term
debt due within one year
|
|
|
- |
|
|
|
5,000 |
|
|
|
- |
|
Accounts
payable
|
|
|
50,055 |
|
|
|
75,786 |
|
|
|
94,422 |
|
Taxes
accrued
|
|
|
10,807 |
|
|
|
8,727 |
|
|
|
12,455 |
|
Interest
accrued
|
|
|
3,876 |
|
|
|
2,837 |
|
|
|
2,785 |
|
Regulatory
liabilities
|
|
|
30,789 |
|
|
|
84,370 |
|
|
|
20,456 |
|
Fair
value of non-trading derivatives
|
|
|
70,052 |
|
|
|
2,792 |
|
|
|
136,735 |
|
Other
current and accrued liabilities
|
|
|
33,343 |
|
|
|
32,251 |
|
|
|
36,467 |
|
Total
current liabilities
|
|
|
289,532 |
|
|
|
279,463 |
|
|
|
551,320 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
credits and other liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes and investment tax credits
|
|
|
273,384 |
|
|
|
221,266 |
|
|
|
257,831 |
|
Regulatory
liabilities
|
|
|
238,264 |
|
|
|
227,076 |
|
|
|
228,157 |
|
Pension
and other postretirement benefit liabilities
|
|
|
116,844 |
|
|
|
43,513 |
|
|
|
138,229 |
|
Fair
value of non-trading derivatives
|
|
|
8,844 |
|
|
|
2,732 |
|
|
|
21,646 |
|
Other
|
|
|
33,396 |
|
|
|
45,482 |
|
|
|
40,596 |
|
Total
deferred credits and other liabilities
|
|
|
670,732 |
|
|
|
540,069 |
|
|
|
686,459 |
|
Commitments
and contingencies (see Note 11)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
capitalization and liabilities
|
|
$ |
2,204,511 |
|
|
$ |
1,955,981 |
|
|
$ |
2,378,152 |
|
See Notes
to Consolidated Financial Statements.
NORTHWEST
NATURAL GAS COMPANY
PART
I. FINANCIAL INFORMATION
Consolidated
Statements of Cash Flows
(Unaudited)
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
50,449 |
|
|
$ |
46,465 |
|
Adjustments
to reconcile net income to cash provided by operations:
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
30,887 |
|
|
|
35,662 |
|
Deferred
income taxes and investment tax credits
|
|
|
15,405 |
|
|
|
14,028 |
|
Undistributed
gains from equity investments
|
|
|
(734 |
) |
|
|
(346 |
) |
Deferred
gas savings - net
|
|
|
15,616 |
|
|
|
(26,873 |
) |
Gain
on sale of non-utility investments
|
|
|
- |
|
|
|
(1,737 |
) |
Non-cash
expenses related to qualified defined benefit pension
plans
|
|
|
4,848 |
|
|
|
1,530 |
|
Contributions
to qualified defined benefit pension plans
|
|
|
(25,000 |
) |
|
|
- |
|
Deferred
environmental costs
|
|
|
(5,227 |
) |
|
|
(4,131 |
) |
Income
from life insurance investments
|
|
|
(2,002 |
) |
|
|
(978 |
) |
Settlement
of interest rate hedge
|
|
|
(10,096 |
) |
|
|
- |
|
Deferred
regulatory and other
|
|
|
(14,123 |
) |
|
|
(6,466 |
) |
Changes
in working capital:
|
|
|
|
|
|
|
|
|
Accounts
receivable and accrued unbilled revenue - net
|
|
|
141,173 |
|
|
|
84,224 |
|
Inventories
of gas, materials and supplies
|
|
|
17,203 |
|
|
|
37,075 |
|
Income
taxes receivable
|
|
|
20,811 |
|
|
|
- |
|
Prepayments
and other current assets
|
|
|
8,428 |
|
|
|
7,083 |
|
Accounts
payable
|
|
|
(44,177 |
) |
|
|
(45,684 |
) |
Accrued
interest and taxes
|
|
|
(557 |
) |
|
|
(4,400 |
) |
Other
current and accrued liabilities
|
|
|
(3,091 |
) |
|
|
2,634 |
|
Cash
provided by operating activities
|
|
|
199,813 |
|
|
|
138,086 |
|
Investing
activities:
|
|
|
|
|
|
|
|
|
Investment
in utility plant
|
|
|
(44,098 |
) |
|
|
(41,338 |
) |
Investment
in non-utility property
|
|
|
(10,330 |
) |
|
|
(5,110 |
) |
Proceeds
from sale of non-utility investments
|
|
|
- |
|
|
|
6,845 |
|
Proceeds
from life insurance
|
|
|
761 |
|
|
|
208 |
|
Other
|
|
|
(4,977 |
) |
|
|
(7,286 |
) |
Cash
used in investing activities
|
|
|
(58,644 |
) |
|
|
(46,681 |
) |
Financing
activities:
|
|
|
|
|
|
|
|
|
Common
stock issued (purchased) - net
|
|
|
(720 |
) |
|
|
2,589 |
|
Long-term
debt issued
|
|
|
75,000 |
|
|
|
- |
|
Change
in short-term debt
|
|
|
(170,241 |
) |
|
|
(75,400 |
) |
Cash
dividend payments on common stock
|
|
|
(20,937 |
) |
|
|
(19,808 |
) |
Other
|
|
|
(80 |
) |
|
|
349 |
|
Cash
used in financing activities
|
|
|
(116,978 |
) |
|
|
(92,270 |
) |
Increase
(decrease) in cash and cash equivalents
|
|
|
24,191 |
|
|
|
(865 |
) |
Cash
and cash equivalents - beginning of period
|
|
|
6,916 |
|
|
|
6,107 |
|
Cash
and cash equivalents - end of period
|
|
$ |
31,107 |
|
|
$ |
5,242 |
|
|
|
|
|
|
|
|
|
|
Supplemental
disclosure of cash flow information:
|
|
|
|
|
|
|
|
|
Interest
paid
|
|
$ |
17,828 |
|
|
$ |
18,424 |
|
Income
taxes paid
|
|
$ |
1,500 |
|
|
$ |
14,800 |
|
See Notes
to Consolidated Financial Statements.
NORTHWEST NATURAL GAS COMPANY
PART
I. FINANCIAL INFORMATION
Notes to
Consolidated Financial Statements
(Unaudited)
1.
|
Basis
of Financial Statements and Accounting
Policies
|
The
consolidated financial statements include the accounts of Northwest Natural Gas
Company (NW Natural), which consist of our regulated gas distribution business,
our regulated gas storage businesses, which include our wholly-owned subsidiary
Gill Ranch Storage, LLC (Gill Ranch), and other investments and business
activities, which include our wholly-owned subsidiary NNG Financial Corporation
(Financial Corporation) and an equity investment in a proposed natural gas
transmission pipeline (Palomar) (see Note 2).
In this
report, the term “utility” is used to describe the gas distribution business and
the term “non-utility” is used to describe the gas storage businesses and other
non-utility investments and business activities. Intercompany
accounts and transactions have been eliminated, except for transactions required
by regulatory accounting not to be eliminated under Statement of Financial
Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types
of Regulation.”
The
information presented in the interim consolidated financial statements is
unaudited, but includes all material adjustments, including normal recurring
accruals, that management considers necessary for a fair statement of the
results for each period reported. These consolidated financial
statements should be read in conjunction with the audited consolidated financial
statements and related notes included in our 2008 Annual Report on Form 10-K
(2008 Form 10-K). A significant part of our business is of a seasonal
nature; therefore, results of operations for interim periods are not necessarily
indicative of the results for a full year.
Investments
in corporate joint ventures and partnerships in which our ownership interest is
50 percent or less and over which we do not exercise control are accounted for
by the equity method or the cost method.
Our
accounting policies are described in Note 1 of the 2008 Form
10-K. There were no significant changes to those accounting policies
during the three and six months ended June 30, 2009. See below for a
further discussion of newly adopted standards and recent accounting
pronouncements.
Newly
Adopted Standards
Business
Combinations. Effective January 1, 2009, we adopted SFAS No. 141R,
“Business Combinations.” This statement amends the principles and requirements
for how an acquiror accounts for and discloses its business
combinations. The adoption of SFAS No. 141R did not have a material
effect on our financial condition, results of operations or cash
flows.
Noncontrolling
Interests. Effective January 1, 2009, we adopted SFAS No. 160,
“Noncontrolling Interests in Consolidated Financial Statements.” This
statement amends the reporting requirements of Accounting Research Bulletin No.
51 for noncontrolling interests in subsidiaries to improve the relevance,
comparability and transparency of the financial information disclosed. The
adoption of SFAS No. 160 did not have a material effect on our financial
condition, results of operations or cash flows.
Derivative
Instruments and Hedging Activities. Effective January 1, 2009,
we adopted SFAS No. 161, “Disclosures About Derivative Instruments and Hedging
Activities--an Amendment of FASB Statement No. 133,” which requires enhanced
disclosures of derivative instruments and hedging activities. SFAS
No. 161 expands disclosures by adding qualitative disclosures about our hedging
objectives and strategies, fair value gains and losses, and credit-risk-related
contingent features in derivative agreements. The disclosures are
intended to provide an enhanced understanding of:
·
|
how
and why we use derivative
instruments;
|
·
|
how
derivative instruments and related hedge items are accounted for under
SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities,” and its related interpretations;
and
|
·
|
how
derivative instruments and related hedged items affect our financial
condition, results of operations and cash
flows.
|
The
adoption and implementation of this statement did not have, and is not expected
to have a material effect on our financial statement disclosures. The
required disclosures are included in Note 10, below.
Determining
Whether Share-Based Payment Transactions are Participating
Securities. Effective January 1, 2009, we adopted Financial
Accounting Standards Board (FASB) Staff Position (FSP) No. EITF 03-6-1,
“Determining Whether Instruments Granted in Share-Based Payment Transactions are
Participating Securities.” This statement requires nonforfeitable
rights to dividends or dividend equivalents on unvested share-awards to be
included in the computation of earnings per share under the two-class
method. The adoption of FSP No. EITF 03-6-1 did not have, and is not
expected to have, a material effect on our financial condition, results of
operations or cash flows.
Interim
Disclosures about Financial Instruments. Effective for periods
ending after June 15, 2009, we adopted FSP SFAS No. 107-1 and Accounting
Principles Board (APB) Opinion No. 28-1, “Interim Disclosures about Fair Value
of Financial Instruments.” This statement requires disclosures about
the fair value of financial instruments to be made in interim reporting periods
where summarized financial information is issued. The adoption of
this statement did not have a material effect on our disclosures. See
Note 5 and Note 10, below.
Fair
Value Considerations. Effective for periods ending after June
15, 2009, we adopted FSP SFAS No. 157-4, “Determining Fair Value When the Volume
and Level of Activity for the Asset or Liability Have Significantly Decreased
and Identifying Transactions That Are Not Orderly.” This
pronouncement provides an outline and required disclosures, if necessary, to
determine if the market for measuring our financial instruments has
significantly decreased in volume and level of activity. The adoption
of this statement did not have a material effect on our financial statement
disclosures.
Subsequent
Events. Effective June 15, 2009, we adopted SFAS No. 165,
“Subsequent Events.” This statement establishes principles and
disclosure requirements for events or transactions that occur after the balance
sheet date but before the financial statements are issued. As of August 6, 2009,
we have evaluated events subsequent to the balance sheet date. For subsequent
event footnote, see Note 12.
Recent
Accounting Pronouncements
Pensions. In
December 2008, the FASB issued SFAS No. 132R-1, “Employers’ Disclosures about
Pensions and Other Postretirement Benefits,” which requires enhanced disclosures
of plan assets in an employer’s defined benefit pension or other postretirement
benefit plans. SFAS No. 132R-1 is effective for reporting periods
ending after December 15, 2009. The disclosures are intended to
provide an enhanced understanding of:
·
|
how
investment allocation decisions are
made;
|
·
|
the
major categories of plan assets;
|
·
|
the
inputs and valuation techniques used to measure the fair value of plan
assets;
|
·
|
the
effect of fair value measurements using significant unobservable inputs
(Level 3 input from SFAS No. 157, “Fair Value Measurements”) on changes in
plan assets for the period; and
|
·
|
significant
concentration or risk within plan
assets.
|
The
adoption of SFAS No. 132R-1 is not expected to have a material effect on our
financial statement disclosures.
Variable
Interest Entity. In June 2009, the FASB issued SFAS No. 167,
“Amendments to FASB Interpretation No. 46(R).” This pronouncement amends FASB
Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” and
requires an analysis to determine whether our variable interest provides us with
a controlling financial interest in the variable interest entity. It defines the
primary beneficiary of the variable interest entity as the entity
having:
·
|
power
to control the activities that most significantly impact the performance;
and
|
·
|
the
obligation to absorb losses or right to receive benefits from the entity
that could potentially be significant to the variable interest
entity.
|
SFAS No.
167 is effective for the first annual reporting period that begins after
November 15, 2009. We are evaluating the impact the adoption of SFAS
No. 167 will have on our investments in variable interest
entities. If consolidated, our variable interest entities could have
a material impact on our balance sheet, but it is not expected to materially
impact our results of operations or cash flows.
We
operate in two primary reportable business segments, local gas distribution and
gas storage. We also have other investments and business activities
not specifically related to either of these two reporting segments which we
aggregate and report as “other.” We refer to our local gas
distribution business as the “utility,” and our “gas storage” and “other”
business segments as “non-utility.” Our gas storage segment includes Gill Ranch
in California and a portion of the Mist underground storage facility in
Oregon, and our “other” segment includes an equity investment in Palomar and
Financial Corporation.
The
following tables present information about the reportable segments for the three
and six months ended June 30, 2009 and 2008. Inter-segment
transactions are insignificant.
|
|
Three
Months Ended June 30,
|
|
Thousands
|
|
Utility
|
|
|
Gas
Storage
|
|
|
Other
|
|
|
Total
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
operating revenues
|
|
$ |
60,066 |
|
|
$ |
5,825 |
|
|
$ |
28 |
|
|
$ |
65,919 |
|
Depreciation
and amortization
|
|
|
15,029 |
|
|
|
336 |
|
|
|
- |
|
|
|
15,365 |
|
Income
from operations
|
|
|
8,955 |
|
|
|
4,852 |
|
|
|
4 |
|
|
|
13,811 |
|
Net
income (loss)
|
|
|
439 |
|
|
|
2,734 |
|
|
|
(87 |
) |
|
|
3,086 |
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
operating revenues
|
|
$ |
57,183 |
|
|
$ |
5,339 |
|
|
$ |
50 |
|
|
$ |
62,572 |
|
Depreciation
and amortization
|
|
|
17,633 |
|
|
|
324 |
|
|
|
- |
|
|
|
17,957 |
|
Income
(loss) from operations
|
|
|
7,451 |
|
|
|
4,907 |
|
|
|
(305 |
) |
|
|
12,053 |
|
Net
income (loss)
|
|
|
(743 |
) |
|
|
2,488 |
|
|
|
1,552 |
|
|
|
3,297 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30,
|
|
Thousands
|
|
Utility
|
|
|
Gas
Storage
|
|
|
Other
|
|
|
Total
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
operating revenues
|
|
$ |
198,160 |
|
|
$ |
10,325 |
|
|
$ |
73 |
|
|
$ |
208,558 |
|
Depreciation
and amortization
|
|
|
30,212 |
|
|
|
675 |
|
|
|
- |
|
|
|
30,887 |
|
Income
from operations
|
|
|
89,849 |
|
|
|
8,597 |
|
|
|
36 |
|
|
|
98,482 |
|
Net
income (loss)
|
|
|
45,743 |
|
|
|
4,766 |
|
|
|
(60 |
) |
|
|
50,449 |
|
Total
assets at June 30, 2009
|
|
|
2,092,788 |
|
|
|
96,711 |
|
|
|
15,012 |
|
|
|
2,204,511 |
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
operating revenues
|
|
$ |
184,562 |
|
|
$ |
10,336 |
|
|
$ |
97 |
|
|
$ |
194,995 |
|
Depreciation
and amortization
|
|
|
35,012 |
|
|
|
650 |
|
|
|
- |
|
|
|
35,662 |
|
Income
from operations
|
|
|
81,328 |
|
|
|
8,750 |
|
|
|
101 |
|
|
|
90,179 |
|
Net
income
|
|
|
39,799 |
|
|
|
4,841 |
|
|
|
1,825 |
|
|
|
46,465 |
|
Total
assets at June 30, 2008
|
|
|
1,877,199 |
|
|
|
67,198 |
|
|
|
11,584 |
|
|
|
1,955,981 |
|
Total
assets at Dec. 31, 2008
|
|
|
2,289,601 |
|
|
|
72,073 |
|
|
|
16,478 |
|
|
|
2,378,152 |
|
Included
in total assets at June 30, 2009 and 2008, our major non-utility investments
were as follows:
·
|
Mist
gas storage (excluding amounts allocated to our utility) was $57.0 million
and $53.6 million, respectively;
|
·
|
Gill
Ranch storage was $23.9 million and $7.8 million,
respectively;
|
·
|
Palomar
was $10.6 million and $9.3 million, respectively;
and
|
·
|
Financial
Corporation was $1.0 million for both
periods.
|
In April
2008, we sold our investment in a Boeing 737-300 aircraft for approximately $6.2
million cash, plus accrued rents. As a result of the sale, we
recognized an after-tax gain of $1.1 million in the second quarter of 2008,
which was recorded in our other segment.
In March
2009, Gill Ranch entered into a cash collateralized credit facility for up to
$40 million that expires on September 30, 2009. As of June 30, 2009,
Gill Ranch had $10.8 million of borrowings outstanding included under notes
payable on the balance sheet, with a corresponding cash collateral included in
prepayments and other current assets on the balance sheet. The effective
interest rate on Gill Ranch’s credit facility is 0.8 percent.
Palomar
has precedent agreements whereby a significant majority of the pipeline capacity
is committed to one shipper. In April 2009, Palomar and that majority
shipper replaced the prior precedent agreement with a new agreement and Palomar
received cash proceeds of $15.8 million which had supported the shipper's
obligations under the prior agreement. The new agreement is for the same
amount of capacity as the prior agreement. Our maximum loss exposure related to
Palomar as of June 30, 2009 is limited to our net investment balance of $10.6
million. Our loss exposure would be reduced by any credit support
recovered from third parties should they default on current
agreements.
As of
June 30, 2009, our common shares authorized were 100,000,000 and our outstanding
shares were 26,513,188.
We have a
common share repurchase program under which we may purchase shares on the open
market or through privately negotiated transactions. Since inception
of the repurchase program in 2000, the Board has authorized repurchases through
May 31, 2010 up to an aggregate 2.8 million shares or $100 million. No shares
were repurchased under this program during the six months ended June 30,
2009. To date, a total of 2.1 million shares have been repurchased at
a total cost of $83.3 million.
4.
|
Stock-Based
Compensation
|
Our
stock-based compensation plans consist of the Long-Term Incentive Plan (LTIP),
the Restated Stock Option Plan (Restated SOP) and the Employee Stock Purchase
Plan (ESPP). These plans are designed to promote stock ownership by
employees and officers. For additional information on our stock-based
compensation plans, see Part II, Item 8., Note 4, in the 2008 Form 10-K and
current updates provided below.
