PE-2013.6.30-10Q

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 June 30, 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 and Six Months Ended June 30, 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
Inability to manage costs during the rate stay out period through March 31, 2016, due to unforeseen events which would cause increases in costs of operations;
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
June 30,
Six Months Ended
June 30,
 
2013
2012
2013
2012
Operating revenue:
 
 
 
 
Electric
$
461,657

$
470,511

$
1,076,291

$
1,082,038

Gas
180,728

207,823

565,493

643,789

Other
101

283

520

1,302

Total operating revenue
642,486

678,617

1,642,304

1,727,129

Operating expenses:
 

 

 

 

Energy costs:
 

 

 

 

Purchased electricity
112,543

156,098

287,587

355,213

Electric generation fuel
40,737

19,861

99,823

89,798

Residential exchange
(14,963
)
(15,302
)
(37,515
)
(38,637
)
Purchased gas
79,487

96,462

269,470

329,981

Unrealized (gain) loss on derivative instruments, net
27,376

(64,076
)
(48,316
)
(59,350
)
Utility operations and maintenance
130,286

128,195

259,521

256,241

Non-utility expense and other
(959
)
(74
)
(1,953
)
787

Depreciation
90,301

84,552

178,480

163,558

Amortization
6,433

11,547

12,177

24,890

Conservation amortization
22,469

28,518

56,576

62,921

Taxes other than income taxes
53,695

72,960

153,638

172,830

Total operating expenses
547,405

518,741

1,229,488

1,358,232

Operating income
95,081

159,876

412,816

368,897

Other income (deductions):
 

 

 

 

Other income
10,844

18,337

22,857

33,273

Other expense
(1,454
)
(1,947
)
(2,996
)
(5,700
)
Non-hedging interest rate derivative (expense) income
1,232

(7,297
)
2,260

(6,770
)
Interest charges:
 

 

 

 

AFUDC
3,162

4,687

7,810

11,982

Interest expense
(108,917
)
(95,964
)
(204,733
)
(203,165
)
Income (loss) before income taxes
(52
)
77,692

238,014

198,517

Income tax (benefit) expense
(957
)
20,000

69,634

52,346

Net income (loss)
$
905

$
57,692

$
168,380

$
146,171


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
June 30,
Six Months Ended
June 30,
 
2013
2012
2013
2012
Net income (loss)
$
905

$
57,692

$
168,380

$
146,171

Other comprehensive income (loss):
 

 

 

 

Reclassification of net unrealized (gain) loss on interest rate swaps during the period, net of tax of $464, $3,817, $924 and $5,167, respectively
861

7,088

1,715

9,596

Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(596), $(56), $(409) and $(112), respectively
(1,107
)
(104
)
(760
)
(209
)
Reclassification of net unrealized (gain) loss on energy derivative instruments settled during the period, net of tax of $0, $66, $(57) and $(39), respectively
—

122

(107
)
(73
)
Other comprehensive income (loss)
(246
)
7,106

848

9,314

Comprehensive income (loss)
$
659

$
64,798

$
169,228

$
155,485


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

6

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


ASSETS
 
(Unaudited)
 
 
June 30,
2013
December 31,
2012
Utility plant (at original cost, including construction work in progress of $579,405 and
$766,035, respectively):
 
 
Electric plant
$
6,924,356

$
6,750,400

Gas plant
2,459,063

2,385,784

Common plant
497,169

487,931

Less: Accumulated depreciation and amortization
(1,228,030
)
(1,067,424
)
Net utility plant
8,652,558

8,556,691

Other property and investments:
 

 

Goodwill
1,656,513

1,656,513

Other property and investments
104,676

112,367

Total other property and investments
1,761,189

1,768,880

Current assets:
 

 

Cash and cash equivalents
27,604

135,542

Restricted cash
4,723

3,700

Accounts receivable, net of allowance for doubtful accounts of $6,299 and $9,932,
respectively
265,022

321,480

Unbilled revenue
124,617

204,359

Materials and supplies, at average cost
84,537

82,353

Fuel and gas inventory, at average cost
77,248

88,953

Unrealized gain on derivative instruments
10,026

6,869

Income taxes
1

4,796

Prepaid expense and other
20,846

13,571

Power contract acquisition adjustment gain
49,746

50,785

Deferred income taxes
30,823

53,437

Total current assets
695,193

965,845

Other long-term and regulatory assets:
 

 

Regulatory asset for deferred income taxes
135,269

119,844

Power cost adjustment mechanism
—

3,773

Regulatory assets related to power contracts
35,177

37,655

Other regulatory assets
793,884

815,785

Unrealized gain on derivative instruments
6,865

14,814

Power contract acquisition adjustment gain
419,488

456,225

Other
92,497

95,763

Total other long-term and regulatory assets
1,483,180

1,543,859

Total assets
$
12,592,120

$
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)
 
 
June 30,
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
291,871

208,100

Accumulated other comprehensive income (loss), net of tax
(31,981
)
(32,829
)
Total common shareholder’s equity
3,568,847

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
1,779,000

1,834,000

Debt discount and other
(235,339
)
(264,072
)
Total long-term debt
5,306,933

5,333,200

Total capitalization
8,875,780

8,817,428

Current liabilities:
 

 

Accounts payable
229,045

321,755

Short-term debt
—

181,000

Current maturities of long-term debt
13,000

13,000

Purchased gas adjustment liability
14,509

32,587

Accrued expenses:
 

 

  Taxes
84,034

95,623

  Salaries and wages
32,113

38,438

  Interest
77,913

82,262

Unrealized loss on derivative instruments
115,038

177,519

Power contract acquisition adjustment loss
3,865

3,902

Other
79,483

72,799

Total current liabilities
649,000

1,018,885

Long-term and regulatory liabilities:
 

 

Deferred income taxes
1,324,539

1,261,636

Unrealized loss on derivative instruments
59,392

83,276

Power cost adjustment mechanism
5,726

—

Regulatory liabilities
650,665

600,697

Regulatory liabilities related to power contracts
469,234

507,009

Power contract acquisition adjustment loss
31,311

33,753

Other deferred credits
526,473

512,591

Total long-term and regulatory liabilities
3,067,340

2,998,962

Commitments and contingencies




Total capitalization and liabilities
$
12,592,120

$
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)
 
Six Months Ended
June 30,
 
2013
2012
Operating activities:
 
 
Net income (loss)
$
168,380

$
146,171

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

 

Depreciation
178,480

163,558

Amortization
12,177

24,890

Conservation amortization
56,576

62,921

Deferred income taxes and tax credits, net
69,635

52,657

Net unrealized (gain) loss on derivative instruments
(53,496
)
(76,850
)
Funding of pension liability
(10,200
)
(11,400
)
Derivative contracts classified as financing activities due to merger
26,013

47,423

AFUDC – Equity
(11,222
)
(14,485
)
Regulatory assets
(66,102
)
(110,088
)
Regulatory liabilities
10,341

37,752

Other long-term assets
10,842

7,302

Other long-term liabilities
54,837

45,284

Change in certain current assets and liabilities:
 

 

Accounts receivable and unbilled revenue
136,457

174,353

Materials and supplies
(2,184
)
(13,722
)
Fuel and gas inventory
11,104

31,138

Income taxes
4,795

1,892

Prepayments and other
(7,340
)
(4,190
)
Purchased gas adjustment
(18,078
)
23,671

Accounts payable
(74,666
)
(86,438
)
Taxes payable
(11,589
)
(10,835
)
Accrued expenses and other
(15,507
)
6,621

Net cash provided by operating activities
469,253

497,625

Investing activities:
 

 

Construction expenditures – excluding equity AFUDC
(326,082
)
(398,900
)
Proceeds from disposition of assets
108,166

—

Restricted cash
(1,023
)
639

Other
(5,119
)
(28,410
)
Net cash used in investing activities
(224,058
)
(426,671
)
Financing activities:
 

 

Change in short-term debt and leases, net
(184,789
)
9,211

Dividends paid
(84,609
)
(88,444
)
Long-term notes and bonds issued
161,860

1,314,000

Redemption of bonds and notes
(216,860
)
(1,273,000
)
Derivative contracts classified as financing activities due to merger
(26,013
)
(47,423
)
Issuance cost of bonds and other
(2,722
)
(6,400
)
Net cash provided by (used in) financing activities
(353,133
)
(92,056
)
Net increase (decrease) in cash and cash equivalents
(107,938
)
(21,102
)
Cash and cash equivalents at beginning of period
135,542

37,235

Cash and cash equivalents at end of period
$
27,604

$
16,133

Supplemental cash flow information:
 

 

Cash payments for interest (net of capitalized interest)
$
162,588

$
170,262

Cash payments (refunds) for income taxes
(4,500
)
(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
June 30,
Six Months Ended
June 30,
 
2013
2012
2013
2012
Operating revenue:
 
 
 
 
Electric
$
461,657

$
470,511

$
1,076,291

$
1,082,038

Gas
180,728

207,823

565,493

643,789

Other
101

283

409

1,302

Total operating revenue
642,486

678,617

1,642,193

1,727,129

Operating expenses:
 

 

 

 

Energy costs:
 

 

 

 

Purchased electricity
112,543

156,098

287,587

355,213

Electric generation fuel
40,737

19,861

99,823

89,798

Residential exchange
(14,963
)
(15,302
)
(37,515
)
(38,637
)
Purchased gas
79,487

96,462

269,470

329,981

Unrealized (gain) loss on derivative instruments, net
27,376

(59,850
)
(45,365
)
(49,715
)
Utility operations and maintenance
130,286

128,195

259,521

256,241

Non-utility expense and other
3,028

2,270

6,120

5,500

Depreciation
90,301

84,552

178,480

163,558

Amortization
6,433

11,547

12,177

24,890

Conservation amortization
22,469

28,518

56,576

62,921

Taxes other than income taxes
53,695

72,960

153,638

172,830

Total operating expenses
551,392

525,311

1,240,512

1,372,580

Operating income (loss)
91,094

153,306

401,681

354,549

Other income (deductions):
 

 

 

 

Other income
10,846

18,329

22,857

33,262

Other expense
(1,454
)
(1,947
)
(2,996
)
(5,700
)
Interest charges:
 

 

 

 

AFUDC
3,162

4,687

7,810

11,982

Interest expense
(65,773
)
(62,333
)
(131,749
)
(123,071
)
Interest expense on parent note
(32
)
(83
)
(61
)
(133
)
Income (loss) before income taxes
37,843

111,959

297,542

270,889

Income tax (benefit) expense
11,180

31,087

90,941

77,301

Net income (loss)
$
26,663

$
80,872

$
206,601

$
193,588


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
June 30,
Six Months Ended
June 30,
 
2013
2012
2013
2012
Net income (loss)
$
26,663

$
80,872

$
206,601

$
193,588

Other comprehensive income (loss):
 

 

 

 

Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,011, $661, $2,835 and $1,962, respectively
1,879

