PE-2013.3.31-10Q


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, 2013

OR
[  ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition period from ________ to ________
Commission File Number
Exact name of registrant as specified in its charter, state of incorporation, address of principal executive offices, telephone number
I.R.S.
Employer
Identification
Number
1-16305
PUGET ENERGY, INC.
A Washington Corporation
10885 NE 4th Street, Suite 1200
Bellevue, Washington 98004-5591
(425) 454-6363
91-1969407
1-4393
PUGET SOUND ENERGY, INC.
A Washington Corporation
10885 NE 4th Street, Suite 1200
Bellevue, Washington 98004-5591
(425) 454-6363
91-0374630

Indicate by check mark whether the registrants: (1) have 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) have been subject to such filing requirements for the past 90 days.
Puget Energy, Inc.
Yes
/X/
No
/  /
 
Puget Sound Energy, Inc.
Yes
/X/
No
/  /
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate websites, 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).
Puget Energy, Inc.
Yes
/X/
No
/  /
 
Puget Sound Energy, Inc.
Yes
/X/
No
/  /
Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See definition of “large accelerated filer, accelerated filer and smaller reporting company” in Rule 12b-2 of the Exchange Act.
Puget Energy, Inc.
Large accelerated filer
/  /
Accelerated filer
/  /
Non-accelerated filer
/X/
Smaller reporting company
/  /
Puget Sound Energy, Inc.
Large accelerated filer
/  /
Accelerated filer
/  /
Non-accelerated filer
/X/
Smaller reporting company
/  /
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Puget Energy, Inc.
Yes
/  /
No
/X/
 
Puget Sound Energy, Inc.
Yes
/  /
No
/X/
All of the outstanding shares of voting stock of Puget Energy, Inc. are held by Puget Equico LLC, an indirect wholly-owned subsidiary of Puget Holdings LLC.  All of the outstanding shares of voting stock of Puget Sound Energy, Inc. are held by Puget Energy, Inc.



Table of Contents

 
 
Page
 
 
 
 
 
 
 
 
Puget Energy, Inc.
 
 
 
Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2013 and 2012
 
 
 
 
 
 
Puget Sound Energy, Inc.
 
 
 
 
 
 
 
 
 
Notes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2


DEFINITIONS

AFUDC
Allowance for Funds Used During Construction
ASU
Accounting Standards Update
ASC
Accounting Standards Codification
BPA
Bonneville Power Administration
EBITDA
Earnings Before Interest, Tax, Depreciation and Amortization
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
GAAP
U.S. Generally Accepted Accounting Principles
IRP
Integrated Resource Plan
ISDA
International Swaps and Derivatives Association
kW
Kilowatt
kWh
Kilowatt Hour
LIBOR
London Interbank Offered Rate
MMBtus
One Million British Thermal Units
MW
Megawatt (one MW equals one thousand kW)
MWh
Megawatt Hour (one MWh equals one thousand kWh)
NAESB
North American Energy Standards Board
NPNS
Normal Purchase Normal Sale
OCI
Other Comprehensive Income
PCA
Power Cost Adjustment
PGA
Purchased Gas Adjustment
PSE
Puget Sound Energy, Inc.
Puget Energy
Puget Energy, Inc.
Puget Holdings
Puget Holdings LLC
PTC
Production Tax Credit
REC
Renewable Energy Credit
REP
Residential Exchange Program
SERP
Supplemental Executive Retirement Plan
Washington Commission
Washington Utilities and Transportation Commission
WSPP
Western Systems Power Pod


3



FILING FORMAT
This report on Form 10-Q is a Quarterly Report filed separately by two registrants, Puget Energy, Inc. (Puget Energy) and Puget Sound Energy, Inc. (PSE).  Any references in this report to the “Company” are to Puget Energy and PSE collectively.

FORWARD-LOOKING STATEMENTS
Puget Energy and PSE include the following cautionary statements in this Form 10-Q to make applicable and to take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by or on behalf of Puget Energy or PSE.  This report includes forward-looking statements, which are statements of expectations, beliefs, plans, objectives and assumptions of future events or performance.  Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” or similar expressions are intended to identify certain of these forward-looking statements.
Forward-looking statements reflect current expectations and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed.  Puget Energy’s and PSE’s expectations, beliefs and projections are expressed in good faith and are believed by Puget Energy and PSE, as applicable, to have a reasonable basis, including without limitation, management’s examination of historical operating trends, data contained in Company records and other data available from third parties.  However, there can be no assurance that Puget Energy’s and PSE’s expectations, beliefs or projections will be achieved or accomplished.
In addition to other factors and matters discussed elsewhere in this report, some important factors that could cause actual results or outcomes for Puget Energy and PSE to differ materially from those discussed in forward-looking statements include:

Ÿ
Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), with respect to allowed rates of return, cost recovery, financing, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation, maintenance and construction of electric generating facilities, natural gas and electric distribution and transmission facilities, licensing of hydroelectric operations and natural gas storage facilities, recovery of other capital investments, recovery of power and natural gas costs, recovery of regulatory assets, implementation of energy efficiency programs and present or prospective wholesale and retail competition;
Ÿ
Failure of PSE to comply with the FERC or the Washington Commission standards and/or rules, which could result in penalties based on the discretion of either commission;
Ÿ
Findings of noncompliance with electric reliability standards developed by the North American Electric Reliability Corporation (NERC) or the Western Electricity Coordinating Council for users, owners and operators of the power system, which could result in penalties;
Ÿ
Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or byproducts of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;
Ÿ
The ability to recover costs arising from changes in enacted federal, state or local tax laws in a timely manner;
Ÿ
Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdictions;
Ÿ
Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;
Ÿ
Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;
Ÿ
Commodity price risks associated with procuring natural gas and power in wholesale markets or counterparties extending credit to PSE without collateral posting requirements;
Ÿ
Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
Ÿ
Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
Ÿ
The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;
Ÿ
PSE electric or natural gas distribution system failure, which may impact PSE’s ability to deliver energy supply to its customers;
Ÿ
Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE’s revenue and expenses;
Ÿ
Regional or national weather, which can have a potentially serious impact on PSE’s ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and on the cost of procuring such supplies;
Ÿ
Variable hydrological conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities;
Ÿ
Electric plant generation and transmission system outages, which can have an adverse impact on PSE’s expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;
Ÿ
The ability of a natural gas or electric plant to operate as intended;
Ÿ
The ability to renew contracts for electric and natural gas supply and the price of renewal;
Ÿ
Blackouts or large curtailments of transmission systems, whether PSE’s or others’, which can affect PSE’s ability to deliver power or natural gas to its customers and generating facilities;
Ÿ
The ability to restart generation following a regional transmission disruption;
Ÿ
The failure of the interstate natural gas pipeline delivering to PSE’s system, which may impact PSE’s ability to adequately deliver natural gas supply or electric power to its customers;
Ÿ
Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
Ÿ
General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE’s accounts receivable;
Ÿ
The loss of significant customers, changes in the business of significant customers or the condemnation of PSE’s facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE’s services;
Ÿ
The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE’s customer service, generation, distribution and transmission;
Ÿ
The impact of acts of God, terrorism, flu pandemic or similar significant events;
Ÿ
Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
Ÿ
Employee workforce and third party vendors factors, including strikes, work stoppages, availability and aging of qualified employees or the loss of a key executive;
Ÿ
The ability to obtain insurance coverage and the cost of such insurance;
Ÿ
The ability to maintain effective internal controls over financial reporting and operational processes;
Ÿ
Changes in Puget Energy’s or PSE’s credit ratings, which may have an adverse impact on the availability and cost of capital for Puget Energy or PSE generally, or the failure to comply with the covenants in Puget Energy’s or PSE’s credit facilities, which would limit the Company’s ability to utilize such facilities for capital; and
Ÿ
Deteriorating values of the equity, fixed income and other markets which could significantly impact the value of investments of PSE’s retirement plan, post-retirement medical benefit plan trusts and the funding of obligations thereunder.

Any forward-looking statement speaks only as of the date on which such statement is made and except as required by law, the Company undertakes 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 management to predict all such factors, nor can it assess the impact of any such factor on the business 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.  You are also advised to consult Item 1A –“Risk Factors” in the Company’s most recent Annual Report on Form 10-K.


4


PART I                    FINANCIAL INFORMATION

Item 1.                      Financial Statements

PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
(Unaudited)


 
Three Months Ended
March 31,
 
2013
2012
Operating revenue:
 
 
Electric
$
614,634

$
611,527

Gas
384,765

435,966

Other
419

1,019

Total operating revenue
999,818

1,048,512

Operating expenses:
 

 

Energy costs:
 

 

Purchased electricity
175,043

199,115

Electric generation fuel
59,087

69,937

Residential exchange
(22,551
)
(23,335
)
Purchased gas
189,983

233,519

Unrealized (gain) loss on derivative instruments, net
(75,692
)
4,726

Utility operations and maintenance
129,235

128,046

Non-utility expense and other
(994
)
861

Depreciation
88,178

79,006

Amortization
5,744

13,343

Conservation amortization
34,107

34,402

Taxes other than income taxes
99,943

99,869

Total operating expenses
682,083

839,489

Operating income
317,735

209,023

Other income (deductions):
 

 

Other income
12,012

14,937

Other expense
(1,542
)
(3,754
)
Non-hedging interest rate derivative expense
1,028

527

Interest charges:
 

 

AFUDC
4,648

7,295

Interest expense
(95,816
)
(107,201
)
Income (loss) before income taxes
238,065

120,827

Income tax (benefit) expense
70,590

32,347

Net income (loss)
$
167,475

$
88,480


The accompanying notes are an integral part of the financial statements.


5



PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
(Unaudited)


 
Three Months Ended
March 31,
 
2013
2012
Net income (loss)
$
167,475

$
88,480

Other comprehensive income (loss):
 

 

Reclassification of net unrealized (gain) loss on interest rate swaps during the period, net of tax of $460 and $1,350, respectively
854

2,508

Net unrealized gain (loss) from pension and postretirement plans, net of tax of $186 and $(58), respectively
347

(107
)
Reclassification of net unrealized (gain) loss on energy derivative instruments settled during the period, net of tax of $(57) and $(105), respectively
(107
)
(195
)
Other comprehensive income (loss)
1,094

2,206

Comprehensive income (loss)
$
168,569

$
90,686


The accompanying notes are an integral part of the financial statements.


6



PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


ASSETS
 
(Unaudited)
 
 
March 31,
2013
December 31,
2012
Utility plant (including construction work in progress of $831,966 and $766,035,
respectively):
 
 
Electric plant
$
6,808,468

$
6,750,400

Gas plant
2,419,175

2,385,784

Common plant
494,079

487,931

Less: Accumulated depreciation and amortization
(1,128,946
)
(1,067,424
)
Net utility plant
8,592,776

8,556,691

Other property and investments:
 

 

Goodwill
1,656,513

1,656,513

Other property and investments
103,922

112,367

Total other property and investments
1,760,435

1,768,880

Current assets:
 

 

Cash and cash equivalents
113,988

135,542

Restricted cash
3,101

3,700

Accounts receivable, net of allowance for doubtful accounts of $9,502 and $9,932,
respectively
322,299

321,480

Unbilled revenue
172,039

204,359

Materials and supplies, at average cost
80,526

82,353

Fuel and gas inventory, at average cost
61,851

88,953

Unrealized gain on derivative instruments
20,410

6,869

Income taxes
4,648

4,796

Prepaid expense and other
17,271

13,571

Power contract acquisition adjustment gain
50,346

50,785

Deferred income taxes
16,241

53,437

Total current assets
862,720

965,845

Other long-term and regulatory assets:
 

 

Regulatory asset for deferred income taxes
129,951

119,844

Power cost adjustment mechanism
3,795

3,773

Regulatory assets related to power contracts
36,928

37,655

Other regulatory assets
743,189

815,785

Unrealized gain on derivative instruments
14,452

14,814

Power contract acquisition adjustment gain
441,297

456,225

Other
99,475

95,763

Total other long-term and regulatory assets
1,469,087

1,543,859

Total assets
$
12,685,018

$
12,835,275


The accompanying notes are an integral part of the financial statements.





PUGET ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


CAPITALIZATION AND LIABILITIES
 
(Unaudited)
 
 
March 31,
2013
December 31,
2012
Capitalization:
 
 
Common shareholder’s equity:
 
 
Common stock $0.01 par value, 1,000 shares authorized, 200 shares outstanding
$
—

$
—

Additional paid-in capital
3,308,957

3,308,957

Earnings reinvested in the business
333,504

208,100

Accumulated other comprehensive income (loss), net of tax
(31,735
)
(32,829
)
Total common shareholder’s equity
3,610,726

3,484,228

Long-term debt:
 

 

First mortgage bonds and senior notes
3,351,412

3,351,412

Pollution control bonds
161,860

161,860

Junior subordinated notes
250,000

250,000

Long-term debt
1,805,000

1,834,000

Debt discount and other
(260,995
)
(264,072
)
Total long-term debt
5,307,277

5,333,200

Total capitalization
8,918,003

8,817,428

Current liabilities:
 

 

Accounts payable
266,714

321,755

Short-term debt
25,000

181,000

Current maturities of long-term debt
13,000

13,000

Purchased gas adjustment liability
26,869

32,587

Accrued expenses:
 

 

  Taxes
112,369

95,623

  Salaries and wages
27,579

38,438

  Interest
74,939

82,262

Unrealized loss on derivative instruments
81,198

177,519

Power contract acquisition adjustment loss
3,943

3,902

Other
89,817

72,799

Total current liabilities
721,428

1,018,885

Long-term and regulatory liabilities:
 

 

Deferred income taxes
1,305,727

1,261,636

Unrealized loss on derivative instruments
51,987

83,276

Regulatory liabilities
645,158

600,697

Regulatory liabilities related to power contracts
491,643

507,009

Power contract acquisition adjustment loss
32,985

33,753

Other deferred credits
518,087

512,591

Total long-term and regulatory liabilities
3,045,587

2,998,962

Commitments and contingencies




Total capitalization and liabilities
$
12,685,018

$
12,835,275


The accompanying notes are an integral part of the financial statements.