Long-Term
Incentive Plan. On February 25, 2009, 39,000 performance-based
shares were granted under the LTIP based on target-level awards, which include a
market condition and a weighted-average grant date fair value of $9.59 per
share. Fair value was estimated as of the date of grant using a
Monte-Carlo option pricing model based on the following
assumptions:
|
|
|
Stock
price on valuation date
|
|
$41.15
|
Performance
term (in years)
|
|
3.0
|
Quarterly
dividends paid per share
|
|
$0.395
|
Expected
dividend yield
|
|
3.8%
|
Dividend
discount factor
|
|
0.8927
|
In
February 2009, the Board approved a payout of performance-based stock awards for
the 2006-08 award period. Shares of common stock were purchased on
the open market to satisfy the approved awards.
Restated
Stock Option Plan. On February 25, 2009, options to purchase
111,750 shares were granted under the Restated SOP, with an exercise price equal
to the closing market price of $41.15 per share on the date of grant, vesting
over a four-year period following the date of grant and with a term of 10 years
and 7 days. The weighted-average grant date fair value was $5.46 per
share. Fair value was estimated as of the date of grant using the
Black-Scholes option pricing model based on the following
assumptions:
|
|
|
Risk-free
interest rate
|
|
2.0%
|
Expected
life (in years)
|
|
4.7
|
Expected
market price volatility factor
|
|
22.5%
|
Expected
dividend yield
|
|
3.8%
|
Forfeiture
rate
|
|
3.7%
|
As of
June 30, 2009, there was $1.0 million of unrecognized compensation cost related
to the unvested portion of outstanding stock option awards expected to be
recognized over a period extending through 2012. For the six months
ended June 30, 2009 and 2008, the expense recognized based on the fair value of
stock options was $0.3 million and $0.4 million, respectively.
5.
|
Cost
and Fair Value Basis of Long-Term
Debt
|
In March
2009, we issued $75 million of 5.37 percent secured medium-term notes (MTNs) due
February 1, 2020. Proceeds from these MTNs were used to redeem
short-term debt of the utility and for general corporate purposes, including
funding utility capital expenditures and working capital needs. On July 9,
2009, we issued another $50 million of secured MTNs with an interest rate of
3.95 percent and a due date of July 15, 2014. Proceeds from these
MTNs will be used to fund utility capital expenditures as well as to redeem
short-term debt.
At June
30, 2009 and 2008 and December 31, 2008, we had outstanding long-term debt as
follows:
|
|
June
30,
|
|
|
June
30,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Medium-Term
Notes
|
|
|
|
|
|
|
|
|
|
First
Mortgage Bonds:
|
|
|
|
|
|
|
|
|
|
6.50 % Series B due
2008(1)
|
|
$ |
- |
|
|
$ |
5,000 |
|
|
$ |
- |
|
4.11
% Series B due 2010
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
7.45
% Series B due 2010
|
|
|
25,000 |
|
|
|
25,000 |
|
|
|
25,000 |
|
6.665%
Series B due 2011
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
7.13
% Series B due 2012
|
|
|
40,000 |
|
|
|
40,000 |
|
|
|
40,000 |
|
8.26
% Series B due 2014
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
4.70
% Series B due 2015
|
|
|
40,000 |
|
|
|
40,000 |
|
|
|
40,000 |
|
5.15
% Series B due 2016
|
|
|
25,000 |
|
|
|
25,000 |
|
|
|
25,000 |
|
7.00
% Series B due 2017
|
|
|
40,000 |
|
|
|
40,000 |
|
|
|
40,000 |
|
6.60
% Series B due 2018
|
|
|
22,000 |
|
|
|
22,000 |
|
|
|
22,000 |
|
8.31
% Series B due 2019
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
7.63
% Series B due 2019
|
|
|
20,000 |
|
|
|
20,000 |
|
|
|
20,000 |
|
5.37 % Series B due
2020(2)
|
|
|
75,000 |
|
|
|
- |
|
|
|
- |
|
9.05
% Series A due 2021
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
5.62
% Series B due 2023
|
|
|
40,000 |
|
|
|
40,000 |
|
|
|
40,000 |
|
7.72
% Series B due 2025
|
|
|
20,000 |
|
|
|
20,000 |
|
|
|
20,000 |
|
6.52
% Series B due 2025
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
7.05
% Series B due 2026
|
|
|
20,000 |
|
|
|
20,000 |
|
|
|
20,000 |
|
7.00
% Series B due 2027
|
|
|
20,000 |
|
|
|
20,000 |
|
|
|
20,000 |
|
6.65
% Series B due 2027
|
|
|
20,000 |
|
|
|
20,000 |
|
|
|
20,000 |
|
6.65
% Series B due 2028
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
7.74
% Series B due 2030
|
|
|
20,000 |
|
|
|
20,000 |
|
|
|
20,000 |
|
7.85
% Series B due 2030
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
5.82
% Series B due 2032
|
|
|
30,000 |
|
|
|
30,000 |
|
|
|
30,000 |
|
5.66
% Series B due 2033
|
|
|
40,000 |
|
|
|
40,000 |
|
|
|
40,000 |
|
5.25
% Series B due 2035
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
10,000 |
|
|
|
|
587,000 |
|
|
|
517,000 |
|
|
|
512,000 |
|
Less
long-term debt due within one year
|
|
|
- |
|
|
|
5,000 |
|
|
|
- |
|
Total
long-term debt
|
|
$ |
587,000 |
|
|
$ |
512,000 |
|
|
$ |
512,000 |
|
(1) Redeemed
at maturity in July 2008.
(2) Issued
in March 2009.
The
following table provides an estimate of the fair value of our long-term debt as
of June 30, 2009 and December 31, 2008, using market prices in effect on the
valuation dates. The fair value of our long-term debt issues was estimated using
marketable debt securities with similar credit ratings, terms and remaining
maturities.
|
|
June
30, 2009
|
|
|
Dec.
31, 2008
|
|
|
|
Carrying
|
|
|
Estimated
|
|
|
Carrying
|
|
|
Estimated
|
|
Thousands
|
|
Amount
|
|
|
Fair
Value (1)
|
|
|
Amount
|
|
|
Fair
Value (1)
|
|
Long-term
debt including amounts due
|
|
|
|
|
|
|
|
|
|
|
|
|
within
one year
|
|
$ |
587,000 |
|
|
$ |
612,931 |
|
|
$ |
512,000 |
|
|
$ |
505,828 |
|
(1) This
estimate is calculated net of commission fees.
6. Earnings
Per Share
Basic
earnings per share are computed using the weighted average number of common
shares outstanding during each period presented. The diluted earnings
per share calculation includes common shares outstanding and the potential
effects of the assumed exercise of stock options outstanding and estimated stock
awards from our other stock-based compensation plans. Diluted
earnings per share are calculated as follows:
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
Thousands,
except per share amounts
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Net
income
|
|
$ |
3,086 |
|
|
$ |
3,297 |
|
|
$ |
50,449 |
|
|
$ |
46,465 |
|
Average
common shares outstanding - basic
|
|
|
26,506 |
|
|
|
26,421 |
|
|
|
26,504 |
|
|
|
26,415 |
|
Additional
shares for stock-based compensation plans
|
|
|
101 |
|
|
|
150 |
|
|
|
99 |
|
|
|
149 |
|
Average
common shares outstanding - diluted
|
|
|
26,607 |
|
|
|
26,571 |
|
|
|
26,603 |
|
|
|
26,564 |
|
Earnings
per share of common stock - basic
|
|
$ |
0.12 |
|
|
$ |
0.12 |
|
|
$ |
1.90 |
|
|
$ |
1.76 |
|
Earnings
per share of common stock - diluted
|
|
$ |
0.12 |
|
|
$ |
0.12 |
|
|
$ |
1.90 |
|
|
$ |
1.75 |
|
For the
three and six months ended June 30, 2009, a total of 6,228 and 5,143 common
shares, respectively, were excluded from the calculation of diluted earnings per
share because the effect of these additional shares would have been
anti-dilutive. For the three and six months ended June 30, 2008, no
common share equivalents were excluded from the calculation of diluted earnings
per share because all common share equivalents were dilutive.
7.
|
Pension
and Other Postretirement
Benefits
|
The
following tables provide the components of net periodic benefit cost for our
company-sponsored qualified and non-qualified defined benefit pension plans and
other postretirement benefit plans:
|
|
Three
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
Other
Postretirement
|
|
|
|
Pension
Benefits
|
|
|
Benefits
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Service
cost
|
|
$ |
1,664 |
|
|
$ |
1,653 |
|
|
$ |
148 |
|
|
$ |
132 |
|
Interest
cost
|
|
|
4,492 |
|
|
|
4,303 |
|
|
|
407 |
|
|
|
349 |
|
Expected
return on plan assets
|
|
|
(3,994 |
) |
|
|
(4,777 |
) |
|
|
- |
|
|
|
- |
|
Amortization
of loss
|
|
|
1,658 |
|
|
|
96 |
|
|
|
4 |
|
|
|
- |
|
Amortization
of prior service cost
|
|
|
305 |
|
|
|
313 |
|
|
|
49 |
|
|
|
50 |
|
Amortization
of transition obligation
|
|
|
- |
|
|
|
- |
|
|
|
103 |
|
|
|
103 |
|
Net
periodic benefit cost
|
|
|
4,125 |
|
|
|
1,588 |
|
|
|
711 |
|
|
|
634 |
|
Amount
allocated to construction
|
|
|
(1,178 |
) |
|
|
(409 |
) |
|
|
(232 |
) |
|
|
(224 |
) |
Net
amount charged to expense
|
|
$ |
2,947 |
|
|
$ |
1,179 |
|
|
$ |
479 |
|
|
$ |
410 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended June 30,
|
|
|
|
|
|
|
|
|
|
|
|
Other
Postretirement
|
|
|
|
Pension
Benefits
|
|
|
Benefits
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Service
cost
|
|
$ |
3,327 |
|
|
$ |
3,308 |
|
|
$ |
295 |
|
|
$ |
265 |
|
Interest
cost
|
|
|
8,984 |
|
|
|
8,604 |
|
|
|
813 |
|
|
|
698 |
|
Expected
return on plan assets
|
|
|
(7,989 |
) |
|
|
(9,554 |
) |
|
|
- |
|
|
|
- |
|
Amortization
of loss
|
|
|
3,317 |
|
|
|
192 |
|
|
|
8 |
|
|
|
- |
|
Amortization
of prior service cost
|
|
|
611 |
|
|
|
627 |
|
|
|
98 |
|
|
|
99 |
|
Amortization
of transition obligation
|
|
|
- |
|
|
|
- |
|
|
|
206 |
|
|
|
206 |
|
Net
periodic benefit cost
|
|
|
8,250 |
|
|
|
3,177 |
|
|
|
1,420 |
|
|
|
1,268 |
|
Amount
allocated to construction
|
|
|
(2,356 |
) |
|
|
(788 |
) |
|
|
(464 |
) |
|
|
(431 |
) |
Net
amount charged to expense
|
|
$ |
5,894 |
|
|
$ |
2,389 |
|
|
$ |
956 |
|
|
$ |
837 |
|
See Part
II, Item 8., Note 7, in the 2008 Form 10-K for more information about our
pension and other postretirement benefit plans.
In
addition to the company-sponsored defined benefit plans referred to above, we
contribute to a multiemployer pension plan for our bargaining unit employees in
accordance with our collective bargaining agreement, known as the Western States
Office and Professional Employees International Union Pension Fund (Western
States Plan). The Western States Plan is managed by a board of
trustees that includes equal representation from participating employers and
labor unions. Contribution rates are established by collective bargaining
agreements and benefit levels are set by the board of trustees based on the
advice of an independent actuary regarding the level of benefits that
agreed-upon contributions are expected to support. The Western States
Plan currently has an accumulated funding deficiency (i.e., a failure to satisfy
the minimum funding requirements) for the current plan year and remains in
“critical status.” Federal law requires pension plans in critical status to
adopt a rehabilitation plan designed to restore the financial health of the
plan. Rehabilitation plans may specify benefit reductions, contribution
surcharges, or a combination of the two. Our total contribution to the Western
States Plan in 2008 amounted to $0.4 million. We made contributions
totaling $0.2 million to the Western States Plan for both the six months ended
June 30, 2009 and 2008. We expect the Western States Plan board
of trustees to impose a 5 percent surcharge on participating employers,
including NW Natural, beginning in 2009 with a 10 percent contribution
surcharge for years thereafter. We also expect the trustees to
reduced benefit accrual rates and adjustable benefits for active employee
participants. These changes are expected as part of a rehabilitation
plan to improve funding status of the plan.
Surcharges
above 10 percent may be assessed to employer participants in future years, but
these higher surcharges will not go into effect for NW Natural until its next
collective bargaining agreement, which is expected to be no earlier than June 1,
2014. Under the terms of our collective bargaining agreement, which
became effective July 13, 2009, we can withdraw from the Western States Plan at
any time. If we withdraw and the plan is underfunded, we could be
assessed a withdrawal liability. We have no current intent to
withdraw from the plan, so we have not recorded a withdrawal
liability.
Employer
Contributions
We make
contributions periodically to our single-employer qualified defined benefit
pension plans based on actuarial assumptions and estimates, tax regulations and
funding requirements under federal law. In April 2009, we made an aggregate $25
million cash contribution for the 2008 plan year. In addition, we made cash
contributions for our unfunded, non-qualified pension plans and other
postretirement benefit plans in the form of ongoing benefit payments of $1.7
million and $1.4 million during the six months ended June 30, 2009 and 2008,
respectively. For more information see Part II, Item 8., Note
7, in the 2008 Form 10-K.
Items
excluded from net income and charged directly to common stock equity are
included in accumulated other comprehensive income (loss), net of
tax. The amount of accumulated other comprehensive loss in common
stock equity is $4.3 million, $2.5 million and $4.4 million at June 30,
2009 and 2008 and December 31, 2008, respectively, which is related to employee
benefit plan liabilities and unrealized gains or losses from derivatives not
included under regulatory assets and liabilities (see Note 10,
below). The following table provides a reconciliation of net income
to total comprehensive income for the three and six months ended June 30, 2009
and 2008.
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Net
income
|
|
$ |
3,086 |
|
|
$ |
3,297 |
|
|
$ |
50,449 |
|
|
$ |
46,465 |
|
Amortization
of employee benefit plan liability, net of tax
|
|
|
63 |
|
|
|
55 |
|
|
|
126 |
|
|
|
110 |
|
Change
in unrealized loss from derivatives, net of tax
|
|
|
- |
|
|
|
304 |
|
|
|
- |
|
|
|
908 |
|
Total
comprehensive income
|
|
$ |
3,149 |
|
|
$ |
3,656 |
|
|
$ |
50,575 |
|
|
$ |
47,483 |
|
9.
|
Fair
Value of Financial
Instruments
|
We use
fair value measurements to record adjustments to certain financial instruments
and to determine fair value disclosures. As of June 30, 2009 and 2008
and December 31, 2008, we recorded our derivatives at fair value according to
SFAS No. 157.
In
accordance with SFAS No. 157, we use the following fair value hierarchy for
determining our derivative fair value measurements:
·
|
Level
1: Valuation is based upon quoted prices for identical instruments traded
in active markets;
|
·
|
Level
2: Valuation is based upon quoted prices for similar instruments in active
markets, quoted prices for identical or similar instruments in markets
that are not active, and model-based valuation techniques for which all
significant assumptions are observable in the market;
and
|
·
|
Level
3: Valuation is generated from model-based techniques that use significant
assumptions not observable in the market. These unobservable assumptions
reflect our own estimates of the assumptions we believe market
participants would use in valuing the asset or
liability.
|
When
developing fair value measurements, it is our policy to use quoted market prices
whenever available, or to maximize the use of observable inputs and minimize the
use of unobservable inputs when quoted market prices are not available.
Derivative contracts outstanding at June 30, 2009 and 2008 and December 31, 2008
were measured at fair value using models or other market accepted valuation
methodologies derived from observable market data. These models are
primarily industry-standard models that consider various inputs including:
(a) quoted future prices for commodities; (b) forward currency prices; (c) time
value; (d) volatility factors; (e) current market and contractual prices for
underlying instruments; (f) market interest rates and yield curves; and (g)
credit spreads, as well as other relevant economic measures.
In
accordance with SFAS No. 157, we include nonperformance risk in calculating fair
value adjustments. This includes a credit risk adjustment based on
the credit spreads of our counterparties when we are in an unrealized gain
position, or on our own credit spread when we are in an unrealized loss
position. Our assessment of nonperformance risk is generally derived
from the credit default swap market or from bond market credit spreads. The
impact of the credit risk adjustments for all outstanding derivatives was
immaterial to the fair value calculation at June 30, 2009 and 2008 and December
31, 2008.
The
following table provides the fair value measurements for our derivative assets
and liabilities as of June 30, 2009 and 2008 and December 31, 2008 in accordance
with the fair value hierarchy under SFAS No. 157:
|
|
|
June
30,
|
|
|
June
30,
|
|
|
Dec.
31,
|
|
Thousands
|
Description
of Derivative Inputs
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Level
1
|
Quoted
prices in active markets
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
Level
2
|
Significant
other observable inputs
|
|
|
(73,314 |
) |
|
|
58,561 |
|
|
|
(153,643 |
) |
Level
3
|
Significant
unobservable inputs
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
$ |
(73,314 |
) |
|
$ |
58,561 |
|
|
$ |
(153,643 |
) |
10.
|
Derivative Instruments
|
We enter
into forward contracts and other related financial transactions that qualify as
derivative instruments under SFAS No. 133, “Accounting for Derivatives,” as
amended by SFAS No. 138 and SFAS No. 149 (collectively referred to as SFAS No.
133). We utilize derivative financial instruments primarily to manage
commodity prices related to natural gas supply requirements and interest rates
related to existing or anticipated debt issuances.
As in the
prior two gas years, our strategy entering the 2008-09 gas year (November 1,
2008 – October 31, 2009) was to hedge up to a targeted level of approximately 75
percent of our anticipated year-round sales volumes based on normal
weather. We do most of our hedging for the upcoming gas year
prior to the start of that gas year and include the hedge prices in
our annual purchased gas adjustment filing.
The
volumes hedged with financial contracts at June 30, 2009 totaled 482 million
therms. These amounts include hedged volumes for the current and
future gas years. At June 30, 2009, we were 60 to 70 percent hedged
for the remainder of the 2008-09 gas year and approximately 40 percent
hedged with financial contracts for the 2009-10 gas year based on anticipated
sales volumes, with approximately an additional 8 percent hedged with physical
supplies in gas storage for the 2009-10 gas year.
In
accordance with SFAS No. 161, the following table discloses the balance sheet
presentation of our derivative instruments outstanding as of June 30, 2009 and
2008 and December 31, 2008:
|
|
Fair
Value of Derivative Instruments
|
|
|
|
June
30, 2009
|
|
|
June
30, 2008
|
|
|
Dec.
