10-Q 1 pe-2012630x10q.htm PUGET ENERGY AND PSE FORM 10-Q PE-2012.6.30-10Q


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, 2012

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
3
4
4
 
 
 
 
 
 
 
 
Puget Energy, Inc.
 
 
6
 
7
 
8
 
10
 
 
 
 
Puget Sound Energy, Inc.
 
 
11
 
12
 
13
 
15
 
 
 
 
Notes
 
 
16
 
 
 
32
 
 
 
46
 
 
 
50
 
 
 
50
 
 
 
50
 
 
 
50
 
 
 
50
 
 
 
51
 
 
52


2


DEFINITIONS

AFUDC
Allowance for Funds Used During Construction
ASC
Accounting Standards Codification
BPA
Bonneville Power Administration
EBITDA
Earnings Before Interest, Tax, Depreciation and Amortization
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


3



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

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

Ÿ
Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), with respect to allowed rates of return, cost recovery, financing, industry and rate structures, transmission and generation business structures within PSE, acquisition and disposal of assets and facilities, operation, maintenance and construction of electric generating facilities, natural gas and electric distribution and transmission facilities, licensing of hydroelectric operations and natural gas storage facilities, recovery of other capital investments, recovery of power and natural gas costs, recovery of regulatory assets, implementation of energy efficiency programs and present or prospective wholesale and retail competition;
Ÿ
Failure of PSE to comply with the FERC or the Washington Commission standards and/or rules, which could result in penalties based on the discretion of either commission;
Ÿ
Findings of noncompliance with electric reliability standards developed by the North American Electric Reliability Corporation (NERC) or the Western Electricity Coordinating Council for users, owners and operators of the power system, which could result in penalties;
Ÿ
Changes in, adoption of and compliance with laws and regulations, including decisions and policies concerning the environment, climate change, greenhouse gas or other emissions or byproducts of electric generation (including coal ash or other substances), natural resources, and fish and wildlife (including the Endangered Species Act) as well as the risk of litigation arising from such matters, whether involving public or private claimants or regulatory investigative or enforcement measures;
Ÿ
The ability to recover costs arising from changes in enacted federal, state or local tax laws in a timely manner;
Ÿ
Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdictions;
Ÿ
Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;
Ÿ
Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, which can interrupt service and lead to lost revenue, cause temporary supply disruptions and/or price spikes in the cost of fuel and raw materials and impose extraordinary costs;
Ÿ
Commodity price risks associated with procuring natural gas and power in wholesale markets or counterparties extending credit to PSE without collateral posting requirements;
Ÿ
Wholesale market disruption, which may result in a deterioration of market liquidity, increase the risk of counterparty default, affect the regulatory and legislative process in unpredictable ways, negatively affect wholesale energy prices and/or impede PSE’s ability to manage its energy portfolio risks and procure energy supply, affect the availability and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
Ÿ
Financial difficulties of other energy companies and related events, which may affect the regulatory and legislative process in unpredictable ways, adversely affect the availability of and access to capital and credit markets and/or impact delivery of energy to PSE from its suppliers;
Ÿ
The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;
Ÿ
PSE electric or natural gas distribution system failure, which may impact PSE’s ability to deliver energy supply to its customers;
Ÿ
Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE’s revenue and expenses;
Ÿ
Regional or national weather, which can have a potentially serious impact on PSE’s ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and on the cost of procuring such supplies;
Ÿ
Variable hydrological conditions, which can impact streamflow and PSE’s ability to generate electricity from hydroelectric facilities;
Ÿ
Electric plant generation and transmission system outages, which can have an adverse impact on PSE’s expenses with respect to repair costs, added costs to replace energy or higher costs associated with dispatching a more expensive generation resource;
Ÿ
The ability of a natural gas or electric plant to operate as intended;
Ÿ
The ability to renew contracts for electric and natural gas supply and the price of renewal;
Ÿ
Blackouts or large curtailments of transmission systems, whether PSE’s or others’, which can affect PSE’s ability to deliver power or natural gas to its customers and generating facilities;
Ÿ
The ability to restart generation following a regional transmission disruption;
Ÿ
The failure of the interstate natural gas pipeline delivering to PSE’s system, which may impact PSE’s ability to adequately deliver natural gas supply or electric power to its customers;
Ÿ
Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
Ÿ
General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE’s accounts receivable;
Ÿ
The loss of significant customers, changes in the business of significant customers or the condemnation of PSE’s facilities as a result of municipalization or other government action or negotiated settlement, which may result in changes in demand for PSE’s services;
Ÿ
The failure of information systems or the failure to secure information system data, which may impact the operations and cost of PSE’s customer service, generation, distribution and transmission;
Ÿ
The impact of acts of God, terrorism, flu pandemic or similar significant events;
Ÿ
Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
Ÿ
Employee workforce factors, including strikes, work stoppages, availability 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,
 
2012
2011
2012
2011
Operating revenue:
 
 
 
 
Electric
$
470,511

$
487,721

$
1,082,038

$
1,087,454

Gas
207,823

245,014

643,789

663,638

Other
283

(60
)
1,302

1,176

Total operating revenue
678,617

732,675

1,727,129

1,752,268

Operating expenses:
 

 

 

 

Energy costs:
 

 

 

 

Purchased electricity
156,098

180,022

355,213

407,918

Electric generation fuel
19,861

25,886

89,798

71,109

Residential exchange
(15,302
)
(15,293
)
(38,637
)
(36,975
)
Purchased gas
96,462

127,174

329,981

363,928

Unrealized (gain) loss on derivative instruments, net
(64,076
)
(16,995
)
(59,350
)
(50,113
)
Utility operations and maintenance
128,195

123,852

256,241

241,820

Non-utility expense and other
(74
)
2,022

787

4,941

Depreciation
84,552

73,579

163,558

148,361

Amortization
11,547

18,450

24,890

36,423

Conservation amortization
28,518

23,871

62,921

56,084

Taxes other than income taxes
72,960

75,414

172,830

175,935

Total operating expenses
518,741

617,982

1,358,232

1,419,431

Operating income
159,876

114,693

368,897

332,837

Other income (deductions):
 

 

 

 

Other income
18,337

15,679

33,273

28,218

Other expense
(1,947
)
(1,278
)
(5,700
)
(2,233
)
Non-hedging interest rate derivative expense
(7,297
)
(25,412
)
(6,770
)
(25,460
)
Interest charges:
 

 

 

 

AFUDC
4,687

7,597

11,982

12,001

Interest expense
(95,964
)
(108,961
)
(203,165
)
(190,009
)
Income (loss) before income taxes
77,692

2,318

198,517

155,354

Income tax (benefit) expense
20,000

(2,717
)
52,346

42,888

Net income (loss)
$
57,692

$
5,035

$
146,171

$
112,466


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,
 
2012
2011
2012
2011
Net income (loss)
$
57,692

$
5,035

$
146,171

$
112,466

Other comprehensive income (loss):
 

 

 

 

Reclassification of net unrealized (gain) loss on interest rate swaps during the period, net of tax of $3,817, $8,486, $5,167 and $10,766, respectively
7,088

15,760

9,596

19,993

Net unrealized gain (loss) from pension and postretirement plans, net of tax of $(56), $(142), $(112) and $(283), respectively
(104
)
(263
)
(209
)
(525
)
Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $66, $95, $(39) and $196, respectively
122

177

(73
)
364

Other comprehensive income (loss)
7,106

15,674

9,314

19,832

Comprehensive income (loss)
$
64,798

$
20,709

$
155,485

$
132,298


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,
2012
December 31,
2011
Utility plant (including construction work in progress of $707,257 and $1,282,463,
respectively):
 
 
Electric plant
$
6,336,530

$
6,067,672

Gas plant
2,314,874

2,238,741

Common plant
439,872

418,236

Less: Accumulated depreciation and amortization
(828,083
)
(674,782
)
Net utility plant
8,263,193

8,049,867

Other property and investments:
 

 

Goodwill
1,656,513

1,656,513

Investment in exchange power contract
17,633

19,396

Other property and investments
116,203

123,352

Total other property and investments
1,790,349

1,799,261

Current assets:
 

 

Cash and cash equivalents
16,133

37,235

Restricted cash
3,544

4,183

Accounts receivable, net of allowance for doubtful accounts of $7,689 and $8,495,
respectively
233,225

336,530

Unbilled revenue
120,102

191,150

Materials and supplies, at average cost
89,790

76,068

Fuel and gas inventory, at average cost
69,154

100,491

Unrealized gain on derivative instruments
6,973

6,647

Income taxes
9,661

11,553

Prepaid expense and other
18,157

13,969

Power contract acquisition adjustment gain
47,012

65,096

Deferred income taxes
87,931

101,934

Total current assets
701,682

944,856

Other long-term and regulatory assets:
 

 

Regulatory asset for deferred income taxes
67,830

62,304

Power cost adjustment mechanism
—

6,818

Regulatory assets related to power contracts
39,227

46,202

Other regulatory assets
866,036

766,825

Unrealized gain on derivative instruments
15,981

10,084

Power contract acquisition adjustment gain
490,354

517,740

Other
82,334

180,753

Total other long-term and regulatory assets
1,561,762

1,590,726

Total assets
$
12,316,986

$
12,384,710


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,
2012
December 31,
2011
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
80,600

22,873

Accumulated other comprehensive income (loss), net of tax
(21,593
)
(30,907
)
Total common shareholder’s equity
3,367,964

3,300,923

Long-term debt:
 

 

First mortgage bonds and senior notes
3,362,000

3,362,000

Pollution control bonds
161,860

161,860

Junior subordinated notes
250,000

250,000

Long-term debt
1,834,000

1,793,000

Debt discount and other
(270,227
)
(289,493
)
Total long-term debt
5,337,633

5,277,367

Total capitalization
8,705,597

8,578,290

Current liabilities:
 

 

Accounts payable
214,847

339,361

Short-term debt
38,000

25,000

Purchased gas adjustment liability
49,611

25,940

Accrued expenses:
 

 

  Taxes
79,892

90,727

  Salaries and wages
29,058

40,892

  Interest
69,480

69,329

Unrealized loss on derivative instruments
277,246

327,089

Power contract acquisition adjustment loss
4,050

8,547

Other
69,381

74,409

Total current liabilities
831,565

1,001,294

Long-term and regulatory liabilities:
 

 

Deferred income taxes
1,202,949

1,153,755

Unrealized loss on derivative instruments
113,209

196,558

Power cost adjustment mechanism
19,433

—

Regulatory liabilities
375,748

346,225

Regulatory liabilities related to power contracts
537,366

582,836

Power contract acquisition adjustment loss
35,177

37,655

Other deferred credits
495,942

488,097

Total long-term and regulatory liabilities
2,779,824

2,805,126

Commitments and contingencies




                  Total capitalization and liabilities
$
12,316,986

$
12,384,710


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,
 
2012
2011
Operating activities:
 
 
Net income (loss)
$
146,171

$
112,466

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

 

Depreciation
163,558

148,361

Amortization
24,890

36,423

Conservation amortization
62,921

56,084

Deferred income taxes and tax credits, net
52,657

43,278

Net unrealized (gain) loss on derivative instruments
(76,850
)
(23,542
)
Pension funding
(11,400
)
(5,000
)
Derivative contracts classified as financing activities due to merger
47,423

123,951

AFUDC – Equity
(14,485
)
(12,033
)
Regulatory assets
(61,856
)
18,450

Regulatory liabilities
37,752

(3,203
)
Other long-term assets
7,302

(23,919
)
Other long-term liabilities
45,284

32,113

Change in certain current assets and liabilities:
 

 

Accounts receivable and unbilled revenue
174,353

169,838

Materials and supplies
(13,722
)
6,416

Fuel and gas inventory
31,138

28,880

Income taxes
1,892

63,893

Prepayments and other
(4,190
)
(2,154
)
Purchased gas adjustment
23,671

18,716

Accounts payable
(86,438
)
(51,557
)
Taxes payable
(10,835
)
(6,726
)
Accrued expenses and other
6,621

10,632

Net cash provided by operating activities
545,857

741,367

Investing activities:
 

 

Construction expenditures – excluding equity AFUDC
(398,900
)
(567,837
)
Energy efficiency expenditures
(48,232
)
(37,758
)
Restricted cash
639

1,018

Other
(28,410
)
1,525

Net cash used in investing activities
(474,903
)
(603,052
)
Financing activities:
 

 

Change in short-term debt and leases, net
9,211

(248,765
)
Dividends paid
(88,444
)
(116,691
)
Long-term notes and bonds issued
1,314,000

1,087,000

Redemption of bonds and notes
(1,273,000
)
(744,000
)
Derivative contracts classified as financing activities due to merger
(47,423
)
(123,951
)
Issuance cost of bonds and other
(6,400
)
(5,593
)
Net cash provided by (used in) financing activities
(92,056
)
(152,000
)
Net increase (decrease) in cash and cash equivalents
(21,102
)
(13,685
)
Cash and cash equivalents at beginning of period
37,235

36,557

Cash and cash equivalents at end of period
$
16,133

$
22,872

Supplemental cash flow information:
 

 

Cash payments for interest (net of capitalized interest)
$
170,262

$
152,789

Cash payments (refunds) for income taxes
(1,898
)
(64,018
)

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,
 
2012
2011
2012
2011
Operating revenue:
 
 
 
 
Electric
$
470,511

$
487,721

$
1,082,038

$
1,087,454

Gas
207,823

245,014

643,789

663,638

Other
283

629

1,302

1,865

Total operating revenue
678,617

733,364

1,727,129

1,752,957

Operating expenses:
 

 

 

 

Energy costs:
 

 

 

 

Purchased electricity
156,098

180,166

355,213

408,207

Electric generation fuel
19,861

25,886

89,798

71,109

Residential exchange
(15,302
)
(15,293
)
(38,637
)
(36,975
)
Purchased gas
96,462