7



PUGET ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
 
Three Months Ended
March 31,
 
2013
2012
Operating activities:
 
 
Net income (loss)
$
167,475

$
88,480

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 

Depreciation
88,178

79,006

Amortization
5,744

13,343

Conservation amortization
34,107

34,402

Deferred income taxes and tax credits, net
70,591

32,564

Net unrealized (gain) loss on derivative instruments
(75,937
)
(5,136
)
Funding of pension liability
(5,100
)
(5,700
)
Derivative contracts classified as financing activities due to merger
26,049

36,621

AFUDC – Equity
(6,524
)
(9,306
)
Regulatory assets
(6,411
)
(48,185
)
Regulatory liabilities
3,029

8,180

Other long-term assets
3,099

(3,625
)
Other long-term liabilities
17,586

28,666

Change in certain current assets and liabilities:
 

 

Accounts receivable and unbilled revenue
31,548

32,439

Materials and supplies
1,827

(8,520
)
Fuel and gas inventory
27,097

23,378

Income taxes
148

1,834

Prepayments and other
(3,732
)
(2,840
)
Purchased gas adjustment
(5,718
)
30,210

Accounts payable
(47,935
)
(68,073
)
Taxes payable
16,746

13,877

Accrued expenses and other
(18,060
)
1,989

Net cash provided by operating activities
323,807

273,604

Investing activities:
 

 

Construction expenditures – excluding equity AFUDC
(168,337
)
(185,634
)
Energy efficiency expenditures
(22,542
)
(22,657
)
Proceeds from disposition of assets
108,166

—

Restricted cash
599

(58
)
Other
(4,248
)
(17,606
)
Net cash used in investing activities
(86,362
)
(225,955
)
Financing activities:
 

 

Change in short-term debt and leases, net
(157,895
)
11,134

Dividends paid
(42,071
)
—

Long-term notes and bonds issued
—

864,000

Redemption of bonds and notes
(29,000
)
(848,000
)
Derivative contracts classified as financing activities due to merger
(26,049
)
(36,621
)
Issuance cost of bonds and other
(3,984
)
(4,933
)
Net cash provided by (used in) financing activities
(258,999
)
(14,420
)
Net increase (decrease) in cash and cash equivalents
(21,554
)
33,229

Cash and cash equivalents at beginning of period
135,542

37,235

Cash and cash equivalents at end of period
$
113,988

$
70,464

Supplemental cash flow information:
 

 

Cash payments for interest (net of capitalized interest)
$
78,346

$
74,588

Cash payments (refunds) for income taxes
—

(1,898
)
The accompanying notes are an integral part of the financial statements.


8




PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF INCOME
(Dollars in Thousands)
(Unaudited)

 
Three Months Ended
March 31,
 
2013
2012
Operating revenue:
 
 
Electric
$
614,634

$
611,527

Gas
384,765

435,966

Other
308

1,019

Total operating revenue
999,707

1,048,512

Operating expenses:
 

 

Energy costs:
 

 

Purchased electricity
175,043

199,115

Electric generation fuel
59,087

69,937

Residential exchange
(22,551
)
(23,335
)
Purchased gas
189,983

233,519

Unrealized (gain) loss on derivative instruments, net
(72,740
)
10,135

Utility operations and maintenance
129,235

128,046

Non-utility expense and other
3,091

3,230

Depreciation
88,178

79,006

Amortization
5,744

13,343

Conservation amortization
34,107

34,402

Taxes other than income taxes
99,943

99,869

Total operating expenses
689,120

847,267

Operating income (loss)
310,587

201,245

Other income (deductions):
 

 

Other income
12,012

14,933

Other expense
(1,542
)
(3,754
)
Interest charges:
 

 

AFUDC
4,648

7,295

Interest expense
(65,977
)
(60,737
)
Interest expense on parent note
(29
)
(51
)
Income (loss) before income taxes
259,699

158,931

Income tax (benefit) expense
79,761

46,215

Net income (loss)
$
179,938

$
112,716


The accompanying notes are an integral part of the financial statements.


9



PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in Thousands)
(Unaudited)

 
Three Months Ended
March 31,
 
2013
2012
Net income (loss)
$
179,938

$
112,716

Other comprehensive income (loss):
 

 

Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,823 and $1,301, respectively
3,386

2,416

Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $975 and $1,035, respectively
1,811

1,923

Amortization of treasury interest rate swaps to earnings, net of tax of $43 and $43, respectively
79

79

Other comprehensive income (loss)
5,276

4,418

Comprehensive income (loss)
$
185,214

$
117,134


The accompanying notes are an integral part of the financial statements.


10



PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)


ASSETS
 
(Unaudited)
 
 
March 31,
2013
December 31,
2012
Utility plant (at original cost, including construction work in progress of $831,966 and
$766,035, respectively):
 
 
Electric plant
$
9,077,027

$
9,048,356

Gas plant
3,030,835

2,998,188

Common plant
557,500

555,549

Less:  Accumulated depreciation and amortization
(4,072,586
)
(4,045,402
)
Net utility plant
8,592,776

8,556,691

Other property and investments:
 

 

Other property and investments
95,091

103,646

Total other property and investments
95,091

103,646

Current assets:
 

 

Cash and cash equivalents
113,947

135,530

Restricted cash
3,101

3,700

Accounts receivable, net of allowance for doubtful accounts of $9,502 and $9,932,
respectively
322,739

321,685

Unbilled revenue
172,039

204,359

Materials and supplies, at average cost
80,526

82,353

Fuel and gas inventory, at average cost
58,450

85,547

Unrealized gain on derivative instruments
20,410

6,869

Income taxes
4,648

4,796

Prepaid expense and other
17,145

13,413

Deferred income taxes
30,956

68,015

Total current assets
823,961

926,267

Other long-term and regulatory assets:
 

 

Regulatory asset for deferred income taxes
129,386

119,279

Power cost adjustment mechanism
3,795

3,773

Other regulatory assets
741,359

813,171

Unrealized gain on derivative instruments
14,452

14,814

Other
94,558

90,330

Total other long-term and regulatory assets
983,550

1,041,367

Total assets
$
10,495,378

$
10,627,971


The accompanying notes are an integral part of the financial statements.


11




PUGET SOUND ENERGY, INC.
CONSOLIDATED BALANCE SHEETS
(Dollars in Thousands)

CAPITALIZATION AND LIABILITIES

 
(Unaudited)
 
 
March 31,
2013
December 31,
2012
Capitalization:
 
 
Common shareholder’s equity:
 
 
Common stock $0.01 par value – 150,000,000 shares authorized, 85,903,791 shares outstanding
$
859

$
859

Additional paid-in capital
3,246,205

3,246,205

Earnings reinvested in the business
418,569

344,280

Accumulated other comprehensive income (loss), net of tax
(181,922
)
(187,198
)
Total common shareholder’s equity
3,483,711

3,404,146

Long-term debt:
 

 

First mortgage bonds and senior notes
3,351,412

3,351,412

Pollution control bonds
161,860

161,860

Junior subordinated notes
250,000

250,000

Debt discount
(14
)
(14
)
Total long-term debt
3,763,258

3,763,258

Total capitalization
7,246,969

7,167,404

Current liabilities:
 

 

Accounts payable
267,126

321,953

Short-term debt
25,000

181,000

Short-term note owed to parent
29,598

29,598

Current maturities of long-term debt
13,000

13,000

Purchased gas adjustment liability
26,869

32,587

Accrued expenses:
 

 

Taxes
112,369

95,623

Salaries and wages
27,579

38,438

Interest
57,274

55,806

       Unrealized loss on derivative instruments
74,652

170,948

       Other
87,548

69,881

Total current liabilities
721,015

1,008,834

Long-term and regulatory liabilities:
 

 

Deferred income taxes
1,330,252

1,274,602

Unrealized loss on derivative instruments
38,567

68,323

Regulatory liabilities
641,011

596,324

Other deferred credits
517,564

512,484

Total long-term and regulatory liabilities
2,527,394

2,451,733

Commitments and contingencies




Total capitalization and liabilities
$
10,495,378

$
10,627,971


The accompanying notes are an integral part of the financial statements.


12



PUGET SOUND ENERGY, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in Thousands)
(Unaudited)
 
Three Months Ended
March 31,
 
2013
2012
Operating activities:
 
 
Net income (loss)
$
179,938

$
112,716

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 

 

Depreciation
88,178

79,006

Amortization
5,744

13,343

Conservation amortization
34,107

34,402

Deferred income taxes and tax credits, net
79,761

46,430

Net unrealized (gain) loss on derivative instruments
(72,740
)
10,135

Funding of pension liability
(5,100
)
(5,700
)
AFUDC – Equity
(6,524
)
(9,306
)
Regulatory assets
(6,411
)
(48,185
)
Regulatory liabilities
3,029

8,180

Other long-term assets
2,922

(4,359
)
Other long-term liabilities
18,162

15,118

Change in certain current assets and liabilities:
 

 

Accounts receivable and unbilled revenue
31,313

32,371

Materials and supplies
1,827

(8,520
)
Fuel and gas inventory
27,097

23,378

Income taxes
148

1,834

Prepayments and other
(3,732
)
(2,840
)
Purchased gas adjustment
(5,718
)
30,210

Accounts payable
(47,721
)
(68,267
)
Taxes payable
16,746

13,877

Accrued expenses and other
(8,783
)
(12,594
)
Net cash provided by operating activities
332,243

261,229

Investing activities:
 

 

Construction expenditures – excluding equity AFUDC
(168,337
)
(185,634
)
Energy efficiency expenditures
(22,542
)
(22,657
)
Proceeds from disposition of assets
108,166

—

Restricted cash
599

(58
)
Other
(4,184
)
(3,417
)
Net cash used in investing activities
(86,298
)
(211,766
)
Financing activities:
 

 

Change in short-term debt and leases, net
(157,895
)
11,134

Dividends paid
(105,648
)
(71,467
)
Issuance cost of bonds and other
(3,985
)
817

Net cash provided by (used in) financing activities
(267,528
)
(59,516
)
Net increase (decrease) in cash and cash equivalents
(21,583
)
(10,053
)
Cash and cash equivalents at beginning of period
135,530

31,010

Cash and cash equivalents at end of period
$
113,947

$
20,957

Supplemental cash flow information:
 

 

Cash payments for interest (net of capitalized interest)
$
57,646

$
50,232

Cash payments (refunds) for income taxes
—

(1,898
)
The accompanying notes are an integral part of the financial statements.


13



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


(1)
Summary of Significant Accounting Policies

Basis of Presentation
Puget Energy, Inc. (Puget Energy) is an energy services holding company that owns Puget Sound Energy, Inc. (PSE).  PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region.  Following the merger with Puget Holdings LLC (Puget Holdings) on February 6, 2009, Puget Energy is an indirect wholly-owned subsidiary of Puget Holdings.
The consolidated financial statements of Puget Energy reflect the accounts of Puget Energy and its subsidiary, PSE.  PSE’s consolidated financial statements include the accounts of PSE and its subsidiaries.  Puget Energy and PSE are collectively referred to herein as “the Company.”  The consolidated financial statements are presented after elimination of intercompany transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments.
The consolidated financial statements contained in this Form 10-Q are unaudited.  In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature.  These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2012.
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period.  Actual results could differ from those estimates.
Certain prior year amounts have been reclassified to conform to the current year presentation.

Revenue Recognition
Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue. In March 2012, PSE changed its estimate of unbilled revenue from a calculation that was based on system load and billing information from its customers to a calculation using meter readings from its automated meter reading (AMR) system. The new estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer.
Sales to other utilities are recognized in accordance with Accounting Standards Codification (ASC) 605, “Revenue Recognition” (ASC 605) and ASC 815, “Derivatives and Hedging” (ASC 815). Non-utility subsidiaries recognize revenue when services are performed or upon the sale of assets. Revenue from retail sales is billed based on tariff rates approved by the Washington Commission. Sales of Renewable Energy Credits (RECs) are deferred as a regulatory liability.
PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $76.9 million and $81.0 million for the three months ended March 31, 2013 and 2012, respectively.  The Company reports the collection of such taxes on a gross basis in operating revenue and as expense in taxes other than income taxes in the accompanying consolidated statements of income.

Statements of Cash Flows
The Company has refinancing transactions that do not result in an actual exchange of cash. For these transactions, the Company evaluates if the non-exchange of cash is for convenience purposes and if so, the Company considers the transaction as if it had constructively received and disbursed the cash and presents the transaction as gross on the financing section of the statements of cash flows.


(2)
New Accounting Pronouncements

Balance Sheet
In December 2011, the Financial Accounting Standards Board (FASB) issued ASU 2011-11, Balance Sheet (Topic 210) (ASU 2011-11). ASU 2011-11, as amended by ASU 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities, enhances disclosure requirements about the nature of an entity's right to offset and related arrangements associated with its derivative instruments. ASU 2011-11 requires the disclosure of the gross amounts subject to rights of set-off, amounts offset in accordance with the accounting standards followed, and the related net exposure.

14


ASU 2011-11, as amended, is effective for fiscal years, and interim periods within those years, beginning on or after January 1, 2013. Retrospective application of the disclosures is required for all periods presented within the financial statements.  These disclosure requirements are the only impact on the Company’s consolidated financial statements. The Company adopted the ASU requirements as disclosed in Note 3 - Accounting for Derivative Instruments and Hedging Activities.

Comprehensive Income
In February 2013, the FASB issued ASU 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU 2013-02), to improve the transparency of reporting reclassifications out of accumulated other comprehensive income. ASU 2013-02 requires an entity to present (either on the face of the statement where net income is presented or in the notes) the effects on the line items of net income of significant amounts reclassified out of accumulated other comprehensive income but only if the item reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. ASU 2013-02 also requires an entity to cross-reference to other disclosures currently required under U.S.GAAP for other reclassification items (that are not required under U.S. GAAP) to be reclassified directly to net income in their entirety in the same reporting period. This would be the case when a portion of the amount reclassified out of accumulated other comprehensive income is initially transferred to a balance sheet account instead of directly to income or expense.
ASU 2013-02 is effective for reporting periods beginning after December 15, 2012, for public companies and is effective for reporting periods beginning after December 15, 2013, for private companies. Other than additional disclosures or a change in the presentation on the statement of comprehensive income when necessary, ASU 2013-02 does not impact the Company's consolidated results of operations, cash flows or financial position. The Company adopted the ASU requirements as disclosed in Note 8 - Accumulated Other Comprehensive Income (loss).


(3)
Accounting for Derivative Instruments and Hedging Activities

PSE employs various energy portfolio optimization strategies, but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. Therefore, wholesale market transactions and related hedging strategies are focused on reducing costs and risks where feasible thus reducing volatility in costs in the portfolio. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into physical and financial transactions which are appropriate for the service territory of PSE and are relevant to its regulated electric and natural gas portfolios. In order to manage its exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends to March 2016.
At the February 2009 merger date, Puget Energy recorded all derivative contracts at fair value as either assets or liabilities. Certain contracts meeting the criteria defined in ASC 815 were subsequently designated as Normal Purchase Normal Sale (NPNS) or cash flow hedges. The difference in the derivative unrealized gains/losses recorded through earnings between Puget Energy and PSE will occur through March 2015.
The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of March 31, 2013, Puget Energy had two interest rate swap contracts outstanding which extend to January 2017. PSE did not have any outstanding interest rate swap instruments.

