Document

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, 2016
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
 
 
 
Financial Information
 
 
 
Financial Statements
 
Puget Energy, Inc.
 
 
Consolidated Statements of Income – Three and Six Months Ended June 30, 2016 and 2015
 
Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2016 and 2015
 
Consolidated Balance Sheets – June 30, 2016 and December 31, 2015
 
Consolidated Statements of Cash Flows – Six Months Ended June 30, 2016 and 2015
 
 
 
 
Puget Sound Energy, Inc.
 
 
Consolidated Statements of Income – Three and Six Months Ended June 30, 2016 and 2015
 
Consolidated Statements of Comprehensive Income – Three and Six Months Ended June 30, 2016 and 2015
 
Consolidated Balance Sheets – June 30, 2016 and December 31, 2015
 
Consolidated Statements of Cash Flows – Six Months Ended June 30, 2016 and 2015
 
 
 
 
Notes
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 


2

DEFINITIONS

ARO
Asset Retirement and Environmental Obligations
ASU
Accounting Standards Update
ASC
Accounting Standards Codification
EBITDA
Earnings Before Interest, Tax, Depreciation and Amortization
ERF
Expedited Rate Filing
FASB
Financial Accounting Standards Board
GAAP
U.S. Generally Accepted Accounting Principles
GRC
General Rate Case
ISDA
International Swaps and Derivatives Association
LIBOR
London Interbank Offered Rate
MMBtu
One Million British Thermal Units
MWh
Megawatt Hour (one MWh equals one thousand kWh)
NAESB
North American Energy Standards Board
NPNS
Normal Purchase Normal Sale
PCA
Power Cost Adjustment
PCORC
Power Cost Only Rate Case
PGA
Purchased Gas Adjustment
PSE
Puget Sound Energy, Inc.
Puget Energy
Puget Energy, Inc.
Puget Holdings
Puget Holdings LLC
REP
Residential Exchange Program
SERP
Supplemental Executive Retirement Plan
Washington Commission
Washington Utilities and Transportation Commission
WSPP
WSPP, Inc.



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 and may be included in discussion of, among other things, our anticipated operating or financial performance, business plans and prospects, planned capital expenditures and other future expectations. In particular, these include statements relating to future actions, business plans and prospects, future performance expenses, the outcome of contingencies, such as legal proceedings, government regulation and financial results.
Forward-looking statements reflect current expectations and involve risks and uncertainties that could cause actual results or outcomes to differ materially from those expressed.  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 past results and those discussed in forward-looking statements include:
●
Governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Washington Utilities and Transportation Commission (Washington Commission), that may affect our ability to recover costs and earn a reasonable return, including but not limited to disallowance or delays in the recovery of capital investments and operating costs and discretion over allowed return on investment;
●
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;
●
Changes in tax law, related regulations or differing interpretation or enforcement of applicable law by the Internal Revenue Service (IRS) or other taxing jurisdiction; and PSE's ability to recover costs in a timely manner arising from such changes;
●
Inability to realize deferred tax assets and use production tax credits (PTCs) due to insufficient future taxable income;
●
Inability to manage costs during the rate stay out period through January 17, 2017, which would cause increases in costs of operations;
●
Accidents or natural disasters, such as hurricanes, windstorms, earthquakes, floods, fires and landslides, and other acts of God, terrorism, asset-based or cyber-based attacks, pandemic or similar significant events, 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;
●
Commodity price risks associated with procuring natural gas and power in wholesale markets from creditworthy counterparties;
●
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;
●
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;
●
The effect of wholesale market structures (including, but not limited to, regional market designs or transmission organizations) or other related federal initiatives;
●
PSE electric or natural gas distribution system failure, blackouts or large curtailments of transmission systems (whether PSE's or others'), or failure of the interstate natural gas pipeline delivering to PSE's system, all of which can affect PSE's ability to deliver power or natural gas to its customers and generating facilities;
●
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;
●
The ability to restart generation following a regional transmission disruption;
●
The ability of a natural gas or electric plant to operate as intended;
●
Changes in climate or weather conditions in the Pacific Northwest, which could have effects on customer usage and PSE's revenue and expenses;
●
Regional or national weather, which could impact PSE's ability to procure adequate supplies of natural gas, fuel or purchased power to serve its customers and the cost of procuring such supplies;
●
Variable hydrological conditions, which can impact streamflow and PSE's ability to generate electricity from hydroelectric facilities;
●
The ability to renew contracts for electric and natural gas supply and the price of renewal;
●
Industrial, commercial and residential growth and demographic patterns in the service territories of PSE;
●
General economic conditions in the Pacific Northwest, which may impact customer consumption or affect PSE's accounts receivable;
●
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;
●
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;
●
Capital market conditions, including changes in the availability of capital and interest rate fluctuations;
●
Employee workforce factors, including strikes, work stoppages, availability of qualified employees or the loss of a key executive;
●
The ability to obtain insurance coverage, the availability of insurance for certain specific losses, and the cost of such insurance;
●
The ability to maintain effective internal controls over financial reporting and operational processes;
●
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; and
●
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.  For further information see 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,
 
2016
2015
2016
2015
Operating revenue:
 
 
 
 
Electric
$
497,152

$
469,616

$
1,127,343

$
1,043,243

Natural gas
163,443

184,941

486,851

533,803

Other
7,574

3,784

16,672

8,129

Total operating revenue
668,169

658,341

1,630,866

1,585,175

Operating expenses:
 

 

 

 

Energy costs:
 

 

 

 

Purchased electricity
118,551

104,471

261,448

257,951

Electric generation fuel
40,930

55,652

95,123

103,668

Residential exchange
(13,376
)
(29,054
)
(33,516
)
(72,768
)
Purchased natural gas
48,273

79,465

171,376

235,898

Unrealized (gain) loss on derivative instruments, net
(46,724
)
(8,232
)
(63,546
)
(11,928
)
Utility operations and maintenance
138,018

131,972

284,008

269,147

Non-utility expense and other
5,179

2,323

10,814

5,535

Depreciation and amortization
111,273

100,412

218,787

206,589

Conservation amortization
22,540

24,561

55,751

54,165

Taxes other than income taxes
67,871

69,999

170,163

164,912

Total operating expenses
492,535

531,569

1,170,408

1,213,169

Operating income (loss)
175,634

126,772

460,458

372,006

Other income (deductions):
 

 

 

 

Other income
7,078

5,255

13,053

10,039

Other expense
(2,122
)
(1,815
)
(3,462
)
(3,222
)
Non-hedged interest rate swap (expense) income
(359
)
(1,440
)
(1,213
)
(3,415
)
Interest charges:
 

 

 

 

AFUDC
2,603

1,729

4,962

3,160

Interest expense
(88,676
)
(89,822
)
(177,489
)
(178,731
)
Income (loss) before income taxes
94,158

40,679

296,309

199,837

Income tax (benefit) expense
29,605

15,063

90,570

58,545

Net income (loss)
$
64,553

$
25,616

$
205,739

$
141,292


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,
 
2016
2015
2016
2015
Net income (loss)
$
64,553

$
25,616

$
205,739

$
141,292

Other comprehensive income (loss):
 

 

 

 

Net unrealized gain (loss) from pension and postretirement plans, net of tax of $100, $688, $200, and $1,000, respectively
(185
)
1,277

(371
)
1,856

Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $0, $0, and $179, respectively
—

—

—

333

Other comprehensive income (loss)
(185
)
1,277

(371
)
2,189

Comprehensive income (loss)
$
64,368

$
26,893

$
205,368

$
143,481


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

6

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



ASSETS
 
June 30,
2016
December 31,
2015
Utility plant (at original cost, including construction work in progress of $460,797 and $408,795, respectively):
 
 
Electric plant
$
7,596,857

$
7,432,490

Natural gas plant
2,943,093

2,850,290

Common plant
536,960

508,750

Less: Accumulated depreciation and amortization
(2,040,106
)
(1,878,868
)
Net utility plant
9,036,804

8,912,662

Other property and investments:
 

 

Goodwill
1,656,513

1,656,513

Other property and investments
84,563

86,731

Total other property and investments
1,741,076

1,743,244

Current assets:
 

 

Cash and cash equivalents
19,019

42,494

Restricted cash
10,128

7,949

Accounts receivable, net of allowance for doubtful accounts of $9,644 and $9,756, respectively
230,829

324,391

Unbilled revenue
126,241

217,274

Materials and supplies, at average cost
96,838

78,244

Fuel and gas inventory, at average cost
53,179

58,658

Unrealized gain on derivative instruments
36,255

24,418

Prepaid expense and other
19,566

17,120

Power contract acquisition adjustment gain
34,716

37,031

Total current assets
626,771

807,579

Other long-term and regulatory assets:
 

 

Regulatory asset for deferred income taxes
71,743

73,231

Power cost adjustment mechanism
4,813

4,749

Regulatory assets related to power contracts
24,041

26,223

Other regulatory assets
880,378

894,071

Unrealized gain on derivative instruments
8,782

5,225

Power contract acquisition adjustment gain
268,589

288,757

Other
62,536

58,513

Total other long-term and regulatory assets
1,320,882

1,350,769

Total assets
$
12,725,533

$
12,814,254


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





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



CAPITALIZATION AND LIABILITIES
 
June 30,
2016
December 31,
2015
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

Retained earnings
381,005

249,534

Accumulated other comprehensive income (loss), net of tax
(27,637
)
(27,266
)
Total common shareholder’s equity
3,662,325

3,531,225

Long-term debt:
 

 

First mortgage bonds and senior notes
3,364,412

3,364,412

Pollution control bonds
161,860

161,860

Junior subordinated notes
250,000

250,000

Long-term debt
1,800,000

1,800,000

Debt discount, issuance costs and other
(241,694
)
(248,754
)
Total long-term debt
5,334,578

5,327,518

Total capitalization
8,996,903

8,858,743

Current liabilities:
 

 

Accounts payable
190,784

259,353

Short-term debt
36,000

159,004

Purchased gas adjustment liability
11,562

12,589

Accrued expenses:
 

 

  Taxes
101,624

114,854

  Salaries and wages
35,722

38,457

  Interest
73,443

73,378

Unrealized loss on derivative instruments
67,417

136,173

Power contract acquisition adjustment loss
3,304

3,611

Other
68,405

53,867

Total current liabilities
588,261

851,286

Other long-term and regulatory liabilities:
 

 

Deferred income taxes
1,524,285

1,435,955

Unrealized loss on derivative instruments
19,859

48,073

Regulatory liabilities
616,231

652,441

Regulatory liabilities related to power contracts
303,304

325,788

Power contract acquisition adjustment loss
20,737

22,613

Other deferred credits
655,953

619,355

Total other long-term and regulatory liabilities
3,140,369

3,104,225

Commitments and contingencies (Note 8)




Total capitalization and liabilities
$
12,725,533

$
12,814,254


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,
 
2016
2015
Operating activities:
 
 
Net income (loss)
$
205,739

$
141,292

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

 
Depreciation and amortization
218,787

206,589

Conservation amortization
55,751

54,165

Deferred income taxes and tax credits, net
90,018

58,580

Net unrealized (gain) loss on derivative instruments
(65,414
)
(12,707
)
Derivative contracts classified as financing activities due to merger
—

8,045

AFUDC – equity
(7,048
)
(3,836
)
Funding of pension liability
(9,000
)
(9,000
)
Regulatory assets and liabilities
(120,615
)
(104,474
)
Other long-term assets and liabilities
14,519

24,828

Change in certain current assets and liabilities:
 

 
Accounts receivable and unbilled revenue
184,595

98,582

Materials and supplies
(18,594
)
(305
)
Fuel and gas inventory
4,974

10,734

Prepayments and other
(2,738
)
(3,276
)
Purchased gas adjustment
(1,027
)
35,963

Accounts payable
(64,132
)
(80,932
)
Taxes payable
(13,230
)
(8,551
)
Accrued expenses and other
4,650

(26,590
)
Net cash provided by (used in) operating activities
477,235

389,107

Investing activities:
 

 

Construction expenditures – excluding equity AFUDC
(303,834
)
(265,500
)
Restricted cash
(2,179
)
24,899

Other
(4,851
)
2,674

Net cash provided by (used in) investing activities
(310,864
)
(237,927
)
Financing activities:
 

 

Change in short-term debt, net
(123,004
)
(85,000
)
Dividends paid
(74,268
)
(192,500
)
Long-term notes and bonds issued
—

825,000

Redemption of bonds and notes
—

(699,000
)
Derivative contracts classified as financing activities due to merger
—

(8,045
)
Issuance cost of bonds and other
7,426

(14,627
)
Net cash provided by (used in) financing activities
(189,846
)
(174,172
)
Net increase (decrease) in cash and cash equivalents
(23,475
)
(22,992
)
Cash and cash equivalents at beginning of period
42,494

37,527

Cash and cash equivalents at end of period
$
19,019

$
14,535

Supplemental cash flow information:
 

 

Cash payments for interest (net of capitalized interest)
$
164,130

$
173,941

Cash payments (refunds) for income taxes
—

—

Non-cash financing and investing activities:
 
 
Accounts payable for capital expenditures eliminated from cash flows
$
47,151

$
51,239


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,
 
2016
2015
2016
2015
Operating revenue:
 
 
 
 
Electric
$
497,152

$
469,616

$
1,127,343

$
1,043,243

Natural gas
163,443

184,941

486,851

533,803

Other
7,574

3,784

16,672

8,138

Total operating revenue
668,169

658,341

1,630,866

1,585,184

Operating expenses:
 

 

 

 

Energy costs:
 

 

 

 

Purchased electricity
118,551

104,471

261,448

257,951

Electric generation fuel
40,930

55,652

95,123

103,668

Residential exchange
(13,376
)
(29,054
)
(33,516
)
(72,768
)
Purchased natural gas
48,273

79,465

171,376

235,898

Unrealized (gain) loss on derivative instruments, net
(46,724
)
(8,232
)
(63,546
)
(11,383
)
Utility operations and maintenance
138,018

131,972

284,008

269,147

Non-utility expense and other
8,822

6,342

17,856

13,349

Depreciation and amortization
111,273

100,412

218,787

206,589

Conservation amortization
22,540

24,561

55,751

54,165

Taxes other than income taxes
67,871

69,999

170,163

164,912

Total operating expenses
496,178

535,588

1,177,450

1,221,528

Operating income (loss)
171,991

122,753

453,416

363,656

Other income (deductions):
 