31, 2008
|
|
Thousands
|
|
Current
|
|
|
Non-Current
|
|
|
Current
|
|
|
Non-Current
|
|
|
Current
|
|
|
Non-Current
|
|
Assets: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas commodity
|
|
$ |
5,293 |
|
|
$ |
289 |
|
|
$ |
54,867 |
|
|
$ |
9,218 |
|
|
$ |
4,592 |
|
|
$ |
146 |
|
Total
|
|
$ |
5,293 |
|
|
$ |
289 |
|
|
$ |
54,867 |
|
|
$ |
9,218 |
|
|
$ |
4,592 |
|
|
$ |
146 |
|
Liabilities: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas commodity
|
|
$ |
69,999 |
|
|
$ |
8,844 |
|
|
$ |
2,755 |
|
|
$ |
1,374 |
|
|
$ |
136,290 |
|
|
$ |
9,734 |
|
Interest
rate
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,358 |
|
|
|
- |
|
|
|
11,912 |
|
Foreign
exchange
|
|
|
53 |
|
|
|
- |
|
|
|
37 |
|
|
|
- |
|
|
|
445 |
|
|
|
- |
|
Total
|
|
$ |
70,052 |
|
|
$ |
8,844 |
|
|
$ |
2,792 |
|
|
$ |
2,732 |
|
|
$ |
136,735 |
|
|
$ |
21,646 |
|
|
(1) Unrealized
fair value gains are classified under current- or non-current assets as
fair value of non-trading
derivatives.
|
|
(2) Unrealized
fair value losses are classified under current- or non-current liabilities
as fair value of non-trading
derivatives.
|
In
accordance with SFAS No. 161, the following table discloses the income statement
presentation for the unrealized gains and losses from our derivative instruments
outstanding for the three and six months ended June 30, 2009 and
2008. It also illustrates that all of our derivative instruments are
related to regulated utility operations and are deferred to balance sheet
accounts in accordance with regulatory accounting under SFAS No. 71.
|
|
Three
Months Ended
|
|
|
|
June
30, 2009
|
|
June
30, 2008 |
Thousands
|
|
Natural gas
commodity (1)
|
|
|
Foreign exchange
(3)
|
|
|
Natural gas
commodity (1)
|
|
|
Interest rate (2)
|
|
|
Foreign exchange
(3)
|
|
Cost
of sales
|
|
$ |
44,446 |
|
|
$ |
- |
|
|
$ |
28,398 |
|
|
$ |
- |
|
|
$ |
- |
|
Other
comprehensive income
|
|
|
- |
|
|
|
101 |
|
|
|
(303 |
) |
|
|
2,255 |
|
|
|
71 |
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts
deferred to regulatory accounts on balance sheet
|
|
|
(44,446 |
) |
|
|
(101 |
) |
|
|
(28,095 |
) |
|
|
(2,255 |
) |
|
|
(71 |
) |
Total
impact on earnings
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six
Months Ended
|
|
|
|
June
30, 2009
|
|
June
30, 2008 |
Thousands
|
|
Natural gas
commodity (1)
|
|
|
Foreign exchange
(3)
|
|
|
Natural gas
commodity (1)
|
|
|
Interest rate (2)
|
|
|
Foreign exchange
(3)
|
|
Cost
of sales
|
|
$ |
(73,261 |
) |
|
$ |
- |
|
|
$ |
60,823 |
|
|
$ |
- |
|
|
$ |
- |
|
Other
comprehensive income
|
|
|
- |
|
|
|
(53 |
) |
|
|
(867 |
) |
|
|
(1,358 |
) |
|
|
(37 |
) |
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts
deferred to regulatory accounts on balance sheet
|
|
|
73,261 |
|
|
|
53 |
|
|
|
(59,956 |
) |
|
|
1,358 |
|
|
|
37 |
|
Total
impact on earnings
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
(1)
|
Unrealized
gain (loss) from natural gas commodity hedge contracts is recorded in cost
of sales and reclassified to regulatory deferral accounts on the balance
sheet in accordance with SFAS No.
71.
|
(2)
|
Unrealized
gain (loss) from interest rate hedge contracts is recorded in other
comprehensive income (loss) and reclassified to regulatory deferral
accounts on the balance sheet in accordance with SFAS No.
71.
|
(3)
|
Unrealized
gain (loss) from foreign exchange forward purchase contracts is recorded
in other comprehensive income, and reclassified to regulatory deferral
accounts on the balance sheet in accordance with SFAS No.
71.
|
In
accordance with SFAS No. 161, the gross derivative liability excludes the
netting of collateral. We had no collateral posted during the six
months ended June 30, 2009. We attempt to minimize our potential
exposure to collateral calls by our counterparties to manage our liquidity
risk. Based on our current credit rating, most counterparties allow
us credit limits that range from $15 million to $25 million before we become
obligated to post collateral. We measure our collateral call
exposure as contractually required under collateral support
agreements. We also measure our collateral call exposure with calls
for adequate assurance, which is not specific as to amount of credit limit
allowed, but could potentially arise if we were to be exposed to a material
adverse change. Based upon the current unrealized loss of $72.9
million, the fair value associated with estimated collateral calls is included
in the table below. The following table discloses the estimates with and
without expected adequate assurance calls, using outstanding derivative
instruments at June 30, 2009, based on current gas prices and with various
credit rating scenarios for NW Natural.
Thousands
|
|
(Current
Ratings) A+/A3
|
|
|
BBB+/Baa1
|
|
|
BBB/Baa2
|
|
|
BBB-/Baa3
|
|
|
Speculative
|
|
With
Adequate Assurance Calls
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
889 |
|
|
$ |
13,679 |
|
|
$ |
53,304 |
|
Without
Adequate Assurance Calls
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
10,290 |
|
|
$ |
44,915 |
|
In the
three and six months ended June 30, 2009, we realized net losses of $42.4
million and $121.7 million, respectively, from the settlement of natural gas
hedge contracts, which were recorded as increases to the cost of gas, compared
to net gains of $17.0 million and $21.3 million, respectively, for the
three and six months ended June 30, 2008, which were recorded as decreases to
the cost of gas. The currency exchange rate in all foreign currency
forward purchase contracts is included in our purchased cost of gas at
settlement; therefore, no gain or loss is recorded from the settlement of those
contracts. We settled our $50 million interest rate swap in March
2009 concurrent with our issuance of the underlying long-term debt and realized
a $10.1 million effective hedge loss, which will be amortized to interest
expense over the term of the debt.
We are
exposed to derivative credit risk primarily through securing pay-fixed natural
gas commodity swaps to hedge the risk of price increases for our natural gas
purchases on behalf of customers. We utilize master netting
arrangements through International Swaps and Derivatives Association contracts
to minimize this risk along with collateral support agreements with
counterparties based on their credit ratings. In certain cases we
require guarantees or letters of credit in order for a counterparty to meet our
credit requirements.
Our
financial derivatives policy requires counterparties to have a certain
investment-grade credit rating at the time the derivative instrument is entered
into, and the policy specifies limits on the contract amount and duration based
on each counterparty’s credit rating. We do not speculate on
derivatives. We utilize derivatives to hedge our exposure above risk
tolerance limits. Any increase in market risk created by the use of
derivatives should be offset by the exposures they modify.
We
actively monitor our derivative credit exposure and place counterparties on hold
for trading purposes or require other forms of credit assurance, such as letters
of credit, cash collateral or guarantees as circumstances warrant. Our
ongoing assessment of counterparty credit risk includes consideration of credit
ratings, credit default swap spreads, bond market credit spreads, financial
condition, government actions and market news. We utilize a Monte-Carlo
simulation model to estimate the change in credit and liquidity risk from the
volatility of natural gas prices. We use the results of the model to
establish at-risk trading limits. The duration of our credit risk for
all outstanding derivatives currently does not extend beyond October 31,
2012.
We could
become materially exposed to credit risk with one or more of our counterparties
if natural gas prices experience a significant increase. If a
counterparty were to become insolvent or fail to perform on its obligations, we
could suffer a material loss, but we would expect such loss to be eligible for
regulatory deferral and rate recovery, subject to prudency
review. All of our existing counterparties currently have
investment-grade credit ratings.
As of
June 30, 2009, all outstanding natural gas hedge contracts were scheduled to
mature on or before October 31, 2012.
11.
|
Commitments
and Contingencies
|
Environmental
Matters
We own,
or have previously owned, properties that are likely to require environmental
remediation or action. We accrue all material loss contingencies
relating to these properties that we believe to be probable of assertion and
reasonably estimable. We continue to study and evaluate the extent of
our potential environmental liabilities at each identified site. Due
to the numerous uncertainties surrounding the course of environmental
remediation and the preliminary nature of several environmental site
investigations, the amount or range of potential loss beyond the amounts
currently accrued, and the probabilities thereof, cannot currently be reasonably
estimated. See Part II, Item 8., Note 12, in the 2008 Form
10-K.
The
status of each site currently under investigation is provided
below.
Gasco
site. We own property in Multnomah County, Oregon that is the site of a
former gas manufacturing plant that was closed in 1956 (the Gasco site). The
Gasco site has been under investigation by us for environmental contamination
under the Oregon Department of Environmental Quality’s (ODEQ) Voluntary Clean-Up
Program. In June 2003, we filed a Feasibility Scoping Plan and an Ecological and
Human Health Risk Assessment with the ODEQ, which outlined a range of remedial
alternatives for the most contaminated portion of the Gasco site. In May 2007,
we completed a revised Upland Remediation Investigation Report and submitted it
to the ODEQ for review. In November 2007, we submitted a Focused
Feasibility Study for groundwater source control which ODEQ conditionally
approved in March 2008. Source control design is underway. We have a
net liability balance of $19.0 million at June 30, 2009 for the Gasco site,
which is estimated at the low end of the range of potential liability because no
amount within the range is considered to be more likely than another and the
high end of the range cannot reasonably be estimated.
Siltronic
site. We previously owned property adjacent to the Gasco site that now is
the location of a manufacturing plant owned by Siltronic Corporation (the
Siltronic site). In 2005, ODEQ directed NW Natural to complete a Remedial
Investigation/Feasibility Study (RI/FS) for manufactured gas plant wastes on the
uplands at this site. ODEQ approved NW Natural’s investigation work
plan, and field work for the investigation is ongoing. The net
liability balance at June 30, 2009 for the Siltronic site is $0.9 million, which
is at the low end of the range of potential liability because no amount within
the range is considered to be more likely than another and the high end of the
range cannot reasonably be estimated.
Portland
Harbor site. In 1998, the ODEQ and the U.S. Environmental Protection
Agency (EPA) completed a study of sediments in a 5.5-mile segment of the
Willamette River (Portland Harbor) that includes the area adjacent to the Gasco
and Siltronic sites. The Portland Harbor was listed by the EPA as a Superfund
site in 2000 and we were notified that we are a potentially responsible party.
We then joined with other potentially responsible parties, referred to as the
Lower Willamette Group, to fund environmental studies in the Portland Harbor.
Subsequently, the EPA approved a Programmatic Work Plan, Field Sampling Plan and
Quality Assurance Project Plan for the Portland Harbor RI/FS. The
submittal of the Remedial Investigation Report to the EPA is expected in 2009,
with the submittal of the Feasibility Study to the EPA anticipated in
2010. The EPA and the Lower Willamette Group are conducting focused
studies on approximately eleven miles of the lower Willamette River, including
the 5.5-mile segment previously studied by the EPA. We continue to receive
estimates of additional expenditures related to our RI/FS development and
environmental remediation. In August 2008, we signed a cooperative agreement to
participate in a phased natural resource damage assessment, with the intent to
identify what, if any, additional information is necessary to estimate further
liabilities sufficient to support an early restoration-based settlement of
natural resource damage claims.
In
November 2007, the EPA invited all parties to whom it had then sent notices of
potential liability for the Portland Harbor site to a meeting to discuss
EPA Region 10’s expectation of a comprehensive settlement offer regarding
implementation of the Portland Harbor record of decision, shortly after it
issues such decision. Additional potentially responsible parties were
subsequently invited to participate in discussions concerning a settlement
process. To date, 72 of these parties have executed an initial
agreement to participate in a non-judicial allocation process intended to
resolve the parties’ liabilities, if any, to the EPA and to one
another. As of June 30, 2009, we have accrued a net balance of
$12.8 million for this site, which is at the low end of the range of potential
liability because no amount within the range is considered to be more likely
than another and the high end of the range cannot reasonably be
estimated.
In April
2004 we entered into an Administrative Order on Consent providing for early
action removal of a specific deposit of tar in the river sediments adjacent to
the Gasco site. We completed this removal of the tar deposit in the Portland
Harbor in October 2005, and on November 5, 2005 the EPA approved the completed
project. The total cost of removal, including technical work, oversight,
consultant fees, legal fees and ongoing monitoring, was about $10.8 million. To
date, we have paid $10.2 million on work related to the removal of the tar
deposit. As of June 30, 2009, we have a remaining net liability balance of $0.6
million for our estimate of ongoing costs related to this tar deposit
removal.
Central
Service Center site. In 2006, we received notice from the ODEQ that our
Central Service Center in southeast Portland (the Central Service Center site)
was assigned a high priority for further environmental investigation. Previously
there were three manufactured gas storage tanks on the premises. The ODEQ
believes there could be site contamination associated with releases of
condensate from stored manufactured gas as a result of historic gas handling
practices. In the early 1990s, we excavated waste piles and much of the
contaminated surface soils and removed accessible waste from some of the
abandoned piping. In early 2007, we received notice that this site was added to
the ODEQ’s list of sites where releases of hazardous substances have been
confirmed and to its list where additional investigation or cleanup is
necessary. We are currently performing an environmental investigation of the
property with the ODEQ’s Independent Cleanup Pathway. As of June 30,
2009, we have a net liability balance of $0.5 million accrued for investigation
at this site. The estimate is at the low end of the range of potential liability
because no amount within the range is considered to be more likely than another
and the high end of the range cannot reasonably be
estimated.
Front
Street site. The Front Street site was the former location of a gas
manufacturing plant we operated. Although it is near but outside the geographic
scope of the current Portland Harbor site sediment studies, the EPA
directed the Lower Willamette Group to collect a series of surface and
subsurface sediment samples off the river bank adjacent to where that facility
was located. Based on the results of that sampling, the EPA notified the Lower
Willamette Group that additional sampling would be required. As the Front Street
site is upstream from the Portland Harbor site, the EPA agreed that it
could be managed separately from the Portland Harbor site under ODEQ
authority. Work plans for sediment investigation and a historical
report have been submitted to ODEQ. ODEQ approval of the sediment
investigation work plan is pending. As of June 30, 2009, we have an
estimated net liability balance of $0.2 million for the study of the site, which
will include investigation of sediments and providing the report of historical
upland activities. The estimate is at the low end of the range of
potential liability because no amount within the range is considered to be more
likely than another and the high end of the range cannot reasonably be
estimated.
Oregon Steel
Mills site. See
“Legal Proceedings,” below.
Accrued
Liabilities Relating to Environmental Sites.
The following table summarizes the accrued liabilities relating to environmental
sites at June 30, 2009 and 2008 and December 31,
2008:
|
|
Current
Liabilities
|
|
|
Non-Current
Liabilities
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
Dec.
31,
|
|
|
June
30,
|
|
|
June
30,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Gasco
site
|
|
$ |
11,373 |
|
|
$ |
8,122 |
|
|
$ |
6,012 |
|
|
$ |
7,615 |
|
|
$ |
12,406 |
|
|
$ |
14,071 |
|
Siltronic
site
|
|
|
722 |
|
|
|
1,211 |
|
|
|
682 |
|
|
|
179 |
|
|
|
- |
|
|
|
332 |
|
Portland
Harbor site
|
|
|
- |
|
|
|
1,348 |
|
|
|
277 |
|
|
|
13,401 |
|
|
|
12,864 |
|
|
|
13,642 |
|
Central
Service Center site
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
523 |
|
|
|
529 |
|
|
|
526 |
|
Front
Street site
|
|
|
221 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
294 |
|
Other
sites
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
90 |
|
|
|
83 |
|
|
|
80 |
|
Total
|
|
$ |
12,316 |
|
|
$ |
10,681 |
|
|
$ |
6,971 |
|
|
$ |
21,808 |
|
|
$ |
25,882 |
|
|
$ |
28,945 |
|
Regulatory
and Insurance Recovery for Environmental Costs. In May 2003,
the Oregon Public Utility Commission (OPUC) approved our request to defer and
seek recovery of unreimbursed environmental costs associated with certain named
sites, including those described above. Also, beginning in 2006 the
OPUC authorized us to accrue interest on deferred environmental cost balances,
subject to an annual demonstration that we have maximized our insurance recovery
or made substantial progress in securing insurance recovery for unrecovered
environmental expenses. Through a series of extensions, these authorizations
have been extended through January 25,
2010.
On a
cumulative basis, we have recognized a total of $72.6 million for environmental
costs, including legal, investigation, monitoring and remediation
costs. Of this total, $38.5 million has been spent to date and $34.1
million is reported as an outstanding liability. At June 30, 2009, we
had a regulatory asset of $70.1 million, which includes $33.7 million of total
paid expenditures to date, $28.7 million for additional environmental costs
expected to be paid in the future and accrued interest of $7.7
million. We believe the recovery of these deferred charges is
probable through the regulatory process. We intend to pursue recovery
of an insurance receivable
and environmental regulatory deferrals from insurance carriers under our general
liability insurance policies, and the regulatory asset will be reduced by the
amount of any corresponding insurance recoveries. We consider insurance recovery
of most of our environmental costs to date probable based on a combination of
factors including: a review of the terms of our insurance policies; the
financial condition of the insurance companies providing coverage; a review of
successful claims filed by other utilities with similar gas manufacturing
facilities; and Oregon law that allows an insured party to seek recovery of “all
sums” from one insurance company. We have initiated settlement
discussions with a majority of our insurers but continue to anticipate that our
overall insurance recovery effort will extend over several
years.
We
anticipate that our regulatory recovery of environmental cost deferrals will not
be initiated within the next 12 months because we do not expect to have
completed our insurance recovery efforts during that time period. As such we
have classified our regulatory assets for environmental cost deferrals as
non-current. The following table summarizes the non-current
regulatory assets relating to environmental sites at June 30, 2009 and 2008 and
December 31, 2008:
|
|
Non-Current
Regulatory Assets
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Gasco
site
|
|
$ |
32,688 |
|
|
$ |
29,898 |
|
|
$ |
30,707 |
|
Siltronic
site
|
|
|
2,367 |
|
|
|
2,247 |
|
|
|
2,327 |
|
Portland
Harbor site
|
|
|
33,727 |
|
|
|
31,092 |
|
|
|
31,791 |
|
Central
Service Center site
|
|
|
548 |
|
|
|
545 |
|
|
|
545 |
|
Front
Street site
|
|
|
350 |
|
|
|
11 |
|
|
|
338 |
|
Other
sites
|
|
|
371 |
|
|
|
366 |
|
|
|
396 |
|
Total
|
|
$ |
70,051 |
|
|
$ |
64,159 |
|
|
$ |
66,104 |
|
Legal
Proceedings
We are
subject to claims and litigation arising in the ordinary course of
business. Although the final outcome of any of these legal
proceedings cannot be predicted with certainty, including the matter described
below, we do not expect that the ultimate disposition of any of these matters
will have a material effect on our financial condition, results of operations or
cash flows.
Oregon Steel
Mills site. In 2004, NW Natural was served with a third-party complaint
by the Port of Portland (Port) in a Multnomah County Circuit Court case, Oregon
Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s
and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke
Company, and 10 other third-party defendants were disposed of in a waste oil
disposal facility operated by the United States or Shaver Transportation Company
on property then owned by the Port and now owned by Oregon Steel Mills. The
complaint seeks contribution for unspecified past remedial action costs incurred
by the Port regarding the former waste oil disposal facility as well as a
declaratory judgment allocating liability for future remedial action costs. No
date has been set for trial and discovery is ongoing. We do not expect that the
ultimate disposition of this matter will have a material effect on our financial
condition, results of operations or cash flows.
