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EX-12 - EXHIBIT 12 FIXED CHARGES - NORTHWEST NATURAL GAS COnwn-2015x630x10qxexhibit12.htm
EX-32.1 - EXHIBIT 32.1 CEO AND CFO CERTIFICATION - NORTHWEST NATURAL GAS COnwn-2015x630x10qxexhibit321.htm
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - NORTHWEST NATURAL GAS COnwn-2015x630x10qxexhibit312.htm
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - NORTHWEST NATURAL GAS COnwn-2015x630x10qxexhibit311.htm
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2015


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 1-15973


NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)

Oregon
93-0256722
(State or other jurisdiction of
incorporation or organization)
(I.R.S. Employer
Identification No.)

220 N.W. Second Avenue, Portland, Oregon 97209
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code:  (503) 226-4211
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  
Yes [ X ]     No  [   ]
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   
Yes [ X ]     No  [   ]
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer [ X ]                                                                Accelerated Filer [    ]
Non-accelerated Filer [    ]                                                                   Smaller Reporting Company [    ]
(Do not check if a Smaller Reporting Company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). 
Yes [   ]     No  [ X ]

At July 24, 2015, 27,362,842 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.

 




NORTHWEST NATURAL GAS COMPANY
 For the Quarterly Period Ended June 30, 2015

TABLE OF CONTENTS

 
 
Page
 
 
 
PART 1.
FINANCIAL INFORMATION
 
 
 
 
 
 
 
 
Unaudited Consolidated Financial Statements:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
PART II.
OTHER INFORMATION
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



FORWARD-LOOKING STATEMENTS

This report contains “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such as “anticipates,” “intends,” “plans,” “seeks,” “believes,” “estimates,” “expects” and similar references to future periods. Examples of forward-looking statements include, but are not limited to, statements regarding the following: 
plans, objectives, goals, and strategies;
assumptions and estimates;
future events or performance;
trends, timing and cyclicality;
risks;
earnings and dividends;
capital structure;
growth;
customer rates;
commodity costs;
gas reserves;
operational performance and costs;
energy policy and preferences;
efficacy of derivatives and hedges;
liquidity and financial positions;
project and program development, expansion, or investment;
competition;
procurement and development of gas supplies;
estimated expenditures;
costs of compliance;
credit exposures;
potential efficiencies;
rate or regulatory recovery or refunds;
impacts of laws, rules and regulations;
tax liabilities or refunds;
levels and pricing of gas storage contracts;
local or national disasters, pandemic illness, terrorist activities, including cyber-attacks, and other extreme events;
outcomes and effects of potential claims, litigation, regulatory actions, and other administrative matters;
projected obligations under retirement plans;
availability, adequacy, and shift in mix, of gas supplies;
approval and adequacy of regulatory deferrals;
potential regulatory disallowances;
effects of regulatory mechanisms; and
environmental, regulatory, litigation and insurance costs and recoveries, and the timing thereof.

Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks, and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. We therefore caution you against relying on any of these forward-looking statements. They are neither statements of historical fact nor guarantees or assurances of future performance. Important factors that could cause actual results to differ materially from those in the forward-looking statements are discussed in our 2014 Annual Report on Form 10-K, Part I, Item 1A “Risk Factors” and Part II, Item 7 and Item 7A, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures about Market Risk,” and in Part I, Items 2 and 3, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Quantitative and Qualitative Disclosures About Market Risk,” and Part II, Item 1A, “Risk Factors,” herein.

Any forward-looking statement made by us in this report speaks only as of the date on which it is made. Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We undertake no obligation to publicly update any forward-looking statement, whether as a result of new information, future developments, or otherwise, except as may be required by law.


1








ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)

 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
In thousands, except per share data
 
2015
 
2014
 
2015
 
2014
 
 
 
 
 
 
 
 
 
Operating revenues
 
$
138,280

 
$
133,169

 
$
399,945

 
$
426,555

 
 
 
 
 
 
 

 
 

Operating expenses:
 
 
 
 
 
 
 
 
Cost of gas
 
62,176

 
58,280

 
187,881

 
213,481

Operations and maintenance
 
35,311

 
34,731

 
89,427

 
70,117

General taxes
 
7,649

 
7,183

 
16,381

 
15,365

Depreciation and amortization
 
20,230

 
19,709

 
40,341

 
39,298

Total operating expenses
 
125,366

 
119,903

 
334,030

 
338,261

Income from operations
 
12,914

 
13,266

 
65,915

 
88,294

Other income and expense, net
 
1,135

 
262

 
6,184

 
1,645

Interest expense, net
 
10,438

 
11,677

 
20,919

 
23,219

Income before income taxes
 
3,611

 
1,851

 
51,180

 
66,720

Income tax expense
 
1,414

 
780

 
20,497

 
27,765

Net income
 
2,197

 
1,071

 
30,683

 
38,955

Other comprehensive income:
 
 
 
 
 
 
 
 
Amortization of non-qualified employee benefit plan liability, net of taxes of $217 and $108 for the three months ended and $433 and $216 for the six months ended June 30, 2015 and 2014, respectively
 
331

 
166

 
663

 
331

Comprehensive income
 
$
2,528

 
$
1,237

 
$
31,346

 
$
39,286

Average common shares outstanding:
 
 
 
 
 


 
 

Basic
 
27,343

 
27,139

 
27,322

 
27,116

Diluted
 
27,388

 
27,182

 
27,378

 
27,158

Earnings per share of common stock:
 
 
 
 
 
 
 
 

Basic
 
$
0.08

 
$
0.04

 
$
1.12

 
$
1.44

Diluted
 
0.08

 
0.04

 
1.12

 
1.43

Dividends declared per share of common stock
 
0.465

 
0.460

 
0.930

 
0.920


See Notes to Unaudited Consolidated Financial Statements


2








NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS (UNAUDITED)

In thousands
 
June 30,
2015
 
June 30,
2014
 
December 31,
2014
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
Current assets:
 
 
 
 
 
 
Cash and cash equivalents
 
$
4,466

 
$
17,240

 
$
9,534

Accounts receivable
 
32,041

 
38,621

 
69,818

Accrued unbilled revenue
 
12,760

 
14,592

 
57,963

Allowance for uncollectible accounts
 
(723
)
 
(1,404
)
 
(969
)
Regulatory assets
 
63,016

 
38,265

 
68,562

Derivative instruments
 
1,023

 
11,191

 
243

Inventories
 
76,511

 
60,808

 
77,832

Gas reserves
 
18,214

 
20,373

 
20,020

Income taxes receivable
 

 

 
1,000

Deferred tax assets
 
12,693

 
4,915

 
23,785

Other current assets
 
15,348

 
14,518

 
34,772

Total current assets
 
235,349

 
219,119

 
362,560

Non-current assets:
 
 
 
 
 
 
Property, plant, and equipment
 
3,042,671

 
2,965,226

 
2,992,560

Less: Accumulated depreciation
 
893,722

 
879,296

 
870,967

Total property, plant, and equipment, net
 
2,148,949

 
2,085,930

 
2,121,593

Gas reserves
 
121,355

 
130,280

 
129,280

Regulatory assets
 
342,806

 
267,248

 
368,908

Derivative instruments
 
1,369

 
1,202

 

Other investments
 
68,147

 
67,689

 
68,238

Restricted cash
 
4,500

 
3,000

 
3,000

Other non-current assets
 
9,404

 
12,646

 
11,366

Total non-current assets
 
2,696,530

 
2,567,995

 
2,702,385

Total assets
 
$
2,931,879

 
$
2,787,114

 
$
3,064,945


See Notes to Unaudited Consolidated Financial Statements


















3








NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS (UNAUDITED)

In thousands
 
June 30,
2015
 
June 30,
2014
 
December 31,
2014
 
 
 
 
 
 
 
Liabilities and equity:
 
 
 
 
 
 
Current liabilities:
 
 
 
 
 
 
Short-term debt
 
$
190,300

 
$
74,200

 
$
234,700

Current maturities of long-term debt
 

 
100,000

 
40,000

Accounts payable
 
49,505

 
68,973

 
91,366

Taxes accrued
 
8,782

 
15,769

 
10,031

Interest accrued
 
5,922

 
7,053

 
6,079

Regulatory liabilities
 
26,712

 
26,742

 
19,105

Derivative instruments
 
15,017

 
1,490

 
29,894

Other current liabilities
 
31,332

 
34,507

 
38,235

Total current liabilities
 
327,570

 
328,734

 
469,410

Long-term debt
 
621,700

 
621,700

 
621,700

Deferred credits and other non-current liabilities:
 
 
 
 
 
 
Deferred tax liabilities
 
524,099

 
489,892

 
530,965

Regulatory liabilities
 
328,646

 
309,327

 
317,205

Pension and other postretirement benefit liabilities
 
233,554

 
145,861

 
236,735

Derivative instruments
 
1,077

 
191

 
3,515

Other non-current liabilities
 
118,269

 
120,423

 
118,094

Total deferred credits and other non-current liabilities
 
1,205,645

 
1,065,694

 
1,206,514

Commitments and contingencies (see Note 13)
 

 

 

Equity:
 
 
 
 
 
 
Common stock - no par value; authorized 100,000 shares; issued and outstanding 27,363, 27,147, and 27,284 at June 30, 2015 and 2014 and December 31, 2014, respectively
 
378,887

 
369,315

 
375,117

Retained earnings
 
407,490

 
407,698

 
402,280

Accumulated other comprehensive loss
 
(9,413
)
 
(6,027
)
 
(10,076
)
Total equity
 
776,964

 
770,986

 
767,321

Total liabilities and equity
 
$
2,931,879

 
$
2,787,114

 
$
3,064,945


See Notes to Unaudited Consolidated Financial Statements



4







NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 
 
Six Months Ended
 
 
June 30,
In thousands
 
2015
 
2014
 
 
 
 
 
Operating activities:
 
 
 
 
Net income
 
$
30,683

 
$
38,955

Adjustments to reconcile net income to cash provided by operations:
 
 
 
 
Depreciation and amortization
 
40,341

 
39,298

Regulatory amortization of gas reserves
 
10,023

 
8,680

Deferred tax liabilities, net
 
6,886

 
989

Non-cash expenses related to qualified defined benefit pension plans
 
3,032

 
2,540

Contributions to qualified defined benefit pension plans
 
(5,810
)
 
(6,000
)
Deferred environmental (expenditures), net of recoveries
 
(5,659
)
 
92,104

Non-cash regulatory disallowance of prior environmental cost deferrals
 
15,000

 

Non-cash interest income on deferred environmental expenses
 
(5,322
)
 

Other
 
418

 
1,010

Changes in assets and liabilities:
 
 
 
 
Receivables
 
85,121

 
89,951

Inventories
 
1,321

 
(139
)
Taxes accrued
 
(249
)
 
8,447

Accounts payable
 
(37,532
)
 
(24,472
)
Interest accrued
 
(157
)
 
(50
)
Deferred gas costs
 
21,718

 
(18,812
)
Other, net
 
7,670

 
744

Cash provided by operating activities
 
167,484

 
233,245

Investing activities:
 
 
 
 
Capital expenditures
 
(58,072
)
 
(52,489
)
Utility gas reserves
 
(1,945
)
 
(18,632
)
Restricted cash
 
(1,500
)
 
1,000

Other
 
201

 
(1,043
)
Cash used in investing activities
 
(61,316
)
 
(71,164
)
Financing activities:
 
 
 
 
Common stock issued, net
 
812

 
3,733

Long-term debt retired
 
(40,000
)
 
(20,000
)
Change in short-term debt
 
(44,400
)
 
(114,000
)
Cash dividend payments on common stock
 
(25,398
)
 
(24,938
)
Other
 
(2,250
)
 
893

Cash used in financing activities
 
(111,236
)
 
(154,312
)
(Decrease) increase in cash and cash equivalents
 
(5,068
)
 
7,769

Cash and cash equivalents, beginning of period
 
9,534

 
9,471

Cash and cash equivalents, end of period
 
$
4,466

 
$
17,240

 
 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
 
Interest paid
 
$
19,615

 
$
23,270

Income taxes paid (net of refunds)
 
4,625

 
14,945

See Notes to Unaudited Consolidated Financial Statements


5








NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND PRINCIPLES OF CONSOLIDATION

The accompanying consolidated financial statements represent the consolidated results of Northwest Natural Gas Company (NW Natural or the Company) and all companies we directly or indirectly control, either through majority ownership or otherwise. We have two core businesses: our regulated local gas distribution business, referred to as the utility segment, which serves residential, commercial, and industrial customers in Oregon and southwest Washington; and our gas storage businesses, referred to as the gas storage segment, which provides storage services for utilities, gas marketers, electric generators, and large industrial users from facilities located in Oregon and California. In addition, we have investments and other non-utility activities we aggregate and report as other.

Our core utility business assets and operating activities are largely included in the parent company, NW Natural. Our direct and indirect wholly-owned subsidiaries include NW Natural Energy, LLC (NWN Energy), NW Natural Gas Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC (Gill Ranch), NNG Financial Corporation (NNG Financial), Northwest Energy Corporation (Energy Corp), and NW Natural Gas Reserves, LLC (NWN Gas Reserves). Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, are accounted for under the equity method, which includes NWN Energy’s investment in Trail West Holdings, LLC (TWH) and NNG Financial's investment in Kelso-Beaver (KB) Pipeline. NW Natural and its affiliated companies are collectively referred to herein as NW Natural. The consolidated unaudited financial statements are presented after elimination of all intercompany balances and transactions, except for amounts required to be included under regulatory accounting standards to reflect the effect of such regulation. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage businesses and other non-utility investments and business activities.

Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments management considers necessary for fair presentation of the results for each period reported including normal recurring accruals. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes included in our 2014 Annual Report on Form 10-K (2014 Form 10-K). A significant part of our business is of a seasonal nature; therefore, results of operations for interim periods are not necessarily indicative of full year results.

2. SIGNIFICANT ACCOUNTING POLICIES
Our significant accounting policies are described in Note 2 of the 2014 Form 10-K. There were no material changes to those accounting policies during the six months ended June 30, 2015. The following are current updates to certain critical accounting policy estimates and new accounting standards.