 

 

 

Other income
7,077

5,255

13,052

10,039

Other expense
(2,122
)
(1,815
)
(3,462
)
(3,222
)
Interest charges:
 

 

 

 

AFUDC
2,603

1,729

4,962

3,160

Interest expense
(60,647
)
(62,620
)
(121,422
)
(125,816
)
Interest expense on parent note
—

(31
)
—

(63
)
Income (loss) before income taxes
118,902

65,271

346,546

247,754

Income tax (benefit) expense
38,002

22,572

109,140

75,955

Net income (loss)
$
80,900

$
42,699

$
237,406

$
171,799


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,
 
2016
2015
2016
2015
Net income (loss)
$
80,900

$
42,699

$
237,406

$
171,799

Other comprehensive income (loss):
 

 

 

 

Net unrealized gain (loss) from pension and postretirement plans, net of tax of $1,260, $2,204, $2,520, and $4,025, respectively
2,340

4,094

4,680

7,475

Reclassification of net unrealized (gain) loss on energy derivative instruments, net of tax of $0, $0, $0, and $369, respectively
—

—

—

686

Amortization of treasury interest rate swaps to earnings, net of tax of $43, $43, $86, and $86, respectively
79

79

158

158

Other comprehensive income (loss)
2,419

4,173

4,838

8,319

Comprehensive income (loss)
$
83,319

$
46,872

$
242,244

$
180,118


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

10

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



ASSETS
 
June 30,
2016
December 31,
2015
Utility plant (at original cost, including construction work in progress of $460,797 and $408,795, respectively):
 
 
Electric plant
$
9,757,074

$
9,601,091

Natural gas plant
3,533,415

3,444,744

Common plant
576,867

548,657

Less:  Accumulated depreciation and amortization
(4,830,552
)
(4,681,830
)
Net utility plant
9,036,804

8,912,662

Other property and investments:
 

 

Other property and investments
80,901

83,069

Total other property and investments
80,901

83,069

Current assets:
 

 

Cash and cash equivalents
18,578

41,856

Restricted cash
10,128

7,949

Accounts receivable, net of allowance for doubtful accounts of $9,644 and $9,756, respectively
230,691

324,358

Unbilled revenue
126,241

217,274

Materials and supplies, at average cost
96,838

78,244

Fuel and gas inventory, at average cost
52,350

57,324

Unrealized gain on derivative instruments
36,255

24,418

Prepaid expense and other
19,566

17,119

Total current assets
590,647

768,542

Other long-term and regulatory assets:
 

 

Regulatory asset for deferred income taxes
71,213

72,694

Power cost adjustment mechanism
4,813

4,749

Other regulatory assets
880,375

894,059

Unrealized gain on derivative instruments
8,782

5,225

Other
62,536

58,513

Total other long-term and regulatory assets
1,027,719

1,035,240

Total assets
$
10,736,071

$
10,799,513


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

11


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



CAPITALIZATION AND LIABILITIES

 
June 30,
2016
December 31,
2015
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
3,275,105

3,275,105

Retained earnings
345,310

236,578

Accumulated other comprehensive income (loss), net of tax
(144,712
)
(149,550
)
Total common shareholder’s equity
3,476,562

3,362,992

Long-term debt:
 

 

First mortgage bonds and senior notes
3,364,412

3,364,412

Pollution control bonds
161,860

161,860

Junior subordinated notes
250,000

250,000

Debt discount, issuance costs and other
(30,437
)
(31,910
)
Total long-term debt
3,745,835

3,744,362

Total capitalization
7,222,397

7,107,354

Current liabilities:
 

 

Accounts payable
190,784

259,353

Short-term debt
36,000

159,004

Purchased gas adjustment liability
11,562

12,589

Accrued expenses:
 

 

Taxes
101,624

114,854

Salaries and wages
35,722

38,457

Interest
47,899

47,772

       Unrealized loss on derivative instruments
64,236

131,420

       Other
68,405

53,868

Total current liabilities
556,232

817,317

Other long-term and regulatory liabilities:
 

 

Deferred income taxes
1,666,329

1,556,616

Unrealized loss on derivative instruments
19,859

47,776

Regulatory liabilities
615,399

651,094

Other deferred credits
655,855

619,356

Total other long-term and regulatory liabilities
2,957,442

2,874,842

Commitments and contingencies (Note 8)




Total capitalization and liabilities
$
10,736,071

$
10,799,513


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,
 
2016
2015
Operating activities:
 
 
Net income (loss)
$
237,406

$
171,799

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

 
Depreciation and amortization
218,787

206,589

Conservation amortization
55,751

54,165

Deferred income taxes and tax credits, net
108,589

75,953

Net unrealized (gain) loss on derivative instruments
(63,546
)
(11,383
)
AFUDC – equity
(7,048
)
(3,836
)
Funding of pension liability
(9,000
)
(9,000
)
Regulatory assets and liabilities
(120,615
)
(104,474
)
Other long-term assets and liabilities
16,820

27,037

Change in certain current assets and liabilities:
 

 
Accounts receivable and unbilled revenue
184,700

98,282

Materials and supplies
(18,594
)
(305
)
Fuel and gas inventory
4,974

10,734

Prepayments and other
(2,738
)
(3,274
)
Purchased gas adjustment
(1,027
)
35,963

Accounts payable
(64,132
)
(80,926
)
Taxes payable
(13,230
)
(8,551
)
Accrued expenses and other
1,567

(31,142
)
Net cash provided by (used in) operating activities
528,664

427,631

Investing activities:
 

 

Construction expenditures – excluding equity AFUDC
(303,834
)
(265,500
)
Restricted cash
(2,179
)
24,899

Other
(1,707
)
4,692

Net cash provided by (used in) investing activities
(307,720
)
(235,909
)
Financing activities:
 

 

Change in short-term debt, net
(123,004
)
(85,000
)
Dividends paid
(128,674
)
(144,387
)
Loan from (payment to) parent
—

(28,933
)
Investment from parent
—

28,900

Long-term notes and bonds issued
—

425,000

Redemption of bonds and notes
—

(400,000
)
Issuance cost of bonds and other
7,456

(11,448
)
Net cash provided by (used in) financing activities
(244,222
)
(215,868
)
Net increase (decrease) in cash and cash equivalents
(23,278
)
(24,146
)
Cash and cash equivalents at beginning of period
41,856

37,466

Cash and cash equivalents at end of period
$
18,578

$
13,320

Supplemental cash flow information:
 

 

Cash payments for interest (net of capitalized interest)
$
113,438

$
128,267

Cash payments (refunds) for income taxes
—

—

Non-cash financing and investing activities:
 
 
Accounts payable for capital expenditures eliminated from cash flows
$
47,151

$
51,239


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

13

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)


(1)
Summary of Consolidation Policy

Basis of Presentation
Puget Energy is an energy services holding company that owns PSE.  PSE is a public utility incorporated in the state of Washington that furnishes electric and natural gas services in a territory covering approximately 6,000 square miles, primarily in the Puget Sound region.  Puget Energy is an indirect wholly-owned subsidiary of Puget Holdings LLC (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 subsidiary, Puget Western, Inc.  Puget Energy and PSE are collectively referred to herein as “the Company”.  The consolidated financial statements are presented after elimination of intercompany transactions.  PSE’s consolidated financial statements continue to be accounted for on a historical basis and do not include any purchase accounting adjustments.
The consolidated financial statements contained in this Form 10-Q are unaudited.  In the respective opinions of the management of Puget Energy and PSE, all adjustments necessary for a fair statement of the results for the interim periods have been reflected and were of a normal recurring nature.  These consolidated financial statements should be read in conjunction with the audited financial statements (and the Combined Notes thereto) included in the combined Puget Energy and PSE Annual Report on Form 10-K for the year ended December 31, 2015.
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.
PSE collected Washington State excise taxes (which are a component of general retail customer rates) and municipal taxes totaling $48.8 million and $123.4 million for the three and six months ended June 30, 2016, respectively, and $50.3 million and $119.9 million for the three and six months ended June 30, 2015, 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.

Change in Accounting Principle
On January 1, 2016, the Company changed its method of presenting unamortized debt issuance costs in the balance sheet. The new method of presenting debt issuance costs was adopted to comply with ASU 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs". ASU 2015-03 requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability, consistent with the presentation of a debt discount. The prior year comparative balance sheet has been adjusted to apply the new method retrospectively. Due to the change in accounting principle, the December 31, 2015 financial statement line item “Other long-term assets” decreased and “Debt discount, issuance costs and other” increased $38.4 million and $30.0 million at Puget Energy and PSE, respectively.


(2)  New Accounting Pronouncements

Revenue Recognition
In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, "Revenue from Contracts with Customers (Topic 606)", which outlines a single comprehensive model for use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The ASU is based on the principle that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments and assets recognized from costs incurred to fulfill a contract.
In August 2015, the FASB issued ASU 2015-14, "Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date", deferring the effective date for ASU 2014-09 to fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. In addition to the FASB's deferral decision, the FASB provided reporting entities with an option to adopt ASU 2014-09 for the fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, the original effective date.

14

In March 2016, the FASB issued ASU 2016-08, "Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)". The amendments in ASU 2016-08 are intended to improve the operability and understanding of the implementation guidance on principal versus agent considerations. Topic 606 requires an entity to determine whether the nature of its promise is to provide a good or service to the customer (i.e., the entity is a principal) or to arrange for the good or service to be provided to the customer by another party (i.e., the entity is an agent). The effective date and transition requirements for ASU 2016-08 are the same as the effective date and transition requirements of ASU 2014-09.
In April 2016, the FASB issued ASU 2016-10, "Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing". The amendments in ASU 2016-10 are intended to clarify the aspects of identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. The effective date and transition requirements for ASU 2016-10 are the same as the effective date and transition requirements of ASU 2014-09.
In May 2016, the FASB issued ASU 2016-12, "Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients". The amendments in ASU 2016-12 are intended to clarify the objective of collectability criterion, presentation of sales taxes and other similar taxes collected from customers, specify the measurement date for noncash consideration, provide practical expedient for contract modifications at transition, define completed contracts at transition and clarify that an entity that retrospectively applies the guidance in Topic 606 to each prior reporting period is not required to disclose the effect of the accounting change for the period of adoption. The effective date and transition requirements for ASU 2016-12 are the same as the effective date and transition requirements of ASU 2014-09.
The Company plans to adopt ASU 2014-09 according to the deferred effective date.  Reporting entities also have the option of using either a full retrospective or a modified retrospective approach for the adoption of the new standard.  The Company initiated a steering committee and project team to evaluate the impact of this standard, update any policies and procedures that may be affected and implement the new revenue recognition guidance. At this time, the Company is still evaluating the impact this standard will have on its consolidated financial statements.

Lease Accounting
In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)". ASU 2016-02 requires lessees to recognize the following for all leases (with the exception of short-term leases) at the commencement date: (i) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Under the new guidance, lessor accounting is largely unchanged.
This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard.  The Company plans to adopt ASU 2016-02 during the first quarter of fiscal year 2019.  At this time, the Company is still evaluating the impact this standard will have on its consolidated financial statements.

Derivatives and Hedging
In March 2016, the FASB issued ASU 2016-06, "Derivatives and Hedging (Topic 815): Contingent Put and Call Options in Debt Instruments". Topic 815 requires that embedded derivatives be separated from the host contract and accounted for separately as derivatives if certain criteria are met, including the “clearly and closely related” criterion. ASU 2016-06 clarifies the requirements for assessing whether contingent call (put) options that can accelerate the payment of principal on debt instruments are clearly and closely related to their debt hosts. An entity performing the assessment under the amendment is required to assess the embedded call (put) options solely in accordance with the four-step decision sequence.
This amendment is effective for financial statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Earlier adoption is permitted for all entities upon issuance. Reporting entities must apply a modified retrospective approach for the adoption of the new standard.  The Company plans to adopt ASU 2016-06 during the first quarter of fiscal year 2017, and is in the process of evaluating the potential impacts, if any, of this new guidance on its 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 Power Cost Adjustment (PCA). Therefore, wholesale market transactions and PSE's related hedging strategies are focused on reducing costs and risks where feasible, thus reducing volatility in costs in the portfolio. In order to manage its

15

exposure to the variability in future cash flows for forecasted energy transactions, PSE utilizes a programmatic hedging strategy which extends out three years. PSE's energy risk portfolio management function monitors and manages these risks using analytical models and tools. In order to manage risks effectively, PSE enters into forward physical electric and natural gas purchase and sale agreements, fixed-for-floating swap contracts, and commodity call/put options. The forward physical electric agreements are both fixed and variable (at index), while the physical natural gas agreements are variable. To fix the price of wholesale electricity and natural gas, PSE may enter into fixed-for-floating swap (financial) contracts with various counterparties. PSE also utilizes natural gas call and put options as an additional hedging instrument to increase the hedging portfolio's flexibility to react to commodity price fluctuations. Currently, the Company does not apply cash flow hedge accounting, and therefore records all mark-to-market gains or losses through earnings.
The Company manages its interest rate risk through the issuance of mostly fixed-rate debt with varied maturities. The Company utilizes internal cash from operations, borrowings under its commercial paper program and its credit facilities to meet short-term funding needs. The Company may enter into swap instruments or other financial hedge instruments to manage the interest rate risk associated with these debts. As of June 30, 2016, Puget Energy had two interest rate swap contracts outstanding which extend to January 2017. As of the date of this report, these swap instruments are no longer hedging any variable interest rate debt. Management continues to monitor the economics of terminating the swaps, and unless the economics of terminating the swaps become more favorable, management intends to let them mature in January 2017. PSE did not have any outstanding interest rate swap instruments.
The following table presents the volumes, fair values and locations of the Company's derivative instruments recorded on the balance sheets:
Puget Energy and
Puget Sound Energy
 
 
 
 
 
 
 
June 30, 2016
December 31, 2015
(Dollars in Thousands)
Volumes
Assets 1
Liabilities 2
Volumes
Assets 1
Liabilities 2
Interest rate swap derivatives 3
$450 million
$
—

$
3,181

$450 million
$
—

$
5,050

Electric portfolio derivatives
*
31,657

56,775

*
23,443

112,106

Natural gas derivatives (MMBtus) 4
322.1 million
13,380

27,320

369.5 million
6,200

67,090

Total derivative contracts
 
$
45,037

$
87,276

 
$
29,643

$
184,246

Current
 
$
36,255

$
67,417

 
$
24,418

$
136,173

Long-term
 
8,782

19,859

 
5,225

48,073

Total derivative contracts
 
$
45,037

$
87,276

 
$
29,643

$
184,246

_______________
1 
Balance sheet locations: Current and Long-term Unrealized gain on derivative instruments.
2 
Balance sheet locations: Current and Long-term Unrealized loss on derivative instruments.
3 
Interest rate swap contracts are only held at Puget Energy.
4 
All fair value adjustments on derivatives relating to the natural gas business have been deferred in accordance with ASC 980, “Regulated Operations,” due to the Purchased Gas Adjustment (PGA) mechanism. The net derivative asset or liability and offsetting regulatory liability or asset are related to contracts used to economically hedge the cost of physical gas purchased to serve natural gas customers.
* 
Electric portfolio derivatives consist of electric generation fuel of 205.0 million One Million British Thermal Units (MMBtu) and purchased electricity of 0.1 million Megawatt Hours (MWhs) at June 30, 2016, and 202.1 million MMBtus and 0.1 million MWhs at December 31, 2015.

