form10q-2009.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 March 31, 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 April 30, 2009, 26,504,188
shares of the registrant’s Common Stock (the only class of Common Stock)
were outstanding.
NORTHWEST
NATURAL GAS COMPANY
For the Quarterly Period Ended March 31, 2009
|
PART
I. FINANCIAL INFORMATION
|
Page
Number
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1
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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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20
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Item
3.
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37
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Item
4.
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38
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PART
II. OTHER INFORMATION
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Item
1.
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39
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Item
1A.
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39
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Item
2.
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39
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Item
6.
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39
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40
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Forward-Looking
Statements
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, gains or losses from our share of gas costs that are less than or
more than the gas costs embedded in customer rates, exploration of new gas
supplies, 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 national 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
environment and financial services
sector;
|
·
|
capital
market conditions, including their effect on financing costs, the fair
value of pension assets and on 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
|
|
|
|
|
March
31,
|
|
Thousands,
except per share amounts
|
|
2009
|
|
|
2008
|
|
Operating
revenues:
|
|
|
|
|
|
|
Gross operating revenues
|
|
$ |
437,355 |
|
|
$ |
387,694 |
|
Less: Cost
of sales
|
|
|
|
284,174 |
|
|
|
245,920 |
|
Revenue taxes
|
|
|
10,542 |
|
|
|
9,351 |
|
Net operating revenues
|
|
|
142,639 |
|
|
|
132,423 |
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
|
33,955 |
|
|
|
28,458 |
|
General taxes
|
|
|
8,491 |
|
|
|
8,134 |
|
Depreciation and amortization
|
|
|
15,522 |
|
|
|
17,705 |
|
Total
operating expenses
|
|
|
57,968 |
|
|
|
54,297 |
|
Income
from operations
|
|
|
84,671 |
|
|
|
78,126 |
|
Other
income and expense - net
|
|
|
890 |
|
|
|
173 |
|
Interest
charges - net of amounts capitalized
|
|
|
9,370 |
|
|
|
9,430 |
|
Income
before income taxes
|
|
|
76,191 |
|
|
|
68,869 |
|
Income
tax expense
|
|
|
28,828 |
|
|
|
25,701 |
|
Net
income
|
|
$ |
47,363 |
|
|
$ |
43,168 |
|
Average
common shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
26,501 |
|
|
|
26,409 |
|
Diluted
|
|
|
26,597 |
|
|
|
26,560 |
|
Earnings
per share of common stock:
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
1.79 |
|
|
$ |
1.63 |
|
Diluted
|
|
$ |
1.78 |
|
|
$ |
1.63 |
|
See Notes
to Consolidated Financial Statements.
NORTHWEST NATURAL GAS COMPANY
PART
I. FINANCIAL INFORMATION
Consolidated
Balance Sheets
(Unaudited)
|
|
|
|
|
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
Plant
and property:
|
|
|
|
|
|
|
|
|
|
Utility
plant
|
|
$ |
2,158,946 |
|
|
$ |
2,071,072 |
|
|
$ |
2,142,988 |
|
Less
accumulated depreciation
|
|
|
663,417 |
|
|
|
627,265 |
|
|
|
659,123 |
|
Utility
plant - net
|
|
|
1,495,529 |
|
|
|
1,443,807 |
|
|
|
1,483,865 |
|
Non-utility
property
|
|
|
80,689 |
|
|
|
68,815 |
|
|
|
74,506 |
|
Less
accumulated depreciation
|
|
|
9,665 |
|
|
|
8,261 |
|
|
|
9,314 |
|
Non-utility
property - net
|
|
|
71,024 |
|
|
|
60,554 |
|
|
|
65,192 |
|
Total
plant and property
|
|
|
1,566,553 |
|
|
|
1,504,361 |
|
|
|
1,549,057 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
10,341 |
|
|
|
6,417 |
|
|
|
6,916 |
|
Accounts
receivable
|
|
|
99,985 |
|
|
|
82,775 |
|
|
|
81,288 |
|
Accrued
unbilled revenue
|
|
|
61,034 |
|
|
|
56,025 |
|
|
|
102,688 |
|
Allowance
for uncollectible accounts
|
|
|
(4,948 |
) |
|
|
(4,066 |
) |
|
|
(2,927 |
) |
Regulatory
assets
|
|
|
124,085 |
|
|
|
6,288 |
|
|
|
147,319 |
|
Fair
value of non-trading derivatives
|
|
|
4,798 |
|
|
|
34,175 |
|
|
|
4,592 |
|
Inventories:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
|
|
|
82,182 |
|
|
|
25,663 |
|
|
|
86,134 |
|
Materials
and supplies
|
|
|
9,846 |
|
|
|
8,834 |
|
|
|
9,933 |
|
Income
taxes receivable
|
|
|
1,804 |
|
|
|
- |
|
|
|
20,811 |
|
Prepayments
and other current assets
|
|
|
26,339 |
|
|
|
20,652 |
|
|
|
24,216 |
|
Total
current assets
|
|
|
415,466 |
|
|
|
236,763 |
|
|
|
480,970 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments,
deferred charges and other assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Regulatory
assets
|
|
|
284,166 |
|
|
|
179,173 |
|
|
|
288,470 |
|
Fair
value of non-trading derivatives
|
|
|
189 |
|
|
|
1,227 |
|
|
|
146 |
|
Other
investments
|
|
|
68,302 |
|
|
|
56,164 |
|
|
|
54,132 |
|
Other
|
|
|
17,691 |
|
|
|
10,601 |
|
|
|
5,377 |
|
Total
investments, deferred charges and other assets
|
|
|
370,348 |
|
|
|
247,165 |
|
|
|
348,125 |
|
Total
assets
|
|
$ |
2,352,367 |
|
|
$ |
1,988,289 |
|
|
$ |
2,378,152 |
|
See Notes
to Consolidated Financial Statements.
NORTHWEST
NATURAL GAS COMPANY
PART
I. FINANCIAL INFORMATION
Consolidated
Balance Sheets
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
March
31,
|
|
|
March 31,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Capitalization
and liabilities:
|
|
|
|
|
|
|
|
|
|
Capitalization:
|
|
|
|
|
|
|
|
|
|
Common
stock
|
|
$ |
335,261 |
|
|
$ |
332,182 |
|
|
$ |
336,754 |
|
Earnings
invested in the business
|
|
|
332,900 |
|
|
|
299,923 |
|
|
|
296,005 |
|
Accumulated
other comprehensive income (loss)
|
|
|
(4,323 |
) |
|
|
(2,840 |
) |
|
|
(4,386 |
) |
Total
common stock equity
|
|
|
663,838 |
|
|
|
629,265 |
|
|
|
628,373 |
|
Long-term
debt
|
|
|
587,000 |
|
|
|
512,000 |
|
|
|
512,000 |
|
Total
capitalization
|
|
|
1,250,838 |
|
|
|
1,141,265 |
|
|
|
1,140,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Notes
payable
|
|
|
88,600 |
|
|
|
54,600 |
|
|
|
248,000 |
|
Long-term
debt due within one year
|
|
|
- |
|
|
|
5,000 |
|
|
|
- |
|
Accounts
payable
|
|
|
93,304 |
|
|
|
93,061 |
|
|
|
94,422 |
|
Taxes
accrued
|
|
|
14,224 |
|
|
|
23,160 |
|
|
|
12,455 |
|
Interest
accrued
|
|
|
11,215 |
|
|
|
11,287 |
|
|
|
2,785 |
|
Regulatory
liabilities
|
|
|
46,475 |
|
|
|
88,197 |
|
|
|
20,456 |
|
Fair
value of non-trading derivatives
|
|
|
107,461 |
|
|
|
1,703 |
|
|
|
136,735 |
|
Other
current and accrued liabilities
|
|
|
41,414 |
|
|
|
34,970 |
|
|
|
36,467 |
|
Total
current liabilities
|
|
|
402,693 |
|
|
|
311,978 |
|
|
|
551,320 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
credits and other liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes and investment tax credits
|
|
|
267,827 |
|
|
|
221,670 |
|
|
|
257,831 |
|
Regulatory
liabilities
|
|
|
239,561 |
|
|
|
220,137 |
|
|
|
228,157 |
|
Pension
and other postretirement benefit liabilities
|
|
|
140,318 |
|
|
|
42,709 |
|
|
|
138,229 |
|
Fair
value of non-trading derivatives
|
|
|
15,387 |
|
|
|
4,995 |
|
|
|
21,646 |
|
Other
|
|
|
35,743 |
|
|
|
45,535 |
|
|
|
40,596 |
|
Total
deferred credits and other liabilities
|
|
|
698,836 |
|
|
|
535,046 |
|
|
|
686,459 |
|
Commitments
and contingencies (see Note 11)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
capitalization and liabilities
|
|
$ |
2,352,367 |
|
|
$ |
1,988,289 |
|
|
$ |
2,378,152 |
|
See Notes
to Consolidated Financial Statements.