127,174

329,981

363,928

Unrealized (gain) loss on derivative instruments, net
(59,850
)
(9,648
)
(49,715
)
(15,632
)
Utility operations and maintenance
128,195

123,852

256,241

241,820

Non-utility expense and other
2,270

2,533

5,500

5,880

Depreciation
84,552

73,579

163,558

148,361

Amortization
11,547

18,450

24,890

36,423

Conservation amortization
28,518

23,871

62,921

56,084

Taxes other than income taxes
72,960

75,414

172,830

175,935

Total operating expenses
525,311

625,984

1,372,580

1,455,140

Operating income (loss)
153,306

107,380

354,549

297,817

Other income (deductions):
 

 

 

 

Other income
18,329

15,677

33,262

28,211

Other expense
(1,947
)
(1,278
)
(5,700
)
(2,233
)
Interest charges:
 

 

 

 

AFUDC
4,687

7,597

11,982

12,001

Interest expense
(62,333
)
(57,812
)
(123,071
)
(114,417
)
Interest expense on parent note
(83
)
(30
)
(133
)
(95
)
Income (loss) before income taxes
111,959

71,534

270,889

221,284

Income tax (benefit) expense
31,087

20,621

77,301

66,932

Net income (loss)
$
80,872

$
50,913

$
193,588

$
154,352


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,
 
2012
2011
2012
2011
Net income (loss)
$
80,872

$
50,913

$
193,588

$
154,352

Other comprehensive income (loss):
 

 

 

 

Net unrealized gain (loss) from pension and postretirement plans, net of tax of $661, $931, $1,962 and $2,196, respectively
1,227

1,729

3,643

3,127

Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $1,545, $1,715, $2,580 and $8,495, respectively
2,869

3,185

4,791

15,774

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

80

159

160

Other comprehensive income (loss)
4,175

4,994

8,593

19,061

Comprehensive income (loss)
$
85,047

$
55,907

$
202,181

$
173,413


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,
2012
December 31,
2011
Utility plant (at original cost, including construction work in progress of $707,257 and
$1,282,463, respectively):
 
 
Electric plant
$
8,655,056

$
8,390,667

Gas plant
2,930,189

2,855,794

Common plant
526,925

518,318

Less:  Accumulated depreciation and amortization
(3,848,976
)
(3,714,912
)
Net utility plant
8,263,194

8,049,867

Other property and investments:
 

 

Investment in exchange power contract
17,633

19,396

Other property and investments
106,379

113,528

Total other property and investments
124,012

132,924

Current assets:
 

 

Cash and cash equivalents
14,630

31,010

Restricted cash
3,544

4,183

Accounts receivable, net of allowance for doubtful accounts of $7,689 and $8,495,
respectively
233,338

336,483

Unbilled revenue
120,102

191,150

Materials and supplies, at average cost
89,790

76,068

Fuel and gas inventory, at average cost
65,936

97,074

Unrealized gain on derivative instruments
6,973

6,647

Income taxes
9,661

11,553

Prepaid expense and other
17,997

13,807

Deferred income taxes
100,916

112,204

Total current assets
662,887

880,179

Other long-term and regulatory assets:
 

 

Regulatory asset for deferred income taxes
66,841

61,344

Power cost adjustment mechanism
—

6,818

Other regulatory assets
861,784

760,585

Unrealized gain on derivative instruments
15,981

10,084

Other
76,492

183,746

Total other long-term and regulatory assets
1,021,098

1,022,577

Total assets
$
10,071,191

$
10,085,547


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,
2012
December 31,
2011
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
219,994

163,735

Accumulated other comprehensive income (loss), net of tax
(179,986
)
(188,579
)
Total common shareholder’s equity
3,287,072

3,222,220

Long-term debt:
 

 

First mortgage bonds and senior notes
3,362,000

3,362,000

Pollution control bonds
161,860

161,860

Junior subordinated notes
250,000

250,000

Debt discount
(14
)
(15
)
Total long-term debt
3,773,846

3,773,845

Total capitalization
7,060,918

6,996,065

Current liabilities:
 

 

Accounts payable
214,937

339,568

Short-term debt
38,000

25,000

Short-term note owed to parent
29,998

29,998

Purchased gas adjustment liability
49,611

25,940

Accrued expenses:
 

 

Taxes
79,892

90,727

Salaries and wages
29,058

40,892

Interest
55,964

55,843

         Unrealized loss on derivative instruments
271,023

301,879

         Other
65,763

68,346

Total current liabilities
834,246

978,193

Long-term and regulatory liabilities:
 

 

Deferred income taxes
1,192,086

1,115,639

Unrealized loss on derivative instruments
99,285

169,359

Power cost adjustment mechanism
19,433

—

Regulatory liabilities
371,096

340,907

Other deferred credits
494,127

485,384

Total long-term and regulatory liabilities
2,176,027

2,111,289

Commitments and contingencies




Total capitalization and liabilities
$
10,071,191

$
10,085,547


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,
 
2012
2011
Operating activities:
 
 
Net income (loss)
$
193,588

$
154,352

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

 

Depreciation
163,558

148,361

Amortization
24,890

36,423

Conservation amortization
62,921

56,084

Deferred income taxes and tax credits, net
77,611

67,272

Net unrealized (gain) loss on derivative instruments
(49,715
)
(15,632
)
Pension funding
(11,400
)
(5,000
)
AFUDC – Equity
(14,485
)
(12,033
)
Regulatory assets
(61,856
)
18,450

Regulatory liabilities
37,752

(3,203
)
Other long-term assets
10,875

(24,644
)
Other long-term liabilities
31,394

18,448

Change in certain current assets and liabilities:
 

 

Accounts receivable and unbilled revenue
174,193

169,612

Materials and supplies
(13,722
)
6,416

Fuel and gas inventory
31,138

28,880

Income taxes
1,892

50,396

Prepayments and other
(4,190
)
(2,154
)
Purchased gas adjustment
23,671

18,716

Accounts payable
(86,555
)
(51,865
)
Taxes payable
(10,835
)
(6,726
)
Accrued expenses and other
(14,296
)
(1,308
)
Net cash provided by operating activities
566,429

650,845

Investing activities:
 

 

Construction expenditures – excluding equity AFUDC
(398,900
)
(567,837
)
Energy efficiency expenditures
(48,232
)
(37,758
)
Restricted cash
639

1,018

Other
(7,635
)
12,042

Net cash used in investing activities
(454,128
)
(592,535
)
Financing activities:
 

 

Change in short-term debt and leases, net
9,211

(248,765
)
Dividends paid
(137,329
)
(164,121
)
Long-term notes and bonds issued
—

300,000

Loan from (payment to) parent
—

7,400

Redemption of bonds and notes
—

(260,000
)
Investment from parent
—

287,000

Issuance cost of bonds and other
(563
)
203

Net cash provided by (used in) financing activities
(128,681
)
(78,283
)
Net increase (decrease) in cash and cash equivalents
(16,380
)
(19,973
)
Cash and cash equivalents at beginning of period
31,010

36,320

Cash and cash equivalents at end of period
$
14,630

$
16,347

Supplemental cash flow information:
 

 

Cash payments for interest (net of capitalized interest)
$
106,823

$
96,703

Cash payments (refunds) for income taxes
(1,898
)
(50,421
)

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 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 all significant intercompany items and transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments.  Certain prior year amounts in the consolidated statements of cash flows have been reclassified to conform to current year presentation.
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, 2011.
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.

Revenue Recognition
Operating utility revenue is recognized when the basis of services is rendered, which includes estimated unbilled revenue. In March 2012, PSE changed its estimate of unbilled revenue from a calculation that was based on system load and billing information from its customers to a calculation using meter readings from its automated meter reading (AMR) system. The new estimate calculates unbilled usage at the end of each month as the difference between the customer meter readings on the last day of the month and the last customer meter readings billed. The unbilled usage is then priced at published rates for each schedule to estimate the unbilled revenues by customer. As a result of further refinements, the estimate of unbilled revenue at June 30, 2012, PSE has additionally identified $4.4 million of revenue that were recorded during the second quarter that should have been included in the estimated unbilled calculation at March 31, 2012. The impact on net income was $2.9 million. This had no impact to cash flow from operations or total cash flows.
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 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 $53.7 million and $134.7 million for the three and six months ended June 30, 2012, respectively, and $57.1 million and $137.4 million for the three and six months ended June 30, 2011, 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.

Accumulated Other Comprehensive Income (Loss)
The following tables present the components of the Company’s accumulated other comprehensive income (OCI) at June 30, 2012 and December 31, 2011:
Puget Energy
(Dollars in Thousands)
June 30,
2012
December 31,
2011
Net unrealized loss on energy derivative instruments
$
(1,186
)
$
(1,113
)
Net unrealized loss on interest rate swaps
(5,003
)
(14,599
)
Net unrealized loss and prior service cost on pension plans
(15,404
)
(15,195
)
Total Puget Energy, net of tax
$
(21,593
)
$
(30,907
)


14


Puget Sound Energy
(Dollars in Thousands)
June 30,
2012
December 31,
2011
Net unrealized loss on energy derivative instruments
$
(8,143
)
$
(12,934
)
Net unrealized loss on treasury interest rate swaps
(6,782
)
(6,941
)
Net unrealized loss and prior service cost on pension plans
(165,061
)
(168,704
)
Total PSE, net of tax
$
(179,986
)
$
(188,579
)

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


(2)
New Accounting Pronouncements

Intangibles - Goodwill and Other
On January 1, 2012, Puget Energy adopted Accounting Standards Update (ASU) 2011-08, Intangibles - Goodwill and Other (Topic 350): Testing Goodwill for Impairment (ASU 2011-08).  ASU 2011-08 allows an entity the option to qualitatively assess whether it must perform the two-step goodwill impairment test in FASB ASC 350-20, Intangibles - Goodwill and Other. An entity has the option to qualitatively assess whether it is more likely than not (more than 50% likelihood) that the fair value of the reporting unit is less than its carrying amount.  If an entity elects to perform the qualitative assessment and determines that it is more likely than not that the reporting unit’s fair value is in excess of its carrying amount, no further evaluation is necessary.  Otherwise, an entity would perform Step 1 of the goodwill impairment test in ASC 350-20.
ASU 2011-08 was effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. ASU 2011-08 did not have a material impact on the financial reporting of Puget Energy.

Comprehensive Income
On January 1, 2012, the Company adopted ASU 2011-05, Comprehensive Income (Topic 220): Presentation of Comprehensive Income (ASU 2011-05). ASU 2011-05 allows an entity the option to present the total of comprehensive income, the components of net income, and the components of OCI either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In both choices, an entity is required to present each component of net income along with total net income, each component of OCI along with a total for OCI, and a total amount for comprehensive income. ASU 2011-05 eliminates the option to present the components of OCI as part of the statement of changes in stockholders' equity. The ASU also requires the presentation of reclassification adjustments for items that are reclassified from OCI to net income on the financial statements.  However, the FASB has deferred this requirement. The amendments to the ASC in the ASU do not change the items that must be reported in OCI or when an item of OCI must be reclassified to net income.
ASU 2011-05 should be applied retrospectively, and was effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.  Prior to the effective date of the ASU, the Company had already complied with the presentation requirement, as the Company presents the total of comprehensive income, the components of net income, and the components of OCI in two separate statements.   Therefore, ASU 2011-05 did not have an impact on the Company’s consolidated financial statements.

Fair Value Measurement
On January 1, 2012, the Company adopted ASU 2011-04, Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS) (ASU 2011-04). ASU 2011-04 represents the converged guidance of the Financial Accounting Standards Board (FASB) and the International Accounting Standards Board on fair value measurement.  Many of the amendments to ASC 820, “Fair Value Measurements and Disclosures” (ASC 820), eliminate unnecessary wording differences between IFRS and GAAP. ASU 2011-04 expands ASC 820’s existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place, and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs.  In addition, ASU 2011-04 requires the Company to indicate the level in the fair value hierarchy of items that are not recorded at fair value but whose fair value must be disclosed.
Other amendments to ASC 820 include clarifying the highest and best use and valuation premise for nonfinancial assets, net risk position fair value measurement option for financial assets and liabilities with offsetting positions in market risks or counterparty credit risk, premiums and discounts in fair value measurement, and fair value of an instrument classified in a reporting entity’s shareholders’ equity.

15


ASU 2011-04 was effective for interim and annual periods beginning after December 15, 2011.  Adoption of ASU 2011-04 did not have a significant impact on the Company’s consolidated financial statements.


(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 balancing PSE's energy portfolio, reducing costs and risks where feasible thus reducing volatility in costs in the portfolio. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into physical and financial transactions which are appropriate for the service territory of PSE and are relevant to its regulated electric and natural gas portfolios.
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.
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 used 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 or periods during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will continue to experience the earnings impact of these reversals from OCI in future periods.
The 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 enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of June 30, 2012, Puget Energy had two interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.
In February 2009, Puget Energy entered into a cash flow hedge using interest rate swaps to hedge the risk associated with one-month London Interbank Offered Rate (LIBOR) floating rate debt. Subsequently, in order to satisfy a commitment the Company made to the Washington Commission and to mitigate interest rate risk, the Company refinanced a portion of the underlying debt hedged by the interest rate swaps in 2010, 2011 and again during 2012. As a result of refinancing in 2010, the Company de-designated the cash flow hedge accounting relationship between the debt and interest rate swaps. A portion of the outstanding interest rate swap derivative loss associated with the probable future interest payments occurring remains in OCI, and is amortized monthly as the payments occur. The portion of the outstanding interest rate swap derivative loss associated with interest payments on the debt where future payments become remote of occurring is reclassified from OCI into earnings.
On June 15, 2012, Puget Energy issued $450.0 million of 10-year senior secured fixed-rate notes and paid down $425.0 million of its outstanding variable rate debt, bringing the balance down to $434.0 million as of June 30, 2012. As the related forecasted transactions (i.e. future interest payments associated with the debt pay down) are now remote of occurring, Puget Energy reclassified a $7.9 million loss from accumulated OCI into earnings. In order to better align its existing swap notional with the reduced balance outstanding under the variable rate senior secured credit facility balance, on June 18, 2012, the Company settled $550.0 million of the interest rate swaps for a $20.2 million loss, thereby reducing the swap notional to $450.0 million. Additionally, the Company amended the remaining two interest rate swap agreements ($450.0 million notional) to extend the maturities to January 2017. This strategy allowed the Company to improve the alignment between the $450.0 million hedge and the variable rate exposure of the remaining balance of $434.0 million of the revolving senior secured credit facility.