It is the Company's policy to record all derivative transactions on a gross basis at the contract level, without offsetting assets or liabilities. The Company generally enters into transactions using the following master agreements: WSPP, Inc. (WSPP) agreements, which standardize physical power contracts; International Swaps and Derivatives Association (ISDA) agreements, which standardize financial gas and electric contracts; and North American Energy Standards Board (NAESB) agreements, which standardize physical gas contracts. The Company believes that such agreements reduce credit risk exposure because such agreements provide for the netting and offsetting of monthly payments as well as the right of set-off in the event of counterparty default. The set-off provision can be used as a final settlement of accounts which extinguishes the mutual debts owed between the parties in exchange for a new net amount. For further details regarding the fair value of derivative instruments, see Note 4.
 

16

The following tables present the potential effect of netting arrangements, including rights of set-off associated with the Company's derivative assets and liabilities:
Puget Energy and
Puget Sound Energy
 
 
 
 
June 30, 2016
 
Gross Amount Recognized in the Statement of Financial Position 1
Gross Amounts Offset in the Statement of Financial Position
Net of Amounts Presented in the Statement of Financial Position
Gross Amounts Not Offset in the Statement of Financial Position
 

(Dollars in Thousands)
Commodity Contracts
Cash Collateral Received/Posted
Net Amount
Assets:
 
 
 
 
 
 
Energy derivative contracts
$
45,037

$
—

$
45,037

$
(38,636
)
$
—

$
6,401

Liabilities:
 
 
 
 
 
 
Energy derivative contracts
84,095

—

84,095

(38,636
)
(137
)
45,322

Interest rate swaps 2
3,181

—

3,181

—

—

3,181

 
 
 
 
 
 
 
Puget Energy and
Puget Sound Energy
 
 
 
 
December 31, 2015
 
Gross Amount Recognized in the Statement of Financial Position 1
Gross Amounts Offset in the Statement of Financial Position
Net of Amounts Presented in the Statement of Financial Position
Gross Amounts Not Offset in the Statement of Financial Position
 

(Dollars in Thousands)
Commodity Contracts
Cash Collateral Received/Posted
Net Amount
Assets:
 
 
 
 
 
 
Energy derivative contracts
$
29,643

$
—

$
29,643

$
(23,998
)
$
—

$
5,645

Liabilities:
 
 
 
 
 
 
Energy derivative contracts
179,196

—

179,196

(23,998
)
—

155,198

Interest rate swaps 2
5,050

—

5,050

—

—

5,050

_______________
1 
All derivative contract deals are executed under ISDA, NAESB and WSPP master netting agreements with right of set-off.
2 
Interest rate swap contracts are only held at Puget Energy.







17

The following tables present the effect and locations of the Company's derivatives recorded on the statements of income:
Puget Energy
 
Three Months Ended June 30,
Six Months Ended
June 30,
(Dollars in Thousands)
Location
2016
2015
2016
2015
Interest rate contracts:
Non-hedged interest rate swap
(expense) income
$
(359
)
$
(1,440
)
$
(1,213
)
$
(3,415
)
 
Interest expense
—

722

—

560

Commodity contracts:
 
 
 

 
 
Electric derivatives
Unrealized gain (loss) on derivative instruments, net 1
46,724

8,232

63,546

11,928

 
Electric generation fuel
(12,327
)
(5,082
)
(33,010
)
(15,744
)
 
Purchased electricity
(3,576
)
(4,261
)
(14,795
)
(26,145
)
Total gain (loss) recognized in income on derivatives
 
$
30,462

$
(1,829
)
$
14,528

$
(32,816
)

Puget Sound Energy
 
Three Months Ended June 30,
Six Months Ended
June 30,
(Dollars in Thousands)
Location
2016
2015
2016
2015
Commodity contracts:
 
 
 
 
 
Electric derivatives
Unrealized gain (loss) on derivative instruments, net 1
$
46,724

$
8,232

$
63,546

$
11,383

 
Electric generation fuel
(12,327
)
(5,082
)
(33,010
)
(15,744
)
 
Purchased electricity
(3,576
)
(4,261
)
(14,795
)
(26,145
)
Total gain (loss) recognized in income on derivatives
 
$
30,821

$
(1,111
)
$
15,741

$
(30,506
)
_______________
1 
Differences between Puget Energy and PSE for the six months ending June 30, 2015 are due to certain derivative contracts recorded at fair value in 2009 and subsequently designated as Normal Purchase Normal Sale (NPNS) or cash flow hedges. These differences occurred through February 2015.

The Company is exposed to credit risk primarily through buying and selling electricity and natural gas to serve its customers. Credit risk is the potential loss resulting from a counterparty's non-performance under an agreement. The Company manages credit risk with policies and procedures for, among other things, counterparty credit analysis, exposure measurement, exposure monitoring and exposure mitigation.
The Company monitors counterparties that have significant swings in credit default swap rates, have credit rating changes by external rating agencies, have changes in ownership or are experiencing financial distress. Where deemed appropriate, the Company may request collateral or other security from its counterparties to mitigate potential credit default losses. Criteria employed in this decision include, among other things, the perceived creditworthiness of the counterparty and the expected credit exposure.
It is possible that volatility in energy commodity prices could cause the Company to have material credit risk exposure with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. However, as of June 30, 2016, approximately 92.0% of the Company's energy portfolio exposure, excluding NPNS transactions, is with counterparties that are rated at least investment grade by rating agencies and 8.0% are either rated below investment grade or not rated by rating agencies. The Company assesses credit risk internally for counterparties that are not rated by the major rating agencies.
The Company computes credit reserves at a master agreement level by counterparty. 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 determined by weighting the fair value and contract tenors for all deals for each counterparty to derive an average value. The default factor used is dependent upon whether the counterparty is in a net asset or a net liability position after applying the master agreement levels.
The Company applies the counterparty's default factor to compute credit reserves for counterparties that are in a net asset position. The Company calculates a non-performance risk on its derivative liabilities by using its estimated incremental borrowing rate over the risk-free rate. Credit reserves are netted against the unrealized gain (loss) positions. As of June 30, 2016, the Company

18

was in a net liability position with many of its counterparties, so the default factors of counterparties did not have a significant impact on reserves for the period. The majority of the Company's derivative contracts are with financial institutions and other utilities operating within the Western Electricity Coordinating Council. As of June 30, 2016, PSE has posted a $1.0 million letter of credit as a condition of transacting on a physical energy exchange and clearinghouse in Canada. PSE did not trigger any collateral requirements with any of its counterparties during the six months ended June 30, 2016, nor were any of PSE's counterparties required to post collateral resulting from credit rating downgrades.
The table below presents the fair value of the overall contractual contingent liability positions for the Company's derivative activity at June 30, 2016:
Puget Energy and
Puget Sound Energy
 
 
 
(Dollars in Thousands)
 
 
 
 
Fair Value 1
Posted
Contingent
Contingent Feature
Liability
Collateral
Collateral
Credit rating 2
$
(11,748
)
$
—

$
11,748

Requested credit for adequate assurance
(15,648
)
—

—

Forward value of contract 3
(106
)
—

—

Total
$
(27,502
)
$
—

$
11,748

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


(4)
Fair Value Measurements

ASC 820 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 measured at fair value are classified in their entirety in the appropriate fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. The Company primarily determines fair value measurements classified as Level 2 or Level 3 using a combination of the income and market valuation approaches. The process of determining the fair values is the responsibility of the derivative accounting department which reports to the Controller and Principal Accounting Officer. Inputs used to estimate the fair value of forwards, swaps and options include market-price curves, contract terms and prices, credit-risk adjustments, and discount factors. Additionally, for options, the Black-Scholes option valuation model and implied market

19

volatility curves are used. Inputs used to estimate fair value in industry-standard models are categorized as Level 2 inputs as substantially all assumptions and inputs are observable in active markets throughout the full term of the instruments. On a daily basis, the Company obtains quoted forward prices for the electric and natural gas markets from an independent external pricing service. For interest rate swaps, the Company obtains monthly market values from an independent external pricing service using London Interbank Offered Rate (LIBOR) forward rates, which is a significant input. Some of the inputs of the interest rate swap valuations, which are less significant, include the credit standing of the counterparties, assumptions for time value and the impact of the Company's nonperformance risk of its liabilities. The Company classifies cash and cash equivalents, and restricted cash as Level 1 financial instruments due to cash being at stated value, and cash equivalents at quoted market prices.
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 with maturity dates falling outside the range of observable price quotes are classified as Level 3 in the fair value hierarchy. Management's assessment is 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 used to value Level 2 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 carrying value for cash, cash equivalents, restricted cash, notes receivable and short-term debt by fair value hierarchy level. The carrying values below are representative of fair values due to the short-term nature of these financial instruments.
 
Carrying / Fair Value
Carrying / Fair Value
Puget Energy
At June 30, 2016
At December 31, 2015
(Dollars in Thousands)
Level 1
Level 2
     Total
Level 1
Level 2
     Total
Assets:
 
 
 
 
 
 
Cash and cash equivalents
$
19,019

$
—

$
19,019

$
42,494

$
—

$
42,494

Restricted cash
10,128

—

10,128

7,949

—

7,949

Other investments
—

51,874

51,874

—

52,820

52,820

Total assets
$
29,147

$
51,874

$
81,021

$
50,443

$
52,820

$
103,263

Liabilities:
 
 
 
 
 
 
Short-term debt
$
36,000

$
—

$
36,000

$
159,004

$
—

$
159,004

Total liabilities
$
36,000

$
—

$
36,000

$
159,004

$
—

$
159,004


 
Carrying / Fair Value
Carrying / Fair Value
Puget Sound Energy
At June 30, 2016
At December 31, 2015
(Dollars in Thousands)
Level 1
Level 2
     Total
Level 1
Level 2
     Total
Assets:
 
 
 
 
 
 
Cash and cash equivalents
$
18,578

$
—

$
18,578

$
41,856

$
—

$
41,856

Restricted cash
10,128

—

10,128

7,949

—

7,949

Other investments
—

51,874

51,874

—

52,820

52,820

Total assets
$
28,706

$
51,874

$
80,580

$
49,805

$
52,820

$
102,625

Liabilities:
 
 
 
 
 
 
Short-term debt
$
36,000

$
—

$
36,000

$
159,004

$
—

$
159,004

Total liabilities
$
36,000

$
—

$
36,000

$
159,004

$
—

$
159,004



20

The fair value of the junior subordinated and long-term notes was estimated using the discounted cash flow method with the U.S. Treasury yields and the Company's 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, 2016
December 31, 2015
(Dollars in Thousands)
Level
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Liabilities:
 
 
 
 
 
Junior subordinated notes
2
$
250,000

$
222,780

$
250,000

$
211,173

Long-term debt (fixed-rate), net of discount 1
2
5,084,578

6,817,865

5,077,518

6,308,831

Total liabilities
 
$
5,334,578

$
7,040,645

$
5,327,518

$
6,520,004

 
 
 
 
 
 
Puget Sound Energy
 
June 30, 2016
December 31, 2015
(Dollars in Thousands)
Level
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
Liabilities:
 
 
 
 
 
Junior subordinated notes
2
$
250,000

$
222,780

$
250,000

$
211,173

Long-term debt (fixed-rate), net of discount 2
2
3,495,835

4,766,386

3,494,362

4,329,444

Total liabilities
 
$
3,745,835

$
4,989,166

$
3,744,362

$
4,540,617

_______________
1 
The carrying value includes debt issuances costs of $35.6 million, and $38.4 million for June 30, 2016 and December 31, 2015, respectively, which are not included in fair value.
2 
The carrying value includes debt issuances costs of $28.6 million, and $30.0 million for June 30, 2016 and December 31, 2015, respectively, which are not included in fair value.