15


The following table presents the volumes, fair values and locations of the Company's derivative instruments recorded on the balance sheets:
Puget Energy and Puget Sound Energy
March 31, 2013
December 31, 2012
(Dollars in Thousands)
Volumes
Assets 1
Liabilities 2

Volumes
Assets 1
Liabilities 2
Interest rate swap derivatives 3
$450 million
$
—

$
19,966

$450 million
$
—

$
21,524

Electric portfolio derivatives
*
16,132

62,240

*
9,557

131,193

Natural gas derivatives (MMBtus) 4
475,822,952
18,730

50,979

516,909,006
12,126

108,078

Total derivative contracts
 
$
34,862

$
133,185

 
$
21,683

$
260,795

 
 
 
 
 
 
 
Current
 
$
20,410

$
81,198

 
$
6,869

$
177,519

Long-term
 
14,452

51,987

 
14,814

83,276

Total derivative contracts
 
$
34,862

$
133,185

 
$
21,683

$
260,795

___________
* 
Electric portfolio derivatives consist of electric generation fuel of 124,156,282 MMBtus and purchased electricity of 9,328,965 MWhs at March 31, 2013, and 129,693,200 MMBtus and 10,722,415 MWhs at December 31, 2012.
1 
Balance sheet location: Current and Long-term Unrealized gain on derivative instruments.
2 
Balance sheet location: Current and Long-term Unrealized loss on derivative instruments.
3 
Interest rate swap contracts are only held at Puget Energy.
4 
PSE had a net derivative liability and an offsetting regulatory asset of $32.2 million at March 31, 2013 and $96.0 million at December 31, 2012 related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers. All fair value adjustments on derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980, “Regulated Operations” (ASC 980) due to the Purchased Gas Adjustment (PGA) mechanism.

For further details regarding the fair value of derivative instruments, see Note 4.

ASU 2013-01 requires disclosure of both gross and net information for recognized derivative assets and liabilities. It is the Company's policy to record all derivative transactions on a gross basis at the contract level, without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: (1) WSPP, Inc. (WSPP) agreement - standardized power sales contract in the electric industry; (2) International Swaps and Derivatives Association (ISDA) agreements - standardized financial gas and electric contracts; and (3) North American Energy Standards Board (NAESB) agreements - standardized physical gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as right of set-off in the event of counterparty default, termination payments. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount.

16


The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:

Puget Energy and Puget Sound Energy
 
 
 
 
At March 31, 2013 (Dollars in Thousands)
Gross Amount Recognized in the Statement of Financial Position 1
Gross Amounts Offset in the Statement of Financial Position
Net of Amounts Presented in the Statement of Financial Position
Gross Amounts Not Offset in the Statement of Financial Position
 
Commodity Contracts
Cash Collateral Received/Posted
Net Amount
Assets
 
 
 
 
 
 
Energy Derivative Contracts
$
34,862

$
—

$
34,862

$
(26,785
)
$
—

$
8,077

Liabilities
 
 
 
 
 
 
Energy Derivative Contracts
$
113,219

$
—

$
113,219

$
(26,785
)
$
—

$
86,434

Interest Rate Swaps 2
$
19,966

$
—

$
19,966

$
—

$
—

$
19,966

 
 
 
 
 
 
 
 
 
 
 
 
 
 
At December 31, 2012(Dollars in Thousands)
Gross Amount Recognized in the Statement of Financial Position 1
Gross Amounts Offset in the Statement of Financial Position
Net of Amounts Presented in the Statement of Financial Position
Gross Amounts Not Offset in the Statement of Financial Position
 
Commodity Contracts
Cash Collateral Received/Posted
Net Amount
Assets
 
 
 
 
 
 
Energy Derivative Contracts
$
21,683

$
—

$
21,683

$
(14,126
)
$
—

$
7,557

Liabilities
 
 
 
 
 
 
Energy Derivative Contracts
$
239,271

$
—

$
239,271

$
(14,126
)
$
—

$
225,145

Interest Rate Swaps 2
$
21,524

$
—

$
21,524

$
—

$
—

$
21,524

___________
1 
All Derivative Contract deals are executed under ISDA, NAESB and WSPP Master Netting Agreements with Right of Offset.
2 
Interest Rate Swap Contracts are only held at Puget Energy.




17


The following tables present the net unrealized (gain) loss and locations of the Company's derivative instruments recorded on the statements of income:

Puget Energy
 
Three Months Ended
March 31,
(Dollars in Thousands)
Location
2013
2012
Interest rate contracts:
Other deductions
$
1,028

$
527

 
Interest expense
(2,578
)
(6,641
)
Commodity contracts:
 
 

 

Electric derivatives
Unrealized gain (loss) on derivative instruments, net 1
75,692

(6,876
)
 
Electric generation fuel
(12,638
)
(22,993
)
 
Purchased electricity
(31,485
)
(45,413
)
Total gain (loss) recognized in income on derivatives
 
$
30,019

$
(81,396
)
___________
1 
For the three months ended March 31, 2012, differs from the amounts stated in the statements of income as it does not include amortization related to contracts that were recorded at fair value at the time of the February 2009 merger and subsequently designated as NPNS of $2.2 million .

Puget Sound Energy
 
Three Months Ended
March 31,
(Dollars in Thousands)
Location
2013
2012
Commodity contracts:
 
 
 
Electric derivatives
Unrealized gain (loss) on derivative instruments, net
$
72,740

$
(10,135
)
 
Electric generation fuel
(12,638
)
(22,993
)
 
Purchased electricity
(31,485
)
(45,413
)
Total gain (loss) recognized in income on derivatives
 
$
28,617

$
(78,541
)

For derivative instruments previously designated as cash flow hedges (including both commodity contracts and interest rate swaps), the effective portion of the gain or loss on the derivative was recorded as a component of OCI, and then is reclassified into earnings in the same period(s) during which the hedged transaction affects earnings. Puget Energy and PSE expect $4.1 million and $2.2 million of losses in accumulated OCI will be reclassified into earnings within the next twelve months, respectively. As the Company has discontinued cash flow hedging and currently records all mark-to-market adjustments through earnings, there were no additional amounts deferred into OCI during 2013 or 2012. The unrealized gain or loss on derivative contracts is reported in the statement of cash flows under the operating section. However, at the time of the merger, all derivative contracts at Puget Energy were assessed to identify contracts that have a “more than an insignificant” fair value. If the fair value was greater than 10% of the notional value, the contract was deemed as having a financing element. For those contracts, the cash inflows (outflows) are presented in the financing activities section of the statement of cash flows. For the three months ending March 31, cash outflows related to financing activities of $26.0 million and $36.6 million were reported on the Puget Energy statement of cash flows for 2013 and 2012, respectively.












18


The following tables present the Company's pre-tax gain (loss) of derivatives that were in a previous cash flow hedge relationship, reclassified out of accumulated OCI into income:

Puget Energy
 
Three Months Ended
March 31,
(Dollars in Thousands)
Location
2013
2012
Interest rate contracts:
Interest expense
$
(1,314
)
$
(3,859
)
Commodity contracts:
 
 
 
Electric derivatives
Electric generation fuel
—

100

 
Purchased electricity
164

200

Total
 
$
(1,150
)
$
(3,559
)
    
Puget Sound Energy
 
Three Months Ended
March 31,
(Dollars in Thousands)
Location
2013
2012
Interest rate contracts:
Interest expense
$
(122
)
$
(122
)
Commodity contracts:
 
 
 
Electric derivatives
Electric generation fuel
—

97

 
Purchased electricity
(2,786
)
(3,055
)
Total
 
$
(2,908
)
$
(3,080
)

The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, exposure monitoring and exposure mitigation.
The Company monitors counterparties that have significant swings in credit default swap rates, have credit rating changes by external rating agencies, have changes in ownership or are experiencing financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.
It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of March 31, 2013, approximately 99.9% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies and 0.1% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated.
As the Company generally enters into transactions using the WSPP, ISDA and NAESB master agreements, it believes that such agreements reduce credit risk exposure because they provide for the netting and offsetting of monthly payments and, in the event of counterparty default, termination payments.
The Company computes credit reserves at a master agreement level by counterparty (i.e., WSPP, ISDA, or NAESB). The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in the determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is used by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. Moreover, the Company applies its own default factor to compute credit reserves for counterparties that are in a net liability position. Credit reserves are booked as contra accounts to unrealized gain (loss) positions. As of March 31, 2013, the Company was in a net liability position with the majority of counterparties, so the default factors of counterparties did not have a significant impact on reserves for the quarter. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. As of March 31, 2013, despite its net liability position, PSE was not required to post any collateral with any of its counterparties. Additionally, PSE did not trigger any collateral

19


requirements with any of its counterparties nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.
The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at March 31, 2013:

Puget Energy and Puget Sound Energy
Contingent Feature
(Dollars in Thousands)
Fair Value 1
Liability
Posted
Collateral
Contingent
Collateral
Credit rating 2
$
(23,515
)
$
—

$
23,515

Requested credit for adequate assurance
(15,771
)
—

—

Forward value of contract 3
(625
)
—

—

Total
$
(39,911
)
$
—

$
23,515

__________
1 
Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions. Excludes NPNS, accounts payable and accounts receivable.
2 
Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.
3 
Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.


(4)
Fair Value

GAAP established a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy categorizes the inputs into three levels with the highest priority given to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority given to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 1 primarily consists of financial instruments such as exchange-traded derivatives and listed equities. Equity securities that are also classified as cash equivalents are considered Level 1 if there are unadjusted quoted prices in active markets for identical assets or liabilities.

Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. Instruments in this category include non-exchange-traded derivatives such as over-the-counter forwards and options.

Level 3 - Pricing inputs include significant inputs that have little or no observability as of the reporting date. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value.

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. If a fair value measurement relies on inputs from different levels of the hierarchy, the entire measurement must be placed based on the lowest level input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas market from an independent external pricing service. These forward price quotes are used in addition to other various inputs to determine the reported fair value. Some of the inputs, which are not significant, include the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), assumptions for time value, and also the impact of the Company's nonperformance risk of its liabilities. For interest rate swaps, the Company obtains monthly mark-to-market values from an independent external pricing service for LIBOR forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are not significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. Cash equivalents and restricted cash classified as Level 2 fair value instruments consist of special money market funds and premium checking accounts. The Company valued

20


Level 2 cash equivalents and restricted cash using the market approach based on the fair value of underlying investments at reporting date.
The Company considers its electric, natural gas and interest rate swap contracts as Level 2 derivative instruments as such contracts are commonly traded as over-the-counter forwards with indirectly observable price quotes. However, certain energy derivative instruments are classified as Level 3 in the fair value hierarchy since Level 3 inputs are significant to the fair value measurement. Management's assessment was based on the trading activity in real-time and forward electric and natural gas markets. Each quarter, the Company confirms the validity of pricing service quoted prices (e.g., Level 2 in the fair value hierarchy) used to value commodity contracts with the actual prices of commodity contracts entered into during the most recent quarter.

Assets and Liabilities with Estimated Fair Value

The following table presents the fair value hierarchy by level, the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.
Puget Energy
Carrying / Fair Value
At March 31, 2013
Carrying / Fair Value
At December 31, 2012
(Dollars in Thousands)
Level 1
Level 2
     Total
Level 1
Level 2
     Total
Assets:
 
 
 
 
 
 
Cash and Cash Equivalents
$
—

$
113,988

$
113,988

$
105,000

$
30,542

$
135,542

Restricted Cash
896

2,205

3,101

914

2,786

3,700

Notes Receivable and Other
—

55,397

55,397

—

63,802

63,802

Total assets
$
896

$
171,590

$
172,486

$
105,914

$
97,130

$
203,044

Liabilities:
 
 
 
 
 
 
Short Term Debt
$
25,000

$
—

$
25,000

$
181,000

$
—

$
181,000

Long Term Debt (variable rate) net of discount
—

—

—

—

—

—

Total liabilities
$
25,000

$
—

$
25,000

$
181,000

$
—

$
181,000


Puget Sound Energy
Carrying / Fair Value
At March 31, 2013
Carrying / Fair Value
At December 31, 2012
(Dollars in Thousands)
Level 1
Level 2
     Total
Level 1
Level 2
     Total
Assets:
 
 
 
 
 
 
Cash and Cash Equivalents
$
—

$
113,947

$
113,947

$
105,000

$
30,530

$
135,530

Restricted Cash
896

2,205

3,101

914

2,786

3,700

Notes Receivable and Other
—

55,397

55,397

—

63,802

63,802

Total assets
$
896

$
171,549

$
172,445

$
105,914

$
97,118

$
203,032

Liabilities:
 
 
 
 
 
 
Short Term Debt
$
25,000

$
—

$
25,000

$
181,000

$
—

$
181,000

Short Term Debt owed to parent
—

29,598

29,598

—

29,598

29,598

Total liabilities
$
25,000

$
29,598

$
54,598

$
181,000

$
29,598

$
210,598














21


The fair value of the junior subordinated and long-term notes were estimated using the discounted cash flow method with U.S. Treasury yields and Company credit spreads as inputs, interpolating to the maturity date of each issue. Carrying values and estimated fair values were as follows:
Puget Energy
 
March 31, 2013
December 31, 2012
(Dollars in Thousands)
Level
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Liabilities:
 
 
 
 
 
Junior subordinated notes
2
$
250,000

$
266,968

$
250,000

$
264,842

Long-term debt (fixed-rate), net of discount
2
4,665,278

6,117,038

4,662,200

6,197,179

Long-term debt (variable-rate), net of discount
2
405,000

405,000

434,000

434,000

     Total
 
$
5,320,278

$
6,789,006

$
5,346,200

$
6,896,021

 
 
 
 
 
 
Puget Sound Energy
 
March 31, 2013
December 31, 2012
(Dollars in Thousands)
Level
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Liabilities:
 
 
 
 
 
Junior subordinated notes
2
$
250,000

$
266,968

$
250,000

$
264,842

Long-term debt (fixed-rate), net of discount
2
3,526,258

4,522,526

3,526,258

4,628,509

     Total
 
$
3,776,258

$
4,789,494

$
3,776,258

$
4,893,351


Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company's financial assets and liabilities by level, within the fair value hierarchy, that were accounted for at fair value on a recurring basis and the reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy. The Company did not have any transfers between Level 2 and Level 1 during the three months ended March 31, 2013 and 2012.