1,227

5,265

3,643

Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $1,545, $975 and $2,580, respectively
—

2,869

1,811

4,791

Amortization of treasury interest rate swaps to earnings, net of tax of $43, $43, $85 and $85, respectively
79

79

158

159

Other comprehensive income (loss)
1,958

4,175

7,234

8,593

Comprehensive income (loss)
$
28,621

$
85,047

$
213,835

$
202,181


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

10

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


ASSETS
 
(Unaudited)
 
 
June 30,
2013
December 31,
2012
Utility plant (at original cost, including construction work in progress of $579,405 and
$766,035, respectively):
 
 
Electric plant
$
9,164,460

$
9,048,356

Gas plant
3,068,902

2,998,188

Common plant
558,231

555,549

Less:  Accumulated depreciation and amortization
(4,139,035
)
(4,045,402
)
Net utility plant
8,652,558

8,556,691

Other property and investments:
 

 

Other property and investments
95,845

103,646

Total other property and investments
95,845

103,646

Current assets:
 

 

Cash and cash equivalents
27,463

135,530

Restricted cash
4,723

3,700

Accounts receivable, net of allowance for doubtful accounts of $6,299 and $9,932,
respectively
271,067

321,685

Unbilled revenue
124,617

204,359

Materials and supplies, at average cost
84,537

82,353

Fuel and gas inventory, at average cost
74,443

85,547

Unrealized gain on derivative instruments
10,026

6,869

Income taxes
1

4,796

Prepaid expense and other
20,753

13,413

Deferred income taxes
45,419

68,015

Total current assets
663,049

926,267

Other long-term and regulatory assets:
 

 

Regulatory asset for deferred income taxes
134,741

119,279

Power cost adjustment mechanism
—

3,773

Other regulatory assets
792,839

813,171

Unrealized gain on derivative instruments
6,865

14,814

Other
83,553

90,330

Total other long-term and regulatory assets
1,017,998

1,041,367

Total assets
$
10,429,450

$
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)
 
 
June 30,
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
362,815

344,280

Accumulated other comprehensive income (loss), net of tax
(179,964
)
(187,198
)
Total common shareholder’s equity
3,429,915

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
7,193,173

7,167,404

Current liabilities:
 

 

Accounts payable
235,090

321,953

Short-term debt
—

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
14,509

32,587

Accrued expenses:
 

 

Taxes
84,034

95,623

Salaries and wages
32,113

38,438

Interest
53,867

55,806

       Unrealized loss on derivative instruments
108,520

170,948

       Other
72,392

69,881

Total current liabilities
643,123

1,008,834

Long-term and regulatory liabilities:
 

 

Deferred income taxes
1,362,304

1,274,602

Unrealized loss on derivative instruments
52,205

68,323

Power cost adjustment mechanism
5,726

—

Regulatory liabilities
647,335

596,324

Other deferred credits
525,584

512,484

Total long-term and regulatory liabilities
2,593,154

2,451,733

Commitments and contingencies




Total capitalization and liabilities
$
10,429,450

$
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)
 
Six Months Ended
June 30,
 
2013
2012
Operating activities:
 
 
Net income (loss)
$
206,601

$
193,588

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

 

Depreciation
178,480

163,558

Amortization
12,177

24,890

Conservation amortization
56,576

62,921

Deferred income taxes and tax credits, net
90,940

77,611

Net unrealized (gain) loss on derivative instruments
(45,365
)
(49,715
)
Funding of pension liability
(10,200
)
(11,400
)
AFUDC – Equity
(11,222
)
(14,485
)
Regulatory assets
(66,102
)
(110,088
)
Regulatory liabilities
10,341

37,752

Other long-term assets
14,921

10,875

Other long-term liabilities
33,285

31,394

Change in certain current assets and liabilities:
 

 

Accounts receivable and unbilled revenue
130,617

174,193

Materials and supplies
(2,184
)
(13,722
)
Fuel and gas inventory
11,104

31,138

Income taxes
4,795

1,892

Prepayments and other
(7,340
)
(4,190
)
Purchased gas adjustment
(18,078
)
23,671

Accounts payable
(68,819
)
(86,555
)
Taxes payable
(11,589
)
(10,835
)
Accrued expenses and other
(17,586
)
(14,296
)
Net cash provided by operating activities
491,352

518,197

Investing activities:
 

 

Construction expenditures – excluding equity AFUDC
(326,082
)
(398,900
)
Proceeds from disposition of assets
108,166

—

Restricted cash
(1,023
)
639

Other
(4,902
)
(7,635
)
Net cash used in investing activities
(223,841
)
(405,896
)
Financing activities:
 

 

Change in short-term debt and leases, net
(184,789
)
9,211

Dividends paid
(188,064
)
(137,329
)
Long-term notes and bonds issued
161,860

—

Redemption of bonds and notes
(161,860
)
—

Issuance cost of bonds and other
(2,725
)
(563
)
Net cash provided by (used in) financing activities
(375,578
)
(128,681
)
Net increase (decrease) in cash and cash equivalents
(108,067
)
(16,380
)
Cash and cash equivalents at beginning of period
135,530

31,010

Cash and cash equivalents at end of period
$
27,463

$
14,630

Supplemental cash flow information:
 

 

Cash payments for interest (net of capitalized interest)
$
122,892

$
106,823

Cash payments (refunds) for income taxes
(4,500
)
(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. PSE's unbilled revenue uses meter readings from its automated meter reading (AMR) system. The 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 $51.5 million and $128.4 million for the three and six months ended June 30, 2013, respectively, and $53.7 million and $134.7 million for the three and six months ended June 30, 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.
Beginning July 1, 2013, PSE's electric and gas operations contain a revenue decoupling mechanism under which PSE's actual energy delivery revenues related to electric transmission and distribution, gas operations and general administrative costs are compared with authorized revenues allowed under the mechanism. Any differences are deferred to a regulatory asset for under recovery or regulatory liability for over recovery. Revenues associated with power costs under the PCA mechanism and PGA rates are excluded from the decoupling mechanism.

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.
The Company revised its Consolidated Statement of Cash Flows due to an immaterial error. Revisions were made in the second quarter ended June 30, 2013 on the Company's Consolidated Statement of Cash Flows to reflect energy efficiency expenditures as operating cash outflows instead of investing cash outflows. The Company determined energy efficiency expenditures should have been classified as operating activities instead of investing activities. These revisions decreased net cash provided by operating activities and decreased net cash used by investing activities. The revision does not affect the net change in cash and cash equivalents for any of the periods, and has no effect on the Company's Consolidated Statements of Income,

14

Consolidated Statements of Comprehensive Income, Consolidated Balance Sheets, and Consolidated Statement of Common Shareholder's Equity. The Company has evaluated the effects of these errors and concluded that none of them are material to any of the Company's previously issued quarterly or annual Financial Statements. Nevertheless, the Company has elected to revise the Consolidated Statement of Cash Flows in this report to correct for the effect of these errors and properly reflect the revised values.
 
The amounts on prior period Consolidated Statements of Cash Flows that have been revised are summarized below:
 
 
As Reported
As Revised
Puget Energy
Three Months Ended
March 31,
Year Ended December 31,
Three Months Ended
March 31,
Year Ended December 31,
(Dollars in Thousands)
2013
2012
2011
2010
2013
2012
2011
2010
Operating Activities:
 
 
 
 
 
 
 
 
Regulatory Assets
$
(6,411
)
$
(64,368
)
$
30,232

$
26,198

$
(28,953
)
$
(170,374
)
$
(64,173
)
$
(69,528
)
Net Cash Provided by Operating Activities
$
323,807

$
888,691

$
1,010,328

$
865,949

$
301,265

$
782,685

$
915,923

$
770,223

Investing Activities:
 
 
 
 
 
 
 
 
Energy Efficiency Expenditures
$
(22,542
)
$
(106,006
)
$
(94,405
)
$
(95,726
)
$
—

$
—

$
—

$
—

Net Cash Used in Investing Activities
$
(86,362
)
$
(798,976
)
$
(1,076,815
)
$
(905,767
)
$
(63,820
)
$
(692,970
)
$
(982,410
)
$
(810,041
)


 
 
As Reported
As Revised
Puget Sound Energy
Three Months Ended
March 31,
Year Ended December 31,
Three Months Ended
March 31,
Year Ended December 31,
(Dollars in Thousands)
2013
2012
2011
2010
2013
2012
2011
2010
Operating Activities:
 
 
 
 
 
 
 
 
Regulatory Assets
$
(6,411
)
$
(64,368
)
$
29,271

$
26,198

$
(28,953
)
$
(170,374
)
$
(65,134
)
$
(69,528
)
Net Cash Provided by Operating Activities
$
332,243

$
903,888

$
903,422

$
575,775

$
309,701

$
797,882

$
809,017

$
480,049

Investing Activities:
 
 
 
 
 
 
 
 
Energy Efficiency Expenditures
$
(22,542
)
$
(106,006
)
$
(94,405
)
$
(95,726
)
$
—

$
—

$
—

$
—

Net Cash Used in Investing Activities
$
(86,298
)
$
(778,075
)
$
(1,060,588
)
$
(905,767
)
$
(63,756
)
$
(672,069
)
$
(966,183
)
$
(810,041
)



15

 
As Reported
As Revised
Puget Energy
Three Months Ended
March 31,
Six Months Ended
June 30,
Nine Months Ended September 30,
Three Months Ended
March 31,
Six Months Ended
June 30,
Nine Months Ended September 30,
(Dollars in Thousands)
2012
2012
2012
2012
2012
2012
Operating Activities:
 
 
 
 
 
 
Regulatory Assets
$
(48,185
)
$
(61,856
)
$
(60,434
)
$
(70,842
)
$
(110,088
)
$
(130,536
)
Net Cash Provided by Operating Activities
$
273,604

$
545,857

$
696,242

$
250,947

$
497,625

$
626,140

Investing Activities:
 
 
 
 
 
 
Energy Efficiency Expenditures
$
(22,657
)
$
(48,232
)
$
(70,103
)
$
—

$
—

$
—

Net Cash Used in Investing Activities
$
(225,955
)
$
(474,903
)
$
(673,248
)
$
(203,298
)
$
(426,671
)
$
(603,145
)


 
As Reported
As Revised
Puget Sound Energy
Three Months Ended
March 31,
Six Months Ended
June 30,
Nine Months Ended September 30,
Three Months Ended
March 31,
Six Months Ended
June 30,
Nine Months Ended September 30,
(Dollars in Thousands)
2012
2012
2012
2012
2012
2012
Operating Activities:
 
 
 
 
 
 
Regulatory Assets
$
(48,185
)
$
(61,856
)
$
(60,434
)
$
(70,842
)
(110,088
)
$
(130,536
)
Net Cash Provided by Operating Activities
$
261,229

$
566,429

$
717,894

$
238,572

$
518,197

$
647,792

Investing Activities:
 
 
 
 
 
 
Energy Efficiency Expenditures
$
(22,657
)
$
(48,232
)
$
(70,103
)
$
—

$
—

$
—

Net Cash Used in Investing Activities
$
(211,766
)
$
(454,128
)
$
(652,411
)
$
(189,109
)
$
(405,896
)
$
(582,308
)


(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.
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

16

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 forward physical and financial agreements, floating-for-fixed swap contracts, and commodity call/put options, which are appropriate for the service territory of PSE and are relevant to its regulated electric and natural gas portfolios. 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. Beginning June 2013, PSE began trading natural gas call and put options. Utilizing options as an additional hedging instrument increases the hedging portfolio's flexibility to react to commodity price fluctuations, as well as creates a commodity price cap for customers, thus protecting rate payers against future price increases.
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 out three years.
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 June 30, 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.