6







Regulatory Accounting
In applying regulatory accounting in accordance with generally accepted accounting principles in the United States of America (GAAP), we capitalize or defer certain costs and revenues as regulatory assets and liabilities. These deferrals were as follows:
 
 
Regulatory Assets
 
 
June 30,
 
December 31,
In thousands
 
2015

2014

2014
Current:
 
 
 
 
 
 
Unrealized loss on derivatives(1)
 
$
15,017

 
$
1,466

 
$
29,889

Gas costs
 
19,070

 
19,268

 
21,794

Other(2)
 
28,929

 
17,531

 
16,879

Total current
 
$
63,016

 
$
38,265

 
$
68,562

Non-current:
 
 
 
 
 
 
Unrealized loss on derivatives(1)
 
$
1,077

 
$
191

 
$
3,515

Pension balancing(3)
 
38,255

 
28,997

 
32,541

Income taxes
 
44,767

 
49,007

 
47,427

Pension and other postretirement benefit liabilities
 
193,356

 
120,942

 
201,845

Environmental costs(4)
 
49,917

 
52,117

 
58,859

Gas costs
 
2,472

 
3,768

 
5,971

Other(2)
 
12,962

 
12,226

 
18,750

Total non-current
 
$
342,806

 
$
267,248

 
$
368,908

 
 
Regulatory Liabilities
 
 
June 30,
 
December 31,
In thousands
 
2015
 
2014
 
2014
Current:
 
 
 
 
 
 
Gas costs
 
$
20,087

 
$
6,423

 
$
5,700

Unrealized gain on derivatives(1)
 
1,015

 
11,286

 
240

Other(2)
 
5,610

 
9,033

 
13,165

Total current
 
$
26,712

 
$
26,742

 
$
19,105

Non-current:
 
 
 
 
 
 
Gas costs
 
$
3,615

 
$
1,057

 
$
2,507

Unrealized gain on derivatives(1)
 
1,369

 
1,202

 

Accrued asset removal costs(5)
 
320,206

 
303,567

 
311,238

Other(2)
 
3,456

 
3,501

 
3,460

Total non-current
 
$
328,646

 
$
309,327

 
$
317,205


(1) 
Unrealized gains or losses on derivatives are non-cash items and, therefore, do not earn a rate of return or a carrying charge. These amounts are recoverable through utility rates as part of the annual Purchased Gas Adjustment (PGA) mechanism when realized at settlement.
(2) 
These balances primarily consist of deferrals and amortizations under approved regulatory mechanisms. The accounts being amortized typically earn a rate of return or carrying charge.
(3) 
The deferral of certain pension expenses above or below the amount set in rates was approved by the Public Utility Commission of Oregon (OPUC), with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower net periodic benefit costs in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of interest income recognized when amounts are collected in rates.
(4) 
Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and Washington Utilities and Transportation Commission (WUTC). In Oregon, we earn a carrying charge on cash amounts paid, whereas amounts accrued but not yet paid do not earn a carrying charge until expended. We also accrue a carrying charge on insurance proceeds for amounts owed to customers. In Washington, a carrying charge related to deferred amounts will be determined in a future proceeding. See Note 13.
(5)  
Estimated costs of removal on certain regulated properties are collected through rates. See Note 2 of the 2014 Form 10-K.


7








Environmental Regulatory Accounting
On February 20, 2015 the OPUC issued an Order addressing outstanding implementation items related to the Site Remediation and Recovery Mechanism (SRRM). Under the Order, $15 million of $95 million in total environmental remediation expenses deferred through 2012 were disallowed. The OPUC found the $95 million to be prudent but disallowed this amount from rate recovery based on its determination of how an earnings test should apply to years between 2003 and 2012, with adjustments for factors the OPUC deemed relevant. The Company recognized the $15 million pre-tax disallowance, or $9.1 million after-tax charge, during the first quarter of 2015. The charge was recorded in operations and maintenance expense. As a result of the order, we recognized $5.3 million pre-tax of interest income related to the equity component on our deferred environmental expenses. See Note 13.

New Accounting Standards

Recent Accounting Pronouncements
We consider the applicability and impact of all accounting standards updates (ASUs) issued by the Financial Accounting Standards Board (FASB). Accounting standards updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position or results of operations.

FAIR VALUE MEASUREMENT. On May 1, 2015, the FASB issued ASU 2017-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). The amendment removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient and also removes certain disclosure requirements. The new requirements are effective for the Company beginning January 1, 2016 with retrospective application to all periods presented required and early adoption permitted. NW Natural does not expect the ASU to affect its financial statements and does not expect it to materially affect its disclosures.

INTANGIBLES - GOODWILL AND OTHER - INTERNAL-USE SOFTWARE. On April 15, 2015 the FASB issued ASU 2015-05, Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement. This amendment provides customers guidance on how to determine whether a cloud computing arrangement includes a software license. The new requirements are effective for the Company January 1, 2016. The amendment can be applied prospectively or retrospectively and early adoption is permitted. NW Natural does not expect the ASU to materially affect its financial statements and disclosures.

DEBT ISSUANCE COSTS. On April 7, 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which requires the presentation of debt issuance costs in the balance sheet as a direct deduction from the associated debt liability. The new requirements are effective for the Company beginning January 1, 2016. Early adoption is permitted, and the new guidance will be applied on a retrospective basis. NW Natural does not expect the ASU to materially affect its financial statements and disclosures.

REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 Revenue From Contracts with Customers. The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts expected to be entitled to in exchange for those goods or services. The model provides a five-step approach to revenue recognition: (1) identify the contract(s) with the customer; (2) identify the separate performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to separate performance obligations; and (5) recognize revenue when, or as, each performance obligation is satisfied. The new requirements prescribe either a full retrospective or simplified transition adoption method. On July 9, 2015, the FASB deferred the effective date by one year to January 1, 2018 for annual reporting periods beginning after December 15, 2017. The FASB also permitted early adoption of the standard, but not before the original effective date of December 15, 2016. The Company is currently assessing the effect of this standard on our financial statements and disclosures.



8







3. EARNINGS PER SHARE

Basic earnings per share are computed using net income and the weighted average number of common shares outstanding for each period presented. Diluted earnings per share are computed in the same manner, except it uses the weighted average number of common shares outstanding plus the effects of the assumed exercise of stock options and the payment of estimated stock awards from other stock-based compensation plans that are outstanding at the end of each period presented. Diluted earnings per share are calculated as follows:
 
 
Three Months Ended
 
Six Months Ended
 
 
June 30,
 
June 30,
In thousands, except per share data
 
2015
 
2014
 
2015
 
2014
Net income
 
$
2,197

 
$
1,071

 
$
30,683

 
$
38,955

Average common shares outstanding - basic
 
27,343

 
27,139

 
27,322

 
27,116

Additional shares for stock-based compensation plans outstanding
 
45

 
43

 
56

 
42

Average common shares outstanding - diluted
 
27,388

 
27,182

 
27,378

 
27,158

Earnings per share of common stock - basic
 
$
0.08

 
$
0.04

 
$
1.12

 
$
1.44

Earnings per share of common stock - diluted
 
$
0.08

 
$
0.04

 
$
1.12

 
$
1.43

Additional information:
 
 
 
 
 
 
 
 
Antidilutive shares excluded from net income per diluted common share calculation
 
35

 
39

 
27

 
28


4. SEGMENT INFORMATION

We primarily operate in two reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment also includes the utility portion of our Mist underground storage facility in Oregon (Mist) and NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp. Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, and all third-party asset management services. Other includes NNG Financial and NWN Energy's equity investment in TWH, which is pursuing development of a cross-Cascades transmission pipeline project. See Note 4 in our 2014 Form 10-K for further discussion of our segments.

Inter-segment transactions are insignificant. The following table presents summary financial information concerning the reportable segments:
 
 
Three Months Ended June 30,
In thousands
 
Utility
 
Gas Storage
 
Other
 
Total
2015
 
 
 
 
 
 
 
 
Operating revenues
 
$
132,891

 
$
5,333

 
$
56

 
$
138,280

Depreciation and amortization
 
18,602

 
1,628

 

 
20,230

Income from operations
 
12,163

 
739

 
12

 
12,914

Net income (loss)
 
2,245

 
(86
)
 
38

 
2,197

Capital expenditures
 
30,464

 
473

 

 
30,937

2014
 
 
 
 
 
 
 
 
Operating revenues
 
$
128,075

 
$
5,038

 
$
56

 
$
133,169

Depreciation and amortization
 
18,087

 
1,622

 

 
19,709

Income (loss) from operations
 
13,735

 
(485
)
 
16

 
13,266

Net income (loss)
 
2,205

 
(1,157
)
 
23

 
1,071

Capital expenditures
 
26,726

 
175

 

 
26,901




9







 
 
Six Months Ended June 30,
In thousands
 
Utility
 
Gas Storage
 
Other
 
Total
2015
 
 
 
 
 
 
 
 
Operating revenues
 
$
389,197

 
$
10,636

 
$
112

 
$
399,945

Depreciation and amortization
 
37,077

 
3,264

 

 
40,341

Income from operations
 
64,043

 
1,794

 
78

 
65,915

Net income
 
30,580

 
28

 
75

 
30,683

Capital expenditures
 
56,273

 
1,799

 

 
58,072

Total assets at June 30, 2015
 
2,646,457

 
270,509

 
14,913

 
2,931,879

2014
 
 
 
 
 
 
 
 
Operating revenues
 
$
413,570

 
$
12,873

 
$
112

 
$
426,555

Depreciation and amortization
 
36,054

 
3,244

 

 
39,298

Income from operations
 
85,192

 
3,068

 
34

 
88,294

Net income
 
38,224

 
470

 
261

 
38,955

Capital expenditures
 
52,076

 
413

 

 
52,489

Total assets at June 30, 2014
 
2,487,771

 
282,939

 
16,404

 
2,787,114

 
 
 
 
 
 
 
 
 
Total assets at December 31, 2014
 
$
2,775,011

 
$
273,813

 
$
16,121

 
$
3,064,945


Utility Margin
Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes and the associated cost of gas. The cost of gas purchased for utility customers is generally a pass-through cost in the amount of revenues billed to regulated utility customers. By subtracting cost of gas from utility operating revenues, utility margin provides a key metric used by our chief operating decision maker in assessing the performance of the utility segment. The gas storage segment and other emphasize growth in operating revenues as opposed to margin because they do not incur a product cost (i.e. cost of gas sold) like the utility and, therefore, use operating revenues and net income to assess performance.

The following table presents additional segment information concerning utility margin:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
In thousands
 
2015
 
2014
 
2015
 
2014
Utility margin calculation:
 
 
 
 
 
 
 
 
Utility operating revenues
 
$
132,891

 
$
128,075

 
$
389,197

 
$
413,570

Less: Utility cost of gas
 
62,176

 
58,280

 
187,881

 
213,481

Utility margin
 
$
70,715

 
$
69,795

 
$
201,316

 
$
200,089




10







5. STOCK-BASED COMPENSATION

Our stock-based compensation plans include a Long-Term Incentive Plan (LTIP) under which various types of equity awards may be granted. For additional information on our stock-based compensation plans, see Note 6 in the 2014 Form 10-K and the updates provided below.
 
Long-Term Incentive Plan

Performance-Based Stock Awards  
LTIP performance shares incorporate a combination of market, performance, and service-based factors. During the first six months of 2015, 49,939 performance-based shares were granted under the LTIP based on target-level awards with a weighted-average grant date fair value of $51.76 per share. As of June 30, 2015, there was $2.7 million of unrecognized compensation cost from LTIP grants, which is expected to be recognized through 2017. Fair value for the market based portion of the LTIP was estimated as of the date of grant using a Monte-Carlo option pricing model based on the following assumptions:
Stock price on valuation date
$
47.64

Performance term (in years)
3.0

Quarterly dividends paid per share
$
0.465

Expected dividend yield
3.8
%
Dividend discount factor
0.8966


Performance-Based Restricted Stock Units (RSUs)
During the first six months of 2015, 38,490 RSUs were granted under the LTIP with a weighted-average grant date fair value of $46.16 per share. The fair value of a RSU is equal to the closing market price of the Company's common stock on the grant date. As of June 30, 2015, there was $3.4 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2019. Generally, the RSUs awarded include a performance-based threshold and a vesting period of four years from the grant date. An RSU obligates the Company upon vesting to issue the RSU holder one share of common stock plus a cash payment equal to the total amount of dividends paid per share between the grant date and vesting date of that portion of the RSU. 

6. DEBT


Short-Term Debt
At June 30, 2015, our short-term debt consisted of commercial paper notes payable with a maximum maturity of 111 days, an average maturity of 51 days, and an outstanding balance of $190.3 million. The carrying cost of our commercial paper approximates fair value using Level 2 inputs due to the short-term nature of the notes. See Note 2 in our 2014 Form 10-K for a description of the fair value hierarchy.

Long-Term Debt
At June 30, 2015, our utility segment had long-term debt of $601.7 million. Utility long-term debt consists of first mortgage bonds (FMBs) with maturity dates ranging from 2016 through 2042, interest rates ranging from 3.176% to 9.05%, and a weighted-average coupon rate of 5.70%. The utility redeemed $40 million of FMBs with a coupon rate of 4.70% in June 2015.

At June 30, 2015, our gas storage segment’s long-term debt consisted of $20 million of fixed-rate senior collateralized debt with a maturity date of November 30, 2016 and an interest rate of 7.75%. This debt is collateralized by all of the membership interests in Gill Ranch and is nonrecourse to NW Natural.

On April 28, 2015, Gill Ranch entered into an amendment to the loan agreement under which the earnings before interest, tax, depreciation, and amortization (EBITDA) covenant requirement is suspended through maturity of the loan. Previously, the covenant had been suspended through March 31, 2015, and the debt service reserve was set at $3 million. Under the amendment, the debt service reserve was fixed at $4.5 million as of June 30, 2015 with


11







scheduled increases by contributions of $1.5 million on each of January 30, 2016 and August 30, 2016, respectively. Additionally, Gill Ranch must receive common equity contributions from its parent NWN Gas Storage of at least $2 million by August 31, 2015 and of at least $4 million by August 31, 2016.

Fair Value of Long-Term Debt
Our outstanding debt does not trade in active markets. We estimate the fair value of our debt using utility companies with similar credit ratings, terms, and remaining maturities to our debt that actively trade in public markets. These valuations are based on Level 2 inputs as defined in the fair value hierarchy. See Note 2 in our 2014 Form 10-K.

The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date:  
 
 
June 30,
 
December 31,
In thousands
 
2015
 
2014
 
2014
Carrying amount
 
$
621,700

 
$
721,700

 
$
661,700

Estimated fair value
 
695,902

 
807,617

 
756,808


See Note 7 in our 2014 Form 10-K for additional information regarding our long-term debt.



12







7. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS
The following table provides the components of net periodic benefit cost for the Company's pension and other postretirement benefit plans:
 
 
Three Months Ended June 30,
 
 
 
 
 
 
Other Postretirement
 
 
Pension Benefits
 
Benefits
In thousands
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
2,309

 
$
1,918

 
$
145

 
$
136

Interest cost
 
4,595

 
4,512

 
292

 
309

Expected return on plan assets
 
(5,174
)
 
(4,886
)
 

 

Amortization of net actuarial loss
 
4,561

 
2,580

 
125

 
46

Amortization of prior service costs
 
58

 
56

 
49

 
49

Net periodic benefit cost
 
6,349

 
4,180

 
611

 
540

Amount allocated to construction
 
(1,879
)
 
(1,201
)
 
(198
)
 
(171
)
Amount deferred to regulatory balancing account(1)
 
(2,165
)
 
(1,123
)
 

 

Net amount charged to expense
 
$
2,305

 
$
1,856

 
$
413

 
$
369


 
 
Six Months Ended June 30,
 
 
 
 
 
 
Other Postretirement
 
 
Pension Benefits
 
Benefits
In thousands
 
2015
 
2014
 
2015
 
2014
Service cost
 
$
4,618

 
$
3,836

 
$
290

 
$
271

Interest cost
 
9,190

 
9,024

 
583

 
619

Expected return on plan assets
 
(10,348
)
 
(9,772
)
 

 

Amortization of net actuarial loss
 
9,122

 
5,160

 
251

 
92

Amortization of prior service costs
 
116

 
112

 
98

 
98

Net periodic benefit cost
 
12,698

 
8,360

 
1,222

 
1,080

Amount allocated to construction
 
(3,704
)
 
(2,402
)
 
(389
)
 
(341
)
Amount deferred to regulatory balancing account(1)
 
(4,340
)
 
(2,224
)
 

 

Net amount charged to expense
 
$
4,654

 
$
3,734

 
$
833

 
$
739

    
(1) 
The deferral of certain pension expenses above or below the amount set in rates was approved by the OPUC, with recovery of these deferred amounts through the implementation of a balancing account, which includes the expectation of lower net periodic benefit costs in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of the interest recognized when amounts are collected in rates.

