Attached files
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EXCEL - IDEA: XBRL DOCUMENT - NORTHWEST NATURAL GAS CO | Financial_Report.xls |
EX-4 - SECOND AMENDMENT TO GILL RANCH LOAN AGREEMENT - NORTHWEST NATURAL GAS CO | grdebtamendment.htm |
EX-12 - EXHIBIT 12 FIXED CHARGES - NORTHWEST NATURAL GAS CO | nwn-2015x331x10qxexhibit12.htm |
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - NORTHWEST NATURAL GAS CO | nwn-2015x331x10qxexhibit311.htm |
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - NORTHWEST NATURAL GAS CO | nwn-2015x331x10qxexhibit312.htm |
EX-32.1 - EXHIBIT 32.1 CEO AND CFO CERTIFICATION - NORTHWEST NATURAL GAS CO | nwn-2015x331x10qxexhibit321.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 March 31, 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 April 24, 2015, 27,332,671 shares of the registrant’s Common Stock (the only class of Common Stock) were outstanding.
NORTHWEST NATURAL GAS COMPANY
For the Quarterly Period Ended March 31, 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; |
• | 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 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 | ||||||||
March 31, | ||||||||
In thousands, except per share data | 2015 | 2014 | ||||||
Operating revenues | $ | 261,665 | $ | 293,386 | ||||
Operating expenses: | ||||||||
Cost of gas | 125,705 | 155,201 | ||||||
Operations and maintenance | 54,116 | 35,386 | ||||||
General taxes | 8,732 | 8,182 | ||||||
Depreciation and amortization | 20,111 | 19,589 | ||||||
Total operating expenses | 208,664 | 218,358 | ||||||
Income from operations | 53,001 | 75,028 | ||||||
Other income and expense, net | 5,049 | 1,383 | ||||||
Interest expense, net | 10,481 | 11,542 | ||||||
Income before income taxes | 47,569 | 64,869 | ||||||
Income tax expense | 19,083 | 26,985 | ||||||
Net income | 28,486 | 37,884 | ||||||
Other comprehensive income: | ||||||||
Amortization of non-qualified employee benefit plan liability, net of taxes of $216 and $109 for the three months ended March 31, 2015 and 2014, respectively | 332 | 165 | ||||||
Comprehensive income | $ | 28,818 | $ | 38,049 | ||||
Average common shares outstanding: | ||||||||
Basic | 27,301 | 27,094 | ||||||
Diluted | 27,369 | 27,126 | ||||||
Earnings per share of common stock: | ||||||||
Basic | $ | 1.04 | $ | 1.40 | ||||
Diluted | 1.04 | 1.40 | ||||||
Dividends declared per share of common stock | 0.465 | 0.460 |
See Notes to Unaudited Consolidated Financial Statements
2
NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED) | ||||||||||||
In thousands | March 31, 2015 | March 31, 2014 | December 31, 2014 | |||||||||
Assets: | ||||||||||||
Current assets: | ||||||||||||
Cash and cash equivalents | $ | 5,218 | $ | 17,929 | $ | 9,534 | ||||||
Accounts receivable | 68,531 | 87,264 | 69,818 | |||||||||
Accrued unbilled revenue | 30,076 | 33,515 | 57,963 | |||||||||
Allowance for uncollectible accounts | (1,363 | ) | (2,235 | ) | (969 | ) | ||||||
Regulatory assets | 67,702 | 27,834 | 68,562 | |||||||||
Derivative instruments | 658 | 15,846 | 243 | |||||||||
Inventories | 69,289 | 33,469 | 77,832 | |||||||||
Gas reserves | 19,112 | 21,990 | 20,020 | |||||||||
Income taxes receivable | 2,000 | — | 1,000 | |||||||||
Deferred tax assets | 13,491 | 4,915 | 23,785 | |||||||||
Other current assets | 17,271 | 13,595 | 34,772 | |||||||||
Total current assets | 291,985 | 254,122 | 362,560 | |||||||||
Non-current assets: | ||||||||||||
Property, plant, and equipment | 3,017,754 | 2,939,760 | 2,992,560 | |||||||||
Less: Accumulated depreciation | 883,254 | 868,257 | 870,967 | |||||||||
Total property, plant, and equipment, net | 2,134,500 | 2,071,503 | 2,121,593 | |||||||||
Gas reserves | 125,187 | 134,894 | 129,280 | |||||||||
Regulatory assets | 348,421 | 285,046 | 368,908 | |||||||||
Derivative instruments | 117 | 1,078 | — | |||||||||
Other investments | 68,614 | 67,288 | 68,238 | |||||||||
Restricted cash | 3,000 | 4,000 | 3,000 | |||||||||
Other non-current assets | 10,577 | 12,453 | 11,366 | |||||||||
Total non-current assets | 2,690,416 | 2,576,262 | 2,702,385 | |||||||||
Total assets | $ | 2,982,401 | $ | 2,830,384 | $ | 3,064,945 |
See Notes to Unaudited Consolidated Financial Statements
3
NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED) | ||||||||||||
In thousands | March 31, 2015 | March 31, 2014 | December 31, 2014 | |||||||||
Liabilities and equity: | ||||||||||||
Current liabilities: | ||||||||||||
Short-term debt | $ | 156,200 | $ | 32,600 | $ | 234,700 | ||||||
Current maturities of long-term debt | 40,000 | 80,000 | 40,000 | |||||||||