Puget Energy
Fair Value
Fair Value
At March 31, 2013
At December 31, 2012
(Dollars in Thousands)
Level 2
Level 3
Total
Level 2
Level 3
Total
Interest rate derivative instruments
$
19,966

$
—

$
19,966

$
21,524

$
—

$
21,524

Total derivative liabilities
$
19,966

$
—

$
19,966

$
21,524

$
—

$
21,524


Puget Energy and
Puget Sound Energy
Fair Value
Fair Value
At March 31, 2013
At December 31, 2012
(Dollars in Thousands)
Level 2
Level 3
Total
Level 2
Level 3
Total
Assets:
 
 
 
 
 
 
Electric derivative instruments
$
7,500

$
8,632

$
16,132

$
1,259

$
8,298

$
9,557

Natural gas derivative instruments
13,837

4,893

18,730

6,769

5,357

12,126

Total assets
$
21,337

$
13,525

$
34,862

$
8,028

$
13,655

$
21,683

Liabilities:
 

 

 

 

 

 

Electric derivative instruments
$
27,166

$
35,074

$
62,240

$
88,971

$
42,221

$
131,192

Natural gas derivative instruments
44,552

6,427

50,979

101,119

6,960

108,079

Total liabilities
$
71,718

$
41,501

$
113,219

$
190,090

$
49,181

$
239,271



22


Puget Energy and
Puget Sound Energy
Three Months Ended
March 31,
Level 3 Roll-Forward Net (Liability)
2013
2012
(Dollars in Thousands)
Electric
Gas
Total
Electric
Gas
Total
Balance at beginning of period
$
(33,924
)
$
(1,602
)
$
(35,526
)
$
(90,311
)
$
(5,041
)
$
(95,352
)
Changes during period
 
 
 
 
 
 
Realized and unrealized energy derivatives:
 
 
 
 
 
 
Included in earnings 1
1,598

—

1,598

(21,947
)
—

(21,947
)
Included in regulatory assets / liabilities
—

674

674

—

(1,283
)
(1,283
)
Settlements 2
6,384

(733
)
5,651

21,042

(218
)
20,824

Transferred into Level 3
(7,700
)
—

(7,700
)
(16,874
)
—

(16,874
)
Transferred out of Level 3
7,200

127

7,327

726

3,375

4,101

Balance at end of period
$
(26,442
)
$
(1,534
)
$
(27,976
)
$
(107,364
)
$
(3,167
)
$
(110,531
)
_________
1 
Income Statement location: Unrealized (gain) loss on derivative instruments, net. Includes unrealized gains (losses) on derivatives still held in position as of the reporting date for electric derivatives of $1.4 million and $(19.0) million for the three months ended March 31, 2013 and 2012, respectively.
2 The Company had no purchases, sales or issuances during the reported periods.

Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income.
In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs.
The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. Below are the forward price ranges for the Company's purchased commodity contracts, as of March 31, 2013:
(Dollars in Thousands)
 
 
 
 
 

Fair Value
 
 
Range
 
Derivative Instrument
Assets 1
Liabilities 1
Valuation Technique
Unobservable Input
Low
High
 Weighted Average
Electric
$
8,632

$
35,074

Discounted cash flow
Power Prices
$8.48 per MWh
$47.07 per MWh
$33.57 per MWh
Natural gas
$
4,893

$
6,427

Discounted cash flow
Natural Gas Prices
$3.44 per MMBtu
$4.91 per MMBtu
$4.25 per MMBtu
__________
1 
The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At March 31, 2013, a hypothetical 10% increase or decrease in market prices of natural gas and

23


electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $20.8 million.

(5)
Retirement Benefits

PSE has a defined benefit pension plan covering substantially all PSE employees.  Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates.  PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees.  In addition to providing pension benefits, PSE provides group health care and life insurance benefits for certain retired employees.  These benefits are provided principally through an insurance company.  The insurance premiums, paid primarily by retirees, are based on the benefits provided during the year.
The February 6, 2009 merger of Puget Energy with Puget Holdings triggered a new basis of accounting for PSE’s retirement benefit plans in the Puget Energy consolidated financial statements.  Such purchase accounting adjustments associated with the remeasurement of the retirement plans are recorded at Puget Energy.
The following tables summarize the Company’s net periodic benefit cost for the three months ended March 31, 2013 and 2012:
Puget Energy
 
 
 
Three Months Ended
March 31,
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands)
2013
2012
2013
2012
2013
2012
Components of net periodic benefit cost:
 
 
 
 
 
 
Service cost
$
4,709

$
4,235

$
375

$
268

$
34

$
38

Interest cost
6,194

6,442

511

538

176

187

Expected return on plan assets
(9,851
)
(9,001
)
—

—

(108
)
(108
)
Amortization of prior service
cost
(495
)
(495
)
(4
)
—

—

—

Amortization of net loss
(gain)
650

149

365

176

17

9

Net periodic benefit cost
$
1,207

$
1,330

$
1,247

$
982

$
119

$
126



Puget Sound Energy
 
 
 
Three Months Ended
March 31,
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands)
2013
2012
2013
2012
2013
2012
Components of net periodic benefit cost:
 
 
 
 
 
 
Service cost
$
4,709

$
4,235

$
375

$
268

$
34

$
38

Interest cost
6,194

6,442

511

538

176

187

Expected return on plan assets
(10,249
)
(10,333
)
—

—

(108
)
(108
)
Amortization of prior service
cost
(393
)
(393
)
(4
)
73

8

9

Amortization of net loss
(gain)
5,085

3,717

548

358

(34
)
(60
)
Amortization of transition
obligation
—

—

—

—

—

12

Net periodic benefit cost
$
5,346

$
3,668

$
1,430

$
1,237

$
76

$
78




24


The following table summarizes the Company’s change in benefit obligation for the periods ended March 31, 2013 and December 31, 2012:

Puget Energy and
Puget Sound Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
 
Three Months Ended
Year
Ended
Three Months Ended
Year
Ended
Three Months Ended
Year
Ended
(Dollars in Thousands)
March 31,
2013
December 31,
2012
March 31,
2013
December 31,
2012
March 31,
2013
December 31,
2012
Change in benefit obligation:






Benefit obligation at beginning of period
$
616,290

$
565,997

$
51,795

$
48,370

$
17,672

$
16,436

Service cost
4,709

16,926

375

1,073

34

139

Interest cost
6,194

25,986

511

2,152

177

751

Amendment
—

—

—

(122
)
—

—

Actuarial loss/(gain)
—

40,914

—

5,483

—

1,199

Benefits paid
(9,625
)
(33,533
)
(444
)
(5,161
)
(420
)
(1,523
)
Medicare part D subsidiary
received
—

—

—

—

—

670

Benefit obligation at end of period
$
617,568

$
616,290

$
52,237

$
51,795

$
17,463

$
17,672


The fair value of the Company’s qualified pension plan assets was $558.4 million and $531.2 million at March 31, 2013 and December 31, 2012, respectively.
The aggregate expected contributions by the Company to fund the qualified pension plan, SERP and the other postretirement plans for the year ending December 31, 2013 are expected to be at least $20.4 million, $5.0 million and $0.8 million, respectively. During the three months ended March 31, 2013, the Company contributed $5.1 million, $0.4 million and $0.4 million to fund the qualified pension plan, SERP and the other postretirement plan, respectively.

(6)
Regulation and Rates

On May 7, 2012, the Washington Commission issued its order in PSE's consolidated electric and natural gas general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually, and an increase in natural gas rates of $13.4 million or 1.3% annually. The rate increases for electric and natural gas customers became effective May 14, 2012. In its order, the Washington Commission approved a weighted cost of capital of 7.8% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.
On June 1, 2012, PSE filed with the Washington Commission a petition seeking an Accounting Order authorizing PSE to change the existing natural gas conservation tracker mechanism into a rider mechanism to be consistent with the electric conservation program recovery. The accounting petition requested the ability to recover the costs associated with the Company's current gas conservation programs via transfers from amounts deferred for the overrecovery of commodity costs in the Company's PGA mechanism. The Washington Commission granted PSE's accounting petition on June 28, 2012. The approved accounting petition resulted in an increase to gas conservation revenues of $6.9 million and an increase to conservation amortization expense of $6.6 million, the difference being recognized as revenue sensitive taxes.
On October 31, 2012, the Washington Commission approved PSE's PGA natural gas tariff filing and allowed the rates to go
into effect on November 1, 2012 on a temporary basis subject to revision. The rates resulted in a decrease to the rates charged to customers under the PGA. At a recessed open meeting on April 5, 2013, the Washington Commission approved a motion that would allow the proposed rates to be made permanent. A final order is pending as of the issuance date of this report. The estimated revenue impact of the approved change is a decrease of $77.0 million, or 7.7% annually. The rate adjustment has no impact on PSE's net income.
On January 31, 2013, the Washington Commission approved a rate change to the PSE's Federal Incentive Tracker tariff, effective February 1, 2013, which incorporated the effects of the Treasury Grant related to the Lower Snake River wind generation project and keeping the ten year amortization period and inclusion of interest on the unamortized balance of the grants. The rate change will pass through 11 months of amortization for both grants to eligible customers over 11 months beginning February 1, 2013, including grant amortization pass-back of $34.6 million and interest pass-back of $23.8 million. This represents an overall average rate decrease of 2.76%.

25




(7)
Litigation

Residential Exchange
The Northwest Power Act, through the Residential Exchange Program (REP), provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE.  The program is administered by the Bonneville Power Administration (BPA).  Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.
In 2007, the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) ruled that REP agreements of the BPA with PSE and a number of other investor-owned utilities were inconsistent with the Northwest Power Act.  Since that time, those investor-owned utilities, including PSE, the BPA and other parties have been involved in ongoing litigation at the Ninth Circuit relating to the amount of REP benefits paid to utilities, including PSE, for the fiscal year 2002 through fiscal year 2011 period and the amount of REP benefits to be paid going forward.
In July 2011, the BPA, PSE and a number of other parties entered into a settlement agreement that by its terms, if upheld in its entirety, would resolve the disputes between BPA and PSE regarding REP benefits paid for fiscal years 2002-2011 and determine REP benefits for fiscal years 2012-2028.  In October 2011, certain other parties challenged BPA decisions with regard to its entering into this most recent settlement agreement.  Oral argument in the Ninth Circuit on this litigation occurred on February 19, 2013. Pending disposition of this challenge, the other pending Ninth Circuit litigation regarding REP benefits has been stayed by the Ninth Circuit.
Due to the pending and ongoing proceedings, PSE is unable to reasonably estimate any amounts of REP payments either to be recovered by the BPA or to be paid for any future periods to PSE, and is unable to determine the impact, if any, these proceedings and litigation may have on PSE.  However, the Company believes it is unlikely that any unfavorable outcome would have a material adverse effect on PSE because REP benefits received by PSE are passed through to PSE's residential and small farm customers.

Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, Sierra Club and Montana Environmental Information Center (MEIC) filed a Clean Air Act citizen suit against all Colstrip owners (including PSE) alleging 39 claims for relief, most which relate to alleged prevention of significant deterioration (PSD) violations. One claim relates to the alleged failure to update the Title V permit to reflect the major modifications alleged in the first thirty-six claims, another claim alleges that the previous Title V compliance certifications have been incomplete because they did not address the alleged major modifications, and the last claim alleges opacity violations since 2007. The lawsuit was filed in U.S. District of Montana, Billings Division requesting injunctive relief and civil penalties, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial mitigation projects. This lawsuit followed various Notices of Intent to Sue sent to Colstrip owners (including PSE) from the Sierra Club and the MEIC on July 25, 2012, amended August 30, 2012, September 27, 2012 and December 1, 2012.  PSE is evaluating the allegations set forth in the notices and cannot at this time predict the outcome of this matter.  

Other Proceedings
The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $3.5 million and $3.4 million relating to these claims as of March 31, 2013 and December 31, 2012, respectively.



26


(8)
Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the Company’s accumulated other comprehensive income (loss) (AOCI) by component for the three months ended March 31, 2013:

Puget Energy
Net unrealized gain (loss) on interest rate swaps
Net unrealized gain (loss) and prior service cost on pension plans
Net unrealized gain (loss) on energy derivative instruments
 
Changes in AOCI, net of tax
 
(Dollars in Thousands)
Total

Balance at December 31, 2012
$
(3,022
)
$
(29,065
)
$
(742
)
$
(32,829
)
Other comprehensive income (loss) before reclassifications
—

—

—

—

Amounts reclassified from accumulated other comprehensive income (loss), net of tax
854

347

(107
)
1,094

Net current-period other comprehensive income (loss)
854

347

(107
)
1,094

Balance at March 31, 2013
$
(2,168
)
$
(28,718
)
$
(849
)
$
(31,735
)

Puget Sound Energy
Net unrealized gain (loss) and prior service cost on pension plans
Net unrealized gain (loss) on energy derivative instruments
Net unrealized gain (loss) on treasury interest rate swaps
 
Changes in AOCI, net of tax
 
(Dollars in Thousands)
Total

Balance at December 31, 2012
$
(175,998
)
$
(4,576
)
$
(6,624
)
$
(187,198
)
Other comprehensive income (loss) before reclassifications
—

—

—

—

Amounts reclassified from accumulated other comprehensive income (loss), net of tax
3,386

1,811

79

5,276

Net current-period other comprehensive income (loss)
3,386

1,811

79

5,276

Balance at March 31, 2013
$
(172,612
)
$
(2,765
)
$
(6,545
)
$
(181,922
)


27


Details about these reclassifications out of accumulated other comprehensive income (loss) for the three months ended March 31, 2013 are as follows:

Puget Energy
 
 
(Dollars in Thousands)
 
 
Details about accumulated other comprehensive income (loss) components
Amount reclassified from accumulated other comprehensive income (loss)
Affected line item in the statement where net income (loss) is presented
Net unrealized gain (loss) on interest rate swaps


Interest rate contracts
$
(1,314
)
Interest expense

460

Tax (expense) or benefit

$
(854
)
Net of Tax
Net unrealized gain (loss) and prior service cost on pension plans



Amortization of prior service cost
499

1 
Amortization of net gain (loss)
(1,032
)
1 

(533
)
Total before tax

186

Tax (expense) or benefit

$
(347
)
Net of Tax
Net unrealized gain (loss) on energy derivative instruments



Commodity contracts: electric derivatives
164

Purchased electricity

(57
)
Tax (expense) or benefit

$
107

Net of Tax
Total reclassification for the period
$
(1,094
)
Net of Tax
__________
1 These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 5 for additional details).

Puget Sound Energy
 
 
(Dollars in Thousands)
 
 
Details about accumulated other comprehensive income (loss) components
Amount reclassified from accumulated other comprehensive income (loss)
Affected line item in the statement where net income (loss) is presented
Net unrealized gain (loss) and prior service cost on pension plans



Amortization of prior service cost
$
389

1 
Amortization of net gain (loss)
(5,599
)
1 

(5,210
)
Total before tax

1,824

Tax (expense) or benefit

$
(3,386
)
Net of Tax
Net unrealized gain (loss) on energy derivative instruments



Commodity contracts: electric derivatives
(2,786
)
Purchased electricity

975

Tax (expense) or benefit

$
(1,811
)
Net of Tax
Net unrealized gain (loss) on treasury interest rate swaps



Interest rate contracts
(122
)
Interest expense

43

Tax (expense) or benefit

$
(79
)
Net of Tax
Total reclassification for the period
$
(5,276
)
Net of Tax
__________
1 These accumulated other comprehensive income components are included in the computation of net periodic pension cost (see Note 5 for additional details).