17

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
June 30, 2013
December 31, 2012
(Dollars in Thousands)
Volumes
Assets 1
Liabilities 2

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

$
13,706

$450 million
$
—

$
21,524

Electric portfolio derivatives
*
10,474

83,957

*
9,557

131,193

Natural gas derivatives (MMBtus) 4
459,420,774
6,417

76,767

516,909,006
12,126

108,078

Total derivative contracts
 
$
16,891

$
174,430

 
$
21,683

$
260,795

 
 
 
 
 
 
 
Current
 
$
10,026

$
115,038

 
$
6,869

$
177,519

Long-term
 
6,865

59,392

 
14,814

83,276

Total derivative contracts
 
$
16,891

$
174,430

 
$
21,683

$
260,795

___________
* 
Electric portfolio derivatives consist of electric generation fuel of 143,999,235 MMBtus and purchased electricity of 7,797,825 MWhs at June 30, 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 $70.4 million at June 30, 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.


18

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. 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. 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 June 30, 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
$
16,891

$
—

$
16,891

$
(10,434
)
$
—

$
6,457

Liabilities
 
 
 
 
 
 
Energy Derivative Contracts
$
160,725

$
—

$
160,725

$
(10,434
)
$
—

$
150,291

Interest Rate Swaps 2
$
13,706

$
—

$
13,706

$
—

$
—

$
13,706

 
 
 
 
 
 
 
 
 
 
 
 
 
 
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.




19

The following tables present the effect and locations of the Company's derivatives not designated as hedging instruments, recorded on the statements of income:

Puget Energy
 
Three Months Ended
June 30,
Six Months Ended
June 30,
(Dollars in Thousands)
Location
2013
2012
2013
2012
Interest rate contracts:
Other deductions
$
1,232

$
(7,297
)
$
2,260

$
(6,770
)
 
Interest expense
1,902

(9,902
)
(676
)
(19,264
)
Commodity contracts:
 
 
 

 
 
Electric derivatives
Unrealized gain (loss) on derivative instruments, net 1
(27,376
)
64,076

48,316

57,199

 
Electric generation fuel
(930
)
(2,981
)
(13,568
)
(25,974
)
 
Purchased electricity
(3,704
)
(39,540
)
(35,189
)
(84,953
)
Total gain (loss) recognized in income on derivatives
 
$
(28,876
)
$
4,356

$
1,143

$
(79,762
)
___________
1 
The six months ended June 30, 2012, differs from the amount 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
June 30,
Six Months Ended
June 30,
(Dollars in Thousands)
Location
2013
2012
2013
2012
Commodity contracts:
 
 
 
 
 
Electric derivatives
Unrealized gain (loss) on derivative instruments, net
$
(27,376
)
$
59,850

$
45,365

$
49,715

 
Electric generation fuel
(930
)
(2,981
)
(13,568
)
(25,974
)
 
Purchased electricity
(3,704
)
(39,540
)
(35,189
)
(84,953
)
Total gain (loss) recognized in income on derivatives
 
$
(32,010
)
$
17,329

$
(3,392
)
$
(61,212
)

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 $2.8 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 six months ending June 30, 2013 and 2012, cash outflows related to financing activities of $26.0 million and $47.4 million, respectively, were reported on the Puget Energy statement of cash flows.


20

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
June 30,
Six Months Ended
June 30,
(Dollars in Thousands)
Location
2013
2012
2013
2012
Interest rate contracts:
Interest expense
$
(1,325
)
$
(10,905
)
$
(2,639
)
$
(14,763
)
Commodity contracts:
 
 
 
 
 
Electric derivatives
Electric generation fuel
—

—

—

100

 
Purchased electricity
—

(188
)
164

12

Total
 
$
(1,325
)
$
(11,093
)
$
(2,475
)
$
(14,651
)
    
Puget Sound Energy
 
Three Months Ended
June 30,
Six Months Ended
June 30,
(Dollars in Thousands)
Location
2013
2012
2013
2012
Interest rate contracts:
Interest expense
$
(122
)
$
(122
)
$
(244
)
$
(244
)
Commodity contracts:
 
 
 
 
 
Electric derivatives
Electric generation fuel
—

(4,414
)
—

97

 
Purchased electricity
—

—

(2,786
)
(7,468
)
Total
 
$
(122
)
$
(4,536
)
$
(3,030
)
$
(7,615
)

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 June 30, 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 June 30, 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 June 30, 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

21

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 June 30, 2013:

Puget Energy and Puget Sound Energy
Contingent Feature
(Dollars in Thousands)
Fair Value 1
Liability
Posted
Collateral
Contingent
Collateral
Credit rating 2
$
(26,147
)
$
—

$
26,147

Requested credit for adequate assurance
(26,762
)
—

—

Forward value of contract 3
(710
)
—

—

Total
$
(53,619
)
$
—

$
26,147

__________
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. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves; contract terms and prices; credit-risk adjustments; and for options, the Black-Scholes option valuation model, implied market volatility and discount factors. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs because substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. 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 of our commodity contracts. Some of the inputs, which are less 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

22

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 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.
 
Carrying / Fair Value
Carrying / Fair Value
Puget Energy
At June 30, 2013
At December 31, 2012
(Dollars in Thousands)
Level 1
Level 2
     Total
Level 1
Level 2
     Total
Assets:
 
 
 
 
 
 
Cash and Cash Equivalents
$
12,000

$
15,604

$
27,604

$
105,000

$
30,542

$
135,542

Restricted Cash
2,405

2,318

4,723

914

2,786

3,700

Notes Receivable and Other
—

55,985

55,985

—

63,802

63,802

Total assets
$
14,405

$
73,907

$
88,312

$
105,914

$
97,130

$
203,044

Liabilities:
 
 
 
 
 
 
Short Term Debt
$
—

$
—

$
—

$
181,000

$
—

$
181,000

Total liabilities
$
—

$
—

$
—

$
181,000

$
—

$
181,000


 
Carrying / Fair Value
Carrying / Fair Value
Puget Sound Energy
At June 30, 2013
At December 31, 2012
(Dollars in Thousands)
Level 1
Level 2
     Total
Level 1
Level 2
     Total
Assets:
 
 
 
 
 
 
Cash and Cash Equivalents
$
12,000

$
15,463

$
27,463

$
105,000

$
30,530

$
135,530

Restricted Cash
2,405

2,318

4,723

914

2,786

3,700

Notes Receivable and Other
—

55,985

55,985

—

63,802

63,802

Total assets
$
14,405

$
73,766

$
88,171

$
105,914

$
97,118

$
203,032

Liabilities:
 
 
 
 
 
 
Short Term Debt
$
—

$
—

$
—

$
181,000

$
—

$
181,000

Short Term Debt owed to parent
—

29,598

29,598

—

29,598

29,598

Total liabilities
$
—

$
29,598

$
29,598

$
181,000

$
29,598

$
210,598




23

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
 
June 30, 2013
December 31, 2012
(Dollars in Thousands)
Level
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Liabilities:
 
 
 
 
 
Junior subordinated notes
2
$
250,000

$
260,160

$
250,000

$
264,842

Long-term debt (fixed-rate), net of discount
2
4,690,933

5,627,648

4,662,200

6,197,179

Long-term debt (variable-rate), net of discount
2
379,000

379,000

434,000

434,000

     Total
 
$
5,319,933

$
6,266,808

$
5,346,200

$
6,896,021

 
 
 
 
 
 
Puget Sound Energy
 
June 30, 2013
December 31, 2012
(Dollars in Thousands)
Level
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Liabilities:
 
 
 
 
 
Junior subordinated notes
2
$
250,000

$
260,160

$
250,000

$
264,842

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

4,114,365

3,526,258

4,628,509

     Total
 
$
3,776,258

$
4,374,525

$
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 and six months ended June 30, 2013 and 2012.

Puget Energy
Fair Value
Fair Value
At June 30, 2013
At December 31, 2012
(Dollars in Thousands)
Level 2
Level 3
Total
Level 2
Level 3
Total
Interest rate derivative instruments
$
13,706

$
—

$
13,706

$
21,524

$
—

$
21,524

Total derivative liabilities
$
13,706

$
—

$
13,706

$
21,524

$
—

$
21,524


Puget Energy and
Fair Value
Fair Value
Puget Sound Energy
At June 30, 2013
At December 31, 2012
(Dollars in Thousands)
Level 2
Level 3
Total
Level 2
Level 3
Total
Assets:
 
 
 
 
 
 
Electric derivative instruments
$
3,621

$
6,853

$
10,474

$
1,259

$
8,298

$
9,557

Natural gas derivative instruments
2,708

3,708

6,416

6,769

5,357

12,126

Total assets
$
6,329

$
10,561

$
16,890

$
8,028

$
13,655

$
21,683

Liabilities:
 

 

 

 

 

 

Electric derivative instruments
$
40,205

$
43,752

$
83,957

$
88,971

$
42,221

$
131,192

Natural gas derivative instruments
70,186

6,581

76,767

101,119

6,960

108,079

Total liabilities
$
110,391

$
50,333

$
160,724

$
190,090

$
49,181

$
239,271



24

 
Puget Energy and
Puget Sound Energy
Three Months Ended
June 30,
 
Level 3 Roll-Forward Net (Liability)
2013
2012
 
(Dollars in Thousands)
Electric
Gas
Total
Electric
Gas
Total
 
Balance at beginning of period
$
(26,442
)
$
(1,534
)
$
(27,976
)
$
(107,364
)
$
(3,167
)
$
(110,531
)
 
Changes during period
 
 
 
 
 
 
 
Realized and unrealized energy derivatives:
 
 
 
 
 
 
 
Included in earnings 1
(12,799
)
—

(12,799
)
5,077

—

5,077

 
Included in regulatory assets / liabilities
—

(684
)
(684
)
—

(4
)
(4
)
 
Settlements 3
2,678

(495
)
2,183

14,372

324

14,696

 
Transferred into Level 3
(830
)
—

(830
)
(38,674
)
(297
)
(38,971
)
 
Transferred out of Level 3
494

(160
)
334

46,136

325

46,461

 
Balance at end of period
$
(36,899
)
$
(2,873
)
$
(39,772
)
$
(80,453
)
$
(2,819
)
$
(83,272
)
 