On July
20, 2009, the governor of Oregon signed House Bill 3405 establishing increases
in the state income tax for corporations. The corporate income tax
rate in Oregon for 2009 and 2010 will increase from 6.6 percent to 7.9 percent
for corporations with taxable income over $250,000. For tax years
2011 and 2012, the income tax rate will decrease to 7.6 percent, and for years
after 2012 the tax rate will return to the current 6.6 percent, except for
corporations with taxable income over $10 million the tax rate will remain at
7.6 percent. The new tax rates are retroactive to January 1,
2009. We are in the process of re-measuring our deferred income tax
assets and liabilities in accordance with SFAS No. 109, “Accounting for Income
Taxes,” and determining the accounting recognition for utility regulation in
accordance with SFAS No. 71. We will seek appropriate rate
increases to restore our deferred income tax assets and liabilities to the
necessary level needed to recover the higher Oregon excise tax
rate. With respect to our non-regulated business segments, we
anticipate that we will need to record an immaterial charge to income tax
expense for the impact on those earnings from the higher Oregon excise tax
rate.
NORTHWEST
NATURAL GAS COMPANY
PART
I. FINANCIAL INFORMATION
The
following is management’s assessment of Northwest Natural Gas Company’s (NW
Natural) financial condition, including the principal factors that affect
results of operations. This discussion refers to our consolidated activities for
the three and six months ended June 30, 2009 and 2008. Unless otherwise
indicated, references in this discussion to “Notes” are to the Notes to
Consolidated Financial Statements in this report. This discussion should be read
in conjunction with our 2008 Annual Report on Form 10-K (2008 Form
10-K).
The
consolidated financial statements include the accounts of NW Natural and its
wholly-owned subsidiaries, NNG Financial Corporation (Financial Corporation) and
Gill Ranch Storage, LLC (Gill Ranch), and an equity investment in a proposed
natural gas pipeline (Palomar). These accounts consist of our regulated local
gas distribution business, our regulated gas storage businesses, and other
regulated and non-regulated investments primarily in energy-related businesses.
In this report, the term “Utility” is used to describe our regulated local gas
distribution segment, and the term “Non-utility” is used to describe our gas
storage segment (gas storage) and our other regulated and non-regulated
investments and business activities (other segment) (see “Strategic
Opportunities,” below, and Note 2).
In
addition to presenting results of operations and earnings amounts in total,
certain measures are expressed in cents per share. These amounts reflect factors
that directly impact earnings. We believe this per share information is useful
because it enables readers to better understand the impact of these factors on
earnings. All references in this section to earnings per share are on the basis
of diluted shares (see Part II, Item 8., Note 1, “Earnings Per Share,” in our
2008 Form 10-K). We also believe that showing operating revenues and
margins excluding the June 2009 refund of gas cost savings to customers
facilitates more meaningful comparisons of operating revenues and margins
between 2008 and 2009. We use such non-GAAP (i.e. not generally
accepted accounting principles) financial measures in analyzing our results of
operations and believe that they provide useful information to investors
and creditors in evaluating our financial condition.
Executive
Summary
Results for
the second quarter of 2009 include:
·
|
Consolidated
net income decreased 6 percent to $3.1 million in the second quarter of
2009, compared to $3.3 million in the second quarter of
2008;
|
·
|
Net
operating revenues (margin) increased 5 percent from $62.6 million to
$65.9 million in 2009, but the margin gain was partially offset by a 3
percent increase in total operating
expenses;
|
·
|
Income
from utility operations increased 20 percent from $7.5 million in 2008 to
$9.0 million in 2009, while income from gas storage operations decreased 1
percent or less than $0.1 million;
|
·
|
Cash
flow from operations increased 45 percent from $138.1 million in 2008 to
$199.8 million in 2009;
|
·
|
Gas
cost savings of $35.3 million were refunded to Oregon and Washington
customers due to lower gas prices;
|
·
|
Twelve-month
customer growth rate declined to 0.8 percent;
and
|
·
|
A
new five-year contract was executed with our bargaining unit
employees, effective July 13, 2009.
|
Issues,
Challenges and Performance Measures
Managing
the utility business in a period of gas price volatility. Our
gas acquisition strategy is designed to secure sufficient supplies of natural
gas to meet the needs of our utility’s residential, commercial and industrial
customers on firm service. Equally important, however, is our
strategy to hedge gas prices for a significant portion of our annual purchase
requirements based upon our utility’s gas load forecast for core utility
customers. We hedged gas prices for the majority of our gas purchases
for the current gas contract year that began on November 1, 2008, and we believe
we have sufficient contracted supplies of natural gas to meet the needs of our
core utility customers. During the six months ended June 30, 2009, the market
price of natural gas continued to be below the prices embedded in our customers’
rates through our annual purchased gas adjustment (PGA) tariff, which resulted
in gas cost savings for customers and shareholders from purchases of gas where
prices were not hedged. Gas costs lower than those set in the PGA may
positively impact earnings due to an incentive sharing mechanism in Oregon.
Conversely, gas costs higher than
those set in the PGA may negatively impact earnings and may also affect our
competitive advantage because they could reduce our ability to add residential
and commercial customers and potentially cause industrial customers to shift
their energy needs to alternative fuel sources. Our PGA cost sharing
mechanism, along with gas hedging strategies and inventories in storage, enables
us to manage and reduce earnings risk exposure due to higher gas
costs. We have been hedging gas prices for the next gas contract
year, and to a certain extent for the next three years, based on
current market prices for those future periods. We are also
continuing to evaluate and develop other gas acquisition strategies to manage
gas prices for customers beyond three years and efficiently meet
demands. Based on today’s hedge levels and current forward prices for
natural gas, we expect to have a customer rate decrease of 15 to 20 percent
effective November 1, 2009.
Economic
weakness and financial market stress. Continued weakness in
local and U.S. economies have resulted in significant negative pressure on
consumer demand and business spending. These conditions have had a
negative impact on our financial results including customer growth, margins, bad
debt expense, and could have a negative impact on net pension and interest
costs. For example, our 12-month customer growth rate slowed to 0.8
percent at June 30, 2009 compared to 2.5 percent at June 30,
2008. Based on current market conditions, we expect lower customer
growth rates to continue and possibly decline more if economic conditions
deteriorate further. However, due to a relatively low market
penetration of natural gas in our service territory compared to the rest of the
country, along with the forecast for long-term population growth in the Pacific
Northwest, the potential for environmental initiatives in Oregon and Washington
that could favor natural gas as an energy source, and our ongoing efforts to
convert existing homes from other heating fuels to natural gas, we still have
the potential to continue adding customers despite tough market
conditions.
Our
funding for strategic opportunities and other capital investments is dependent
upon our ability to access capital markets and maintain working capital
sufficient to meet operating requirements. In March 2009, and again
in July 2009, we were able to issue long-term debt totaling $125 million at
favorable rates (see Note 5). We continue to focus on: maintaining a
strong balance sheet; providing sufficient liquidity; accessing capital markets
as needed; managing critical business risks; and maintaining a balanced capital
structure through the appropriate issuance of equity or long-term debt
securities. If we are unable to secure financing to fund certain
strategic opportunities, we may look at potentially re-prioritizing the use of
existing resources or consider delaying investments until market conditions
improve.
We
believe that, despite the current economic and credit market environment, our
financial condition and liquidity position remain strong and afford us access to
capital at reasonable costs. See Part I, Item 1A., “Risk Factors,”
and Part II, Item 7., “Financial Condition—Liquidity and Capital Resources,” in
our 2008 Form 10-K.
Performance
Measures. In order to deal with these and other challenges affecting our
business, we continue to refine our strategic plan to map our course over the
next several years. The plan includes strategies: for further
improving our core gas distribution business; for growing our non-utility gas
storage business; for investing in new natural gas infrastructure in the region;
and for maintaining a leadership role within the gas utility industry by
addressing long-term energy policies and pursuing business opportunities that
support new clean technologies. The key performance measures we
intend to use in monitoring progress against our goals in these areas
include, but are not limited to: earnings per share growth; total shareholder
return; return on invested capital; utility return on equity; utility customer
satisfaction ratings; capital, operations and maintenance expense per customer;
and non-utility earnings before interest, taxes, depreciation and amortization,
commonly referred to as EBITDA.
Strategic
Opportunities
Business
Process Improvements. To address the current economic and competitive
challenges, we continue to evaluate and implement business strategies to
improve efficiencies. Our goal is to integrate, consolidate and streamline
operations and support our employees with new technology tools. In 2008, we
implemented the first phase of our new enterprise resource planning (ERP)
system, and in February 2009 we implemented the second phase with our fixed
assets, payroll and construction work management systems. This
substantially completes our transition to the new ERP system, which is designed
to reduce the number of technology platforms and improve overall operating
efficiencies by:
·
|
integrating
systems and data;
|
·
|
automating
control procedures with auditable financial and operational workflows;
and
|
·
|
improving
monthly closing and financial reporting
processes.
|
We
initiated a project to automate the reading of gas meters (AMR) for the
remaining two-thirds of our customers in 2008. Meters equipped with this new
technology electronically transmit usage data to receiving devices located in
our vehicles as they are driven in the area, substantially reducing the labor
costs associated with manually reading meters. The capital cost of
this project is estimated to be $30 million, and in January 2009 we filed for
and subsequently received approval for regulatory deferral of this investment in
Oregon (see “Results of Operations—Regulatory Matters—Rate Mechanisms—AMR
Deferral Application,” below). Also in 2008, we initiated an automated
dispatching system, which provides integrated planning and scheduling with
global positioning system capabilities to more effectively collect and
distribute data.
In 2009,
we began to identify additional areas for further cost reductions based on work
load declines primarily related to slower customer growth. We intend
to mitigate the potential impact of the decline by aligning current staffing
levels with work load demands and reducing operating costs. At this
time, it is likely we will make reductions that equate to between 50 and 100
full-time positions, with a majority of those reductions made by the end of this
fiscal year. See “Issues, Challenges and Performance Measures—Economic Weakness
and Financial Market Stress,” above.
These
technology investments, workforce reductions and other initiatives are expected
to facilitate process improvements, contribute to long-term operational
efficiencies and reduce operating expenses throughout NW Natural.
Gas
Storage Development. In September 2007, we initiated a joint project with
Pacific Gas & Electric Company (PG&E) to develop an underground
natural gas storage facility near Fresno, California. We formed a wholly-owned
subsidiary, Gill Ranch, to plan, develop and operate the facility. In July 2008,
Gill Ranch filed an application with the California Public Utilities Commission
(CPUC) for a Certificate of Public Convenience and Necessity. In
December 2008, the CPUC indicated that our application qualified for a Mitigated
Negative Declaration, which allows an expedited review process. A
decision on the application is expected to be received by the end of this
year. Gill Ranch’s provision of market-based rate storage
services in California will be subject to CPUC regulation including, but not
limited to, service terms and conditions, tariff compliance, securities
issuances, lien grants and sales of property. Our share of the total
project is estimated to be between $160 and $180 million. Our share
represents 75 percent of the total cost of the initial development, which
includes an estimated total 20 Bcf of gas storage capacity and approximately 27
miles of gas transmission pipeline. The initial development of gas
storage at Gill Ranch is currently scheduled to be in-service by late
2010.
Pipeline
Diversification. Currently, we depend on a single bi-directional
interstate pipeline to ship gas supplies to our distribution
system. Palomar Gas Transmission, LLC (Palomar), a wholly-owned
subsidiary of Palomar Gas Holdings, LLC, (PGH), is seeking to build a new
transmission pipeline that would provide a new transmission pipeline
interconnection with our gas distribution system. PGH is owned 50
percent by NW Natural and 50 percent by Gas Transmission Corporation (GTN), an
indirect wholly-owned subsidiary of TransCanada Corporation. The
proposed Palomar pipeline is a 217-mile natural gas transmission pipeline in
Oregon designed to serve our utility and the growing markets in Oregon and other
parts of the western United States. The project includes an east and
west segment. The east segment of the Palomar pipeline would extend
approximately 111 miles west from an interconnection with GTN’s existing
interstate transmission mainline near Maupin, Oregon to an interconnection with
NW Natural’s gas distribution system near Molalla, Oregon. The west
segment would then extend approximately 106 miles further west to other
potential additional interconnections including a possible connection to one of
the several liquefied natural gas (LNG) terminals proposed to be built on the
Columbia River. The east segment of Palomar would diversify NW
Natural’s gas delivery options and enhance the reliability of service to our
utility customers by providing an alternate transportation path for gas
purchases from western Canada and the U.S. Rocky Mountains. The west
segment of Palomar would provide our utility customers with potential
access to a new source of gas supply if an LNG terminal is built on the Columbia
River. The Palomar pipeline would be regulated by the Federal Energy
Regulatory Commission (FERC). In December 2008, Palomar filed for a
Certificate of Public Convenience and Necessity with the FERC. See
"Financial Condition—Cash Flows—Investing Activities," below for further
discussion on Palomar.
Earnings
and Dividends
Three
months ended June 30, 2009 compared to June 30, 2008:
Net
income was $3.1 million, or $0.12 per share, for the three months ended June 30,
2009, compared to $3.3 million, or $0.12 per share, for the same period last
year.
The
primary factors contributing to the $0.2 million decrease in net income
were:
·
|
a
$5.8 million net decrease in utility margin from sales and transportation
customers, after weather and decoupling mechanism adjustments, primarily
due to a rate decrease for lower depreciation rates and lower sales due to
warmer weather and weak economic conditions (see Results of Operations –
Business Segments—Utility Operations,”
below);
|
·
|
a
$4.3 million increase in operations and maintenance expense primarily due
to higher pension expense, bonus accruals, and health care benefit
expenses; and
|
·
|
a
$1.2 million decrease in other income reflecting a last year’s gain from
the sale of our investment in a leased aircraft in
2008.
|
Partially
offsetting the above factors were:
·
|
an $8.1
million increase in utility margin from our regulatory share of gas cost
savings, reflecting a margin loss of $5.5 million in 2008 compared to a
margin gain of $2.6 million in 2009;
and
|
·
|
a
$2.6 million decrease in depreciation expense reflecting lower
depreciation rates effective January 1, 2009, which was offset by a
corresponding decrease in utility margin referred to
above.
|
Six
months ended June 30, 2009 compared to June 30, 2008:
Net
income was $50.4 million, or $1.90 per share, for the six months ended June 30,
2009, compared to $46.5 million, or $1.75 per share, for the same period last
year.
The
primary factors contributing to the $4.0 million increase in net income
were:
·
|
a
$16.9 million increase in utility margin from our regulatory share of gas
cost savings, reflecting a margin loss of $5.8 million in 2008 compared to
a margin gain of $11.1 million in
2009;
|
·
|
a
$2.5 million increase from a regulatory adjustment for income taxes paid
versus collected in rates; and
|
·
|
a
$4.8 million decrease in depreciation expense primarily from lower
depreciation rates effective January 1,
2009.
|
Partially
offsetting the above factors were:
·
|
a
$9.8 million increase in operations and maintenance expense primarily due
to higher pension expense, bonus accruals, and health care benefit
expenses; and
|
·
|
a
$6.6 million net decrease in utility margin from sales and transportation
customers, after weather and decoupling mechanism adjustments, primarily
due to a rate decrease for lower depreciation rates referred to
above.
|
Dividends
paid on our common stock were 39.5 cents per share in the second quarter of
2009, compared to 37.5 cents per share in the second quarter of
2008. In July 2009, the Board of Directors declared a quarterly
dividend on our common stock of 39.5 cents per share, payable on August 14, 2009
to shareholders of record on July 31, 2009. The current indicated
annual dividend rate is $1.58 per share.
Application
of Critical Accounting Policies and Estimates
In
preparing our financial statements using generally accepted accounting
principles in the United States of America, management exercises judgment in the
selection and application of accounting principles, including making estimates
and assumptions that affect reported amounts of assets, liabilities, revenues,
expenses and related disclosures in the financial
statements. Management considers our critical accounting policies to
be those which are most important
to the representation of our financial condition and results of operations and
which require management’s most difficult and subjective or complex judgments,
including accounting estimates that could result in materially different amounts
if we reported under different conditions or used different
assumptions. Our most critical estimates and judgments include
accounting for:
·
|
regulatory
cost recovery and amortizations;
|
·
|
derivative
instruments and hedging activities;
|
·
|
environmental
contingencies.
|
There
have been no material changes to the information provided in the 2008 Form 10-K
with respect to the application of critical accounting policies and estimates
(see Part II, Item 7., “Application of Critical Accounting Policies and
Estimates,” in the 2008 Form 10-K). Management has discussed the
estimates and judgments used in the application of critical accounting policies
with the Audit Committee of the Board.
Within
the context of our critical accounting policies and estimates, management is not
aware of any reasonably likely events or circumstances that would result in
materially different amounts being reported. For a description of
recent accounting pronouncements that could have an impact on our financial
condition, results of operations or cash flows, see Note
1.
Results
of Operations
Regulatory
Matters
Regulation
and Rates
We
are currently subject to regulation with respect to, among other matters, rates
and systems of accounts set by the Oregon Public Utility Commission (OPUC), the
Washington Utilities and Transportation Commission (WUTC) and the
FERC. The OPUC and WUTC also regulate our issuance of
securities. Approximately 90 percent of our utility gas volumes are
delivered to, and utility operating revenues were derived from, Oregon customers
and the balance from Washington customers. Future earnings and cash flows from
utility operations will be determined largely by the Oregon and southwest
Washington economies in general, and by the pace of growth in the residential
and commercial markets in particular, by our ability to remain price
competitive, control expenses, and obtain reasonable and timely regulatory
recovery for our utility gas costs, operating and maintenance costs and
investments made in utility plant. See Part II, Item 7., “Results of
Operations—Regulatory Matters,” in the 2008 Form
10-K.