Accounts payable | 62,904 | 89,201 | 91,366 | |||||||||
Taxes accrued | 17,755 | 34,146 | 10,031 | |||||||||
Interest accrued | 10,427 | 11,144 | 6,079 | |||||||||
Regulatory liabilities | 24,263 | 37,686 | 19,105 | |||||||||
Derivative instruments | 23,242 | 1,191 | 29,894 | |||||||||
Other current liabilities | 35,950 | 38,069 | 38,235 | |||||||||
Total current liabilities | 370,741 | 324,037 | 469,410 | |||||||||
Long-term debt | 621,700 | 661,700 | 621,700 | |||||||||
Deferred credits and other non-current liabilities: | ||||||||||||
Deferred tax liabilities | 523,929 | 489,108 | 530,965 | |||||||||
Regulatory liabilities | 326,424 | 308,858 | 317,205 | |||||||||
Pension and other postretirement benefit liabilities | 235,516 | 147,733 | 236,735 | |||||||||
Derivative instruments | 1,117 | 96 | 3,515 | |||||||||
Other non-current liabilities | 118,059 | 119,376 | 118,094 | |||||||||
Total deferred credits and other non-current liabilities | 1,205,045 | 1,065,171 | 1,206,514 | |||||||||
Commitments and contingencies (see Note 13) | — | — | — | |||||||||
Equity: | ||||||||||||
Common stock - no par value; authorized 100,000 shares; issued and outstanding 27,332, 27,132, and 27,284 at March 31, 2015 and 2014 and December 31, 2014, respectively | 376,656 | 366,560 | 375,117 | |||||||||
Retained earnings | 418,003 | 419,109 | 402,280 | |||||||||
Accumulated other comprehensive loss | (9,744 | ) | (6,193 | ) | (10,076 | ) | ||||||
Total equity | 784,915 | 779,476 | 767,321 | |||||||||
Total liabilities and equity | $ | 2,982,401 | $ | 2,830,384 | $ | 3,064,945 |
See Notes to Unaudited Consolidated Financial Statements
NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) | ||||||||
Three Months Ended | ||||||||
March 31, | ||||||||
In thousands | 2015 | 2014 | ||||||
Operating activities: | ||||||||
Net income | $ | 28,486 | $ | 37,884 | ||||
Adjustments to reconcile net income to cash provided by operations: | ||||||||
Depreciation and amortization | 20,111 | 19,589 | ||||||
Regulatory amortization of gas reserves | 5,255 | 2,981 | ||||||
Deferred tax liabilities, net | 5,918 | 205 | ||||||
Non-cash expenses related to qualified defined benefit pension plans | 1,509 | 1,278 | ||||||
Contributions to qualified defined benefit pension plans | (2,630 | ) | (2,800 | ) | ||||
Deferred environmental (expenditures), net of recoveries | (3,315 | ) | 83,252 | |||||
Non-cash regulatory disallowance of prior environmental cost deferrals | 15,000 | — | ||||||
Non-cash interest income on deferred environmental expenses | (5,322 | ) | — | |||||
Other | 900 | 603 | ||||||
Changes in assets and liabilities: | ||||||||
Receivables | 29,193 | 23,216 | ||||||
Inventories | 8,543 | 27,200 | ||||||
Taxes accrued | 6,724 | 26,824 | ||||||
Accounts payable | (26,550 | ) | (1,671 | ) | ||||
Interest accrued | 4,348 | 4,041 | ||||||
Deferred gas costs | 13,074 | (14,049 | ) | |||||
Other, net | 17,005 | 11,579 | ||||||
Cash provided by operating activities | 118,249 | 220,132 | ||||||
Investing activities: | ||||||||
Capital expenditures | (27,135 | ) | (25,588 | ) | ||||
Utility gas reserves | (1,860 | ) | (19,681 | ) | ||||
Other | 49 | (191 | ) | |||||
Cash used in investing activities | (28,946 | ) | (45,460 | ) | ||||
Financing activities: | ||||||||
Common stock issued, net | 700 | 1,400 | ||||||
Change in short-term debt | (78,500 | ) | (155,600 | ) | ||||
Cash dividend payments on common stock | (12,688 | ) | (12,456 | ) | ||||
Other | (3,131 | ) | 442 | |||||
Cash used in financing activities | (93,619 | ) | (166,214 | ) | ||||
Increase (decrease) in cash and cash equivalents | (4,316 | ) | 8,458 | |||||
Cash and cash equivalents, beginning of period | 9,534 | 9,471 | ||||||
Cash and cash equivalents, end of period | $ | 5,218 | $ | 17,929 | ||||
Supplemental disclosure of cash flow information: | ||||||||
Interest paid | $ | 5,399 | $ | 7,502 | ||||
Income taxes paid | — | — |
4
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.
Certain prior year balances in our unaudited consolidated financial statements and notes have been reclassified to conform with the current presentation. These reclassifications had no effect on our prior year’s consolidated results of operations, financial condition, or cash flows.
Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments that 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 three months ended March 31, 2015. The following are current updates to certain critical accounting policy estimates and new accounting standards.