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:
 
Fair Value
Fair Value
Puget Energy
At June 30, 2016
At December 31, 2015
(Dollars in Thousands)
Level 2
Level 3
Total
Level 2
Level 3
Total
Liabilities:
 
 
 
 
 
 
Interest rate derivative instruments
$
3,181

$
—

$
3,181

$
5,050

$
—

$
5,050

Total liabilities
$
3,181

$
—

$
3,181

$
5,050

$
—

$
5,050


Puget Energy and
Fair Value
Fair Value
Puget Sound Energy
At June 30, 2016
At December 31, 2015
(Dollars in Thousands)
Level 2
Level 3
Total
Level 2
Level 3
Total
Assets:
 
 
 
 
 
 
Electric derivative instruments
$
24,411

$
7,246

$
31,657

$
10,709

$
12,734

$
23,443

Natural gas derivative instruments
10,787

2,593

13,380

4,538

1,662

6,200

Total assets
$
35,198

$
9,839

$
45,037

$
15,247

$
14,396

$
29,643

Liabilities:
 

 

 

 

 

 

Electric derivative instruments
$
46,467

$
10,308

$
56,775

$
92,027

$
20,079

$
112,106

Natural gas derivative instruments
24,243

3,077

27,320

63,045

4,045

67,090

Total liabilities
$
70,710

$
13,385

$
84,095

$
155,072

$
24,124

$
179,196


21


The following table presents the Company's reconciliation of the changes in the fair value of Level 3 derivatives in the fair value hierarchy:
Puget Energy and
Puget Sound Energy
Three Months Ended June 30,
(Dollars in Thousands)
2016
2015
Level 3 Roll-Forward Net Asset/(Liability)
Electric
Natural Gas
Total
Electric
Natural Gas
Total
Balance at beginning of period
$
1,602

$
(1,622
)
$
(20
)
$
(16,091
)
$
(1,601
)
$
(17,692
)
Changes during period:
 
 
 
 
 
 
Realized and unrealized energy derivatives:
 
 
 
 
 
 
Included in earnings 1
(1,954
)
—

(1,954
)
(4,064
)
—

(4,064
)
Included in regulatory assets / liabilities
—

1,562

1,562

—

2,813

2,813

Settlements
(494
)
(879
)
(1,373
)
52

(389
)
(337
)
Transferred into Level 3
—

—

—

—

—

—

Transferred out of Level 3
(2,216
)
455

(1,761
)
4,733

—

4,733

Balance at end of period
$
(3,062
)
$
(484
)
$
(3,546
)
$
(15,370
)
$
823

$
(14,547
)
 
Puget Energy and
Puget Sound Energy
Six Months Ended
June 30,
(Dollars in Thousands)
2016
2015
Level 3 Roll-Forward Net Asset/(Liability)
Electric
Natural Gas
Total
Electric
Natural Gas
Total
Balance at beginning of period
$
(7,345
)
$
(2,383
)
$
(9,728
)
$
(12,061
)
$
(2,039
)
$
(14,100
)
Changes during period:



 
 
 
Realized and unrealized energy derivatives:



 
 
 
Included in earnings 2
2,654

—

2,654

(9,102
)
—

(9,102
)
Included in regulatory assets / liabilities
—

3,082

3,082

—

2,938

2,938

Settlements
(554
)
(1,816
)
(2,370
)
165

(298
)
(133
)
Transferred into Level 3
(2,080
)
—

(2,080
)
(787
)
—

(787
)
Transferred out of Level 3
4,263

633

4,896

6,415

222

6,637

Balance at end of period
$
(3,062
)
$
(484
)
$
(3,546
)
$
(15,370
)
$
823

$
(14,547
)
_______________
1 
Income Statement locations: 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 $(2.5) million and $(3.8) million for the three months ended June 30, 2016 and 2015, respectively.
2 
Income Statement locations: 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 $3.1 million and $(8.8) million for the six months ended June 30, 2016 and 2015, respectively.

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 did not have any transfers between Level 2 and Level 1 during the reported periods. 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 forward market prices. Such transactions are classified

22

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.
The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of June 30, 2016:
 
Fair Value
 
 
Range
 
(Dollars in Thousands)
Assets 1
Liabilities 1
Valuation Technique
Unobservable Input
Low
High
 Weighted Average
Electric
$
7,246

$
10,308

Discounted cash flow
Power prices
$12.72 per MWh
$32.00 per MWh
$27.99 per MWh
Natural gas
$
2,593

$
3,077

Discounted cash flow
Natural gas prices
$1.25 per MMBtu
$3.46 per MMBtu
$2.53 per MMBtu
_______________
1 
The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The following table presents the forward price ranges for the Company's Level 3 commodity contracts as of December 31, 2015:
 
Fair Value
 
 
Range
 
(Dollars in Thousands)
Assets 1
Liabilities 1
Valuation Technique
Unobservable Input
Low
High
 Weighted Average
Electric
$
12,734

$
20,079

Discounted cash flow
Power prices
$10.69 per MWh
$29.18 per MWh
$23.39 per MWh
Natural gas
$
1,662

$
4,045

Discounted cash flow
Natural gas prices
$1.12 per MMBtu
$2.95 per MMBtu
$2.25 per MMBtu
_______________
1 
The valuation techniques, unobservable inputs and ranges are the same for asset and liability positions.

The significant unobservable inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. Consequently, significant increases or decreases in the forward prices of electricity or natural gas in isolation would result in a significantly higher or lower fair value for Level 3 assets and liabilities. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets. At June 30, 2016 and December 31, 2015, 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 $0.6 million and $1.3 million, respectively.

Long-Lived Assets Measured at Fair Value on a Nonrecurring Basis
Puget Energy records 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 non-performance risk. Management also incorporated certain assumptions related to quantities and market presentation that it believes market participants would make in the valuation. The fair value of the power contracts is amortized as the contracts settle.
ASC 360 requires long-lived assets to be tested for impairment on an annual basis, and upon the occurrence of any events or circumstances that would be more likely than not to reduce the fair value of the long-lived assets below their carrying value. One such triggering event is a significant decrease in the forward market prices of power.

23

At June 30, 2016, Puget Energy completed valuation and impairment testing of its power purchase contracts classified as intangible assets and found no impairment. However, due to decreases in forward power prices of 8.6% at March 31, 2016 and 4.5% at December 31, 2015, the following impairments were recorded to one of the Company's intangible asset contracts, with corresponding reductions to the regulatory liability as follows:
Puget Energy
 
(Dollars in Thousands)
 
 
 
 
Valuation Date
Contract Name
Carrying
Value
Fair
Value
Write
Down
March 31, 2016
Wells Hydro
$
25,193

$
19,855

$
5,338

December 31, 2015
Wells Hydro
32,988

27,628

5,360


The valuations were measured using a discounted cash flow, income-based valuation methodology. 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. A less significant input is the discount rate reflective of PSE's cost of capital used in the valuation.
Below are significant unobservable inputs used in estimating the impaired long-term power purchase contracts' fair value at March 31, 2016 and December 31, 2015:
Valuation Date
Unobservable Input
Low
High
Average
March 31, 2016
 
 
 
 
 
Power prices
$9.46 per MWh
$25.96 per MWh
$21.38 per MWh
 
Power contract costs (in thousands)
$4,100 per qtr
$4,659 per qtr
$4,452 per qtr
December 31, 2015
 
 
 
 
 
Power prices
$15.16 per MWh
$27.25 per MWh
$23.23 per MWh
 
Power contract costs (in thousands)
$4,100 per qtr
$4,659 per qtr
$4,417 per qtr


(5)
Retirement Benefits

PSE has a defined benefit pension plan (Qualified Pension Benefits) covering the largest portion of 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.  Starting with January 1, 2014 all newly hired non-represented employees, United Association of Journeymen and Apprentices of the Plumbing and Pipe Fitting Industry (UA) employees, and International Brotherhood of Electrical Workers Local Union 77 (IBEW) employees hired on or after December 12, 2014 will receive annual pay credits of 4% each year, which is the Company contribution. Non-represented and IBEW employees can accumulate the Company contribution in the cash balance formula or the 401(k) plan. UA employees will automatically receive the Company contribution in the cash balance formula plan. They will also receive interest credits like other participants in the cash balance pension formula of the pension plan, which are at least 1% per quarter. When an employee with a vested cash balance formula benefit leaves PSE, he or she will have annuity and lump sum options for distribution. Those who select the lump sum option will receive their current cash balance amount. 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 legacy group health care and life insurance benefits (Other 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 prior year.
Puget Energy records purchase accounting adjustments associated with the re-measurement of the retirement plans.

24

The following tables summarize the Company’s net periodic benefit cost for the three and six months ended June 30, 2016 and 2015:
Puget Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
 
Three Months Ended June 30,
(Dollars in Thousands)
2016
2015
2016
2015
2016
2015
Components of net periodic benefit cost:
 
 
 
 
 
 
Service cost
$
4,605

$
5,172

$
271

$
277

$
24

$
23

Interest cost
7,226

6,937

582

570

157

150

Expected return on plan assets
(11,687
)
(11,117
)
—

—

(111
)
(133
)
Amortization of prior service cost
(495
)
(495
)
11

11

—

—

Amortization of net loss (gain)
—

962

228

410

(29
)
(51
)
Net periodic benefit cost
$
(351
)
$
1,459

$
1,092

$
1,268

$
41

$
(11
)

 
Puget Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
 
 
 
Six Months Ended
June 30,
 
(Dollars in Thousands)
2016
2015
2016
2015
2016
2015
 
Components of net periodic benefit cost:
 

 

 

 

 

 

 
Service cost
$
9,209

$
10,644

$
542

$
554

$
49

$
56

 
Interest cost
14,452

14,044

1,163

1,140

313

311

 
Expected return on plan assets
(23,374
)
(22,519
)
—

—

(222
)
(266
)
 
Amortization of prior service cost
(990
)
(990
)
22

22

—

—

 
Amortization of net loss (gain)
—

1,943

456

820

(58
)
(66
)
 
Net periodic benefit cost
$
(703
)
$
3,122

$
2,183

$
2,536

$
82

$
35


 
Puget Sound Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
 
 
 
Three Months Ended June 30,
 
(Dollars in Thousands)
2016
2015
2016
2015
2016
2015
 
Components of net periodic benefit cost:
 

 

 

 

 

 

 
Service cost
$
4,605

$
5,172

$
271

$
277

$
24

$
23

 
Interest cost
7,226

6,937

582

570

157

150

 
Expected return on plan assets
(11,736
)
(11,223
)
—

—

(111
)
(133
)
 
Amortization of prior service cost
(393
)
(393
)
11

11

—

1

 
Amortization of net loss (gain)
3,740

5,141

333

530

(90
)
(120
)
 
Net periodic benefit cost
$
3,442

$
5,634

$
1,197

$
1,388

$
(20
)
$
(79
)

25

 
Puget Sound Energy
Qualified
Pension Benefits
SERP
Pension Benefits
Other
Benefits
 
 
 
Six Months Ended
June 30,
 
(Dollars in Thousands)
2016
2015
2016
2015
2016
2015
 
Components of net periodic benefit cost:
 

 

 

 

 

 

 
Service cost
$
9,209

$
10,644

$
542

$
554

$
49

$
56

 
Interest cost
14,452

14,044

1,163

1,140

313

311

 
Expected return on plan assets
(23,472
)
(22,731
)
—

—

(222
)
(266
)
 
Amortization of prior service cost
(786
)
(786
)
22

22

—

2

 
Amortization of net loss (gain)
7,480

10,277

666

1,060

(180
)
(203
)
 
Net periodic benefit cost
$
6,883

$
11,448

$
2,393

$
2,776

$
(40
)
$
(100
)

The following table summarizes the Company’s change in benefit obligation for the periods ended June 30, 2016 and December 31, 2015:
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,
2016
December 31,
2015
June 30,
2016
December 31,
2015
June 30,
2016
December 31,
2015
Change in benefit obligation:
 
 
 
 
 
 
Benefit obligation at beginning of period
$
643,088

$
690,194

$
51,279

$
55,855

$
13,946

$
15,688

Service cost
9,209

21,287

542

1,108

49

112

Interest cost
14,452

28,088

1,163

2,281

313

621

Actuarial loss (gain)
—

(55,665
)
—

(4,430
)
—

(1,416
)
Benefits paid
(20,650
)
(39,963
)
(2,092
)
(3,535
)
(664
)
(1,354
)
Medicare part D subsidy received
—

—

—

—

5

295

Administrative Expense
—

(853
)
—

—

—

—

Benefit obligation at end of period
$
646,099

$
643,088

$
50,892

$
51,279

$
13,649

$
13,946


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, 2016 are expected to be at least $24.0 million, $2.5 million and $0.5 million, respectively. During the three months ended June 30, 2016, the Company contributed $4.5 million, $1.0 million and $0.2 million to fund the qualified pension plan, SERP and other postretirement plan, respectively. During the six months ended June 30, 2016, the Company contributed $9.0 million, $2.1 million, and $0.4 million to the fund the qualified pension plan, SERP and other postretirement plan, respectively.
 

(6)
Regulation and Rates

Decoupling Filings
While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigate the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from residential, commercial and

26

industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will be recovered on a per customer basis regardless of actual consumption levels. The energy supply costs, which are part of the PCA and PGA mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers over a 12-month period beginning the following May. The decoupling mechanism will end on December 31, 2017 unless the continuation of the mechanism is approved in PSE's next General Rate Case (GRC) filing, which PSE is required to submit by January 17, 2017 at the latest.
On April 28, 2016, the Washington Commission approved PSE's request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2016. The overall changes represent a rate increase for electric customers of $20.8 million, or 1.0%, annually, and a rate increase for natural gas customers of $25.4 million, or 2.8%, annually. In addition, PSE exceeded the earnings test threshold for both its electric and natural gas business in 2015. As a result, PSE recorded a reduction in electric decoupling deferral and revenue of $11.9 million and a reduction in natural gas decoupling deferral and revenue of $5.5 million. This was reflected as a reduction to the electric and natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue.  This limitation was triggered for the natural gas residential rate class. The resulting amount of deferral that was not included in the 2016 rate increase is $28.7 million for natural gas revenue that was accrued through December 31, 2015. This amount may be included in customer rates beginning in May 2017, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.  
On April 22, 2015, the Washington Commission approved PSE's request to change rates under its electric and natural gas decoupling mechanism, effective May 1, 2015. As part of this filing, PSE also requested to change the methodology of how decoupling deferrals are calculated going forward and adjust deferrals calculated in 2014. The change was done to ensure that the amortization of prior years’ accumulated decoupling deferrals were not included in the calculation of the current year decoupling deferrals. The effect of the methodology change was a reduction of approximately $12.0 million previously recognized revenue from May through December of 2014. The overall changes represent a rate increase for electric customers of $53.8 million, or 2.6%, annually, and a rate increase for natural gas customers of $22.0 million, or 2.1%, annually, effective May 1, 2015. In addition, PSE exceeded the earnings test threshold for its natural gas business in 2014. As a result, PSE recorded a reduction in natural gas decoupling deferral and revenue of $1.3 million. This was reflected as a reduction to the natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue.  This limitation was triggered for certain rate classes. The resulting amount of deferral that was not included in the 2015 rate increase is $1.9 million for electric revenue and $8.2 million for natural gas revenue that was accrued through December 31, 2014. These amounts may be included in customer rates beginning in May 2016, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.  