16


The following tables present the fair value and locations of the Company's derivative instruments recorded on the balance sheets:

Derivatives Not Designated as Hedging Instruments
Puget Energy
June 30, 2012
December 31, 2011
(Dollars in Thousands)
Assets 1
Liabilities 2
Assets 1
Liabilities 2
Interest rate swaps:
 
 
 
 
Current
$
—

$
6,223

$
—

$
25,210

Long-term
—

13,924

—

27,199

Total interest rate swaps
$
—

$
20,147

$
—

$
52,409

 
 
 
 
 
Puget Energy and Puget Sound Energy
 
 
 
 
Electric portfolio:
 

 

 

 

Current
$
4,031

$
160,033

$
5,212

$
173,582

Long-term
9,523

50,048

5,508

90,752

Natural gas portfolio: 3
 

 

 

 

Current
2,942

110,990

1,435

128,297

Long-term
6,458

49,237

4,576

78,607

Total energy derivatives
$
22,954

$
370,308

$
16,731

$
471,238

___________
1 
Balance sheet location: Unrealized gain on derivative instruments.
2 
Balance sheet location: Unrealized loss on derivative instruments.
3 
PSE had a net derivative liability and an offsetting regulatory asset of $150.8 million at June 30, 2012 and $200.9 million at December 31, 2011 related to financial 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. All increases and decreases in the cost of natural gas supply are passed on to customers with the PGA mechanism and the gains and losses on the hedges in future periods will be recorded as gas costs.

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

The following tables present the net unrealized (gain) loss of the Company's derivative instruments recorded on the statements of income:
Puget Energy
Three Months Ended June 30,
Six Months Ended June 30,
(Dollars in Thousands)
2012
2011
2012
2011
Natural gas / Power NPNS 1
$
—

$
(2,720
)
$
(2,151
)
$
(10,769
)
Natural gas for power generation
(13,647
)
1,261

(13,698
)
(40,262
)
Power
(50,429
)
(15,536
)
(43,501
)
918

Total net unrealized (gain) loss on derivative instruments
$
(64,076
)
$
(16,995
)
$
(59,350
)
$
(50,113
)
Interest expense – interest rate swaps
$
(8,563
)
$
14,171

$
(4,102
)
$
12,245

Other deductions – interest rate swaps
$
925

$
16,126

$
(13,398
)
$
14,326

___________
1 
Amount represents amortization related to contracts that were recorded at fair value as of the date of the merger.

Puget Sound Energy
Three Months Ended June 30,
Six Months Ended June 30,
(Dollars in Thousands)
2012
2011
2012
2011
Natural gas for power generation
$
(13,647
)
$
1,476

$
(13,696
)
$
(23,201
)
Power
(46,203
)
(11,124
)
(36,019
)
7,569

Total net unrealized (gain) loss on derivative instruments
$
(59,850
)
$
(9,648
)
$
(49,715
)
$
(15,632
)


17


The following tables present the effect of hedging instruments on Puget Energy's OCI and statements of income, related to derivatives that were in a previous cash flow hedge relationship:

Puget Energy
(Dollars in Thousands)
Three Months Ended June 30,
Derivatives in Cash Flow Hedging Relationships
Gain (Loss) Recognized
 in OCI on Derivatives
(Effective Portion 1)
Gain (Loss) Reclassified from Accumulated OCI
into Income (Effective Portion 2)
 
2012
2011
Location
2012
2011
Interest rate contracts:
$
—

$
—

Interest expense
$
(10,905
)
$
(24,246
)
Commodity contracts:
Electric derivatives
—

—

Electric generation fuel
—

(20
)
 
 

 

Purchased electricity
(188
)
(252
)
Total
$
—

$
—

 
$
(11,093
)
$
(24,518
)

Puget Energy
(Dollars in Thousands)
Six Months Ended June 30,
Derivatives in Cash Flow Hedging Relationships
Gain (Loss) Recognized
 in OCI on Derivatives
(Effective Portion 1)
Gain (Loss) Reclassified from Accumulated OCI
into Income (Effective Portion 2)
 
2012
2011
Location
2012
2011
Interest rate contracts:
$
—

$
—

Interest expense
$
(14,763
)
$
(30,758
)
Commodity contracts:
Electric derivatives
—

—

Electric generation fuel
100

(50
)
 
 

 

Purchased electricity
12

(510
)
Total
$
—

$
—

 
$
(14,651
)
$
(31,318
)
________
1 
Changes in OCI are reported in after-tax dollars.
2 
A reclassification of a loss in OCI increases accumulated OCI and decreases earnings.  Amounts reported are in pre-tax dollars.

The following tables present the effect of hedging instruments on PSE's OCI and statements of income, related to derivatives that were in a previous cash flow hedge relationship:

Puget Sound Energy
(Dollars in Thousands)
Three Months Ended June 30,
Derivatives in Cash Flow Hedging Relationships
Gain (Loss) Recognized
 in OCI on Derivatives 
(Effective Portion 1)
Gain (Loss) Reclassified from Accumulated OCI
into Income (Effective Portion 2)
 
2012
2011
Location
2012
2011
Interest rate contracts:
$
—

$
—

Interest expense
$
(122
)
$
(123
)
Commodity contracts:
Electric derivatives
—

—

Electric generation fuel
(4,414
)
(237
)
 
 

 

Purchased electricity
—

(4,663
)
Total
$
—

$
—

 
$
(4,536
)
$
(5,023
)


18


Puget Sound Energy
(Dollars in Thousands)
Six Months Ended June 30,
Derivatives in Cash Flow Hedging Relationships
Gain (Loss) Recognized
 in OCI on Derivatives 
(Effective Portion 1)
Gain (Loss) Reclassified from Accumulated OCI
into Income (Effective Portion 2)
 
2012
2011
Location
2012
2011
Interest rate contracts:
$
—

$
—

Interest expense
$
(244
)
$
(246
)
Commodity contracts:
Electric derivatives
—

—

Electric generation fuel
97

(17,109
)
 
 

 

Purchased electricity
(7,468
)
(7,159
)
Total
$
—

$
—

 
$
(7,615
)
$
(24,514
)
___________
1 
Changes in OCI are reported in after-tax dollars.
2 
A reclassification of a loss in OCI increases accumulated OCI and decreases earnings.  Amounts reported are in pre-tax dollars.

For derivative instruments designated as cash flow hedges, the effective portion of the gain or loss on the derivative was reported as a component of OCI, then reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Puget Energy expects that $6.1 million of losses in accumulated OCI will be reclassified into earnings within the next twelve months. PSE expects that $8.3 million of losses in accumulated OCI will be reclassified into earnings within the next twelve months. The maximum length of time over which the Company is hedging its exposure to the variability in future cash flows extends to June 2015 for purchased electricity contracts, October 2018 for gas for power generation contracts and January 2017 for interest rate swaps.
The following tables present the effect of the Company's derivatives not designated as hedging instruments on income:
Puget Energy
 
Three Months Ended June 30,
Six Months Ended June 30,
(Dollars in Thousands)
Location
2012
2011
2012
2011
Interest rate contracts:
Other deductions
$
(7,297
)
$
(25,412
)
$
(6,770
)
$
(25,460
)
 
Interest expense
(9,902
)
(22,699
)
(19,264
)
(27,276
)
Commodity contracts:
 
 

 

 

 

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

14,275

57,199

39,344

 
Electric generation fuel
(2,981
)
(8,808
)
(25,974
)
(49,622
)
 
Purchased electricity
(39,540
)
(19,158
)
(84,953
)
(33,830
)
Total gain (loss) recognized in income on derivatives
 
$
4,356

$
(61,802
)
$
(79,762
)
$
(96,844
)
___________
1 
Differs from the amounts stated in the statements of income as it does not include amortization related to contracts that were recorded at fair value at the time of the February 2009 merger and subsequently designated as NPNS of $0.0 million and $2.2 million for the three and six months ended June 30, 2012 and $2.7 million and $10.8 million for the three and six months ended June 30, 2011, respectively.
Puget Sound Energy
 
Three Months Ended June 30,
Six Months Ended June 30,
(Dollars in Thousands)
Location
2012
2011
2012
2011
Commodity contracts:
 
 
 
 
 
Electric derivatives
Unrealized gain (loss) on derivative instruments, net
$
59,850

$
9,648

$
49,715

$
15,632

 
Electric generation fuel
(2,981
)
(8,808
)
(25,974
)
(49,622
)
 
Purchased electricity
(39,540
)
(19,158
)
(84,953
)
(33,830
)
Total gain (loss) recognized in income on derivatives
 
$
17,329

$
(18,318
)
$
(61,212
)
$
(67,820
)


19


The Company had the following outstanding interest rate and commodity contracts as of June 30, 2012:

Derivatives not designated as hedging instruments:
Number of Units
Puget Energy:
 
Interest rate swaps

$450.0
 million
Puget Energy and Puget Sound Energy:
 

Natural gas derivatives
508,805,338
 MMBtus
Electric generation fuel
137,635,000
 MMBtus
Purchased electricity
11,629,550
 MWhs

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 problems. 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, 2012, 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.
The Company generally enters into the following master agreements: (1) WSPP, Inc. (WSPP) agreements - 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 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 and coming up with 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, 2012, 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. Despite its net liability position, PSE was not required to post any additional collateral with any of its counterparties. Additionally, PSE did not trigger any collateral requirements with any of its counterparties nor were any of PSE's counterparties required to post additional collateral resulting from credit rating downgrades.
As of June 30, 2012, the Company did not have any outstanding energy supply contracts with counterparties that contained credit risk related contingent features, which could result in a counterparty requesting immediate payment or demanding immediate and ongoing full overnight collateralization on derivative instruments in a net liability position.

20


The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at June 30, 2012:

Puget Energy and Puget Sound Energy
Contingent Feature
(Dollars in Thousands)
Fair Value 1
Liability
Posted
Collateral
Contingent
Collateral
Credit rating 2
$
(37,833
)
$
—

$
37,833

Requested credit for adequate assurance
(74,936
)
—

—

Forward value of contract 3
(12,093
)
—

—

Total
$
(124,862
)
$
—

$
37,833

__________
1 
Represents the derivative fair value of contracts with contingent features for counterparties in net derivative liability positions at June 30, 2012. Excludes NPNS, accounts payable and accounts receivable.
2 
Failure by PSE to maintain an investment grade credit rating from each of the major credit rating agencies provides counterparties a contractual right to demand collateral.
3 
Collateral requirements may vary, based on changes in the forward value of underlying transactions relative to contractually defined collateral thresholds.


(4)
Fair Value

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

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

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

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

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

21


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

Assets and Liabilities with Estimated Fair Value

The following table presents the fair value hierarchy by level, the carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.
Puget Energy
Carrying / Fair Value
At June 30, 2012
Carrying / Fair Value
At December 31, 2011
(Dollars in Thousands)
Level 1
Level 2
Level 3
     Total
Level 1
Level 2
Level 3
     Total
Assets:
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
$
1,314

$
14,819

$
—

$
16,133

$
14,809

$
22,426

$
—

$
37,235

Restricted Cash
1,174

2,370

—

3,544

2,043

2,140

—

4,183

Notes Receivable and Other
—

65,883

—

65,883

—

73,031

—

73,031

Total assets
$
2,488

$
83,072

$
—

$
85,560

$
16,852

$
97,597

$
—

$
114,449

Liabilities:
 
 
 
 
 
 
 
 
Short Term Debt
$
—

$
38,000

$
—

$
38,000

$
—

$
25,000

$
—

$
25,000

Total liabilities
$
—

$
38,000

$
—

$
38,000

$
—

$
25,000

$
—

$
25,000


Puget Sound Energy
Carrying / Fair Value
At June 30, 2012
Carrying / Fair Value
At December 31, 2011
(Dollars in Thousands)
Level 1
Level 2
Level 3
     Total
Level 1
Level 2
Level 3
     Total
Assets:
 
 
 
 
 
 
 
 
Cash and Cash Equivalents
$
200

$
14,430

$
—

$
14,630

$
9,200

$
21,810

$
—

$
31,010

Restricted Cash
1,174

2,370

—

3,544

2,043

2,140

—

4,183

Notes Receivable and Other
—

65,883

—

65,883

—

73,031


73,031

Total assets
$
1,374

$
82,683

$
—

$
84,057

$
11,243

$
96,981

$
—

$
108,224

Liabilities:
 
 
 
 
 
 
 
 
Short Term Debt
$
—

$
38,000

$
—

$
38,000

$
—

$
25,000

$
—

$
25,000

Short Term Debt owed to parent
—

29,998

—

29,998

—

29,998

—

29,998

Total liabilities
$
—

$
67,998

$
—

$
67,998

$
—

$
54,998

$
—

$
54,998



22


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, 2012
December 31, 2011
(Dollars in Thousands)
Level
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Liabilities:
 
 
 
 
 
Junior subordinated notes
2
$
250,000

$
252,313

$
250,000

$
248,583

Long-term debt (fixed-rate), net of discount
2
4,653,633

6,077,979

4,197,511

5,503,571

Long-term debt (variable-rate), net of discount
2
434,000

434,000

829,856

856,978

     Total
 
$
5,337,633

$
6,764,292

$
5,277,367

$
6,609,132

 
 
 
 
 
 
Puget Sound Energy
 
June 30, 2012
December 31, 2011
(Dollars in Thousands)
Level
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Liabilities:
 
 
 
 
 
Junior subordinated notes
2
$
250,000

$
252,313

$
250,000

$
248,583

Long-term debt (fixed-rate), net of discount
2
3,523,846

4,606,220

3,523,845

4,499,295

     Total
 
$
3,773,846

$
4,858,533

$
3,773,845

$
4,747,878


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, 2012 and 2011.