At June
30, 2009 and 2008 and at December 31, 2008, the amounts deferred as regulatory
assets and liabilities were as follows:
|
|
Current
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Regulatory
assets:
|
|
|
|
|
|
|
|
|
|
Unrealized loss on
non-trading derivatives(1)
|
|
$ |
70,052 |
|
|
$ |
1,912 |
|
|
$ |
136,735 |
|
Pension and other
postretirement benefit obligations(2)
|
|
|
8,074 |
|
|
|
2,792 |
|
|
|
8,074 |
|
Other(4)
|
|
|
11,053 |
|
|
|
1,044 |
|
|
|
2,510 |
|
Total
regulatory assets
|
|
$ |
89,179 |
|
|
$ |
5,748 |
|
|
$ |
147,319 |
|
Regulatory
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
costs payable
|
|
$ |
19,010 |
|
|
$ |
24,307 |
|
|
$ |
5,284 |
|
Unrealized gain on
non-trading derivatives(1)
|
|
|
5,293 |
|
|
|
53,999 |
|
|
|
4,592 |
|
Other(4)
|
|
|
6,486 |
|
|
|
6,064 |
|
|
|
10,580 |
|
Total
regulatory liabilities
|
|
$ |
30,789 |
|
|
$ |
84,370 |
|
|
$ |
20,456 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Current
|
|
|
|
June
30,
|
|
|
June
30,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Regulatory
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on
non-trading derivatives(1)
|
|
$ |
8,844 |
|
|
$ |
2,732 |
|
|
$ |
21,646 |
|
Income
tax asset
|
|
|
70,096 |
|
|
|
69,547 |
|
|
|
69,948 |
|
Pension and other
postretirement benefit obligations(2)
|
|
|
109,833 |
|
|
|
26,203 |
|
|
|
113,869 |
|
Environmental costs
- paid(3)
|
|
|
41,362 |
|
|
|
32,087 |
|
|
|
36,135 |
|
Environmental costs
- accrued but not yet paid(3)
|
|
|
28,689 |
|
|
|
32,072 |
|
|
|
29,969 |
|
Other(4)
|
|
|
11,220 |
|
|
|
10,680 |
|
|
|
16,903 |
|
Total
regulatory assets
|
|
$ |
270,044 |
|
|
$ |
173,321 |
|
|
$ |
288,470 |
|
Regulatory
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
costs payable
|
|
$ |
3,758 |
|
|
$ |
1,263 |
|
|
$ |
1,868 |
|
Unrealized gain on
non-trading derivatives(1)
|
|
|
289 |
|
|
|
9,218 |
|
|
|
146 |
|
Accrued
asset removal costs
|
|
|
231,880 |
|
|
|
214,044 |
|
|
|
223,716 |
|
Other(4)
|
|
|
2,337 |
|
|
|
2,551 |
|
|
|
2,427 |
|
Total
regulatory liabilities
|
|
$ |
238,264 |
|
|
$ |
227,076 |
|
|
$ |
228,157 |
|
(1)
|
An
unrealized gain or loss on non-trading derivatives does not earn a rate of
return or a carrying charge. These amounts, when realized at
settlement, are recoverable through utility rates as part of the PGA
mechanism.
|
(2)
|
Qualified
pension plan and other postretirement benefit obligations are approved for
regulatory deferral. Such amounts are recoverable in rates,
including an interest component, when recognized in net periodic benefit
cost (see Note 7).
|
(3)
|
Environmental
costs are related to those sites that are approved for regulatory
deferral. We earn the authorized rate of return as a carrying
charge on amounts paid, whereas the amounts accrued but not yet paid do
not earn a rate of return or a carrying charge until
expended.
|
(4)
|
Other
primarily consists of deferrals and amortizations under other approved
regulatory mechanisms. The accounts being amortized typically
earn a rate of return or carrying
charge.
|
Rate
Mechanisms
Purchased
Gas Adjustment. Rate changes are established each year under
PGA mechanisms in Oregon and Washington to reflect changes in the expected cost
of natural gas commodity purchases, including gas storage, purchase prices
hedged with financial derivatives, interstate pipeline demand charges, the
application of temporary rate adjustments to amortize balances in deferred
regulatory accounts and the removal of temporary rate adjustments effective for
the previous year.
In
October 2008, the OPUC and WUTC approved rate changes effective on November 1,
2008 under our PGA mechanisms. The effect of the rate changes was to
increase the average monthly bills of Oregon residential customers by 14 percent
and those of Washington residential customers by 21 percent.
Under the
new Oregon PGA incentive sharing mechanism, effective November 1, 2008, we are
required to select, by August 1 of each year, either an 80 percent deferral or
90 percent deferral of higher or lower gas costs compared to PGA prices such
that the impact on current earnings from the gas cost sharing is either 20
percent or 10 percent, respectively. We are also subject to an annual earnings
review to see if the utility is earning over an allowed threshold. If utility
earnings exceed a threshold level, then 33 percent of the excess amount above
the threshold will be deferred for future refund to customers. Under
our current mechanism, if we select the 80 percent deferral, we retain all of
our earnings up to 150 basis points above the currently authorized return on
equity (ROE), or if we select the 90 percent deferral, we retain all of our
earnings up to 100 basis points above the currently authorized ROE. For the
current PGA year, we selected the 80 percent deferral. In August
2009, however, we selected the 90 percent deferral for the PGA year
beginning November 1, 2009. The earnings threshold is subject to
adjustment up or down each year depending on movements in long-term interest
rates.
In 2008,
the earnings threshold after adjustment for long-term interest rates was 13.1
percent. In July 2009, we received the final report from the OPUC on our 2008
earnings review, which resulted in a ROE of 9.6 percent. As this is
below the earnings threshold, no refund will be made to customers as a result of
the 2008 earnings review. There has been no change to the Washington
PGA mechanism under which we defer 100 percent of the higher or lower actual
purchased gas costs and pass that difference through to customers as an
adjustment to future rates.
Regulatory
Recovery for Environmental Costs. In May 2003, the OPUC
approved our request to defer unreimbursed environmental costs associated with
certain named sites. The OPUC also authorized us to accrue interest
on deferred environmental cost balances, subject to an annual demonstration that
we have maximized our insurance recovery or made substantial progress in
securing insurance recovery for unrecovered environmental
expenses. Through a series of extensions, these authorizations have
been extended through January 25, 2010. See Note
11.
Integrated
Resource Plan. The OPUC and WUTC have implemented integrated
resource planning (IRP) processes under which utilities develop plans defining
alternative growth scenarios and resource acquisition
strategies. These plans are consistent with state and energy policy
and include:
·
|
an
evaluation of supply and demand
resources;
|
·
|
the
consideration of uncertainties in the planning process and the need for
flexibility to respond to changes;
and
|
·
|
a
primary goal of “least cost”
service.
|
In
January 2009, the OPUC acknowledged our 2008 IRP. Although the OPUC
acknowledgment of the IRP does not constitute ratemaking approval of any
specific resource acquisition strategy or expenditure, the OPUC generally
indicates that it would give considerable weight in prudency reviews to utility
actions that are consistent with acknowledged plans. We filed our 2009 IRP with
the WUTC in March 2009. In July 2009, the WUTC provided notice that
our 2009 IRP met the requirements of the Washington Administrative
Code. The WUTC has indicated that the IRP process is one factor it
will consider in a prudency review.
System
Integrity Program. In July 2004, the OPUC approved specific
accounting treatment and cost recovery for our transmission pipeline integrity
management program, a program mandated by the Pipeline Safety Improvement Act of
2002 and the related rules adopted by the U.S. Department of Transportation’s
Pipeline and Hazardous Materials
Safety Administration. We record these costs as either capital
expenditures or regulatory assets, accumulate the costs over each 12-month
period ending September 30, and recover the costs, subject to audit, through
rate changes effective with the annual PGA in Oregon. In February
2009, the OPUC approved a stipulated agreement to create a new, consolidated
system integrity program (SIP). The new SIP will integrate the older
and the proposed programs into a single program. The SIP also includes a
component for a proposed distribution integrity management program, which will
be implemented following the enactment of new federal
regulations. Costs will be tracked into rates annually, with recovery
to be sought after the first $3.3 million of capital costs. An annual cap for
expenditures will be approximately $12 million, but extraordinary costs above
the cap may be approved with written consent of all parties.
The SIP
allows recovery of costs incurred in Oregon during the period from October 2008
through October 2011, or until the effective date of new rates adopted in the
company’s next general rate case. We do not have any special
accounting or rate treatment for system integrity program costs incurred in the
state of Washington.
AMR
Deferral Application. In 2008, we initiated a project to
automate the reading of gas meters for the remaining two-thirds of our
customers. The capital cost of this automated meter reading project
is estimated to be $30 million, and in January 2009 we filed for approval to
defer the costs associated with the AMR project. This request was
approved on March 30, 2009. We will continue to defer costs associated with the
AMR project, including interest on deferred balances, until we amortize those
balances. We are currently negotiating an agreement regarding the
recovery of the AMR investment, with a target of beginning recovery in the 2010
PGA filing.
Depreciation
Study. In December 2008, the OPUC and WUTC approved our filed
depreciation study and our request to change the amortization of our regulatory
asset account balance on pre-1981 plant. These approvals specifically
authorized the implementation of new depreciation rates in Oregon and
Washington, with a corresponding decrease to customer rates effective January 1,
2009. The new amortization schedule on pre-1981 regulatory assets,
with a corresponding increase to customer rates, became effective January 1,
2009 in Washington and will be effective November 1, 2009 in
Oregon. The implementation of the new rates decreases depreciation
expense and increases income tax expense, both of which are offset by a
corresponding change in utility operating revenues. In addition, in December
2008 we filed our depreciation study with the FERC requesting approval to apply
these same new depreciation rates to our gas storage business
assets. Our FERC filing was approved in May 2009 and the new
depreciation rates were made effective as of January 1,
2009.
Customer
Refunds for Gas Cost Incentive Sharing. For the period between
November 1, 2008 and March 31, 2009, our actual gas costs were significantly
lower than the gas costs embedded in customer rates. As a result, our
PGA incentive sharing mechanism recorded 80 percent of these gas cost savings
attributed to Oregon, and 100 percent of the savings attributed to Washington,
to a regulatory account for refund to customers (see “Purchased Gas Adjustment,”
above). Ordinarily, these refunds would be included in customer rates
in the next year’s PGA filing, but this year we received special regulatory
approval to refund the accumulated gas costs to our Oregon and
Washington customers. In June 2009, we refunded $31.0 million to
our Oregon customers and $4.3 million to our Washington customers through
billing credits.
Rate
Adjustment for Income Taxes Paid and Interstate Storage Credits. In June
2009, $6.2 million was collected from customers, representing the 2007 surcharge
for an adjustment for income taxes paid. The surcharge was included
in operating revenues from residential, commercial and industrial customers (see
“Business Segments – Utility Operations—Regulatory Adjustment for Income Taxes
Paid,” below), but it was more than offset by a refund to customers of $7.2
million from a sharing mechanism for interstate
storage.
Business
Segments - Utility Operations
Our
utility margin results are primarily affected by customer growth and to a
certain extent by changes in weather and customer consumption patterns, with a
significant portion of our earnings being derived from natural gas sales to
residential and commercial customers. In Oregon, we have a
conservation rate mechanism that adjusts revenues to offset changes in margin
resulting from increases or decreases in residential and commercial customer
consumption. We also have a weather normalization mechanism that
adjusts revenues and customer bills up or down to offset changes in margin
resulting from above- or below-average temperatures during the winter heating
season (see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate
Mechanisms,” in the 2008 Form 10-K). Both mechanisms are designed to
reduce the volatility of our utility earnings.
Three
months ended June 30, 2009 compared to June 30, 2008:
Utility
operations resulted in net income of $0.4 million, or 2 cents per share, in the
second quarter of 2009 compared to a net loss of $0.7 million, or 3 cents per
share, in the second quarter of 2008. Net income from utility
operations is typically a small net gain or loss during the second quarter each
year because of the reduced use of natural gas in the spring and early
summer. The $1.1 million increase over 2008 is primarily due to lower
gas costs in 2009 (see “Cost of Gas Sold,” below), partially offset by warmer
weather and reduced customer use in 2009. Total utility volumes sold
and delivered in the second quarter of this year decreased by 20 percent over
last year, while total utility margin increased by 5 percent, primarily due to
an $8.1 million swing in gas cost savings from our incentive sharing
mechanism.
Six
months ended June 30, 2009 compared to June 30, 2008:
In the
six months ended June 30, 2009, utility operations contributed net income of
$45.7 million or $1.72 per share, compared to $39.8 million or $1.50 per share
in 2008. Total utility volumes sold and delivered in the six months
ended June 30, 2009 decreased by 13 percent over last year, while total utility
margin increased by 7 percent, primarily due to a $16.9 million swing in gas
cost savings from our incentive sharing mechanism.
The
following tables summarize the composition of utility volumes, operating
revenues and margin:
|
|
Three
months ended
|
|
|
|
|
|
|
June
30,
|
|
|
Favorable/
|
|
Thousands,
except degree day and customer data
|
|
2009
|
|
|
2008
|
|
|
(Unfavorable)
|
|
Utility
volumes - therms:
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
|
58,156 |
|
|
|
78,444 |
|
|
|
(20,288 |
) |
Commercial
sales
|
|
|
43,497 |
|
|
|
52,161 |
|
|
|
(8,664 |
) |
Industrial
- firm sales
|
|
|
8,568 |
|
|
|
10,556 |
|
|
|
(1,988 |
) |
Industrial
- firm transportation
|
|
|
29,377 |
|
|
|
41,868 |
|
|
|
(12,491 |
) |
Industrial
- interruptible sales
|
|
|
17,368 |
|
|
|
21,799 |
|
|
|
(4,431 |
) |
Industrial
- interruptible transportation
|
|
|
52,229 |
|
|
|
57,784 |
|
|
|
(5,555 |
) |
Total
utility volumes sold and delivered
|
|
|
209,195 |
|
|
|
262,612 |
|
|
|
(53,417 |
) |
Utility
operating revenues - dollars:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
$ |
72,491 |
|
|
$ |
95,660 |
|
|
$ |
(23,169 |
) |
Commercial
sales
|
|
|
42,311 |
|
|
|
53,385 |
|
|
|
(11,074 |
) |
Industrial
- firm sales
|
|
|
7,949 |
|
|
|
9,531 |
|
|
|
(1,582 |
) |
Industrial
- firm transportation
|
|
|
1,442 |
|
|
|
1,643 |
|
|
|
(201 |
) |
Industrial
- interruptible sales
|
|
|
13,280 |
|
|
|
16,011 |
|
|
|
(2,731 |
) |
Industrial
- interruptible transportation
|
|
|
2,039 |
|
|
|
1,936 |
|
|
|
103 |
|
Regulatory
adjustment for income taxes paid (1)
|
|
|
(626 |
) |
|
|
(673 |
) |
|
|
47 |
|
Other
revenues
|
|
|
4,290 |
|
|
|
8,366 |
|
|
|
(4,076 |
) |
Total
utility operating revenues
|
|
|
143,176 |
|
|
|
185,859 |
|
|
|
(42,683 |
) |
Cost
of gas sold
|
|
|
79,359 |
|
|
|
124,004 |
|
|
|
44,645 |
|
Revenue
taxes
|
|
|
3,753 |
|
|
|
4,672 |
|
|
|
919 |
|
Utility
margin
|
|
$ |
60,064 |
|
|
$ |
57,183 |
|
|
$ |
2,881 |
|
Utility
margin: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
$ |
34,901 |
|
|
$ |
44,328 |
|
|
$ |
(9,427 |
) |
Commercial
sales
|
|
|
14,793 |
|
|
|
18,713 |
|
|
|
(3,920 |
) |
Industrial
- sales and transportation
|
|
|
6,524 |
|
|
|
7,054 |
|
|
|
(530 |
) |
Miscellaneous
revenues
|
|
|
1,474 |
|
|
|
1,480 |
|
|
|
(6 |
) |
Gain
(loss) from gas cost incentive sharing
|
|
|
2,647 |
|
|
|
(5,471 |
) |
|
|
8,118 |
|
Other
margin adjustments
|
|
|
496 |
|
|
|
13 |
|
|
|
483 |
|
Margin
before regulatory adjustments
|
|
|
60,835 |
|
|
|
66,117 |
|
|
|
(5,282 |
) |
Weather
normalization adjustment
|
|
|
(756 |
) |
|
|
(6,184 |
) |
|
|
5,428 |
|
Decoupling
adjustment
|
|
|
611 |
|
|
|
(2,077 |
) |
|
|
2,688 |
|
Regulatory
adjustment for income taxes paid (1)
|
|
|
(626 |
) |
|
|
(673 |
) |
|
|
47 |
|
Utility
margin
|
|
$ |
60,064 |
|
|
$ |
57,183 |
|
|
$ |
2,881 |
|
Customers
- end of period:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
customers
|
|
|
599,614 |
|
|
|
594,121 |
|
|
|
5,493 |
|
Commercial
customers
|
|
|
61,938 |
|
|
|
61,861 |
|
|
|
77 |
|
Industrial
customers
|
|
|
923 |
|
|
|
936 |
|
|
|
(13 |
) |
Total
number of customers - end of period
|
|
|
662,475 |
|
|
|
656,918 |
|
|
|
5,557 |
|
Actual
degree days
|
|
|
577 |
|
|
|
860 |
|
|
|
|
|
Percent colder
(warmer) than average weather
(3)
|
|
|
(16 |
%) |
|
|
26 |
% |
|
|
|
|
|
|
Six
months ended
|
|
|
|
|
|
|
June
30,
|
|
|
Favorable/
|
|
Thousands,
except degree day and customer data
|
|
2009
|
|
|
2008
|
|
|
(Unfavorable)
|
|
Utility
volumes - therms:
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
|
236,545 |
|
|
|
260,812 |
|
|
|
(24,267 |
) |
Commercial
sales
|
|
|
146,614 |
|
|
|
159,117 |
|
|
|
(12,503 |
) |
Industrial
- firm sales
|
|
|
20,605 |
|
|
|
25,098 |
|
|
|
(4,493 |
) |
Industrial
- firm transportation
|
|
|
64,778 |
|
|
|
90,854 |
|
|
|
(26,076 |
) |
Industrial
- interruptible sales
|
|
|
40,267 |
|
|
|
47,841 |
|
|
|
(7,574 |
) |
Industrial
- interruptible transportation
|
|
|
111,696 |
|
|
|
128,166 |
|
|
|
(16,470 |
) |
Total
utility volumes sold and delivered
|
|
|
620,505 |
|
|
|
711,888 |
|
|
|
(91,383 |
) |
Utility
operating revenues - dollars:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
$ |
325,548 |
|
|
$ |
321,343 |
|
|
$ |
4,205 |
|
Commercial
sales
|
|
|
171,661 |
|
|
|
168,349 |
|
|
|
3,312 |
|
Industrial
- firm sales
|
|
|
21,653 |
|
|
|
23,353 |
|
|
|
(1,700 |
) |
Industrial
- firm transportation
|
|
|
2,844 |
|
|
|
3,229 |
|
|
|
(385 |
) |
Industrial
- interruptible sales
|
|
|
35,219 |
|
|
|
35,692 |
|
|
|
(473 |
) |
Industrial
- interruptible transportation
|
|
|
3,961 |
|
|
|
4,031 |
|
|
|
(70 |
) |
Regulatory
adjustment for income taxes paid (1)
|
|
|
2,887 |
|
|
|
382 |
|
|
|
2,505 |
|
Other
revenues
|
|
|
12,203 |
|
|
|
12,122 |
|
|
|
81 |
|
Total
utility operating revenues
|
|
|
575,976 |
|
|
|
568,501 |
|
|
|
7,475 |
|
Cost
of gas sold
|
|
|
363,523 |
|
|
|
369,916 |
|
|
|
6,393 |
|
Revenue
taxes
|
|
|
14,295 |
|
|
|
14,023 |
|
|
|
(272 |
) |
Utility
margin
|
|
$ |
198,158 |
|
|
$ |
184,562 |
|
|
$ |
13,596 |
|
Utility
margin: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
$ |
121,234 |
|
|
$ |
131,920 |
|
|
$ |
(10,686 |
) |
Commercial
sales
|
|
|
48,567 |
|
|
|
53,347 |
|
|
|
(4,780 |
) |
Industrial
- sales and transportation
|
|
|
13,946 |
|
|
|
15,385 |
|
|
|
(1,439 |
) |
Miscellaneous
revenues
|
|
|
3,366 |
|
|
|
3,208 |
|
|
|
158 |
|
Gain
(loss) from gas cost incentive sharing
|
|
|
11,079 |
|
|
|
(5,794 |
) |
|
|
16,873 |
|
Other
margin adjustments
|
|
|
994 |
|
|
|
329 |
|
|
|
665 |
|
Margin
before regulatory adjustments
|
|
|
199,186 |
|
|
|
198,395 |
|
|
|
791 |
|
Weather
normalization adjustment
|
|
|
(9,470 |
) |
|
|
(13,732 |
) |
|
|
4,262 |
|
Decoupling
adjustment
|
|
|
5,555 |
|
|
|
(483 |
) |
|
|
6,038 |
|
Regulatory
adjustment for income taxes paid (1)
|
|
|
2,887 |
|
|
|
382 |
|
|
|
2,505 |
|
Utility
margin
|
|
$ |
198,158 |
|
|
$ |
184,562 |
|
|
$ |
13,596 |
|
Actual
degree days
|
|
|
2,598 |
|
|
|
2,840 |
|
|
|
|
|
Percent colder
(warmer) than average weather
(3)
|
|
|
2 |
% |
|
|
11 |
% |
|
|
|
|
|
(1)Regulatory
adjustment for income taxes is described below under “Regulatory
Adjustment for Income Taxes
Paid.”