5
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 | ||||||||||||
March 31, | December 31, | |||||||||||
In thousands | 2015 | 2014 | 2014 | |||||||||
Current: | ||||||||||||
Unrealized loss on derivatives(1) | $ | 23,242 | $ | 1,191 | $ | 29,889 | ||||||
Gas costs | 19,653 | 14,168 | 21,794 | |||||||||
Other(2) | 24,807 | 12,475 | 16,879 | |||||||||
Total current | $ | 67,702 | $ | 27,834 | $ | 68,562 | ||||||
Non-current: | ||||||||||||
Unrealized loss on derivatives(1) | $ | 1,117 | $ | 96 | $ | 3,515 | ||||||
Pension balancing(3) | 35,374 | 27,328 | 32,541 | |||||||||
Deferred income taxes | 44,767 | 49,007 | 47,427 | |||||||||
Pension and other postretirement benefit liabilities | 197,601 | 123,399 | 201,845 | |||||||||
Environmental costs(4) | 50,175 | 63,517 | 58,859 | |||||||||
Gas costs | 4,334 | 6,541 | 5,971 | |||||||||
Other(2) | 15,053 | 15,158 | 18,750 | |||||||||
Total non-current | $ | 348,421 | $ | 285,046 | $ | 368,908 |
Regulatory Liabilities | ||||||||||||
March 31, | December 31, | |||||||||||
In thousands | 2015 | 2014 | 2014 | |||||||||
Current: | ||||||||||||
Gas costs | $ | 12,774 | $ | 9,137 | $ | 5,700 | ||||||
Unrealized gain on derivatives(1) | 436 | 15,788 | 240 | |||||||||
Other(2) | 11,053 | 12,761 | 13,165 | |||||||||
Total current | $ | 24,263 | $ | 37,686 | $ | 19,105 | ||||||
Non-current: | ||||||||||||
Gas costs | $ | 4,729 | $ | 2,602 | $ | 2,507 | ||||||
Unrealized gain on derivatives(1) | 117 | 1,078 | — | |||||||||
Accrued asset removal costs(5) | 315,946 | 299,026 | 311,238 | |||||||||
Other(2) | 5,632 | 6,152 | 3,460 | |||||||||
Total non-current | $ | 326,424 | $ | 308,858 | $ | 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 being unrecognized until 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. |
6
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 prudently incurred 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 of interest income related to the equity component on our deferred environmental expenses. See Note 13.
New Accounting Standards
Recent Accounting Pronouncements
DEBT ISSUANCE COSTS. On April 7, 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (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 plan to adopt the standard early and does not expect the ASU to materially effect 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 are effective for the Company beginning January 1, 2017, and either a full retrospective or simplified transition adoption method is allowed; early adoption is not permitted. On April 1, 2015, the FASB proposed deferring the effective date by one year to January 1, 2018 for annual reporting periods beginning after December 15, 2017. The FASB also proposed permitting early adoption of the standard, but not before the original effective date of December 15, 2016. The proposal is expected to be finalized in the second quarter of 2015. The Company is currently assessing the effect of this standard on our financial statements and disclosures.
Subsequent Event
See Note 14 for information regarding the amendment of our Gill Ranch debt agreement.
7
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 | ||||||||
March 31, | ||||||||
In thousands, except per share data | 2015 | 2014 | ||||||
Net income | $ | 28,486 | $ | 37,884 | ||||
Average common shares outstanding - basic | 27,301 | 27,094 | ||||||
Additional shares for stock-based compensation plans outstanding | 68 | 32 | ||||||
Average common shares outstanding - diluted | 27,369 | 27,126 | ||||||
Earnings per share of common stock - basic | $ | 1.04 | $ | 1.40 | ||||
Earnings per share of common stock - diluted | $ | 1.04 | $ | 1.40 | ||||
Additional information: | ||||||||
Antidilutive shares excluded from net income per diluted common share calculation | 28 | 44 |
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 Trail West Holdings, LLC (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 March 31, | ||||||||||||||||
In thousands | Utility | Gas Storage | Other | Total | ||||||||||||
2015 | ||||||||||||||||
Operating revenues | $ | 256,306 | $ | 5,303 | $ | 56 | $ | 261,665 | ||||||||
Depreciation and amortization | 18,475 | 1,636 | — | 20,111 | ||||||||||||
Income from operations | 51,880 | 1,055 | 66 | 53,001 | ||||||||||||
Net income | 28,335 | 114 | 37 | 28,486 | ||||||||||||
Capital expenditures | 25,809 | 1,326 | — | 27,135 | ||||||||||||
Total assets at March 31, 2015 | 2,696,506 | 270,992 | 14,903 | 2,982,401 | ||||||||||||
2014 | ||||||||||||||||
Operating revenues | $ | 285,495 | $ | 7,835 | $ | 56 | $ | 293,386 | ||||||||
Depreciation and amortization | 17,967 | 1,622 | — | 19,589 | ||||||||||||
Income from operations | 71,457 | 3,553 | 18 | 75,028 | ||||||||||||
Net income | 36,019 | 1,627 | 238 | 37,884 | ||||||||||||
Capital expenditures | 25,350 | 238 | — | 25,588 | ||||||||||||
Total assets at March 31, 2014 | 2,506,930 | 307,055 | 16,399 | 2,830,384 | ||||||||||||
Total assets at December 31, 2014 | $ | 2,775,011 | $ | 273,813 | $ | 16,121 | $ | 3,064,945 |
8
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 costs 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 March 31, | ||||||||
In thousands | 2015 | 2014 | ||||||
Utility margin calculation: | ||||||||
Utility operating revenues | $ | 256,306 | $ | 285,495 | ||||
Less: Utility cost of gas | 125,705 | 155,201 | ||||||
Utility margin | $ | 130,601 | $ | 130,294 |
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 quarter of 2015, 44,550 performance-based shares were granted under the LTIP based on target-level awards with a weighted-average grant date fair value of $52.05 per share. As of March 31, 2015, there was $3.2 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 quarter of 2015, 28,020 RSUs were granted under the LTIP with a weighted-average grant date fair value of $47.64 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 March 31, 2015, there was $3.3 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.