Puget Energy
Fair Value
Fair Value
At June 30, 2012
At December 31, 2011
(Dollars in Thousands)
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets:
 
 
 
 
 
 
 
 
Electric derivative instruments
$
—

$
4,116

$
9,438

$
13,554

$
—

$
2,340

$
8,380

$
10,720

Natural gas derivative instruments
—

3,375

6,025

9,400

—

—

6,011

6,011

Total derivative assets
$
—

$
7,491

$
15,463

$
22,954

$
—

$
2,340

$
14,391

$
16,731

Liabilities:
 

 

 

 

 

 

 

 

Electric derivative instruments
$
—

$
120,190

$
89,891

$
210,081

$
—

$
165,643

$
98,691

$
264,334

Natural gas derivative instruments
—

151,383

8,844

160,227

—

195,852

11,052

206,904

Interest rate derivative instruments
—

20,147

—

20,147

—

52,409

—

52,409

Total derivative liabilities
$
—

$
291,720

$
98,735

$
390,455

$
—

$
413,904

$
109,743

$
523,647



23


Puget Sound Energy
Fair Value
Fair Value
At June 30, 2012
At December 31, 2011
(Dollars in Thousands)
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets:
 
 
 
 
 
 
 
 
Electric derivative instruments
$
—

$
4,116

$
9,438

$
13,554

$
—

$
2,340

$
8,380

$
10,720

Natural gas derivative instruments
—

3,375

6,025

9,400

—

—

6,011

6,011

Total assets
$
—

$
7,491

$
15,463

$
22,954

$
—

$
2,340

$
14,391

$
16,731

Liabilities:
 

 

 

 

 

 

 

 

Electric derivative instruments
$
—

$
120,190

$
89,891

$
210,081

$
—

$
165,643

$
98,691

$
264,334

Natural gas derivative instruments
—

151,383

8,844

160,227

—

195,852

11,052

206,904

Total liabilities
$
—

$
271,573

$
98,735

$
370,308

$
—

$
361,495

$
109,743

$
471,238


Puget Energy and
Puget Sound Energy
Three Months Ended June 30,
Level 3 Roll-Forward Net (Liability)
2012
2011
(Dollars in Thousands)
Electric
Gas
Total
Electric
Gas
Total
Balance at beginning of period
$
(107,364
)
$
(3,167
)
$
(110,531
)
$
(89,758
)
$
(1,785
)
$
(91,543
)
Changes during period
 
 
 
 
 
 
Realized and unrealized energy derivatives:
 
 
 
 
 
 
Included in earnings 1
5,077

—

5,077

(4,244
)
—

(4,244
)
Included in regulatory assets / liabilities
—

(4
)
(4
)
—

1,860

1,860

Settlements 3
14,372

324

14,696

8,234

(1,127
)
7,107

Transferred into Level 3
(38,674
)
(297
)
(38,971
)
—

363

363

Transferred out of Level 3
46,136

325

46,461

4,475

445

4,920

Balance at end of period
$
(80,453
)
$
(2,819
)
$
(83,272
)
$
(81,293
)
$
(244
)
$
(81,537
)

Puget Energy and
Puget Sound Energy
Six Months Ended June 30,
Level 3 Roll-Forward Net (Liability)
2012
2011
(Dollars in Thousands)
Electric
Gas
Total
Electric
Gas
Total
Balance at beginning of period
$
(90,311
)
$
(5,041
)
$
(95,352
)
$
(87,436
)
$
(3,859
)
$
(91,295
)
Changes during period:
 
 
 
 
 
 
Realized and unrealized energy derivatives:
 
 
 
 
 
 
Included in earnings 2
(16,870
)
—

(16,870
)
(19,951
)
—

(19,951
)
Included in regulatory assets / liabilities
—

(1,287
)
(1,287
)
—

2,979

2,979

Settlements 3
35,415

105

35,520

19,139

(1,592
)
17,547

Transferred into Level 3
(55,548
)
(297
)
(55,845
)
—

363

363

Transferred out of Level 3
46,861

3,701

50,562

6,955

1,865

8,820

Balance at end of period
$
(80,453
)
$
(2,819
)
$
(83,272
)
$
(81,293
)
$
(244
)
$
(81,537
)
__________
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 $6.2 million and $(5.0) million for the three months ended June 30, 2012 and 2011, 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 $(12.8) million and $(17.5) million for the six months ended June 30, 2012 and 2011, respectively.
3 
The Company had no purchases, sales or issuances during the reported periods.

24



Realized gains and losses on energy derivatives for Level 3 recurring items are included in energy costs in the Company's consolidated statements of income under purchased electricity, electric generation fuel or purchased natural gas when settled. Unrealized gains and losses on energy derivatives for Level 3 recurring items are included in net unrealized (gain) loss on derivative instruments in the Company's consolidated statements of income.
In order to determine which assets and liabilities are classified as Level 3, the Company receives market data from its independent external pricing service defining the tenor of observable market quotes. To the extent any of the Company's commodity contracts extend beyond what is considered observable as defined by its independent pricing service, the contracts are classified as Level 3. The actual tenor of what the independent pricing service defines as observable is subject to change depending on market conditions. Therefore, as the market changes, the same contract may be designated Level 3 one month and Level 2 the next, and vice versa. The changes of fair value classification into or out of Level 3 are recognized each month, and reported in the Level 3 Roll-forward table above. The Company does periodically transact at locations, or market price points, that are illiquid or for which no prices are available from the independent pricing service. In such circumstances the Company uses a more liquid price point and performs a 15-month regression against the illiquid locations to serve as a proxy for market prices. Such transactions are classified as Level 3. The Company does not use internally developed models to make adjustments to significant unobservable pricing inputs. The only significant unobservable input into the fair value measurement of the Company's Level 3 assets and liabilities is the forward price for electric and natural gas contracts. Below are the forward price ranges for the Company's purchased commodity contracts, as of June 30, 2012:
(Dollars in Thousands)
 
 
 
 
 

Fair Value
 
 
Range
 
Derivative Instrument
Assets 1
Liabilities 1
Valuation Technique
Unobservable Input
Low
High
 Weighted Average
Electric
$9,438
$89,891
Discounted cash flow
Power Prices
$6.11 per MWh
$46.86 per MWh
$29.93 per MWh
Natural gas
$6,025
$8,844
Discounted cash flow
Natural Gas Prices
$1.77 per MMBtu
$4.79 per MMBtu
$3.88 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, 2012, 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 $18.7 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 on-going basis, whenever events or circumstances would more likely than not reduce the fair value of the long-lived assets below its carrying value. One such triggering event is a significant decrease in market price.
Due to decreasing forward wholesale market prices at March 31, 2012, Puget Energy completed a valuation and impairment test for long-term power purchase contracts, and the valuation indicated impairment to one of the purchased power contracts. As of March 31, 2012, the carrying value for the intangible asset contract was $113.3 million and its fair value on a discounted basis was determined to be $96.7 million, thereby requiring a $16.6 million write-off of the intangible asset with a corresponding reduction in the regulatory liability.

25


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 the quarterly significant unobservable inputs used in estimating the long-term power purchase contracts' fair value of $513.6 million during the period ended March 31, 2012:

Valuation Technique
Unobservable Input
Low
High
Weighted Average
Discounted cash flow
Power prices
$10.36 per MWh
$49.78 per MWh
$34.98 per MWh
Discounted cash flow
Power contract costs (in thousands)
$3,185 per qtr
$5,030 per qtr
$4,663 per qtr


(5)
Retirement Benefits

PSE has a defined benefit pension plan covering substantially all PSE employees.  Pension benefits earned are a function of age, salary, years of service and, in the case of employees in the cash balance formula plan, the applicable annual interest crediting rates.  PSE also maintains a non-qualified Supplemental Executive Retirement Plan (SERP) for its key senior management employees.  In addition to providing pension benefits, PSE provides group health care and life insurance benefits for certain retired employees.  These benefits are provided principally through an insurance company.  The insurance premiums, paid primarily by retirees, are based on the benefits provided during the year.
The February 6, 2009 merger of Puget Energy with Puget Holdings triggered a new basis of accounting for PSE’s retirement benefit plans in the Puget Energy consolidated financial statements.  Such purchase accounting adjustments associated with the remeasurement of the retirement plans are recorded at Puget Energy.
The following tables summarize the Company’s net periodic benefit cost for the three and six months ended June 30, 2012 and 2011:
Puget Energy
 
 
 
Three Months Ended June 30,
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands)
2012
2011
2012
2011
2012
2011
Components of net periodic benefit cost:
 
 
 
 
 
 
Service cost
$
4,229

$
4,059

$
268

$
310

$
32

$
31

Interest cost
6,551

6,630

538

548

188

204

Expected return on plan assets
(9,101
)
(8,860
)
—

—

(109
)
(125
)
Amortization of prior service
cost
(495
)
(495
)
—

—

—

—

Amortization of net loss
(gain)
234

—

176

90

17

1

Net periodic benefit cost
$
1,418

$
1,334

$
982

$
948

$
128

$
111




26


Puget Energy
 
 
 
Six Months Ended June 30,
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands)
2012
2011
2012
2011
2012
2011
Components of net periodic benefit cost:






Service cost
$
8,463

$
8,119

$
537

$
620

$
70

$
62

Interest cost
12,993

13,259

1,076

1,096

375

409

Expected return on plan assets
(18,102
)
(17,720
)
—

—

(218
)
(250
)
Amortization of prior service
cost
(990
)
(990
)
—

—

—

—

Amortization of net loss
(gain)
384

—

351

180

27

1

Net periodic benefit cost
$
2,748

$
2,668

$
1,964

$
1,896

$
254

$
222


Puget Sound Energy
 
 
 
Three Months Ended June 30,
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands)
2012
2011
2012
2011
2012
2011
Components of net periodic benefit cost:
 
 
 
 
 
 
Service cost
$
4,229

$
4,059

$
268

$
310

$
32

$
31

Interest cost
6,551

6,630

538

548

188

204

Expected return on plan assets
(10,434
)
(11,056
)
—

—

(109
)
(125
)
Amortization of prior service
cost
(393
)
(394
)
74

141

9

16

Amortization of net loss
(gain)
3,790

2,695

358

298

(63
)
(109
)
Amortization of transition
obligation
—

—

—

—

12

13

Net periodic benefit cost
$
3,743

$
1,934

$
1,238

$
1,297

$
69

$
30


Puget Sound Energy
 
Six Months Ended June 30,
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
(Dollars in Thousands)
2012
2011
2012
2011
2012
2011
Components of net periodic benefit cost:
 
 
 
 
 
 
Service cost
$
8,463

$
8,119

$
537

$
620

$
70

$
62

Interest cost
12,993

13,259

1,076

1,096

375

409

Expected return on plan assets
(20,767
)
(22,112
)
—

—

(217
)
(250
)
Amortization of prior service
cost
(787
)
(786
)
146

281

18

31

Amortization of net loss
(gain)
7,508

5,389

716

598

(123
)
(217
)
Amortization of transition
obligation
—

—

—

—

25

25

Net periodic benefit cost
$
7,410

$
3,869

$
2,475

$
2,595

$
148

$
60


27



The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2012 and December 31, 2011:

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,
2012
December 31,
2011
June 30,
2012
December 31,
2011
June 30,
2012
December 31,
2011
Change in benefit obligation:






Benefit obligation at beginning of period
$
565,997

$
532,615

$
48,370

$
44,322

$
16,436

$
16,579

Service cost
8,463

15,822

537

1,241

70

113

Interest cost
12,993

26,263

1,076

2,192

375

807

Actuarial loss/(gain)
2,030

18,485

—

4,467

(132
)
384

Benefits paid
(20,950
)
(27,188
)
(4,271
)
(2,687
)
(866
)
(1,855
)
Medicare part D subsidiary
received
—

—

—

—

505

408

Curtailment loss/(gain)1
—

—

—

(1,165
)
—

—

Benefit obligation at end of period
$
568,533

$
565,997

$
45,712

$
48,370

$
16,388

$
16,436

__________
1 
A curtailment gain was recognized in OCI due to the plan amendment that ceased SERP benefits for non-officers still in the plan as of December 31, 2011.

The fair value of the Company’s qualified pension plan assets was $498.7 million and $479.8 million at June 30, 2012 and December 31, 2011, 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, 2012 are expected to be at least $18.8 million, $6.1 million and $0.9 million, respectively. During the three months ended June 30, 2012, the Company contributed $5.7 million, $0.4 million and $0.1 million to fund the qualified pension plan, SERP and the other postretirement plan, respectively. During the six months ended June 30, 2012, the Company contributed $11.4 million, $4.3 million and $0.5 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 9.80%.
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 over-recovery of commodity costs in the Company's PGA commodity account. The 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.


(7)
Litigation

Residential Exchange. The Northwest Power Act, through the Residential Exchange Program (REP), provides access to the benefits of low-cost federal hydroelectric power to 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)

28


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 U.S. Court of Appeals for the 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 the fiscal year 2002-fiscal year 2011 period. In October 2011, certain other parties challenged BPA decisions with regard to its entering into this most recent settlement agreement. Pending disposition of this challenge, the other pending Ninth Circuit litigation regarding REP benefits for the fiscal year 2002 through fiscal year 2011 period 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.