NORTHWEST NATURAL GAS COMPANY
PART
I. FINANCIAL INFORMATION
Consolidated
Statements of Cash Flows
(Unaudited)
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
Operating
activities:
|
|
|
|
|
|
|
Net
income
|
|
$ |
47,363 |
|
|
$ |
43,168 |
|
Adjustments
to reconcile net income to cash provided by operations:
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
15,522 |
|
|
|
17,705 |
|
Deferred
income taxes and investment tax credits
|
|
|
9,848 |
|
|
|
14,432 |
|
Undistributed
gains from equity investments
|
|
|
(288 |
) |
|
|
(25 |
) |
Deferred
gas savings - net
|
|
|
33,974 |
|
|
|
3,740 |
|
Non-cash
expenses related to qualified defined benefit pension
plans
|
|
|
2,490 |
|
|
|
780 |
|
Deferred
environmental costs
|
|
|
(2,669 |
) |
|
|
(2,048 |
) |
Income
from life insurance investments
|
|
|
(1,081 |
) |
|
|
(459 |
) |
Settlement
of interest rate hedge
|
|
|
(10,096 |
) |
|
|
- |
|
Deferred
regulatory and other
|
|
|
(15,020 |
) |
|
|
(13,679 |
) |
Changes
in working capital:
|
|
|
|
|
|
|
|
|
Accounts
receivable and accrued unbilled revenue - net
|
|
|
25,837 |
|
|
|
9,822 |
|
Inventories
of gas, materials and supplies
|
|
|
4,039 |
|
|
|
45,447 |
|
Income
taxes receivable
|
|
|
19,007 |
|
|
|
- |
|
Prepayments
and other current assets
|
|
|
3,677 |
|
|
|
4,917 |
|
Accounts
payable
|
|
|
(928 |
) |
|
|
(28,409 |
) |
Accrued
interest and taxes
|
|
|
10,199 |
|
|
|
18,483 |
|
Other
current and accrued liabilities
|
|
|
5,013 |
|
|
|
5,405 |
|
Cash
provided by operating activities
|
|
|
146,887 |
|
|
|
119,279 |
|
Investing
activities:
|
|
|
|
|
|
|
|
|
Investment
in utility plant
|
|
|
(21,641 |
) |
|
|
(19,263 |
) |
Investment
in non-utility property
|
|
|
(6,171 |
) |
|
|
(1,682 |
) |
Proceeds
from life insurance
|
|
|
120 |
|
|
|
- |
|
Contributions
to non-utility investments
|
|
|
(900 |
) |
|
|
(1,500 |
) |
Other |
|
|
(5,483 |
) |
|
|
(63 |
) |
Cash
used in investing activities
|
|
|
(34,075 |
) |
|
|
(22,508 |
) |
Financing
activities:
|
|
|
|
|
|
|
|
|
Common
stock issued (purchased) - net
|
|
|
(1,184 |
) |
|
|
1,874 |
|
Long-term
debt issued
|
|
|
75,000 |
|
|
|
- |
|
Change
in short-term debt
|
|
|
(172,251 |
) |
|
|
(88,500 |
) |
Cash
dividend payments on common stock
|
|
|
(10,468 |
) |
|
|
(9,903 |
) |
Other |
|
|
(484 |
) |
|
|
68 |
|
Cash
used in financing activities
|
|
|
(109,387 |
) |
|
|
(96,461 |
) |
Increase
in cash and cash equivalents
|
|
|
3,425 |
|
|
|
310 |
|
Cash
and cash equivalents - beginning of period
|
|
|
6,916 |
|
|
|
6,107 |
|
Cash
and cash equivalents - end of period
|
|
$ |
10,341 |
|
|
$ |
6,417 |
|
|
|
|
|
|
|
|
|
|
Supplemental
disclosure of cash flow information:
|
|
|
|
|
|
|
|
|
Interest
paid
|
|
$ |
816 |
|
|
$ |
1,017 |
|
Income
taxes paid
|
|
$ |
- |
|
|
$ |
350 |
|
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 includes our wholly-owned subsidiary
Gill Ranch Storage, LLC (Gill Ranch), and other investments and business
activities, which includes 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 months ended March 31, 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, “Accounting for Derivative Instruments and Hedging
Activities,” 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 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.
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 plan. 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.
Interim
Disclosures about Financial Instruments. In April 2009, the
FASB issued FSP SFAS No. 107-1 and Accounting Principles Board (APB) 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. FSP SFAS No. 107-1 and APB No. 28-1 will be effective for
interim reporting periods ending after June 15, 2009. The adoption of
this statement is not expected to have a material effect on our
disclosures.
Fair Value
Considerations. In April 2009, the FASB issued 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. FSP SFAS No. 157-4 is
effective for interim and annual reporting periods ending after June 15,
2009. The adoption of this statement is not expected to have a
material effect on our financial condition, 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
and a portion of the Mist underground storage facility, and our “other” segment
includes an equity investment in Palomar and our Financial Corporation
subsidiary.
The
following table presents information about the reportable
segments. Inter-segment transactions are insignificant.
|
|
Three
Months Ended March 31,
|
|
Thousands
|
|
Utility
|
|
|
Gas
Storage
|
|
|
Other
|
|
|
Total
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
operating revenues
|
|
$ |
138,094 |
|
|
$ |
4,500 |
|
|
$ |
45 |
|
|
$ |
142,639 |
|
Depreciation
and amortization
|
|
|
15,183 |
|
|
|
339 |
|
|
|
- |
|
|
|
15,522 |
|
Income
from operations
|
|
|
80,894 |
|
|
|
3,745 |
|
|
|
32 |
|
|
|
84,671 |
|
Net
income
|
|
|
45,304 |
|
|
|
2,032 |
|
|
|
27 |
|
|
|
47,363 |
|
Total
assets at March 31, 2009
|
|
$ |
2,244,899 |
|
|
$ |
88,991 |
|
|
$ |
18,477 |
|
|
$ |
2,352,367 |
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
operating revenues
|
|
$ |
127,379 |
|
|
$ |
4,997 |
|
|
$ |
47 |
|
|
$ |
132,423 |
|
Depreciation
and amortization
|
|
|
17,379 |
|
|
|
326 |
|
|
|
- |
|
|
|
17,705 |
|
Income
from operations
|
|
|
73,877 |
|
|
|
3,843 |
|
|
|
406 |
|
|
|
78,126 |
|
Net
income
|
|
|
40,542 |
|
|
|
2,353 |
|
|
|
273 |
|
|
|
43,168 |
|
Total
assets at March 31, 2008
|
|
|
1,908,870 |
|
|
|
65,969 |
|
|
|
13,450 |
|
|
|
1,988,289 |
|
Total
assets at December 31, 2008 |
|
$ |
2,289,601 |
|
|
$ |
72,073 |
|
|
$ |
16,478 |
|
|
$ |
2,378,152 |
|
Included
in total assets at March 31, 2009 and 2008, our major non-utility investments
were as follows:
· |
Mist
gas storage (excluding utility) was $56.0 million and $56.2 million,
respectively; |
·
|
Gill
Ranch was $19.0 million and $0.1 million,
respectively;
|
·
|
Palomar
was $15.5 million and $7.6 million,
respectively;
|
·
|
Financial
Corporation was $1.0 million and $1.1 million, respectively; and
|
· |
Investment
in Boeing 737 (leveraged lease) was $0.0 million and $3.6 million,
respectively, as it was sold in April
2008. |
In March
2009, Gill Ranch entered into a $40 million cash collateralized credit facility
that expires on September 30, 2009. As of March 31, 2009, Gill Ranch
had borrowed loan proceeds of $5.8 million with an effective interest rate of
LIBOR plus 50 basis points.
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 cash proceeds which had
supported the shipper's obligations under the prior agreement. Our maximum
loss exposure related to Palomar at March 31, 2009 would be limited to our
investment balance of $15.5 million less any commitments or credit support from
third parties.
As of
March 31, 2009, common shares authorized were 100,000,000 and outstanding were
26,504,188.
We have a
share repurchase program for our common stock under which we 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 three months
ended March 31, 2009. To date, a total of 2.1 million shares or $83.3
million have been repurchased.
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, with 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 weighted-average
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 the payout of our 2006-08 performance-based
stock awards. Shares 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 weighted-average
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
March 31, 2009, there was $1.1 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.
On March
25, 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.