|
|
(2)Amounts
reported as margin for each category of customers are net of cost of gas
sold and revenue
taxes.
|
|
(3)Average
weather represents the 25-year average degree days, as determined in our
last Oregon general rate
case.
|
In June
2009 we refunded $35.3 million to our Oregon and Washington
customers. The following non-GAAP table summarizes the impact of the
refund on our operating revenues and margins for the three and six months ended
June 30, 2009, and a comparison to 2008.
|
|
Three
months ended
|
|
|
|
June
30, 2009
|
|
|
|
|
Thousands
|
|
As
Reported
|
|
|
Refund
|
|
|
Excluding
Refund (Non-GAAP)
|
|
|
June
30, 2008
|
|
Utility
operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
$ |
72,491 |
|
|
$ |
(19,679 |
) |
|
$ |
92,170 |
|
|
$ |
95,660 |
|
Commercial
sales
|
|
|
42,311 |
|
|
|
(11,423 |
) |
|
|
53,734 |
|
|
|
53,385 |
|
Industrial
- firm sales
|
|
|
7,949 |
|
|
|
(1,515 |
) |
|
|
9,464 |
|
|
|
9,531 |
|
Industrial
- firm transportation
|
|
|
1,442 |
|
|
|
- |
|
|
|
1,442 |
|
|
|
1,643 |
|
Industrial
- interruptible sales
|
|
|
13,280 |
|
|
|
(2,673 |
) |
|
|
15,953 |
|
|
|
16,011 |
|
Industrial
- interruptible transportation
|
|
|
2,039 |
|
|
|
- |
|
|
|
2,039 |
|
|
|
1,936 |
|
Regulatory
adjustment for income taxes paid
|
|
|
(626 |
) |
|
|
- |
|
|
|
(626 |
) |
|
|
(673 |
) |
Other
revenue
|
|
|
4,290 |
|
|
|
- |
|
|
|
4,290 |
|
|
|
8,366 |
|
Total utility operating revenues
|
|
|
143,176 |
|
|
|
(35,290 |
) |
|
|
178,466 |
|
|
|
185,859 |
|
Cost
of gas sold
|
|
|
79,359 |
|
|
|
34,206 |
|
|
|
113,565 |
|
|
|
124,004 |
|
Revenue
taxes
|
|
|
3,753 |
|
|
|
887 |
|
|
|
4,640 |
|
|
|
4,672 |
|
Utility
margin
|
|
$ |
60,064 |
|
|
$ |
(197 |
) |
|
$ |
60,261 |
|
|
$ |
57,183 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
`
|
|
Six
months ended
|
|
|
|
June
30, 2009
|
|
|
|
|
|
Thousands
|
|
As
Reported
|
|
|
Refund
|
|
|
Excluding
Refund (Non-GAAP)
|
|
|
June
30, 2008
|
|
Utility
operating revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
$ |
325,548 |
|
|
$ |
(19,679 |
) |
|
$ |
345,227 |
|
|
$ |
321,343 |
|
Commercial
sales
|
|
|
171,661 |
|
|
|
(11,423 |
) |
|
|
183,084 |
|
|
|
168,349 |
|
Industrial
- firm sales
|
|
|
21,653 |
|
|
|
(1,515 |
) |
|
|
23,168 |
|
|
|
23,353 |
|
Industrial
- firm transportation
|
|
|
2,844 |
|
|
|
- |
|
|
|
2,844 |
|
|
|
3,229 |
|
Industrial
- interruptible sales
|
|
|
35,219 |
|
|
|
(2,673 |
) |
|
|
37,892 |
|
|
|
35,692 |
|
Industrial
- interruptible transportation
|
|
|
3,961 |
|
|
|
- |
|
|
|
3,961 |
|
|
|
4,031 |
|
Regulatory
adjustment for income taxes paid
|
|
|
2,887 |
|
|
|
- |
|
|
|
2,887 |
|
|
|
382 |
|
Other
revenue
|
|
|
12,203 |
|
|
|
- |
|
|
|
12,203 |
|
|
|
12,122 |
|
Total
utility operating revenues
|
|
|
575,976 |
|
|
|
(35,290 |
) |
|
|
611,266 |
|
|
|
568,501 |
|
Cost
of gas sold
|
|
|
363,523 |
|
|
|
34,206 |
|
|
|
397,729 |
|
|
|
369,916 |
|
Revenue
taxes
|
|
|
14,295 |
|
|
|
887 |
|
|
|
15,182 |
|
|
|
14,023 |
|
Utility
margin
|
|
$ |
198,158 |
|
|
$ |
(197 |
) |
|
$ |
198,355 |
|
|
$ |
184,562 |
|
The
refunds represent the customers’ portion of gas cost savings realized between
November 1, 2008 and March 31, 2009, which had been deferred, with interest,
pursuant to our PGA tariffs in Oregon and Washington (see “Regulatory Matters –
Rate Mechanisms,” above). The refunds reduced total utility operating
revenues for the three and six months ended June 30, 2009 by $35.3 million, cost
of gas sold by $34.2 million and revenue taxes by $0.9 million, which resulted
in a reduction to margin of $0.2 million. This was offset by other
revenue-based expenses like lower uncollectible expense and lower regulatory
fees.
Residential
and Commercial Sales
Residential
and commercial sales are impacted by customer growth rates, seasonal weather
patterns, energy prices, competition from other energy sources and economic
conditions. Typically, 80 percent or more of our annual utility
operating revenues are derived from gas sales to weather-sensitive residential
and commercial customers. Although variations in temperatures between
periods affect volumes of gas sold to these customers, the effect on
margin and net income is significantly reduced by our weather normalization
mechanism which is effective from December 1 through May 15 of each heating
season in Oregon, where about 90 percent of our customers are
served. Approximately 10 percent of our eligible Oregon customers opt
out of the mechanism each year. In Oregon, we also have a
conservation decoupling adjustment mechanism that is intended to break the link
between our earnings and the quantity of gas consumed by our customers, so that
we do not have an incentive to encourage greater consumption contrary to
customers’ energy conservation efforts. In Washington, where
approximately 10 percent of our customers are served, we do not have a weather
normalization or a conservation decoupling mechanism. As a result, we
are not completely insulated from earnings volatility due to weather conditions
and conservation efforts by customers.
Three
months ended June 30, 2009 compared to June 30, 2008:
The
primary factors contributing to changes in residential and commercial volumes
and operating revenues in the second quarter of this year as compared to the
same period last year were:
·
|
sales
volumes to residential and commercial customers decreased 22 percent due
to warmer weather, customer conservation, and weak economic
conditions;
|
·
|
utility
operating revenues decreased $34.2 million or 23 percent, primarily due to
$31.1 million of bill credits to customers in June 2009 for the refund of
gas cost savings and $2.5 million from rate decreases for lower
depreciation expense effective January 1, 2009, which were partially
offset by PGA rate increases for higher gas prices effective November 1,
2008; and
|
·
|
margin
decreased $5.2 million or 10 percent, after weather normalization and
decoupling mechanism adjustments, primarily due to rate decreases that
reflect the lower margin requirements for new depreciation rates and lower
volumes due to warmer weather, which was partially offset by the increased
margin from customer growth of 0.8 percent over the last 12
months.
|
Six
months ended June 30, 2009 compared to June 30, 2008:
The
primary factors contributing to changes in residential and commercial volumes
and operating revenues in the six months ended June 30, 2009, compared to
the same period last year were:
·
|
sales
volumes to residential and commercial customers decreased 9 percent due to
warmer weather, customer conservation, and weak economic
conditions;
|
·
|
utility
operating revenues increased $7.5 million or 2 percent primarily due to
PGA rate increases of 14 to 21 percent in Oregon and Washington,
respectively, effective November 1, 2008 and annual customer growth of 0.8
percent, partially offset by $31.1 million in customer refunds for gas
cost savings and $6.5 million from rate decreases effective January 1,
2009 for lower depreciation expense;
and
|
·
|
margin
decreased $5.2 million or 3 percent, after weather normalization and
decoupling adjustments, primarily due to rate decreases that reflect the
lower margin requirements for new depreciation rates, which was partially
offset by the increased margin from customer growth of 0.8 percent over
the last 12 months.
|
Utility
operating revenues include accruals for unbilled revenues (gas delivered but not
yet billed to customers) based on estimates of gas deliveries from that month’s
meter reading dates to month end. Weather conditions, rate changes
and customer billing dates affect the balance of accrued unbilled revenues at
the end of each month. At June 30, 2009, accrued unbilled revenue was
$18.1 million, compared to $19.7 million at June 30, 2008, with the 8 percent
decrease primarily due to the lower volumes partially offset by the higher
billing rates mentioned above.
Industrial
Sales and Transportation
Utility
operating revenues from the industrial customer sector include commodity
costs only for those customers under sales service but not under
transportation service. Therefore, industrial customers switching between sales
service and transportation service result in swings in operating revenues, but
generally our margins are not affected because we do not mark up (i.e. we earn
no additional margin) the higher or lower cost of gas. In addition, a
significant portion of our margin revenues from our largest industrial customers
are in the form of fixed monthly charges. As such, we believe margin is a
better measure of performance for the industrial sector.
Three
months ended June 30, 2009 compared to June 30, 2008:
The
primary factors that impacted results of operations in industrial sales and
transportation markets are as follows:
·
|
volumes
delivered to industrial customers decreased by 24.5 million therms, or 19
percent;
|
·
|
utility
operating revenues decreased $4.4 million or 15 percent, which included
$4.2 million refunded to customers for gas cost savings;
and
|
·
|
margin
decreased $0.5 million, or 8 percent, a result of reduced usage due to the
current economic environment, which was partially offset by fixed charges
not affected by declining use, and by rate decreases related to lower
depreciation expense.
|
Six
months ended June 30, 2009 compared to June 30, 2008:
The
primary factors that impacted results of operations in industrial sales and
transportation markets are as follows:
·
|
volumes
delivered to industrial customers decreased by 54.6 million therms, or 19
percent;
|
·
|
utility
operating revenues decreased $2.6 million or 4 percent, which included
$4.2 million refunded to customers for gas cost savings;
and
|
·
|
margin
decreased $1.4 million, or 9 percent, a result of reduced usage due to the
current economic environment, which was partially offset by fixed
charges not affected by declining use, and by rate decreases related to
lower depreciation expense.
|
Regulatory
Adjustment for Income Taxes Paid
In
Oregon, utilities are required to true-up any differences between income taxes
authorized to be collected in rates and income taxes actually paid to
governmental entities for amounts “properly attributed” to the utilities’
regulated operations. Utilities file a tax report with the OPUC
reporting these amounts on October 15 of each year. If amounts
collected and paid differ by $100,000 or more, then the OPUC orders the utility
to establish an automatic rate adjustment to account for the difference, with
the rate adjustment to be effective June 1 of each subsequent year.
For the
six months ended June 30, 2009, we recognized $2.9 million of incremental margin
revenues representing a difference of $2.7 million of federal and state income
taxes paid in excess of taxes collected in rates plus accrued interest of $0.2
million attributed to 2007 and 2009 tax years. This indicated
surcharge to customers is primarily driven by the gains from gas cost savings
under our PGA incentive mechanism. For the six months ended June 30,
2008, we recognized a surcharge of $0.4 million representing $0.3 million
attributed to regulated operations for the 2008 tax year and a $0.1 million
adjustment for the 2007 tax year.
Other
Revenues
Other
revenues include miscellaneous fee income as well as utility revenue adjustments
reflecting deferrals to, or amortizations from, regulatory asset or liability
accounts other than deferred gas costs.
Three
months ended June 30, 2009 compared to June 30, 2008:
Other
revenues were $4.3 million in the second quarter of 2009, a decrease of $4.1
million over the second quarter of 2008, with the decrease due to the June 2009
collection of the regulatory adjustment for income taxes of $6.2 million, a
decrease in the interstate storage credits, partially offset by a net increase
in the deferral and amortization for the decoupling
adjustment. Although the decoupling adjustment and other regulatory
deferral collections or surcharges can have a material impact on utility
operating revenues, they generally do not have a material impact on margin
because they are offset by increases and decreases in customer sales
rates.
Six
months ended June 30, 2009 compared to June 30, 2008:
Other
revenues were $12.2 million in the six months ended June 30, 2009, an increase
of $0.1 million over the first half of 2008, with the increase primarily due to
a net increase in the deferral and amortization related to the decoupling
adjustment, which was partially offset by a decrease in the interstate storage
credit compared to 2008 and the collection of the regulatory adjustment for
income taxes, mentioned above.
Cost
of Gas Sold
The cost
of gas sold includes current gas purchases, gas drawn from storage inventory,
gains and losses from commodity hedges, pipeline demand charges, seasonal demand
cost balancing adjustments, regulatory gas cost deferrals and company gas
use. The OPUC and the WUTC require the natural gas commodity cost to
be billed to customers at the same cost incurred or expected to be incurred by
the utility. However, under the PGA mechanism in Oregon, our net
income is affected by differences between actual and expected purchased gas
costs primarily due to changes in market prices and weather, which affects the
volume of unhedged purchases. We use natural gas derivatives,
primarily fixed-price commodity swaps, in accordance with guidelines set forth
in our financial derivatives policies which are designed to help manage our
exposure to rising gas prices. Gains and losses from financial hedge
contracts are generally reflected in our PGA prices and normally do not impact
net income as the hedges are usually 100 percent passed through to customers in
annual rate changes, subject to a regulatory prudency review. However, hedge
contracts entered into after the annual PGA filing may impact net income to the
extent of our share of any gain or loss under the PGA in Oregon. In Washington,
100 percent of the actual gas costs, including all hedge gains and losses, are
passed through in customer rates (see Part II, Item 7., “Application of Critical
Accounting Policies and Estimates—Accounting for Derivative Instruments and
Hedging Activities,” and “Results of Operations—Regulatory Matters—Rate
Mechanisms—Purchased Gas Adjustment,” in the 2008 Form 10-K, and Note
10).
Three
months ended June 30, 2009 compared to June 30,
2008:
·
|
including
the customer refund, total cost of gas sold decreased $44.6 million or 36
percent compared to 2008, while excluding the customer refund, total cost
of gas decreased $10.4 million or 8
percent;
|
·
|
the
average gas cost collected through rates, excluding the effect of customer
refunds, increased 17 percent from 76 cents per therm in 2008
to 89 cents per therm in 2009, primarily reflecting higher prices that
were passed through to customers through PGA rate increases effective
November 1, 2008; and
|
·
|
hedge
losses totaling $42.4 million were realized and included in cost of gas
this quarter, compared to $17.0 million of hedge gains in the same period
of 2008.
|
The
effect on operating results from our gas cost incentive sharing mechanism was a
margin gain of $2.6 million in the second quarter of 2009, compared to a margin
loss of $5.5 million for the second quarter of 2008.
Six
months ended June 30, 2009 compared to June 30, 2008:
·
|
including
the customer refund, total cost of gas sold decreased $6.4 million or 2
percent compared to 2008, while excluding the customer refund, total cost
of gas increased $27.8 million or 8
percent;
|
·
|
the
average gas cost collected through rates, excluding the effect for
customer refunds, increased 20 percent from 75 cents per therm
in 2008 to 90 cents per therm in 2009, primarily reflecting higher prices
that were passed through to customers through PGA rate increases effective
November 1, 2008; and
|
·
|
hedge
losses totaling $121.7 million were realized and included in cost of gas
for the six months ended June 30, 2009, compared to $21.3 million of hedge
gains in the same period of 2008.
|
The
effect on operating results from our gas cost incentive sharing mechanism was a
margin gain of $11.1 million in the six months ended June 30, 2009, compared to
a margin loss of $5.8 million in the same period of 2008.
Business
Segments Other than Utility Operations
Gas
Storage
Our gas
storage segment primarily consists of the non-utility portion of our Mist
underground storage facility, asset optimization services and Gill Ranch (see
Part I, Item 1., “Business Segments—Gas Storage,” in our 2008 Form 10-K). For
the three months ended June 30, 2009, we earned $2.7 million, or 10 cents per
share, compared to $2.5 million, or 9 cents per share, for the same period in
2008. The $0.2 million increase in earnings over 2008 is primarily due to
increased revenues from optimization services. For the six months
ended June 30, 2009, we earned $4.8 million, or 18 cents per share, compared to
$4.9 million, or 18 cents per share, for the same period in 2008.
In
Oregon, we retain 80 percent of pre-tax income from gas storage services and
from optimization services when the costs of the capacity being used is not
included in utility rates, or 33 percent of pre-tax income from such storage and
optimization services when the capacity being used is included in utility
rates. The remaining 20 percent and 67 percent, respectively, are credited
to a deferred regulatory account for refund to our core utility
customers. We have a similar sharing mechanism in Washington for pre-tax
income derived from gas storage and optimization
services.
We are
currently developing a second underground storage facility and related pipeline
near Fresno, California. This project, Gill Ranch, is expected to
serve the California and west coast market (see Note 2). We are also
exploring the potential for further development of underground storage
reservoirs at Mist in Oregon.
On May 1,
2009, a total of 100,000 therms per day of Mist storage capacity and 50,000
therms per day of compression capacity that had previously been available for
interstate storage services was recalled by the utility and committed to use for
its core customers. Our last recall was in May 2008. Under a
regulatory agreement with the OPUC, non-utility gas storage at Mist, which has
been developed in advance of core utility customer needs for interstate storage
services, can be recalled by the utility to serve utility
customers. Storage capacity recalled by the utility is added to
utility rate base at net book value and tracked into utility rates in the next
annual PGA filing so there is minimal regulatory lag in cost
recovery.
Other
Our other
business segment consists of an equity investment in an intrastate pipeline by
Financial Corporation, an equity investment in Palomar pipeline, and other
non-utility investments and business activities. Financial
Corporation’s total investment balance was $1.0 million as of June 30, 2009 and
2008, and our investment balance in the proposed Palomar pipeline was $10.6
million and $9.3 million, respectively. Financial
Corporation’s assets include a non-controlling interest in the Kelso Beaver
pipeline. The current balance in Palomar reflects our equity investment to date
in a proposed 217-mile transmission pipeline. Net income from our
other business segment for the three and six months ended June 30, 2009 was less
than $0.1 million and $0.1 million, respectively, compared to $1.5 million and
$1.8 million for the three and six months ended June 30, 2008, respectively. See
Note 2.