General Rate Case Filing Postponed to 2017
On March 17, 2016, the Washington Commission approved a joint petition postponing the filing of PSE’s GRC until no later than January 17, 2017. All parties to PSE's 2011 GRC, including Public Counsel, Washington Commission Staff, Industrial Customers of Northwest Utilities (ICNU) and Northwest Industrial Gas Users (NWIGU), either supported the petition or did not oppose it. As part of the petition, PSE agreed to update power costs on December 1, 2016 in conjunction with the Centralia PPA compliance filing and to include in the GRC a filing regarding its interest in Colstrip Units 1 and 2. Monthly allowed revenue per customer values, which include an automatic annual increase, will continue through December 2017 until new rates go into effect from PSE's 2017 GRC.

Electric Regulation and Rates
Storm Damage Deferral Accounting
The Washington Commission issued a GRC order that defined deferrable catastrophic/extraordinary losses and provided that costs in excess of $8.0 million annually can be recorded as a regulatory asset for qualifying storm damage costs that meet the Institute of Electrical and Electronics Engineers (IEEE) threshold criteria for a major event. For the six months ended June 30, 2016 and 2015, PSE incurred $15.6 million and $2.5 million, respectively, in storm-related electric transmission and distribution system restoration costs, of which $6.5 million was recorded as a regulatory asset in 2016 and $0.2 million in 2015.


27

Electric Property Tax Tracker Mechanism
The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs as a component rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker will be adjusted each year in May based on that year's assessed property taxes and true-ups to the rate from the prior year.
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2016
0.3%
$5.7
May 1, 2015
0.4
8.4

Electric Conservation Rider
The electric conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2016
(0.5)%
$(11.7)
May 1, 2015
0.2
4.2

Federal Incentive Tracker Tariff
The Federal Incentive Tracker Tariff passes through to customers the benefits associated with realized treasury grants and production tax credits (PTCs). The filing results in a credit back to customers for pass-back of treasury grant amortization and pass-through of interest and any related true-ups. The filing is adjusted annually for new Federal benefits, actual versus forecast interest and to true-up for actual load being different than the forecasted load set in rates.
The following table sets forth Federal Incentive Tracker Tariff revenue requirement approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Total annual amount to be passed back to eligible customers
(Dollars in Millions)
January 1, 2016
(0.2)%
$(57.3)
January 1, 2015
(0.2)
(55.2)

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Gas Regulation and Rates
Gas Conservation Rider
The gas conservation rider collects revenue to cover the costs incurred in providing services and programs for conservation. Rates change annually on May 1 to collect the annual budget that started the prior January.
The following table sets forth conservation rider rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
 
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
 
 
 
 
May 1, 2016
0.3%
$2.9
 
May 1, 2015
0.2
2.3

Cost Recovery Mechanism
The purpose of the Cost Recovery Mechanism (CRM) is to recover capital costs related to enhancing the safety of the natural gas distribution system.
The following table sets forth CRM rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 2015
0.5%
$5.3

Property Tax Tracker Mechanism
The purpose of the property tax tracker mechanism is to pass through the cost of all property taxes incurred by the Company. The mechanism was implemented in 2013 and removed property taxes from general rates and included those costs as a component rate. After the implementation, the mechanism acts as a tracker rate schedule and collects the total amount of property taxes assessed. The tracker will be adjusted each year in May based on that year's assessed property taxes.
The following table sets forth property tax tracker mechanism rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
May 1, 2016
0.4%
$3.5
June 1, 2015
(0.2)
(2.3)


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Purchased Gas Adjustment
PSE has a PGA mechanism that 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 or payable balance in the PGA mechanism reflects an under recovery or over recovery, respectively, of natural gas cost through the PGA mechanism.
The following table sets forth PGA rate adjustments approved by the Washington Commission and the corresponding impact on PSE’s revenue based on the effective dates:
Effective Date
Average
Percentage
Increase (Decrease)
in Rates
Increase (Decrease)
in Revenue
(Dollars in Millions)
November 1, 2015
(17.4)%
$(185.9)


(7)
Asset Retirement Obligation

The Company has recorded liabilities for steam, combustion turbine, combined cycle, and wind generation sites, distribution and transmission poles, gas mains, and leased facilities where disposal is governed by ASC 410 “Asset Retirement and Environmental Obligations (ARO)”.
On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates Coal Combustion Residuals (CCR) under the Resource Conservation and Recovery Act, Subtitle D. The CCR rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash surface impoundments by establishing technical requirements for CCR landfills and surface impoundments. The rule also sets out recordkeeping and reporting requirements including requirements to post specific information to a publicly-accessible website.
The CCR rule requires significant changes to the Company’s Colstrip, Montana coal-fired steam electric generation facility (Colstrip) operations and those changes were reviewed by the Company and the plant operator in the second and third quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip, in 2003. Due to the CCR rule, additional disposal costs were added to the ARO.
The actual ARO costs related to the CCR rule requirements may vary substantially from the estimates used to record the increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to estimate costs. We will continue to gather additional data and coordinate with the plant operator to make decisions about compliance strategies and the timing of closure activities. As additional information becomes available, the Company will update the ARO obligation for these changes, which could be material.
During the first quarter 2016, the Company updated its estimated decommissioning costs and timing of its ARO for Lower Snake River and Hopkins Ridge wind generation sites and increased the undiscounted ARO liability by $19.7 million.
The following table describes the changes to the Company’s ARO for the six months ended June 30, 2016:
Puget Sound Energy
 
(Dollars in Thousands)
Changes in ARO
Balance at December 31, 2015
$
85,028

New asset retirement obligation recognized in the period
—

Liability adjustments
(411
)
Revisions in estimated cash flows
16,854

Accretion expense
1,240

Balance at June 30, 2016
$
102,711




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(8)
Commitment and Contingencies

Colstrip
PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. Based on a second amended complaint filed in August 2014, the plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review program of the Clean Air Act and the Montana State Implementation Plan arising from seven projects undertaken at Colstrip during the time period from 2001 to 2012. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station. As part of the settlement, which has been filed with the court for its approval, PSE has agreed, along with Talen Energy, to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the shutdown, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. PSE is not able to determine the decommissioning costs of Colstrip Units 1 and 2 at this time; however, any associated decommissioning and historical costs are expected to be fully recovered through rates.

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 $0.5 million and $0.3 million relating to these claims as of June 30, 2016 and December 31, 2015, respectively.
There have been no material changes to the contractual obligations and consolidated commercial commitments set forth in Part II, Item 7 in the Company's Annual Report on Form 10-K for the year ended December 31, 2015.


(9)
Other

Related Party Transactions
Scott Armstrong serves on the Board of Directors of the Company, and is the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provides coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elect Group Health as their medical provider and as a result, PSE paid Group Health a total of $10.7 million and $20.3 million for medical coverage for the six months ended June 30, 2016, and the year ended December 31, 2015, respectively.


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. (Puget Energy) and Puget Sound Energy, Inc. (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 I, Item 1A in Puget Energy's and Puget Sound Energy's Form 10-K for the period ended December 31, 2015. 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 U.S. 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.


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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. All of Puget Energy's common stock is indirectly owned by Puget Holdings LLC (Puget Holdings). Puget Holdings is owned by a consortium of long-term infrastructure investors including Macquarie Infrastructure Partners I, Macquarie Infrastructure Partners II, Macquarie Capital Group Limited, FSS Infrastructure Trust, the Canada Pension Plan Investment Board, the British Columbia Investment Management Corporation, and the Alberta Investment Management Corporation. 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. PSE continually balances its load requirements, generation resources, purchase power agreements, and market purchases to meet customer demand. 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, 2016, as compared to the same period in 2015, PSE's net income was affected primarily by the following factors: (1) an increase in electric margin driven by increased electric revenues, primarily from residential customers; (2) an increase in natural gas operating margin; and (3) offset by an increase in operations and maintenance expense.

Factors and Trends Affecting PSE's Performance
The principal business, economic and other factors that affect PSE's operations and financial performance include:
•
The rates PSE is allowed to charge for its services;
•
PSE’s ability to recover power costs that are included in rates which are based on volume;
•
PSE’s ability to manage costs during the rate stay out period through January 17, 2017;
•
Weather conditions, including snow-pack affecting hydrological conditions;
•
Regulatory decisions allowing PSE to recover purchased power and fuel costs, on a timely basis;
•
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;
•
Equal sharing between PSE and its customers of earnings which exceed PSE's authorized rate of return;
•
Availability and access to capital and the cost of capital;
•
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;
•
Wholesale commodity prices of electricity and natural gas;
•
Increasing depreciation and amortization;
•
Bonus depreciation and the impact on rate base;
•
General economic conditions in PSE's service territory and its effects on customer growth and use-per-customer; and
•
Federal, state, and local taxes.

Further detail regarding the factors and trends affecting performance of the Company during the fiscal quarter ended June 30, 2016 is set forth below in this "Overview" section as well as in other sections of the Management's Discussion and Analysis.

Regulation of PSE Rates and Recovery of PSE Costs
PSE's regulatory requirements and operational needs require the investment of substantial capital in 2016 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. 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 has traditionally required these rates be determined based, to a large extent, on historic test year costs plus weather normalized assumptions about hydroelectric conditions and power costs in the relevant rate year. Incremental customer growth and sales typically have not provided sufficient revenue to cover general cost increases over time due to the combined effects of regulatory lag and attrition.

32

Accordingly, the Company will need to seek rate relief on a regular and frequent basis in the future. In addition, the Washington Commission determines whether the Company's expenses and capital investments are reasonable and prudent for the provision of cost effective, reliable and safe electric and natural gas service. If the Washington Commission determines that a capital investment does not meet the reasonable and prudent standards, the costs (including return on any resulting rate base) related to such capital investment may be disallowed, partially or entirely, and not recovered in rates.

2013 Expedited Rate Filing, Decoupling and Centralia Decision
PSE filed a settlement agreement with the Washington Commission on March 22, 2013. The agreement was intended to settle all issues regarding decoupling, a power purchase agreement with TransAlta Centralia and the Expedited Rate Filing (ERF) which includes the property tax tracker. The Washington Commission placed the ERF and decoupling filings under a common procedural schedule.
On June 25, 2013, the Washington Commission issued final orders resolving the amended decoupling petition, the ERF filing and the Petition for Reconsideration (related to the TransAlta Centralia power purchase agreement). Order No. 7 in the ERF/decoupling proceeding approved PSE's ERF filing with a small change to its cost of capital from 7.80% to 7.77% to update long term debt costs and a capital structure that included 48.0% common equity with a return on equity (ROE) of 9.8%. This order also approved the property tax tracker discussed below and approved the amended decoupling and rate plan filing with the further condition that PSE and the customers will share 50.0% each in earnings in excess of the 7.77% authorized rate of return. In addition, the rate plan (K-Factor) increase allowed decoupling revenue per customer for the recovery of delivery system costs to subsequently increase by 3.0% for the electric customers and 2.2% for the gas customers on January 1 of each year, until the conclusion of PSE's next General Rate Case (GRC) which was to be filed before April 1, 2016 and was later extended to January 17, 2017, as discussed below. In the rate plan, increases are subject to a cap of 3.0% of the total revenue for customers. Order No. 8 in the TransAlta Centralia proceeding granted in part and denied in part PSE's Petition for Reconsideration, clarifying certain portions of the Washington Commission's original order regarding TransAlta Centralia.

Decoupling Filings
While fluctuations in weather conditions will continue to affect PSE's billed revenue and energy supply expenses from month to month, PSE's decoupling mechanisms are expected to mitigate the impact of weather on operating revenue and net income. The Washington Commission has allowed PSE to record a monthly adjustment to its electric and natural gas operating revenues related to electric transmission and distribution, natural gas operations and general administrative costs from residential, commercial and industrial customers to mitigate the effects of abnormal weather, conservation impacts and changes in usage patterns per customer. As a result, these electric and natural gas revenues will be recovered on a per customer basis regardless of actual consumption levels. The energy supply costs, which are part of the Power Cost Adjustment (PCA) and Purchased Gas Adjustment (PGA) mechanisms, are not included in the decoupling mechanism. The revenue recorded under the decoupling mechanisms will be affected by customer growth and not actual consumption. Following each calendar year, PSE will recover or refund the difference between allowed decoupling revenue and the corresponding actual revenue to affected customers over a 12-month period beginning the following May. The decoupling mechanism will end on December 31, 2017 unless the continuation of the mechanism is approved in PSE's next GRC filing, which PSE is required to submit by January 17, 2017 at the latest.
On April 28, 2016, the Washington Commission approved PSE’s request to change rates under its electric and natural gas decoupling mechanisms, effective May 1, 2016. The overall changes represent a rate increase for electric customers of $20.8 million, or 1.0%, annually, and a rate increase for natural gas customers of $25.4 million, or 2.8%, annually. In addition, PSE exceeded the earnings test threshold for both its electric and natural gas businesses in 2015. As a result, PSE recorded a reduction in electric decoupling deferral and revenue of $11.9 million and a reduction in natural gas deferral and revenue of $5.5 million. This was reflected as a reduction to the electric and natural gas rate increases noted above. As noted earlier, the Company is also limited to a 3.0% annual decoupling related cap on increases in total revenue.  This limitation was triggered for the natural gas residential rate class. The resulting amount of deferral that was not included in the 2016 rate increase is $28.7 million for natural gas revenue that was accrued through December 31, 2015. This amount may be included in customer rates beginning in May 2017, subject to subsequent application of the earnings test and the 3.0% cap on decoupling related rate increases.

General Rate Case Filing Postponed to 2017
On March 17, 2016, the Washington Commission approved a joint petition postponing the filing of PSE’s GRC until no later than January 17, 2017. All parties to PSE's 2011 GRC, including Public Counsel, Washington Commission Staff, Industrial Customers of Northwest Utilities (ICNU) and Northwest Industrial Gas Users (NWIGU), either supported the petition or did not oppose it. As part of the petition, PSE agreed to update power costs on December 1, 2016 in conjunction with the Centralia PPA compliance filing and to include in the GRC a filing regarding its interest in Colstrip Units 1 and 2. Monthly allowed revenue per customer values, which include an automatic annual increase, will continue through December 2017 until new rates go into effect from PSE's 2017 GRC.