28



(9)
Other

Jefferson County Public Utility District (JPUD). The Company completed the sale of its electric infrastructure assets located in Jefferson County and the transition of electrical services in the county to JPUD on March 31, 2013. The proceeds from the sale, which will be subject to a further true-up of certain related costs and reimbursement amounts 90 days from the date of the transaction exceed the transferred assets' net carrying value of $46.4 million resulting in a pre-tax gain of approximately $61.8 million. In its 2010 order on the subject, the Washington Commission stated that the Company must file an accounting and ratemaking petition with the Washington Commission to determine how this gain will be allocated between customers and shareholders. As a result, the gain was deferred and recorded as a regulatory liability until the Washington Commission determines the accounting and ratemaking treatment. The Company expects to complete this filing in the third quarter of 2013.
For federal income tax purposes, the Company has elected to treat the transaction as an involuntary conversion under the Internal Revenue Code which allows tax deferral on the gain if PSE acquires qualified replacement property by December 31, 2015. Based on PSE's current construction program projection,  it should have qualified replacement property; however, there can be no assurance that PSE will meet the requirement.


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the financial statements and related notes thereto included elsewhere in this report on Form 10-Q. The discussion contains forward-looking statements that involve risks and uncertainties, such as Puget Energy, Inc.'s (Puget Energy) and Puget Sound Energy, Inc.'s (PSE) objectives, expectations and intentions. Words or phrases such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “future,” “intends,” “may,” “might,” “plans,” “potential,” “predicts,” “projects,” “should,” “will likely result,” “will continue” and similar expressions are intended to identify certain of these forward-looking statements. However, these words are not the exclusive means of identifying such statements. In addition, any statements that refer to expectations, projections or other characterizations of future events or circumstances are forward-looking statements. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. Puget Energy's and PSE's actual results could differ materially from results that may be anticipated by such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed in the section entitled “Forward-Looking Statements” included elsewhere in this report and in the section entitled "Risk Factors" included in Part 1, Item 1A in Puget Energy's and Puget Sound Energy's Form 10-K for the period ended December 31, 2012. Except as required by law, neither Puget Energy nor PSE undertakes any obligation to revise any forward-looking statements in order to reflect events or circumstances that may subsequently arise. Readers are urged to carefully review and consider the various disclosures made in this report and in Puget Energy's and PSE's other reports filed with the United States Securities and Exchange Commission (SEC) that attempt to advise interested parties of the risks and factors that may affect Puget Energy's and PSE's business, prospects and results of operations.

Overview

Puget Energy is an energy services holding company and all of its operations are conducted through its subsidiary PSE, a regulated electric and natural gas utility company. PSE is the largest electric and natural gas utility in the state of Washington, primarily engaged in the business of electric transmission, distribution and generation and natural gas distribution. Puget Energy's business strategy is to generate stable cash flows by offering reliable electric and natural gas service in a cost-effective manner through PSE. On February 6, 2009, Puget Holdings completed its merger with Puget Energy. Puget Holdings is a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust, the Canada Pension Plan Investment Board (CPPIB), the British Columbia Investment Management Corporation, and the Alberta Investment Management Corporation. As a result of the merger, all of Puget Energy's common stock is indirectly owned by Puget Holdings. Puget Energy accounted for the merger as a business combination and all its assets and liabilities were recorded at fair value as of the merger date. PSE's basis of accounting continues to be on a historical basis and PSE's financial statements do not include any purchase accounting adjustments. Puget Energy and PSE are collectively referred to herein as “the Company.”
The Company's strategy is to be a safe, dependable, and efficient utility. The Company strives to be world-class in safety for employees, customers and communities, and is committed to providing exceptional customer service, investing in technology to enhance customer service, assisting in the professional development of its workforce, working with stakeholders to ensure timely and consistent regulatory support, and driving necessary changes to maintain the financial strength of the Company.
These investments and commitments related to utility infrastructure and customer service may give rise to expenditures, which may not be recovered on a timely basis through the ratemaking process.  Additionally, Washington state law requires PSE to pursue

29


conservation initiatives that promote efficient use of energy. This mandate negatively impacts financial performance due to the lost sales margins arising from reduced energy sales. To mitigate the “regulatory lag” and costs associated with conservation initiatives, the Company is focused on the following initiatives:
•
Develop an Expedited Rate Filing (ERF) process that would reduce the regulatory lag.
•
Establish a decoupling mechanism to allow recovery of lost margins from conservation initiatives.
•
Design a pipeline integrity program that would accelerate and enhance the safety of the gas system and ultimately reduce costs.
Additionally, the Company has initiatives to reduce spending over the next five years to maintain its financial strength. The initiatives include re-engineering the customer value chain process as well as evaluating and improving processes in all areas of the Company.
PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. To meet customer growth, to replace expiring power contracts and to meet Washington state's renewable energy portfolio standards, PSE is increasing energy efficiency programs to reduce the demand for additional energy generation and is pursuing additional renewable energy production resources (primarily wind) and base load natural gas-fired generation. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.
For the three months ended March 31, 2013, as compared to the same period in 2012, PSE's net income was affected primarily by the following factors: (1) an unrealized gain in derivatives instruments for energy contracts compared to an unrealized loss for the same period in the prior year; (2) lower power costs; (3) an increase in electric margin; and (4) a decrease in natural gas margin.
Further detail on each of these primary drivers, as well as other factors affecting performance, is set forth in this “Overview” section, as well as in other sections of the Management's Discussion & Analysis.

Factors and Trends Affecting PSE's Performance. PSE's regulatory requirements and operational needs require the investment of substantial capital in 2013 and future years. Because PSE intends to seek recovery of these investments through the regulatory process, its financial results depend heavily upon favorable outcomes from that process. Further, PSE's financial performance is heavily influenced by general economic conditions in its service territory, which affect customer growth and use-per-customer and thus utility sales, as well as by its customers' conservation investments, which to reduce energy sales. The principal business, economic and other factors that affect PSE's operations and financial performance include:

Ÿ
The rates PSE is allowed to charge for its services;
Ÿ
PSE’s ability to recover fixed costs that are included in rates which are based on volume;
Ÿ
Weather conditions, including snow-pack affecting hydrological conditions;
Ÿ
Demand for electricity and natural gas among customers in PSE’s service territory;
Ÿ
Regulatory decisions allowing PSE to recover costs, including purchased power and fuel costs, on a timely basis;
Ÿ
PSE’s ability to supply electricity and natural gas, either through company-owned generation, purchase power contracts or by procuring natural gas or electricity in wholesale markets;
Ÿ
Availability and access to capital and the cost of capital;
Ÿ
Regulatory compliance costs, including those related to new and developing federal regulations of electric system reliability, state regulations of natural gas pipelines and federal, state and local environmental laws and regulations;
Ÿ
The impact of energy efficiency programs on sales and margins;
Ÿ
Wholesale commodity prices of electricity and natural gas;
Ÿ
Increasing depreciation and related property taxes; and
Ÿ
Federal, state, and local taxes.

Regulation of PSE Rates and Recovery of PSE Costs. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Commission. The Washington Commission requires these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically do not provide sufficient revenue to cover year-to-year cost growth, thus rate increases are required. If, in a particular year, PSE's costs are higher than what is currently allowed to be recovered in rates, revenue may not be sufficient to permit PSE to earn its allowed return. In addition, the Washington Commission determines whether expenses and investments are reasonable and prudent in providing electric and natural gas service. If the Washington

30


Commission determines that part of PSE's costs do not meet the standard applied, those costs may be disallowed partially or entirely and not recovered in rates.

Electric Rates
PSE has a Power Cost Adjustment (PCA) mechanism that provides for the recovery of power costs from customers or refunding of power cost savings to customers in the event those costs vary from the “power cost baseline” level of power costs. The “power cost baseline” levels are set, in part, based on normalized assumptions about weather and hydroelectric conditions. Excess power costs or power cost savings are apportioned between PSE and its customers pursuant to the graduated scale set forth in the PCA mechanism.
The graduated scale is as follows:
Annual Power Cost Variability
Customers’
Share
Company’s
Share
+/- $20 million
0%
100%
+/- $20 million - $40 million
50
50
+/- $40 million - $120 million
90
10
+/- $120 + million
95
5

PSE had a favorable PCA imbalance for the three months ended March 31, 2013 which was $15.3 million below the “power cost baseline” level, of which no amount was apportioned to customers. This compares to a favorable imbalance for the three months ended March 31, 2012 of $31.6 million, of which $5.8 million was apportioned to customers.
On January 31, 2013, the Washington Commission approved a rate change to the PSE's Federal Incentive Tracker tariff, effective February 1, 2013, which incorporated the effects of the Treasury Grant related to the Lower Snake River wind generation project and keeping the ten year amortization period and inclusion of interest on the unamortized balance of the grants. The rate change will pass through 11 months of amortization for both grants to eligible customers over 11 months beginning February 1, 2013. Of the total credit, $34.6 million represents the pass-back of grant amortization and $23.8 million represents the pass through of interest. This represents an overall average rate decrease of 2.76%.
 
Natural Gas Rates
PSE has a Purchased Gas Adjustment (PGA) mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs. Variations in natural gas rates are passed through to customers; therefore, PSE's net income is not affected by such variations. Changes in the PGA rates affect PSE's revenue, but do not impact net income as the changes to revenue are offset by increased or decreased purchased gas and gas transportation costs. The following table sets forth natural gas rate adjustments approved by the Washington Commission and the corresponding impact to PSE's annual revenue based on the effective dates:
Type of Rate
Adjustment
Effective
Date
Average Percentage
Increase (Decrease)
in Rates
Annual Increase
(Decrease) in Revenue
(Dollars in Millions)
Purchased Gas Adjustment
November 1, 2012
(7.7
)%
$
(77.0
)
Gas General Rate Case
May 14, 2012
1.3

13.4


Current Rate Proceedings
PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement is intended to settle all issues regarding decoupling, expedited rate filing (ERF) including a property tax tracker, and the power purchase agreement with TransAlta Centralia. The Washington Commission has placed these filings under a common procedural schedule. Hearings are scheduled May 16, 2013 and final orders are anticipated in mid-to-late June 2013.
    
Decoupling. On October 25, 2012, PSE and the Northwest Energy Coalition (NWEC) filed a petition for an order seeking approval of an electric and a natural gas decoupling mechanism for the recovery of its delivery-system costs and authority to record accounting entries associated with the mechanisms. After the petition and supporting testimony were filed, the Washington Commission held two technical conferences to allow interested stakeholders to further discuss the proposed decoupling mechanisms. PSE also responded to inquiries of interested stakeholders seeking additional information about the decoupling proposal.     
On March 4, 2013, PSE and NWEC, taking this process into account, reached an agreement on certain modifications to the decoupling mechanisms and filed an amended petition and testimony in support of these modifications to the original decoupling

31


proposal. The Commission’s regulatory staff (Commission Staff) filed testimony in support of the revised proposal on the same day.

Expedited Rate Filing. On February 4, 2013, PSE filed revised tariff sheets seeking to update its rates established in general rate proceedings in May 2012. The ERF filing is limited in scope and rate impact. This filing is primarily intended to establish baseline rates on which the decoupling mechanisms are proposed to operate. Within the ERF is a proposal for the recovery of PSE’s property tax expenses through a separate rate tracker.
Included in the amended decoupling petition is a rate plan that would allow PSE an opportunity to earn its authorized rate of return without the need for another general rate case process over the plan period. The rate plan includes predetermined annual increases to PSE's allowed electric and gas revenue. Under this plan, PSE, with limited exceptions, would be allowed to file its next general rate case no sooner than April 1, 2015 and no later than April 1, 2016 unless agreed to otherwise by the parties. PSE would continue to be authorized to file for rate changes under existing rate mechanisms such as the PCA and the PGA, during the rate plan period.

TransAlta Centralia Agreement. In 2012, PSE executed a power purchase agreement with TransAlta Centralia for the purchase of up to 380 MW of coal transition power (Centralia Agreement). PSE filed a petition for approval of the Centralia agreement and recovery of related acquisition costs. The Washington Commission issued an order granting PSE's petition which contained conditions that have left PSE with a level of uncertainty such that it would terminate the contract. PSE then subsequently filed for reconsideration of the order which is pending before the Washington Commission as of the issuance date of this report.

If the settlement agreement is approved as proposed, the ERF proposal would produce an additional $31.9 million in estimated annual electric revenue and reduce estimated annual gas revenue by $1.2 million. The property tax tracker proposed as part of the ERF will initially produce little or no incremental revenue, but is intended to reduce regulatory lag associated with the recovery of future increases in property tax expenses. The decoupling settlement proposal would increase electric revenue by $21.2 million annually and $10.8 million annually in gas revenue. The allowed decoupling revenue per customer would subsequently increase by 3.0% for electric customers and 2.2% for gas customers on January 1 of each year until the conclusion of PSE’s next general rate case. The settlement agreement would also resolve the uncertainty related to the Centralia Agreement and would result in the costs and equity component of the contract being eligible for recovery and deferral in PSE’s PCA mechanism beginning in December 2014.

Weather Conditions. Weather conditions in PSE's service territory have a significant impact on customer energy usage, affecting PSE's revenue and energy supply expenses. PSE's operating revenue and associated energy supply expenses are not generated evenly throughout the year. While both PSE's electric and natural gas sales are generally greatest during winter months, variations in energy usage by customers occur from season to season and month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales, and subsequently higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales in the third quarter of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult. PSE reported lower customer usage in the three months ended March 31, 2013 primarily due to Pacific Northwest temperatures being warmer as compared to the same period in the prior year. The actual average temperature during the three months ended March 31, 2013 was 43.44 degrees, or 1.38 degrees warmer than the same period in the prior year, and 0.55 degrees cooler when compared to the historical average.

Customer Demand. PSE expects the number of natural gas customers to grow at rates slightly above electric customers. PSE also expects energy usage by both residential electric and natural gas customers to continue a long-term trend of slow decline primarily due to continued energy efficiency improvements.