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6. DEBT
Short-Term Debt
At March 31, 2015, our short-term debt consisted of commercial paper notes payable with a maximum maturity of 89 days, an average maturity of 57 days, and an outstanding balance of $156.2 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.
Current Maturities of Long-Term Debt
The utility has long-term debt due within the next 12 months consisting of $40 million of first mortgage bonds (FMBs) with a coupon rate of 4.70% and maturity in June 2015.
Long-Term Debt
At March 31, 2015, our utility segment had long-term debt, including current maturities referred to above, of $641.7 million. Utility long-term debt consists of FMBs with maturity dates ranging from 2015 through 2042, interest rates ranging from 3.176% to 9.05%, and a weighted-average coupon rate of 5.64%.
At March 31, 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. Under the amended loan agreement, $20 million of variable-rate debt was retired in June 2014. As part of the amended agreement, the earnings before interest, tax, depreciation, and amortization (EBITDA) covenant requirement was suspended through March 31, 2015 and the EBITDA hurdles thereafter were lowered. The debt service reserve requirement was fixed at $3 million.
On April 28, 2015, Gill Ranch entered into a second amendment to the loan agreement under which the EBITDA covenant requirement is suspended through maturity of the loan. As part of the second amendment Gill Ranch will increase the debt reserve account by $4.5 million with contributions of $1.5 million by each of May 30, 2015, January 30, 2016, and August 30, 2016. 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:
March 31, | December 31, | |||||||||||
In thousands | 2015 | 2014 | 2014 | |||||||||
Carrying amount | $ | 661,700 | $ | 741,700 | $ | 661,700 | ||||||
Estimated fair value | 762,554 | 820,458 | 756,808 |
See Note 7 in our 2014 Form 10-K for more detail on our long-term debt.
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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:
The following table provides the components of net periodic benefit cost for the Company's pension and other postretirement benefit plans:
Three Months Ended March 31, | ||||||||||||||||
Other Postretirement | ||||||||||||||||
Pension Benefits | Benefits | |||||||||||||||
In thousands | 2015 | 2014 | 2015 | 2014 | ||||||||||||
Service cost | $ | 2,308 | $ | 1,918 | $ | 145 | $ | 136 | ||||||||
Interest cost | 4,596 | 4,512 | 291 | 309 | ||||||||||||
Expected return on plan assets | (5,174 | ) | (4,886 | ) | — | — | ||||||||||
Amortization of net actuarial loss | 4,561 | 2,580 | 126 | 46 | ||||||||||||
Amortization of prior service costs | 58 | 56 | 49 | 49 | ||||||||||||
Net periodic benefit cost | 6,349 | 4,180 | 611 | 540 | ||||||||||||
Amount allocated to construction | (1,825 | ) | (1,201 | ) | (191 | ) | (171 | ) | ||||||||
Amount deferred to regulatory balancing account(1) | (2,175 | ) | (1,101 | ) | — | — | ||||||||||
Net amount charged to expense | $ | 2,349 | $ | 1,878 | $ | 420 | $ | 369 |
(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 being unrecognized until 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 March 31, | ||||||
In thousands | 2015 | 2014 | ||||
Beginning balance | $ | (10,076 | ) | $ | (6,358 | ) |
Amounts reclassified from AOCL: | ||||||
Amortization of prior service costs | — | (2 | ) | |||
Amortization of actuarial losses | 548 | 276 | ||||
Total reclassifications before tax | 548 | 274 | ||||
Tax expense | (216 | ) | (109 | ) | ||
Total reclassifications for the period | 332 | 165 | ||||
Ending balance | $ | (9,744 | ) | $ | (6,193 | ) |
Employer Contributions to Company-Sponsored Defined Benefit Pension Plan
For the three months ended March 31, 2015, we made cash contributions totaling $2.6 million to our qualified defined benefit pension plan. We expect further plan contributions of $12.3 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 $1.1 million and $0.5 million for the three months ended March 31, 2015 and 2014, respectively.
See Note 8 in the 2014 Form 10-K for more information concerning these retirement and other postretirement benefit plans.
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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 March 31, | |||||||
Dollars in thousands | 2015 | 2014 | |||||
Income tax at statutory rates (federal and state) | $ | 18,892 | $ | 25,721 | |||
Increase (decrease): | |||||||
Differences required to be flowed-through by regulatory commissions | 1,329 | 1,433 | |||||
Other, net | (1,138 | ) | (169 | ) | |||
Income tax expense | $ | 19,083 | $ | 26,985 | |||
Effective income tax rate | 40.1 | % | 41.6 | % |
The decrease in the income tax expense amount for the three months ended March 31, 2015, compared to the same period in 2014, was primarily due to lower pre-tax income. The effective tax rate for the three months ended March 31, 2015, compared to the same period in 2014, decreased as a result of depletion deductions from gas reserves activity. Additionally, there was 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 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.