33


Electric Rates
Power Cost Adjustment Mechanism
PSE currently has a 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” level is 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 currently applicable is as follows:
Annual Power Cost Variability
Company's Share
Customers’ Share
+/- $20 million
100%
—%
+/- $20 million - $40 million
50
50
+/- $40 million - $120 million
10
90
+/- $120 + million
5
95

On August 7, 2015, the Washington Commission issued an order approving the settlement proposing changes to the PCA mechanism. The settlement agreement will not take effect until January 1, 2017. Key components of the settlement will include the following changes to the PCA mechanism:
Annual Power Cost Variability
Company's Share
Customers’ Share
 
Over
Under
Over
Under
+/- $17 million
100%
100%
—%
—%
+/- $17 million - $40 million
35
50
65
50
+/- $40 + million
10
10
90
90

•
Reduction to the cumulative deferral trigger for surcharge or refund from $30.0 million to $20.0 million;
•
Removal of fixed production costs from the PCA mechanism and placing them in the decoupling mechanism, assuming the decoupling mechanism continues as part of the next GRC. If decoupling was not to continue, those fixed production costs would be treated the same as other non-PCA costs unless permission to treat them in another manner is obtained from the Washington Commission. These fixed production costs include: (i) return and depreciation/amortization on fixed production assets and regulatory assets and liabilities; (ii) return on, depreciation, transmission expense and revenues on specific transmission assets; and (iii) hydro, other production and other power related expenses and O&M costs;
•
Suspension of the requirement that a GRC must be filed within three months after rates are approved in a Power Cost Only Rate Case (PCORC), and agreeing, for a five-year period, that PSE will not file a GRC or PCORC within six months of the date rates go into effect for a PCORC filing; and
•
Establishment of a five-year moratorium on changes to the PCA/PCORC.

PSE had an unfavorable PCA imbalance for the three and six months ended June 30, 2016, which was $14.8 million and $3.1 million, respectively, above the “power cost baseline” level, of which no amount was apportioned to customers. This compares to an unfavorable PCA imbalance for the three and six months ended June 30, 2015, which was $3.0 million and $5.0 million, respectively, above the "power cost baseline" level, of which no amount was apportioned to customers.

Conservation Rider
On April 28, 2016, the Washington Commission approved PSE's request to implement changes to rates under its electric conservation rider mechanism, effective May 1, 2016.  The approved rate change incorporates a decrease in the amounts budgeted and the true-up of costs and collections.  This represents a rate decrease for electric customers of $11.7 million, or 0.5% annually.

Property Tax Tracker Mechanism
On April 28, 2016, the Washington Commission approved PSE's request to change rates under its electric property tax tracker mechanism, effective May 1, 2016.  The approved rate change incorporates the effects of an increase to property taxes paid as well as true-ups to the rate from the prior year.  This represents a rate increase for electric customers of $5.7 million, or 0.3% annually.

34


Federal Incentive Tracker Tariff
On December 30, 2015, the Washington Commission approved the annual true-up and rate filing to PSE's Federal Incentive Tracker Tariff, effective January 1, 2016. The true-up filing resulted in a total credit of $57.3 million to be passed back to eligible customers over the twelve months beginning January 1, 2016.  The total credit includes $39.6 million which represents the pass-back of grant amortization and $17.7 million represents the pass through of interest, in addition to a minor true-up associated with the 2015 rate period.  This filing represents an overall average rate decrease of 0.2% annually.

Natural Gas Rates
Purchased Gas Adjustment
On October 29, 2015, the Washington Commission approved PSE's PGA natural gas tariff filing with an effective date of November 1, 2015, which reflected changes in wholesale gas and pipeline transportation costs and changes in deferral amortization rates. The impact to the PGA rates is an annual revenue decrease of $185.9 million, or 17.4% annually, with no impact on net operating income.

Conservation Rider
On April 28, 2016, the Washington Commission approved PSE's request to implement changes to rates under its natural gas conservation rider mechanism, effective May 1, 2016.  The approved rate change reflects actual costs and collections for the conservation program.  This represents a rate increase for natural gas customers of $2.9 million, or 0.3% annually.

Cost Recovery Mechanism
On October 29, 2015, the Washington Commission approved PSE's CRM natural gas tariff filing with an effective date of November 1, 2015. The purpose of this filing is to recover capital costs related to enhancing the safety of the natural gas distribution system.  The impact to the CRM rates is an annual revenue increase of $5.3 million, or 0.5% annually.

Property Tax Tracker Mechanism
On April 28, 2016, the Washington Commission approved PSE's request to change rates under its natural gas property tax tracker mechanism, effective May 1, 2016.  This represents a rate increase for natural gas customers of $3.5 million or 0.4% annually.

Other Factors and Trends
Weather Conditions
Weather conditions in PSE's service territory have an impact on customer energy usage, affecting PSE's billed revenue and energy supply expenses. PSE's operating revenue and associated energy supply expenses are not generated evenly throughout the year. While both PSE's electric and natural gas sales are generally greatest during winter months, variations in energy usage by customers occur from season to season and also 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.

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

Access to Debt Capital
PSE relies on access to bank borrowings and short-term money markets as sources of liquidity and longer-term capital markets to fund its utility construction program, to meet maturing debt obligations and other capital expenditure requirements not satisfied by cash flow from its operations or equity investment from its parent, Puget Energy. Neither Puget Energy nor PSE have any debt outstanding whose maturity would accelerate upon a credit rating downgrade. However, a ratings downgrade could adversely affect the Company's ability to renew existing, or obtain access to new credit facilities and could increase the cost of such facilities. For example, under Puget Energy's and PSE's credit facilities, the borrowing costs increase as their respective credit ratings decline due to increases in credit spreads and commitment fees. If PSE is unable to access debt capital on reasonable terms, its ability to

35

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 mature in 2019 and Puget Energy's senior secured credit facility matures in 2018. (See discussion on credit facilities in Item 2, “Financing Program - Credit Facilities”).

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 by-products 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 on measures including, but not limited to, resource planning, remediation, monitoring, pollution control equipment and emissions-related abatement and fees.
Compliance with these or other future regulations, such as those pertaining to climate change, 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
Competition
PSE’s electric and natural gas utility retail customers generally do not have the ability to choose their electric or natural gas supplier and therefore, PSE’s business has historically been recognized as a natural monopoly. However, PSE faces competition from public utility districts and municipalities that want to establish their own municipal-owned utility, as a result of which PSE may lose a number of customers in its service territory. Further, PSE faces increasing competition for sales to its retail customers.  Alternative methods of electric energy generation, including solar and other self-generation methods, compete with PSE for sales to existing electric retail customers.  In addition, PSE’s natural gas customers may elect to use heating oil, propane or other fuels instead of using and purchasing natural gas from PSE. 

Results of Operations
Puget Sound Energy
Non-GAAP Financial Measures - Electric and Natural 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 natural 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 includes adjustments that result in a departure from GAAP presentation.  The presentation of electric margin and gas margin is intended to supplement an understanding of PSE’s operating performance.  Electric margin and natural gas margin are used by PSE to determine whether PSE is collecting the appropriate amount of revenue from its customers to maintain electric and gas margins to ultimately provide adequate recovery of operating costs, including interest and equity returns.  PSE’s electric margin and natural gas margin measures may not be comparable to other companies’ electric margin and natural 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.


36

Electric Margin
Electric margin represents electric sales to retail and transportation customers less the cost of generating and purchasing electric energy sold to customers, including transmission costs, to bring electric energy to PSE's service territory. The following table displays the details of PSE's electric margin changes:
Electric Margin
Three Months Ended June 30,
 
Six Months Ended
June 30,
 
(Dollars in Thousands)
2016
2015
Change
2016
2015

Change
Electric operating revenue:
 
 
 
 
 


Residential sales
$
231,345

$
220,343

$
11,002

$
576,176

$
506,369

$
69,807

Commercial sales
197,668

198,439

(771
)
429,394

420,729

8,665

Industrial sales
24,975

26,811

(1,836
)
54,677

55,761

(1,084
)
Other retail sales
4,868

5,237

(369
)
10,202

10,233

(31
)
Total retail sales
458,856

450,830

8,026

1,070,449

993,092

77,357

Transportation sales
2,779

2,291

488

5,622

4,529

1,093

Sales to other utilities and marketers
10,729

5,691

5,038

17,538

12,268

5,270

Decoupling revenue
15,783

8,730

7,053

34,476

22,898

11,578

Other decoupling adjustments 1
4,538

(4,499
)
9,037

(2,663
)
3,043

(5,706
)
Other
4,467

6,573

(2,106
)
1,921

7,413

(5,492
)
Total electric operating revenues 2
497,152

469,616

27,536

1,127,343

1,043,243

84,100

Minus electric energy costs:
 

 

 
 

 

 
Purchased electricity 2
118,551

104,471

14,080

261,448

257,951

3,497

Electric generation fuel 2
40,930

55,652

(14,722
)
95,123

103,668

(8,545
)
Residential exchange 2
(13,376
)
(29,054
)
15,678

(33,516
)
(72,768
)
39,252

Total electric energy costs
146,105

131,069

15,036

323,055

288,851

34,204

Electric margin 3
$
351,047

$
338,547

$
12,500

$
804,288

$
754,392

$
49,896

 
 
 
 
 
 
 
Electric Energy Sales, MWh
 
 
 
 
 
 
Residential sales
2,062,717

2,187,386

(124,669
)
5,175,549

5,083,955

91,594

Commercial sales
2,083,751

2,173,307

(89,556
)
4,370,929

4,437,238

(66,309
)
Industrial sales
284,081

321,664

(37,583
)
591,171

624,748

(33,577
)
Other retail sales
21,362

24,315

(2,953
)
46,096

48,518

(2,422
)
Total energy sales to customers
4,451,911

4,706,672

(254,761
)
10,183,745

10,194,459

(10,714
)
_____________
1 
Includes amortization of prior year collection/refund, adjustments related to excess rate of return, and adjustments related to amounts that will not be collected within 24 months.
2 
As reported on PSE’s Consolidated Statement of Income.
3 
Electric margin does not include any allocation for amortization/depreciation expense or electric generation operation and maintenance expense.

Three Months Ended June 30, 2016 compared to 2015
Electric Operating Revenue
Electric operating revenues increased $27.5 million primarily due to higher residential sales of $11.0 million, other decoupling revenue of $9.0 million, decoupling revenue of $7.1 million, and sales to other utilities and marketers of $5.0 million.   These items are discussed in detail below.
•
Electric retail sales increased $8.0 million primarily due to increases in residential rates of $25.0 million and partially offset by $12.6 million due to a decrease in residential electricity usage of 124,669 Megawatt Hour (MWhs), mostly from slightly warmer temperatures than the prior year.
•
Sales to other utilities and marketers increased $5.0 million due to less usage by retail customers; therefore, there was more energy to sell in the wholesale market.

37

•
Decoupling revenue increased $7.1 million due to the allowed decoupled revenues per customer as compared to lower volumetric revenues.
•
Other decoupling adjustments increased $9.0 million due to the impact of $13.3 million primarily related to a 2015 adjustment of sharing of excess earnings; partially offset by a $3.6 million increase in the amortization of prior year collection.

Electric Energy Costs
•
Purchased electricity expense increased $14.1 million primarily due to an increase of $13.5 million of firm purchases and $4.7 million of PURPA purchases, partially offset by a $6.5 million decrease related to secondary purchases.
•
Electric generation fuel expense decreased $14.7 million primarily due to a decrease in natural gas fuel costs of $5.3 million at Goldendale and $4.7 million at Mint Farm.
•
Residential exchange credits decreased $15.7 million resulting from lower Residential Exchange Program (REP) credits associated with the BPA REP settlement.  The REP credit tariff was lowered effective October 1, 2015. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.
The Northwest Power Act, through the REP, provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE.  The program is administered by the BPA.  Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.

Six Months Ended June 30, 2016 compared to 2015
Electric Operating Revenue
Electric operating revenues increased $84.1 million primarily due to higher residential sales of $69.8 million, commercial sales of $8.7 million, decoupling revenue of $11.6 million and sales to other utilities and marketers of $5.3 million, which revenues were partially offset by decreases in other decoupling revenue of $5.7 million and other electric operating revenue of $5.5 million.  These items are discussed in detail below.
•
Electric retail sales increased $77.4 million due to increases in rates of $59.6 million and $9.1 million due to an increase in residential electricity usage of 91,594 MWhs. In addition, there was an increase of $15.2 million due to an increase in rates for commercial customers which was partially offset by $6.3 million due to a decrease in electricity usage of 66,309 MWhs.
•
Sales to other utilities and marketers increased $5.3 million due to less usage by retail customers; therefore, there was more energy to sell in the wholesale market.
•
Decoupling revenue increased $11.6 million due to the allowed decoupled revenues per customer as compared to lower volumetric revenues.
•
Other decoupling adjustments decreased $5.7 million primarily due to an increase in the amortization of prior year collection of $11.6 million, partially offset by the impact of a $6.5 million sharing of the excess earnings related to the decoupling mechanism.
•
Other electric operating revenue decreased $5.5 million primarily due to a reduction of non-core gas sales of $7.7 million. In addition, the decrease was partially offset by a reduction of PTC deferral of $3.3 million.

Electric Energy Costs
•
Purchased electricity expense increased $3.5 million primarily due to an $18.6 million increase related to long-term firm purchases and $6.4 million in PURPA purchases, partially offset by a $24.3 million decrease in secondary purchases.
•
Electric generation fuel expense decreased $8.5 million primarily due to a decrease in natural gas energy costs of $6.2 million at Goldendale and $6.1 million at Mint Farm.
•
Residential exchange credits decreased $39.3 million resulting from lower REP credits associated with the BPA REP settlement.  The REP credit tariff was lowered effective October 1, 2015. The REP credit is a pass-through tariff item with a corresponding credit in electric operating revenue, with no impact on net income.
The Northwest Power Act, through the REP, provides access to the benefits of low-cost federal power for residential and small farm customers of regional utilities, including PSE.  The program is administered by the BPA.  Pursuant to agreements (including settlement agreements) between the BPA and PSE, the BPA has provided payments of REP benefits to PSE, which PSE has passed through to its residential and small farm customers in the form of electricity bill credits.