Access to Debt Capital. PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under Puget Energy's and PSE's credit facilities, the borrowing costs increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. If PSE is unable to access debt capital on reasonable terms, its ability to pursue improvements or acquisitions, including generating capacity, which may be relied on for future growth and to otherwise implement its strategy, could be adversely affected. PSE monitors the credit environment and expects to continue to be able to access the capital markets to meet its short-term and long-term borrowing needs. PSE's credit facilities expire in 2018 and Puget Energy's senior secured credit facility expires in 2017. (See discussion on credit facilities in the section entitled “Financing Program - Credit Facilities and Commercial Paper”).


32


Regulatory Compliance Costs and Expenditures. PSE's operations are subject to extensive federal, state and local laws and regulations. These regulations cover electric system reliability, gas pipeline system safety and energy market transparency, among other areas. Environmental laws and regulations related to air and water quality, including climate change and endangered species protection, waste handling and disposal (including generation byproducts such as coal ash), remediation of contamination and siting new facilities also impact the Company's operations. PSE must spend significant amounts to fulfill requirements set by regulatory agencies, many of which have greatly expanded mandates, and on measures including, but not limited to, resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees in order to comply with these regulatory requirements.
Compliance with these or other future regulations, such as those pertaining to climate change and generation by-products, could require significant capital expenditures by PSE and may adversely affect PSE's financial position, results of operations, cash flows and liquidity.


Other Challenges and Strategies
Energy Supply. As noted in PSE's Integrated Resource Plan (IRP) filed with the Washington Commission, PSE projects future energy needs will begin to exceed current resources by 2015 from long-term power purchase agreements and Company-controlled power resources.  The IRP identifies reductions in contractual supplies of energy and capacity available under certain long-term power purchase agreements, requiring replacement of supplies to meet projected demands.  Therefore, PSE’s IRP sets forth a multi-part strategy of implementing energy efficiency programs and pursuing additional renewable resources (primarily wind) and additional base load natural gas-fired generation to meet the growing needs of its customers.  If PSE cannot acquire needed energy supply resources at a reasonable cost, it may be required to purchase additional power in the open market at a cost that could, in the absence of regulatory relief, significantly increase its expenses and reduce earnings and cash flows.
Infrastructure Investment. PSE is investing in its utility infrastructure and customer service functions in order to meet regulatory requirements, serve customers' energy needs and replace aging infrastructure. These investments and operating requirements give rise to significant growth in depreciation, amortization and operating expenses, which are not recovered through the ratemaking process in a timely manner. This “regulatory lag” is expected to continue for the foreseeable future.
Operational Risks Associated With Generating Facilities. PSE owns and operates coal, natural gas-fired, hydroelectric, wind-powered, solar and oil-fired generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels, including facility shutdowns due to equipment and process failures or fuel supply interruptions. PSE does not have business interruption insurance coverage to cover replacement power costs.
Energy Efficiency Related Lost Sales Margin. PSE's sales, margins, earnings and cash flow are adversely affected by its energy efficiency programs, many of which are mandated by law. The Company is evaluating strategies and other means to reduce or eliminate these adverse financial effects such as the decoupling mechanism petition discussed in the "Settlement Agreement" section.
Markets For Intangible Power Attributes. The Company is actively engaged in monitoring the development of the commercial markets for such intangible power attributes as Renewable Energy Credits (RECs) and carbon financial instruments. The Company supports the development of regional and national markets for these products that are open, transparent and liquid.


33


Results of Operations
Puget Sound Energy
The following discussion should be read in conjunction with the unaudited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE's results of operations:
 
Three Months Ended
March 31,
 
Puget Sound Energy
(Dollars in Thousands)
2013
2012
Favorable/
(Unfavorable)
Operating revenue:
 
 
 
Electric
 
 
 
Residential sales
$
360,918

$
362,479

(0.4
)%
Commercial sales
225,956

230,199

(1.8
)
Industrial sales
26,810

27,952

(4.1
)
Other retail sales, including unbilled revenue
(11,282
)
(15,130
)
25.4

Total retail sales
602,402

605,500

(0.5
)
Transportation sales
1,846

2,466

(25.1
)
Sales to other utilities and marketers
8,986

7,046

27.5

Other
1,400

(3,485
)
*

Total electric operating revenue
614,634

611,527

0.5

Gas
 

 

 
Residential sales
261,184

296,795

(12.0
)
Commercial sales
106,557

120,880

(11.8
)
Industrial sales
9,718

10,886

(10.7
)
Total retail sales
377,459

428,561

(11.9
)
Transportation sales
4,061

3,921

3.6

Other
3,245

3,484

(6.9
)
Total gas operating revenue
384,765

435,966

(11.7
)
Non-utility operating revenue
308

1,019

(69.8
)
Total operating revenue
999,707

1,048,512

(4.7
)
Operating expenses:
 

 

 
Energy costs
 

 

 
Purchased electricity
175,043

199,115

12.1

Electric generation fuel
59,087

69,937

15.5

Residential exchange
(22,551
)
(23,335
)
(3.4
)
Purchased gas
189,983

233,519

18.6

Net unrealized (gain) loss on derivative instruments
(72,740
)
10,135

*

Utility operations and maintenance
129,235

128,046

(0.9
)
Non-utility expense and other
3,091

3,230

4.3

Depreciation
88,178

79,006

(11.6
)
Amortization
5,744

13,343

57.0

Conservation amortization
34,107

34,402

0.9

Taxes other than income taxes
99,943

99,869

(0.1
)
Total operating expenses
689,120

847,267

18.7

Operating income (loss)
310,587

201,245

54.3

Other income
12,012

14,933

(19.6
)
Other expense
(1,542
)
(3,754
)
58.9

Interest expense
(61,358
)
(53,493
)
(14.7
)
Income (loss) before income taxes
259,699

158,931

63.4

Income tax (benefit) expense
79,761

46,215

(72.6
)
Net income (loss)
$
179,938

$
112,716

59.6
 %
__________
* 
Not meaningful


34


NON-GAAP FINANCIAL MEASURES - Electric and Gas Margins
The following discussion includes financial information prepared in accordance with U.S. Generally Accepted Accounting Principles (GAAP), as well as two other financial measures, electric margin and gas margin, that are considered “non-GAAP financial measures.” Generally, a non-GAAP financial measure is a numerical measure of a company's financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. The presentation of electric margin and gas margin is intended to supplement an understanding of PSE's operating performance. Electric margin and gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of energy costs from its customers to allow recovery of operating costs. PSE's electric margin and gas margin measures may not be comparable to other companies' electric margin and gas margin measures. Furthermore, these measures are not intended to replace operating income as determined in accordance with GAAP as an indicator of operating performance.


Electric Margin
Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs to bring electric energy to PSE's service territory. The following table displays the details of PSE's electric margin changes:

 
Three Months Ended
March 31,
 
Electric Margin
(Dollars in Thousands)
2013
2012
Favorable/
(Unfavorable)
Electric operating revenue:
 
 
 
Residential sales
$
360,918

$
362,479

(0.4
)%
Commercial sales
225,956

230,199

(1.8
)
Industrial sales
26,810

27,952

(4.1
)
Other retail sales, including unbilled revenues
(11,282
)
(15,130
)
25.4

Total retail sales
602,402

605,500

(0.5
)
Transportation sales
1,846

2,466

(25.1
)
Sales to other utilities and marketers
8,986

7,046

27.5

Other
1,400

(3,485
)
*

Total electric operating revenues1
614,634

611,527

0.5

Minus power costs:
 

 

 

Purchased electricity1
175,043

199,115

12.1

Electric generation fuel1
59,087

69,937

15.5

Residential exchange1
(22,551
)
(23,335
)
(3.4
)
Total electric power costs
211,579

245,717

13.9

Electric margin2
$
403,055

$
365,810

10.2
 %
______________
1 
As reported on PSE’s Consolidated Statement of Income.
2 
Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense.
* 
Not meaningful

35


Electric margin increased $37.2 million, or 10.2%, to $403.1 million from $365.8 million for the three months ended March 31, 2013, as compared to the same period in 2012. Following is a discussion of significant items that impact electric operating revenue and electric energy costs, which are included in electric margin:

Electric Operating Revenue
Electric operating revenues increased $3.1 million, or 0.5%, to $614.6 million from $611.5 million for the three months ended March 31, 2013, as compared to the same period in 2012. The increase in operating revenues was primarily due to higher miscellaneous operating revenues of $4.9 million and higher sales to other utilities and marketers of $1.9 million, which were partially offset by lower electric retail sales of $3.1 million. These items are discussed in detail below.
Electric retail sales decreased $3.1 million, or 0.5%, to $602.4 million from $605.5 million for the three months ended March 31, 2013, as compared to the same period in 2012. The decrease in electric retail sales was primarily due to a revenue decrease of $12.3 million due to lower retail electricity usage of 125,093 MWhs, or 2.0%, as a result of warmer average temperatures in PSE's service territory during the three months ended March 31, 2013, as compared to the same period in the prior year (see discussion in the section entitled "Weather Conditions"); and a net revenue increase of $9.2 million due to the electric rate increase effective May 14, 2012 (average 3.2% increase), offset by the rate decrease due to PSE's Federal Incentive Tracker tariff, effective July 3, 2012 (average 0.24% decrease) and February 1, 2013 (average 2.76% decrease), and various other pass-through tariff items that have no impact on net earnings.
Sales to other utilities and marketers increased $1.9 million, or 27.5%, to $9.0 million from $7.0 million for the three months ended March 31, 2013, as compared to the same period in 2012. The increase was primarily driven by an increase of $1.8 million due to higher wholesale electricity prices, and an increase of $0.1 million due to an increase in sales volumes of 5,763 MWhs, or 1.8%, for the three months ended March 31, 2013.
Other electric operating revenue increased $4.9 million to a revenue of $1.4 million from a loss of $3.5 million for the three months ended March 31, 2013, as compared to the same period in 2012. The increase was primarily the result of a higher transmission revenue of $3.1 million and lower losses on non-core gas sales of $0.3 million for the three months ended March 31, 2013.
Electric Energy Costs
Purchased electricity expense decreased $24.1 million, or 12.1%, to $175.0 million from $199.1 million for the three months ended March 31, 2013, as compared to the same period in 2012. The decrease was primarily the result of a decrease of $18.7 million related to the expiration of a high cost long-term firm purchase contract that was replaced with lower market price power and wind generation, a decrease of $5.8 million due to a decrease in the overrecovery of power costs, which is shared with customers in accordance with the PCA mechanism, and a decrease of $4.9 million due to a decrease in additional costs recognized in order to offset the deferral of variable costs related to the Lower Snake River project prior to the inclusion of the plant in rates. Partially offsetting the decrease was an increase of $4.1 million credits related to Ferndale market price offset for the three months ended March 31, 2013, which provides the customer an offset for the market power purchases built into current rates that will not be incurred during the deferral period.
To meet customer demand, PSE economically dispatches resources in its power supply portfolio, such as, fossil-fuel generation, owned and contracted hydroelectric capacity and energy and long-term contracted power. However, depending principally upon availability of hydroelectric and wind energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its regulated power portfolio through short-term and intermediate-term off-system physical purchases and sales as well as through other risk management techniques.
Electric generation fuel expense decreased $10.9 million, or 15.5%, to $59.1 million from $69.9 million for the three months ended March 31, 2013, as compared to the same period in 2012. The decrease was primarily due to a decrease of $14.5 million in fuel expense at PSE's combustion turbine facilities. For the three months ended March 31, 2013, electric generation at combustion turbine facilities decreased 50,035 MWhs, or 4.7%, primarily due to an increase of 86,270 MWhs, or 19.6%, wind generation, as compared to the same period in 2012. Additionally, the decrease was offset by an increase of $3.6 million in fuel expense at the Colstrip facility as its electric generation increased 254,263 MWhs, or 22.5%, for the three months ended March 31, 2013, as compared to the same period in 2012.


36


Natural Gas Margin
Gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE's service territory. The following table displays the details of PSE's natural gas margin:
 
Three Months Ended
March 31,
 
Natural Gas Margin
(Dollars in Thousands)
2013
2012
Favorable/
(Unfavorable)
Gas operating revenue:
 
 
 
Residential sales
$
261,184

$
296,795

(12.0
)%
Commercial sales
106,557

120,880

(11.8
)
Industrial sales
9,718

10,886

(10.7
)
Total retail sales
377,459

428,561

(11.9
)
Transportation sales
4,061

3,921

3.6

Other
3,245

3,484

(6.9
)
Total gas operating revenues1
384,765

435,966

(11.7
)
Minus purchased gas costs1
189,983

233,519

18.6

Natural gas margin2
$
194,782

$
202,447

(3.8
)%
______________
1 
As reported on PSE's Consolidated Statement of Income.
2 
Gas margin does not include any allocation for amortization/depreciation expense or electric generation operations and maintenance expense.

Natural gas margin decreased $7.7 million, or 3.8%, to $194.8 million from $202.4 million for the three months ended March 31, 2013, as compared to the same period in 2012. Following is a discussion of significant items of gas operating revenue and gas energy costs which are included in gas margin:

Gas Operating Revenue
Gas operating revenues decreased $51.2 million, or 11.7%, to $384.8 million from $436.0 million for three months ended March 31, 2013, as compared to the same period in 2012. The decrease was due primarily to lower natural gas retail sales as discussed in detail below.
Natural gas retail sales decreased $51.1 million, or 11.9%, to $377.5 million from $428.6 million for the three months ended March 31, 2013, as compared to the same period in 2012. The decrease was primarily due to a revenue decrease of $26.3 million due to lower therm sales of 23.2 million, or 6.1%, primarily due to warmer average temperatures (See discussion in the section entitled "Weather Conditions"); and a net revenue decrease of $24.8 million due to the PGA rate decrease effective November 1, 2012 (average 7.7% decrease) offset by the gas rate increase effective May 14, 2012 (average 1.3% increase). The PGA mechanism passes through to customers increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE's net income is not affected by changes under the PGA mechanism.

Gas Energy Costs
Purchased gas expenses decreased $43.5 million, or 18.6%, to $190.0 million from $233.5 million for the three months ended March 31, 2013, as compared to the same period in 2012. The decrease was primarily due to lower natural gas costs reflected in PGA rates effective November 1, 2012. Also contributing to the decrease was a reduction in customer usage of 6.1% as a result of warmer average temperatures for the three months ended March 31, 2013, as compared to the same period in 2012.
The PGA mechanism provides the rates used to determine natural gas costs based on customer usage. The rate decrease was the result of decreasing costs of wholesale natural gas. The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable balance in the PGA mechanism reflects an underrecovery of natural gas cost through rates. A payable balance reflects overrecovery of natural gas cost through rates. The PGA mechanism payable balance at March 31, 2013 was $26.9 million, which will be reflected on customers' bills through a future PGA rate filing.