At March
31, 2009 and 2008 and December 31, 2008, we had outstanding long-term debt as
follows:
|
|
March
31,
|
|
|
March
31,
|
|
|
|
|
|
|
2009
|
|
|
2008
|
|
|
Dec.
31,
|
|
Thousands
|
|
(Unaudited)
|
|
|
(Unaudited)
|
|
|
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
on March 25, 2009.
|
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
|
|
|
|
March
31,
|
|
Thousands,
except per share amounts
|
|
2009
|
|
|
2008
|
|
Net
income
|
|
$ |
47,363 |
|
|
$ |
43,168 |
|
Average
common shares outstanding - basic
|
|
|
26,501 |
|
|
|
26,409 |
|
Additional
shares for stock-based compensation plans
|
|
|
96 |
|
|
|
151 |
|
Average
common shares outstanding - diluted
|
|
|
26,597 |
|
|
|
26,560 |
|
Earnings
per share of common stock - basic
|
|
$ |
1.79 |
|
|
$ |
1.63 |
|
Earnings
per share of common stock - diluted
|
|
$ |
1.78 |
|
|
$ |
1.63 |
|
For the
three months ended March 31, 2009 and 2008, 6,891 and 1,765 common shares,
respectively, were excluded from the calculation of diluted earnings per share
because the effect of these additional shares for both periods would have been
anti-dilutive.
7.
|
Pension
and Other Postretirement
Benefits
|
The
following table provides the components of net periodic benefit cost for our
company-sponsored qualified and non-qualified defined benefit pension plans and
other postretirement benefit plans:
|
|
|
|
|
|
|
|
Other
Postretirement
|
|
|
|
Pension
Benefits
|
|
|
Benefits
|
|
|
|
Three
Months Ended March 31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
Service
cost
|
|
$ |
1,663 |
|
|
$ |
1,655 |
|
|
$ |
147 |
|
|
$ |
133 |
|
Interest
cost
|
|
|
4,492 |
|
|
|
4,301 |
|
|
|
406 |
|
|
|
349 |
|
Expected
return on plan assets
|
|
|
(3,995 |
) |
|
|
(4,777 |
) |
|
|
- |
|
|
|
- |
|
Amortization
of loss
|
|
|
1,659 |
|
|
|
96 |
|
|
|
4 |
|
|
|
- |
|
Amortization
of prior service cost
|
|
|
306 |
|
|
|
314 |
|
|
|
49 |
|
|
|
49 |
|
Amortization
of transition obligation
|
|
|
- |
|
|
|
- |
|
|
|
103 |
|
|
|
103 |
|
Net
periodic benefit cost
|
|
|
4,125 |
|
|
|
1,589 |
|
|
|
709 |
|
|
|
634 |
|
Amount
allocated to construction
|
|
|
(1,178 |
) |
|
|
(379 |
) |
|
|
(232 |
) |
|
|
(207 |
) |
Net
amount charged to expense
|
|
$ |
2,947 |
|
|
$ |
1,210 |
|
|
$ |
477 |
|
|
$ |
427 |
|
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. This plan, the Western States Office and Professional
Employees Pension Fund (Western States Plan), is managed by a Board of Trustees
that includes representatives from participating employers and labor unions.
Contribution rates are established by collective bargaining 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 can be expected
to support. As of March 31, 2009, the Western States Plan had an
accumulated funding deficiency (i.e., a failure to satisfy the minimum funding
requirements) for the current plan year and was declared to be 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 expect the Board of
Trustees to impose a 5 percent surcharge to participating employers in 2009 and
a 10 percent contribution surcharge for years thereafter, and also reduce
benefit rates and adjustable benefits for active employee participants as part
of its rehabilitation plan to improve funding status of the plan. It
is uncertain as to whether other actions will be necessary, including when
higher surcharges may be imposed on participating employers or whether we
may withdraw from the plan subject to consent from NW Natural's
bargaining unit employees. As we have no current intent to withdraw
from the plan, 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 $0.7
million and $0.6 million during the three months ended March 31, 2009 and 2008,
respectively. We also made contributions totaling $0.1 million to the
Western States Plan for both the three months ended March 31, 2009 and
2008. For more information see Part II, Item 8., Note 7, in the
2008 Form 10-K.
Items
that are 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, $2.8 million and $4.4 million at March 31,
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 months ended March 31, 2009 and
2008.
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
Net
income
|
|
$ |
47,363 |
|
|
$ |
43,168 |
|
Amortization
of employee benefit plan liability, net of tax
|
|
|
63 |
|
|
|
55 |
|
Change
in unrealized loss from derivatives, net of tax
|
|
|
- |
|
|
|
604 |
|
Total
comprehensive income
|
|
$ |
47,426 |
|
|
$ |
43,827 |
|
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 March 31, 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 assumptions 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 March 31, 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 March 31, 2009 and 2008 and December
31, 2008.
The
following table provides the fair value measurements for our derivative assets
and liabilities as of March 31, 2009 and 2008 and December 31, 2008 in
accordance with the fair value hierarchy under SFAS No. 157:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March
31,
|
|
|
March
31,
|
|
|
Dec.
31,
|
|
Thousands
|
Description
of Derivative Inputs
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Level
1
|
Quoted
prices in active markets
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
Level
2
|
Significant
other observable inputs
|
|
|
(117,861 |
) |
|
|
28,704 |
|
|
|
(153,643 |
) |
Level
3
|
Significant
unobservable inputs
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
$ |
(117,861 |
) |
|
$ |
28,704 |
|
|
$ |
(153,643 |
) |
10.
|
Derivatives
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 hedge
level of approximately 75 percent of our normal weather anticipated year round
sales volumes. 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
financially hedged volumes outstanding at March 31, 2009 totaled 391 million
therms. These amounts include hedged volumes for the current and next
gas year. At March 31, 2009, we were approximately 60 to 70 percent
hedged for the remainder of the 2008-09 gas year and approximately 30
percent financially hedged for the 2009-10 gas year based on normal weather
anticipated sales volumes.
In
accordance with SFAS No. 161, the following table discloses the amounts and
balance sheet presentation of our derivative instruments as of March 31, 2009
and 2008 and December 31, 2008:
|
|
Fair
Value of Derivative Instruments
|
|
Thousands
|
|
Mar.
31, 2009
|
|
|
Mar.
31, 2008
|
|
|
Dec.
31, 2008
|
|
|
|
Current
|
|
|
Non-Current
|
|
|
Current
|
|
|
Non-Current
|
|
|
Current
|
|
|
Non-Current
|
|
Assets (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
$ |
4,798 |
|
|
$ |
189 |
|
|
$ |
34,175 |
|
|
$ |
1,227 |
|
|
$ |
4,592 |
|
|
$ |
146 |
|
Total
|
|
$ |
4,798 |
|
|
$ |
189 |
|
|
$ |
34,175 |
|
|
$ |
1,227 |
|
|
$ |
4,592 |
|
|
$ |
146 |
|
Liabilities (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity
contracts
|
|
$ |
107,307 |
|
|
$ |
15,387 |
|
|
$ |
1,595 |
|
|
$ |
1,383 |
|
|
$ |
136,290 |
|
|
$ |
9,734 |
|
Interest
rate contracts
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,613 |
|
|
|
- |
|
|
|
11,912 |
|
Foreign
exchange contracts
|
|
|
154 |
|
|
|
- |
|
|
|
108 |
|
|
|
- |
|
|
|
445 |
|
|
|
- |
|
Total
|
|
$ |
107,461 |
|
|
$ |
15,387 |
|
|
$ |
1,703 |
|
|
$ |
4,996 |
|
|
$ |
136,735 |
|
|
$ |
21,646 |
|
(1)
|
The
unrealized fair value gains are classified under current- or non-current
assets as fair value of non-trading
derivatives.
|
(2)
|
The
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 amounts and
income statement presentation of our derivative instruments. It also
illustrates that all fair value measurements are related to regulated utility
operations and are deferred to balance sheet accounts in accordance with
regulatory accounting under SFAS No. 71 for the three months ended March 31,
2009 and 2008.
|
|
Unrealized
Gains (Losses) from Derivative Instruments for the three months
ended
|
|
|
|
March
31, 2009
|
|
|
March
31, 2008
|
|
Thousands
|
|
Commodity contracts (1)
|
|
|
Foreign exchange contracts (3)
|
|
|
Commodity contracts (1)
|
|
|
Interest rate contracts (2)
|
|
|
Foreign exchange contracts (3)
|
|
Cost
of sales
|
|
$ |
(117,707 |
) |
|
$ |
- |
|
|
$ |
32,425 |
|
|
$ |
- |
|
|
$ |
- |
|
Other
comprehensive income
|
|
|
- |
|
|
|
(154 |
) |
|
|
(564 |
) |
|
|
(3,613 |
) |
|
|
(108 |
) |
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amounts
deferred to regulatory accounts on balance sheet
|
|
|
117,707 |
|
|
|
154 |
|
|
|
(31,861 |
) |
|
|
3,613 |
|
|
|
108 |
|
Total
impact on earnings
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
(1)
|
Unrealized
gain (loss) from 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 hedge 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 quarter
or at the end of the quarter with our derivative counterparties. We
calculate our potential exposure to collateral calls by our counterparties
to manage our
liquidity risk. Based on our current credit rating, most
counterparties give 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. To be conservative, 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. The fair value
associated with the amounts in the table below is a $116.3 million
unrealized loss. The following table discloses the estimates of
potential collateral calls with and without adequate assurance calls,
using outstanding derivative instruments at March 31, 2009, based on current
gas prices and with various credit rating scenarios for NW Natural.