9. PROPERTY, PLANT, AND EQUIPMENT
The following table sets forth the major classifications of our property, plant, and equipment and related accumulated depreciation:
March 31, | December 31, | |||||||||||
In thousands | 2015 | 2014 | 2014 | |||||||||
Utility plant in service | $ | 2,676,280 | $ | 2,605,018 | $ | 2,661,097 | ||||||
Utility construction work in progress | 34,048 | 30,699 | 24,886 | |||||||||
Less: Accumulated depreciation | 847,278 | 838,285 | 836,510 | |||||||||
Utility plant, net | 1,863,050 | 1,797,432 | 1,849,473 | |||||||||
Non-utility plant in service | 299,969 | 297,352 | 297,295 | |||||||||
Non-utility construction work in progress | 7,457 | 6,691 | 9,282 | |||||||||
Less: Accumulated depreciation | 35,976 | 29,972 | 34,457 | |||||||||
Non-utility plant, net | 271,450 | 274,071 | 272,120 | |||||||||
Total property, plant, and equipment | $ | 2,134,500 | $ | 2,071,503 | $ | 2,121,593 | ||||||
Capital expenditures in accrued liabilities | $ | 8,451 | $ | 7,769 | $ | 8,757 |
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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, less associated production costs, 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.
Since the amendment, we have been notified by Jonah Energy of investment opportunities in the sections of the Jonah field where we have working interests. The amended agreement allows 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. We have also signed a memorandum of understanding with all parties agreeing that individual wells drilled in any year will be reviewed for prudence annually. 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 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.
The following table outlines our net investment in gas reserves:
March 31, | December 31, | |||||||||||
In thousands | 2015 | 2014 | 2014 | |||||||||
Gas reserves, current | $ | 19,112 | $ | 21,990 | $ | 20,020 | ||||||
Gas reserves, non-current | 168,352 | 156,450 | 167,190 | |||||||||
Less: Accumulated amortization | 43,165 | 21,556 | 37,910 | |||||||||
Total gas reserves(1) | 144,299 | 156,884 | 149,300 | |||||||||
Less: Deferred tax liabilities on gas reserves | 28,383 | 30,704 | 18,551 | |||||||||
Net investment in gas reserves(1) | $ | 115,916 | $ | 126,180 | $ | 130,749 |
(1) | Total gas reserves includes our investment in additional wells, subject to regulatory deferral approvals, with total gas reserves of $9.2 million and net investment of $8.3 million at March 31, 2015 and no net investment or total gas reserves from additional wells at March 31, 2014. |
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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 development stage 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 March 31, 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 also 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.
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:
March 31, | December 31, | |||||||||||
In thousands | 2015 | 2014 | 2014 | |||||||||
Natural gas (in therms): | ||||||||||||
Financial | 229,925 | 295,125 | 287,475 | |||||||||
Physical | 250,250 | 875,150 | 420,980 | |||||||||
Foreign exchange | $ | 8,690 | $ | 5,590 | $ | 12,230 |
Purchased Gas Adjustment
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.
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Unrealized and Realized Gain/Loss
The following table reflects the income statement presentation for the unrealized gains and losses from our derivative instruments:
Three Months Ended March 31, | ||||||||||||||||
2015 | 2014 | |||||||||||||||
In thousands | Natural gas commodity | Foreign currency | Natural gas commodity | Foreign currency | ||||||||||||
Benefit (expense) to cost of gas | $ | (23,481 | ) | $ | (741 | ) | $ | 15,912 | $ | 275 | ||||||
Operating revenues | 638 | — | — | — | ||||||||||||
Less: | ||||||||||||||||
Amounts deferred to regulatory accounts on the balance sheet | 23,065 | 741 | (15,875 | ) | (275 | ) | ||||||||||
Total gain in pre-tax earnings | $ | 222 | $ | — | $ | 37 | $ | — |
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.
We realized a net loss of $14.1 million and a net gain of $8.5 million for the three months ended March 31, 2015 and 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.
Credit Risk Management of Financial Derivative Instruments
No collateral was posted with, or by, our counterparties as of March 31, 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 $23.1 million at March 31, 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 | $ | — | $ | — | $ | — | $ | — | $ | 20,683 | ||||||||||
Without Adequate Assurance Calls | — | — | — | — | 15,773 |
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 $0.6 million and a liability of $24.2 million as of March 31, 2015. As of March 31, 2014, our derivative position would have resulted in an asset of $16.6 million and a liability of $1.0 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.
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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 March 31, 2015. As of March 31, 2015 and 2014 and December 31, 2014, the net fair value was a liability of $23.6 million, an asset of $15.6 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 three months ended March 31, 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 preliminary nature of several site investigations, in some cases, 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 responsibility, the complexity of environmental laws and regulations, and the determination by regulators of remediation alternatives.
The Company has a 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.
To date, the Company has 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 ratably to costs over the next 20 years.
Under the mechanism, 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 filed its required compliance report demonstrating the proposed implementation of this mechanism on March 31, 2015. The report is subject to review and approval by the OPUC and as such, may require additional or different implementation procedures, which could, among other things, result in additional impacts on earnings.
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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.