The following table presents amounts recognized in accumulated other comprehensive loss (AOCL) and the changes in AOCL related to our non-qualified employee benefit plans:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
In thousands
2015
2014
 
2015
2014
Beginning balance
$
(9,744
)
$
(6,193
)
 
$
(10,076
)
$
(6,358
)
Amounts reclassified from AOCL:

 
 

 
Amortization of prior service costs

(2
)
 

(4
)
Amortization of actuarial losses
548

276

 
1,096

551

Total reclassifications before tax
548

274

 
1,096

547

Tax expense
(217
)
(108
)
 
(433
)
(216
)
Total reclassifications for the period
331

166

 
663

331

Ending balance
$
(9,413
)
$
(6,027
)
 
$
(9,413
)
$
(6,027
)



13







Employer Contributions to Company-Sponsored Defined Benefit Pension Plan
For the six months ended June 30, 2015, we made cash contributions totaling $5.8 million to our qualified defined benefit pension plan. We expect further plan contributions of $9.2 million during the remainder of 2015.

Defined Contribution Plan
The Retirement K Savings Plan provided to our employees is a qualified defined contribution plan under Internal Revenue Code Section 401(k). Company contributions to this plan totaled $2.0 million and $1.9 million for the six months ended June 30, 2015 and 2014, respectively.

See Note 8 in the 2014 Form 10-K for more information concerning these retirement and other postretirement benefit plans.

8. INCOME TAX
An estimate of annual income tax expense is made each interim period using estimates for annual pre-tax income, regulatory flow-through adjustments, tax credits, and other items. The estimated annual effective tax rate is applied to year-to-date, pre-tax income to determine income tax expense for the interim period consistent with the annual estimate.

The effective income tax rate varied from the combined federal and state statutory tax rates due to the following:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
Dollars in thousands
2015
 
2014
 
2015
 
2014
Income tax at statutory rates (federal and state)
$
1,429

 
$
728

 
$
20,321

 
$
26,449

Increase (decrease):
 
 
 
 
 
 
 
Differences required to be flowed-through by regulatory commissions
85

 
61

 
1,414

 
1,494

Other, net
(100
)
 
(9
)
 
(1,238
)
 
(178
)
Income tax expense
$
1,414

 
$
780

 
$
20,497

 
$
27,765

Effective income tax rate
39.2
%
 
42.1
%
 
40.0
%
 
41.6
%

Increases or decreases in income tax expense are correlated with changes in pre-tax income. The effective tax rate for the three and six months ended June 30, 2015, compared to the same periods in 2014, decreased primarily as a result of depletion deductions from gas reserves activity. Additionally, there was a comparative decrease due to a $0.6 million income tax charge in the first quarter of 2014 due to the revaluation of deferred tax balances related to a higher effective tax rate in Oregon. See Note 9 in the 2014 Form 10-K for more detail on income taxes and effective tax rates.

The Company’s examination under the Internal Revenue Service (IRS) Compliance Assurance Process for the 2013 tax year was completed during the first quarter of 2015. The examination did not result in a material change to the return as originally filed.



14







9. PROPERTY, PLANT, AND EQUIPMENT

The following table sets forth the major classifications of our property, plant, and equipment and related accumulated depreciation:
 
 
June 30,
 
December 31,
In thousands
 
2015
 
2014
 
2014
Utility plant in service
 
$
2,701,010

 
$
2,624,774

 
$
2,661,097

Utility construction work in progress
 
38,024

 
36,798

 
24,886

Less: Accumulated depreciation
 
857,373

 
847,828

 
836,510

Utility plant, net
 
1,881,661

 
1,813,744

 
1,849,473

Non-utility plant in service
 
296,046

 
297,269

 
297,295

Non-utility construction work in progress
 
7,591

 
6,385

 
9,282

Less: Accumulated depreciation
 
36,349

 
31,468

 
34,457

Non-utility plant, net
 
267,288

 
272,186

 
272,120

Total property, plant, and equipment
 
$
2,148,949

 
$
2,085,930

 
$
2,121,593

 
 
 
 
 
 
 
Capital expenditures in accrued liabilities
 
$
6,081

 
$
9,826

 
$
8,757


10. GAS RESERVES

Our gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the balance sheet.

We entered into our original agreements with Encana Oil & Gas (USA) Inc. (Encana) in 2011 to develop physical gas reserves to provide long-term gas price protection for utility customers. Encana began drilling in 2011 under these agreements. We hold working interests in certain sections of the Jonah Field. Gas produced in these sections is sold at prevailing market prices, and revenues from such sales, net of associated operating and production costs and amortization, are credited to the utility's cost of gas. The cost of gas, including a carrying cost for the rate base investment, is included in NW Natural's annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our net investment under the original agreement earns a rate of return and provides long-term price protection for our utility customers.

On March 28, 2014, we amended the original gas reserves agreement in order to facilitate Encana's proposed sale of its interest in the Jonah field to Jonah Energy LLC (Jonah Energy). Under the amendment, we ended the drilling program with Encana, but increased our working interests in our assigned sections of the Jonah field. We also retained the right to invest in new wells with Jonah Energy.

We were notified by Jonah Energy of investment opportunities in the sections of the Jonah field where we have working interests. The amended agreements allow us to invest in additional wells on a well-by-well basis with drilling costs and resulting gas volumes shared at our amended proportionate working interest for each well in which we invest. We elected to participate in some of the additional wells drilled in 2014, and we may have the opportunity to participate in more wells in the future.

We filed an application requesting regulatory deferral in Oregon for these additional investments, which was granted in April 2015. Accordingly, we filed in 2015 seeking cost recovery for the additional wells drilled in 2014 and expect the OPUC to review and determine the prudence of this investment in the second half of 2015. Our cumulative investment of approximately $10 million in these additional wells has been accounted for as a utility investment. If regulatory approval is not received, our investment in these additional wells would follow oil and gas accounting.


15







The following table outlines our net investment in gas reserves:
 
 
June 30,
 
December 31,
In thousands
 
2015
 
2014
 
2014
Gas reserves, current
 
$
18,214

 
$
20,373

 
$
20,020

Gas reserves, non-current
 
169,288

 
157,535

 
167,190

Less: Accumulated amortization
 
47,933

 
27,255

 
37,910

Total gas reserves(1)
 
139,569

 
150,653

 
149,300

Less: Deferred tax liabilities on gas reserves
 
27,357

 
34,828

 
18,551

Net investment in gas reserves(1)
 
$
112,212

 
$
115,825

 
$
130,749


(1) 
Gas reserves include our investments in additional wells, subject to regulatory deferral approval with the total gross investment of $10.1 million and $0.5 million at June 30, 2015 and 2014, respectively. Total gas reserves in the additional wells were $8.8 million and $0.5 million and the net investment was $7.9 million and $0.5 million at June 30, 2015 and June 30, 2014, respectively.


11. INVESTMENTS

Equity Method Investments
Trail West Pipeline, LLC (TWP), a wholly-owned subsidiary of TWH, is pursuing the development of a new gas transmission pipeline that would provide an interconnection with our utility distribution system. NWN Energy, a wholly-owned subsidiary of NW Natural owns 50% of TWH, and 50% is owned by TransCanada American Investments Ltd., an indirect wholly-owned subsidiary of TransCanada Corporation.

VIE Analysis
TWH is a Variable Interest Entity, with our investment in TWP reported under equity method accounting. We have determined we are not the primary beneficiary of TWH’s activities, in accordance with the authoritative guidance related to consolidations, as we only have a 50% share of the entity and there are no stipulations that allow us a disproportionate influence over it. Our investment in TWH and TWP are included in other investments on our balance sheet. If we do not develop this investment, then our maximum loss exposure related to TWH is limited to our equity investment balance, less our share of any cash or other assets available to us as a 50% owner. Our investment balance in TWH was $13.4 million at June 30, 2015 and 2014 and December 31, 2014. See Note 12 in our 2014 Form 10-K.

Other Investments
Other investments include financial investments in life insurance policies, which are accounted for at cash surrender value, net of policy loans. See Note 12 in the 2014 Form 10-K.

12. DERIVATIVE INSTRUMENTS

We enter into financial derivative contracts to hedge a portion of our utility’s natural gas sales requirements. These contracts include swaps, options, and combinations of option contracts. We primarily use these derivative financial instruments to manage commodity price variability. A small portion of our derivative hedging strategy involves foreign currency exchange contracts.

We enter into these financial derivatives, up to prescribed limits, primarily to hedge price variability related to our physical gas supply contracts as well as to hedge spot purchases of natural gas. The foreign currency forward contracts are used to hedge the fluctuation in foreign currency exchange rates for pipeline demand charges paid in Canadian dollars.

In the normal course of business, we enter into indexed-price physical forward natural gas commodity purchase contracts and options to meet the requirements of utility customers. These contracts qualify for regulatory deferral accounting treatment.



16







We also enter into exchange contracts related to the third-party asset management of our gas portfolio, some of which are derivatives that do not qualify for hedge accounting or regulatory deferral, but are subject to our regulatory sharing agreement. These derivatives are recognized in operating revenues in our gas storage segment, net of amounts shared with utility customers.

Notional Amounts
The following table presents the absolute notional amounts related to open positions on our derivative instruments:
 
 
June 30,
 
December 31,
In thousands
 
2015
 
2014
 
2014
Natural gas (in therms):
 
 
 
 
 
 
Financial
 
350,250

 
297,925

 
287,475

Physical
 
296,250

 
241,150

 
420,980

Foreign exchange
 
$
7,920

 
$
10,844

 
$
12,230


Purchased Gas Adjustment (PGA)
As of November 1, 2014, we reached our target hedge percentage for the 2014-15 gas year; hedge transactions are recoverable through the Company's PGA mechanism.

Unrealized Gain/Loss
The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments:
 
 
Three Months Ended June 30,
 
 
2015

2014
In thousands
 
Natural gas commodity
 
Foreign currency
 
Natural gas commodity
 
Foreign currency
Benefit (expense) to cost of gas
 
$
10,020

 
$
478

 
$
(5,379
)
 
$
454

Operating revenues
 
(616
)
 

 

 

Less:
 


 


 


 


Amounts deferred to regulatory accounts on the balance sheet
 
(9,618
)
 
(478
)
 
5,223

 
(454
)
Total loss in pre-tax earnings
 
$
(214
)
 
$

 
$
(156
)
 
$

 
 
Six Months Ended June 30,
 
 
2015
 
2014
In thousands
 
Natural gas commodity
 
Foreign currency
 
Natural gas commodity
 
Foreign currency
(Expense) benefit to cost of gas
 
$
(13,461
)
 
$
(263
)
 
$
10,533

 
$
179

Operating revenues
 
22

 

 

 

Less:
 


 


 


 


Amounts deferred to regulatory accounts on the balance sheet
 
13,447

 
263

 
(10,652
)
 
(179
)
Total gain (loss) in pre-tax earnings
 
$
8

 
$

 
$
(119
)
 
$


Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards. The cost of foreign currency forward contracts and natural gas derivative contracts are recognized immediately in the cost of gas; however, costs above or below the amount embedded in the current year PGA are subject to a regulatory deferral tariff and therefore, are recorded as a regulatory asset or liability.

Realized Gain/Loss
We realized a net loss of $7.9 million and $22.0 million for the three and six months ended June 30, 2015 and a net gain of $4.3 million and $12.8 million for the three and six months ended June 30, 2014, respectively, from the settlement of natural gas financial derivative contracts. Realized gains and losses are recorded in cost of gas, deferred through our regulatory accounts and amortized through customer rates in the following year.



17







Credit Risk Management of Financial Derivative Instruments
No collateral was posted with, or by, our counterparties as of June 30, 2015 or 2014. We attempt to minimize the potential exposure to collateral calls by counterparties to manage our liquidity risk. Counterparties generally allow a certain credit limit threshold before requiring us to post collateral against loss positions. Given our counterparty credit limits and portfolio diversification, we have not been subject to collateral calls in 2014 or 2015. Our collateral call exposure is set forth under credit support agreements, which generally contain credit limits. We could also be subject to collateral call exposure where we have agreed to provide adequate assurance, which is not specific as to the amount of credit limit allowed, but could potentially require additional collateral in the event of a material adverse change. Based on current financial swap and option contracts outstanding, which reflect net unrealized losses of $14.2 million at June 30, 2015, we have estimated the level of collateral demands, with and without potential adequate assurance calls, using current gas prices and various credit downgrade rating scenarios for NW Natural as follows:
 
 
 
 
Credit Rating Downgrade Scenarios
In thousands
 
(Current Ratings) 
A+/A3
 
BBB+/Baa1
 
BBB/Baa2
 
BBB-/Baa3
 
Speculative
With Adequate Assurance Calls
 
$

 
$

 
$

 
$

 
$
12,709

Without Adequate Assurance Calls
 

 

 

 

 
8,767


Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our statement of financial position. The Company and its counterparties have the ability to set-off their obligations to each other under specified circumstances. Such circumstances may include a defaulting party, a credit change due to a merger affecting either party, or any other termination event.

If netted by counterparty, our net derivative position would result in an asset of $1.1 million and a liability of $14.8 million as of June 30, 2015. As of June 30, 2014, our derivative position would have resulted in an asset of $11.5 million and a liability of $0.8 million, and as of December 31, 2014, our position would have resulted in an asset of $0.2 million and a liability of $33.4 million.

We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. See Note 13 in our 2014 Form 10-K for additional information.
 
Fair Value
In accordance with fair value accounting, we include nonperformance risk in calculating fair value adjustments. This includes a credit risk adjustment based on the credit spreads of our counterparties when we are in an unrealized gain position, or on our own credit spread when we are in an unrealized loss position. The inputs in our valuation models include natural gas futures, volatility, credit default swap spreads, and interest rates. Additionally, our assessment of non-performance risk is generally derived from the credit default swap market and from bond market credit spreads. The impact of the credit risk adjustments for all outstanding derivatives was immaterial to the fair value calculation at June 30, 2015. As of June 30, 2015 and 2014 and December 31, 2014, the net fair value was a liability of $13.7 million, an asset of $10.7 million, and a liability of $33.2 million, respectively, using significant other observable, or Level 2, inputs. No Level 3 inputs were used in our derivative valuations, and there were no transfers between Level 1 or Level 2 during the six months ended June 30, 2015 and 2014.