Thousands
|
|
|
|
|
BBB+/Baa1
|
|
|
BBB/Baa2
|
|
|
BBB-/Baa3
|
|
|
Speculative
|
|
With
Adequate Assurance Calls
|
|
$ |
(1,086 |
) |
|
$ |
(6,086 |
) |
|
$ |
(14,361 |
) |
|
$ |
(35,490 |
) |
|
$ |
(88,518 |
) |
Without
Adequate Assurance Calls
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(5,775 |
) |
|
$ |
(24,403 |
) |
|
$ |
(72,432 |
) |
In the
three months ended March 31, 2009, we realized net losses of $79.3 million from
the settlement of natural gas hedge contracts, which were recorded as increases
to the cost of gas, compared to net gains of $4.3 million in 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 maturity period 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 transact
business with us.
Our
financial derivative 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 more than offset the exposures they
modify.
Some of
our counterparties were recently downgraded but continue to maintain strong
investment grade credit ratings. Due to current market conditions and
credit concerns, we continue to enforce a high level of credit requirements for
financial derivative counterparties in accordance with our policy. We actively
monitor our derivative credit exposure and place counterparties on hold for
trading purposes or require letters of credit, cash collateral or guarantees as
circumstances warrant.
Our
ongoing assessment of counterparty credit risk includes consideration of credit
ratings, the credit default swap market, bond market credit spreads, financial
results, 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
trading limits. The duration of our credit risk for all outstanding
derivatives currently does not extend beyond October 31, 2010.
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 subject to
review and potentially deferred for rate recovery. All of our
existing counterparties currently have investment-grade credit ratings, and
as of March 31, 2009, we have no exposure to a derivative credit loss with
any counterparty.
As of
March 31, 2009, all outstanding natural gas hedge contracts were scheduled to
mature on or before October 31, 2010.
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 accrued of $19.4 million at March 31, 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 investigations is ongoing. The net
liability accrued at March 31, 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. In 2008, we received a
revised estimate and updated our estimate for additional expenditures related to
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, EPA invited all parties (approximately 70) to whom it has thus
far 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 . Approximately 60
parties have “convened” to negotiate an agreement outlining the process for a
non-judicial allocation. An initial allocation process agreement has
been developed and is presently being circulated for execution. As of
March 31, 2009, we have a net liability accrued of $12.6 million for this site,
which is at the low end of the range of the 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 deposit of tar in the river sediments adjacent to the Gasco
site. We completed the 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
March 31, 2009, we have a net liability accrued of $0.6 million for our estimate
of ongoing costs related to the 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 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 March 31, 2009, we have
a net liability 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 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 . As of March 31, 2009, we accrued an estimated liability
of $0.3 million for the study of the site, which will include investigation of
sediments and provide a 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 March 31, 2009 and 2008 and December 31,
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current
Liabilities
|
|
|
Non-Current
Liabilities
|
|
|
|
March
31,
|
|
|
March
31,
|
|
|
Dec.
31,
|
|
|
March
31,
|
|
|
March
31,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Gasco
site
|
|
$ |
8,457 |
|
|
$ |
8,444 |
|
|
$ |
6,012 |
|
|
$ |
10,935 |
|
|
$ |
12,406 |
|
|
$ |
14,701 |
|
Siltronic
site
|
|
|
831 |
|
|
|
1,502 |
|
|
|
682 |
|
|
|
114 |
|
|
|
- |
|
|
|
332 |
|
Portland
Harbor site
|
|
|
- |
|
|
|
1,454 |
|
|
|
277 |
|
|
|
13,191 |
|
|
|
12,887 |
|
|
|
13,642 |
|
Central
Service Center site
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
526 |
|
|
|
529 |
|
|
|
526 |
|
Front
Street site
|
|
|
294 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
294 |
|
Other
sites
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
64 |
|
|
|
84 |
|
|
|
80 |
|
Total
|
|
$ |
9,582 |
|
|
$ |
11,400 |
|
|
$ |
6,971 |
|
|
$ |
24,830 |
|
|
$ |
25,906 |
|
|
$ |
29,575 |
|
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, this authorization has
been extended through January 25, 2009. We have requested
another extension from the OPUC, which is currently
pending.
On a
cumulative basis, we have recognized a total of $71.2 million for environmental
costs, including legal, investigation, monitoring and remediation
costs. Of this total, $36.8 million has been spent to date and $34.4
million is reported as an outstanding liability. At March 31, 2009,
we had a regulatory asset of $67.8 million, which includes $32.0 million of
total paid expenditures to date, $29.0 million for additional environmental
costs expected to be paid in the future and accrued interest of $6.8
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 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 March 31, 2009 and 2008 and
December 31, 2008:
|
|
Non-Current
Regulatory Assets
|
|
|
|
March
31,
|
|
|
March
31,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Gasco
site
|
|
$ |
31,493 |
|
|
$ |
29,414 |
|
|
$ |
30,707 |
|
Siltronic
site
|
|
|
2,223 |
|
|
|
2,247 |
|
|
|
2,327 |
|
Portland
Harbor site
|
|
|
32,820 |
|
|
|
30,880 |
|
|
|
31,791 |
|
Central
Service Center site
|
|
|
548 |
|
|
|
545 |
|
|
|
545 |
|
Front
Street site
|
|
|
347 |
|
|
|
- |
|
|
|
338 |
|
Other
sites
|
|
|
350 |
|
|
|
300 |
|
|
|
396 |
|
Total
|
|
$ |
67,781 |
|
|
$ |
63,386 |
|
|
$ |
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.
NORTHWEST NATURAL GAS COMPANY
PART
I. FINANCIAL INFORMATION
Item
2. MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
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
months ended March 31, 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. 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).
Executive
Summary
Highlights of the first quarter of 2009 include:
·
|
Consolidated
net income increased 10 percent from $43.2 million in the first
quarter of 2008 to $47.4 million, or $1.78 per share, in the first quarter
of 2009;
|
·
|
Net
operating revenues increased 8 percent from $132.4 million to $142.6
million, largely due to gains from our regulatory share of gas cost
savings;
|
·
|
Income
from utility operations increased 9 percent from $73.9 million to $80.9
million, while income from gas storage operations decreased 3 percent from
$3.8 million to $3.7 million;
|
·
|
Cash
flow from operations increased 23 percent from $119.3 million to $146.9
million, primarily due to deferred gas cost savings;
and
|
·
|
We
celebrated our company's 150th anniversary in January
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 have hedged gas prices for the majority of our gas
purchases for the gas contract year that began on November 1, 2008, and we
believe we have sufficient supplies of natural gas to meet the needs of our core
utility customers. During the first quarter of 2009, the market price of natural
gas has continued to be below the prices embedded in our customers’ rates
through our annual purchased gas adjustment (PGA) resulting in increased margin
from our regulatory share of gas cost savings. 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
started to lock in gas prices for next year and may begin to hedge future years
prices based on current price levels, and we continue to develop other gas
acquisition strategies to manage future gas prices and efficiently meet
demands.
Economic
weakness and financial market stress. The overall weakness in
the U.S. economy, has resulted in significant negative pressure on consumer
demand and business spending. These conditions could have a negative
impact on our financial results including certain performance measures
such as margins, customer growth rates, bad debt expense, and net interest
charges. Our annual customer growth rate slowed to 1.2 percent at
March 31, 2009 compared to 2.5 percent at March 31, 2008. Based on
current market conditions, we expect customer growth rates in 2009 to continue
below 2008 levels, and possibly decline more if economic conditions deteriorate
further. Our growth rate has the potential to remain above the
national average due to a comparatively low market penetration of
natural gas in our service territory, the forecasted population growth in our
service territory, the potential for environmental initiatives in Oregon and
Washington that could favor natural gas as an energy source, and our efforts to
convert existing homes from other heating fuels to natural
gas.