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 | |||||||||||||||||||||||
March 31, | December 31, | March 31, | December 31, | |||||||||||||||||||||
In thousands | 2015 | 2014 | 2014 | 2015 | 2014 | 2014 | ||||||||||||||||||
Portland Harbor site: | ||||||||||||||||||||||||
Gasco/Siltronic Sediments | $ | 1,572 | $ | 776 | $ | 1,767 | $ | 38,379 | $ | 38,584 | $ | 38,019 | ||||||||||||
Other Portland Harbor | 1,308 | 1,408 | 1,934 | 5,186 | 3,283 | 4,338 | ||||||||||||||||||
Gasco site | 8,205 | 8,766 | 9,535 | 36,833 | 39,482 | 37,117 | ||||||||||||||||||
Siltronic Uplands site | 750 | 872 | 957 | 405 | 394 | 348 | ||||||||||||||||||
Central Service Center site | 170 | 70 | 171 | — | 224 | — | ||||||||||||||||||
Front Street site | 755 | 1,176 | 1,020 | 115 | 115 | 122 | ||||||||||||||||||
Oregon Steel Mills | — | — | — | 179 | 179 | 179 | ||||||||||||||||||
Total | $ | 12,760 | $ | 13,068 | $ | 15,384 | $ | 81,097 | $ | 82,261 | $ | 80,123 |
The following table presents information regarding the total amount of cash paid for environmental sites and the total regulatory asset deferred:
March 31, | December 31, | |||||||||||
In thousands | 2015 | 2014 | 2014 | |||||||||
Cumulative cash paid | $ | 117,005 | $ | 106,105 | $ | 113,740 | ||||||
Total regulatory asset deferral(1) | 50,175 | 63,517 | 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 11 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands and Siltronic uplands sites. We have been notified that we are a potentially responsible party to the Superfund site and we have joined with some of the other potentially responsible parties (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 potentially responsible parties. 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
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additional studies and design work needed before the clean-up can occur, and for regulatory oversight throughout the clean-up range from $40 million to $350 million. We have recorded a liability of $40 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, which 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 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 submitted it to ODEQ for review. 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 initial 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 March 31, 2015.
Siltronic Upland site. Siltronic is the location of a manufactured gas plant formerly owned by NW Natural. 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, and cleanup is necessary.
Front Street site. The Front Street site was the former location of a gas manufacturing plant we operated. Studies for source control investigation have been presented to ODEQ and a final sampling plan required by ODEQ is currently being developed.
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Oregon Steel Mills site. See “Legal Proceedings,” below.
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 commitment and contingencies, see Note 14 in our 2014 Form 10-K.
14. SUBSEQUENT EVENTS
On April 28, 2015, Gill Ranch entered into a second amendment to the loan agreement under which the EBITDA covenant requirement is suspended through maturity of the loan. As part of the second amendment Gill Ranch will increase the debt reserve account by $4.5 million with contributions of $1.5 million by each of May 30, 2015, January 30, 2016, and August 30, 2016. 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.
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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 months ended March 31, 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 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, 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 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 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
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taxes. All references in this section to EPS are on the basis of diluted shares (see Note 3). We use such 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
Key financial highlights include:
Key financial highlights include:
Three Months Ended March 31, | ||||||||||||||||
2015 | 2014 | |||||||||||||||
In thousands, except per share data | Amount | Per Share | Amount | Per Share | $ Change | |||||||||||
Consolidated net income | $ | 28,486 | $ | 1.04 | $ | 37,884 | $ | 1.40 | $ | (9,398 | ) | |||||
Adjustments: | ||||||||||||||||
Regulatory environmental disallowance, net of taxes $5,925(1) | 9,075 | 0.33 | — | — | 9,075 | |||||||||||
Adjusted consolidated net income(1) | $ | 37,561 | $ | 1.37 | $ | 37,884 | $ | 1.40 | $ | (323 | ) | |||||
Utility margin | $ | 130,601 | $ | 130,294 | $ | 307 | ||||||||||
Gas storage operating revenues | 5,303 | 7,835 | (2,532 | ) |
(1) Regulatory environmental disallowance of $15 million is recorded in utility operations and maintenance expense. Adjusted EPS and net income (non-GAAP) are based on the after-tax disallowance, and EPS calculated using the combined federal and state statutory tax rate of 39.5% and divided by 27,369 thousand dilutive shares for the quarter.
THREE MONTHS ENDED MARCH 31, 2015 COMPARED TO MARCH 31, 2014. Consolidated net income for the quarter was $28.5 million, compared to $37.9 million for the same period of last year. The primary factor contributing to the $9.4 million decrease in consolidated net income was the $9.1 million after-tax charge related to the regulatory disallowance associated with a February 2015 OPUC Order in the Company's Site Remediation and Recovery Mechanism (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. In addition, consolidated net income was impacted by the following factors:
• | an increase in utility margin of $0.3 million; and |
• | a decrease in gas storage operating revenues of $2.5 million. |
We continued to make progress on several key strategic initiatives, as evidenced by the following items:
• | received the OPUC's Order on our SRRM which allows for full recovery of future prudently incurred environmental costs, subject to an annual earnings test; |
• | added more than 9,000 customers and sustained a customer growth rate in the core utility of 1.3%; |
• | received acknowledgment of our recently filed Integrated Resource Plans (IRP), which outlines long-term capital investment requirements based on projected customer growth and infrastructure needs; and |
• | continued permitting and land acquisition work on the North Mist gas storage expansion project. |
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ISSUES AND CHALLENGES
ECONOMY. The local, national, and global economies continue to show signs of improvement. Additionally, the unemployment rate in the Portland metropolitan region decreased to under 6% during the first quarter of 2015, a decrease of about 1% from the same period in 2014. The utility’s customer base increased to over 707,000 customers, reflecting a growth rate of 1.3% on a trailing 12-month basis at March 31, 2015, consistent with the growth rate at March 31, 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 44% for the upcoming 2015-16 gas year and between 5% and 9% for the following five gas years as of March 31, 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 from 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 decreases in supplies can put upward pressure on gas prices and gas price volatility, which could improve the market value for gas storage. Similarly, decreases in future demand and increases in supplies 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 anticipate a rebound 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.