13. ENVIRONMENTAL MATTERS

We own, or previously owned, properties that may require environmental remediation or action. We estimate the range of loss for environmental liabilities based on current remediation technology, enacted laws and regulations, industry experience gained at similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Due to the numerous uncertainties surrounding the course of environmental remediation and the ongoing nature of several site investigations, we may not be able to reasonably estimate the high end of the range of possible loss. In those cases, we have disclosed the nature of the possible loss and the fact that the high end of the range cannot be reasonably estimated. Unless there is an estimate within a range of possible losses that is more likely than other cost estimates within that range, we record the liability at the low end of this range. It is likely that changes in these estimates and ranges will occur throughout the remediation process for each of these sites due to our continued evaluation and clarification concerning our


18







responsibility, the complexity of environmental laws and regulations, and the determination by regulators of remediation alternatives.

The Company has a Site Remediation and Recovery Mechanism (SRRM) through which NW Natural tracks and has the ability to recover past deferred and future environmental remediation costs. An Order from the OPUC in February 2015 deemed certain environmental remediation expenses and associated carrying costs deferred through March 31, 2014 prudent. The Company’s settlement with insurance carriers resulting in insurance proceeds received was also deemed prudent in the Order. Under the Order, NW Natural was required to forego the collection of $15 million out of approximately $95 million of environmental remediation expenses and associated carrying costs it had deferred through 2012 under the Order. The OPUC disallowed this amount from rate recovery based on its determination of how an earnings test should apply to amounts deferred from 2003 to 2012. See Note 2 for information regarding the regulatory disallowance of past deferred costs under the Order received from the OPUC in February 2015.

The Company received total environmental insurance proceeds of approximately $150 million as a result of settlements from our litigation that was dismissed in July 2014. Under the Order, one-third of the proceeds recognized in regulatory accounts are applied to costs deferred through 2012 and the remaining two-thirds is applied to costs over the next 20 years.

Under the SRRM, the Company will recover the first $5 million of annual expense through an amount that will be collected from Oregon customers through a tariff rider. The Company will apply $5 million of insurance (plus interest) to the next portion of environmental expenses each year. Any expenses in excess of the annual $10 million (plus interest from insurance) are fully recoverable through the SRRM, to the extent the utility earns at or below its authorized Return On Equity (ROE). To the extent the Company earns more than its authorized ROE in a year, the Company is required to cover environmental expenses greater than the $10 million (plus interest from insurance proceeds) with those earnings that exceed its authorized ROE. The Company submitted the required compliance filing demonstrating the proposed implementation of the Order and SRRM on March 31, 2015. The Company is engaged in discussions with the parties to resolve issues they have raised regarding the compliance filing and expects resolution of these matters in the second half of 2015. The compliance filing is subject to final review and approval by the OPUC and as a consequence thereof, additional or different implementation procedures could be required, which may, among other things, result in additional impacts on earnings.

In addition, the Company requested clarification from the OPUC regarding the amount of insurance proceeds to be held in a secured account. In July 2015, the Company entered into an all-party settlement regarding this issue, which is pending OPUC review and approval. Under the proposed settlement, the Company would accrue interest on the portion of insurance proceeds to be used to offset future environmental expenses at an interest rate equal to the five-year treasury rate plus 100 basis points. Currently, these insurance proceeds total approximately $96 million on a pre-tax basis.

In Washington, cost recovery and carrying charges on amounts deferred for costs associated with services provided to Washington customers will be determined in a future proceeding. Annually, we review all regulatory assets for recoverability or more often if circumstances warrant. If we should determine that all or a portion of these regulatory assets no longer meet the criteria for continued application of regulatory accounting, then we would be required to write off the net unrecoverable balances against earnings in the period such a determination is made.














19







Environmental Sites
The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other current liabilities and other non-current liabilities on the balance sheet:
 
 
Current Liabilities
 
Non-Current Liabilities
 
 
June 30,
 
December 31,
 
June 30,

December 31,
In thousands
 
2015
 
2014
 
2014
 
2015
 
2014

2014
Portland Harbor site:
 
 
 
 
 
 
 
 
 
 
 
 
Gasco/Siltronic Sediments
 
$
1,512

 
$
799

 
$
1,767

 
$
38,342

 
$
38,535

 
$
38,019

Other Portland Harbor
 
1,208

 
1,317

 
1,934

 
4,941

 
3,080

 
4,338

Gasco site
 
5,938

 
7,152

 
9,535

 
37,031

 
39,553

 
37,117

Siltronic Uplands site
 
710

 
884

 
957

 
390

 
401

 
348

Central Service Center site
 
153

 
70

 
171

 

 
190

 

Front Street site
 
665

 
1,115

 
1,020

 
107

 
107

 
122

Oregon Steel Mills
 

 

 

 
179

 
179

 
179

Total
 
$
10,186

 
$
11,337

 
$
15,384

 
$
80,990

 
$
82,045

 
$
80,123


The following table presents information regarding the total amount of cash paid for environmental sites and the total regulatory asset deferred:
 
 
June 30,
 
December 31,
In thousands
 
2015
 
2014
 
2014
Cumulative cash paid
 
$
119,403

 
$
108,783

 
$
113,740

Total regulatory asset deferral(1)
 
49,917

 
52,117

 
58,859


(1) 
Includes cash paid, remaining liability, and interest, net of insurance reimbursement and amounts reclassified to utility plant for the water treatment station.

PORTLAND HARBOR SITE. The Portland Harbor is an Environmental Protection Agency (EPA) listed Superfund site that is approximately 10 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands and Siltronic uplands sites. We are a potentially responsible party (PRP) to the Superfund site and we have joined with some of the other PRPs (the Lower Willamette Group or LWG) to develop a Portland Harbor Remedial Investigation/Feasibility Study (RI/FS). The LWG submitted a draft Feasibility Study (FS) to the EPA in March 2012 that provides a range of remedial costs for the entire Portland Harbor Superfund Site, which includes the Gasco/Siltronic Sediment site, discussed below. The range of costs estimated for various remedial alternatives for the entire Portland Harbor, as provided in the draft FS, is $169 million to $1.8 billion. NW Natural's potential liability is a portion of the costs of the remedy the EPA will select for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 PRPs. NW Natural is participating in a non-binding allocation process in an effort to settle this potential liability. We manage our liability related to the Superfund site as two distinct remediation projects, the Gasco/Siltronic Sediments and Other Portland Harbor projects.

GASCO/SILTRONIC SEDIMENTS. In 2009, NW Natural and Siltronic Corporation entered into a separate Administrative Order on Consent with the EPA to evaluate and design specific remedies for sediments adjacent to the Gasco uplands and Siltronic uplands sites. NW Natural submitted a draft Engineering Evaluation/Cost Analysis (EE/CA) to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA, as well as costs for the additional studies and design work needed before the clean-up can occur, and for regulatory oversight throughout the clean-up, range from $39.9 million to $350 million. We have recorded a liability of $39.9 million for the sediment clean-up, which reflects the low end of the range. At this time, we believe sediments at this site represent the largest portion of our liability related to the Portland Harbor site, discussed above.  

OTHER PORTLAND HARBOR. NW Natural incurs costs related to its membership in the LWG, who is performing the RI/FS for the EPA. NW Natural also incurs costs related to natural resource damages from these sites. The Company and other parties have signed a cooperative agreement with the Portland Harbor Natural Resource


20







Trustee council to participate in a phased natural resource damage assessment to estimate liabilities to support an early restoration-based settlement of natural resource damage claims. Natural resource damage claims may arise only after a remedy for clean-up has been settled. We have accrued a liability for these claims which is at the low end of the range of the potential liability; the high end of the range cannot be reasonably estimated at this time. This liability is not included in the range of costs provided in the draft FS for the Portland Harbor noted above.

GASCO SITE. NW Natural owns a former gas manufacturing plant that was closed in 1958 (Gasco site) and is adjacent to the Portland Harbor site described above. The Gasco site has been under investigation by us for environmental contamination under the Oregon Department of Environmental Quality (ODEQ) Voluntary Clean-Up Program. It is not included in the range of remedial costs for the Portland Harbor site noted above. We manage the Gasco site in two parts, the uplands portion and the groundwater source control action.

Uplands. In May 2007, we completed a revised Remedial Investigation Report for the uplands portion and it was approved by the ODEQ in March 2010. In 2015, ODEQ approved a risk assessment for the Uplands site, and we are currently working on a feasibility study. We have recognized a liability for the remediation of the uplands portion of the site which is at the low end of the range of potential liability; the high end of the range cannot be reasonably estimated at this time.

Groundwater Source Control. In September 2013, we completed construction of a groundwater source control system, including a water treatment station, at the Gasco site. We are working with ODEQ on monitoring the effectiveness of the system and at this time it is unclear what, if any, additional actions ODEQ may require subsequent to the performance testing of the system or as part of the final remedy for the uplands portion of the Gasco site. We have estimated the cost associated with the ongoing operation of the system and have recognized a liability which is at the low end of the range of potential cost. We cannot estimate the high end of the range at this time due to the uncertainty associated with the duration of running the water treatment station, which will be highly dependent upon the remedy determined for both the upland portion as well as the final remedy for our Gasco sediment exposure.

Beginning November 1, 2013, capital asset costs of $19 million for the Gasco water treatment station were placed into rates with OPUC approval. The OPUC deemed these costs prudent. Beginning November 1, 2014, the OPUC approved the application of $2.5 million from insurance proceeds plus interest to reduce the total amount of Gasco capital costs to be recovered through rate base.

OTHER SITES. In addition to those sites above, we have environmental exposures at four other sites: Siltronic, Central Service Center, Front Street, and Oregon Steel Mills. Due to the uncertainty of the design of remediation, regulation, timing of the liabilities, and in the case of the Oregon Steel Mills site, pending litigation, liabilities for each of these sites have been recognized at their respective low end of the range of potential liability; the high end of the range could not be reasonably estimated as of June 30, 2015.

Siltronic Upland site. A portion of the Siltronic property was formerly part of the Gasco site. We are currently conducting an investigation of manufactured gas plant wastes on the uplands portion of this site for the ODEQ.

Central Service Center site. We are currently performing an environmental investigation of the property under the ODEQ's Independent Cleanup Pathway. This site is on ODEQ's list of sites with confirmed releases of hazardous substances requiring cleanup.

Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated. At ODEQs request, we conducted a sediment and source control investigation and provided findings to ODEQ. A Feasibility Study is currently underway.

Oregon Steel Mills site. See “Legal Proceedings,” below.
 


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Legal Proceedings
NW Natural is subject to claims and litigation arising in the ordinary course of business. Although the final outcome of any of these legal proceedings cannot be predicted with certainty, including the matter described below, NW Natural does not expect the ultimate disposition of any of these matters will have a material effect on our financial condition, results of operations or cash flows. See also Part II, Item 1, “Legal Proceedings.”
 
OREGON STEEL MILLS SITE. In 2004, NW Natural was served with a third-party complaint by the Port of Portland (the Port) in a Multnomah County Circuit Court case, Oregon Steel Mills, Inc. v. The Port of Portland. The Port alleges that in the 1940s and 1950s petroleum wastes generated by our predecessor, Portland Gas & Coke Company, and 10 other third-party defendants, were disposed of in a waste oil disposal facility operated by the United States or Shaver Transportation Company on property then owned by the Port and now owned by Oregon Steel Mills. The complaint seeks contribution for unspecified past remedial action costs incurred by the Port regarding the former waste oil disposal facility as well as a declaratory judgment allocating liability for future remedial action costs. No date has been set for trial. Although the final outcome of this proceeding cannot be predicted with certainty, we do not expect that the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows.

For additional information regarding other commitments and contingencies, see Note 14 in our 2014 Form 10-K.





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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural or the Company) financial condition, including the principal factors that affect results of operations. The disclosures contained in this report refer to our consolidated activities for the three and six months ended June 30, 2015 and 2014. References to “Notes” are to the Notes to Unaudited Consolidated Financial Statements in this report. A significant portion of our business results are seasonal in nature, and, as such, the results of operations for the three and six month periods are not necessarily indicative of expected fiscal year results. Therefore, this discussion should be read in conjunction with our 2014 Annual Report on Form 10-K (2014 Form 10-K).
 
The consolidated financial statements include NW Natural, the parent company, and its direct and indirect wholly-owned subsidiaries. Selected subsidiaries are depicted and organized as follows:


We operate in two primary reportable business segments: local gas distribution and gas storage. We also have other investments and business activities not specifically related to one of these two reporting segments, which we aggregate and report as other. We refer to our local gas distribution business as the utility, and our gas storage segment and other as non-utility. Our utility segment includes our NW Natural local gas distribution business, NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp, and the utility portion of our Mist underground storage facility in Oregon (Mist). Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist (NWN's storage facility in Oregon), and asset management services. Other includes NWN Energy's equity investment in Trail West Holdings, LLC (TWH), which is pursuing the development of a proposed natural gas pipeline through its wholly-owned subsidiary, Trail West Pipeline, LLC (TWP), and NNG Financial's equity investment in Kelso-Beaver Pipeline (KB Pipeline). TWH and our equity investments, TWP and KB Pipeline, are not depicted in the chart above. For a further discussion of our business segments and other, see Note 4.

In addition to presenting the results of operations and earnings amounts in total, certain financial measures are expressed in cents per share or exclude the after-tax regulatory disallowance related to the OPUC's 2015 environmental order, which are non-GAAP financial measures. We present net income and earnings per share (EPS) excluding the regulatory disallowance along with the U.S. GAAP measures to illustrate the magnitude of this disallowance on ongoing business and operational results. Although the excluded amounts are properly included in the determination of net income and earnings per share under U.S. GAAP, we believe the amount and nature of such disallowance make period to period comparisons of operations difficult or potentially confusing. Financial measures are expressed in cents per share as these amounts reflect factors that directly impact earnings, including income taxes. All references in this section to EPS are on the basis of diluted shares (see Note 3). We use such


23







non-GAAP measures to analyze our financial performance because we believe they provide useful information to our investors and creditors in evaluating our financial condition and results of operations.

EXECUTIVE SUMMARY
Consolidated results include:
 
Three Months Ended June 30,
 
 
 
2015
 
2014
 
 
In thousands, except per share data
Amount
Per Share
 
Amount
Per Share
 
Change
Consolidated net income
$
2,197

$
0.08

 
$
1,071

$
0.04

 
$
1,126

Utility margin
70,715

 
 
69,795

 
 
920

Gas storage operating revenues
5,333

 
 
5,038

 
 
295


THREE MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Consolidated net income increased $1.1 million primarily due to a $0.9 million increase in utility margin, a $0.3 million increase in gas storage operating revenues, and a $1.2 million decrease in interest expense. These variances were partially offset by a $0.6 million increase in operations and maintenance expense primarily at the utility.

 
Six Months Ended June 30,
 
 
 
2015
 
2014
 
 
In thousands, except per share data
Amount
Per Share
 
Amount
Per Share
 
Change
Consolidated net income
$
30,683

$
1.12

 
$
38,955

$
1.43

 
$
(8,272
)
Adjustments:
 
 
 
 
 
 
 
Regulatory environmental disallowance, net of taxes $5,925(1)
9,075

0.33

 


 
9,075

Adjusted consolidated net income(1)
$
39,758

$
1.45

 
$
38,955

$
1.43

 
$
803

Utility margin
$
201,316

 
 
$
200,089

 
 
$
1,227

Gas storage operating revenues
10,636

 
 
12,873

 
 
(2,237
)

(1)
Regulatory environmental disallowance of $15 million is recorded in utility operations and maintenance expense. Adjusted EPS and net income are non-GAAP measures based on the after-tax disallowance. EPS is calculated using the combined federal and state statutory tax rate of 39.5% and 27.4 million dilutive shares for the first six months of 2015.

SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Consolidated net income decreased $8.3 million primarily due to the $9.1 million after-tax charge related to the regulatory disallowance associated with a February 2015 OPUC Order in the Company's SRRM docket. Under the Order, we were required to forego collection of $15 million, pre-tax, out of the approximate $95 million of environmental expenditures and associated carrying costs deferred through 2012. This charge is reflected in operations and maintenance expense. Other factors were a $1.2 million increase in utility margin, a $4.5 million increase in other income, and a $2.3 million decrease in interest expense, offset by a $2.2 million decrease in gas storage revenues and a $4.3 million increase in operations and maintenance expense.

We continued to make progress on several key strategic initiatives, as evidenced by the following items:
added more than 10,000 customers over the past twelve months and increased our customer growth rate in the core utility to 1.5%;
submitted our Combined Heat and Power (CHP) program filing to the OPUC under Senate Bill (SB) 844; and
continued permitting and land acquisition work on the North Mist gas storage expansion project.



24







Dividends
Dividend highlights include:
 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
QTR
YTD
Per common share
 
2015
2014
2015
2014
Change
Change
Dividends paid
 
$
0.465

 
$
0.460

 
$
0.930

 
$
0.920

 
$
0.005

$
0.010


The Board of Directors declared a quarterly dividend on our common stock of $0.465 per share, payable on August 14, 2015, to shareholders of record on July 31, 2015, reflecting an indicated annual dividend rate of $1.86 per share.

ISSUES AND CHALLENGES
ECONOMY. The local, national, and global economies continue to show signs of improvement. The unemployment rate in the Portland metropolitan region decreased to about 5% during the second quarter of 2015, a decrease of about 1% from the same period in 2014. The utility’s customer base is over 707,000 customers, reflecting a growth rate of 1.5% on a trailing 12-month basis at June 30, 2015, up from 1.4% at June 30, 2014. We continue to believe our utility is well positioned to add customers and to serve increasing industrial demand as the economy improves, regional business projects move forward, and legislation favoring lower carbon emissions continues to develop.

GAS PRICES, SUPPLIES, AND STORAGE VALUES. Our utility gas acquisition strategy is designed to secure sufficient supplies of natural gas to meet the needs of our customers and to manage gas prices. Our utility’s annual PGA mechanisms in Oregon and Washington, combined with our gas price hedging strategies, enable us to reduce earnings exposure for the Company and secure more stable gas costs for customers. We typically hedge gas prices on approximately 75% of our utility’s annual sales requirement based on normal weather, including both physical and financial hedges. We entered the 2014-15 gas year (November 1, 2014 – October 31, 2015) hedged at approximately 75% of our forecasted sales volumes, including 41% in financial swap and option contracts, 22% in physical gas supplies, and 12% in gas reserves. For further discussion see "Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment" below.

In addition to the amount hedged for the current gas contract year, we were hedged at approximately 62% for the upcoming 2015-16 gas year and between 6% and 14% for the following five gas years as of June 30, 2015. Our hedge levels are based on estimated sales volumes, which depend, to a certain extent, on weather and economic conditions. Our gas reserves amounts may increase or decrease depending on production and investment levels. Also, our gas storage inventory levels may increase or decrease depending on future storage expansions, changes in storage contracts with third parties, and future storage recall by the utility pursuant to our utility's integrated resource plan. 

While low and stable gas prices provide opportunities to lower costs for our utility customers, they also present challenges for our gas storage businesses by lowering the price of, and reducing the demand for, storage services, particularly at our Gill Ranch facility. Our Mist facility benefits from a more constrained regional supply system in the Pacific Northwest region and is impacted to a lesser extent by market fluctuations. The Gill Ranch storage contracts for the 2014-15 gas storage year were at historically low prices due to the flat natural gas price curve and generally weak market conditions, which negatively impacted our financial results. Future increases in the demand for natural gas or a decrease in supply can put upward pressure on gas prices and gas price volatility, which could improve the market value for gas storage. Similarly, a decrease in future demand and an increase in supply can cause downward pressure on gas prices and gas price volatility.

Despite current market conditions, we continue to believe in the long-term need for gas storage in California and may see some improvement in gas storage values and an increase in the demand and demand variability for natural gas largely driven by California's renewable portfolio standards and carbon reduction targets. We have seen slightly higher contract prices for the 2015-16 storage year, but overall prices are still significantly lower than the long-term contracts that expired at the end of the 2013-14 storage year. As such, we continue to expect shorter contract lengths and prices reflecting current market trends and remain focused on lowering operating costs, finding opportunities in the market to increase revenues through enhanced services for storage customers, and capitalizing on market opportunities that fit our business-risk profile. See Results of Operations—Business Segments—Gas Storage.  



25







ENVIRONMENTAL COSTS. We accrue estimates for environmental loss contingencies related to environmental sites for which we are responsible. Due to numerous uncertainties surrounding the nature of environmental investigations and the development of remediation solutions approved by regulatory agencies, actual costs could vary significantly from our loss estimates. As a regulated utility, we have been allowed to defer and recover certain costs pursuant to regulatory orders, including our SRRM, as noted in "Regulatory Matters—Rate Mechanisms—Environmental Cost Deferral" below. In addition, environmental cost recovery and carrying charges on amounts charged to Washington customers will be determined in a future proceeding.

REGULATORY MATTERS

Regulation and Rates
UTILITY. Our utility business is subject to regulation by the OPUC, the WUTC, and the Federal Energy Regulatory Commission (FERC) with respect to, among other matters, rates and terms of service. The OPUC and WUTC also regulate the system of accounts and issuance of securities by our utility. At December 31, 2014, approximately 89% of our utility gas volumes and revenues are derived from Oregon customers, with the remaining 11% from Washington customers. Earnings and cash flows from utility operations are largely determined by rates set in general rate cases and other rate proceedings in Oregon and Washington, but are also affected by the local economies in Oregon and Washington, the pace of customer growth in the residential, commercial, and industrial markets, and our ability to remain price competitive, control expenses, and obtain reasonable and timely regulatory recovery of our utility-related costs, including operating expenses and investment costs in utility plant and other regulatory assets. See "Regulatory Activities" below.

GAS STORAGE. Our gas storage businesses are subject to regulation by the OPUC, California Public Utilities Commission (CPUC), and FERC with respect to, among other matters, rates and terms of service. The OPUC and CPUC also regulate the issuance of securities and system of accounts. The OPUC and CPUC regulate intrastate storage services, and the FERC regulates interstate storage services. The OPUC and FERC use a maximum cost of service model which allows for gas storage prices to be set at or below the cost of service as approved by each agency in the latest regulatory filing. The CPUC regulates Gill Ranch under a market-based rate model which allows for the price of storage services to be set by the marketplace. In 2014, approximately 69% of our storage revenues were derived from operations regulated by OPUC and FERC, and approximately 31% were derived from operations regulated by CPUC.

Ongoing Regulatory Activities
The following provides a list of significant regulatory activities:
Prepaid Pension Asset - On August 3, 2015, the OPUC issued the final Order related to this docket. See "Rate Mechanisms—Pension Cost Deferral and Prepaid Pension Asset" below.
Gas Reserves - We filed with the OPUC in February 2015 seeking cost recovery on additional investments in gas reserves. See "Rate Mechanisms—Gas Reserves" below.
System Integrity Program (SIP) - We filed a request to extend the SIP program in the fourth quarter of 2014. The OPUC considered our renewal request at a public meeting in March 2015 and suspended our filing and ordered additional process, including involvement of other gas utilities in the state before making a final decision. See "Rate Mechanisms—System Integrity Program" below.
Hedging - The OPUC opened a new docket to discuss appropriate portfolio hedging across gas utilities in the state. Our request for the OPUC to consider long-term hedging practices will be considered as part of this docket.
Interstate Storage Sharing - We received an order from the OPUC in March 2015 on their review of the current revenue sharing arrangement that allocates a portion of the net revenues generated from non-utility Mist storage services and third-party asset management services to utility customers. The order requires a third-party cost study to be performed and the results of the cost study may initiate a new docket or the re-opening of the original docket.
Carbon Solutions Program - SB 844 required the OPUC to develop rules and programs to reduce carbon emissions in Oregon. We anticipate submitting several programs developed under these rules to the OPUC. In June 2015, we submitted our first project related to CHP for OPUC approval. The submitted CHP program would pay owners of new commercial- and industrial-scale CHP systems for verified carbon emissions reductions. SB 844 establishes a six-month review process for these programs; therefore, a final decision is expected by the end of 2015 or at a later time as agreed to by the Company. Additionally, we expect to submit a residential heating conversion program in 2015 to replace fuel oil consumption with cleaner burning natural gas.


26







Environmental Cost Deferral and Site Remediation and Recovery Mechanism (SRRM)- In February 2015, the OPUC issued an order regarding the SRRM for recovering prudently incurred environmental site remediation costs through customer billings, subject to an earnings test. The Company submitted the required compliance filing on March 31, 2015 and also filed a motion for clarification regarding the amount of insurance proceeds to be held in a secured account. The compliance filing is subject to review and approval by the OPUC, and we are engaged in discussions with the parties to resolve issues they have raised with the filing. We entered into an all-party settlement regarding the secured account, which is currently pending with the OPUC. See "Rate Mechanisms—Environmental Cost Deferral and SRRM."

Rate Mechanisms
PURCHASED GAS ADJUSTMENT. Rate changes are established annually under PGA rate filings in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases. This includes gas prices under spot purchases as well as contract supplies, gas prices hedged with financial derivatives, gas prices from the withdrawal of storage inventories, the production of gas reserves, interstate pipeline demand costs, a bare steel recovery program, temporary rate adjustments that amortize balances of deferred regulatory accounts, and the removal of temporary rate adjustments effective for the previous year.

Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year either an 80% deferral or a 90% deferral of higher or lower actual gas costs compared to estimated PGA prices, such that the impact on current earnings from the incentive sharing is either 20% or 10% of the difference between actual and estimated gas costs, respectively. Under the Washington PGA mechanism, we defer 100% of the higher or lower actual gas costs, and those gas cost differences are passed on to customers through the annual PGA rate adjustment.

EARNINGS REVIEW. We are subject to an annual earnings review in Oregon to determine if the utility is earning above its authorized ROE threshold; this is a separate earnings review from the environmental earnings test. If utility earnings exceed a specific ROE threshold, then 33% of the amount above that level is required to be deferred for refund to customers. Under this provision, if we select the 80% deferral option under the PGA, then we retain all of our earnings up to 150 basis points above the currently authorized ROE. If we select the 90% deferral option, then we retain all of our earnings up to 100 basis points above the currently authorized ROE. We selected the 90% deferral option for the 2014-2015 PGA year. The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For the 2014 calendar year, the ROE threshold was 10.66%. We filed the 2014 earnings test in April 2015. The Commission approved it in July 2015, and we were not subject to a customer refund adjustment.

GAS RESERVES. In 2011 the OPUC approved the Encana gas reserve transaction to provide long-term gas price protection for our utility customers and determined the Company's costs under the agreement would be recovered, on an ongoing basis through our annual PGA mechanism. Gas produced from our interests is sold at then prevailing market prices, and revenues from such sales, net of associated operating and production costs and amortization, are credited to our cost of gas. The cost of gas, including a carrying cost for the rate base investment, is included in NW Natural's annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our net investment under the original agreement earns a rate of return and provides long-term price protection for our utility customers.

On March 28, 2014, we amended the original gas reserve agreement in order to facilitate Encana's sale of its interest in the Jonah field to Jonah Energy. Under the amendment, we ended the drilling program with Encana, but increased our working interests in our assigned sections of the Jonah field and we retained the right to invest in new wells with Jonah Energy.

In 2014 we elected to participate in some of the additional wells drilled in the Jonah field under our amended gas reserves agreement with Jonah Energy and may have the opportunity to participate in more wells in the future. We filed an application requesting regulatory deferral in Oregon for these additional investments, which was granted in April 2015. Accordingly, we filed in 2015 seeking cost recovery for the additional wells drilled in 2014, and we expect the OPUC to review and determine the prudence of this investment in the second half of 2015.

SYSTEM INTEGRITY PROGRAM. Until November of 2014, NW Natural had the approval of the OPUC for specific accounting treatment and cost recovery for our SIP, which is an integrated safety program that consolidates the bare steel replacement program, the transmission pipeline integrity management program, and the distribution


27







integrity management program related to pipeline safety rules adopted by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA). We recorded these costs as either capital expenditures or regulatory assets, accumulated the costs over each 12-month period, and recovered the revenue requirement associated with these costs, subject to audit, through rate changes effective with the Oregon annual PGA. Our SIP costs were tracked into rates annually, with the first $4 million of capital costs subject to regulatory lag and annual rate-base recovery capped at $12 million. Extraordinary costs above the cap could also be approved with written consent of the OPUC staff and other interested parties and approval of the OPUC.

During 2013, the OPUC approved a temporary two-year extension, beginning in November 2012, of our capital expenditure tracking mechanism to recover capital costs related to SIP and authorized a total increase of $13.7 million above the cap during the extension period. Regulatory authority for SIP expired October 31, 2014, although the bare steel replacement portion of the mechanism remains in place until the end of 2015. We filed a request to extend the SIP program in the fourth quarter of 2014 and upon consideration of our request in March of 2015, the OPUC ordered an additional process and evaluation with other gas utilities in the state before making a final decision. In the interim, we continue to recover all bare steel replacement costs through our annual PGA, and we expect system integrity capital costs not tracked through an SIP mechanism would be included in rate base in our next rate case.

ENVIRONMENTAL COST DEFERRAL AND SRRM. On February 20, 2015, the OPUC issued an Order regarding the SRRM for recovering prudently incurred environmental site remediation costs through customer billings, subject to an earnings test. The OPUC Order addressed a number of key issues including: (1) prudence of all but $33 thousand of costs incurred through March 31, 2014; (2) insurance settlements of approximately $150 million were deemed prudent with one-third of the proceeds applied to costs prior to December 31, 2012 and two-thirds to offset future environmental expenses; and (3) disallowed recovery of expenses totaling $15 million for costs deferred between 2003 to 2012.

With respect to recovery of remediation expenses deferred after 2012: (1) The Company will recover the first $5 million of annual expense through a tariff rider from Oregon customers; (2) the Company will apply $5 million of insurance proceeds plus interest to environmental expenses each year; and (3) any expenditures above the $10 million (plus interest) described above would be fully recoverable through the SRRM, to the extent the Company earns at or below its authorized ROE. To the extent the Company earns more than its authorized ROE in a year, the Company is required to cover environmental expenses greater than the $10 million (plus interest from insurance proceeds) with those earnings that exceed its authorized ROE.

In any year environmental expenses are less than $10 million (plus the interest on insurance), any unused tariff rider amount will offset deferred amounts otherwise collected through the SRRM and any unused insurance proceeds (plus interest) will roll forward to offset the next year’s expenses. Under the Order, the OPUC will revisit the deferral and amortization of future remediation expenses, as well as the treatment of remaining insurance proceeds in three years or earlier if the Company gains greater certainty about its future remediation costs.