Pacific Northwest Refund Proceeding. In October 2000, PSE filed a complaint with the FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result the FERC ordered for the California markets. The FERC issued an order including price caps in July 2001, and PSE moved to dismiss the proceeding. In response to PSE's motion, various entities intervened and sought to convert PSE's complaint into one seeking retroactive refunds in the Pacific Northwest. The FERC rejected that effort, after holding what the FERC referred to as a “preliminary evidentiary hearing” before an administrative law judge. On October 3, 2011, after appellate reviews, the FERC issued an Order on Remand and set the matter for hearing before an administrative law judge, but first requiring the parties to engage in settlement talks that began in the fall of 2011 and are ongoing. On July 2, 2012 PSE and one of the parties to the refund proceeding (Tacoma) filed a settlement as to Tacoma's claims against PSE, under which PSE will pay Tacoma for a full release. Seattle City Light and the Port of Seattle are the other parties that have asserted claims against PSE. PSE cannot predict whether settlement with those parties can be achieved. The hearing as to all unresolved claims is expected to begin in April 2013. PSE has not taken any reserve on this matter as it believes it has no exposure, and intends to vigorously defend its position but is unable to predict the outcome of this matter.

Other Proceedings. The Company is also involved in litigation relating to claims arising out of its operations in the normal course of business. The Company has recorded reserves of $3.6 million and $2.6 million relating to these claims as of June 30, 2012 and 2011, respectively.


(8)
Other

Bond Issuances. On June 15, 2012, Puget Energy issued $450.0 million of senior secured notes. The notes are secured by substantially all of Puget Energy's assets, which consist primarily of the equity interests it holds in PSE. The notes mature on July 15, 2022 and have an interest rate of 5.625%. Net proceeds from the note offering were used by Puget Energy to pay down $425.0 million of the $859.0 million balance outstanding on a five-year $1.0 billion revolving senior secured credit facility put in place in February 2012. As of June 30, 2012, the balance on the senior secured credit facility was $434.0 million.

Allowance for Funds Used During Construction (AFUDC).  AFUDC represents the cost of both debt and equity funds used to finance utility plant additions during the construction period.  The amount of AFUDC recorded in each accounting period varies depending principally upon the level of construction work in progress and the AFUDC rate used.  AFUDC is capitalized as a part of the cost of utility plant and is credited to interest expense and as a non-cash item to other income.  Cash inflow related to AFUDC does not occur until these charges are reflected in rates.
The AFUDC rates authorized by the Washington Commission for natural gas and electric utility plant additions is 7.8% which was effective May 14, 2012.
The Washington Commission authorized the Company to calculate AFUDC using its allowed rate of return.  To the extent amounts calculated using this rate exceed the AFUDC calculated rate using the FERC formula, PSE capitalizes the excess as a deferred asset, crediting other income.  The deferred asset is amortized over the average useful life of PSE’s non-project electric utility plant, which is approximately 30 years.

29


The following table presents the Company’s AFUDC amounts:
 
Three Months Ended June 30,
Six Months Ended June 30,
(Dollars in Thousands)
2012
2011
2012
2011
Equity AFUDC
$
5,179

$
8,299

$
14,485

$
12,033

Washington Commission AFUDC
178

365

319

4,271

Total in other income
5,357

8,664

14,804

16,304

Debt AFUDC
4,687

7,597

11,982

12,001

Total AFUDC
$
10,044

$
16,261

$
26,786

$
28,305


    

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, 2011. 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, Macquarie-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.”
PSE generates revenue and cash flow primarily from the sale of electric and natural gas services to residential and commercial customers within a service territory covering approximately 6,000 square miles, principally in the Puget Sound region of the state of Washington. To meet customer growth, to replace expiring power contracts and to meet Washington state's renewable energy portfolio standards, PSE is increasing energy efficiency programs to reduce the demand for additional energy generation and is pursuing additional renewable energy production resources (primarily wind) and base load natural gas-fired generation. The Company's external financing requirements principally reflect the cash needs of its construction program, its schedule of maturing debt and certain operational needs. PSE requires access to bank and capital markets to meet its financing needs.
For the three and six months ended June 30, 2012 as compared to the same period in 2011, PSE's net income was affected by the following factors: (1) a decrease in electric and natural gas retail sales (2) lower power costs; (3) an increase in utility operations and maintenance primarily due to an increase in storm related expenses; and (4) an increase in unrealized gain in derivatives instruments for energy contracts.

30


For the three and six months ended June 30, 2012 as compared to the same period in 2011, Puget Energy's net income was affected by PSE as noted above and the following factors: (1) an increase in interest expense on Puget Energy debt due to write-off of unamortized debt costs, mark-to-market on interest rate swap contracts and higher interest costs; and (2) higher gain on energy derivative instruments due to purchase accounting.
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 2012 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 also tend to reduce energy sales. The principal business, economic and other factors that affect PSE's operations and financial performance include:

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

Regulation of PSE Rates and Recovery of PSE Costs. The rates that PSE is allowed to charge for its services influence its financial condition, results of operations and liquidity. PSE is highly regulated and the rates that it charges its retail customers are approved by the Washington Utilities and Transportation Commission (Washington Commission). The Washington Commission requires these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically do not provide sufficient revenue to cover year-to-year cost growth, thus rate increases are required. If, in a particular year, PSE's costs are higher than what is 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.

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
%


31


PSE had a favorable PCA imbalance for the three and six months ended June 30, 2012, which was $26.4 million and $58.0 million, respectively, below the “power cost baseline” level, of which $20.4 million and $26.2 million, respectively, was apportioned to customers. This compares to a favorable imbalance for the three and six months ended June 30, 2011 of $24.0 million and $30.4 million, respectively, of which $4.2 million and $5.2 million, respectively, was apportioned to customers.    
On January 6, 2012, PSE filed an electric transmission rate case with Federal Energy Regulatory Commission (FERC) as well as an increase in ancillary service charges. PSE requested a rate increase of $3.8 million with an effective date of April 1, 2012. On March 30, 2012, FERC issued an order setting for hearing PSE's formula transmission rate filing. PSE's proposed reclassification of facilities and formula rate for network and point-to-point service on the Washington area facilities have been suspended for five months until September 1, 2012. PSE's proposed formula rate decrease for service on the Colstrip and Southern Intertie lines have been accepted and placed into effect April 1, 2012 subject to refund if rates should be lower. The initial settlement conference was held on May 3, 2012. Settlement discussions are proceeding.
On May 7, 2012, the Washington Commission issued its order in PSE's electric general rate case filed in June 2011, approving a general rate increase for electric customers of $63.3 million or 3.2% annually. The rate increases for electric 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%.

Natural Gas Rates
PSE has a Purchased Gas Adjustment (PGA) mechanism in retail natural gas rates to recover variations in natural gas supply and transportation costs. Variations in natural gas rates are passed through to customers; therefore, PSE's net income is not affected by such variations. Changes in the PGA rates affect PSE's revenue, but do not impact net income as the changes to revenue are offset by increased or decreased purchased gas and gas transportation costs. The following table sets forth natural gas rate adjustments approved by the Washington Commission and the corresponding impact to PSE's annual revenue based on the effective dates:
Type of Rate
Adjustment
Effective
Date
Average Percentage
Increase (Decrease)
in Rates
Annual Increase
(Decrease) in Revenue
(Dollars in Millions)
Gas General Rate Case
May 14, 2012
1.3
 %
$
13.4

Purchased Gas Adjustment
November 1, 2011
(4.3
)
(43.5
)
Natural Gas General Tariff Adjustment
April 1, 2011
1.8

19.0


On May 7, 2012, the Washington Commission issued its order in PSE's natural gas general rate case filed in June 2011, approving a general rate increase for natural gas customers of $13.4 million or 1.3% annually. The rate increases for 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 over-recovery of commodity costs in the Company's PGA commodity account. The 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.
Weather Conditions. Weather conditions in PSE's service territory have a significant impact on customer energy usage, affecting PSE's revenue and energy supply expenses. PSE's operating revenue and associated energy supply expenses are not generated evenly throughout the year. While both PSE's electric and natural gas sales are generally greatest during winter months, variations in energy usage by customers occur from season to season and month to month within a season, primarily as a result of weather conditions. PSE normally experiences its highest retail energy sales, and subsequently higher power costs, during the winter heating season in the first and fourth quarters of the year and its lowest sales in the third quarter of the year. Varying wholesale electric prices and the amount of hydroelectric energy supplies available to PSE also make quarter-to-quarter comparisons difficult. PSE reported lower customer usage in the six months ended June 30, 2012 primarily due to Pacific Northwest temperatures being warmer as compared to the same period in the prior year. The actual average temperature during the six months ended June 30, 2012 was 48.2 degrees, or 1.24 degrees warmer than the same period in the prior year. Although, the temperature during the six months ended June 30, 2012 was warmer than the same period in the prior year, the temperature is 1.66 cooler than the historical average.

32


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 due to continued energy efficiency improvements and the effect of higher retail rates.
Access to Debt Capital. PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term debt 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 due to increase in credit spreads and commitment fees increase as their respective credit ratings decline. 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 2014 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” included below).
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 exceed current resources from long-term power purchase agreements and Company-controlled power resources. The IRP identifies reductions in contractual supplies of energy and capacity available under certain long-term power purchase agreements, requiring replacement of supplies to meet projected demands. Therefore, PSE's IRP sets forth a multi-part strategy of implementing energy efficiency programs and pursuing additional renewable resources (primarily wind) and additional base load natural gas-fired generation to meet the growing needs of its customers. If PSE cannot acquire needed energy supply resources at a reasonable cost, it may be required to purchase additional power in the open market at a cost that could, in the absence of regulatory relief, significantly increase its expenses and reduce earnings and cash flows.
Infrastructure Investment. PSE is investing in its utility infrastructure and customer service functions in order to meet regulatory requirements, serve customers' energy needs and replace aging infrastructure. These investments and operating requirements give rise to significant growth in depreciation, amortization and operating expenses, which are not recovered through the ratemaking process in a timely manner. This “regulatory lag” is expected to continue for the foreseeable future.
Operational Risks Associated With Generating Facilities. PSE owns and operates coal, natural gas-fired, hydroelectric, wind-powered, solar and oil-fired generating facilities. Operation of electric generating facilities involves risks that can adversely affect energy output and efficiency levels, including facility shutdowns due to equipment and process failures or fuel supply interruptions. PSE does not have business interruption insurance coverage to cover replacement power costs.
Energy Efficiency Related Lost Sales Margin. PSE's sales, margins, earnings and cash flow are adversely affected by its energy efficiency programs, many of which are mandated by law. The Company is evaluating strategies and other means to reduce or eliminate these adverse financial effects.
Markets For Intangible Power Attributes. The Company is actively engaged in monitoring the development of the commercial markets for such intangible power attributes as Renewable Energy Credits (RECs) and carbon financial instruments. The Company supports the development of regional and national markets for these products that are open, transparent and liquid.









33


Results of Operations
Puget Sound Energy
The following discussion should be read in conjunction with the unaudited consolidated financial statements and the related notes included elsewhere in this document. The following discussion provides the significant items that impacted PSE's results of operations:
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
Puget Sound Energy
(Dollars in Thousands)
2012
2011
Favorable/
(Unfavorable)
2012
2011
Favorable/
(Unfavorable)
Operating revenue:
 
 
 
 
 
 
Electric
 
 
 
 
 
 
Residential sales
$
251,735

$
266,097

(5.4
)%
$
614,214

$
635,413

(3.3
)%
Commercial sales
198,621

198,732

(0.1
)%
428,813

429,216

(0.1
)%
Industrial sales
25,905

25,889

0.1
 %
53,857

53,384

0.9
 %
Other retail sales, including unbilled revenue
(9,996
)
(9,496
)
(5.3
)%
(25,126
)
(32,309
)
(22.2
)%
Total retail sales
466,265

481,222

(3.1
)%
1,071,758

1,085,704

(1.3
)%
Transportation sales
2,463

2,298

7.2
 %
4,935

4,839

2.0
 %
Sales to other utilities and marketers
1,390

5,495

(74.7
)%
8,436

14,443

(41.6
)%
Other
393

(1,294
)
130.4
 %
(3,091
)
(17,532
)
82.4
 %
Total electric operating revenue
470,511

487,721

(3.5
)%
1,082,038

1,087,454

(0.5
)%
Gas
 

 

 
 

 

 

Residential sales
129,641

155,350

(16.5
)%
426,436

436,965

(2.4
)%
Commercial sales
63,972

74,712

(14.4
)%
184,851

193,281

(4.4
)%
Industrial sales
6,933

7,621

(9.0
)%
17,818

18,697

(4.7
)%
Total retail sales
200,546

237,683

(15.6
)%
629,105

648,943

(3.1
)%
Transportation sales
3,752

3,662

2.5
 %
7,673

7,388

3.9
 %
Other
3,525

3,669

(3.9
)%
7,011

7,307

(4.1
)%
Total gas operating revenue
207,823

245,014

(15.2
)%
643,789

663,638

(3.0
)%
Non-utility operating revenue
283

629

(55.0
)%
1,302

1,865

(30.2
)%
Total operating revenue
678,617

733,364

(7.5
)%
1,727,129

1,752,957

(1.5
)%
Operating expenses:
 

 

 
 

 

 

Energy costs:
 

 

 
 

 

 

Purchased electricity
156,098

180,166

13.4
 %
355,213

408,207

13.0
 %
Electric generation fuel
19,861

25,886

23.3
 %
89,798

71,109

(26.3
)%
Residential exchange
(15,302
)
(15,293
)
0.1
 %
(38,637
)
(36,975
)
4.5
 %
Purchased gas
96,462