37


Other Operating Expenses
Net unrealized gain on derivative instruments increased $82.9 million to a gain of $72.7 million during the three months ended March 31, 2013 from a loss of $10.1 million during the same period in 2012. The net gain for the three months ended March 31, 2013 is primarily due to a gain of $41.0 million related to the settlement of contracts with unrealized losses from previous periods, and a gain of $31.7 million due to the increase in natural gas and wholesale electricity prices from previously recorded losses. The average prices of electricity and natural gas, weighted based on PSE's derivative portfolio volumes, increased 12.1% and 6.7%, respectively, during the three months ended March 31, 2013.
Depreciation expense increased $9.2 million, or 11.6%, to $88.2 million from $79.0 million for the three months ended March 31, 2013, as compared to the same period in 2012. The increase was primarily due to additional capital expenditures placed into service, net of retirements, such as the Lower Snake River (LSR) wind generation facility which began commercial operations on February 29, 2012.
Amortization expense decreased $7.6 million, or 57.0%, to $5.7 million from $13.3 million for the three months ended March 31, 2013, as compared to the same period in 2012. The decrease was primarily due to deferral of Ferndale fixed costs of $2.0 million and amortization of LSR US Treasury Grant interests of $4.3 million for the three months ended March 31, 2013. There were no such credits during the same period in 2012.

Other Income and Interest Expense and Income Tax Expense
Other income decreased $2.9 million, or 19.6%, to $12.0 million from $14.9 million for the three months ended March 31, 2013, as compared to the same period in 2012. The decrease was primarily due to a decrease of $2.4 million in AFUDC income, mostly related to the decrease in average construction work in process for the three months ended March 31, 2013, as compared to the same period in 2012.
Other expense decreased $2.2 million, or 58.9%, to $1.5 million from $3.8 million for the three months ended March 31, 2013, as compared to the same period in 2012. The decrease was primarily due to a reduction of $2.4 million related to customer credits resulting from the outages due to the January 2012 winter storm.
Interest expense increased $7.9 million, or 14.7%, to $61.4 million from $53.5 million for the three months ended March 31, 2013, as compared to the same period in 2012. The increase was primarily due to an increase of $5.3 million in LSR US Treasury Grant interests for the three months ended March 31, 2013. In December 2012, the U.S. Treasury approved a Treasury Grant of $205.3 million related to LSR wind generation project. The Treasury Grant and the interest on its unamortized balance will be passed through to eligible customers as specified in PSE's Federal Incentive Tracker tariff, effective February 1, 2013. Also contributing to the increase is a decrease of $2.6 million in debt component of AFUDC for the three months ended March 31, 2013, primarily due to the decrease in average construction work in process.
Income tax expense increased $33.5 million, or 72.6%, to $79.8 million from $46.2 million for the three months ended March 31, 2013, as compared to the same period in 2012. The increase was primarily due to higher taxable income for the three months ended March 31, 2013, as compared to same period in 2012.


38


Puget Energy

Summary Results of Operations
All the operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income for the three months ended March 31, 2013 and 2012 was as follows:
 
Three Months Ended
March 31,
 
Benefit/(Expense)
(Dollars in Thousands)
2013
2012
Percent
Change
PSE net income
$
179,938

$
112,716

59.6
 %
Other operating revenue
111

—

*

Net unrealized gain on energy derivative instruments
2,952

5,409

(45.4
)
Non-utility expense and other
4,085

2,370

72.4

Other income
—

3

*

Non-hedging interest rate derivative expense
1,028

527

95.1

Interest expense 1
(29,810
)
(46,413
)
35.8

Income tax benefit (expense)
9,171

13,868

33.9

Puget Energy net income
$
167,475

$
88,480

89.3
 %
__________
* 
Not meaningful
1 
Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt.

Puget Energy's net income for the three months ended March 31, 2013 was $167.5 million with operating revenue of $1.0 billion as compared to a net income of $88.5 million with operating revenue of $1.0 billion for the same period in 2012.
The following are significant factors that impacted Puget Energy's net income, which are not included in PSE's discussion:
Net unrealized gain on derivative instruments decreased $2.5 million, or 45.4%, to $3.0 million from $5.4 million for three months ended March 31, 2013, as compared to the same period in 2012, due to the effects of purchase accounting on derivative contracts in OCI of $0.3 million and the fair value amortization of NPNS derivative contracts of $2.2 million.
Interest expense decreased $16.6 million, or 35.8%, to $29.8 million from $46.4 million for the three months ended March 31, 2013, as compared to the same period in 2012. The decrease was primarily due to a write-off of the unamortized issuance costs of $13.2 million for the three months ended March 31, 2012, related to a retirement of the five-year term loan; a decrease of $3.6 million in mark-to-market gains on hedged interest rate swap contracts; a decrease of $3.2 million in interest expense related to hedged interest rate swap contracts; a decrease of $2.2 million in interest expense related to Puget Energy's revolving senior secured credit facility as its balance was reduced in 2012; and partially offset by an increase of $6.3 million in interest expense related to the senior secured notes of $450.0 million issued on June 15, 2012.


Capital Requirements
Contractual Obligations and Commercial Commitments
There have been no material changes to the contractual obligations set forth in Part II, Item 7 in Puget Energy's and PSE's combined annual report on Form 10-K for the year ended December 31, 2012.

39


The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of March 31, 2013:
 
Amount of Available Commitments
Expiration Per Period
Commercial Commitments
(Dollars in Thousands)
Total

2013

2014-2015

2016-2017

Thereafter

PSE liquidity facility 1
$
641,400

$
—

$
—

$
—

$
641,400

PSE energy hedging facility 1
350,000

—

—

—

350,000

Inter-company short-term debt 2
402

402

—

—

—

Total PSE commercial commitments
$
991,802

$
402

$
—

$
—

$
991,400

Puget Energy revolving credit facility 3
395,000

—

—

395,000

—

Less: Inter-company short-term debt elimination 2
(402
)
(402
)
—

—

—

Total Puget Energy commercial commitments
$
1,386,400

$
—

$
—

$
395,000

$
991,400

_____________
1 
As of December 31, 2012, PSE had three credit facilities totaling $1.15 billion and no amount had been drawn. On February 4, 2013, PSE entered into two new credit facilities and terminated its previous three credit facilities. The new credit facilities provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) for general corporate purposes, including a backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. As of March 31, 2013, no amount was drawn and outstanding under PSE's $650.0 million liquidity facility. One letter of credit totaling $8.6 million in support of contracts was outstanding under the facility, and $25.0 million was outstanding under the commercial paper program. No amounts were drawn or outstanding (including letters of credit) under PSE's $350.0 million facility supporting energy hedging. Outside of the credit agreements, PSE had a $4.9 million letter of credit in support of a long-term transmission contract.
2 
As of March 31, 2013, PSE had a revolving credit facility with Puget Energy in the form of a promissory note to borrow up to $30.0 million of which $29.6 million was drawn.
3 
Concurrent with the closing of the new PSE credit facilities in February 2013, the Company reduced the size of Puget Energy's credit facility from $1.0 billion to $800.0 million. The Puget Energy revolving credit facility also has an accordion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. All other terms and conditions of that facility remain unchanged. As of March 31, 2013, $405.0 million was drawn under the $800.0 million Puget Energy revolving credit facility.

Utility Construction Program
PSE’s construction programs for generating facilities, the electric transmission system and the natural gas and electric distribution systems are designed to meet regulatory requirements and customer growth and to support reliable energy delivery.  Construction expenditures, excluding equity AFUDC, were $168.3 million for the three months ended March 31, 2013.  Presently planned utility construction expenditures, excluding AFUDC, are as follows:

Capital Expenditure Projections
(Dollars in Thousands)
2013

2014

2015

Total energy delivery, technology and facilities expenditures
$
521,427

$
514,331

$
565,341


The program is subject to change based upon general business, economic and regulatory conditions.  Utility construction expenditures and any new generation resource expenditures may be funded from a combination of sources which may include cash from operations, short-term debt, long-term debt and/or equity.  PSE’s planned capital expenditures may result in a level of spending that will exceed its cash flow from operations.  As a result, execution of PSE’s strategy is dependent in part on continued access to capital markets.  The largest single projects include the following:
Snoqualmie Falls.  Under the Snoqualmie Falls hydroelectric facility’s federal operating license granted by the FERC in 2004 and amended in 2009, PSE is performing a major, three year redevelopment project to upgrade aging energy infrastructure, enhance park and recreation amenities and preserve cultural and historical artifacts.  This project will enable Snoqualmie Falls to continue to produce clean, renewable energy for decades to come.
The substantial upgrades and enhancements to its power-generating infrastructure include new generators, water-intake structures, penstocks and flow-control systems at Plant 1 and Plant 2.  The upgrades will boost the project’s authorized output (currently 44 megawatt (MW)) to 54 MW.  Plant 1 is now offline and is expected to return to service by the end of the third quarter in 2013.  Plant 2 returned to service on April 17, 2013. PSE has engaged a general contractor to perform this work on its behalf, pursuant to a guaranteed maximum price construction contract.
Baker.  Under the terms of the FERC issued 50-year operating license for the Baker hydroelectric generating facility, PSE has completed several capital projects and is currently undertaking several more, each of which implements various license provisions and upgrades for the 80-year old facility. One of these upgrades includes the addition of 30 MW of generating capacity, which is expected to be in service by the end of 2013.


40




Capital Resources
Cash From Operations

Puget Sound Energy
Cash generated from operations for the three months ended March 31, 2013 increased by $71.0 million from $261.2 million generated during the same period in 2012.  The increase in cash flow was primarily due to the absence of storm costs in the first quarter of 2013 compared to $67.0 million incurred in 2012.

Puget Energy
Cash generated from operations for the three months ended March 31, 2013 was $323.8 million, an increase of $50.2 million from the $273.6 million generated during the three months ended March 31, 2012.  The increase is primarily due to cash provided by the operating activities of PSE as previously discussed of $71.0 million offset by an increase of Puget Energy bond interest payment of $14.8 million.

Financing Program
The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. The Company anticipates refinancing the redemption of bonds or other long-term borrowings with its credit facilities and/or the issuance of new long-term debt. Access to funds depends upon factors such as Puget Energy's and PSE's credit ratings, prevailing interest rates and investor receptivity to investing in the utility industry, Puget Energy and PSE.

Credit Facilities and Commercial Paper
Proceeds from PSE's short-term borrowings and sales of commercial paper are used to provide working capital and the interim funding of utility construction programs. Puget Energy and PSE continue to have reasonable access to the capital and credit markets.

Puget Sound Energy Credit Facilities
On February 4, 2013, PSE entered into two new unsecured revolving credit facilities and terminated its previous three credit facilities. The new credit facilities provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The new credit facilities also have an accordion feature that, upon the banks' approval, would increase the total size of these facilities to $1.5 billion.
The credit agreements for these two replacement credit facilities contain similar terms and conditions and are syndicated among numerous lenders and mature in February 2018. The credit agreements contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to incur additional indebtedness and liens, issue equity, pay dividends, transact with affiliates and make asset dispositions and investments. The credit agreements also contain a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of March 31, 2013, PSE was in compliance with all applicable covenants.
The credit agreements provide PSE with the ability to borrow at different interest rate options. The credit agreements allow PSE to borrow at the bank's prime rate or to make floating rate advances at the LIBOR plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facilities. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.50% and the commitment fee is 0.225%.
As of March 31, 2013, no amount was drawn and outstanding under PSE's $650.0 million liquidity facility. One letter of credit in the amount of $8.6 million in support of contracts was outstanding under the facility, and $25.0 million was outstanding under the commercial paper program. No amounts were drawn or outstanding (including letters of credit) under PSE's $350.0 million facility supporting energy hedging. Outside of the credit agreements, PSE had a $4.9 million letter of credit in support of a long-term transmission contract.

Demand Promissory Note.
On June 1, 2006, PSE entered into a revolving credit facility with Puget Energy, in the form of a credit agreement and a Demand Promissory Note (Note) pursuant to which PSE may borrow up to $30.0 million from Puget Energy subject to approval by Puget Energy. Under the terms of the Note, PSE pays interest on the outstanding borrowings based on the lower of the weighted-average interest rates of PSE's outstanding commercial paper interest rate or PSE's senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. At March 31, 2013, the outstanding balance of the

41


Note was $29.6 million. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE's financial statements.

Puget Energy Credit Facilities
On February 10, 2012, Puget Energy entered into a $1.0 billion five-year revolving senior secured credit facility. Concurrent with the closing of the new PSE credit facilities in February 2013, the Company reduced the size of Puget Energy's credit facility from $1.0 billion to $800.0 million. The Puget Energy revolving credit facility also has an accordion feature that, upon the banks' approval, would increase the size of the facility to $1.3 billion. All other terms and conditions of that facility remain unchanged from when it was committed in 2012. Initial borrowings under this facility were used to repay debt outstanding under the term loan and capital expenditure credit facility and those agreements were terminated. As a revolving facility, amounts borrowed may be repaid without a reduction in the size of the facility.
The five-year revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains two financial covenants based on the following ratios: Group Funds From Operations (FFO) Coverage Ratio and Maximum Leverage Ratio, as defined in the agreement governing the senior secured credit facility. As of March 31, 2013, Puget Energy was in compliance with all applicable covenants.
The senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the prime rate or LIBOR, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of March 31, 2013, $405.0 million was drawn and outstanding under the facility, the spread over LIBOR was 2.0% and the commitment fee was 0.375%. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility (see Note 3 and the "Interest Rate Risk" section in Item 3).

Dividend Payment Restrictions
The payment of dividends by PSE to Puget Energy is restricted by provisions of certain covenants applicable to long-term debt contained in PSE's electric and natural gas mortgage indentures. At March 31, 2013, approximately $578.7 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.
Beginning February 6, 2009, pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE's common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission. Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE's corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE's ratio of Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3 to one. The common equity ratio, calculated on a regulatory basis, was 49.1% at March 31, 2013 and the EBITDA to interest expense was 4.5 to one for the twelve months then ended.
PSE's ability to pay dividends is also limited by the terms of its credit facilities, pursuant to which PSE is not permitted to pay dividends during any Event of Default, or if the payment of dividends would result in an Event of Default (as defined in the facilities), such as failure to comply with certain financial covenants.
Puget Energy's ability to pay dividends is also limited by the merger order issued by the Washington Commission. Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy's ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2 to one. Puget Energy's EBITDA to interest expense was 2.9 to one for the twelve months ended March 31, 2013.
At March 31, 2013, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Debt Restrictive Covenants
The type and amount of future long-term financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.
PSE's ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures. Under the most restrictive tests, at March 31, 2013, PSE could issue:

•
Approximately $1.3 billion of additional first mortgage bonds under PSE's electric mortgage indenture based on approximately $2.2 billion of electric bondable property available for issuance, subject to an interest coverage ratio limitation of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at March 31, 2013; and
•
Approximately $259.0 million of additional first mortgage bonds under PSE's natural gas mortgage indenture based on approximately $380.0 million of gas bondable property available for issuance, subject to a combined gas and electric interest coverage test of 1.75 times net earnings available for interest and a gas interest coverage test of 2.0 times net earnings available for interest (as defined in the natural gas utility mortgage), both of which PSE exceeded at March 31, 2013.