The Company submitted the required compliance filing on March 31, 2015 with the OPUC demonstrating the proposed implementation of the Order and SRRM. The Company is engaged in discussions with the parties to resolve issues they have raised regarding the compliance filing and expects resolution of these matters in the second half of 2015. The Company does not currently anticipate a disallowance for 2013 and 2014 based on the earnings test outlined in the Order. The compliance filing is subject to review and final approval by the OPUC and, as a consequence thereof, additional or different implementation procedures could be required, which may, among other things, result in additional impacts on earnings.

In addition, the Company requested clarification from the OPUC regarding the amount of insurance proceeds to be held in a secured account. In July 2015, the Company entered into an all-party settlement regarding this issue, which is pending OPUC review and approval. Under the proposed settlement, the Company would accrue interest on the portion of insurance proceeds to be used to offset future environmental expenses at an interest rate equal to the five-year treasury rate plus 100 basis points. Currently, these insurance proceeds total approximately $96 million on a pre-tax basis.

The WUTC has also previously authorized the deferral of environmental costs, if any, that are appropriately allocated to Washington customers. This order was effective January 26, 2011 with cost recovery and a carrying charge to be determined in a future proceeding.



28







PENSION COST DEFERRAL AND PREPAID PENSION ASSET. In Oregon, we are allowed to defer annual pension expenses related to the qualified employee defined benefit pension plan. The amount deferred each period represents the difference between the annual accounting expense (FAS 87 expense) and the amount included and recovered in customer rates. Recovery of the deferred amounts is through the implementation of a balancing account, which includes the expectation of higher and lower pension expenses in future years. Our recovery of these deferred balances includes accrued interest. Future years’ deferrals will depend on changes in plan assets, projected benefit liabilities based on a number of key assumptions, and pension contributions. Pension expense deferrals were $2.2 million and $4.3 million for the three and six months ended June 30, 2015, respectively.

A prepaid pension asset docket was opened in 2013 to evaluate pension cost recovery for all utilities in Oregon. The utilities requested recovery of the financing costs incurred as a result of timing differences between cash contributions made to their pension plans and the recognition of expense. On August 3, 2015, the OPUC issued the final Order, which confirmed the use of accounting expense (FAS 87 expense) for recovery of pension expense, but denied the utilities' request to include prepaid pension assets in rates. Although the Company will not recover the financing costs associated with the prepaid asset, there will be no impact to earnings from this Order. The Company will continue collecting pension expense based on the amounts set in its 2003 Oregon general rate case and will continue deferring the difference between actual pension expense and collected expense in its pension balancing account.

CUSTOMER CREDITS FOR GAS STORAGE AND ASSET MANAGEMENT SHARING. In the second quarter of 2015, the Company received regulatory approval to provide an interstate storage credit of $9.6 million to its Oregon utility customers, which was reflected in their June bills. These customer credits are part of our regulatory incentive sharing mechanism related to non-utility Mist storage and asset management services. The OPUC approved and the Company provided an $11.4 million interstate storage credit to Oregon customers in June of 2014. The Washington portion of these credits is included with the Washington PGA.

For a discussion of other rate mechanisms, see Part II, Item 7, “Results of Operations—Regulatory Matters—Rate Mechanisms” in our 2014 Form 10-K.



29







RESULTS OF OPERATIONS

Business Segments - Local Gas Distribution Utility Operations
Utility margin results are primarily affected by customer growth, revenues from rate-base additions, and, to a certain extent, by changes in delivered volumes due to weather and customers’ gas usage patterns because a significant portion of our utility margin is derived from natural gas sales to residential and commercial customers. In Oregon, we have a conservation tariff (also called the decoupling mechanism), which adjusts utility margin up or down each month through a deferred regulatory accounting adjustment designed to offset changes resulting from increases or decreases in average use by residential and commercial customers. We also have a weather normalization tariff in Oregon, which adjusts customer bills up or down to offset changes in utility margin resulting from above- or below-average temperatures during the winter heating season. Both mechanisms are designed to reduce the volatility of customer bills and our utility’s earnings. See “Results of Operations—Regulatory Matters—Rate Mechanisms” in our 2014 Form 10-K for more information on our decoupling and weather normalization mechanisms.

Utility segment highlights include: 
 
Three Months Ended June 30,
 
Six Months Ended June 30,
QTR Change
YTD Change
In thousands, except per share data
2015
2014
 
2015
2014
Utility net income
$
2,245

$
2,205

 
$
30,580

$
38,224

$
40

$
(7,644
)
EPS - utility segment
$
0.08

$
0.08

 
$
1.12

$
1.41

$

$
(0.29
)
Gas sold and delivered (therms)
207,886

208,253

 
537,863

614,470

(367
)
(76,607
)
Utility margin(1)
$
70,715

$
69,795

 
$
201,316

$
200,089

$
920

$
1,227


(1)
See Utility Margin Table below for a reconciliation and additional detail.

THREE MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Utility net income was slightly higher due to the following:
a $0.9 million increase in utility margin primarily due to:
a $2.0 million increase from customer growth, added loads under higher commercial rate schedules, and rate-base returns on certain investments;
a $0.8 million increase from gas cost incentive sharing resulting from lower gas prices than those estimated in the PGA; offset by
a $1.9 million decrease from a number of other items primarily related to cost deferrals.
a $0.7 million decrease in interest expense due to the redemption of $100 million of utility FMBs over the last twelve months; and
a $1.5 million increase in operations and maintenance expense primarily due to higher compensation and benefit expense.

SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Utility net income decreased $7.6 million due to the following:
the $15 million pre-tax charge, or $9.1 million after-tax charge, for the regulatory disallowance associated with the February 2015 OPUC Order on the recovery of past environmental cost deferrals. This charge is reflected in operations and maintenance expense;
a $1.2 million increase in utility margin primarily due to:
a $3.5 million increase from customer growth in residential and commercial customers, added loads under higher commercial rate schedules, and rate-base returns on certain investments;
a $3.8 million increase from gas cost incentive sharing resulting from lower gas prices than those estimated in the PGA; offset by
an approximate $4 million decrease due to lower customer usage from warmer weather, which impacts utility margins from our Washington customers where we do not have a weather normalization mechanism in place, and from our Oregon customers who opted out of weather normalization; and
a $1.9 million decrease from a number of other items primarily related to cost deferrals.
a $1.0 million net negative impact from the following offsetting items: an increase in other income, a decrease in interest expense, and an increase in operations and maintenance, depreciation, and general tax expense.

Total utility volumes sold and delivered in the three months ended June 30, 2015 decreased slightly over the same period of 2014. For the six months ended June 30 2015, volumes decreased 12% compared to the six months ended June 30, 2014 due to the impact of 18% warmer weather.


30







UTILITY MARGIN TABLE. The following table summarizes the composition of utility gas volumes, revenues, and costs of gas:
 
Three months ended
 
Six months ended
 
Favorable/
In thousands, except degree day and customer data
June 30,
 
June 30,
 
(Unfavorable)
2015
2014
 
2015
2014
 
QTD
YTD
 
 
 
 
 
 
 
 
 
Utility volumes (therms):
 
 
 
 
 
 
 
 
Residential and commercial sales
97,066

96,533

 
303,883

370,689

 
533

(66,806
)
Industrial sales and transportation
110,820

111,720

 
233,980

243,781

 
(900
)
(9,801
)
Total utility volumes sold and delivered
207,886

208,253

 
537,863

614,470

 
(367
)
(76,607
)
Utility operating revenues:
 
 
 
 
 
 
 
 
Residential and commercial sales
$
117,919

$
113,186

 
$
358,831

$
383,188

 
$
4,733

$
(24,357
)
Industrial sales and transportation
17,138

16,855

 
37,664

38,367

 
283

(703
)
Other revenues
1,131

1,166

 
2,537

2,643

 
(35
)
(106
)
Less: Revenue taxes
3,297

3,132

 
9,835

10,628

 
165

(793
)
Total utility operating revenues
132,891

128,075

 
389,197

413,570

 
4,816

(24,373
)
Less: Cost of gas
62,176

58,280

 
187,881

213,481

 
3,896

(25,600
)
Utility margin
$
70,715

$
69,795

 
$
201,316

$
200,089

 
$
920

$
1,227

Utility margin:(1)
 
 
 
 
 
 
 
 
Residential and commercial sales
$
61,940

$
62,468

 
$
182,312

$
184,572

 
$
(528
)
$
(2,260
)
Industrial sales and transportation
7,258

6,707

 
14,832

15,191

 
551

(359
)
Miscellaneous revenues
1,133

1,279

 
2,539

2,866

 
(146
)
(327
)
Gain (loss) from gas cost incentive sharing
340

(430
)
 
1,561

(2,261
)
 
770

3,822

Other margin adjustments
44

(229
)
 
72

(279
)
 
273

351

Utility margin
$
70,715

$
69,795

 
$
201,316

$
200,089

 
$
920

$
1,227

Degree days:
 
 
 
 
 
 
 
 
Average(2)
691

691

 
2,546

2,546

 


Actual degree days
512

530

 
1,993

2,420

 
(3
)%
(18
)%
Percent colder (warmer) than average weather(2)
(26
)%
(23
)%
 
(22
)%
(5
)%
 


 
As of June 30,
 
 
 
 
 
 
Customers - end of period:
2015
2014
 
Change
% Change
 
 
 
Residential customers
640,581

630,868

 
9,713

1.5
 %
 
 


Commercial customers
66,036

65,619

 
417

0.6

 
 


Industrial customers
922

935

 
(13
)
(1.4
)
 
 


Total number of customers
707,539

697,422

 
10,117

1.5
 %
 
 



(1)
Amounts reported as margin for each category of customer consist of operating revenues, which are net of revenue taxes, less cost of gas.
(2)
Average weather represents the 25-year average degree days, as determined in our 2012 Oregon general rate case.







31







Residential and Commercial Sales
Residential and commercial sales highlights include:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
QTR Change
YTD Change
In thousands
2015
2014
 
2015
2014
 
Utility volumes (therms):
 
 
 
 
 
 
 
 
Residential sales
56,655

56,059

 
186,715

229,236

 
596

(42,521
)
Commercial sales
40,411

40,474

 
117,168

141,453

 
(63
)
(24,285
)
Total volumes
97,066

96,533

 
303,883

370,689

 
533

(66,806
)
Utility operating revenues:
 
 
 
 
 
 
 
 
Residential sales
$
75,775

$
72,230

 
$
236,312

$
252,212

 
$
3,545

$
(15,900
)
Commercial sales
42,144

40,956

 
122,519

130,976

 
1,188

(8,457
)
Total operating revenues
$
117,919

$
113,186

 
$
358,831

$
383,188

 
$
4,733

$
(24,357
)
Utility margin:
 
 
 
 
 
 
 
 
Residential:
 
 
 
 
 
 
 
 
Sales
$
39,764

$
39,444

 
$
110,540

$
127,952

 
$
320

$
(17,412
)
Weather normalization adjustments
139

1,663

 
12,492

489

 
(1,524
)
12,003

Decoupling adjustments
2,964

1,542

 
4,169

407

 
1,422

3,762

Total residential utility margin
42,867

42,649

 
127,201

128,848

 
218

(1,647
)
Commercial:
 
 
 
 
 
 
 
 
Sales
16,506

17,359

 
44,261

52,307

 
(853
)
(8,046
)
Weather normalization adjustments
(29
)
752

 
5,215

296

 
(781
)
4,919

Decoupling adjustments
2,596

1,708

 
5,635

3,121

 
888

2,514

Total commercial utility margin
19,073

19,819

 
55,111

55,724

 
(746
)
(613
)
Total utility margin
$
61,940

$
62,468

 
$
182,312

$
184,572

 
$
(528
)
$
(2,260
)

THREE MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Residential and commercial utility variances were as follows:
sales volumes increased 0.5 million therms primarily due to customer growth;
operating revenues increased $4.7 million primarily due to a 6% increase in average cost of gas; and
utility margin decreased $0.5 million reflecting several individually insignificant decreases offset by increases from commercial and residential customer growth, added loads under higher commercial rate schedules, and added rate-base returns on certain investments.

SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Residential and commercial utility variances were as follows:
sales volumes decreased 66.8 million therms primarily due to 18% warmer weather compared to prior year;
operating revenues decreased $24.4 million primarily due to 18% warmer weather, partially offset by a 6% increase in average cost of gas; and
utility margin decreased $2.3 million primarily due to the effects of warmer weather on customers that are not covered by a weather normalization mechanism. The effect of weather was partially offset by increases from commercial and residential customer growth, added loads under higher commercial rate schedules, and added rate-base returns on certain investments.

Industrial Sales and Transportation
Industrial customers have the option of purchasing sales or transportation services from the utility. Under the sales service, the customer buys the gas commodity from the utility. Under the transportation service, the customer buys the gas commodity directly from a third-party gas marketer or supplier. Our gas commodity cost is primarily a pass-through cost to customers; therefore, our profit margins are not materially affected by an industrial customer's decision to purchase gas from us or from third parties. Industrial and large commercial customers may also select


32







between firm and interruptible service options, with firm services generally providing higher profit margins compared to interruptible services. To help manage gas supplies, our industrial tariffs are designed to provide some certainty regarding industrial customers' volumes by requiring an annual service election, special charges for changes between elections, and in some cases, meeting a minimum or maximum volume requirement before changing options.

Industrial sales and transportation highlights include:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
QTR Change
YTD Change
In thousands
2015
2014
 
2015
2014
 
Volumes (therms):
 
 
 
 
 
 
 
 
Industrial - firm sales
7,305

7,427

 
15,956

17,565

 
(122
)
(1,609
)
Industrial - firm transportation
34,796

35,666

 
75,624

79,826

 
(870
)
(4,202
)
Industrial - interruptible sales
20,853

23,264

 
37,245

41,683

 
(2,411
)
(4,438
)
Industrial - interruptible transportation
47,866

45,363

 
105,155

104,707

 
2,503

448

Total volumes
110,820

111,720

 
233,980

243,781

 
(900
)
(9,801
)
Utility margin:
 
 
 
 
 
 
 
 
Industrial - firm and interruptible sales
$
3,165

$
2,872

 
$
6,382

$
6,596

 
$
293

$
(214
)
Industrial - firm and interruptible transportation
4,093

3,835

 
8,450

8,595

 
258

(145
)
Total utility margin
$
7,258

$
6,707

 
$
14,832

$
15,191

 
$
551

$
(359
)

THREE MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Industrial sales and transportation volumes decreased 0.9 million therms, while industrial margins increased by $0.6 million or 8%. The volume decrease was primarily due to lower usage from a customer and the impact of warmer weather, while the margin increase was largely due to an increase in industrial customers under higher margin rate schedules.

SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Industrial sales and transportation volumes decreased 9.8 million therms, while industrial margins decreased by $0.4 million compared to last year. The volume decrease was primarily due to lower usage from warmer weather, while the margin decrease was largely due to higher fee revenues in the prior year from increased usage and other charges resulting from the cold weather event in February 2014.
 