Consolidated
Operating Expenses
Operations
and Maintenance
Three
months ended June 30, 2009 compared to June 30,
2008:
Operations
and maintenance expense was $30.2 million in 2009, compared to $25.8 million in
2008, an increase of $4.3 million or 17 percent. The major factors that
contributed to the increase in operations and maintenance expense
are:
·
|
a
$1.7 million increase in pension expense primarily due to lower returns on
plan investments resulting from a decline in the market value of assets
during 2008;
|
·
|
a
$1.0 million increase in technology expense primarily due to start up
costs related to new systems;
|
·
|
a
$0.7 million increase from higher health care benefit expenses;
and
|
·
|
a
$0.7 million increase in incentive bonus accruals due to improved
operating results.
|
Six
months ended June 30, 2009 compared to June 30, 2008:
Operations
and maintenance expense was $64.1 million in 2009, compared to $54.3 million in
2008, an increase of $9.8 million or 18 percent. The major factors that
contributed to the increase in operations and maintenance expense
are:
·
|
a
$3.8 million increase in pension expense primarily due to lower returns on
plan investments resulting from a decline in the market value of assets
during 2008;
|
·
|
a
$1.4 million increase from higher health care benefit
expenses;
|
·
|
a
$1.9 million increase in incentive bonus accruals due to improved
operating results; and
|
·
|
a
$1.1 million increase in utility bad debt
expense.
|
Our
bad debt expense ratio as a percent of revenues was 0.38 percent for the 12
months ended June 30, 2009, compared to 0.31 percent in the same period last
year. Excluding customer refunds in June 2009, our bad debt expense as a percent
of revenues was 0.36 percent for the 12 months ended June 30, 2009. Due to the
weak economy and high unemployment rates, we are seeing an increase in
delinquent balances and customers on payment plans. Partially helping
our collection results are an increase in low income energy assistance funds for
customers and a rate mechanism that covers the increase in bad debt expense tied
to historically higher commodity costs. Under our PGA mechanism,
billing rates are adjusted each year to recover the expected increase (or
decrease) in bad debt expense due to the higher cost of natural
gas. The revenue adjustment for bad debt expense is based on our
average write-off rate over the last three years multiplied by the estimated
increase in commodity costs. In the six months ended June 30, 2009,
margin revenues increased by approximately $0.5 million to offset the expected
increase in bad debt expense related to higher gas costs. Although we
may experience a higher increase in bad debt expense this year, we believe much
of the increase will be offset by the allowed rate increase under our PGA
mechanism.
General
Taxes
Three
months ended June 30, 2009 compared to June 30,
2008:
General
taxes, which are principally comprised of property taxes, payroll taxes and
regulatory fees, decreased $0.2 million, or 2 percent, in the three months ended
June 30, 2009 over the same period in 2008. Property taxes increased
$0.3 million, or 7 percent, reflecting an increase in net utility plant and net
non-utility property in service.
Six
months ended June 30, 2009 compared to June 30,
2008:
For the
six months ended June 30, 2009, general taxes increased $0.2 million, or 1
percent, compared to the same period in 2008. Property taxes
increased $0.5 million, or 5 percent, reflecting an increase in net utility
plant and net non-utility property in service.
We have
been involved in litigation with the Oregon Department of Revenue (ODOR) over
whether natural gas inventories and appliance inventories held for resale are
required to be taxed as personal property. In November 2007, the
Oregon Tax Court ruled in our favor stating that these inventories were exempt
from property tax. However, the ODOR appealed the judgment to the Oregon
Supreme Court in August 2008. If we are successful in this litigation, we would
be entitled to a refund of over $5.0 million for property taxes paid on gas
inventories beginning with the 2002-03 tax year and appliance inventories
beginning with the 2005-06 tax year, plus accrued interest. Due to
the uncertain outcome of the proceeding, we have not recorded the recovery of
property taxes paid on gas inventories or appliance inventories to recognize the
potential gain contingency.
Depreciation
and Amortization
Depreciation
and amortization expense decreased by $2.6 million and $4.8 million, or 14
percent and 13 percent, respectively, for the three and six months ended June
30, 2009, compared to the same periods in 2008. The lower expense
reflects new depreciation rates approved by the OPUC and WUTC, effective January
1, 2009. The decrease in depreciation expense in 2009 is offset by a
decrease in operating revenues of $6.5 million for the six months ended June 30,
2009. See “Regulatory Matters—Rate Mechanisms—Depreciation Study,”
above.
Other
Income and Expense – Net
The
following table summarizes other income and expense – net by primary
components:
|
|
Three
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
June
30,
|
|
|
June
30,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Other
income and expense - net:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gains
from company-owned life insurance
|
|
$ |
921 |
|
|
$ |
519 |
|
|
$ |
2,002 |
|
|
$ |
978 |
|
Interest
income
|
|
|
39 |
|
|
|
131 |
|
|
|
99 |
|
|
|
130 |
|
Income
from equity investments
|
|
|
446 |
|
|
|
371 |
|
|
|
734 |
|
|
|
346 |
|
Net
interest on deferred regulatory accounts
|
|
|
288 |
|
|
|
(176 |
) |
|
|
789 |
|
|
|
(343 |
) |
Other
|
|
|
(962 |
) |
|
|
1,095 |
|
|
|
(2,002 |
) |
|
|
1,002 |
|
Total
other income and expense - net
|
|
$ |
732 |
|
|
$ |
1,940 |
|
|
$ |
1,622 |
|
|
$ |
2,113 |
|
Three
months ended June 30, 2009 compared to June 30,
2008:
Other
income and expense – net decreased $1.2 million, primarily due to a decrease in
other non-operating income as 2008 included a gain from the sale of our
investment in a Boeing aircraft in the second quarter. This was
partially offset by additional income from company-owned life insurance and
interest income from our deferred regulatory accounts.
Six
months ended June 30, 2009 compared to June 30,
2008:
Other
income and expense – net decreased $0.5 million, primarily due to a decrease in
other non-operating income as 2008 included a gain from the sale of our aircraft
investment. This was partially offset by additional income from
company-owned life insurance and interest income from our deferred regulatory
accounts.
Interest
Charges – Net of Amounts Capitalized
Interest
charges – net of amounts capitalized increased $1.1 million and $1.0 million, or
12 percent and 6 percent, in the three and six months ended June 30, 2009
compared to the same period in 2008, respectively. The increase is primarily due
to higher balances on short-term debt and long-term debt outstanding, including
the $75 million of 5.37 percent MTNs issued in March 2009 (see Note
5).
Income
Tax Expense
Income
tax expense totaled $30.3 million in the six months ended June 30, 2009 compared
to $27.5 million in the same period of 2008. The effective tax rate
was 37.5 percent in 2009 compared to 37.2 percent in 2008. The
slightly higher income tax rate in 2009 is primarily due to higher taxable
income. For additional factors impacting our effective tax rate, see
Note 12.
Financial
Condition
Capital
Structure
Our goal
is to maintain a strong consolidated capital structure, generally consisting of
45 to 50 percent common stock equity and 50 to 55 percent long-term and
short-term debt. When additional capital is required, debt or equity
securities are issued depending upon both the target capital structure and
market conditions. These sources also are used to fund long-term debt redemption
requirements and short-term commercial paper maturities (see “Liquidity and
Capital Resources,” below, and Note 5). Achieving the target capital
structure and maintaining sufficient liquidity to meet operating requirements
are necessary to maintain attractive credit ratings and have access to capital
markets at reasonable costs. Our consolidated capital structure was
as follows:
|
|
June
30,
|
|
|
June
30,
|
|
|
Dec.
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Common
stock equity
|
|
|
49.2 |
% |
|
|
51.6 |
% |
|
|
45.3 |
% |
Long-term
debt
|
|
|
44.0 |
% |
|
|
42.4 |
% |
|
|
36.8 |
% |
Short-term
debt, including current maturities of long-term debt
|
|
|
6.8 |
% |
|
|
6.0 |
% |
|
|
17.9 |
% |
Total
|
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
Liquidity
and Capital Resources
At June
30, 2009, we had $31.1 million of cash and cash equivalents compared to $5.2
million at June 30, 2008. In order to have sufficient liquidity during these
uncertain times, we are continuing to maintain higher cash balances and plenty
of short-term borrowing capacity while refinancing short-term debt balances in a
low long-term fixed rate environment. Short-term liquidity is
provided by cash balances, internal cash flow from operations, proceeds from the
sale of commercial paper notes, committed credit facilities, including
multi-year commitments which are primarily used to back-up commercial paper (see
“Credit Agreement,” below), an ability to borrow from cash surrender value in
company-owned life insurance policies, and proceeds from the sale of long-term
debt. We use long-term debt proceeds to finance capital expenditures, refinance
maturing short-term or long-term debt and for general corporate
purposes. In March 2009, we issued $75 million of secured medium-term
notes (MTNs) at 5.37 percent, with a maturity date of February 1, 2020. On July
9, 2009, we issued $50 million of secured MTNs at 3.95 percent, with a maturity
date of July 15, 2014.
Our
current senior secured long-term debt ratings are AA- and A1 from Standard &
Poor’s (S&P) and Moody’s Investors Service (Moody’s), respectively, as
Moody's upgraded our rating from A2 to A1 on August 3, 2009. Our
short-term debt ratings are A-1+ and P-1 from S&P and Moody’s, respectively.
The capital markets, including the commercial paper market, have experienced
significant volatility and tight credit conditions over the last nine months, as
reflected by increased credit spreads and limited access to new financing. With
our current debt ratings we have been able to issue commercial paper notes at
attractive rates and have not needed to borrow from our $250 million back-up
facility. In the event that we are not able to issue commercial paper due to
market conditions, we expect that our liquidity needs can be met by using cash
balances or drawing upon our committed credit facility (see “Credit Agreement,”
below). We also have a universal shelf registration statement filed with the
Securities and Exchange Commission for the issuance of secured and unsecured
debt or equity securities, market conditions permitting. After giving
effect to the issuance of $50 million of secured MTNs in July, 2009, we had OPUC
approval to issue up to $175 million of additional MTNs under the shelf
registration statement.
Our
senior unsecured long-term debt ratings are A+ and A3 from S&P and Moody’s,
respectively. In the event that our senior unsecured long-term debt
credit ratings are downgraded, our counterparties under derivative contracts
could require us to post cash, a letter of credit or other form of collateral,
which could expose us to additional costs and may trigger significant increases
in short-term borrowings.
Based on
our current credit ratings, our recent experience issuing commercial paper, our
current cash reserves, the availability and size of our committed credit
facilities and other liquidity resources, and our ability to issue long-term
debt and equity securities under our universal shelf registration, we believe
our liquidity is sufficient to meet our anticipated near-term cash requirements,
including the contractual obligations and investing and financing activities
discussed below.
Off-Balance
Sheet Arrangements
Except
for certain lease and purchase commitments (see “Contractual Obligations,”
below), we have no material off-balance sheet financing
arrangements.
Contractual
Obligations
Since
December 31, 2008, our other purchase commitments increased $14 million from
additional purchase commitments made in the ordinary course of
business. Our contractual obligations also increased from our
issuances of $75 million of secured MTNs at 5.37 percent in March 2009 and $50
million of secured MTNs at 3.95 percent in July 2009. Our contractual
obligations at December 31, 2008 are described in Part II, Item 7., “Financial
Condition—Liquidity and Capital Resources—Contractual Obligations,” in the 2008
Form 10-K.
On July 13, 2009, our union employees who are members of the Office and
Professional Employees International Union (OPEIU), Local No. 11, ratified a new
five-year labor agreement called the Joint Accord. The agreement includes a 2.3
percent average wage increase effective June 1, 2009, and a scheduled one
percent wage increase each year thereafter with the potential for up to an
additional two percent based per year based on wage inflation and other factors,
and it maintains competitive health benefits while keeping cost increases to the
same level as the annual wage increases. The Joint Accord also provides
increased job flexibility for the company along with an ability to use
short-term unpaid leave to temporarily adjust the workforce without layoffs. It
also continues the company’s defined benefit retirement plan for existing
employees, but closes the plan to new employees hired after December 31,
2009.
Commercial
Paper and Other Short-Term Loans
Our
primary source of short-term liquidity is from internal cash flows and the sale
of commercial paper notes payable. In addition to issuing commercial
paper to meet seasonal working capital requirements, including the financing of
gas inventories and accounts receivable, short-term debt may be used to
temporarily fund capital requirements. Commercial paper is
periodically refinanced through the sale of long-term debt or equity
securities. Our outstanding commercial paper, which is sold through
two commercial banks under an issuing and paying agency agreement, is supported
by one or more unsecured revolving credit facilities (see “Credit Agreement,”
below). Our commercial paper program did not experience any liquidity
disruptions as a result of the credit problems that affected issuers of
asset-backed commercial paper and certain other commercial paper programs last
year. At June 30, 2009 and 2008, we had commercial paper outstanding
of $79.8 million and $67.7 million, respectively. This year’s
outstanding balances were higher than last year’s primarily due to higher
balances in gas inventories.
In
March 2009, Gill Ranch entered into a cash collateralized credit facility for up
to $40 million that expires on September 30, 2009. As of June 30,
2009, Gill Ranch had borrowed loan proceeds of $10.8 million. The effective
interest rate on Gill Ranch’s credit facility is 0.8 percent.
Credit
Agreement
We have a
syndicated line of credit for unsecured revolving loans totaling $250 million
available and committed for a term expiring on May 31, 2012, with $210 million
of that commitment amount extended through May 31, 2013. The lenders
under our syndicated credit agreement are major financial institutions with
committed balances and investment grade credit ratings as of June 30, 2009 as
follows:
|
|
|
Amount
|
|
|
|
Committed
|
Lender
rating, by category
|
|
|
(in
$000's)
|
AAA/Aaa
|
|
$ |
-
|
AA/Aa
|
|
|
230,000
|
A/A
|
|
|
20,000
|
BBB/Baa
|
|
|
-
|
Total
|
|
$ |
250,000
|
Based on
current credit market conditions, it is possible that one or more lending
commitments could be unavailable to us if the lender defaulted due to lack of
funds or insolvency. However, based on our current assessment of our
lenders’ creditworthiness, including a review of capital ratios, credit default
swap spreads and credit ratings, we believe the risk of lender default is
minimal.
Pursuant
to the terms of our credit agreement for the syndicated line of credit, we may
request maturity extensions for additional one-year periods subject to lender
approval. We extended commitments with six of the seven lenders under the
syndicated credit agreement, with commitments totaling $210 million, to May 31,
2013. The credit agreement also allows us to request increases in the
total commitment amount from time to time, up to a maximum amount of $400
million, and to replace any lenders who decline to extend the terms of the
credit agreement. The credit agreement also permits the issuance of letters of
credit in an aggregate amount up to the applicable total borrowing commitment.
Any principal and unpaid interest owed on borrowings under the credit agreement
is due and payable on or before the expiration date. There were no outstanding
balances under this credit agreement at June 30, 2009 and 2008. The
credit agreement also requires us to maintain a consolidated indebtedness to
total capitalization ratio of 70 percent or less. Failure to comply with this
covenant would entitle the lenders to terminate their lending commitments and
accelerate the maturity of all amounts outstanding. We were in compliance with
this covenant at June 30, 2009 and 2008, with consolidated indebtedness to
total capitalization ratios of 50.8 percent and 48.4 percent,
respectively.
The
credit agreement also requires that we maintain credit ratings with S&P and
Moody’s and notify the lenders of any change in our senior unsecured debt
ratings by such rating agencies. A change in our debt ratings is not
an event of default, nor is the maintenance of a specific minimum level of debt
rating a condition of drawing upon the credit agreement. However, a
change in our debt rating below BBB- or Baa3 would require additional approval
from the OPUC prior to issuance of debt, and interest rates on any loans
outstanding under the credit agreement are tied to debt ratings, which would
increase or decrease the cost of any loans under the credit agreement when
ratings are changed (see “Credit Ratings,” below).
Credit
Ratings
The
following table summarizes our current debt credit ratings from S&P and
Moody’s:
|
S&P
|
Moody’s
|
Commercial
paper (short-term debt)
|
A-1+
|
P-1
|
Senior
secured (long-term debt)
|
AA-
|
A1
|
Senior
unsecured (long-term debt)
|
A+
|
A3
|
Ratings
outlook
|
Negative
|
Stable
|
In
August 2009, Moody’s upgraded our senior secured long-term debt ratings from A2
to A1. Both rating agencies have assigned investment grade credit
ratings to NW Natural. These credit ratings are dependent upon a
number of factors, both qualitative and quantitative, and are subject to change
at any time. The disclosure of these credit ratings is not a
recommendation to buy, sell or hold NW Natural securities. Each
rating should be evaluated independently of any other rating.
Redemptions
of Long-Term Debt
In July
2008, we redeemed $5 million of secured 6.50 percent MTNs at
maturity. For long-term debt maturing over the next five years, see
Part II, Item 7., "Results of Operations—Financial Condition—Contractual
Obligations," in our 2008 Form 10-K.
Cash
Flows
Operating
Activities
Year-over-year
changes in our operating cash flows are primarily affected by net income,
changes in working capital requirements and other cash and non-cash adjustments
to operating results. In the six months ended June 30, 2009, cash flow from
operating activities, excluding working capital changes, increased $2.9 million
compared to the same period in 2008. Cash flow from working capital
changes in the six months ended June 30, 2009 increased by $58.8 million
compared to the same period in 2008. The overall change in cash flow
from operating activities was an increase of $61.7 million. The
significant factors contributing to changes in the cash flow between the six
months ended June 30, 2009 compared to the same period of 2008 are as
follows:
·
|
an
increase in cash of $42.5 million from deferred gas costs reflecting
actual gas costs lower than gas costs embedded in rates in
2009;
|
·
|
an
increase in cash of $56.9 million from reductions in accounts
receivable and accrued unbilled revenue primarily due to customer refunds
in June 2009 and higher balances in accounts receivable and accrued
unbilled revenue balances at year end 2008 compared to 2007 because of
colder weather at the end of 2008;
|
·
|
a
decrease in cash of $19.9 million from gas inventories due to lower
withdrawals from storage because of warmer weather in 2009 compared to
2008;
|
·
|
a
decrease in cash of $25.0 million from our pension contribution in April
2009 to reduce our unfunded
liability;
|
·
|
a
decrease in cash of $10.1 million from the loss realized on the settlement
of our interest rate hedge (see Note 10);
and
|
·
|
an
increase in cash of $20.8 million from income taxes receivable which we
received as a cash refund of $10.3 million in June 2009 and the balance as
a reduction to income taxes paid.
|
In June
2009, we refunded an aggregate $35.3 million to our Oregon and Washington
customers for the customers’ shares of accumulated gas cost savings from
November 1, 2008 through March 31, 2009 due to lower gas prices. This
reduction in cash was more than offset by the lower gas costs and other factors
described above.
In
addition to actual changes in cash flow discussed above, we filed an application
with the Internal Revenue Service (IRS) in December 2008, requesting a change in
tax accounting method in connection with our routine repair and maintenance
costs for gas pipelines that are currently being capitalized and depreciated for
book purposes. We anticipate that the IRS will consent to this change
during the third quarter of 2009. If approved, then we will file a
claim for a tax deduction and record current tax benefits and a deferred tax
liability, which will result in a refund of taxes paid and an increase in cash
flow. We estimate the tax refund amount for 2009 and prior years to
be in excess of $15 million related to routine repair and maintenance
costs.