 
 
 
 
Puget Energy and
Puget Sound Energy
Six Months Ended
June 30,
 
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 2
(11,201
)
—

(11,201
)
(16,870
)
—

(16,870
)
 
Included in regulatory assets / liabilities
—

(10
)
(10
)
—

(1,287
)
(1,287
)
 
Settlements 3
9,062

(1,228
)
7,834

35,415

105

35,520

 
Transferred into Level 3
(8,530
)
—

(8,530
)
(55,548
)
(297
)
(55,845
)
 
Transferred out of Level 3
7,694

(33
)
7,661

46,861

3,701

50,562

 
Balance at end of period
$
(36,899
)
$
(2,873
)
$
(39,772
)
$
(80,453
)
$
(2,819
)
$
(83,272
)
_________
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 $(15.6) million and $6.2 million for the three months ended June 30, 2013 and 2012, respectively.
2 
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 $(14.2) million and $(12.8) million for the six months ended June 30, 2013 and 2012, respectively.
3 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

25

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 June 30, 2013:
(Dollars in Thousands)
 
 
 
 
 

Fair Value
 
 
Range
 
Derivative Instrument
Assets 1
Liabilities 1
Valuation Technique
Unobservable Input
Low
High
 Weighted Average
Electric
$
6,853

$
43,752

Discounted cash flow
Power Prices
$13.09 per MWh
$44.76 per MWh
$32.46 per MWh
Natural gas
$
3,708

$
6,581

Discounted cash flow
Natural Gas Prices
$2.97 per MMBtu
$4.71 per MMBtu
$3.99 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 June 30, 2013, a hypothetical 10% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative portfolio, classified as Level 3 within the fair value hierarchy, by $24.1 million.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

At the time of merger, Puget Energy recorded the fair value of its intangible assets in accordance with ASC 360, “Property, Plant, and Equipment,” (ASC 360). The fair value assigned to the power contracts was determined using an income approach comparing the contract rate to the market rate for power over the remaining period of the contracts incorporating nonperformance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.
ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in market price.
At June 30, 2013, Puget Energy completed a valuation and impairment test of its purchased power contracts classified as intangible assets. The valuation indicated a fair value of $484.1 million with an impairment to one of the purchased power contracts. As of June 30, 2013, the carrying value for the Priest Rapids Reasonable Portion intangible asset contract was $47.1 million and its fair value on a discounted basis was determined to be an asset of $33.6 million, thereby requiring a write-down of $13.5 million to the intangible asset with a corresponding reduction in the regulatory liability.
The valuation was measured using the income approach. Significant inputs included forward electricity prices and power contract pricing which provided future net cash flow estimates which are classified as Level 3 within the fair value hierarchy. An insignificant input is the discount rate reflective of PSE's cost of capital used in the valuation. Below are significant unobservable inputs used estimating the long-term power purchase contracts' fair value of $484.1 million during the period ended June 30, 2013:
Valuation Technique
Unobservable Input
Low
High
Weighted Average
Discounted cash flow
Power prices
$
30.85
 per MWh
$
65.35
 per MWh
$
48.47
 per MWh
Discounted cash flow
Power contract costs (in thousands)
$
389
 per yr
$
6,845
 per yr
$
4,110
 per yr


(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

26

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 and six months ended June 30, 2013 and 2012:
Puget Energy
 
 
 
Three Months Ended
June 30,
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
$
4,934

$
4,229

$
375

$
268

$
32

$
32

Interest cost
6,182

6,551

511

538

155

188

Expected return on plan assets
(9,696
)
(9,101
)
—

—

(109
)
(109
)
Amortization of prior service
cost
(495
)
(495
)
(4
)
—

—

—

Amortization of net loss
(gain)
794

234

365

176

18

17

Net periodic benefit cost
$
1,719

$
1,418

$
1,247

$
982

$
96

$
128


Puget Energy
 
 
 
Six Months Ended
June 30,
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
$
9,643

$
8,463

$
749

$
537

$
67

$
70

Interest cost
12,377

12,993

1,022

1,076

332

375

Expected return on plan assets
(19,548
)
(18,102
)
—

—

(218
)
(218
)
Amortization of prior service
cost
(990
)
(990
)
(9
)
—

—

—

Amortization of net loss
(gain)
1,444

384

731

351

34

27

Net periodic benefit cost
$
2,926

$
2,748

$
2,493

$
1,964

$
215

$
254


27

Puget Sound Energy
 
 
 
Three Months Ended
June 30,
Qualified
SERP
Other
Pension Benefits
Pension Benefits
Benefits
(Dollars in Thousands)
2013
2012
2013
2012
2013
2012
Components of net periodic benefit cost:
 

 

 

 

 

 

Service cost
$
4,934

$
4,229

$
375

$
268

$
32

$
32

Interest cost
6,182

6,551

511

538

155

188

Expected return on plan assets
(10,094
)
(10,434
)
—

—

(109
)
(109
)
Amortization of prior service
cost
(393
)
(393
)
(4
)
74

8

9

Amortization of net loss
(gain)
5,221

3,790

548

358

(108
)
(63
)
Amortization of transition
obligation
—

—

—

—

—

12

Net periodic benefit cost
$
5,850

$
3,743

$
1,430

$
1,238

$
(22
)
$
69

Puget Sound Energy
 
 
 
Six Months Ended
June 30,
Qualified
SERP
Other
Pension Benefits
Pension Benefits
Benefits
(Dollars in Thousands)
2013
2012
2013
2012
2013
2012
Components of net periodic benefit cost:
 
 
 
 
 
 
Service cost
$
9,643

$
8,463

$
749

$
537

$
67

$
70

Interest cost
12,377

12,993

1,022

1,076

332

375

Expected return on plan assets
(20,343
)
(20,767
)
—

—

(218
)
(218
)
Amortization of prior service
cost
(787
)
(787
)
(8
)
146

14

18

Amortization of net loss
(gain)
10,306

7,508

1,096

716

(142
)
(122
)
Amortization of transition
obligation
—

—

—

—

—

25

Net periodic benefit cost
$
11,196

$
7,410

$
2,859

$
2,475

$
53

$
148




28

The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2013 and December 31, 2012:

Puget Energy and
Puget Sound Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
 
Six Months Ended
Year
Ended
Six Months Ended
Year
Ended
Six Months Ended
Year
Ended
(Dollars in Thousands)
June 30,
2013
December 31,
2012
June 30,
2013
December 31,
2012
June 30,
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
9,642

16,926

749

1,073

67

139

Interest cost
12,377

25,986

1,023

2,152

332

751

Amendment
—

—

—

(122
)
—

—

Actuarial loss/(gain)
3,436

40,914

—

5,483

(1,055
)
1,199

Benefits paid
(23,250
)
(33,533
)
(3,182
)
(5,161
)
(802
)
(1,523
)
Medicare part D subsidiary
received
—

—

—

—

125

670

Benefit obligation at end of period
$
618,495

$
616,290

$
50,385

$
51,795

$
16,339

$
17,672


The fair value of the Company’s qualified pension plan assets was $560.1 million and $531.2 million at June 30, 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 June 30, 2013, the Company contributed $5.1 million, $2.7 million, and $0.3 million to fund the qualified pension plan, SERP and the other postretirement plan, respectively. During the six months ended June 30, 2013, the Company contributed $10.2 million, $3.2 million and $0.7 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. On May 1, 2013, the Washington Commission approved the proposed rates and allowed them to be made permanent. 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 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,

29

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%.
On June 25, 2013, the Washington Commission approved PSE's electric and natural gas decoupling mechanism and expedited rate filing (ERF) tariff filings, effective July 1, 2013. The estimated revenue impact of the decoupling mechanism is an increase for electric of $21.4 million, or 1.0% annually, and an increase for natural gas of $10.8 million, or 1.1% annually. The estimated revenue impact of the ERF filings is an increase for electric of $30.7 million, or 1.5% annually, while the revenue impact for natural gas is a decrease of $2.0 million, or a decrease of 0.2% annually. In its order, the Washington Commission approved a weighted cost of capital of 7.77% and a capital structure that included 48.0% common equity with a return on equity of 9.8%.
On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court seeking judicial review of various aspects of the Washington Commission's ERF and decoupling mechanism final order. The parties petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests that it be vacated and that the matter be remanded to the Washington Commission. PSE is evaluating these petitions and cannot at this time predict the outcomes of these matters.


(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 between July and December 2012.  Discovery in the case has begun, and a prehearing conference took place in July 2013. The case has been bifurcated into separate liability and remedy trials set for October 2014 and August 2015, respectively. PSE is evaluating the allegations set forth in the notices and cannot at this time predict the outcome of this matter.  


30

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 $1.2 million and $3.4 million relating to these claims as of June 30, 2013 and December 31, 2012, respectively.


(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 and six months ended June 30, 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 March 31, 2013
$
(2,168
)
$
(28,718
)
$
(849
)
$
(31,735
)
Other comprehensive income (loss) before reclassifications
—

(1,548
)
—

(1,548
)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax
861

441

—

1,302

Net current-period other comprehensive income (loss)
861

(1,107
)
—

(246
)
Balance at June 30, 2013
$
(1,307
)
$
(29,825
)
$
(849
)
$
(31,981
)
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
—

(1,548
)
—

(1,548
)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax
1,715

788

(107
)
2,396

Net current-period other comprehensive income (loss)
1,715

(760
)
(107
)
848

Balance at June 30, 2013
$
(1,307
)
$
(29,825
)
$
(849
)
$
(31,981
)

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 March 31, 2013
$
(172,612
)
$
(2,765
)
$
(6,545
)
$
(181,922
)
Other comprehensive income (loss) before reclassifications
(1,548
)
—

—

(1,548
)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax
3,427

—

79

3,506

Net current-period other comprehensive income (loss)
1,879

—

79

1,958

Balance at June 30, 2013
$
(170,733
)
$
(2,765
)
$
(6,466
)
$
(179,964
)

31

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
(1,548
)
—

—

(1,548
)
Amounts reclassified from accumulated other comprehensive income (loss), net of tax
6,813

1,811

158

8,782

Net current-period other comprehensive income (loss)
5,265

1,811

158

7,234

Balance at June 30, 2013
$
(170,733
)
$
(2,765
)
$
(6,466
)
$
(179,964
)


Details about these reclassifications out of accumulated other comprehensive income (loss) for the three months ended June 30, 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
$
(1,325
)
Interest expense
 
464

Tax (expense) or benefit
 
$
(861
)
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)
(1,177
)
1 
 
(678
)
Total before tax
 
237

Tax (expense) or benefit
 
$
(441
)
Net of Tax
Net unrealized gain (loss) on energy derivative instruments


 
Commodity contracts: electric derivatives
—

Purchased electricity
 
—

Tax (expense) or benefit
 
$
—

Net of Tax
Total reclassification for the period
$
(1,302
)
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).