Cost of Gas
Cost of gas as reported by the utility includes gas purchases, gas withdrawn from storage inventory, gains and losses from commodity hedges, pipeline demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals, gas reserves costs, and company gas use. The OPUC and WUTC generally require natural gas commodity costs to be billed to customers at the actual cost incurred, or expected to be incurred, by the utility. Customer rates are set each year so that if cost estimates were met, we would not expect to earn a profit or incur a loss on the gas commodity purchased for customers; however, in Oregon we have an incentive sharing mechanism which has been described under “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment” above. In addition to the PGA incentive sharing mechanism, gains and losses from hedge contracts entered into after annual PGA rates are effective for Oregon customers are also required to be shared and therefore may impact net income. Further, we also have a regulatory agreement whereby we earn a rate of return on our investment in gas reserves, which is also reflected in utility margin. See Part II, Item 7, “Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities” and “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment” in our 2014 Form 10-K for additional information, as well as Note 12 in this report.



33







Cost of gas highlights include:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
 
QTR Change
YTD Change
In thousands, except as noted
2015
2014
 
2015
2014
 
Cost of gas
$
62,176

$
58,280

 
$
187,881

$
213,481

 
$
3,896

$
(25,600
)
Volumes sold (therms)(1)
118,633

118,999

 
350,493

421,712

 
(366
)
(71,219
)
Average cost of gas (cents per therm)(1)
$
0.52

$
0.49

 
$
0.54

$
0.51

 
$
0.03

0.03

Gain (loss) from gas cost incentive sharing
340

(430
)
 
1,561

(2,261
)
 
770

3,822


(1)
This calculation excludes volumes delivered to transportation only customers.

THREE MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Cost of gas increased $3.9 million or 7% primarily due to a 6% increase in average cost of gas.

SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Cost of gas decreased $25.6 million or 12% primarily due to a 17% decrease in sales volume due to warmer weather, partially offset by a 6% increase average cost of gas.

Due to the extreme cold weather event in February 2014, the Company experienced a record sendout and consequently, the higher volumes of gas purchased at higher gas prices at that time resulted in a margin loss in 2014 compared to a margin gain thus far in 2015 as prices were lower due to the record warmer weather. For a discussion of our gas cost incentive sharing mechanism, see “Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment” above.

Business Segments - Gas Storage
Our gas storage segment primarily consists of the non-utility portion of our Mist underground storage facility in Oregon and our 75% ownership interest in the Gill Ranch underground storage facility in California. We also contract with an independent energy marketing company to provide asset management services using utility and non-utility storage and transportation capacity, the results of which are included in this segment.

Gas storage segment highlights include:
In thousands, except per share data
Three Months Ended June 30,
 
Six Months Ended June 30,
QTR Change
YTD Change
2015
2014
 
2015
2014
Gas storage net income (loss)
$
(86
)
$
(1,157
)
 
$
28

$
470

$
1,071

$
(442
)
EPS - gas storage segment

(0.04
)
 

0.02

0.04

(0.02
)
Operating revenues
5,333

5,038

 
10,636

12,873

295

(2,237
)
Operating expenses
4,594

5,523

 
8,842

9,805

(929
)
(963
)

THREE MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Gas storage net loss decreased $1.1 million due to a $0.3 million increase in operating revenues from slightly higher contract prices for the 2015-16 gas storage year and a $0.9 million decrease in operating expenses due to lower repair and power costs at our Gill Ranch facility.

SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Gas storage net income decreased $0.4 million due to a $2.2 million decrease in operating revenues mainly due to lower contract prices for the 2014-15 gas storage year offset by a $1.0 million decrease in operating expenses due to lower repair and power costs at our Gill Ranch facility. Over the past few years, market prices for natural gas storage, particularly in California, were negatively affected by the abundant supply of natural gas, low volatility of natural gas prices, and surplus gas storage capacity. We contracted capacity for the 2014-15 gas storage year with shorter-term contracts at lower market prices than in previous years, which contributed to the decline in gas storage operating revenues.

Our gas storage segment financial results have been negatively impacted by the decline in market conditions, particularly at our Gill Ranch facility. Our Mist facility benefits from a more constrained regional supply system in the Pacific Northwest region and is impacted to a lesser extent from market fluctuations. Despite these conditions, we


34







continue to believe in the long-term need for gas storage in California and have recently seen a slight increase in contracting prices for the 2015-16 gas storage year. In the future, we may see an improvement in gas storage values and an increase in the demand for natural gas driven by a number of factors, including changes in electric generation triggered by California's renewable portfolio standards, an increase in use of alternative fuels to meet carbon reduction targets, recovery of the California economy, growth of domestic industrial manufacturing, potential exports of liquefied natural gas from the west coast, and other favorable market conditions in and around California. These factors may contribute to higher summer/winter natural gas price spreads, gas price volatility, and gas storage values. Refer to Note 2 in our 2014 Form 10-K for more information regarding our accounting for impairment of long-lived assets.

Other
Other business activities of the Company primarily consist of NNG Financial's equity investment in KB Pipeline, an equity investment in TWH, and other miscellaneous non-utility investments. Contributions from our other businesses produced less than $0.1 million of net income for the three months ended June 30, 2015 and 2014. For the six months ended June 30, 2015 our other businesses produced just over $0.1 million compared to $0.3 million for the same period in 2014. See Note 4 and Note 11 for further details on our other activities and our investment in TWH.

Consolidated Operations

Operations and Maintenance
Operations and maintenance highlights include:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
QTR Change
YTD Change
In thousands
2015
2014
 
2015
2014
Operations and maintenance
$
35,311

$
34,731

 
$
89,427

$
70,117

$
580

$
19,310


THREE MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Operations and maintenance expense increased $0.6 million due to the following:
a $2.2 million increase in compensation and benefit expense including increased pension and employee incentive costs, as well as higher wage rates under the new union labor contract, which became effective June 1, 2014; offset by
a $1.3 million decrease related to 2014 repair and power costs at our Gill Ranch gas storage facility; and
a $0.3 million decrease in non-payroll costs primarily associated with contract work and professional services.

SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Operations and maintenance expense increased $19.3 million due to the following:
the $15 million pre-tax charge, or $9.1 million after-tax, for the regulatory disallowance associated with the February 2015 OPUC Order on the recovery of past environmental cost deferrals. The Company also expensed an additional $1 million related to the Order; and
a $4.0 million increase in compensation and benefit expense including increased health care, pension, and employee incentive costs, as well as higher wage rates under the new union labor contract, which became effective June 1, 2014; and
a $1.1 million increase in non-payroll costs primarily associated with ongoing growth initiatives and facilities costs; offset by
a $1.8 million decrease related to 2014 repair and power costs at our Gill Ranch gas storage facility.

Delinquent customer receivable balances and bad debt expense continues to remain at historically low levels for the Company. The utility's annualized bad debt expense as a percent of revenues was 0.1% for the six months ended June 30, 2015 and has remained well below 0.5% of revenues every year since 2007.

Other Operating Expenses
General taxes increased $0.5 million and $1.0 million for the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014 primarily due to increases in Oregon property taxes and local business license taxes. Depreciation expense increased $0.5 million and $1.0 million for the three and six months ended June 30, 2015, respectively, compared to the same respective periods in 2014, as a result of planned capital expenditures. See "Financial Condition—Cash Flows—Investing Activities" below for additional information.


35








Other Income and Expense, Net
Other income and expense, net highlights include:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
QTR Change
YTD Change
In thousands
2015
2014
 
2015
2014
Other income and expense, net
$
1,135

$
262

 
$
6,184

$
1,645

$
873

$
4,539


THREE MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Other income increased $0.9 million primarily due to a decrease in regulatory interest expense from the application of insurance proceeds under the SRRM.

SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Other income increased $4.5 million due to the recognition of net $5.3 million related to the equity component in interest income from our deferred environmental expenses. We realized the equity component of interest on these deferred regulatory asset balances as a result of the OPUC SRRM Order we received in February 2015. Offsetting the $5.3 million was a $0.8 million increase in regulatory interest expense primarily related to the receipt of insurance proceeds in the first quarter of 2014.

Interest Expense
Interest expense highlights include:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
QTR Change
YTD Change
In thousands
2015
2014
 
2015
2014
Interest expense
$
10,438

$
11,677

 
$
20,919

$
23,219

$
(1,239
)
$
(2,300
)

THREE AND SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Interest expense decreased $1.2 million for the quarter and $2.3 million for the six month period due to the redemption of $40 million of utility FMBs in June 2015, $60 million of utility FMBs in 2014, and the retirement of $20 million of Gill Ranch's debt in June 2014.

Income Tax Expense
Income tax expense highlights include:
 
Three Months Ended June 30,
 
Six Months Ended June 30,
QTR Change
YTD Change
In thousands
2015
2014
 
2015
2014
Income tax expense
$
1,414

$
780

 
$
20,497

$
27,765

$
634

$
(7,268
)

THREE AND SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Increases or decreases in income tax expense are correlated with changes in pre-tax income.



36







FINANCIAL CONDITION

Capital Structure
One of our long-term goals is to maintain a strong consolidated capital structure, generally consisting of 45% to 50% common stock equity and 50% to 55% long-term and short-term debt, and with a target utility capital structure of 50% common stock and 50% long-term debt. When additional capital is required, debt or equity securities are issued depending on both the target capital structure and market conditions. These sources of capital are also used to fund long-term debt retirements and short-term commercial paper maturities. See “Liquidity and Capital Resources” below and Note 6.

Achieving both the target capital structure and maintaining sufficient liquidity to meet operating requirements are necessary to maintain attractive credit ratings and provide access capital markets at reasonable costs. Our consolidated capital structure was as follows:
 
 
June 30,
 
December 31,
 
 
2015
 
2014
 
2014
Common stock equity
 
48.9
%
 
49.2
%
 
46.1
%
Long-term debt
 
39.1

 
39.7

 
37.4

Short-term debt, including any current maturities of long-term debt
 
12.0

 
11.1

 
16.5

Total
 
100.0
%
 
100.0
%
 
100.0
%

Liquidity and Capital Resources
At June 30, 2015, we had $4.5 million of cash and cash equivalents compared to $17.2 million at June 30, 2014. We also had $4.5 million and $3.0 million in restricted cash at Gill Ranch at June 30, 2015 and 2014, respectively, which is held as collateral for the long-term debt outstanding. In order to maintain sufficient liquidity during periods when capital markets are volatile, we may elect to maintain higher cash balances and add short-term borrowing capacity. In addition, we may also pre-fund utility capital expenditures when long-term fixed rate environments are attractive. As a regulated entity, our issuance of equity securities and most forms of debt securities are subject to approval by the OPUC and WUTC. Our use of retained earnings is not subject to those restrictions. 

Utility Segment
For the utility segment, the short-term borrowing requirements typically peak during colder winter months when the utility borrows money to cover the lag between natural gas purchases and bill collections from customers. Our short-term liquidity for the utility is primarily provided by cash balances, internal cash flow from operations, proceeds from the sale of commercial paper notes, as well as available cash from multi-year credit facilities, company-owned life insurance policies, and the sale of long-term debt. Utility long-term debt proceeds are primarily used to finance utility capital expenditures, refinance maturing debt of the utility, and provide temporary funding for other general corporate purposes of the utility.   

Based on our current debt ratings (see "Credit Ratings" below), we have been able to issue commercial paper and long-term debt at attractive rates and have not needed to borrow or issue letters of credit from our back-up credit facility. In the event we are not able to issue new debt due to adverse market conditions or other reasons, we expect our near term liquidity needs can be met using internal cash flows or, for the utility segment, drawing upon our committed credit facility. We also have a universal shelf registration statement filed with the SEC for the issuance of secured and unsecured debt or equity securities, subject to market conditions and certain regulatory approvals. As of June 30, 2015, we have Board authorization to issue up to $325 million of additional FMB's. We also have OPUC approval to issue up to $325 million of additional long-term debt for approved purposes.
 
In the event our senior unsecured long-term debt credit ratings are downgraded, or our outstanding derivative position exceeds a certain credit threshold, our counterparties under derivative contracts could require us to post cash, a letter of credit, or another form of collateral, which could expose us to additional cash requirements and may trigger increases in short-term borrowings while we were in a net loss position. We were not near the threshold for posting collateral at June 30, 2015. However, if the credit risk-related contingent features underlying these contracts were triggered on June 30, 2015, assuming our long-term debt ratings dropped to non-investment grade levels, we could have been required to post $12.7 million of collateral to our counterparties. See "Credit Ratings" below and Note 12.


37








Other items that may have a significant impact on our liquidity and capital resources include pension contribution requirements, expiration of bonus tax depreciation, environmental expenditures and insurance recoveries. See "Cash Flows—Operating Activities" below.

With respect to pensions, we expect to make significant contributions to our company-sponsored defined benefit plan, which is closed to new employees, over the next several years until we are fully funded under the Pension Protection Act rules, including the new rules issued under the Moving Ahead for Progress in the 21st Century Act (MAP-21) and the Highway and Transportation Funding Act of 2014 (HATFA). See "Cash Flows—Operating Activities" below for expected contribution amounts.

Gas Storage Segment
Short-term liquidity for the gas storage segment is supported by cash balances, internal cash flow from operations, external financing, and funds from its parent company. The abundant supply of natural gas, low volatility of natural gas prices, and available gas storage capacity, particularly in California, have recently resulted in lower storage market prices than we have seen in previous years. The amount and timing of our Gill Ranch facility's cash flows from year to year are uncertain, as the majority of these storage contracts are currently short-term. We have seen slightly higher contract prices for the 2015-16 storage year, but overall prices are still significantly lower than the long-term contracts that expired at the end of the 2013-14 storage year. As such, we expect continuing challenges for Gill Ranch in 2015 causing negative cash flows from operations in 2015. We do not anticipate material changes in our ability to access sources of cash for short-term liquidity.

In November 2011, Gill Ranch issued $40 million of senior collateralized debt, with a fixed interest rate of 7.75% on $20 million and a variable interest rate on the remaining $20 million, with a maturity date of November 30, 2016. Under the debt agreement, Gill Ranch was subject to certain covenants and restrictions. We have amended this agreement twice, which resulted in repayment of the $20 million variable-rate outstanding debt during the second quarter of 2014, suspension of the EBITDA covenant requirement through the maturity date, and maintain a debt reserve account, which is currently $4.5 million, and is required to increase by $1.5 million on each of January 30, 2016 and August 30, 2016. In addition, under the amended agreement, Gill Ranch must receive common equity contributions from its parent NWN Gas Storage of at least $2 million by August 31, 2015 and at least $4 million by August 31, 2016. The senior collateralized debt is secured by all of the membership interests in Gill Ranch and is nonrecourse to NW Natural and other entities in the consolidated group.

Consolidated
Based on several factors, including our current credit ratings, our commercial paper program, current cash reserves, committed credit facilities, and our expected ability to issue long-term debt in the capital markets, we believe the Company's liquidity is sufficient to meet anticipated near-term cash requirements, including all contractual obligations, investing, and financing activities discussed below.