42



At March 31, 2013, PSE had approximately $6.6 billion in electric and natural gas ratebase to support the interest coverage ratio limitation test for net earnings available for interest.
Upon approval of the merger in 2009, the Company was required to refinance its debt in place at the time of the merger. The Company has met this refinancing requirement as of March 31, 2013.

Shelf Registrations and Long-Term Debt Activity
Puget Sound Energy. PSE has in effect a shelf registration statement under which it may issue, from time to time, senior notes secured by first mortgage bonds. The Company remains subject to the restrictions of PSE's indentures and credit agreements on the amount of first mortgage bonds that PSE may issue.


Other

Residential Exchange
The Northwest Power Act, through the Residential Exchange Program (REP), provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE.  The program is administered by the BPA.  Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.
In 2007, the United States Court of Appeals for the Ninth Circuit (Ninth Circuit) ruled that REP agreements of the BPA with PSE and a number of other investor-owned utilities were inconsistent with the Northwest Power Act.  Since that time, those investor-owned utilities, including PSE, the BPA and other parties have been involved in ongoing litigation at the Ninth Circuit relating to the amount of REP benefits paid to utilities, including PSE, for the fiscal year 2002 through fiscal year 2011 period and the amount of REP benefits to be paid going forward.
In July 2011, the BPA, PSE and a number of other parties entered into a settlement agreement that by its terms, if upheld in its entirety, would resolve the disputes between BPA and PSE regarding REP benefits paid for fiscal years 2002-2011 and determine REP benefits for fiscal years 2012-2028.  In October 2011, certain other parties challenged BPA decisions with regard to its entering into this most recent settlement agreement.  Oral argument in the Ninth Circuit on this litigation occurred on February 19, 2013. Pending disposition of this challenge, the other pending Ninth Circuit litigation regarding REP benefits has been stayed by the Ninth Circuit.
Due to the pending and ongoing proceedings, PSE is unable to reasonably estimate any amounts of REP payments either to be recovered by the BPA or to be paid for any future periods to PSE, and is unable to determine the impact, if any, these proceedings and litigation may have on PSE.  However, the Company believes it is unlikely that any unfavorable outcome would have a material adverse effect on PSE because REP benefits received by PSE are passed through to PSE's residential and small farm customers.

Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, Sierra Club and Montana Environmental Information Center (MEIC) filed a Clean Air Act citizen suit against all Colstrip owners (including PSE) alleging 39 claims for relief, most which relate to alleged prevention of significant deterioration (PSD) violations, one claim relates to the alleged failure to update the Title V permit to reflect the major modifications alleged in the first thirty-six claims, another claim alleges that the previous Title V compliance certifications have been incomplete because they did not address the alleged major modifications, and the last claim alleges opacity violations since 2007. The lawsuit was filed in U.S. District of Montana, Billings Division requesting injunctive relief and civil penalties, including a request that the owners remediate environmental damage and that $100,000 of the civil penalties be used for beneficial mitigation projects. This lawsuit followed various Notices of Intent to Sue sent to Colstrip owners (including PSE) from the Sierra Club and the MEIC on July 25, 2012, amended August 30, 2012, September 27, 2012 and December 1, 2012.  PSE is evaluating the allegations set forth in the notices and cannot at this time predict the outcome of this matter.
 

Item 3.                      Quantitative and Qualitative Disclosure about Market Risk

Energy Portfolio Management

Accounting Standards Codification (ASC) 815, “Derivatives and Hedging” (ASC 815), requires a significant amount of disclosure regarding PSE’s derivative activities and the nature of their impact on PSE’s financial position, financial performance

43


and cash flows.  The information in this Item 3 should serve as an accompaniment to Management’s Discussion and Analysis and Note 3 to the consolidated financial statements, included in Item 2 and Part 1 of this report, respectively.
PSE maintains energy risk policies and procedures to manage commodity price exposure and risks associated with its natural gas and electric portfolios.  PSE’s Energy Management Committee (EMC) establishes PSE’s risk management policies and procedures and monitors compliance.  The EMC is comprised of certain PSE officers and is overseen by the PSE Board of Directors.  It is not engaged in the business of assuming risk for the purpose of speculative trading.  
PSE hedges open natural gas and electric positions to reduce the volatility risk in prices.  The exposure position is determined by using a probabilistic risk system that models 250 simulations of how PSE’s natural gas and power portfolios will perform under various weather, hydroelectric and unit performance conditions.  The objectives of the hedging strategy are to:
Ÿ
Ensure physical energy supplies are available to reliably and cost-effectively serve retail load;
Ÿ
Manage the energy portfolio prudently to serve retail load at overall least cost and limit undesired impacts on PSE’s customers and shareholders;
Ÿ
Reduce power costs by extracting the value of PSE’s assets; and
Ÿ
Meet the credit, liquidity, financing, tax and accounting requirements of PSE.

The nature of serving regulated electric customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks within the sharing mechanism of the PCA. PSE's natural gas retail customers are served by natural gas purchase contracts which expose PSE's customers to commodity price risks through the PGA mechanism. All purchased natural gas costs are recovered through customer rates with no direct impact on PSE. Therefore, wholesale market transactions and related hedging strategies are focused on reducing costs and risks where feasible thus reducing volatility in costs in the natural gas and electric portfolio. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, and floating-for-fixed swap contracts. The forward physical electric contracts are both fixed and variable (at index) while the physical natural gas contracts are variable with investment grade counterparties that do not require collateral calls on the contracts. To fix the price of wholesale electricity and natural gas, PSE may enter into floating-for-fixed swap (financial) contracts with various counterparties.
On July 1, 2009, Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated OCI is transferred to earnings in the same period(s) during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will continue to experience the earnings impact of these reversals from OCI in future periods.
The following table presents the Company's energy derivative instruments:

Puget Energy and Puget Sound Energy
 
(Dollars in thousands)
March 31, 2013
December 31, 2012
 
Assets
Liabilities
Assets
Liabilities
Electric portfolio:
 
 
 
 
Current
$
9,538

$
37,714

$
3,418

$
93,097

Long-term
6,594

24,526

6,139

38,096

Total electric derivatives
$
16,132

$
62,240

$
9,557

$
131,193

Natural Gas portfolio:
 

 

 

 

Current
$
10,872

$
36,938

$
3,451

$
77,851

Long-term
7,858

14,041

8,675

30,227

Total natural gas derivatives
$
18,730

$
50,979

$
12,126

$
108,078

Total energy derivatives
$
34,862

$
113,219

$
21,683

$
239,271


For further details regarding both the fair value of derivative instruments and the impacts such instruments have on current period earnings and OCI (for cash flow hedges), see Notes 3 and 4 to the consolidated financial statements.
At March 31, 2013, the Company had total assets of $18.7 million and total liabilities of $51.0 million related to derivative contracts used to hedge the supply and cost of natural gas to serve natural gas customers. All fair value adjustments of derivatives relating to the natural gas business have been reclassified to a deferred account in accordance with ASC 980, “Regulated Operations” (ASC 980) due to the PGA mechanism. All increases and decreases in the cost of natural gas supply are passed on

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to customers with the PGA mechanism. As the gains and losses on the hedges are realized in future periods, they will be recorded as natural gas costs under the PGA mechanism. As the gains and losses in the electric portfolio are realized, they will be recorded as either purchased power costs or electric generation fuel costs under the PCA mechanism.
A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative contracts by $44.3 million.

Contingent Features and Counterparty Credit Risk
PSE is exposed to credit risk primarily through buying and selling electricity and natural gas to serve customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. PSE manages credit risk with policies and procedures for, among other things, counterparty analysis and measurement, monitoring and mitigation of exposure.
Where deemed appropriate, and when allowed under the terms of the agreements, PSE may request collateral or other security from its counterparties to mitigate the potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure. As of March 31, 2013, PSE held approximately $5.9 billion worth of standby letters of credit and parental guarantees in support of various electric and natural gas transactions.
It is possible that volatility in energy commodity prices could cause PSE to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, PSE could suffer a material financial loss. As of March 31, 2013, approximately 80.68% of PSE's energy and natural gas portfolio exposure, including Normal Purchase Normal Sale (NPNS) transactions, is with counterparties that are rated at least investment grade by the major rating agencies, while 19.32% are either rated below investment grade or are not rated by rating agencies. PSE assesses credit risk for counterparties that are not rated.
PSE has entered into commodity master arrangements with its counterparties to mitigate credit exposure to those counterparties. PSE generally enters into the following master arrangements: (1) WSPP, Inc. (WSPP) agreements - to standardized power sales contracts in the electric industry; (2) International Swaps and Derivatives Association (ISDA) agreements - to standardized financial gas and electric contracts; and (3) North American Energy Standards Board (NAESB) agreements- to standardized physical gas contracts. PSE believes that entering into such agreements reduces the risk of default by allowing a counterparty the ability to make only one net payment.
PSE monitors counterparties that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies or have changes in ownership. Counterparty credit risk impacts PSE's decisions on derivative accounting treatment. A counterparty may have a deterioration of credit below investment grade, potentially indicating it is no longer probable that it will fulfill its obligations under a contract (e.g., make a physical delivery upon the contracts maturity). If a forecasted transaction associated with cash flow hedge is probable of not occurring , PSE will reclassify the amounts deferred in accumulated OCI into earnings.
Should a counterparty file for bankruptcy, which would be considered a default under master arrangements, PSE may terminate related contracts. Derivative accounting entries previously recorded would be reversed in the financial statements. PSE would compute any terminations receivable or payable, based on the terms of existing master agreements.
The Company computes credit reserves at a master agreement level by counterparty (i.e., WSPP, ISDA or NAESB). The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is used by weighting the fair value and contract tenors of all deals for each counterparty and arriving at an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. The fair value of derivatives includes the impact of credit and non-performance reserves. As of March 31, 2013, the Company was in a net liability position with the majority of its counterparties, therefore the default factors of counterparties did not have a significant impact on reserves for the year. Despite its net liability position, PSE was not required to post any collateral with any of its counterparties. Additionally, PSE did not trigger collateral requirements with any of its counterparties, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.

Interest Rate Risk
The Company believes its interest rate risk primarily relates to the use of short-term debt instruments, variable rate leases and anticipated long-term debt financing needed to fund capital requirements. The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program, and its credit facilities to meet short-term funding needs. Short-term obligations are commonly refinanced with fixed-rate bonds or notes when needed and when interest rates are considered favorable. The Company may also

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enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of March 31, 2013, Puget Energy had two interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.
At March 31, 2013, the fair value of the interest rate swaps was a $20.0 million pre-tax loss. This fair value considers the risk of Puget Energy's non-performance by using Puget Energy's incremental borrowing rate on unsecured debt over the risk-free rate in the valuation estimate. The ending balance in OCI includes a loss of $3.3 million pre-tax and $2.2 million after tax, related to the interest rate swaps previously designated as a cash flow hedge. The OCI balance relates to the loss that was recorded when the cash flow hedge was previously de-designated. Currently, all changes in market value are recorded in earnings instead of OCI.
A hypothetical 10% increase or decrease in interest rates would change the fair value of Puget Energy's interest rate swaps by $1.1 million.
The following table presents Puget Energy's interest rate swaps:
Puget Energy
(Dollars in Thousands)
March 31, 2013
December 31, 2012
 
Liabilities
Liabilities
Interest rate swaps:
 
 
Current
$
6,545

$
6,571

Long-term
13,421

14,953

Total interest rate swaps
$
19,966

$
21,524


From time to time, PSE may enter into treasury locks or forward starting swap contracts to hedge interest rate exposure related to an anticipated debt issuance. The ending balance in OCI related to the forward starting swaps and previously settled treasury lock contracts at March 31, 2013 was a net loss of $6.5 million after tax and accumulated amortization. This compares to an after-tax loss of $6.6 million in OCI as of December 31, 2012. All financial hedge contracts of this type are reviewed by an officer, presented to the Board of Directors or a committee of the Board, as applicable, and are approved prior to execution. PSE had no treasury locks or forward starting swap contracts outstanding at March 31, 2013.


Item 4.                      Controls and Procedures

Puget Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of Puget Energy’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, Puget Energy has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of March 31, 2013, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting
There have been no changes in Puget Energy’s internal control over financial reporting during the three months ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Puget Sound Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of March 31, 2013, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting
There have been no changes in PSE’s internal control over financial reporting during the three months ended March 31, 2013 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.


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PART II                    OTHER INFORMATION


Item 1.                      Legal Proceedings

For details on legal proceedings, see the Litigation footnote in the notes to the consolidated financial statements of this Quarterly Report on Form 10-Q.  Contingencies arising out of the normal course of PSE’s business existed as of March 31, 2013.  Litigation is subject to numerous uncertainties and PSE is unable to predict the ultimate outcome of these matters.


Item 1A.                  Risk Factors

There have been no material changes from the risk factors set forth in Part I, Item 1A in Puget Energy’s and PSE’s Form 10-K for the period ended December 31, 2012.


Item 6.                      Exhibits

Included in the Exhibit Index are a list of exhibits filed as part of this Quarterly Report on Form 10-Q.


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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

 
 
PUGET ENERGY, INC.
PUGET SOUND ENERGY, INC.
 
 
 
/s/ Michael J. Stranik
 
 
Michael J. Stranik
Controller and Principal Accounting Officer
Date:  
May 7, 2013
Officer duly authorized to sign this report on behalf of each registrant



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EXHIBIT INDEX

12.1*
Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2008 through 2012 and 12 months ended March 31, 2013).
12.2*
Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2008 through 2012 and 12 months ended March 31, 2013).
31.1*
Chief Executive Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
Principal Financial Officer certification of Puget Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.3*
Chief Executive Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.4*
Principal Financial Officer certification of Puget Sound Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*
Chief Executive Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
Principal Financial Officer certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101**
Financial statements from the quarterly report on Form 10-Q of Puget Energy, Inc. and Puget Sound Energy, Inc. for the quarter ended March 31, 2013, filed on May 7, 2013 formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iii) the Consolidated Statements of Cash Flows (Unaudited), and (iv) the Notes to Consolidated Financial Statements (submitted electronically herewith).
__________________
* Filed herewith.
** In accordance with Rule 406T of Regulation S-T, the XBRL information in Exhibit 101 to this quarterly report on Form 10-Q shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (Exchange Act), or otherwise subject to the liability of that section, and shall not be incorporated by reference into any registration statement or other document filed under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.


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