32

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)
(5,661
)
1 
 
(5,272
)
Total before tax
 
1,845

Tax (expense) or benefit
 
$
(3,427
)
Net of Tax
Net unrealized gain (loss) on energy derivative instruments
 
 
Commodity contracts: electric derivatives
—

Purchased electricity
 
—

Tax (expense) or benefit
 
$
—

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
$
(3,506
)
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).

Details about these reclassifications out of accumulated other comprehensive income (loss) for the six months ended June 30, 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
$
(2,639
)
Interest expense

924

Tax (expense) or benefit

$
(1,715
)
Net of Tax
Net unrealized gain (loss) and prior service cost on pension plans


 
Amortization of prior service cost
999

1 
Amortization of net gain (loss)
(2,209
)
1 

(1,210
)
Total before tax

422

Tax (expense) or benefit

$
(788
)
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
$
(2,396
)
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).

33

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
$
781

1 
Amortization of net gain (loss)
(11,260
)
1 

(10,479
)
Total before tax

3,666

Tax (expense) or benefit

$
(6,813
)
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
(244
)
Interest expense

86

Tax (expense) or benefit

$
(158
)
Net of Tax
Total reclassification for the period
$
(8,782
)
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).


(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 exceed the transferred assets' net carrying value of $46.4 million resulting in a pre-tax gain of approximately $60.9 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.
Bond Issuances. On May 23, 2013, PSE refinanced $161.9 million of its Pollution Control Revenue Refunding Bonds (the Bonds) to a lower weighted average interest rate from 5.01% to 3.91%. The Bonds will mature on March 1, 2031. On or after March 1, 2023, the Company may elect to call the bonds at a redemption price of 100% of the principal amount thereof, without premium, plus accrued interest, if any, to the redemption date. Due to the refinance of the Bonds, Puget Energy wrote off $18.0 million of fair value related to the Bonds that were redeemed to interest expense. 



34

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 conservation initiatives that promote efficient use of energy. This mandate has traditionally negatively impacted 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 focused on the following initiatives:
•
Expedited Rate Filing (ERF) to reduce the regulatory lag which was approved in June 2013.
•
Decoupling mechanism to allow recovery of costs on electric transmission, distribution, gas operations and general administrative operations on a per-customer basis, rather than on consumption. This was approved in June 2013 and effective on July 1, 2013.
•
Design of 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

35

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 and six months ended June 30, 2013, as compared to the same periods in 2012, PSE's net income was affected primarily by the following factors: (1) changes in unrealized gain and loss in derivatives instruments for energy contracts; (2) an increase in electric margin and a decrease in natural gas margin: (3) implementation of a property tax tracker mechanism which lowered property tax expense; and (4) a decrease in other income due to lower regulatory income.
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 reduces 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
PSE’s ability to manage costs during the rate stay out period through March 31, 2016;
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;
Ÿ
Wholesale commodity prices of electricity and natural gas;
Ÿ
Increasing depreciation; 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 has traditionally required that 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 have not provided 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 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.

Recent Rate Proceedings
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%.
    
Expedited Rate Filing (ERF). On February 4, 2013, PSE filed revised tariffs seeking to update its rates established in general rate proceedings in May 2012. The ERF filing was limited in scope and rate impact. This filing was primarily intended to establish baseline rates on which the decoupling mechanisms are proposed to operate. The ERF established annual adjustment factor (K factor) between now and the next general rate case which will be reflected in the annual decoupling adjustments which are effective

36

January of each year.  The filing also provided for the collection of property taxes through a property tax tracker mechanism based on cash payments of property tax made by PSE during the year. Any difference between the cash payments and property tax valuation accruals will be deferred and recovered in a property tax tracker.

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 proposal. The Washington Commission's regulatory staff (Commission Staff) filed testimony in support of the revised proposal on the same day. Included in the amended decoupling petition was a rate plan that allows 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 PGA mechanism, and emergency rate relief during the rate plan period.
PSE's rates related to the cumulative deferred decoupling mechanism accrued by each rate group through the calendar year and effective May 1 in the following year will be subject to a 3.0% “soft cap” on rate increases. Any difference between the soft cap and the actual amount will be added to the decoupling tracker in subsequent rate periods, subject to a 3.0% soft cap on rate increases in the subsequent year. In addition, PSE and the customers would have shared 50.0% each in any earnings in excess of the authorized rate of return of 7.77%. The customers share of the over earnings will be returned to customers over the subsequent 12 month 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 left PSE with a level of uncertainty such that it could terminate the contract. PSE subsequently filed a Petition for Reconsideration of the order with the Washington Commission.
       
Washington Commission Decision. PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement was intended to settle all issues regarding Expedited Rate Filing (ERF) including a property tax tracker, decoupling and the power purchase agreement with TransAlta Centralia. The Washington Commission placed these filings under a common procedural schedule. On June 25, 2013, the Washington Commission issued three final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration. Order No. 6 rejected the multi-party settlement agreement between PSE, NWEC and Commission Staff due to uncertainty regarding the legality of consolidating the three filings. Order No. 7 approved PSE's ERF filing with a small change to cost to capital from 7.80% to 7.77% to update long term debt cost. This order also approved the property tax tracker discussed above. In addition, Order No. 7 approved the amended decoupling and rate plan filing as filed by PSE and NWEC on March 4, 2013 with the requirement that PSE update the underlying ERF rates for the change in cost of capital, and with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. Order No. 8 granted PSE's Petition for Reconsideration, clarifying certain portions of the Washington Commission's original order.
As currently approved, the ERF filing will produce an additional $30.7 million in annual electric revenue and reduce annual gas revenue by $2.0 million. The property tax rate tracker will initially produce no incremental revenue, but is intended to reduce regulatory lag associated with the recovery of future increases in property tax expenses. PSE's 2012 and 2013 property taxes that are not in current rates will be recovered in later years. The decoupling mechanisms will initially produce an additional $21.4 million in annual electric revenue and $10.8 million in annual gas revenue. The allowed decoupling revenue per customer for the recovery of delivery system costs will subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next general rate case.
Three parties to the ERF and decoupling proceedings have filed Petitions for Reconsideration of Order of No. 7, requesting that the Washington Commission reconsider its decision not to reduce PSE's allowed return on equity and requesting that certain rate schedules used to provide service to larger retail customers be removed from the operation of the decoupling mechanism. The disposition of these petitions is still pending and the Company cannot at this time predict the outcome of this matter.
On July 24, 2013, the Public Counsel Division of the Washington State Attorney General's Office (Public Counsel) and the Industrial Customers of Northwest Utilities (ICNU) each filed a petition in Thurston County Superior Court seeking judicial review of various aspects of the Washington Commission's ERF and decoupling mechanism final order. The parties petition argues that the order violates various procedural and substantive requirements of the Washington Administrative Procedure Act, and so requests

37

that it be vacated and that the matter be remanded to the Washington Commission. PSE is evaluating these petitions and cannot at this time predict the outcomes of these matters.


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 and six months ended June 30, 2013 which was $23.7 million and $39.0 million, respectively, below the “power cost baseline” level, of which $9.5 million was apportioned to customers. This compares to a favorable imbalance for the three and six months ended June 30, 2012 of $26.4 million and $58.0 million, respectively, of which $20.4 million and $26.2 million, respectively, was apportioned to customers.

As discussed above, the Washington Commission approved rate increases related to the recovery of PSE's electric delivery system costs. The following table sets forth the associated electric 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)
Decoupling
July 1, 2013
1.0
%
$
21.4

Expedited Rate Filing
July 1, 2013
1.5

30.7

 
In addition, PSE will be increasing the rates under the ERF filing by 3.0% for electric customers on January 1 of each year until the conclusion of PSE's next general rate case.

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.
As discussed above, the Washington Commission approved rate increases related to the recovery of PSE's gas delivery system costs. The following table sets forth the associated natural gas rate adjustments, including those for the PGA, that were 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)
Decoupling
July 1, 2013
1.1
 %
$
10.8

Expedited Rate Filing
July 1, 2013
(0.2
)
(2.0
)
Purchased Gas Adjustment
November 1, 2012
(7.7
)
(77.0
)
Gas General Rate Case
May 14, 2012
1.3

13.4


In addition, PSE will be increasing the rates under the ERF filing by 2.2% for natural gas customers on January 1 of each year until the conclusion of PSE's next general rate case.


38


Weather Conditions. Weather conditions in PSE's service territory have a significant impact on customer energy usage, affecting PSE's billed 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 and six months ended June 30, 2013, respectively, primarily due to Pacific Northwest temperatures being warmer as compared to the same periods in the prior year. The actual average temperature during the three months ended June 30, 2013 was 57.82 degrees, or 3.47 degrees warmer than the same period in the prior year, and 2.08 degrees warmer when compared to the historical average. The actual average temperature during the six months ended June 30, 2013 was 50.67 degrees, or 2.71 degrees warmer than the same period in the prior year, and 0.78 degrees warmer when compared to the historical average.

Revenue Decoupling. While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's new decoupling mechanisms that went into effect on July 1, 2013 for electric and gas operations will greatly diminish the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and gas operating revenues related to electric transmission and distribution, gas operations and general administrative costs from residential, commercial and industrial customers to eliminate the effects of abnormal weather and changes in usage patterns per customer. As a result, these electric and gas revenues will be recovered on a per customer basis regardless of actual consumption levels. The energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will bill or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers during the following May to April time period.

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”).

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-

39

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.
PSE owns a 25% share of Colstrip Unit 4 coal fired plant in eastern Montana. PSE's share of the unit's net maximum capacity is 185.0 megawatts (MW). On July 1, 2013, Colstrip Unit 4 was tripped off-line.  Upon inspection of the unit, significant damage was observed to the generator which will require repairs to the stator, core and rotor. The unit is expected to return to service in the first quarter of 2014.  PSE's share of the estimated costs of repair, which are capital expenditures, would be in the range of $7.0 million to $8.0 million.  The repair costs for the plant are covered by insurance and are subject to PSE's share of the deductible of $0.6 million.  In addition, power costs are projected to increase approximately $15.6 million based on current market prices for the rest of 2013. The power costs are subject to the PCA mechanism sharing bands, of which PSE's share of costs is estimated to be $7.8 million.
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.