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.
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CONSOLIDATED EARNINGS AND DIVIDENDS
Consolidated Earnings
Consolidated highlights include:
Three Months Ended March 31, | QTR Change | ||||||
In thousands, except per share data | 2015 | 2014 | |||||
Consolidated net income | 28,486 | 37,884 | (9,398 | ) | |||
Consolidated EPS | 1.04 | 1.40 | (0.36 | ) |
THREE MONTHS ENDED MARCH 31, 2015 COMPARED TO MARCH 31, 2014. The decrease in net income was primarily due to the $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. In addition, there was a $2.5 million decrease in gas storage operating revenues, a $3.7 million increase in operations and maintenance expense (excluding the regulatory disallowance) offset by a $3.7 million increase in other income, a $1.0 million decrease in interest expense, and a $0.3 million increase in utility margin.
Dividends
Dividend highlights include:
Three Months Ended March 31, | QTR | |||||||||||
Per common share | 2015 | 2014 | Change | |||||||||
Dividends paid | $ | 0.465 | $ | 0.460 | $ | 0.005 |
The Board of Directors declared a quarterly dividend on our common stock of $0.465 per share, payable on May 15, 2015, to shareholders of record on April 30, 2015, reflecting an indicated annual dividend rate of $1.86 per share.
REGULATORY MATTERS
Regulation and Rates
UTILITY. Our utility business is subject to regulation by the OPUC, the WUTC, and 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. 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.
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Regulatory Activities
The following provides a list of significant regulatory activities:
• | Prepaid Pension Asset - A schedule was established to resolve this docket in the second half of 2015. See "Rate Mechanisms—Pension Cost Deferral and Prepaid Pension Assets" 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 the 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 be performed and the results of the cost study may initiate a new docket or the re-opening of the original docket. |
• | Carbon Solutions Programs - Under Senate Bill (SB) 844 we anticipate submitting programs developed under these rules to the OPUC in 2015. These potential programs include heating conversion, combined heat and power, and other carbon emission reduction programs. |
• | Environmental Cost Deferral and Site Remediation and Recovery Mechanism - 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 filed the required compliance report on March 31, 2015. The Company 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. See "Rate Mechanisms—Environmental Cost Deferral and SRRM." |
Completed Regulatory Activities
We completed the following regulatory activity in the first quarter of 2015:
• | Integrated Resource Plans (IRP) - We filed our 2014 Oregon and Washington IRP in 2014 and received acknowledgment from the OPUC in February 2015. We also received notice from WUTC in March 2015. The IRPs included analysis of different market scenarios and corresponding resource acquisition strategies. This analysis is needed to develop supply and demand resource requirements, consider uncertainties in the planning process, and to establish a plan for providing reliable and low cost natural gas service. See "Financial Condition—Cash Flows—Investing Activities" below. |
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 permanent rate adjustment for our SIP 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 level, 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, 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
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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 do not expect a refund for 2014 based on our results and filed the 2014 earnings test in April 2015.
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 by Encana at then prevailing market prices, and revenues from such sales, net of associated operating and production costs, 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 proposed 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. We filed in February 2015 seeking cost recovery for the additional wells drilled in 2014, and we expect the OPUC to review the prudence of this investment in 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 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 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 approximately $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
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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 filed the required compliance report on March 31, 2015 with the OPUC demonstrating implementation of the Order. The Company also requested 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, as a consequence thereof, additional or different implementation procedures could be required, which may, among other things, result in additional impacts on earnings. We do not currently anticipate a disallowance for 2013 or 2014 based on the earnings test outlined in the Order.
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.
PENSION COST DEFERRAL AND PREPAID PENSION ASSETS. 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 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 $1.1 million for the three months ended March 31, 2015 and 2014, respectively.
CUSTOMER CREDITS FOR GAS STORAGE SHARING. In 2015, the Company filed for regulatory approval to refund an interstate storage credit of $9.9 million to its Oregon utility customers. These customer credits are part of our regulatory incentive sharing mechanism related to non-utility Mist storage and asset management services. The OPUC approved 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.
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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 March 31, | QTR Change | |||||||||
In thousands, except per share data | 2015 | 2014 | ||||||||
Utility net income | $ | 28,335 | $ | 36,019 | $ | (7,684 | ) | |||
EPS - utility segment | $ | 1.04 | $ | 1.33 | $ | (0.29 | ) | |||
Gas sold and delivered (therms) | 329,977 | 406,217 | (76,240 | ) | ||||||
Utility margin(1) | $ | 130,601 | $ | 130,294 | $ | 307 |
(1) See Utility Margin Table below for a reconciliation and additional detail.
THREE MONTHS ENDED MARCH 31, 2015 COMPARED TO MARCH 31, 2014. The primary factors contributing to the decrease in net income were as follows:
• | the $15 million pre-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 $0.3 million increase in utility margin primarily due to: |
◦ | a $2.7 million increase from customer growth in residential and commercial customers, added loads under higher commercial rate schedules, and added rate-base returns on certain investments, including gas reserves; |
◦ | a $3.1 million increase from gas cost incentive sharing resulting from lower gas prices than those estimated in the PGA; |
◦ | 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 that opted out of weather normalization. |
• | In addition, there was a $0.9 million net positive impact from the following offsetting items: an increase in other income, a decrease in interest expense, and an increase in operations and maintenance expense. |
Total utility volumes sold and delivered in the first quarter of 2015 decreased 19% over the same period of 2014 due to the impact of 22% warmer weather on customers.