38

Natural Gas Margin
Natural gas margin is natural gas sales to retail and transportation customers less the cost of natural gas purchased, including transportation costs to bring natural gas to PSE's service territory. The following table displays the details of PSE's natural gas
margin:
Natural Gas Margin
Three Months Ended June 30,
 
Six Months Ended
June 30,
 
(Dollars in Thousands)
2016
2015
Change
2016
2015
Change
Natural gas operating revenue:
 
 
 
 
 

Residential sales
$
92,099

$
111,299

$
(19,200
)
$
309,830

$
328,254

$
(18,424
)
Commercial sales
44,125

57,652

(13,527
)
125,273

147,722

(22,449
)
Industrial sales
3,627

5,054

(1,427
)
10,393

12,177

(1,784
)
Total retail sales
139,851

174,005

(34,154
)
445,496

488,153

(42,657
)
Transportation sales
5,018

4,640

378

10,111

9,251

860

Decoupling revenue
15,979

10,353

5,626

36,030

37,940

(1,910
)
Other decoupling adjustments 1
(297
)
(7,373
)
7,076

(10,661
)
(8,179
)
(2,482
)
Other
2,892

3,316

(424
)
5,875

6,638

(763
)
Total natural gas operating revenues 2
163,443

184,941

(21,498
)
486,851

533,803

(46,952
)
Minus purchased natural gas energy costs 2
48,273

79,465

(31,192
)
171,376

235,898

(64,522
)
Natural gas margin 3
$
115,170

$
105,476

$
9,694

$
315,475

$
297,905

$
17,570

 
 
 
 
 
 
 
Natural Gas Volumes, therms (thousands):
 
 
 
 
 
 
Residential
72,506

80,671

(8,165
)
286,531

262,217

24,314

Commercial firm
41,387

44,139

(2,752
)
127,467

120,593

6,874

Industrial firm
4,394

5,054

(660
)
12,389

12,373

16

Interruptible
8,582

11,516

(2,934
)
24,377

24,168

209

Total retail natural gas volumes, therms
126,869

141,380

(14,511
)
450,764

419,351

31,413

Transportation volumes
56,164

53,495

2,669

118,249

111,206

7,043

Total natural gas volumes
183,033

194,875

(11,842
)
569,013

530,557

38,456

___________________
1 
Includes amortization of prior year collection/refund, adjustments related to excess rate of return, and adjustments related to amounts that will not be collected within 24 months.
2 
As reported on PSE’s Consolidated Statement of Income.
3 
Natural gas margin does not include any allocation for amortization/depreciation expense or natural gas operations and maintenance expense.

Three Months Ended June 30, 2016 compared to 2015
Natural Gas Operating Revenue
Natural gas operating revenue decreased $21.5 million due primarily to a decrease of $34.2 million in total retail sales primarily the result of a PGA rate reduction; partially offset by $7.1 million in other decoupling revenue and $5.6 million in decoupling revenue. These items are discussed in detail below.
•
Natural gas retail sales revenue decreased $34.2 million primarily due to a decrease in natural gas retail sales as a result of a PGA rate reduction of $19.1 million and a decrease of $17.0 million decrease due to 14,511 lower therms sold.
•
Decoupling revenue increased $5.6 million due to the allowed decoupled revenues per customer as compared to lower volumetric revenues.
•
Other decoupling adjustments increased $7.1 million due to the impact of $5.4 million primarily related to a 2015 adjustment of sharing of excess earnings and a decrease of $4.6 million in the 24-month revenue reserve; partially offset by an increase in the amortization of prior year collection of $2.9 million.


39

Natural Gas Energy Costs
Purchased natural gas expense decreased $31.2 million due to a reduction in the PGA rates and lower therms sold.

Six Months Ended June 30, 2016 compared to 2015
Natural Gas Operating Revenue
Natural gas operating revenue decreased $47.0 million due primarily to a decrease of $42.7 million in total retail sales primarily the result of a PGA rate reduction and a $2.5 million decrease in other decoupling revenue. These items are discussed in detail below.
•
Natural gas retail sales revenue decreased $42.7 million primarily due to a decrease in natural gas retail sales as a result of a PGA rate reduction of $75.3 million, partially offset by $38.2 million increase due to higher therms sold.
•
Other Decoupling adjustments decreased $2.5 million primarily due to an increase in the amortization of prior year collection of $10.1 million; partially offset by a decrease of $4.6 million in the 24-month revenue reserve and the impact of a $3.0 million sharing of the excess earnings related to the decoupling mechanism.

Natural Gas Energy Costs
Purchased natural gas expense decreased $64.5 million due to a reduction in the PGA rates offset by higher therms sold.

Other Operating Expenses and Other Income (Deductions)
The following table displays the details of PSE's operating expenses and other income (deductions) for the three and six months ended June 30, 2016 and 2015:
Puget Sound Energy
Three Months Ended June 30,
 
Six Months Ended
June 30,
 
(Dollars in Thousands)
2016
2015
Change
2016
2015
Change
Operating expenses:
 

 

 

 
 
 
Net unrealized (gain) loss on derivative instruments
$
(46,724
)
$
(8,232
)
$
(38,492
)
$
(63,546
)
$
(11,383
)
$
(52,163
)
Utility operations and maintenance
138,018

131,972

6,046

284,008

269,147

14,861

Non-utility expense and other
8,822

6,342

2,480

17,856

13,349

4,507

Depreciation and amortization
111,273

100,412

10,861

218,787

206,589

12,198

Conservation amortization
22,540

24,561

(2,021
)
55,751

54,165

1,586

Taxes other than income taxes
67,871

69,999

(2,128
)
170,163

164,912

5,251

Other income (deductions):
 
 
 
 
 
 
Other income
7,077

5,255

1,822

13,052

10,039

3,013

Other expense
(2,122
)
(1,815
)
(307
)
(3,462
)
(3,222
)
(240
)
Interest expense
(58,044
)
(60,922
)
2,878

(116,460
)
(122,719
)
6,259

Income tax expense
38,002

22,572

15,430

109,140

75,955

33,185


Three Months Ended June 30, 2016 compared to 2015
Other Operating Expenses
•
Net unrealized (gain) loss on derivative instruments increased $38.5 million. The net gain in 2016 was comprised of a gain of $45.3 million related to natural gas for power derivative instruments and a $1.4 million gain related to PSE's electric derivative instruments.  This compares to a gain of $4.3 million related to natural gas for power derivative instruments and a gain of $3.9 million related to PSE's electric derivative instruments during the prior year.  The overall gain was primarily due to decreases in natural gas and wholesale electricity forward prices. 
•
Utility operations and maintenance expense increased $6.0 million which was primarily driven by increased generation operation and maintenance expense of $3.1 million, an increase of $2.6 million of administrative and general expense, an increase in gas operations expense of $2.2 million and an increase in electric transmission and distribution expense of $2.1 million; partially offset by a decrease in meter reading non-production expense of $3.3 million.

40

•
Non-utility expense and other expense increased $2.5 million primarily due to an increase in cost of biogas of $3.3 million.
•
Depreciation and amortization expense increased $10.9 million primarily due to $6.4 million of regulatory credits related to the JPUD gain on sale returned to customers in 2015 and an increase of $4.6 million of depreciation expense in 2016 due to an increase in net additions of assets.

Other Income, Interest Expense and Income Tax Expense
•
Interest expense decreased $2.9 million primarily due a reduction of $2.0 million of interest on long term debt, and an increase of $0.9 million of AFUDC debt.
•
Income tax expense increased $15.4 million primarily driven by a higher pre-tax income.

Six Months Ended June 30, 2016 compared to 2015
Other Operating Expenses
•
Net unrealized (gain) loss on derivative instruments increased $52.2 million. The net gain in 2016 was comprised of a gain of $50.8 million related to natural gas for power derivative instruments and a $12.7 million gain related to electric derivative instruments.  This compares to a gain of $17.4 million related to electricity derivative instruments and a loss of $6.0 million related to natural gas for power derivative instruments during the prior year.  The overall gain was primarily due to decreases in natural gas and wholesale electricity forward prices. 
•
Utility operations and maintenance expense increased $14.9 million which was driven by increased storm expense of $6.8 million, an increase of $5.6 million of generation operation and maintenance expense, an increase of $3.9 million of administrative and general expense and an increase of $3.5 million of natural gas operations expense; partially offset by a decrease in meter reading non-production expense of $7.0 million.
•
Non-utility expense and other expense increased $4.5 million due primarily to an increase in cost of biogas of $5.9 million.
•
Depreciation and amortization expense increased $12.2 million primarily due to an increase of $8.4 million of depreciation expense due to an increase in net additions of assets and $4.7 million of regulatory credits related to the JPUD gain on sale returned to customers in 2015.
•
Taxes other than income taxes increased $5.3 million primarily due to an increase in electric municipal taxes of $4.2 million, electric property tax amortization of $3.5 million, electric state excise taxes of $2.9 million; partially offset by electric property taxes of $2.3 million, natural gas municipal taxes of $1.9 million, and natural gas state excise taxes of $1.7 million; all of which are based on changes in sales volumes for electricity and natural gas.

Other Income, Interest Expense and Income Tax Expense
•
Other income increased $3.0 million primarily due to an increase in AFUDC equity of $3.2 million
•
Interest expense decreased $6.3 million primarily due a reduction of $4.4 million of interest on long term debt, and an increase of $1.8 million of AFUDC debt.
•
Income tax expense increased $33.2 million primarily driven by a higher pre-tax income.


41

Puget Energy
All the operations of Puget Energy are conducted through its subsidiary PSE. Puget Energy's net income (loss) for the three and six months ended June 30, 2016 and 2015 are as follows:
Benefit/(Expense)
Three Months Ended June 30,
 
Six Months Ended
June 30,
 
(Dollars in Thousands)
2016
2015
Change
2016
2015
Change
PSE net income
$
80,900

$
42,699

$
38,201

$
237,406

$
171,799

$
65,607

Net unrealized gain on energy derivative instruments
—

—

—

—

544

(544
)
Non-utility expense and other
3,644

4,019

(375
)
7,043

7,806

(763
)
Non-hedged interest rate swap (expense)
(359
)
(1,440
)
1,081

(1,213
)
(3,415
)
2,202

Interest expense 1
(28,029
)
(27,171
)
(858
)
(56,067
)
(52,852
)
(3,215
)
Income tax benefit (expense)
8,397

7,509

888

18,570

17,410

1,160

Puget Energy net income (loss)
$
64,553

$
25,616

$
38,937

$
205,739

$
141,292

$
64,447

_______________
1 
Puget Energy’s interest expense includes elimination adjustments of intercompany interest on short-term debt.

Summary Results of Operation
Three Months Ended June 30, 2016 compared to 2015
Puget Energy’s net income increased by $38.9 million, which is primarily attributable to PSE's net income increase of $38.2 million.  The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:
•
Non-hedged interest rate swap expense decreased $1.1 million primarily due to higher interest rates in 2016 compared to 2015.

Six Months Ended June 30, 2016 compared to 2015
Puget Energy’s net income increased by $64.4 million, which is primarily attributable to PSE's net income increase of $65.6 million.  The following are significant factors that impacted Puget Energy’s net income which are not included in PSE’s discussion:
•
Non-hedged interest rate swap expense decreased $2.2 million primarily due to higher interest rates in 2016 compared to 2015.
•
Interest expense increased $3.2 million primarily due to the long-term senior secured notes issued in May 2015 issued at a higher interest rate and larger principal amount than the previous term loans.

Capital Requirements
Contractual Obligations and Commercial Commitments
There have been no material changes to the contractual obligations and consolidated commercial commitments set forth in Part II, Item 7 in the Company's Annual Report on Form 10-K for the year ended December 31, 2015.


42

The following are the Company's aggregate availability under commercial commitments as of June 30, 2016:
Puget Sound Energy and
Puget Energy
Amount of Available Commitments
Expiration Per Period
(Dollars in Thousands)
Total

2016
2017-2018

2019-2020

Thereafter

PSE liquidity facility 1
$
650,000

$
—

$
—

$
650,000

$
—

PSE energy hedging facility 1
350,000

—

—

350,000

—

Inter-company short-term debt 2
30,000

—

—

—

30,000

Total PSE commercial commitments
$
1,030,000

$
—

$
—

$
1,000,000

$
30,000

Puget Energy revolving credit facility 3
800,000

—

800,000

—

—

Less: Inter-company short-term debt elimination 2
(30,000
)
—

—

—

(30,000
)
Total Puget Energy commercial commitments
$
1,800,000

$
—

$
800,000

$
1,000,000

$
—

_______________
1 
For more information, see PSE Credit Facilities.
2  
For more information, see PSE Demand Promissory Note.
3 
For more information, see Puget Energy Credit Facilities.

Off-Balance Sheet Arrangements
As of June 30, 2016, the Company had no off-balance sheet arrangements that have or are reasonably likely to have a material effect on the Company's financial condition.

Utility Construction Program
PSE’s construction programs for generating facilities, the electric transmission system and the natural gas and electric distribution systems and the LNG are designed to meet regulatory requirements and customer growth and to support reliable energy delivery.  Construction expenditures, excluding equity AFUDC, totaled $303.8 million for the six months ended June 30, 2016.  Presently planned utility construction expenditures, excluding equity AFUDC, are as follows:
Capital Expenditure Projections
 
 
 
(Dollars in Thousands)
2016

2017

2018

Total energy delivery, technology and facilities expenditures
$
806,655

$
815,989

$
665,462


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.  

Capital Resources
Cash from Operations

Six Months Ended June 30, 2016 compared to 2015
Puget Sound Energy
Cash generated from operations increased by $101.0 million, including $65.6 million from net income. The following are significant factors that impacted PSE's cash inflows/outflows from operations.
•
Accounts receivable and unbilled revenue increased $86.4 million. Key drivers were rate changes and improved cash collections processes which led to quicker collections.
•
Accrued expenses and other increased $32.7 million primarily due to lower incentive payout, customer deposits and termination of a capital lease.
•
Net Unrealized loss (gain) on derivative instruments decreased $52.2 million primarily due to a net gain. The net gain in 2016 was comprised of a gain of $50.8 million related to natural gas for power derivative instruments and a $12.7

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million gain related to electric derivative instruments.  The gain was primarily due to decreases in natural gas and wholesale electricity forward prices. 
•
Purchase gas adjustment decreased $37.0 million due to the tracker mechanism which tracks current and prior year over/under gas collections based on rates. The primary reason for the decrease is due to over-collection in cost in 2015, which is being amortized throughout 2016.