40

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
June 30,
 
Six Months Ended
June 30,
 
Puget Sound Energy
(Dollars in Thousands)
2013
2012
Favorable/
(Unfavorable)
2013
2012
Favorable/
(Unfavorable)
Operating revenue:
 
 
 
 
 
 
Electric
 
 
 
 
 
 
Residential sales
$
246,267

$
251,735

(2.2
)%
$
607,185

$
614,214

(1.1
)%
Commercial sales
188,162

198,627

(5.3
)
414,118

428,825

(3.4
)
Industrial sales
22,715

25,905

(12.3
)
49,525

53,857

(8.0
)
Other retail sales, including unbilled revenue
(11,714
)
(9,996
)
(17.2
)
(22,996
)
(25,125
)
8.5

Total retail sales
445,430

466,271

(4.5
)
1,047,832

1,071,771

(2.2
)
Transportation sales
2,334

2,457

(5.0
)
4,180

4,923

(15.1
)
Sales to other utilities and marketers
9,156

1,390

*

18,142

8,436

115.1

Other
4,737

393

*

6,137

(3,092
)
*

Total electric operating revenue
461,657

470,511

(1.9
)
1,076,291

1,082,038

(0.5
)
Gas
 

 

 
 

 

 

Residential sales
113,159

129,641

(12.7
)
374,343

426,436

(12.2
)
Commercial sales
54,751

63,972

(14.4
)
161,307

184,851

(12.7
)
Industrial sales
5,287

6,933

(23.7
)
15,005

17,818

(15.8
)
Total retail sales
173,197

200,546

(13.6
)
550,655

629,105

(12.5
)
Transportation sales
3,929

3,752

4.7

7,990

7,673

4.1

Other
3,602

3,525

2.2

6,848

7,011

(2.3
)
Total gas operating revenue
180,728

207,823

(13.0
)
565,493

643,789

(12.2
)
Non-utility operating revenue
101

283

(64.3
)
409

1,302

(68.6
)
Total operating revenue
642,486

678,617

(5.3
)
1,642,193

1,727,129

(4.9
)
Operating expenses:
 

 

 
 

 

 

Energy costs
 

 

 
 

 

 

Purchased electricity
112,543

156,098

27.9

287,587

355,213

19.0

Electric generation fuel
40,737

19,861

(105.1
)
99,823

89,798

(11.2
)
Residential exchange
(14,963
)
(15,302
)
(2.2
)
(37,515
)
(38,637
)
(2.9
)
Purchased gas
79,487

96,462

17.6

269,470

329,981

18.3

Net unrealized (gain) loss on derivative instruments
27,376

(59,850
)
*

(45,365
)
(49,715
)
(8.7
)
Utility operations and maintenance
130,286

128,195

(1.6
)
259,521

256,241

(1.3
)
Non-utility expense and other
3,028

2,270

(33.4
)
6,120

5,500

(11.3
)
Depreciation
90,301

84,552

(6.8
)
178,480

163,558

(9.1
)
Amortization
6,433

11,547

44.3

12,177

24,890

51.1

Conservation amortization
22,469

28,518

21.2

56,576

62,921

10.1

Taxes other than income taxes
53,695

72,960

26.4

153,638

172,830

11.1

Total operating expenses
551,392

525,311

(5.0
)
1,240,512

1,372,580

9.6

Operating income (loss)
91,094

153,306

(40.6
)
401,681

354,549

13.3

Other income
10,846

18,329

(40.8
)
22,857

33,262

(31.3
)
Other expense
(1,454
)
(1,947
)
25.3

(2,996
)
(5,700
)
47.4

Interest expense
(62,643
)
(57,729
)
(8.5
)
(124,000
)
(111,222
)
(11.5
)
Income (loss) before income taxes
37,843

111,959

(66.2
)
297,542

270,889

9.8

Income tax (benefit) expense
11,180

31,087

64.0

90,941

77,301

(17.6
)
Net income (loss)
$
26,663

$
80,872

(67.0
)%
$
206,601

$
193,588

6.7
 %
__________
* 
Not meaningful


41

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
June 30,
 
Six Months Ended
June 30,
 
Electric Margin
(Dollars in Thousands)
2013
2012
Favorable/
(Unfavorable)
2013
2012
Favorable/
(Unfavorable)
Electric operating revenue:
 
 
 
 
 


Residential sales
$
246,267

$
251,735

(2.2
)%
$
607,185

$
614,214

(1.1
)%
Commercial sales
188,162

198,627

(5.3
)
414,118

428,825

(3.4
)
Industrial sales
22,715

25,905

(12.3
)
49,525

53,857

(8.0
)
Other retail sales, including unbilled revenues
(11,714
)
(9,996
)
(17.2
)
(22,996
)
(25,125
)
8.5

Total retail sales
445,430

466,271

(4.5
)
1,047,832

1,071,771

(2.2
)
Transportation sales
2,334

2,457

(5.0
)
4,180

4,923

(15.1
)
Sales to other utilities and marketers
9,156

1,390

*

18,142

8,436

115.1

Other
4,737

393

*

6,137

(3,092
)
*

Total electric operating revenues1
461,657

470,511

(1.9
)
1,076,291

1,082,038

(0.5
)
Minus power costs:
 

 

 

 

 

 
Purchased electricity1
112,543

156,098

27.9

287,587

355,213

19.0

Electric generation fuel1
40,737

19,861

(105.1
)
99,823

89,798

(11.2
)
Residential exchange1
(14,963
)
(15,302
)
(2.2
)
(37,515
)
(38,637
)
(2.9
)
Total electric power costs
138,317

160,657

13.9

349,895

406,374

13.9

Electric margin2
$
323,340

$
309,854

4.4
 %
$
726,396

$
675,664

7.5
 %
______________
* 
Not meaningful
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.


42

Electric margin increased $13.5 million and $50.7 million, or 4.4% and 7.5%, to $323.3 million and $726.4 million from $309.9 million and $675.7 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods 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 decreased $8.9 million, or 1.9%, to $461.7 million from $470.5 million for the three months ended June 30, 2013 as compared to the same period in 2012. The decrease in operating revenues was primarily due to lower electric retail sales of $20.8 million, which was partially offset by higher miscellaneous operating revenues of $4.3 million and higher sales to other utilities and marketers of $7.8 million. These items are discussed in detail below.
Electric operating revenues decreased $5.7 million, or 0.5%, to $1,076.3 million from $1,082.0 million for the six months ended June 30, 2013, as compared to the same period in 2012. The decrease in operating revenues was primarily due to lower electric retail sales of $23.9 million, which was partially offset by higher miscellaneous operating revenues of $9.2 million and higher sales to other utilities and marketers of $9.7 million. These items are discussed in detail below.
Electric retail sales decreased $20.8 million, or 4.5%, to $445.4 million from $466.3 million for the three months ended June 30, 2013 as compared to the same period in 2012. The decrease in electric retail sales was primarily due to a revenue decrease of $4.7 million due to lower retail electricity usage of 47,166 MWhs, or 1.0%, as a result of warmer average temperatures in PSE's service territory during the three months ended June 30, 2013 as compared to the same period in the prior year and the transition of electrical services in Jefferson county to JPUD on March 31, 2013. The decrease was also driven by a net revenue decrease of $16.1 million due to the rate decrease primarily related to PSE's Federal Incentive Tracker tariff which passes through to customers the benefits of federal income tax incentives with no impact on earnings. The offset is recorded in amortization expense and federal tax expense. The rate decrease was offset by the electric rate increase of 3.2% effective May 14, 2012, and various other pass-through tariff items that have no impact on earnings.
Electric retail sales decreased $23.9 million, or 2.2%, to $1,047.8 million from $1,071.8 million for the six months ended June 30, 2013 as compared to the same period in 2012. The decrease was primarily due to a revenue decrease of $17.0 million due to lower retail electricity usage of 172,258 MWhs, or 1.6%, as a result of warmer average temperatures in PSE's service territory during the six months ended June 30, 2013 as compared to the same period in the prior year and the transition of electrical services in Jefferson county to JPUD on March 31, 2013. The decrease was also driven by a net revenue decrease of $6.9 million primarily due to PSE's Federal Incentive Tracker and various other pass-through tariff items that have no impact on earnings.
Sales to other utilities and marketers increased $7.8 million to $9.2 million from $1.4 million for the three months ended June 30, 2013 as compared to the same period in 2012. The increase was primarily driven by an increase of $7.8 million due to higher wholesale electricity prices for the three months ended June 30, 2013.
Sales to other utilities and marketers increased $9.7 million, or 115.1%, to $18.1 million from of $8.4 million for the six months ended June 30, 2013 as compared to the same period in 2012. The increase was primarily driven by an increase of $9.6 million due to higher wholesale electricity prices.
Other electric operating revenue increased $4.3 million to $4.7 million from $0.4 million for the three months ended June 30, 2013 as compared to the same period in 2012. The increase was primarily the result of an increase of $2.4 million due to higher non-core gas sales and an increase of $1.5 million due to higher transmission revenue for the three months ended June 30, 2013.
Other electric operating revenue increased $9.2 million to $6.1 million from a loss of $3.1 million for the six months ended June 30, 2013 as compared to the same period in 2012. The increase was primarily the result of an increase of $4.5 million due to higher transmission revenue and an increase of $2.8 million due to lower losses on non-core gas sales for the six months ended June 30, 2013.
Electric Energy Costs
Purchased electricity expense decreased $43.6 million, or 27.9%, to $112.5 million from $156.1 million for the three months ended June 30, 2013 as compared to the same period in 2012. The decrease was primarily the result of a decrease of $32.4 million in long-term firm purchases and market purchases as it was more economical to meet customer demand with PSE's own power generation due to market price fluctuation, a decrease of $10.9 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 $2.4 million due to a market price offset as it relates to generation plant in the PCA mechanism as compared to the same period in 2012, which provides the customer an offset for the market power purchases built into current rates that will not be incurred during the deferral period.
Purchased electricity expense decreased $67.6 million, or 19.0%, to $287.6 million from $355.2 million for the six months ended June 30, 2013 as compared to the same period in 2012. The decrease was primarily the result of a decrease of $50.4 million in long-term firm purchases and market purchases, a decrease of $16.7 million due to a decrease in the overrecovery of power costs and a decrease of $4.4 million due to a decrease in market price offset for the six months ended June 30, 2013 as compared to the same period in 2012.
To meet customer demand, PSE economically dispatches resources in its power supply portfolio, such as, fossil-fuel generation, owned and contracted hydroelectric energy and long-term contracted power. However, depending principally upon availability

43

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 increased $20.9 million, or 105.1%, to $40.7 million from $19.9 million for the three months ended June 30, 2013 as compared to the same period in 2012. The increase was primarily due to an increase of $12.5 million in fuel expense at PSE's combustion turbine facilities and an increase of $8.4 million in fuel expense at PSE's Colstrip facility. For the three months ended June 30, 2013 electric generation at combustion turbine facilities and Colstrip facility increased 405,325 MWhs and 691,170 MWHs, respectively, as compared to the same period in 2012, partially due to two coal plants at Colstrip facility that were taken offline for maintenance and remained offline during the second quarter of 2012 as other sources of electric generation were considered more economical.
Electric generation fuel expense increased $10.0 million, or 11.2%, to $99.8 million from $89.8 million for the six months ended June 30, 2013, as compared to the same period in 2012. The increase was primarily due to an increase of $12.0 million in fuel expense at PSE's Colstrip facility for the six months ended June 30, 2013, as compared to the same period in 2012, primarily due to the closure in 2012 discussed above. The increase was partially offset by a decrease of $2.0 million in fuel expense at PSE's combustion turbine facilities primarily due to favorable natural gas prices for the six months ended June 30, 2013, as compared to the same period in 2012.
   