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UTILITY MARGIN TABLE. The following table summarizes the composition of utility gas volumes, revenues, and costs of sales:
Three months ended | Favorable/ | |||||||||
In thousands, except degree day and customer data | March 31, | (Unfavorable) | ||||||||
2015 | 2014 | QTR Change | ||||||||
Utility volumes (therms): | ||||||||||
Residential and commercial sales | 206,817 | 274,156 | (67,339 | ) | ||||||
Industrial sales and transportation | 123,160 | 132,061 | (8,901 | ) | ||||||
Total utility volumes sold and delivered | 329,977 | 406,217 | (76,240 | ) | ||||||
Utility operating revenues: | ||||||||||
Residential and commercial sales | $ | 240,912 | $ | 270,002 | $ | (29,090 | ) | |||
Industrial sales and transportation | 20,526 | 21,512 | (986 | ) | ||||||
Other revenues | 1,406 | 1,477 | (71 | ) | ||||||
Less: Revenue taxes | 6,538 | 7,496 | (958 | ) | ||||||
Total utility operating revenues | 256,306 | 285,495 | (29,189 | ) | ||||||
Less: Cost of gas | 125,705 | 155,201 | (29,496 | ) | ||||||
Utility margin | $ | 130,601 | $ | 130,294 | $ | 307 | ||||
Utility margin:(1) | ||||||||||
Residential and commercial sales | $ | 120,372 | $ | 122,104 | $ | (1,732 | ) | |||
Industrial sales and transportation | 7,574 | 8,484 | (910 | ) | ||||||
Miscellaneous revenues | 1,406 | 1,587 | (181 | ) | ||||||
Gain (loss) from gas cost incentive sharing | 1,221 | (1,831 | ) | 3,052 | ||||||
Other margin adjustments | 28 | (50 | ) | 78 | ||||||
Utility margin | $ | 130,601 | $ | 130,294 | $ | 307 | ||||
Degree days: | ||||||||||
Average(2) | 1,855 | 1,855 | — | |||||||
Actual degree days | 1,481 | 1,890 | (22 | )% | ||||||
Percent colder (warmer) than average weather(2) | (20 | )% | 2 | % | ||||||
Customers - end of period: | ||||||||||
Residential customers | 640,235 | 631,557 | 8,678 | |||||||
Commercial customers | 66,314 | 65,883 | 431 | |||||||
Industrial customers | 923 | 932 | (9 | ) | ||||||
Total number of customers | 707,472 | 698,372 | 9,100 |
(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. |
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Residential and Commercial Sales
Residential and commercial sales highlights include:
Three Months Ended March 31, | QTR Change | |||||||||
In thousands | 2015 | 2014 | ||||||||
Utility volumes (therms): | ||||||||||
Residential sales | 130,060 | 173,177 | (43,117 | ) | ||||||
Commercial sales | 76,757 | 100,979 | (24,222 | ) | ||||||
Total volumes | 206,817 | 274,156 | (67,339 | ) | ||||||
Utility operating revenues: | ||||||||||
Residential sales | $ | 160,537 | $ | 179,982 | $ | (19,445 | ) | |||
Commercial sales | 80,375 | 90,020 | (9,645 | ) | ||||||
Total operating revenues | $ | 240,912 | $ | 270,002 | $ | (29,090 | ) | |||
Utility margin: | ||||||||||
Residential: | ||||||||||
Sales | $ | 70,776 | $ | 88,508 | $ | (17,732 | ) | |||
Weather normalization adjustments | 12,353 | (1,174 | ) | 13,527 | ||||||
Decoupling adjustments | 1,205 | (1,135 | ) | 2,340 | ||||||
Total residential utility margin | 84,334 | 86,199 | (1,865 | ) | ||||||
Commercial: | ||||||||||
Sales | 27,755 | 34,948 | (7,193 | ) | ||||||
Weather normalization adjustments | 5,244 | (456 | ) | 5,700 | ||||||
Decoupling adjustments | 3,039 | 1,413 | 1,626 | |||||||
Total commercial utility margin | 36,038 | 35,905 | 133 | |||||||
Total utility margin | $ | 120,372 | $ | 122,104 | $ | (1,732 | ) |
THREE MONTHS ENDED MARCH 31, 2015 COMPARED TO MARCH 31, 2014. The primary factors contributing to changes in residential and commercial results were as follows:
• | sales volumes decreased 25% or 67 million therms primarily due to 22% warmer weather; |
• | operating revenues decreased $29.1 million primarily due to 22% warmer weather; and |
• | utility margin decreased $1.7 million primarily due to the effects of warmer weather on customers that are not covered by a weather normalization mechanism. Increases from commercial and residential customer growth, added loads under higher commercial rate schedules, and added rate-base returns on our gas reserves and other investments partially offset the effect of weather. |
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 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.
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Industrial sales and transportation highlights include:
Three Months Ended March 31, | QTR Change | |||||||||
In thousands | 2015 | 2014 | ||||||||
Volumes (therms): | ||||||||||
Industrial - firm sales | 8,651 | 10,138 | (1,487 | ) | ||||||
Industrial - firm transportation | 40,828 | 44,160 | (3,332 | ) | ||||||
Industrial - interruptible sales |