127,174

24.1
 %
329,981

363,928

9.3
 %
Net unrealized (gain) loss on derivative instruments
(59,850
)
(9,648
)
*

(49,715
)
(15,632
)
*

Utility operations and maintenance
128,195

123,852

(3.5
)%
256,241

241,820

(6.0
)%
Non-utility expense and other
2,270

2,533

10.4
 %
5,500

5,880

6.5
 %
Depreciation
84,552

73,579

(14.9
)%
163,558

148,361

(10.2
)%
Amortization
11,547

18,450

37.4
 %
24,890

36,423

31.7
 %
Conservation amortization
28,518

23,871

(19.5
)%
62,921

56,084

(12.2
)%
Taxes other than income taxes
72,960

75,414

3.3
 %
172,830

175,935

1.8
 %
Total operating expenses
525,311

625,984

16.1
 %
1,372,580

1,455,140

(5.7
)%
Operating income (loss)
153,306

107,380

42.8
 %
354,549

297,817

19.0
 %
Other income
18,329

15,677

16.9
 %
33,262

28,211

17.9
 %
Other expense
(1,947
)
(1,278
)
(52.3
)%
(5,700
)
(2,233
)
(155.3
)%
Interest expense
(57,729
)
(50,245
)
(14.9
)%
(111,222
)
(102,511
)
(8.5
)%
Income (loss) before income taxes
111,959

71,534

56.5
 %
270,889

221,284

22.4
 %
Income tax (benefit) expense
31,087

20,621

(50.8
)%
77,301

66,932

(15.5
)%
Net income (loss)
$
80,872

$
50,913

58.8
 %
$
193,588

$
154,352

25.4
 %
__________
* 
Not meaningful

34


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


Electric Margin
Electric margin represents electric sales to retail and transportation customers less pass-through tariff items, revenue-sensitive taxes and 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)
2012
2011
Percent
Change
2012
2011
Percent
Change
Electric operating revenue1
$
470,511

$
487,721

(3.5
)%
$
1,082,038

$
1,087,454

(0.5
)%
Add (less): Other electric operating revenue
(392
)
1,294

(130.3
)
3,092

17,532

*

Less: Other electric operating revenue-gas
     supply resale
(1,381
)
(5,976
)
(76.9
)
(4,578
)
(38,645
)
(88.2
)%
Add (less): Other electric operating revenue-
    RECs & PTCs
(8,854
)
(6,679
)
32.6

(19,199
)
(67
)
*

Total electric revenue for margin
459,884

476,360

(3.5
)
1,061,353

1,066,274

(0.5
)%
Adjustments for amounts included in revenue:
 

 

 

 

 

 

Pass-through tariff items
(22,086
)
(23,351
)
(5.4
)
(51,463
)
(52,963
)
(2.8
)%
Pass-through revenue-sensitive taxes
(35,694
)
(36,371
)
(1.9
)
(81,400
)
(81,817
)
(0.5
)%
Net electric revenue for margin
402,104

416,638

(3.5
)
928,490

931,494

(0.3
)%
Minus power costs:
 

 

 

 

 

 
Purchased electricity1
(156,098
)
(180,166
)
(13.4
)
(355,213
)
(408,207
)
(13.0
)%
Electric generation fuel1
(19,861
)
(25,886
)
(23.3
)
(89,798
)
(71,109
)
26.3
 %
Residential exchange1
15,302

15,293

0.1

38,637

36,975

4.5
 %
Total electric power costs
(160,657
)
(190,759
)
(15.8
)
(406,374
)
(442,341
)
(8.1
)%
Electric margin2
$
241,447

$
225,879

6.9
 %
$
522,116

$
489,153

6.7
 %
______________
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.
* 
Percent change not applicable or meaningful.
Electric margin increased $15.6 million and $33.0 million for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. 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 $17.2 million, or 3.5%, to $470.5 million from $487.7 million for the three months ended June 30, 2012, as compared to the same period in 2011. The decrease in operating revenues of $17.2 million for the three months ended June 30, 2012 was primarily due to lower electric retail sales of $15.0 million, lower sales to other utilities and marketers of $4.1 million, which were offset by higher miscellaneous operating revenues of $1.7 million. These items are discussed in detail below.

35


Electric operating revenues decreased $5.4 million, or 0.5%, to $1,082.0 million from $1,087.5 million for the six months ended June 30, 2012 as compared to the same period in 2011. The decrease in operating revenues of $5.4 million for the six months ended June 30, 2012 was primarily due to lower electric retail sales of $14.0 million, lower sales to other utilities and marketers of $6.0 million, which were offset by higher miscellaneous operating revenues of $14.4 million. These items are discussed in detail below.
Electric retail sales decreased $15.0 million, or 3.1%, to $466.3 million from $481.2 million for the three months ended June 30, 2012, as compared to the same period in 2011. The decrease in electric retail sales was primarily due to a $21.9 million decrease in retail electricity usage of 224,721 Megawatt Hour (MWhs), or 4.6%, as a result of warmer temperatures in PSE's service territory during the three months ended June 30, 2012 as compared to the same period in the prior year. Partially offsetting the decrease was a net increase in retail sales of $6.9 million due to the 3.2% electric rate increase effective May 14, 2012 and various pass through tariff items that have no impact on earnings. The net increase included tariff items, such as, the suspension of REC credits in 2011 which contributed $3.6 million in electric retail sales for the three months ended June 30, 2012. The REC credit to customers is offset in other electric operating revenue with no impact to earnings. PSE's customers received credits effective November 1, 2010 through April 30, 2011.
Electric retail sales decreased $14.0 million, or 1.3%, to $1,071.8 million from $1,085.7 million for the six months ended June 30, 2012, as compared to the same period in 2011. The decrease in electric retail sales was primarily due to a $20.2 million decrease in retail electricity usage of 205,591 MWhs, or 1.9%, as a result of warmer temperatures in PSE's service territory during the six months ended June 30, 2012 as compared to the same period in the prior year. The actual temperature during the six months ended June 30, 2012 was 48.2 degrees, or 1.24 degrees warmer than the same period in the prior year. Although, the temperature during the six months ended June 30, 2012 was warmer than the same period in the prior year, the temperature was 1.66 cooler than the historical average. Partially offsetting the decrease was a $6.2 million net increase in retail sales due to the electric rate increase effective May 14, 2012 and various pass through tariff items that have no impact on earnings. The net increase included tariff items, such as, the suspension of REC credits in 2011 which contributed an increase of $20.2 million in electric retail sales for the six months ended June 30, 2012. The REC credit to customers is offset in other electric operating revenue with no impact to earnings. PSE's customers received credits effective November 1, 2010 through April 30, 2011.
Sales to other utilities and marketers decreased $4.1 million and $6.0 million for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. These decreases were primarily due to a decline in market electricity prices which decreased revenue by $3.6 million and $5.5 million for the three and six months ended June 30, 2012.
Other electric operating revenue increased $1.6 million and $14.4 million for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The increases were primarily due to reductions to revenue offsets due to non-core gas sales of $4.6 million and $34.1 million for the three and six months ended June 30, 2012, respectively, and a reduction to revenue offsets which contributed increases of $19.0 million and $40.1 million, respectively, related to PTCs deferrals, which are deferred until PSE utilizes the tax credit on its tax return. Partially offsetting the increase was a decrease in REC revenue of $21.3 million and $59.3 million for the three and six months ended June 30, 2012, respectively. As discussed above, REC revenue is an offset of the REC credit provided to PSE's customers in electric retail sales with no impact to earnings.
Electric Energy Costs
Purchased electricity expense decreased $24.1 million, or 13.4%, and $53.0 million, or 13.0%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The decrease in purchased electricity expense for the three months ended June 30, 2012 was primarily the result of a decrease of $37.9 million related to the expiration of long-term firm contracts and a $5.4 million decrease related to energy agreements. Offsetting this decrease was a $3.6 million wholesale market offset cost related to Lower Snake River which is being deferred and included in purchased power. Also offsetting the decrease was a $16.2 million increase due to sharing of overrecovery of power costs with customers in accordance with the PCA mechanism customer sharing for the three months ended June 30, 2012, which reduced the customer PCA deferral.
The $53.0 million decrease in purchased electricity expense for the six months ended June 30, 2012 was primarily the result of a decrease of $85.9 million related to the expiration of long-term firm contracts. Offsetting this decrease was a $1.8 million increase related to energy agreements and $8.4 million wholesale market offset cost related to Lower Snake River which is being deferred and included in purchased power. Also offsetting the decrease is a $21.0 million increase due to sharing of overrecovery of power costs with customers in accordance with the PCA mechanism customer sharing for the six months ended June 30, 2012, which reduced the customer PCA deferral.
To meet customer demand, PSE economically dispatches resources in its power supply portfolio such as fossil-fuel generation, owned and contracted hydroelectric capacity and energy and long-term contracted power. However, depending principally upon availability of hydroelectric energy, plant availability, fuel prices and/or changing load as a result of weather, PSE may sell surplus power or purchase deficit power in the wholesale market. PSE manages its regulated power portfolio through short-term and intermediate-term off-system physical purchases and sales as well as through other risk management techniques.
Electric generation fuel expense decreased $6.0 million, or 23.3%, and increased $18.7 million, or 26.3%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. PSE experienced a decrease in electric generation at coal plants of 211,680 MWhs, or 41.2% for the three months ended June 30, 2012. The decrease in coal generation reduced electric generation fuel by $3.7 million for the three months ended June 30, 2012. The decrease in electric generation at

36


coal plants was primarily due to two coal plants that were taken offline for maintenance and remained offline as other sources of electric generation were considered more economical. Contributing to the decrease was $2.4 million due to lower wholesale gas prices related to the electricity generation from PSE's combustion turbine facilities.
For the six months ended June 30, 2012 the increase was primarily due to increased generation from PSE's combustion turbine facilities due to lower hydroelectric generation of 575,776 MWhs, or 13.7%, and the decrease in electric generation at coal plants of 209,687 MWhs, or 12.8%. Although wholesale gas prices were lower, the increased electricity generation from PSE's combustion turbine facilities compared to the same period in the prior year contributed $23.3 million in expense. Offsetting the increase was $4.6 million decrease due to the decrease in coal plant generation. The decrease in electric generation at coal plants was primarily due to two coal plants that were taken offline for maintenance and remained offline as other sources of electric generation were considered more economical.
Residential exchange credits increased $1.7 million, or 4.5%, for the six months ended June 30, 2012, as compared to the same period in 2011 as a result of higher electric residential and farm customer sales volumes associated with the Bonneville Power Administration (BPA) Residential Exchange Program (REP). The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.

Natural Gas Margin
Gas margin is natural gas sales to retail and transportation customers less pass-through tariff items and revenue-sensitive taxes and 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)
2012
2011
Percent
Change
2012
2011
Percent
Change
Gas operating revenue1
$
207,823

$
245,014

(15.2
)%
$
643,789

$
663,638

20.8
 %
Less: Other gas operating revenue
(3,525
)
(3,668
)
(3.9
)
(7,010
)
(7,307
)
(4.1
)
Total gas revenue for margin
204,298

241,346

(15.4
)
636,779

656,331

(3.0
)
Adjustments for amounts included in
    revenue:
 
 
 
 
 
 
Pass-through tariff items
(10,838
)
(5,122
)
111.6

(22,332
)
(14,169
)
57.6

Pass-through revenue-sensitive taxes
(17,994
)
(20,710
)
(13.1
)
(53,319
)
(55,561
)
(4.0
)
Net gas revenue for margin
175,466

215,514

(18.6
)
561,128

586,601

(4.3
)
Minus purchased gas costs1
(96,462
)
(127,174
)
(24.1
)
(329,981
)
(363,928
)
(9.3
)
Natural gas margin2
$
79,004

$
88,340

(10.6
)%
$
231,147

$
222,673

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

Natural gas margin decreased $9.4 million and increased $8.5 million for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. 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 $37.2 million, or 15.2%, to $207.8 million from $245.0 million for the three months ended June 30, 2012 as compared to the same period in 2011. The decrease in gas operating revenues of $37.2 million was due primarily to lower natural gas retail sales. These items are discussed in detail below.
Gas operating revenues decreased $19.9 million, or 3.0%, to $643.8 million from $663.6 million for the six months ended June 30, 2012 as compared to the same period in 2011. The decrease in gas operating revenues of $19.9 million was due primarily to lower natural gas retail sales. These items are discussed in detail below.

Natural gas retail sales decreased $37.1 million, or 15.6%, to $200.6 million from $237.7 million for the three months ended June 30, 2012 as compared to the same period in 2011. The decrease in natural gas retail sales for the three months ended June 30, 2012 as compared to the same period in 2011 was primarily due to a decrease of 34.8 million in therm sales, or 18.1% due to warmer temperatures that resulted in a $43.2 million decrease. Contributing to the decrease was a net $1.0 million decrease due to the gas rate increase effective May 14, 2012 and the PGA rate decrease effective November 1, 2011. Offsetting the decrease was a $6.9 million increase related to gas conservation revenues as a result of an approved accounting petition authorizing PSE

37


to recover the costs associated with the Company's current 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.
Natural gas retail sales decreased $19.8 million, or 3.1%, to $629.1 million from $648.9 million for the six months ended June 30, 2012 as compared to the same period in 2011. The decrease in natural gas retail sales for the six months ended June 30, 2012 as compared to the same period in 2011 was primarily due to a decrease of 12.3 million in therm sales, or 2.2%, due to warmer temperatures that resulted in a $14.5 million decrease. The average temperature during the six months ended June 30, 2012 was 48.2 degrees which was 1.24 degrees warmer than the same period in the prior year. Although the temperature during the six months ended June 30, 2012 was warmer than the same period in the prior year, the current period average temperature was still 1.66 degrees cooler than the historical average. Contributing to the decrease was a net $12.1 million decrease related to the gas rate increases effective April 1, 2011 and May 14, 2012 and the PGA rate decrease effective November 1, 2011. Partially offsetting these decreases was a $6.9 million increase in retail sales related to gas conservation revenues with no impact to earnings. The PGA mechanism passes through to customers increases or decreases in the natural gas supply portion of the natural gas service rates based upon changes in the price of natural gas purchased from producers and wholesale marketers or changes in natural gas pipeline transportation costs. PSE's net income is not affected by changes under the PGA mechanism.