Our
funding for strategic and other capital investment opportunities is dependent
upon our ability to access capital markets and maintain working capital
sufficient to meet operating requirements. We intend to continue
focusing on: maintaining a strong balance sheet; providing sufficient liquidity
resources; monitoring and managing critical business risks; and securing, as
needed, proceeds from the issuance of equity or long-term debt securities in
order to fund utility and business development capital
expenditures. To help mitigate the effect of the negative economic
and capital market trends referred to above, we expect to manage costs, extend
short-term debt maturities, maintain higher cash balances, maintain the ability
to increase the amount of committed credit facilities, and access
capital markets as needed to secure proceeds from the issuance of long-term
securities for capital expenditure requirements. 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, including our liquidity position, is strong and we can
access 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 recently completed a new 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 our economic and competitive
challenges, we intend to continue re-assessing business processes for improved
efficiencies. Our goal to integrate, consolidate and streamline operations and
support our employees with new technology tools is underway. 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 improve overall operating efficiencies with:
·
|
the
integration of systems and data;
|
·
|
automated
control procedures with auditable financial and operational workflows;
and
|
·
|
improved
monthly closing and financial reporting
processes.
|
In
2008, we initiated a project to automate the reading of gas meters (AMR) for the
remaining two-thirds of our customers. The meters equipped with this 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. These technology investments and other initiatives are expected
to facilitate process improvements and contribute to long-term operational
efficiencies 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. We expect to receive a decision on our application by the
end of this year. Gill Ranch will become subject to CPUC
regulation regarding various matters including, but not limited to, securities
issuances, lien grants and sales of property. We estimate our share
of the total cost of this project to be between $160 and $180
million. Our share represents 75 percent of the total cost of the
initial phase of storage development, which includes an estimated 20 Bcf of gas
storage capacity and approximately 27 miles of gas transmission
pipeline. The initial phase of gas storage at Gill Ranch is
currently scheduled to be in-service by late 2010.
Pipeline Diversification. Currently, we depend on a single interstate
pipeline company to ship gas supplies to our 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 connect
with our 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 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 delivery options and enhance the
reliability of service to our utility customers by providing an alternate
transportation path for gas purchases from different regions in western Canada
and the U.S. Rocky Mountains. The west segment of Palomar would also
provide our utility customers with 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—Investing
Activities," below for further discussion on Palomar.
Earnings
and Dividends
Net income was $47.4
million, or $1.78 per share, for the three months ended March 31, 2009, compared
to $43.2 million, or $1.63 per share, for the same period last
year.
The primary factors contributing to the $4.2 million increase in net income
were:
·
|
an
$8.4 million gain in utility margin from our regulatory share of gas cost
savings, compared to a margin loss of $0.4 million from our share of gas
cost increases in the first quarter of 2008;
and
|
·
|
a
$2.5 million increase from a regulatory adjustment for income taxes paid
versus collected in rates.
|
Partially offsetting the above factors were:
·
|
a
$5.5 million increase in operations and maintenance expense primarily due
to increases in incentive pay accruals, employee pension costs and bad
debt expense; and
|
·
|
a
decrease in utility margin from industrial sales and transportation of
$0.9 millions due to lower volumes.
|
Dividends paid on our common stock were 39.5 cents per share in the first
quarter of 2009, compared to 37.5 cents per share in the first quarter of
2008. In April 2009, the Board of Directors declared a quarterly
dividend on our common stock of 39.5 cents per share, payable on May 15, 2009 to
shareholders of record on April 30, 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),
Washington Utilities and Transportation Commission (WUTC) and
FERC. The OPUC and WUTC also regulate our issuance of
securities. In 2009, approximately 90 percent of our utility gas
volumes were 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
Washington economies in general, and by the pace of growth in the residential
and commercial markets in particular, and 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 March
31, 2009 and 2008 and at December 31, 2008, the amounts deferred as regulatory
assets and liabilities were as follows:
|
|
Current
|
|
|
|
March
31,
|
|
|
March
31,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Regulatory
assets:
|
|
|
|
|
|
|
|
|
|
Unrealized loss on non-trading derivatives(1)
|
|
$ |
107,461 |
|
|
$ |
1,703 |
|
|
$ |
136,735 |
|
Pension and other postretirement benefit
obligations(2)
|
|
|
8,074 |
|
|
|
1,912 |
|
|
|
8,074 |
|
Other(4)
|
|
|
8,550 |
|
|
|
2,673 |
|
|
|
2,510 |
|
Total
regulatory assets
|
|
$ |
124,085 |
|
|
$ |
6,288 |
|
|
$ |
147,319 |
|
Regulatory
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
costs payable
|
|
$ |
31,925 |
|
|
$ |
41,422 |
|
|
$ |
5,284 |
|
Unrealized gain on non-trading derivatives(1)
|
|
|
4,798 |
|
|
|
33,611 |
|
|
|
4,592 |
|
Other(4)
|
|
|
9,752 |
|
|
|
13,164 |
|
|
|
10,580 |
|
Total
regulatory liabilities
|
|
$ |
46,475 |
|
|
$ |
88,197 |
|
|
$ |
20,456 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-Current
|
|
|
|
March
31,
|
|
|
March
31,
|
|
|
Dec.
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Regulatory
assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on non-trading derivatives(1)
|
|
$ |
15,387 |
|
|
$ |
4,995 |
|
|
$ |
21,646 |
|
Income
tax asset
|
|
|
70,096 |
|
|
|
69,547 |
|
|
|
69,948 |
|
Pension and other postretirement benefit
obligations(2)
|
|
|
111,851 |
|
|
|
26,678 |
|
|
|
113,869 |
|
Environmental costs - paid(3)
|
|
|
38,804 |
|
|
|
30,004 |
|
|
|
36,135 |
|
Environmental costs - accrued but not yet
paid(3)
|
|
|
28,977 |
|
|
|
33,459 |
|
|
|
29,969 |
|
Other(4)
|
|
|
19,051 |
|
|
|
14,490 |
|
|
|
16,903 |
|
Total
regulatory assets
|
|
$ |
284,166 |
|
|
$ |
179,173 |
|
|
$ |
288,470 |
|
Regulatory
liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
costs payable
|
|
$ |
9,201 |
|
|
$ |
7,281 |
|
|
$ |
1,868 |
|
Unrealized gain on non-trading derivatives(1)
|
|
|
189 |
|
|
|
1,227 |
|
|
|
146 |
|
Accrued
asset removal costs
|
|
|
227,770 |
|
|
|
209,248 |
|
|
|
223,716 |
|
Other(4)
|
|
|
2,401 |
|
|
|
2,381 |
|
|
|
2,427 |
|
Total
regulatory liabilities
|
|
$ |
239,561 |
|
|
$ |
220,137 |
|
|
$ |
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 evaluate the utility’s financial performance. If utility earnings
exceed a threshold level, then 33 percent of the 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 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 PGA year in Oregon beginning on November
1, 2008, we selected the 80 percent deferral of gas cost
differences. The earnings threshold is currently 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. We do not expect that any amounts will be required to be refunded to
customers as a result of the 2008 earnings review, which will be approved by the
OPUC during the second quarter of 2009. 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. 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, this authorization has been
extended through January 25, 2009. We have requested another
extension from the OPUC, which is currently pending. 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.
|
We filed our 2008 IRP with the OPUC and an update to our 2007 IRP with the WUTC
in April 2008. In October 2008, we received notification from the
WUTC that our 2007 IRP met the requirements of the Washington Administrative
Code. 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. The WUTC has indicated that the IRP process is one factor it will
consider in a prudency review.
On March
31, 2009, we filed our 2009 IRP with the WUTC. We anticipate that the WUTC will
review and comment on the document by the end of 2009.
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 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
plan to seek approval to recover the deferred costs in our next 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 these new rates will decrease
depreciation expense and increase effective income tax expense rates, both of
which will be 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 on May 4,
2009 and the new depreciation rates are 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 to
a regulatory account for refund to customers (see “Purchased Gas Adjustment,”
above). Ordinarily, these refunds would be included in customer rates
under next year’s PGA filing. However, in April 2009 we sought
regulatory approval from the OPUC to immediately refund an aggregate $32
million to our Oregon customers through billing credits. If approved,
we intend to refund this amount to customers during the second quarter of
2009.
Business
Segments - Utility Operations
Our
utility margin results are 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.