Short-Term Debt
Our primary source of utility short-term liquidity is from internal cash flows and the sale of commercial paper. In addition to issuing commercial paper to meet working capital requirements, including seasonal requirements to finance gas purchases and accounts receivable, short-term debt may also be used to temporarily fund utility capital requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold through two commercial banks under an issuing and paying agency agreement, is supported by one or more unsecured revolving credit facilities. See “Credit Agreements” below. At June 30, 2015 and 2014, our utility had commercial paper outstanding of $190.3 million and $74.2 million, respectively. The effective interest rate on the utility’s commercial paper outstanding at June 30, 2015 and 2014 was 0.4% and 0.2%, respectively.



38







Credit Agreements
NW Natural has a $300 million revolving credit facility, with a feature that allows the Company to request increases in the total commitment amount, up to a maximum of $450 million. The final maturity date of the agreement is December 20, 2019.

All lenders under the agreement are major financial institutions with committed balances and investment grade credit ratings as of June 30, 2015 as follows:
Lender rating, by category, in millions
Loan Commitment
AA/Aa
$
234

A/A1
66

BBB/Baa

Total
$
300


Based on credit market conditions, it is possible one or more lending commitments could be unavailable to us if the lender defaulted due to lack of funds or insolvency; however, the Company does not believe this risk to be imminent due to the lenders' strong investment-grade credit ratings.

Our credit agreement permits the issuance of letters of credit in an aggregate amount of up to $100 million. Any principal and unpaid interest amounts owed on borrowings under the credit agreements is due and payable on or before the maturity date. There were no outstanding balances under this credit agreement at June 30, 2015 or 2014. The credit agreement requires us to maintain a consolidated indebtedness to total capitalization ratio of 70% or less. Failure to comply with this covenant would entitle the lenders to terminate their lending commitments and accelerate the maturity of all amounts outstanding. We were in compliance with this covenant at June 30, 2015 and 2014, with consolidated indebtedness to total capitalization ratios of 51.1% and 50.8%, respectively.

The agreement also requires us to maintain credit ratings with Standard & Poor's (S&P) and Moody's Investors Service, Inc. (Moody’s) and notify the lenders of any change in our senior unsecured debt ratings or senior secured debt ratings, as applicable, by such rating agencies. A change in our debt ratings by S&P or Moody’s is not an event of default, nor is the maintenance of a specific minimum level of debt rating a condition of drawing upon the credit agreement. Rather, interest rates on any loans outstanding under the credit agreements are tied to debt ratings and therefore, a change in the debt rating would increase or decrease the cost of any loans under the credit agreements when ratings are changed. See “Credit Ratings” below.

Credit Ratings
Our credit ratings are a factor of our liquidity, potentially affecting our access to capital markets including the commercial paper market. Our credit ratings also have an impact on the cost of funds and the need to post collateral under derivative contracts. There were no changes in our credit ratings during the quarter. Our credit ratings are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at any time. The disclosure of or reference to these credit ratings is not a recommendation to buy, sell, or hold NW Natural securities. Each rating should be evaluated independently of any other rating.

Maturity and Redemption of Long-Term Debt
We redeemed $40 million of FMB's with a coupon rate of 4.70% in June 2015. There are no scheduled redemptions in the coming 12 months.

See Part II, Item 7, "Financial Condition—Contractual Obligations” in our 2014 Form 10-K for long-term debt maturing over the next five years.



39







Cash Flows

Operating Activities
Year-over-year changes in our operating cash flows are primarily affected by net income, changes in working capital requirements, and other cash and non-cash adjustments to operating results.

Operating activity highlights include:
 
 
Six Months Ended June 30,
 
 
In thousands
 
2015

2014
 
Change
Cash provided by operating activities
 
$
167,484

 
$
233,245

 
$
(65,761
)

SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Operating cash flows decreased $65.8 million due to the following: 
a decrease of $97.8 million in deferred environmental recoveries reflecting insurance settlements totaling approximately $91 million received in the first quarter of 2014, which did not recur in 2015;
a decrease of $8.7 million from changes in accrued taxes, which reflected lower earnings in the current year and environmental proceeds which were included in taxable income in the first quarter of 2014;
a decrease of $13.1 million from changes in accounts payable due to fewer gas purchases as a result of warmer weather in the first six months of 2015 compared to 2014 when we were refilling gas storage after a cold winter;
a $15.0 million non-cash regulatory disallowance of prior environmental cost deferrals in 2015; and
an increase of $40.5 million for deferred gas costs, net due to lower actual gas prices than prices embedded in the PGA compared to the prior year.

The non-cash pension expense recognized on the income statement for the six months ended June 30, 2015 was $3.0 million, compared to $2.5 million for the same period in 2014. Although we expect gross non-cash pension expense to increase in the coming years, these increases will be mitigated by our balancing account in Oregon; and therefore, net non-cash pension expenses are expected to remain relatively flat in the coming years.

During the six months ended June 30, 2015, we contributed $5.8 million to our utility's qualified defined benefit pension plan, compared to $6.0 million for the same period in 2014. We plan to make $9.2 million in contributions during the remainder of 2015. The amount and timing of future contributions will depend to a certain extent on market interest rates, investment returns on the plan's assets, and future federal funding requirements.

Bonus tax depreciation of 50 percent has been available in recent years, resulting in net operating loss (NOL) carryforwards that are available to reduce current year taxable income. Bonus tax depreciation expired at the end of 2014 and has not yet been enacted for 2015. We anticipate taxable income for 2015 will be in excess of the available NOL carryforwards, and as of June 30, 2015, an income tax payable balance of $1.8 million has been recorded.

The final tangible property regulations applicable to all taxpayers were issued on September 13, 2013 and are generally effective for taxable years beginning on or after January 1, 2014. In addition, procedural guidance related to the regulations was issued under which taxpayers may make accounting method changes to comply with the regulations. We have evaluated the regulations and do not anticipate any material impact. However, unit-of-property guidance applicable to natural gas distribution networks has not yet been issued and is expected in 2015. We will further evaluate the effect of these regulations after this guidance is issued, but believe our current method is materially consistent with the new regulations and do not expect these regulations to have a material effect on our financial statements.



40








Investing Activities
Investing activity highlights include:
 
 
Six Months Ended June 30,
 
 
In thousands
 
2015

2014
 
Change
Total cash used in investing activities
 
$
(61,316
)
 
$
(71,164
)
 
$
9,848

Capital expenditures
 
(58,072
)
 
(52,489
)
 
(5,583
)
Utility gas reserves
 
(1,945
)
 
(18,632
)
 
16,687


SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Investing cash flows decreased $9.8 million due to lower investments in utility gas reserves, partially offset by higher capital expenditures at the utility.

Under the amended gas reserves agreement, NW Natural ended its original drilling program with Encana, but increased the Company's assigned working interests in certain sections of the Jonah field. We continue to evaluate and make decisions whether or not to participate with Jonah Energy in additional wells drilled, and currently we do not expect to drill any additional wells in 2015. See Note 10 for additional information regarding the amended gas reserve agreement.

We received acknowledgment of our recently filed Integrated Resource Plan (IRP), which outlines long-term capital investments based on projected customer and infrastructure needs. Among other things, the IRP included projected infrastructure projects such as continued refurbishments of the Newport Liquefied Natural Gas (LNG) facility in Oregon over the next three years with an expected investment of approximately $20 million, and upgrading distribution infrastructure in Clark County, Washington which could total approximately $25 million over the next five years. In addition, the IRP also included recall of non-utility Mist gas storage capacity of 0.3 million therms per day of deliverability and 0.7 Bcf of associated storage capacity to serve core utility customer needs, which occurred on May 1, 2015. Finally, the IRP discusses various changes to the resource portfolio and preserves the optionality of participating in both the Trail West and Pacific Connector interstate connector pipeline projects. These and other investments are included in our expected capital expenditures in Part II, Item 7, "Financial Condition—Cash Flows—Investing Activities” in the 2014 Form 10-K.

The utility plans to expand its North Mist facility, supported by a contract with PGE to serve their gas-fired electric power generation facilities at Port Westward, which is located approximately 15 miles from Mist. In early 2015, we received authorization from PGE to begin permitting and land acquisition work. The estimated cost of the expansion is approximately $125 million with a potential in-service date in 2018 or 2019. This project is subject to PGE's final approval of estimated projected costs and a notice to proceed, as well as our receipt of permits and certain land rights needed for the project.

Financing Activities
Financing activity highlights include:
 
 
Six Months Ended June 30,
 
 
In thousands
 
2015

2014
 
Change
Total cash used in financing activities
 
$
(111,236
)
 
$
(154,312
)
 
$
43,076

Change in short-term debt
 
(44,400
)
 
(114,000
)
 
69,600

Long-term debt retired
 
(40,000
)
 
(20,000
)
 
(20,000
)

SIX MONTHS ENDED JUNE 30, 2015 COMPARED TO JUNE 30, 2014. Financing cash flows decreased $43.1 million due to the receipt of approximately $91 million of proceeds from our insurance settlements, which was used to reduce our short-term debt balance in the same period of 2014. In addition, we retired $40 million of utility FMBs in the second quarter of 2015 compared to $20 million retired at Gill Ranch in the same period of 2014.



41







Ratios of Earnings to Fixed Charges
For the six and twelve months ended June 30, 2015 and the twelve months ended December 31, 2014, our ratios of earnings to fixed charges computed using the method set forth in Item 503(d) of the SEC's Regulation S-K, were 3.32, 2.89, and 3.13, respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, with fixed charges consisting of interest on all indebtedness, the amortization of debt discount or premium and expense, and the estimated interest portion of rentals charged to income. See Exhibit 12 for the detailed ratio calculation.

Contingent Liabilities
Loss contingencies are recorded as liabilities when it is probable that a liability has been incurred and the amount of the loss is reasonably estimable in accordance with accounting standards for contingencies. See Part II, Item 7, “Application of Critical Accounting Policies and Estimates” in our 2014 Form 10-K. At June 30, 2015, we had a net regulatory asset of $49.9 million for deferred environmental costs, which includes deferred payments and interest of $58.4 million and $91.2 million for additional costs expected to be paid in the future, partially offset by $99.7 million of insurance recoveries. If it is determined that future customer rate recovery of such costs are not probable, then the costs will be charged to expense in the period such determination is made. For further discussion of contingent liabilities, see Note 13 and see also "Regulatory Matters—Rate Mechanisms—Environmental Costs".

APPLICATION OF CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In preparing our financial statements using GAAP, management exercises judgment in the selection and application of accounting principles, including making estimates and assumptions that affect reported amounts of assets, liabilities, revenues, expenses, and related disclosures in the financial statements. Management considers our critical accounting policies to be those which are most important to the representation of our financial condition and results of operations and which require management’s most difficult and subjective or complex judgments, including accounting estimates that could result in materially different amounts if we reported under different conditions or used different assumptions. Our most critical estimates and judgments include accounting for:
regulatory cost recovery and amortizations;
revenue recognition;
derivative instruments and hedging activities;
pensions and postretirement benefits;
income taxes; and
environmental contingencies.

See Note 2 for a discussion of the $15 million regulatory disallowance related to the SRRM Order received in February 2015. There have been no material changes to the information provided in the 2014 Form 10-K with respect to the application of critical accounting policies and estimates (see Part II, Item 7, “Application of Critical Accounting Policies and Estimates,” in the 2014 Form 10-K).

Management has discussed its current estimates and judgments used in the application of critical accounting policies with the Audit Committee of the Board. Within the context of our critical accounting policies and estimates, management is not aware of any reasonably likely events or circumstances that would result in materially different amounts being reported. For a description of recent accounting pronouncements that could have an impact on our financial condition, results of operations, or cash flows, see Note 2.


42








ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various forms of market risk including commodity supply risk, commodity price and storage value risk, interest rate risk, foreign currency risk, credit risk, and weather risk. We monitor and manage these financial exposures as an integral part of our overall risk management program. No material changes have occurred related to our disclosures about market risk for the six month period ended June 30, 2015. See Part II, Item 1A, “Risk Factors” in this report and Part II, Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” in the 2014 Form 10-K for details regarding these risks.

ITEM 4. CONTROLS AND PROCEDURES
 
(a) Evaluation of Disclosure Controls and Procedures

Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has completed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the Exchange Act)). Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this report, our disclosure controls and procedures were effective to ensure that information required to be disclosed by us and included in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission (SEC) rules and forms and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

(b) Changes in Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f).

There have been no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. The statements contained in Exhibit 31.1 and Exhibit 31.2 should be considered in light of, and read together with, the information set forth in this Item 4(b).



43







PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Other than the proceedings disclosed in Note 13 and those proceedings disclosed and incorporated by reference in Part I, Item 3, “Legal Proceedings” in our 2014 Form 10-K, we have only routine nonmaterial litigation that occurs in the ordinary course of our business.

ITEM 1A. RISK FACTORS

There were no material changes from the risk factors discussed in Part I, Item 1A, "Risk Factors” in our 2014 Form 10-K. In addition to the other information set forth in this report, you should carefully consider those risk factors, which could materially affect our business, financial condition or results of operations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
 
The following table provides information about purchases of our equity securities that are registered pursuant to Section 12 of the Securities Exchange Act of 1934 during the quarter ended June 30, 2015:

ISSUER PURCHASES OF EQUITY SECURITIES
Period
 
(a)
Total Number of
Shares Purchased
(1)
 
(b)
Average
Price Paid per Share
 
(c)
Total Number of Shares
Purchased as Part of
Publicly Announced Plans or Programs (2)
 
(d)
Maximum Dollar Value of
Shares that May Yet Be
Purchased Under the Plans or Programs (2)
Balance forward
 
 
 
 
 
2,124,528

 
$
16,732,648

04/01/15 - 04/30/15
 

 
$

 

 

05/01/15 - 05/31/15
 
3,409

 
44.41

 

 

06/01/15 - 06/30/15
 

 

 

 

Total
 
3,409

 
$
44.41

 
2,124,528

 
$
16,732,648


(1)
During the quarter ended June 30, 2015, 3,409 shares of our common stock were purchased on the open market to meet the requirements of our share-based programs. During the quarter ended June 30, 2015, no shares of our common stock were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.
(2)
We have a common stock share repurchase program under which we purchase shares on the open market or through privately negotiated transactions. We currently have Board authorization through May 31, 2016 to repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million. During the quarter ended June 30, 2015, no shares of our common stock were purchased pursuant to this program. Since the program’s inception in 2000, we have repurchased approximately 2.1 million shares of common stock at a total cost of approximately $83.3 million.

ITEM 6. EXHIBITS

See Exhibit Index attached hereto. 


44







SIGNATURE
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
NORTHWEST NATURAL GAS COMPANY
(Registrant)
Dated:
August 4, 2015
 
 
 
 
 
/s/ Brody J. Wilson
 
 
 
Brody J. Wilson
 
 
 
Principal Accounting Officer
 
 
 
Controller


45







NORTHWEST NATURAL GAS COMPANY
Exhibit Index to Quarterly Report on Form 10-Q
For the Quarter Ended June 30, 2015
Exhibit Number
Document
12
Statement Re: Computation of Ratios of Earnings to Fixed Charges.
 
 
31.1
Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
31.2
Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
32.1
Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
101
The following materials from Northwest Natural Gas Company Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, formatted in Extensible Business Reporting Language (XBRL):
(i) Consolidated Statements of Income;
(ii) Consolidated Balance Sheets;
(iii) Consolidated Statements of Cash Flows; and
(iv) Related notes.


46