Gas Energy Costs
Purchased gas expenses decreased $30.7 million, or 24.1%, and $34.0 million, or 9.3%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The decrease was primarily due to lower natural gas costs reflected in PGA rates effective November 1, 2011. Also contributing to the decrease was a decrease in customer usage of 18.1% as a result of warmer temperatures for the three months ended June 30, 2012 as compared to the same period in 2011.
The PGA mechanism provides the rates used to determine natural gas costs based on customer usage. The rate decrease was the result of decreasing costs of wholesale natural gas. The PGA mechanism allows PSE to recover expected natural gas supply and transportation costs and defer, as a receivable or liability, any natural gas supply and transportation costs that exceed or fall short of this expected natural gas cost amount in PGA mechanism rates, including accrued interest. PSE is authorized by the Washington Commission to accrue carrying costs on PGA receivable and payable balances. A receivable balance in the PGA mechanism reflects an underrecovery of natural gas cost through rates. A payable balance reflects overrecovery of natural gas cost through rates. The PGA mechanism payable balance at June 30, 2012 was $49.6 million, which will be passed through to customers through a future PGA rate filing.

Other Operating Expenses
Net unrealized gain on derivative instruments increased $50.2 million to a gain of $59.9 million during the three months ended June 30, 2012 from a gain of $9.7 million during the same period in 2011. Net unrealized gain on derivative instruments increased $34.1 million, to a gain of $49.7 million during the six months ended June 30, 2012 from a gain of $15.6 million during the same period in 2011. The gains were primarily due to a reversal of prior period losses on settled contracts offset by losses due to declining natural gas and wholesale electricity prices. The contracts that were recorded in previous periods as losses were reversed at settlement, leading to gains. Forward prices of electricity and natural gas increased by 4.5% and 1.0%, respectively, for the three months ended June 30, 2012 and decreased by 6.5% and 8.6%, respectively, for the six months ended June 30, 2012.
Utility operations and maintenance expense increased $4.3 million, or 3.5%, and $14.4 million, or 6.0%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The increase was primarily driven by increases in administration and general expenses of $2.2 million and $3.6 million for the three and six months ended June 30, 2012, respectively and electric transmission and distribution expenses of $2.2 and $7.8 million for the three and six months ended June 30, 2012, respectively. The six month ended June 30, 2012 increase in electric transmission and distribution expense was due primarily to the January storm. Additionally, PSE deferred as a regulatory asset for future recovery approximately $58.8 million in transmission and distribution expenses related to the January 2012 winter storm.
Depreciation expense increased $11.0 million, or 14.9%, and $15.2 million, or 10.2%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The increase for the three and six months ended June 30, 2012 was primarily due to additional capital expenditures placed into service, net of retirements.
Amortization expense decreased $6.9 million, or 37.4%, and $11.5 million, or 31.7%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The decrease is primarily due to the deferral of amortization related to the Lower Snake River project of $5.5 million and $9.4 million for the three and six months ended June 30, 2012, respectively. Additionally, a decrease of $1.0 million and $2.1 million for the three and six months ended June 30, 2012, respectively, related to the Goldendale deferred costs being fully amortized in 2011.
Conservation amortization increased $4.6 million, or 19.5%, and $6.8 million, or 12.2%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The increase was due to an approved accounting petition authorizing PSE to recover the costs associated with the Company's current 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.

38


Taxes other than income taxes decreased $2.5 million, or 3.3%, and $3.1 million, or 1.8%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. For the three months ended June 30, 2012, the decrease was due primarily to a decrease in state and municipal taxes, which was partially offset by an increase in property taxes. For the six months ended June 30, 2012, the decrease was due to a decrease in state and municipal taxes.


Other Income and Interest Expense and Income Tax Expense
Other Income increased $2.7 million, or 16.9%, and $5.1 million, or 17.9%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The increase was primarily due to the carrying costs associated with the Lower Snake River accruing interest income of $15.8 million and $19.5 million for the three and six months ended June 30, 2012, respectively, as authorized by the Washington Commission. Partially offsetting the increase are decreases of $3.1 million and $1.6 million increase in Allowance for Funds Used During Construction (AFUDC) equity income for the three and six months ended June 30, 2012, respectively. Also offsetting the increase are decreases of $8.8 million and $10.9 million increase in regulatory interest for the three and six months ended June 30, 2012, respectively.
Other Expense increased $3.5 million for the six months ended June 30, 2012 as compared to the same period in 2011. The increase was primarily due to a $2.4 million increase related to customer credits resulting from the outages due to the January 2012 winter storm.
Interest Expense increased $7.5 million, or 14.9%, and $8.7 million, or 8.5%, for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The increase was primarily due to an increase in long term debt and the debt component of AFUDC which contributed $5.6 million and $7.5 million for the three and six months ended June 30, 2012, respectively.
Income tax increased $10.5 million, or 50.8%, and $10.4 million, or 15.5%, for the three and for the six months ended June 30, 2012, respectively, as compared to the same period in 2011. The increase was primarily due to higher taxable income for the three and six months ended June 30, 2012, as compared to same periods in 2011.

Puget Energy

Summary Results of Operations
All the operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income (loss) were as follows:

 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
Benefit/(Expense)
(Dollars in Thousands)
2012
2011
Percent
Change
2012
2011
Percent
Change
PSE net income (loss)
$
80,872

$
50,913

58.8
 %
193,588

$
154,352

25.4
 %
Other operating revenue
—

(689
)
*

—

(689
)
*

Purchased electricity
—

145

*

—

288

*

Net unrealized gain on energy derivative
    instruments
4,226

7,347

(42.5
)
9,635

34,482

(72.1
)%
Non-utility expense and other
2,344

510

*

4,713

939

*

Other income
8

2

*

11

7

66.0

Non-hedging interest rate derivative
    expense
(7,297
)
(25,412
)
(71.3
)
(6,770
)
(25,460
)
(73.7
)%
Interest expense 1
(33,548
)
(51,119
)
34.4

(79,961
)
(75,497
)
5.9
 %
Income tax benefit (expense)
11,087

23,338

(52.5
)
24,955

24,044

3.8
 %
Puget Energy net income (loss)
$
57,692

$
5,035

*

$
146,171

$
112,466

30.3
 %
__________
* 
Not meaningful
1 
Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt.

Puget Energy's net income for the three months ended June 30, 2012 was $57.7 million with operating revenue of $678.6 million as compared to net income of $5.0 million with operating revenue of $732.7 million for the same period in 2011. Puget Energy's net income for the six months ended June 30, 2012 was $146.2 million with operating revenue of $1,727.1 million as compared to net income of $112.5 million with operating revenue of $1,752.3 million for the same period in 2011.

39


The following are significant factors that impacted Puget Energy's net income which are not included in PSE's discussion:

Net unrealized gain on derivative instruments decreased $3.1 million and $24.8 million for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011 due to the effects of purchase accounting on derivative contracts in other comprehensive income (OCI) of $2.7 million and $8.6 million respectively, and the fair value amortization of Normal Purchase Normal Sale (NPNS) derivative contracts of $0.4 million and $16.2 million, respectively.
Non-utility expense and other increased $3.8 million for the six months ended June 30, 2012 as compared to the same period in 2011 due primarily to pension expense.
Unhedged interest rate expense decreased $18.1 million and $18.7 million for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The decrease was primarily a result of paying down a portion of a five-year term loan during the prior year. The five-year variable rate term loan was initially fully hedged; however, a portion of the hedge was unwound during the prior year and again in the first quarter of the current year.
Interest expense decreased $18.1 million and increased $4.5 million for the three and six months ended June 30, 2012, respectively, as compared to the same periods in 2011. The decrease for the three months ended June 30, 2012 was primarily due to a $6.8 million increase in write-off in the same period during the prior year related to the unamortized issuance costs associated with the five-year term loan and capital expenditure credit facility. Also contributing to the decrease was a $22.7 million decrease related to mark-to-market on interest rate swap contracts. Partially offsetting the decrease was $9.9 million of interest expense related to higher fixed rate debt issuances and additional debt balances.
The increase for the six months ended June 30, 2012 was primarily due to a $6.4 million increase in write-off related to the unamortized issuance costs associated with the five-year term loan and capital expenditure credit facility which were terminated on February 10, 2012. Also contributing to the increase was $12.7 million of interest expense related to higher fixed rate debt issuances and additional debt balances. Partially offsetting the increase was a $16.4 million decrease related to mark-to-market on interest rate swap contracts.
Income tax benefit increased $12.3 million for the three months ended June 30, 2012 as compared to the same period in 2011 due primarily to a higher pre-tax loss.

Capital Requirements
Contractual Obligations and Commercial Commitments
The only changes to the contractual obligations and consolidated commercial commitments 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, 2011 are as follows: (1) PSE's repayment of $25.0 million under its working capital facility on January 30, 2012 offset by new borrowings of $38.0 million on March 30, 2012; (2) Puget Energy's borrowing of $864.0 million on February 10, 2012 under a new $1.0 billion, five-year revolving senior secured credit facility and the concurrent repayment of debt outstanding under Puget Energy's prior term loan of $298.0 million and capital expenditure credit facility of $545.0 million which were then terminated; (3) Puget Energy's repayment of $5.0 million outstanding on March 12, 2012 under the $1.0 billion, five-year revolving senior secured credit facility; and (4) Puget Energy's issuance of $450.0 million of senior secured notes on June 15, 2012 and subsequent paydown of $425.0 million outstanding under the $1.0 billion, five-year revolving senior secured credit facility.
Contractual Obligations. These changes increased contractual obligations by $54.0 million, net of redemptions due to a net increase in borrowings of $41.0 million at Puget Energy and $13.0 million at PSE.
Commercial Commitments. These changes increased available commercial commitments by $98.0 million. This is due to (1) an increase of $111.0 million due to the change in debt structure at Puget Energy from $545.0 million drawn under the prior $1.0 billion term loan capital expenditure credit facility to $434.0 million drawn under the new $1.0 billion, five-year senior secured credit facility and (2) an offsetting decrease of $13.0 million due to the net increase in funds borrowed under PSE's working capital 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 $398.9 million for the six months ended June 30, 2012.  Presently planned utility construction expenditures, excluding AFUDC, are as follows:

Capital Expenditure Projections
(Dollars in Thousands)
2012

 
2013

 
2014

Total energy delivery, technology and facilities expenditures
$
698,458

 
$
632,400

 
$
591,206



40


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 Project.  Under the Snoqualmie Falls hydroelectric facility’s federal operating license granted by Federal Energy Regulatory Commission (FERC) in 2004 and amended in 2009, PSE is performing a major, three year redevelopment project to upgrade aging energy infrastructure, enhance park and recreation amenities and preserve cultural and historical artifacts.  This project will enable Snoqualmie Falls to continue to produce clean, renewable energy for decades to come.
The substantial upgrades and enhancements to its power-generating infrastructure include new generators, water-intake structures, penstocks and flow-control systems at Plant 1 and Plant 2.  The upgrades will boost the project’s authorized output (currently 44 megawatt (MW)) to 54 MW.  Plant 1 and Plant 2 are now offline and are expected to return to service by the end of the second quarter in 2013.  PSE has engaged a general contractor to perform this work on its behalf, pursuant to a guaranteed maximum price construction contract.
Baker Project.  Under the terms of the FERC issued 50-year operating license for the Baker power 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.
Lower Snake River.  The Lower Snake River wind project is PSE’s newest renewable energy development project. The project was designed to be built in five phases. PSE began construction on Phase 1 in 2010. On February 29, 2012, the 343 MW Phase 1 Lower Snake River Wind Facility began commercial operations and was placed in-service. The new facility’s 149 wind turbines are located in Garfield County in southeast Washington.

Capital Resources
Cash From Operations

Puget Sound Energy
Cash generated from operations for the six months ended June 30, 2012 decreased by $84.4 million from $650.8 million generated during the same period in 2011.  The decrease in cash flow was primarily the result of the following:

•
In 2012, there was approximately $66.5 million of cash outflow for costs incurred related to the January winter storm of which $58.8 million was deferred for future recovery.
•
Tax refunds received decreased by $48.5 million in 2012.
•
Increase in payments of $34.7 million related to energy and operational costs.
•
Increase in payments for materials and supplies of $20.1 million due to primarily generation and electric plant inventory to support major construction projects.
•
Decrease in Tenaska regulatory asset in 2011 by $20.3 million and no Tenaska regulatory asset in 2012, caused a decrease in cash flow in 2012 as compared to 2011.

The decrease in cash generated from operating activities in 2012 described above was partially offset by the following cash increases:
•
Increase in PCA recovery owed to customers in 2012 as compared to 2011, causing an increase in cash flow of $21.0 million.
•
Payments made in 2011 relating to transmission prepayments for the Lower Snake River project and the purchase of combustion turbine inventory that did not occur in 2012, which caused an increase in cash flow of approximately $18.0 million.
•
In 2012, PSE sold and deferred REC proceeds of $13.3 million and in 2011, PSE received REC proceeds of $1.9 million, which provided an increase in cash flow of $11.4 million.

In addition, non cash items decreased approximately $13.2 million related to items such as depreciation, amortization, deferred income taxes and credits, and fair value adjustment related to derivative instruments.



41


Puget Energy
Cash generated from operations for the six months ended June 30, 2012 was $545.8 million, a decrease of $195.5 million from the $741.3 million generated during the six months ended June 30, 2011.  The decrease included $84.4 million from the cash provided by the operating activities of PSE as previously discussed.  The other factors contributing to the decrease included the following:

•
As a result of the merger, $47.4 million in derivative settlement payments were reclassified to financing activities during the six months ended June 30, 2012 as compared to $123.9 million during the same period in 2011, resulting in a decrease in operating cash flows of $76.5 million.  This decrease was due to a decline in the number of contracts settled during 2012 as compared to the prior period.  These contracts represent proceeds received from derivative instruments that included financing elements at the merger date.
•
Tax refund received by Puget Energy of $13.5 million in 2011 as compared to no refund received in 2012.