Investing
Activities
Cash used
in investing activities for the six months ended June 30, 2009 totaled
$58.6 million, up from $46.7 million for the same period in
2008. Cash requirements for the acquisition and construction of
utility plant were $44.1 million in six months ended June 30, 2009, up $2.8
million from $41.3 million for the same period in 2008. The increase
was primarily due to automated meter reading project costs, which were partially
offset by lower costs for new construction and system
expansion.
Cash
requirements for investments in non-utility property were $10.3 million in the
six months ended June 30, 2009, primarily related to investments in Gill Ranch,
compared to $5.1 million in 2008. In the six months ended June 30, 2008 we sold
our investment in a Boeing 737-300 aircraft for proceeds of $6.8
million. Cash requirements for other non-utility investments were a
net $5.0 million, compared to $7.3 million last year. In the six
months ended June 30, 2009, cash used in other investing activities increased
$2.3 million, primarily due to a $5.0 million increase in our restricted cash
investment in Gill Ranch. This was partially offset by a net
distribution from Palomar of $4.3 million, compared to contributions of $3.0
million to Palomar for the same period in 2008.
In 2009,
utility capital expenditures are estimated to be between $100 and $110 million,
and non-utility capital investments are expected to be between $50 and $70
million for business development projects that are currently in process (see
“Strategic Opportunities,” above).
Over the
five-year period 2009 through 2013, utility construction expenditures are
estimated at between $450 and $500 million. The estimated level of
capital expenditures over the next five years reflects customer growth, utility
storage development at Mist, AMR, technology improvements and utility system
improvements, including requirements under the Pipeline Safety Improvement Act
of 2002. Most of the required funds are expected to be internally
generated over the five-year period and any remaining funding will be obtained
through the issuance of long-term debt or equity securities, with short-term
debt providing liquidity and bridge financing (see Part II, Item 7., “Financial
Condition—Cash Flows—Investing Activities,” in the 2008 Form 10-K).
Our share
of the total project cost of Gill Ranch is estimated to be between $160 million
and $180 million. As of June 30, 2009, we have spent $23.9
million.
In 2009
and 2010, Palomar will continue to work on the planning and permitting phase of
the Palomar pipeline project. The total cost for planning and
permitting is estimated to be between $40 million and $50 million, of which
our ownership interest is 50 percent. As of June 30, 2009, we had a net equity
investment of $10.6 million in this project. The total cost
estimate for the entire 217-mile pipeline, if constructed, is estimated to be
between $750 million and $800 million, with our current 50 percent share
estimated at between $375 million and $400 million. See "Strategic
Opportunities—Pipeline Diversification," above.
The
Palomar pipeline project includes both an east and west segment. Palomar
intends to proceed with the construction of the west segment of the pipeline if
an LNG terminal is developed. However, the development of LNG terminals
along the Columbia River may or may not proceed, dependent upon a variety of
factors, including obtaining state and federal permits, securing acceptable
financing and economic conditions. Palomar had executed precedent
agreements whereby a significant majority of the pipeline capacity was committed
to one shipper. In April 2009, Palomar and that shipper replaced
their existing precedent agreement with a new agreement for the same amount of
capacity and Palomar received $15.8 million of cash proceeds which had supported
the shipper's obligations under the prior agreement. The cash proceeds
received were applied against project costs. Under the new precedent
agreement the shipper provided, and Palomar accepted, a new form of credit
support. The new credit support is expected to support a portion of
the ongoing planning and permitting costs as the project develops. In
addition, Palomar has the right to request additional credit support from the
shipper at future stages of the project development. A failure to
provide acceptable ongoing credit support to meet such shipper's obligations may
result in Palomar reassessing its commitment to the development of the west
segment.
Based on an ongoing review of the Palomar pipeline project, and continuing
interest expressed by this shipper, and other potential shippers, PGH determined
that the Palomar project was still viable, especially the east
segment. As of May 1, 2009, Palomar has binding precedent agreements
with two shippers, including our own utility, which represents a majority of the
current design capacity on the pipeline. We will continue to manage
project risks, evaluate project costs and assess the fair value of our
investment on a quarterly basis, including a valuation of the available credit
support. Further, during 2009 and 2010, PGH will continue to evaluate
market conditions and project status to determine if and when to proceed with
construction of all or some portion of the project. See Part I, Item 1A.,
"Risk Factors," in the 2008 Form
10-K.
Financing
Activities
Cash used
in financing activities in the six months ended June 30, 2009 totaled $117.0
million, up from $92.3 million cash used in the same period of
2008. Our short-term debt balances decreased by $170.2 million in the
six months ended June 30, 2009 compared to a decrease of $75.4 million for the
same period in 2008. In March 2009, we issued $75 million of MTNs at 5.37
percent, the proceeds of which were primarily used to reduce short-term debt
balances and for general corporate purposes. No shares were purchased
under our common stock repurchase program, and no long-term debt was redeemed in
the six months ended June 30, 2009 and 2008.
Pension
Funding Status
We make
contributions to our qualified defined benefit pension plans based on actuarial
assumptions and estimates, tax regulations and funding requirements under
federal law. The Pension Protection Act of 2006 (the Act) established new
funding requirements for defined benefit plans. The Act establishes a
100 percent funding target for plan years beginning after December 31,
2008. Our qualified defined benefit pension plans were underfunded by
$98.4 million at December 31, 2008. In April 2009, we contributed $25
million. We anticipate no further funding requirements for our
qualified plans in 2009, but we may make additional contributions later this
year that could bring our total contributions in 2009 up to $40
million. For more information on the funding status of our qualified
retirement plans and other postretirement benefits, see Note 7, and Part II,
Item 7., “Financial Condition—Pension Cost and Funding Status of Qualified
Retirement Plans,” and Part II, Item 8., Note 7, “Pension and Other
Postretirement Benefits,” in the 2008 Form 10-K.
We also
contribute to a multiemployer pension plan pursuant to our collective bargaining
agreement. Our total contribution to the Western States Plan in 2008
amounted to $0.4 million. We made contributions totaling $0.2 million
to the Western States Plan for both the six months ended June 30, 2009 and
2008. See Note 7 for further discussion.
Ratios
of Earnings to Fixed Charges
For the
six and twelve months ended June 30, 2009 and the twelve months ended December
31, 2008, our ratios of earnings to fixed charges, computed using the Securities
and Exchange Commission method, were 4.96, 3.87 and 3.76, respectively. For this
purpose, earnings consist of net income before taxes plus fixed charges, and
fixed charges consist of interest on all indebtedness, the amortization of debt
expense and discount or premium and the estimated interest portion of rentals
charged to income. Because a significant part of our business is of a
seasonal nature, the ratios for the interim periods are not necessarily
indicative of the results for a full year.
Contingent
Liabilities
Loss
contingencies are recorded as liabilities when it is probable that a liability
has been incurred and the amount of the loss is reasonably estimable in
accordance with SFAS No. 5, “Accounting for Contingencies” (see Part II, Item
7., “Application of Critical Accounting Policies and Estimates,” in the 2008
Form 10-K). At June 30, 2009, we had a regulatory asset of $70.1
million for environmental costs, which includes $33.7 million of total paid
expenditures to date, $28.7 million for additional environmental costs expected
to be paid in the future and accrued interest of $7.7 million. If it
is determined that both the insurance recovery and future customer rate recovery
of such costs are not probable, then the costs will be charged to expense in the
period such determination is made. For further discussion of
contingent liabilities, see Note 11.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
We are
exposed to various forms of market risk including commodity supply risk,
commodity price risk, interest rate risk, foreign currency risk, credit risk and
weather risk (see Part I, Item 1A., “Risk Factors,” and Part II, Item 7A.
“Quantitative and Qualitative Disclosures about Market Risk,” in the 2008
Form 10-K). The following are updates to certain of these market
risks:
Commodity
Price Risk
Natural
gas commodity prices are subject to fluctuations due to unpredictable factors
including weather, pipeline transportation congestion, potential market
speculation and other factors that affect short-term supply and
demand. Commodity-swap and option contracts (financial hedge
contracts) are used to convert certain natural gas supply contracts from
floating prices to fixed, capped or discounted prices. These
financial hedge contracts are generally included in our annual PGA filing for
cost recovery, subject to a regulatory prudence review. At June 30,
2009 and 2008, notional amounts under these financial hedge contracts totaled
$308.4 million and $332.6 million, respectively. If all of the
commodity-based financial hedge contracts had been settled on June 30, 2009, a
loss of about $72.9 million would have been realized and recorded to a deferred
regulatory account (see Note 10). We regularly monitor and manage the financial
exposure and liquidity risk of our financial hedge contracts under the direction
of our Gas Acquisition Strategies and Policies Committee, which consists of
senior management with Audit Committee oversight. Based on the
existing open interest in the contracts held, we believe financial exposure to
be minimal and existing contracts to be liquid. All of our financial hedge
contracts mature on or before October 31, 2012. The $72.9 million unrealized
loss is an estimate of future cash flows based on forward market prices that are
expected to be paid as follows: $59.4 million in the next
12 months and $13.5 million thereafter. The amount realized will
change based on market prices at the time contract settlements are
fixed.
Credit
Risk
Credit
exposure to financial derivative counterparties. Based
on estimated fair value at June 30, 2009, our credit exposure relating to
commodity hedge contracts reflected an amount we owed of $72.9 million to our
financial derivative counterparties. Our financial derivatives policy
requires counterparties to have a certain minimum investment-grade credit rating
at the time the derivative instrument is entered into, and specific limits on
the contract amount and duration based on each counterparty’s credit
rating. Some counterparties were downgraded but continue to maintain
investment grade ratings (see table below). Due to current market conditions and
credit concerns, we continue to enforce strong credit
requirements. We actively monitor and manage our derivative
credit exposure and place counterparties on hold for trading purposes or require
letters of credit or guarantees as circumstances warrant. Our
derivative credit risk exposure, which reflects amounts that financial
derivative counterparties owe to us, is minimal and all outstanding contracts at
June 30, 2009 expire or are expected to settle on or before October 31,
2012.
The
following table summarizes our credit exposure, based on estimated fair value,
and the corresponding counterparty credit ratings for our unrealized fair value
gains and losses. The table uses credit ratings from S&P and Moody’s,
reflecting the higher of the S&P or Moody’s rating or a middle rating if the
entity is split-rated with more than one rating level difference:
Thousands
|
|
June
30, 2009
|
|
|
June
30, 2008
|
|
|
Dec.
31, 2008
|
|
AAA/Aaa
|
|
$ |
- |
|
|
$ |
8,906 |
|
|
$ |
(16,827 |
) |
AA/Aa
|
|
|
(65,060 |
) |
|
|
45,863 |
|
|
|
(122,287 |
) |
A/A |
|
|
|
|
(7,821 |
) |
|
|
6,013 |
|
|
|
(12,006 |
) |
BBB/Baa
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
|
|
$ |
(72,881 |
) |
|
$ |
60,782 |
|
|
$ |
(151,120 |
) |
To
mitigate the credit risk of financial derivatives we have master
netting arrangements with our counterparties that provide for making or
receiving net cash settlements. Generally, transactions of the same type
in the same currency that have a settlement on the same day with a single
counterparty are netted and a single payment is delivered or received depending
on which party is due funds.
Additionally we have master
contracts in place with each of our derivative counterparties that
usually include provisions for the posting or calling of collateral.
Generally we can obtain cash or marketable securities as
collateral with one day’s notice. We use various collateral
management strategies to reduce liquidity risk. The collateral provisions vary
by counterparty but are not expected to result in the significant posting of
collateral, if any. We have performed stress tests on the portfolio
and concluded that the current liquidity risk from collateral calls is not
material. Our derivative credit exposure is primarily with investment grade
counterparties rated AA-/Aa3 or higher. Contracts are diversified across
counterparties to reduce credit and liquidity risk.
(a)
Evaluation of Disclosure Controls and Procedures
Our
management, under the supervision and with the participation of our Chief
Executive Officer and Chief Financial Officer, has completed an evaluation of
the effectiveness of the design and operation of our disclosure controls and
procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities
Exchange Act of 1934, as amended (the “Exchange Act”)). Based upon
this evaluation, our Chief Executive Officer and Chief Financial Officer have
concluded that, as of the end of the period covered by this report, our
disclosure controls and procedures were effective to ensure that information
required to be disclosed by us and included in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission rules and
forms and that such information is accumulated and communicated to management,
including the Chief Executive Officer and Chief Financial Officer as appropriate
to allow timely decisions regarding required disclosure.
(b)
Changes in Internal Control Over Financial Reporting
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting, as such term is defined in the Exchange Act
Rule 13a-15(f).
There
have been no changes in our internal control over financial reporting that
occurred during the quarter ended June 30, 2009 that have materially affected,
or are reasonably likely to materially affect, our internal control over
financial reporting. The statements contained in Exhibit 31.1 and
Exhibit 31.2 should be considered in light of, and read together with, the
information set forth in this Item 4(b).
PART
II. OTHER INFORMATION
Litigation
We are
subject to claims and litigation arising in the ordinary course of
business. Although the final outcome of any of these legal
proceedings cannot be predicted with certainty, we do not expect that the
ultimate disposition of any of these matters will have a material adverse effect
on our financial condition, results of operations or cash flows.
For a
discussion of certain pending legal proceedings, see Note 11.
There
were no material changes from the risk factors discussed in Part I, “Item 1A.
Risk Factors,” in our 2008 Form 10-K. In addition to the other information set
forth in this report, you should carefully consider those risk factors, which
could materially affect our business, financial condition or results of
operations. The risks described in the 2008 Form 10-K are not the only risks
facing our company. Additional risks and uncertainties not currently known to us
or that we currently deem to be immaterial also may materially affect our
financial condition, results of operations or cash flows.
Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND
USE OF PROCEEDS
The
following table provides information about purchases by us during the quarter
ended June 30, 2009 of equity securities that are registered pursuant to Section
12 of the Exchange Act:
ISSUER
PURCHASES OF EQUITY SECURITIES
|
|
|
|
|
|
|
|
(c)
|
|
|
(d)
|
|
|
|
(a)
|
|
|
(b)
|
|
|
Total Number of Shares
|
|
|
Maximum Dollar Value of
|
|
|
|
Total Number
|
|
|
Average
|
|
|
Purchased as Part of
|
|
|
Shares
that May Yet Be
|
|
|
|
of Shares
|
|
|
Price Paid
|
|
|
Publicly
Announced
|
|
|
Purchased
Under the
|
|
Period
|
|
Purchased (1)
|
|
|
per
Share
|
|
|
Plans or Programs
(2)
|
|
|
Plans or Programs
(2)
|
|
Balance
forward
|
|
|
|
|
|
|
|
|
2,124,528 |
|
|
$ |
16,732,648 |
|
04/01/09
- 04/30/09
|
|
|
1,792 |
|
|
$ |
41.89 |
|
|
|
- |
|
|
|
- |
|
05/01/09
- 05/31/09
|
|
|
22,813 |
|
|
$ |
41.47 |
|
|
|
- |
|
|
|
- |
|
06/01/09
- 06/30/09
|
|
|
3,156 |
|
|
$ |
44.46 |
|
|
|
- |
|
|
|
- |
|
Total
|
|
|
27,761 |
|
|
$ |
41.84 |
|
|
|
2,124,528 |
|
|
$ |
16,732,648 |
|
(1)
|
During
the three months ended June 30, 2009, 26,921 shares of our common stock
were purchased on the open market to meet the requirements of our Dividend
Reinvestment and Direct Stock Purchase Plan. In addition, 840
shares of our common stock were purchased on the open market during the
quarter to meet the requirements of our share-based
programs. During the three months ended June 30, 2009, no
shares of our common stock were accepted as payment for stock option
exercises pursuant to our Restated Stock Option
Plan.
|
(2)
|
We
have a share repurchase program for our common stock under which we
purchase shares on the open market or through privately negotiated
transactions. We currently have Board authorization through May
31, 2010 to repurchase up to an aggregate of 2.8 million shares or up to
an aggregate of $100 million. During the three months ended
June 30, 2009, no shares of our common stock were purchased pursuant to
this program. Since the program’s inception in 2000 we have
repurchased 2.1 million shares of common stock at a total cost of $83.3
million.
|
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS
NW
Natural’s Annual Meeting of Shareholders was held in Portland, Oregon on
May 28, 2009. At the meeting, four director-nominees were elected, as
follows:
|
|
|
|
|
Director
|
Class
|
Term
Expiring
|
Votes
For
|
Votes Withheld
|
Timothy
P. Boyle
|
I
|
2012
|
23,053,175
|
387,132
|
Mark
S. Dodson
|
I
|
2012
|
22,993,053
|
447,254
|
George
J. Puentes
|
I
|
2012
|
23,072,614
|
367,693
|
Gregg
S. Kantor
|
III
|
2011
|
22,973,334
|
466,973
|
The other
seven directors whose terms of office as directors continued after the Annual
Meeting are: Martha L. “Stormy” Byorum, John D. Carter, C. Scott Gibson, Tod R.
Hamachek, Jane J. Peverett, Kenneth Thrasher, and Russell F.
Tromley.
The
following matters also were acted upon at the meeting:
The
ratification of the Audit Committee’s appointment of PricewaterhouseCoopers LLP
as NW Natural’s independent registered public accounting firm for the year 2009
was approved by the following vote:
For
|
Against
|
Abstain
|
23,049,448
|
276,959
|
113,898
|
No other
matters were acted upon at the meeting.
On July
20, 2009, the governor of Oregon signed House Bill 3405 establishing increases
in the state income tax for corporations. The corporate income tax
rate in Oregon for 2010 will increase from 6.6 percent to 7.9 percent for
corporations with taxable income over $250,000. For tax years 2011
and 2012, the income tax rate will decrease to 7.6 percent, and for years after
2012 the tax rate will return to the current 6.6 percent, except for
corporations with taxable income over $10 million the tax rate will remain at
7.6 percent. The new tax rates are retroactive to January 1,
2009. We are in the process of re-measuring our deferred income tax
assets and liabilities in accordance with SFAS No. 109 “Accounting for Income
Taxes,” and determining the accounting recognition for utility regulation in
accordance with SFAS No. 71 “Accounting for the Effects of Certain Types of
Regulation.” With respect to our regulated utility, we expect to
record a regulatory asset for the tax effect of the corporate income tax rate
changes in the third quarter of 2009. With respect to our
non-regulated business segments, we anticipate that we will need to record an
immaterial charge to income tax expense for the impact on those earnings from
the corporate tax rate change.
See Exhibit Index attached hereto.
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.
NORTHWEST NATURAL GAS
COMPANY
(Registrant)
Dated: August 6,
2009
/s/
Stephen P. Feltz
Stephen
P. Feltz
Principal
Accounting Officer
Treasurer
and Controller
NORTHWEST
NATURAL GAS COMPANY
EXHIBIT
INDEX
To
Quarterly
Report on Form 10-Q
For
Quarter Ended
June 30,
2009
|
|
Exhibit
|
Document
|
|
Number
|
|
|
|
|
|
12
|
|
|
|
|
|
31.1
|
|
|
|
|
|
|
|
|
31.2
|
|
|
|
|
|
|
|
|
32.1
|
|
|
|