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
June 30,
 
Six Months Ended
June 30,
 
Natural Gas Margin
(Dollars in Thousands)
2013
2012
Favorable/
(Unfavorable)
2013
2012
Favorable/
(Unfavorable)
Gas operating revenue:
 
 
 
 
 

Residential sales
$
113,159

$
129,641

(12.7
)%
$
374,343

$
426,436

(12.2
)%
Commercial sales
54,751

63,972

(14.4
)
161,307

184,851

(12.7
)
Industrial sales
5,287

6,933

(23.7
)
15,005

17,818

(15.8
)
Total retail sales
173,197

200,546

(13.6
)
550,655

629,105

(12.5
)
Transportation sales
3,929

3,752

4.7

7,990

7,673

4.1

Other
3,602

3,525

2.2

6,848

7,011

(2.3
)
Total gas operating revenues1
180,728

207,823

(13.0
)
565,493

643,789

(12.2
)
Minus purchased gas costs1
79,487

96,462

17.6

269,470

329,981

18.3

Natural gas margin2
$
101,241

$
111,361

(9.1
)%
$
296,023

$
313,808

(5.7
)%
______________
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 $10.1 million and $17.8 million, or 9.1% and 5.7%, to $101.2 million and $296.0 million from $111.4 million and $313.8 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods 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 $27.1 million and $78.3 million, or 13.0% and 12.2%, to $180.7 million and $565.5 million from $207.8 million and $643.8 million for three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The decrease was due primarily to lower natural gas retail sales as discussed in detail below.
Natural gas retail sales decreased $27.3 million, or 13.6%, to $173.2 million from $200.5 million for the three months ended June 30, 2013 as compared to the same period in 2012. The decrease was primarily due to a revenue decrease of $10.1 million due to lower therm sales of $8.2 million, or 5.2%, for the three months ended June 30, 2013 primarily due to warmer average temperatures; and a net revenue decrease of $10.4 million for the six months ended June 30, 2013 due to the PGA rate decrease of 7.7% effective November 1, 2012 partially offset by the gas rate increase of 1.3% effective May 14, 2012.
Natural gas retail sales decreased $78.5 million, or 12.5%, to $550.7 million from $629.1 million for the six months ended June 30, 2013 as compared to the same period in 2012. The decrease was primarily due to a revenue decrease of $36.5 million

44

due to lower therm sales of $31.5 million, or 5.9%, for the six months ended June 30, 2013 primarily due to warmer average temperatures; and a net revenue decrease of $35.1 million for the six months ended June 30, 2013 due to the PGA rate change. 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.
Also contributing to the decrease for three and six months ended June 30, 2013 was a decrease of $6.9 million related to gas conservation revenues as a result of an approved accounting petition authorizing PSE to recover the costs associated with the Company's 2012 gas conservation programs via transfers from amounts deferred for the over-recovery of commodity costs in the Company's PGA commodity account. This had no impact on earnings as conservation expense increased by the same amount.

Gas Energy Costs
Purchased gas expenses decreased $17.0 million and $60.5 million, or 17.6% and 18.3%, to $79.5 million and $269.5 million from $96.5 million and $330.0 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods 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 5.2% and 5.9% as a result of warmer average temperatures for the three and six months ended June 30, 2013, respectively, as compared to the same periods 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 payable, 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 June 30, 2013 was $14.5 million, which will be reflected on customers' bills through a future PGA rate filing.

Other Operating Expenses
Net unrealized (gain) loss on derivative instruments decreased $87.3 million to a loss of $27.4 million during the three months ended June 30, 2013 from a gain of $59.9 million during the same period in 2012. The net loss during the three months ended June 30, 2013 is primarily due to a loss of $6.0 million and $21.4 million related to PSE' electric and natural gas derivative instruments, respectively. This compares to a gain of $46.2 million and $13.7 million related to PSE's electric and natural gas derivative instruments, respectively, during the same period in 2012.
Net unrealized gain on derivative instruments decreased $4.2 million to a gain of $45.4 million during the six months ended June 30, 2013 from a gain of $49.7 million during the same period in 2012. The net gain during the six months ended June 30, 2013 is primarily due to a gain of $43.3 million and $2.1 million related to PSE's electric and natural gas derivative instruments, respectively. This compares to a gain of $36.0 million and $13.7 million related to PSE's electric and natural gas derivative instruments, respectively, during the same period in 2012.
Utility operations and maintenance expense increased $3.3 million, or 1.3%, to $259.5 million from $256.2 million for the six months ended June 30, 2013, as compared to the same period in 2012. The increase was primarily driven by an increase of $4.2 million in administrative and general expenses, an increase of $2.2 million in low income program expense, an increase of $1.4 million in production operations and maintenance expense, and an increase of $1.1 million in gas operation and maintenance for the six months ended June 30, 2013. Partially offsetting the increase was a decrease of $5.4 million in electric transmission and distribution expense, due primarily to the higher expenses during the same period in 2012 related to the January storm.
Depreciation expense increased $5.7 million and $14.9 million, or 6.8% and 9.1%, to $90.3 million and $178.5 million from $84.6 million and $163.6 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods 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, and Snoqualmie Falls Plant 2 which returned to service on April 17, 2013.
Amortization expense decreased $5.1 million, or 44.3%, to $6.4 million from $11.5 million for the three months ended June 30, 2013 as compared to the same period in 2012. The decrease was primarily due to an increase in regulatory credit related to amortization of Treasury Grant and related interests of $10.1 million and deferral of Ferndale and Snoqualmie Falls Plant 2 fixed costs of $3.3 million for the three months ended June 30, 2013 as compared to the same period in 2012. Partially offsetting the decrease was a decrease of $5.5 million in other regulatory credit and an increase of $2.7 million in computer software system amortization for the three months ended June 30, 2013 related to a new Customer Information System placed in service in April 2013.
Amortization expense decreased $12.7 million, or 51.1%, to $12.2 million from $24.9 million for the six months ended June 30, 2013 as compared to the same period in 2012. The decrease was primarily due to an increase in regulatory credit related to amortization of Treasury Grant and related interests of $18.8 million and deferral of Ferndale and Snoqualmie Falls Plant 2 fixed costs of $5.3 million for the six months ended June 30, 2013 as compared to the same period in 2012. Partially offsetting the

45

decrease was a decrease of $9.3 million in other regulatory credit and an increase of $1.4 million in computer software system amortization for the six months ended June 30, 2013 related to a new Customer Information System.
Conservation amortization decreased $6.0 million and $6.3 million, or 21.2% and 10.1%, to $22.5 million and $56.6 million from $28.5 million and $62.9 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The decrease was primarily due to a decrease of $6.5 million and $6.0 million in gas conservation amortization for the three and six months ended June 30, 2013, respectively. During the second quarter of 2012, an approved accounting petition authorized PSE to recover the costs associated with the Company's 2012 gas conservation programs via transfers from amounts deferred for the over-recovery commodity costs in the Company's PGA commodity account. Conservation amortization is a pass-through tariff item with no impact on earnings.
Taxes other than income taxes decreased $19.3 million and $19.2 million, or 26.4% and 11.1%, to $53.7 million and $153.6 million from $73.0 million and $172.8 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The decrease was primarily due to a decrease of $9.5 million and $6.0 million in Washington property taxes related to a property tax tracker approved in June 2013 (See discussion in the section entitled "Regulations and Rates"), a decrease of $7.8 million and $7.4 million in Montana property taxes primarily due to a settlement between PSE and the Montana Department of Revenue (DOR) in June 2013 on property tax, and a decrease of $2.2 million and $6.3 million in Washington State excise taxes and municipal taxes primarily due to lower electric and natural gas retail sales for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. In June 2013, PSE and DOR reached a settlement on the proper valuation of PSE's assets in Montana. PSE had paid its property tax bills under protest for each year since 2005, with the exception of 2008. The settlement results in a 10% reduction of PSE's values in Montana relative to the original DOR valuation for each year under protest.


Other Income and Interest Expense and Income Tax Expense
Other income decreased $7.5 million and $10.4 million, or 40.8% and 31.3%, to $10.8 million and $22.9 million from $18.3 million and $33.3 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The decrease was primarily due to a decrease of $7.4 million and $8.1 million in regulatory interest income and a decrease of $0.4 million and $2.8 million in AFUDC income mostly related to the decrease in average construction work in process for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The decrease was partially offset by an increase of $0.5 million and $0.9 million in life insurance gains for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012.
Other expense decreased $2.7 million, or 47.4%, to $3.0 million from $5.7 million for the six months ended June 30, 2013, as compared to the same period in 2012. The decrease was primarily due to a reduction of $2.4 million for the six months ended June 30, 2013, related to customer credits resulting from the outages due to the January 2012 winter storm.
Interest expense increased $4.9 million and $12.8 million, or 8.5% and 11.5%, to $62.6 million and $124.0 million from $57.7 million and $111.2 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. The increase was primarily due to an increase of $5.1 million and $10.4 million in interest expense associated with Treasury Grant regulatory liability for the three and six months ended June 30, 2013, respectively. 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 was a decrease of $1.5 million and $4.2 million related to the debt component of AFUDC for the three and six months ended June 30, 2013, respectively, primarily due to the decrease in average construction work in process. The increase was partially offset by a decrease of $1.0 million and $1.6 million in debt issuance cost amortization for the three and six months ended June 30, 2013, respectively, primarily because PSE adjusted its revolving credit facilities in February 2013.
Income tax expense decreased $19.9 million, or 64.0%, to $11.2 million from $31.1 million for the three months ended June 30, 2013 as compared to the same period in 2012. The decrease was primarily due to lower pre-tax income for the three months ended June 30, 2013 as compared to same period in 2012.
Income tax expense increased $13.6 million, or 17.6%, to $90.9 million from $77.3 million for the six months ended June 30, 2013, as compared to the same period in 2012. The increase was primarily due to higher pre-tax income for the six months ended June 30, 2013, as compared to same period in 2012.