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
PSE maintains three committed unsecured revolving credit facilities that provide, in the aggregate, $1.15 billion in short-term borrowing capability and which mature concurrently in February 2014. These facilities include a $400.0 million credit agreement for working capital needs, a $400.0 million credit facility for funding capital expenditures and a $350.0 million facility to support energy hedging activities.
PSE's 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 financial covenants which include a cash flow interest coverage ratio and, in addition, if PSE has a below investment grade credit rating, a cash flow to net debt outstanding ratio (each as specified in the facilities). PSE certifies its compliance with such covenants to participating banks each quarter. As of June 30, 2012, PSE maintained its investment grade ratings and was in compliance with all applicable covenants.
These credit facilities contain similar terms and conditions and are syndicated among numerous committed lenders. The agreements provide PSE with the ability to borrow at different interest rate options and include variable fee levels. The credit agreements allow PSE to borrow at the bank's prime rate or to make floating rate advances at the London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE's credit rating. The working capital facility, as amended, includes a swing line feature allowing same day availability on borrowings up to $50.0 million. The $400.0 million working capital facility and $350.0 million credit agreement to support energy hedging allow for issuing standby letters of credit. PSE must also 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 0.85% and the commitment fee is 0.26%. The $400.0 million working capital facility also serves as a backstop for PSE's commercial paper program.
As of June 30, 2012, $38.0 million was drawn and outstanding under PSE's $400.0 million working capital facility. A $12.5 million letter of credit supporting contracts was outstanding under the facility and there were no amounts outstanding under the commercial paper program. The $400.0 million capital expenditure facility had no amounts drawn and outstanding. 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 $5.3 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, 2012, the outstanding balance of the Note was $30.0 million. The outstanding balance and the related interest under the Note are eliminated by Puget Energy upon consolidation of PSE's financial statements.


42


Puget Energy Credit Facilities
At the time of the merger in February 2009, Puget Energy entered into a $1.225 billion five-year term loan and a $1.0 billion five-year capital expenditure credit facility for funding capital expenditures. On February 10, 2012, Puget Energy entered into a $1.0 billion five-year revolving senior secured credit facility. As a revolving facility, amounts borrowed may be repaid without a reduction in the size of the facility. 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. On June 15, 2012, Puget Energy issued $450.0 million of senior secured notes. Proceeds from the notes offering were used to pay down $425.0 million of the revolving senior secured credit facility balance resulting in an outstanding balance of $434.0 million as of June 30, 2012.
The new 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, 2012, Puget Energy was in compliance with all applicable covenants.
The senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the prime rate or LIBOR, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of June 30, 2012, 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" sections).

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, 2012, approximately $472.5 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 48.3% at June 30, 2012 and the EBITDA to interest expense was 4.3 to one for the 12 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. At June 30, 2012, the EBITDA to interest expense was 2.5 to one for the 12 months then ended.

Debt Restrictive Covenants
The type and amount of future long-term financings for PSE are limited by provisions in PSE's credit agreements and mortgage indentures. Under its credit agreements, PSE's long-term debt issuances can not exceed $500.0 million per year, plus any amount needed to refinance maturing bonds. Unused amounts under this limitation may be carried forward into future years.
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, 2012, PSE could issue:

•
Approximately $1.3 billion of additional first mortgage bonds under PSE's electric mortgage indenture based on approximately $2.1 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, 2012; and
•
Approximately $221.0 million of additional first mortgage bonds under PSE's natural gas mortgage indenture based on approximately $368.3 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, 2012.

At June 30, 2012, PSE had approximately $6.0 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 requirement as of June 30, 2012.

43



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


Other

Residential Exchange
The Northwest Power Act, through the REP, provides access to the benefits of low-cost federal hydroelectric power to 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 U.S. Court of Appeals for the 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 the fiscal year 2002-fiscal year 2011 period. In October 2011, certain other parties challenged BPA decisions with regard to its entering into this most recent settlement agreement. Pending disposition of this challenge, the other pending Ninth Circuit litigation regarding REP benefits for the period fiscal year 2002 through fiscal year 2011 period 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.

Pacific Northwest Refund Proceeding
In October 2000, PSE filed a complaint with the FERC (Docket No. EL01-10) against “all jurisdictional sellers” in the Pacific Northwest seeking prospective price caps consistent with any result the FERC ordered for the California markets. The FERC issued an order including price caps in July 2001, and PSE moved to dismiss the proceeding. In response to PSE's motion, various entities intervened and sought to convert PSE's complaint into one seeking retroactive refunds in the Pacific Northwest. The FERC rejected that effort, after holding what the FERC referred to as a “preliminary evidentiary hearing” before an administrative law judge. On October 3, 2011, after appellate reviews, the FERC issued an Order on Remand and set the matter for hearing before an administrative law judge, but first requiring the parties to engage in settlement talks that began in the fall of 2011 and are ongoing. On July 2, 2012 PSE and Tacoma filed a settlement as to Tacoma's claims against PSE, under which PSE will pay Tacoma for a full release. Seattle City Light and the Port of Seattle are the other parties that have asserted claims against PSE. PSE cannot predict whether settlement with those parties can be achieved. The hearing as to all unresolved claims is expected to begin in April 2013. PSE has not taken any reserve on this matter as it believes it has no exposure, and intends to vigorously defend its position but is unable to predict the outcome of this matter.


Item 3.                      Quantitative and Qualitative Disclosure about Market Risk

Energy Portfolio Management

PSE maintains energy risk policies and procedures to manage commodity and volatility risks and the related effects on credit, tax accounting, financing and liquidity.  PSE’s Energy Management Committee establishes PSE’s risk management policies and procedures and monitors compliance.  The Energy Management Committee is comprised of certain PSE officers and is overseen by the PSE Board of Directors.

44


PSE is focused on the commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios and related effects noted above.  It is not engaged in the business of assuming risk for the purpose of speculative trading.  PSE hedges open gas and electric positions to reduce both the portfolio risk and 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.

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.  Such detail should serve as an accompaniment to Management’s Discussion and Analysis included in Item 2 of this report.
PSE employs various energy portfolio optimization strategies but is not in the business of assuming risk for the purpose of realizing speculative trading revenue. PSE's portfolio of owned and contracted electric generation resources exposes PSE and its retail electric customers to 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 balancing PSE's energy portfolio, reducing costs and risks where feasible thus reducing volatility. 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 electricity and natural gas purchase and sale agreements, and floating-for-fixed swap contracts that are related to its regulated electric and natural gas portfolios. The forward physical electricity contracts are both fixed and variable (at index) while the physical natural gas contracts are variable with investment grade counterparties that do not require collateral calls on the contracts. To fix the price of wholesale electricity and natural gas, PSE may enter into floating-for-fixed swap (financial) contracts with various counterparties.
On July 1, 2009, Puget Energy and PSE elected to de-designate all energy related derivative contracts previously recorded as cash flow hedges for the purpose of simplifying its financial reporting. The contracts that were de-designated related to physical electric supply contracts and natural gas swap contracts to fix the price of natural gas for electric generation. For these contracts and for contracts initiated after such date, all mark-to-market adjustments are recognized through earnings. The amount previously recorded in accumulated OCI is transferred to earnings in the same period or periods during which the hedged transaction affects earnings or sooner if management determines that the forecasted transaction is probable of not occurring. As a result, the Company will continue to experience the earnings impact of these reversals from OCI in future periods.
The following table presents the Company's energy derivative instruments that do not meet the NPNS exception:

Puget Energy and Puget Sound Energy
 
Derivative Portfolio
(Dollars in thousands)
June 30, 2012
December 31, 2011
 
Assets
Liabilities
Assets
Liabilities
Electric portfolio:
 
 
 
 
Current
$
4,031

$
160,033

$
5,212

$
173,582

Long-term
9,523

50,048

5,508

90,752

Total electric derivatives
$
13,554

$
210,081

$
10,720

$
264,334

Natural gas portfolio:
 

 

 

 

Current
$
2,942

$
110,990

$
1,435

$
128,297

Long-term
6,458

49,237

4,576

78,607

Total natural gas derivatives
$
9,400

$
160,227

$
6,011

$
206,904

Total derivatives
$
22,954

$
370,308

$
16,731

$
471,238


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.

45


At June 30, 2012, the Company had total assets of $9.4 million and total liabilities of $160.2 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.
A hypothetical 10.0% increase or decrease in market prices of natural gas and electricity would change the fair value of the Company's derivative contracts by $44.6 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, 2012, PSE held approximately $1.1 million worth of standby letters of credit in support of various electricity and REC 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, 2012, approximately 94.5% of PSE's energy and natural gas portfolio exposure, including NPNS transactions, is with counterparties that are rated at least investment grade by the major rating agencies, while 5.5% are either rated below investment grade or are not rated by rating agencies. PSE assesses credit risk internally 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). ASC 815 specifies the requirements for derivative contracts to qualify for the NPNS scope exception. When performance is no longer probable, PSE records the fair value of the contract on the balance sheet with the corresponding amount recorded in the statements of income.
Accumulated OCI of the cash flow hedge is also impacted by a counterparty's deterioration of credit under ASC 815 guidelines. If a forecasted transaction associated with cash flow hedge is not probable of occurring, PSE will reclassify the amounts deferred in accumulated OCI into earnings.
Should a counterparty file for bankruptcy, which would be considered a default under master arrangements, PSE may terminate related contracts. Derivative accounting entries previously recorded would be reversed in the financial statements. PSE would compute any terminations receivable or payable, based on the terms of existing master agreements.
The Company computes credit reserves at a master agreement level by counterparty (i.e., WSPP, ISDA or NAESB). The Company considers external credit ratings and market factors, such as credit default swaps and bond spreads, in determination of reserves. The Company recognizes that external ratings may not always reflect how a market participant perceives a counterparty's risk of default. The Company uses both default factors published by Standard & Poor's and factors derived through analysis of market risk, which reflect the application of an industry standard recovery rate. The Company selects a default factor by counterparty at an aggregate master agreement level based on a weighted average default tenor for that counterparty's deals. The default tenor is used by weighting the fair value and contract tenors of all deals for each counterparty and arriving at an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. The fair value of derivatives includes the impact of credit and non-performance reserves. As of June 30, 2012, 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 additional 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 additional collateral resulting from credit rating downgrades.


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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 its debt. As of June 30, 2012, Puget Energy had two interest rate swap contracts outstanding and PSE did not have any outstanding interest rate swap instruments.
In February 2009, Puget Energy entered into a cash flow hedge using interest rate swap to hedge the risk associated with one-month LIBOR floating rate debt. Subsequently, in order to satisfy a commitment the Company made to the Washington Commission and to mitigate interest rate risk, the Company refinanced a portion of the underlying debt hedged by the interest rate swaps in 2010, 2011 and again during 2012. As a result of refinancing in 2010, the Company de-designated the cash flow hedge accounting relationship between the debt and interest rate swaps. A portion of the outstanding interest rate swap derivative loss associated with the probable future interest payments occurring remains in OCI, and is amortized monthly as the payments occur. The portion of the outstanding interest rate swap derivative loss associated with interest payments on the debt where future payments become remote of occurring is reclassified from OCI into earnings.
On June 15, 2012, Puget Energy issued $450.0 million of 10-year senior secured fixed-rate notes and paid down $425.0 million of its outstanding variable rate debt, bringing the balance down to $434.0 million as of June 30, 2012. As the related forecasted transactions (i.e. future interest payments associated with the debt pay down) are now remote of occurring, Puget Energy reclassified a $7.9 million loss from accumulated OCI into earnings. In order to better align its existing swap notional with the reduced credit facility balance, on June 18, 2012 the Company settled $550.0 million of the interest rate swaps for a $20.2 million loss, thereby reducing the swap notional to $450.0 million. Additionally, the Company amended the remaining two interest rate swap agreements ($450.0 million notional) to extend the maturities to January 2017. This strategy also allowed the Company to improve the alignment between the $450.0 million hedge and the variable rate exposure of the remaining balance of $434.0 million of the revolving senior secured credit facility.
At June 30, 2012, the fair value of the interest rate swaps was a $20.1 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 $7.7 million pre-tax and $5.0 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 de-designated in December 2010. 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 $1.6 million.
The following table presents Puget Energy's interest rate swaps:
Puget Energy
Derivative Portfolio
(Dollars in Thousands)
June 30, 2012
December 31, 2011
 
Liabilities
Liabilities
Interest rate swaps:
 
 
Current
$
6,223

$
25,210

Long-term
13,924

27,199

Total
$
20,147

$
52,409


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, 2012 was a net loss of $6.8 million after tax and accumulated amortization. This compares to an after-tax loss of $6.9 million in OCI as of December 31, 2011. 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, 2012.


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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, 2012, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of Puget Energy concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting
There have been no changes in Puget Energy’s internal control over financial reporting during the three months ended June 30, 2012 that have materially affected, or are reasonably likely to materially affect, Puget Energy’s internal control over financial reporting.

Puget Sound Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2012, the end of the period covered by this report.  Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer of PSE concluded that these disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting
There have been no changes in PSE’s internal control over financial reporting during the three months ended June 30, 2012 that have materially affected, or are reasonably likely to materially affect, PSE’s internal control over financial reporting.


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, 2012.  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, 2011.


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, 2012
Officer duly authorized to sign this report on behalf of each registrant



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EXHIBIT INDEX

4.1
Third Supplemental Indenture between Wells Fargo Bank, National Association and Puget Energy, Inc. dated as of June 15, 2012 (incorporated by reference to Exhibits 4.1 to Puget Energy's Current Report on Form 8-K, filed June 18, 2012, Commission File No. 1-16305).
4.2
Registration Rights Agreement by and among Puget Energy, Inc. and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities, LLC and Other Initial Purchasers dated as of June 15, 2012 (incorporated by reference to Exhibits 4.4 to Puget Energy's Current Report on Form 8-K, filed June 18, 2012, Commission File No. 1-16305).
12.1*
Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2007 through 2011 and 12 months ended June 30, 2012).
12.2*
Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2007 through 2011 and 12 months ended June 30, 2012).
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, 2012, filed on August 2, 2012, 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 tagged as blocks of text (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.


50