Utility
operations resulted in net income of $45.3 million, or $1.70 per share, in the
first quarter of 2009 compared to $40.5 million, or $1.53 per share, in first
quarter of 2008. The most significant factors contributing to the
$4.8 million increase in earnings were the margin gains from our regulatory
share of gas cost savings and from a regulatory adjustment for income taxes
paid. Total utility margin increased $10.7 million, with $8.8 million
from our share of lower gas costs and $2.5 million from the regulatory tax
adjustment, partially offset by a $4.4 million decrease in margin from lower
depreciation rates (see “Consolidated Operating Expenses—Depreciation and
Amortization,” below). Even though weather was 2 percent colder than
last year, total utility volumes decreased 38 million therms, or 8 percent,
primarily from reduced usage by industrial customers due to economic conditions.
The
following tables summarize the composition of utility volumes, operating
revenues and margin:
|
|
Three
months ended
|
|
|
|
|
|
|
March
31,
|
|
|
Favorable/
|
|
Thousands,
except degree day and customer data
|
|
2009
|
|
|
2008
|
|
|
(Unfavorable)
|
|
Utility volumes -
therms:
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
|
178,389 |
|
|
|
182,368 |
|
|
|
(3,979 |
) |
Commercial
sales
|
|
|
103,117 |
|
|
|
106,956 |
|
|
|
(3,839 |
) |
Industrial
- firm sales
|
|
|
12,037 |
|
|
|
14,542 |
|
|
|
(2,505 |
) |
Industrial
- firm transportation
|
|
|
35,401 |
|
|
|
48,986 |
|
|
|
(13,585 |
) |
Industrial
- interruptible sales
|
|
|
22,899 |
|
|
|
26,042 |
|
|
|
(3,143 |
) |
Industrial
- interruptible transportation
|
|
|
59,467 |
|
|
|
70,382 |
|
|
|
(10,915 |
) |
Total
utility volumes sold and delivered
|
|
|
411,310 |
|
|
|
449,276 |
|
|
|
(37,966 |
) |
Utility operating revenues -
dollars:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
$ |
253,057 |
|
|
$ |
225,683 |
|
|
$ |
27,374 |
|
Commercial
sales
|
|
|
129,350 |
|
|
|
114,964 |
|
|
|
14,386 |
|
Industrial
- firm sales
|
|
|
13,704 |
|
|
|
13,822 |
|
|
|
(118 |
) |
Industrial
- firm transportation
|
|
|
1,402 |
|
|
|
1,586 |
|
|
|
(184 |
) |
Industrial
- interruptible sales
|
|
|
21,939 |
|
|
|
19,681 |
|
|
|
2,258 |
|
Industrial
- interruptible transportation
|
|
|
1,922 |
|
|
|
2,095 |
|
|
|
(173 |
) |
Regulatory
adjustment for income taxes paid (1)
|
|
|
3,513 |
|
|
|
1,055 |
|
|
|
2,458 |
|
Other
revenues
|
|
|
7,913 |
|
|
|
3,756 |
|
|
|
4,157 |
|
Total
utility operating revenues
|
|
|
432,800 |
|
|
|
382,642 |
|
|
|
50,158 |
|
Cost of gas sold
|
|
|
284,164 |
|
|
|
245,912 |
|
|
|
(38,252 |
) |
Revenue
taxes
|
|
|
10,542 |
|
|
|
9,351 |
|
|
|
(1,191 |
) |
Utility
margin
|
|
$ |
138,094 |
|
|
$ |
127,379 |
|
|
$ |
10,715 |
|
Utility
margin: (2)
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
sales
|
|
$ |
86,333 |
|
|
$ |
87,592 |
|
|
$ |
(1,259 |
) |
Commercial
sales
|
|
|
33,774 |
|
|
|
34,634 |
|
|
|
(860 |
) |
Industrial
- sales and transportation
|
|
|
7,422 |
|
|
|
8,331 |
|
|
|
(909 |
) |
Miscellaneous
revenues
|
|
|
1,892 |
|
|
|
1,728 |
|
|
|
164 |
|
Gain
(loss) from gas cost incentive sharing
|
|
|
8,432 |
|
|
|
(353 |
) |
|
|
8,785 |
|
Other
margin adjustments
|
|
|
498 |
|
|
|
346 |
|
|
|
152 |
|
Margin
before regulatory adjustments
|
|
|
138,351 |
|
|
|
132,278 |
|
|
|
6,073 |
|
Weather
normalization adjustment
|
|
|
(8,714 |
) |
|
|
(7,548 |
) |
|
|
(1,166 |
) |
Decoupling
adjustment
|
|
|
4,944 |
|
|
|
1,594 |
|
|
|
3,350 |
|
Regulatory adjustment for income taxes paid (1)
|
|
|
3,513 |
|
|
|
1,055 |
|
|
|
2,458 |
|
Utility
margin
|
|
$ |
138,094 |
|
|
$ |
127,379 |
|
|
$ |
10,715 |
|
Customers - end of
period:
|
|
|
|
|
|
|
|
|
|
|
|
|
Residential
customers
|
|
|
601,917 |
|
|
|
594,431 |
|
|
|
7,486 |
|
Commercial
customers
|
|
|
62,541 |
|
|
|
62,035 |
|
|
|
506 |
|
Industrial
customers
|
|
|
929 |
|
|
|
949 |
|
|
|
(20 |
) |
Total
number of customers - end of period
|
|
|
665,387 |
|
|
|
657,415 |
|
|
|
7,972 |
|
Actual
degree days
|
|
|
2,021 |
|
|
|
1,980 |
|
|
|
|
|
Percent colder (warmer) than average
(3)
|
|
|
8 |
% |
|
|
5 |
% |
|
|
|
|
(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.
|
Residential
and Commercial Sales
Residential and commercial sales are impacted by
customer growth, seasonal weather patterns, energy prices, competition from
other energy sources and economic conditions in our service
areas. 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 will affect volumes of gas sold to these customers, the effect on margin
and net income is significantly reduced due to our weather normalization
mechanism in Oregon where about 90 percent of our customers are served, and is
effective from December 1 through May 15 of each heating
season. Approximately 10 percent of our eligible Oregon customers
have opted out of the mechanism. 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 fully insulated from
earnings volatility due to weather and
conservation.
For the
three months ended March 31, 2009 compared to March 31, 2008, we
experienced:
·
|
3 percent lower
sales volumes from residential and commercial customers due to weak
economic conditions and customers conserving more, partially offset by
weather that was 2 percent colder than last year;
and
|
·
|
annual
customer growth of 1.2 percent in 2009 as compared to 2.5 percent in
2008.
|
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 March 31, 2009, accrued
unbilled revenue was $61.0 million, compared to $56.0 million at March 31, 2008,
a 9 percent increase primarily due to higher billing rates in
2009.
Industrial
Sales and Transportation
Industrial
operating revenues include the commodity cost component of gas sold under sales
service but not for transportation service. Therefore, industrial customer
switching between sales service and transportation service can cause swings in
operating revenues, but generally our margins are not affected because we do not
mark up the cost of gas. In addition, a significant portion of 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. The primary factors that impacted results of operations
in industrial sales and transportation markets are as follows:
·
|
volumes
delivered to industrial customers decreased by 30.1 million therms, or 19
percent; and
|
·
|
margin
decreased $0.9 million, or 11 percent, reflecting reduced usage due to the
current economic environment, partially offset by fixed charges that are
not affected by declining use.
|
Several
large industrial customers transferred from sales service back to transportation
service since mid-year 2008. High natural gas prices can result in a
number of our large industrial customers switching from transportation service,
where they arrange for their own supplies through independent third parties, to
sales service, where we sell them the gas commodity under regulatory tariffs. In
such cases, our tariff requires us to charge any incremental cost of gas supply
incurred to those customers.
Regulatory
Adjustment for Income Taxes Paid
In
Oregon, Senate Bill 408 (SB 408) requires utilities to true-up any differences
between income taxes authorized to be collected in rates from customers and
income taxes actually paid to governmental entities that are “properly
attributed” to the utilities’ regulated operations. Utilities are
required to file a tax report with the OPUC reporting these amounts on October
15 of each year. If amounts collected and amounts paid differ by
$100,000 or more, then the OPUC must order the utility to establish an automatic
adjustment clause to account for the difference, with a rate adjustment to be
effective June 1 of each year.
Based on
our regulated operations through March 31, 2009, we recognized $3.5 million of
pre-tax income representing a difference of $3.3 million of federal and state
income taxes paid in excess of taxes collected in rates plus accrued interest of
$0.2 million attributed to the 2007 and 2009 tax years. This
indicated surcharge was primarily driven by gains from gas cost savings from our
PGA incentive mechanism during the first quarter of 2009. For the
three months ended March 31, 2008, we recognized a surcharge of $1.1 million
representing $0.7 million attributed to regulated operations for the 2008 tax
year and a $0.4 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. Other revenues were
$7.9 million in the first quarter of 2009, an increase of $4.2 million over the
first quarter of 2008, with the increase primarily due to a net increase in the
deferral and amortization related to the decoupling
adjustment. Although the decoupling adjustment can have a material
impact on gross operating revenues, it does not have a material impact on margin
because it generally offsets increases and decreases in customer sales
margins.