46

Puget Energy

Summary Results of Operations
All the operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income (loss) for the three and six months ended June 30, 2013 and 2012 was as follows:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
Benefit/(Expense)
(Dollars in Thousands)
2013
2012
Percent
Change
2013
2012
Percent
Change
PSE net income
$
26,663

$
80,872

(67.0
)%
$
206,601

$
193,588

6.7
 %
Other operating revenue
—

—

*

111

—

*

Net unrealized gain on energy derivative instruments
—

4,226

*

2,952

9,635

(69.4
)
Non-utility expense and other
3,986

2,344

70.1

8,071

4,713

71.2

Other income
1

8

(87.5
)
1

11

(90.9
)
Non-hedging interest rate derivative (expense) income
1,232

(7,297
)
*

2,260

(6,770
)
*

Interest expense 1
(43,113
)
(33,548
)
(28.5
)
(72,923
)
(79,961
)
8.8

Income tax benefit (expense)
12,136

11,087

9.5

21,307

24,955

(14.6
)
Puget Energy net income (loss)
$
905

$
57,692

(98.4
)%
$
168,380

$
146,171

15.2
 %
__________
* 
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 June 30, 2013 was $0.9 million with operating revenue of $642.5 million as compared to a net income of $57.7 million with operating revenue of $678.6 million for the same period in 2012. Puget Energy's net income for the six months ended June 30, 2013 was $168.4 million with operating revenue of $1.6 billion as compared to a net income of $146.2 million with operating revenue of $1.7 billion for the same period in 2012. The following are significant factors that impacted Puget Energy's net income (loss), which are not included in PSE's discussion:

Net unrealized gain on derivative instruments for Puget Energy did not have a difference as compared to PSE for the three months ended June 30, 2013 as compared to a net unrealized gain of $4.2 million during the same period in 2012. The differences with PSE are due to the effects of purchase accounting on derivative contracts in OCI of $4.2 million in 2012.
Net unrealized gain on derivative instruments decreased $6.7 million, or 69.4%, to $3.0 million from $9.6 million for the six months ended June 30, 2013 as compared to the same period in 2012, due to the effects of purchase accounting on derivative contracts in OCI of $4.5 million and the fair value amortization of NPNS derivative contracts of $2.2 million.
Income related to non-utility expense and other increased $3.4 million, or 71.2%, to $8.1 million from $4.7 million for the six months ended June 30, 2013 as compared to the same period in 2012 due primarily to pension expense.
Income related to non-hedging interest rate derivative increased $8.5 million and $9.0 million to an income of $1.2 million and $2.3 million from an expense of $7.3 million and $6.8 million for the three and six months ended June 30, 2013, respectively, as compared to the same periods in 2012. Due to swap balance reductions in February and May, 2012, the interest expense decreased by $6.2 million and $19.9 million for the three and six months ended June 30, 2013, respectively. Additionally, mark-to-market gains on non-hedging interest rate derivative increased by $2.3 million and decreased by $10.9 million for the three and six months ended June 30, 2013, respectively.
Interest expense increased $9.6 million, or 28.5%, to $43.1 million from $33.5 million for the three months ended June 30, 2013, as compared to the same period in 2012. The increase was primarily due to a write off of the unamortized fair value adjustment and debt issuance cost of $18.0 million related to PSE's Pollution Control Bonds, an increase of $5.2 million in interest expense related to the senior secured notes of $450.0 million issued on June 15, 2012, and a decrease of $5.0 million in mark-to-market gains on hedged interest rate swap contracts. The increase was partially offset by a decrease of $16.8 million in interest expense related to hedged interest rate swap contracts and a decrease of $2.0 million in interest expense related to Puget Energy's revolving senior secured credit facility as its balance was reduced in 2012.
Interest expense decreased $7.0 million, or 8.8%, to $72.9 million from $80.0 million for the six months ended June 30, 2013 as compared to the same period in 2012. The decrease was primarily due to a decrease of $20.0 million in interest expense related to hedged interest rate swap contracts, 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 and a decrease of $4.2 million in interest expense related to Puget Energy's revolving senior secured credit facility as its balance was reduced in 2012. The decrease was partially offset by a write off of the unamortized fair value adjustment and debt issuance cost of $18.0 million related to PSE's Pollution Control

47

Bonds, an increase of $11.5 million in interest expense related to the senior secured notes of $450.0 million issued on June 15, 2012, and a decrease of $1.4 million in mark-to-market gains on hedged interest rate swap contracts.
Income tax benefit decreased $3.6 million, or 14.6%, to $21.3 million from $25.0 million for the six months ended June 30, 2013 as compared to the same period in 2012 due primarily to a lower pre-tax loss.

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.
The following are PSE’s and Puget Energy’s aggregate availability under commercial commitments as of June 30, 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
403,000

—

—

403,000

—

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

—

—

Total Puget Energy commercial commitments
$
1,394,400

$
—

$
—

$
403,000

$
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 June 30, 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 no amount 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 June 30, 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 June 30, 2013, $379.0 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 $326.1 million for the six months ended June 30, 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.

48

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 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.
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.


Capital Resources
Cash From Operations

Puget Sound Energy
Cash generated from operations for the six months ended June 30, 2013 decreased by $26.8 million from $518.2 million generated during the same period in 2012.  The decrease in cash flow was primarily the result of the following:

•Cash collections from revenues decreased by $43.6 million.
•A decrease in the purchased gas adjustment of $41.8 million.

The decrease in cash generated from operating activities in 2013 described above was primarily offset by the following cash increases:

•In 2013 there was $1.0 million of storm costs compared to approximately $67.9 million of cash outflow for costs incurred related to the January 2012 winter storm of which $58.8 million was deferred for future recovery.

Puget Energy
Cash generated from operations for the six months ended June 30, 2013 was $469.3 million, a decrease of $28.4 million from the $497.6 million generated during the six months ended June 30, 2012.  The decrease is primarily due to cash provided by the operating activities of PSE as previously discussed of $26.8 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 June 30, 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

49

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 June 30, 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 no amount 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 June 30, 2013, $29.6 million was outstanding under the Note. 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 June 30, 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 bank's 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 June 30, 2013, $379.0 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 June 30, 2013, approximately $540.8 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 June 30, 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 June 30, 2013.
At June 30, 2013, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.


50

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 June 30, 2013, PSE could issue:

•
Approximately $1.1 billion of additional first mortgage bonds under PSE's electric mortgage indenture based on approximately $1.9 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 June 30, 2013; and
•
Approximately $327.0 million of additional first mortgage bonds under PSE's natural gas mortgage indenture based on approximately $492.8 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 June 30, 2013.

At June 30, 2013, PSE had approximately $6.7 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 June 30, 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.
On May 23, 2013, PSE refinanced $161.9 million of its Pollution Control Revenue Refunding Bonds to a lower weighted average interest rate from 5.01% to 3.91%. The bonds will mature on March 1, 2031. On or after March 1, 2023, the Company may elect to call the bonds at a redemption price of 100% of the principal amount thereof, without premium, plus accrued interest, if any, to the redemption date.


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.




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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 between July and December 2012.  Discovery in the case has begun and a prehearing conference took place in July 2013. The case has been bifurcated into separate liability and remedy trials set for October 2014 and August 2015, respectively. 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 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, floating-for-fixed swap contracts, and commodity call/put options. 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. Beginning June 2013, PSE began trading natural gas call and put options. Utilizing options as an additional hedging instrument increases the hedging portfolio's flexibility to react to commodity price fluctuations, as well as create a commodity price cap for customers, thus protecting rate payers against future price increases.
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

52

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 fair values of the Company's energy derivative instruments, recorded on the balance sheets:

Puget Energy and Puget Sound Energy
 
(Dollars in thousands)
June 30, 2013
December 31, 2012
 
Assets
Liabilities
Assets
Liabilities
Electric portfolio:
 
 
 
 
Current
$
6,088

$
52,855

$
3,418

$
93,097

Long-term
4,386

31,102

6,139

38,096

Total electric derivatives
$
10,474

$
83,957

$
9,557

$
131,193

Natural Gas portfolio:
 

 

 

 

Current
$
3,938

$
55,665

$
3,451

$
77,851

Long-term
2,479

21,102

8,675

30,227

Total natural gas derivatives
$
6,417

$
76,767

$
12,126

$
108,078

Total energy derivatives
$
16,891

$
160,724

$
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 June 30, 2013, the Company had total assets of $6.4 million and total liabilities of $76.8 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 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 $42.6 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 June 30, 2013, PSE held approximately $17.4 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 June 30, 2013, approximately 85.74% 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 14.26% 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 contract's 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.

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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 June 30, 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 enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of June 30, 2013, Puget Energy had two interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.
At June 30, 2013, the fair value of the interest rate swaps was a $13.7 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 $2.0 million pre-tax and $1.3 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 $1.5 million.
The following table presents the fair values of Puget Energy's interest rate swaps, recorded on the balance sheet:
Puget Energy
(Dollars in Thousands)
June 30, 2013
December 31, 2012
 
Liabilities
Liabilities
Interest rate swaps:
 
 
Current
$
6,518

$
6,571

Long-term
7,188

14,953

Total interest rate swaps
$
13,706

$
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 June 30, 2013 was a net loss of $6.5 million after tax compared 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 June 30, 2013.



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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 June 30, 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
During the quarter ended June 30, 2013, the Company implemented a new Customer Information System as part of its overall information technology strategy. The system change was not made in response to any deficiency in the Company's internal controls. This implementation has resulted in certain changes to business processes and internal controls impacting financial reporting. PSE has taken steps to monitor and maintain appropriate internal control over financial reporting during this period of system change and will continue to evaluate the operating effectiveness of related controls during subsequent periods.
There were no other changes in the Company's internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its 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 June 30, 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
During the quarter ended June 30, 2013, PSE implemented a new Customer Information System as part of its overall information technology strategy. The system change was not made in response to any deficiency in the Company's internal controls. This implementation has resulted in certain changes to business processes and internal controls impacting financial reporting. PSE has taken steps to monitor and maintain appropriate internal control over financial reporting during this period of system change and will continue to evaluate the operating effectiveness of related controls during subsequent periods.
There were no other changes in the Company's internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its 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 June 30, 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:  
August 2, 2013
Officer duly authorized to sign this report on behalf of each registrant



57

EXHIBIT INDEX

4.1
Trust Indenture, dated as of May 1, 2013 (the “Indenture”), by and between the City and Wells Fargo Bank, National Association, as trustee. (incorporated herein by reference to Exhibit 4.1 to Puget Sound Energy's Current Report on Form 8-K, dated May 30, 2013, Commission File No. 1-04393)
4.2
Loan Agreement, dated as of May 1, 2013, between Puget Sound Energy, Inc. and the City of Forsyth, Rosebud County, Montana. (incorporated herein by reference to Exhibit 4.2 to Puget Sound Energy's Current Report on Form 8-K, dated May 30, 2013, Commission File No. 1-04393)
4.3
Pledge Agreement, dated as of May 1, 2013, between Puget Sound Energy, Inc. and Wells Fargo Bank, National Association, as trustee. (incorporated herein by reference to Exhibit 4.3 to Puget Sound Energy's Current Report on Form 8-K, dated May 30, 2013, Commission File No. 1-04393)
4.4
Ninety-Second Supplemental Indenture defining the rights of the holders of Puget Sound Energy's Series II Pledged First Mortgage Bonds. (incorporated herein by reference to Exhibit 4.4 to Puget Sound Energy's Current Report on Form 8-K, dated May 30, 2013, Commission File No. 1-04393)
12.1*
Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2008 through 2012 and 12 months ended June 30, 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 June 30, 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 June 30, 2013, filed on August 2, 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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