Puget Energy
Cash generated from operations for the six months ended June 30, 2016 increased by $88.1 million compared to the same period in 2015.  The net difference was primarily impacted by the increase from cash flow provided by the operating activities of PSE, as previously discussed. The remaining variance is explained below.
•
Derivative contracts classified as financing activities due to merger decreased $8.0 million due to derivatives with a financing element settling in February 2015.

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. The Company believes it has sufficient liquidity through its credit facilities and access to capital markets and operations to fund its needs over the next twelve months.
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 has two unsecured revolving credit facilities which provide, in aggregate, $1.0 billion of short-term liquidity needs. These facilities consist of a $650.0 million revolving liquidity facility (which includes a liquidity letter of credit facility and a swingline facility) to be used for general corporate purposes, including a backstop to the Company's commercial paper program and a $350.0 million revolving energy hedging facility (which includes an energy hedging letter of credit facility). The $650.0 million liquidity facility includes a swingline feature allowing same day availability on borrowings up to $75.0 million. The credit facilities also have an accordion feature which, upon the banks' approval, would increase the total size of these facilities to $1.45 billion. These unsecured revolving credit facilities mature in April 2019.
The credit agreements are syndicated among numerous lenders and contain usual and customary affirmative and negative covenants that, among other things, place limitations on PSE's ability to transact with affiliates, make asset dispositions and investments or permit liens to exist. The credit agreements also contain a financial covenant of total debt to total capitalization of 65% or less. PSE certifies its compliance with such covenants to participating banks each quarter. As of June 30, 2016, PSE was in compliance with all applicable covenant ratios.
The credit agreements provide PSE with the ability to borrow at different interest rate options. The credit agreements allow PSE to borrow at the bank's prime rate or to make floating rate advances at London Interbank Offered Rate (LIBOR) plus a spread that is based upon PSE's credit rating. PSE must pay a commitment fee on the unused portion of the credit facilities. The spreads and the commitment fee depend on PSE's credit ratings. As of the date of this report, the spread to the LIBOR is 1.25% and the commitment fee is 0.175%.
As of June 30, 2016, no amounts were drawn and outstanding under PSE's $650.0 million liquidity facility. No letters of credit were outstanding under either facility, and $36.0 million was outstanding under the commercial paper program. Outside of the credit agreements, PSE had a $3.9 million letter of credit in support of a long-term transmission contract and a $1.0 million letter of credit in support of natural gas purchases in Canada.

Demand Promissory Note
In, 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 or PSE's senior unsecured revolving credit facility. Absent such borrowings, interest is charged at one-month LIBOR plus 0.25%. On June 30, 2015, PSE repaid in full the $28.9 million outstanding balance under the Note.

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Debt Restrictive Covenants
The type and amount of future long-term financings for PSE may be limited by provisions in PSE's electric and natural gas mortgage indentures.
PSE’s ability to issue additional secured debt may also be limited by certain restrictions contained in its electric and natural gas mortgage indentures.  Under the most restrictive tests, at June 30, 2016, PSE could issue:
•
Approximately $2.4 billion of additional first mortgage bonds under PSE’s electric mortgage indenture based on approximately $3.9 billion of electric bondable property available for issuance, subject to a minimum interest coverage ratio of 2.0 times net earnings available for interest (as defined in the electric utility mortgage), which PSE exceeded at June 30, 2016; and
•
Approximately $415.0 million of additional first mortgage bonds under PSE’s natural gas mortgage indenture based on approximately $691.7 million of gas bondable property available for issuance, subject to a minimum 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, 2016.

At June 30, 2016, PSE had approximately $6.9 billion in electric and natural gas rate base to support the interest coverage ratio limitation test for net earnings available for interest.

Shelf Registrations
PSE has in effect a shelf registration statement under which it may issue, from time to time, up to $375.0 million aggregate principal amount of 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.

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, 2016, approximately $531.5 million of unrestricted retained earnings was available for the payment of dividends under the most restrictive mortgage indenture covenant.
Pursuant to the terms of the Washington Commission merger order, PSE may not declare or pay dividends if PSE’s common equity ratio, calculated on a regulatory basis, is 44.0% or below except to the extent a lower equity ratio is ordered by the Washington Commission.  Also, pursuant to the merger order, PSE may not declare or make any distribution unless on the date of distribution PSE’s corporate credit/issuer rating is investment grade, or, if its credit ratings are below investment grade, PSE’s ratio of Earnings Before Interest, Tax, Depreciation and Amortization (EBITDA) to interest expense for the most recently ended four fiscal quarter periods prior to such date is equal to or greater than 3 to one.  The common equity ratio, calculated on a regulatory basis, was 49.2% at June 30, 2016 and the EBITDA to interest expense was 5.2 to one for the 12 months ended June 30, 2016.
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 (as defined in the facilities), or if the payment of dividends would result in an Event of Default, such as failure to comply with certain financial covenants.

Puget Energy
Credit Facility
At June 30, 2016, Puget Energy maintained an $800.0 million revolving senior secured credit facility, which matures April 2018. The Puget Energy revolving senior secured credit facility also has an accordion feature which, upon the banks' approval, would increase the size of the facility to $1.3 billion.
The revolving senior secured credit facility provides Puget Energy the ability to borrow at different interest rate options and includes variable fee levels. Interest rates may be based on the bank's prime rate or LIBOR, plus a spread based on Puget Energy's credit ratings. Puget Energy must pay a commitment fee on the unused portion of the facility. As of June 30, 2016, there was no amount drawn and outstanding under the facility. As of the date of this report, the spread over LIBOR was 1.75% and the commitment fee was 0.275% as of the date of this report. Puget Energy entered into interest rate swap contracts to manage the interest rate risk associated with the credit facility or similar variable rate debt (see Note 3 for more details).
The revolving senior secured credit facility contains usual and customary affirmative and negative covenants. The agreement also contains a maximum leverage ratio financial covenant as defined in the agreement governing the senior secured credit facility. As of June 30, 2016, Puget Energy was in compliance with all applicable covenants.


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Dividend Payment Restrictions
Puget Energy’s ability to pay dividends is also limited by the merger order issued by the Washington Commission.  Pursuant to the merger order, Puget Energy may not declare or make a distribution unless on such date Puget Energy’s ratio of consolidated EBITDA to consolidated interest expense for the four most recently ended fiscal quarters prior to such date is equal to or greater than 2 to one.  Puget Energy's EBITDA to interest expense was 3.5 to one for the 12 months ended June 30, 2016.
At June 30, 2016, the Company was in compliance with all applicable covenants, including those pertaining to the payment of dividends.

Other

New Accounting Pronouncements
For the discussion of new accounting pronouncements, see Note 2 in the Combined Notes to the Consolidated Financial Statements in Part I.

Colstrip 
PSE has a 50% ownership interest in Colstrip Units 1 and 2, and a 25% interest in Colstrip Units 3 and 4. On March 6, 2013, the Sierra Club and the Montana Environmental Information Center filed a Clean Air Act citizen suit against all Colstrip owners in the U.S. District Court, District of Montana. Based on a second amended complaint filed in August 2014, plaintiffs' lawsuit alleged violations of permitting requirements under the New Source Review program of the Clean Air Act and the Montana State Implementation Plan arising from seven projects undertaken at Colstrip during the time period from 2001 to 2012. On July 12, 2016, PSE reached a settlement with the Sierra Club to dismiss all of the Clean Air Act allegations against the Colstrip Generating Station. As part of the settlement, which has been filed with the court for its approval, PSE has agreed, along with Talen Energy, to retire the two oldest units (Units 1 and 2) at Colstrip in eastern Montana by no later than July 1, 2022. Colstrip Units 3 and 4, which are newer and more efficient, are not affected by the shutdown, and allegations in the lawsuit against Colstrip Units 3 and 4 were dismissed as part of the settlement. PSE is not able to determine the decommissioning costs of Colstrip Units 1 and 2 at this time; however, any associated decommissioning and historical costs are expected to be fully recovered through rates.

Coal Combustion Residuals
On April 17, 2015, the U.S. Environmental Protection Agency (EPA) published a final rule, effective October 19, 2015, that regulates CCRs under the Resource Conservation and Recovery Act, Subtitle D. The CCR rule addresses the risks from coal ash disposal, such as leaking of contaminants into ground water, blowing of contaminants into the air as dust, and the catastrophic failure of coal ash containment structures by establishing technical design, operation and maintenance, closure and post closure care requirements for CCR landfills and surface impoundments, and corrective action requirements for any related leakage. The rule also sets forth recordkeeping and reporting requirements, including posting specific information related to CCR surface impoundments and landfills to publicly-accessible websites.
The CCR rule requires significant changes to the Company's Colstrip operations and those changes were reviewed by the Company and the plant operator in the second quarter of 2015. PSE had previously recognized a legal obligation under the EPA rules to dispose of coal ash material at Colstrip in 2003. Due to the CCR rule, additional disposal costs were added to the Asset Retirement and Environmental Obligations (ARO).

Clean Air Act 111(d)/EPA Clean Power Plan
In June 2014, the EPA issued a proposed Clean Power Plan rule under Section 111(d) of the Clean Air Act designed to regulate GHG emissions from existing power plants. The proposed rule includes state-specific goals and guidelines for states to develop plans for meeting these goals. PSE filed comments on this rule in December 2014. The EPA issued a pre-publication version of the final Clean Power Plan rule under Section 111(d) on August 3, 2015 and published a final rule on October 23, 2015. PSE is reviewing the final rule and working with key stakeholders in preparation towards implementation. PSE cannot yet provide a determination of how the final rule may impact PSE or its existing generation facilities, if at all.


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Related Party Transactions
Scott Armstrong serves on the Board of Directors of the Company, and is the president and Chief Executive Officer of Group Health Cooperative (Group Health). Group Health provides coverage to over 600,000 residents in Washington and Northern Idaho. Certain employees of PSE elect Group Health as their medical provider and as a result, PSE paid Group Health a total of $10.7 million and $20.3 million for medical coverage for the six months ended June 30, 2016, and the year ended December 31, 2015, respectively.


Item 3.      Quantitative and Qualitative Disclosure about Market Risk

The Company is exposed to various forms of market risk, consisting primarily of fluctuations in commodity prices, counterparty credit risk, as well as interest rate risk. PSE maintains risk policies and procedures to help manage the various risks. There have been no material changes to market risks affecting the Company from those set forth in Part II, Item 7A of the Company’s Annual Report on Form 10-K for the year ended December 31, 2015.

Commodity Price Risk
The nature of serving regulated electric and natural gas customers with its portfolio of owned and contracted electric generation resources exposes PSE and its customers to some volumetric and commodity price risks. PSE’s Energy Management Committee (EMC) establishes energy risk management policies and procedures to manage commodity and volatility risks and the related effects on credit, tax, accounting, financing and liquidity.    
PSE's objective is to minimize commodity price exposure and risks associated with volumetric variability in the natural gas and electric portfolios. It is not engaged in the business of assuming risk for the purpose of speculative trading.  PSE hedges open natural gas and electric positions to reduce both the portfolio risk and the volatility risk in prices.  

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 counterparty analysis and measurement, monitoring and mitigation of exposure. Additionally, PSE has entered into commodity master arrangements (i.e., WSPP, Inc. (WSPP), International Swaps and Derivatives Association (ISDA) or North American Energy Standards Board (NAESB) with its counterparties to mitigate credit exposure to those counterparties.
  
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 swaps or other financial hedge instruments to manage the interest rate risk associated with the debt.


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, 2016, 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.


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Changes in Internal Control over Financial Reporting
There were no changes in the Company's internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

Puget Sound Energy
Evaluation of Disclosure Controls and Procedures
Under the supervision and with the participation of PSE’s management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer, PSE has evaluated the effectiveness of its disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934) as of June 30, 2016, 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 were no changes in the Company's internal control over financial reporting that occurred during the period covered by this quarterly report that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting. 

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PART II                    OTHER INFORMATION

Item 1.                         Legal Proceedings

Contingencies arising out of the Company's normal course of business existed as of June 30, 2016.  Litigation is subject to numerous uncertainties and the Company is unable to predict the ultimate outcome of these matters. For details on legal proceedings, see Note 8 in the Combined Notes to Consolidated Financial Statements in Part I.


Item 1A.                      Risk Factors

There have been no material changes from the risk factors set forth in Part I, Item 1A of the Company's Annual Report on Form 10-K for the period ended December 31, 2015.


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/ Matthew R. Marcelia
 
 
Matthew R. Marcelia
Controller and Principal Accounting Officer
Date:  
August 3, 2016
 



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EXHIBIT INDEX

3(i).1
Amended Articles of Incorporation of Puget Energy (incorporated herein by reference to Exhibit 3.1 to Puget Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-16305).
3(i).2
Amended and Restated Articles of Incorporation of Puget Sound Energy, Inc. (incorporated herein by reference to Exhibit 3.2 to Puget Sound Energy’s Current Report on Form 8-K, dated February 6, 2009, Commission File No. 1-4393).
3(ii).1
Amended and Restated Bylaws of Puget Energy dated February 6, 2009 (incorporated herein by reference to Exhibit 3.3 to Puget Energy’s Current Report on Form 8-K, Commission File No. 1-16305).
3(ii).2
Amended and Restated Bylaws of Puget Sound Energy, Inc. dated February 6, 2009 (incorporated herein by reference to Exhibit 3.4 to Puget Sound Energy’s Current Report on Form 8-K, Commission File No. 1-4393).
12.1*
Statement setting forth computation of ratios of earnings to fixed charges of Puget Energy, Inc. (2011 through 2015 and 12 months ended June 30, 2016).
12.2*
Statement setting forth computation of ratios of earnings to fixed charges of Puget Sound Energy, Inc. (2011 through 2015 and 12 months ended June 30, 2016).
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, 2016 filed on August 3, 2016 formatted in XBRL: (i) the Consolidated Statement of Income (Unaudited), (ii) the Consolidated Statements of Comprehensive Income (Unaudited), (iii) the Consolidated Balance Sheets (Unaudited), (iv) the Consolidated Statements of Cash Flows (Unaudited), and (v) the Notes to Consolidated Financial Statements (submitted electronically herewith).
__________________
*
Filed herewith.



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