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, under the terms of our financial
derivatives policies to help manage our exposure to rising gas
prices. Gains and losses from financial hedge contracts are generally
included 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, utility gas hedges entered
into after the annual PGA filing in Oregon may impact net income to the extent
of our share of any gain or loss under the PGA. In Washington, 100 percent of
the actual gas costs, including 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). For
the three months ended March 31, 2009:
·
|
total
cost of gas sold increased $38.3 million or 16 percent compared to
2008;
|
·
|
the
average gas cost collected through rates increased 20 percent from 75
cents per therm in 2008 to 90 cents per therm in 2009, primarily
reflecting cost increases that were passed through to customers through
PGA rate increases effective November 1, 2008;
and
|
·
|
hedge
losses totaling $79.3 million were realized, compared to $4.3 million of
hedge gains in the same period of
2008.
|
For the
three months ended March 31, 2009, our actual gas costs were lower than gas
costs embedded in rates, while during the three months ended March 31, 2008 and
the year ended December 31, 2008 our actual gas costs were higher than the gas
costs embedded in rates. The effect on net income from the gas cost
incentive sharing mechanism was a margin gain of $8.4 million in the first
quarter of 2009, compared to a margin loss of $0.4 million for the three months
ended March 31, 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 and Gill Ranch. In
the first quarter of 2009, we earned $2.0 million, or 8 cents per share, from
our gas storage segment, after regulatory sharing and income taxes. This
compares to net income of $2.4 million, or 9 cents per share, in the first
quarter of 2008. The $0.4 million decrease in earnings over 2008 is
due to decreased revenues from optimization services under a contract with an
independent energy marketing company. See Part I, Item 1., “Business
Segments—Gas Storage,” in our 2008 Form 10-K.
In
Oregon, we retain 80 percent of the pre-tax income from gas storage services as
well as from optimization services when the costs of the capacity being used is
not included in utility rates, or 33 percent of the 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 in the process of developing a second underground storage facility,
Gill Ranch, and related pipeline near Fresno, California. Our Gill
Ranch project is expected to serve the California and west coast
market. See Note 2.
Other
Our other
business segment consists of Financial Corporation, an equity investment in
Palomar and other non-utility investments and business
activities. Financial Corporation’s total investment balance as of
March 31, 2009 and 2008 were $1.0 million and $1.1 million, respectively, and
our equity balance in the proposed Palomar transmission pipeline was $15.5
million and $7.6 million, respectively. Our total assets at Financial
Corporation reflect a non-controlling interest in the Kelso Beaver pipeline. The
current equity balance in Palomar reflects our investment to date in a proposed
217-mile transmission pipeline. Net income from our other business
segment for the first quarter of 2009 and 2008 was less than $0.1 million and
$0.3 million, respectively. For further information, see Note
2.
Consolidated
Operating Expenses
Operations
and Maintenance
Operations
and maintenance expense in the first quarter of 2009 was $34.0 million, compared
to $28.5 million in 2008, an increase of $5.5 million or 19 percent. The major
factors that contributed to the increase in operations and maintenance expense
are:
·
|
a
$1.7 million increase in bonus accruals due to higher operating results
primarily from our gas cost
savings;
|
·
|
a
$1.7 million increase in pension expense primarily due to lower income
from pension assets resulting from a decline in the market value of assets
during 2008; and
|
·
|
a
$0.9 million increase in utility bad debt
expense.
|
Our bad
debt expense ratio as a percent of revenues was 0.4 percent for the 12 months
ended March 31, 2009, compared to 0.3 percent in the same period year. With a
weaker economy and high unemployment rates, it may be more difficult for our
customers to pay their bills. Under the PGA mechanism, our rates are
adjusted each year to recover the expected increase 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 first
quarter of 2009, margin revenues increased by approximately $0.4 million due to
an OPUC approved rate increase 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
General
taxes, which are principally comprised of property taxes, payroll taxes and
regulatory fees, increased $0.4 million, or 4 percent, in the three months ended
March 31, 2009 over the same period in 2008. Property taxes increased
$0.2 million, or 3 percent, reflecting an increase in net utility plant and net
non-utility plant in service. Regulatory fees increased $0.2 million,
or 8 percent, reflecting higher utility gross operating revenues.
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 2002-2003 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 $2.2 million, or 12 percent, for the three
months ended March 31, 2009, compared to the same period in 2008. The
lower expense reflects decreased depreciation rates effective January 1, 2009 in
accordance with OPUC and WUTC approval of our depreciation study. The
decrease in depreciation expense in 2009 will be offset by a
corresponding decrease in operating revenues this year. See
“Regulatory Matters—Rates and Regulations—Depreciation Study,”
above.
Other
Income and Expense – Net
The
following table summarizes other income and expense – net by primary
components:
|
|
Three
Months Ended
|
|
|
|
March
31,
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
Other
income and expense - net:
|
|
|
|
|
|
|
Gains
from company-owned life insurance
|
|
$ |
1,081 |
|
|
$ |
459 |
|
Interest
income
|
|
|
60 |
|
|
|
(1 |
) |
Income
(loss) from equity investments
|
|
|
288 |
|
|
|
(25 |
) |
Net
interest on deferred regulatory accounts
|
|
|
501 |
|
|
|
(167 |
) |
Other
|
|
|
(1,040 |
) |
|
|
(93 |
) |
Total
other income and expense - net
|
|
$ |
890 |
|
|
$ |
173 |
|
In the
three months ended March 31, 2009, other income and expense – net increased $0.7
million compared to the same period in 2008. The increase is
primarily due to additional income from our company-owned life insurance and
interest income from our deferred regulatory accounts, partially offset by a
decrease in our other non-operating expenses.
Interest
Charges – Net of Amounts Capitalized
Interest charges – net of amounts capitalized decreased less than $0.1 million,
or less than 1 percent, in the three months ended March 31, 2009 compared to the
same period in 2008.
Income Tax
Expense
Income tax expense totaled $28.8 million in the three months ended March 31,
2009 compared to $25.7 million in the three months ended March 31,
2008. The effective tax rate was 37.8 percent in 2009 compared to
37.3 percent in 2008. The higher income tax rate in 2009 is due
primarily to accelerated amortization of deferred tax amounts related to
pre-1981 regulatory assets.
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:
|
|
March
31,
|
|
|
March
31,
|
|
|
Dec.
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2008
|
|
Common
stock equity
|
|
|
49.6 |
% |
|
|
52.4 |
% |
|
|
45.3 |
% |
Long-term
debt
|
|
|
43.8 |
% |
|
|
42.6 |
% |
|
|
36.8 |
% |
Short-term
debt, including current maturities of long-term debt
|
|
|
6.6 |
% |
|
|
5.0 |
% |
|
|
17.9 |
% |
Total
|
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
Liquidity
and Capital Resources
At March
31, 2009, we had $10.3 million of cash and cash equivalents compared to $6.4
million at March 31, 2008. 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. On March 25, 2009,
we issued $75 million of secured medium-term notes (MTNs) at 5.37 percent, which
will mature in 2020. In connection with this issuance, we settled our
$50 million interest rate swap and realized a $10.1 million loss, which will be
recognized in interest expense over the maturity period of the
debt .
Our
senior secured long-term debt ratings are AA- and A2 from Standard & Poor’s
(S&P) and Moody’s Investors Service (Moody’s), respectively, while 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 in the last six 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 without the need to borrow from our $250 million back-up
facility. In the event that we are not able to issue commercial paper or other
debt instruments 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. At March 31, 2009, we had OPUC approval to issue up to
$225 million of additional MTNs under the shelf registration.
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 draws from our borrowing facilities.
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 future contractual obligations have not materially
changed. 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.
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 March 31, 2009 and 2008 we had commercial paper outstanding
of $82.8 million and $54.6 million, respectively. This year’s
outstanding balances were higher than last year’s primarily due to higher
balances in gas inventories and accounts receivable and temporary negative cash
flow from losses related to the settlement of gas hedge contracts.
In March
2009, Gill Ranch entered into a $40 million cash collateralized credit facility
that expires on September 30, 2009. As of March 31, 2009, Gill Ranch
had borrowed loan proceeds of $5.8 million.
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 March 31, 2009 as
follows:
|
|
Amount
|
|
|
Committed
|
Lender
rating, by category
|
|
(in
$000's)
|
AAA/Aaa
|
|
$ |
- |
AA/Aa
|
|
|
165,000 |
A/A
|
|
|
85,000 |
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
are due and payable on or before the expiration date. There were no outstanding
balances under this credit agreement at March 31, 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 March 31, 2009 and 2008, with consolidated indebtedness to
total capitalization ratios of 50.4 percent, and 47.6 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-
|
A2
|
Senior
unsecured (long-term debt)
|
A+
|
A3
|
Ratings
outlook
|
Negative
|
Stable
|
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
Redemptions
of long-term debt during the three months ended March 31, 2009 and 2008 and the
year-ended December 31, 2008 were as follows:
|
|
Three
months ended March 31,
|
|
|
Year
ended
|
|
Thousands
|
|
2009
|
|
|
2008
|
|
|
Dec.
31, 2008
|
|
Medium-Term
Notes:
|
|
|
|
|
|
|
|
|
|
First
Mortgage Bonds:
|
|
|
|
|
|
|
|
|
|
6.50%
Series B due 2008
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
5,000 |
|
For long-term debt maturing over the next five years, see Part II, Item 7A.,
"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 first quarter of 2009, cash flow from net income
and operating activities, excluding working capital changes, increased $16.4
million compared to the same period in 2008. Cash flow from working
capital changes in the first quarter of 2009 increased by $11.2 million compared
to the same period in 2008. The overall change in cash flow from
operating activities was an increase of $27.6 million. The
significant factors contributing to the cash flow changes between 2009 and 2008
are as follows:
2009
compared to 2008:
·
|
an
increase in cash of $30.2 million in deferred gas costs, an increase in
cash of $27.5 million in accounts payable and a decrease in cash of $41.4
million in gas inventory due to lower gas costs in 2009 compared to
2008;
|
·
|
a
decrease in cash of $10.1 million due to the loss realized on the
settlement of our interest rate hedge which will be amortized over the
period of the debt outstanding (see Note
10);
|
·
|
an
increase in cash of $16.0 million in accounts receivable and accrued
unbilled revenue due to higher rates effective November 1, 2008 and colder
weather in December 2008 (see Results of Operations—Regulatory
Matters—Rate Mechanisms—Purchased Gas Adjustment,” above);
and
|
·
|
an
increase in cash of $19.0 million in income taxes receivable due to
accelerated depreciation and a net operating loss in
2008.
|
In
April 2009, we announced we have filed for regulatory approval from the OPUC to
provide an aggregate $32 million refund to our Oregon customers, related to our
significant gas cost savings from lower gas prices during the period of November
1, 2008 to March 31, 2009. If approved, we intend to refund this
amount to customers through billing credits in the second quarter of
2009. This refund will reduce gross operating revenues and utility
margin, but will be offset by a corresponding reduction in cost of gas
sold.
In
December 2008, we filed an application with the Internal Revenue Service (IRS)
for a change in tax accounting method in connection with our routine repairs and
maintenance of gas pipelines that are currently being capitalized and
depreciated. We anticipate that the IRS will consent to this change
during the second or third quarter of 2009. If we receive consent,
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 cash refund of taxes
paid. We estimate the tax refund amount in 2009 for prior years’
taxes paid to be in excess of $15 million related to the routine repairs and
maintenance.
Investing
Activities
Cash used
for investing activities in the first quarter of 2009 totaled
$34.1 million, up from $22.5 million for the same period in
2008. Cash requirements for the acquisition and construction of
utility plant were $21.6 million in first quarter of 2009, up $2.3 million from
$19.3 million for the same period in 2008 primarily due to automated
meter reading project costs. Cash requirements for investments in
non-utility property were $6.2 million in the first quarter of 2009, primarily
related to investments in Gill Ranch, compared to $1.7 million in 2008. Cash
used in other investing activities in the first quarter of 2009 totaled $6.3
million, compared to $1.6 million in 2008, with the increase in
2009 primarily due to a $5.8 million restricted cash investment in Gill
Ranch.
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 continued 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 cost of Gill Ranch is between $160 million and $180 million. As
of March 31, 2009, we have spent $19.0 million on our Gill Ranch project.
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,
50 percent of which is our investment based on our ownership interest. As of
March 31, 2009, we had invested $15.5 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 cash proceeds
which had supported the shipper's obligations under the prior agreement.
The cash proceeds received are expected to be applied against project
costs. The new agreement provides the shipper will provide a new
form of credit support, as determined to be acceptable to Palomar, that is
expected to support a portion of the planning and permitting costs as the
project develops. The failure to receive acceptable credit support or 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, our own utility and this other shipper,
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 first three months of 2009 totaled $109.4
million, up from $96.5 million cash used in the same period of
2008. Our short-term debt balances decreased by $172.3 million in the
first three months of 2009 compared to a decrease of $88.5 million 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. No shares were purchased under our common stock repurchase
program, and no long-term debt was redeemed in the three months ended March 31,
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. Our minimum contribution
requirement during 2009 is estimated to be $17 million to avoid any restrictions
on benefit payments. In April 2009, we contributed $25 million. We
have 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. See Note 7 for further
discussion.
Ratios of
Earnings to Fixed Charges
For the
three and twelve months ended March 31, 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 8.74, 3.96 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 March 31, 2009, we had a regulatory asset of $67.8
million for environmental costs, which includes $32.0 million of total paid
expenditures to date, $29.0 million for additional environmental costs expected
to be paid in the future and accrued interest of $6.8 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-price financial 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 March 31, 2009 and 2008, notional amounts under these
financial hedge contracts totaled $281.9 million and $170.2 million,
respectively. If all of the commodity-based financial hedge contracts
had been settled on March 31, 2009, a loss of about $116.3 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, 2010. The
$116.3 million unrealized loss is an estimate of future cash flows based on
forward market prices that are expected to be paid as follows: $101.4 million in
the next 12-month period, and $14.9 million in the following 12-month period.
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 March 31, 2009, our credit exposure relating to
commodity hedge contracts reflected an amount we owed of $116.3 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
March 31, 2009 expire or are expected to settle on or before October 31,
2010.
The
following table summarizes our credit exposure, based on estimated fair value,
and the corresponding counterparty credit ratings. 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:
|
|
|
Financial
Derivative Position by Credit Rating
|
|
|
|
|
Unrealized
Fair Value Gain (Loss)
|
|
Thousands
|
|
|
March
31, 2009
|
|
|
March
31, 2008
|
|
|
Dec.
31, 2008
|
|
AAA/Aaa
|
|
|
$ |
(9,246 |
) |
|
$ |
5,102 |
|
|
$ |
(16,827 |
) |
AA/Aa
|
|
|
|
(101,516 |
) |
|
|
19,452 |
|
|
|
(122,287 |
) |
A/A
|
|
|
|
(5,531 |
) |
|
|
5,193 |
|
|
|
(12,006 |
) |
BBB/Baa
|
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
|
|
|
$ |
(116,293 |
) |
|
$ |
29,747 |
|
|
$ |
(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
posting or calling for 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.
Item 4. CONTROLS AND
PROCEDURES
(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 March 31, 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 March 31, 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 |
|
01/01/09
- 01/31/09
|
|
|
925 |
|
|
$ |
41.74 |
|
|
|
- |
|
|
|
- |
|
02/01/09
- 02/28/09
|
|
|
22,836 |
|
|
$ |
43.99 |
|
|
|
- |
|
|
|
- |
|
03/01/09
- 03/31/09
|
|
|
54,750 |
|
|
$ |
39.15 |
|
|
|
- |
|
|
|
- |
|
Total
|
|
|
78,511 |
|
|
$ |
40.59 |
|
|
|
2,124,528 |
|
|
$ |
16,732,648 |
|
(1)
|
During
the quarter ended March 31, 2009, 21,598 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,
56,913 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 March 31, 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
March 31, 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.
|
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: May
4,
2009
/s/ Stephen
P.
Feltz
Stephen P. Feltz
Principal Accounting Officer
Treasurer and Controller
NORTHWEST
NATURAL GAS COMPANY
To
Quarterly
Report on Form 10-Q
For
Quarter Ended
March 31,
2009
|
|
Exhibit
|
Document
|
|
Number
|
|
|
|
Computation
of Ratio of Earnings to Fixed Charges
|
|
12
|
|
|
|
Certification
of Principal Executive Officer Pursuant to
|
|
31.1
|
Rule
13a-14(a)/15d-14(a), Section 302 of the Sarbanes-Oxley Act of
2002
|
|
|
|
|
|
Certification
of Principal Financial Officer Pursuant to
|
|
31.2
|
Rule
13a-14(a)/15d-14(a), Section 302 of the Sarbanes-Oxley Act of
2002
|
|
|
|
|
|
Certification
of Principal Executive Officer and Principal Financial
Officer
|
|
32.1
|
Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|