Attached files
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EX-32.1 - EXHIBIT 32.1 CEO AND CFO CERTIFICATION - NORTHWEST NATURAL GAS CO | ex321q12017.htm |
EX-31.2 - EXHIBIT 31.2 CFO CERTIFICATION - NORTHWEST NATURAL GAS CO | ex312q12017.htm |
EX-31.1 - EXHIBIT 31.1 CEO CERTIFICATION - NORTHWEST NATURAL GAS CO | ex311q12017.htm |
EX-12 - EXHIBIT 12 FIXED CHARGES - NORTHWEST NATURAL GAS CO | ex122017.htm |
EX-10.1 - EXHIBIT 10.1 - NORTHWEST NATURAL GAS CO | ex101amendedrsuawardagreem.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, 2017
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", "smaller reporting company" and "emerging growth 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) Emerging Growth Company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
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 28, 2017, 28,644,327 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, 2017
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, which are subject to the safe harbors created by such Act. Forward-looking statements can be identified by words such as anticipates, assumes, 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, projections, forecasts and predictions; |
• | objectives, goals and strategies; |
• | assumptions and estimates; |
• | ongoing continuation of past practices or patterns; |
• | future events or performance; |
• | trends, uncertainties, timing and cyclicality; |
• | risks; |
• | earnings and dividends; |
• | capital and other expenditures and allocation; |
• | capital or organizational structure; |
• | climate change and our role in a low carbon future; |
• | growth and profitability; |
• | customer rates; |
• | labor relations; |
• | workforce succession; |
• | commodity costs and volumes; |
• | gas reserves, volumes, investment and recovery; |
• | operational and maintenance performance and costs; |
• | energy policy infrastructure and preferences; |
• | efficacy of and exposure under derivatives and hedges; |
• | liquidity, funding sources, and financial positions; |
• | valuations; |
• | project and program development, expansion, or investment; |
• | pipeline capacity demand, location, and reliability; |
• | adequacy of property rights; |
• | procurement and development of gas supplies; |
• | estimated expenditures; |
• | competition; |
• | costs of compliance; |
• | credit exposures; |
• | rate or regulatory outcomes, prudency, recovery or refunds; |
• | impacts of, or changes in, laws, rules and regulations; |
• | tax positions, liabilities or refunds; |
• | levels and pricing of gas storage contracts and gas storage markets; |
• | outcomes, timing and effects of potential claims, litigation, regulatory actions, and other administrative matters; |
• | projected obligations, contributions, expectations and treatment under retirement plans; |
• | availability, adequacy, and shift in mix, of gas supplies; |
• | effects of new or anticipated changes in accounting standards or pronouncements; |
• | approval and adequacy of regulatory deferrals; |
• | effects and efficacy of regulatory mechanisms; |
• | local or national disasters, pandemic illness, terrorist activities, including cyber-attacks, explosions, or other extreme events; and |
• | environmental, regulatory, litigation and insurance costs, allocations 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 operational or financial performance. Important factors that could cause actual results to differ
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materially from those in the forward-looking statements are discussed in our 2016 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.
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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 | 2017 | 2016 | ||||||
Operating revenues | $ | 297,323 | $ | 255,529 | ||||
Operating expenses: | ||||||||
Cost of gas | 143,611 | 108,411 | ||||||
Operations and maintenance | 40,420 | 38,939 | ||||||
Environmental remediation | 6,954 | 5,029 | ||||||
General taxes | 9,025 | 8,684 | ||||||
Depreciation and amortization | 21,085 | 20,394 | ||||||
Total operating expenses | 221,095 | 181,457 | ||||||
Income from operations | 76,228 | 74,072 | ||||||
Other income (expense), net | 881 | (2,309 | ) | |||||
Interest expense, net | 9,876 | 9,736 | ||||||
Income before income taxes | 67,233 | 62,027 | ||||||
Income tax expense | 26,923 | 25,386 | ||||||
Net income | 40,310 | 36,641 | ||||||
Other comprehensive income: | ||||||||
Amortization of non-qualified employee benefit plan liability, net of taxes of $89 and $127 for the three months ended March 31, 2017 and 2016, respectively | 136 | 194 | ||||||
Comprehensive income | $ | 40,446 | $ | 36,835 | ||||
Average common shares outstanding: | ||||||||
Basic | 28,633 | 27,448 | ||||||
Diluted | 28,723 | 27,560 | ||||||
Earnings per share of common stock: | ||||||||
Basic | $ | 1.41 | $ | 1.33 | ||||
Diluted | 1.40 | 1.33 | ||||||
Dividends declared per share of common stock | 0.4700 | 0.4675 |
See Notes to Unaudited Consolidated Financial Statements
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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED) | ||||||||||||
March 31, | March 31, | December 31, | ||||||||||
In thousands | 2017 | 2016 | 2016 | |||||||||
Assets: | ||||||||||||
Current assets: | ||||||||||||
Cash and cash equivalents | $ | 40,639 | $ | 4,321 | $ | 3,521 | ||||||
Accounts receivable | 70,429 | 69,066 | 66,700 | |||||||||
Accrued unbilled revenue | 38,017 | 36,393 | 64,946 | |||||||||
Allowance for uncollectible accounts | (1,668 | ) | (1,376 | ) | (1,290 | ) | ||||||
Regulatory assets | 34,874 | 61,524 | 42,362 | |||||||||
Derivative instruments | 2,908 | 1,960 | 17,031 | |||||||||
Inventories | 48,484 | 60,581 | 54,129 | |||||||||
Gas reserves | 15,378 | 16,420 | 15,926 | |||||||||
Other current assets | 16,832 | 23,311 | 24,728 | |||||||||
Total current assets | 265,893 | 272,200 | 288,053 | |||||||||
Non-current assets: | ||||||||||||
Property, plant, and equipment | 3,247,177 | 3,115,854 | 3,208,816 | |||||||||
Less: Accumulated depreciation | 960,336 | 919,187 | 947,916 | |||||||||
Total property, plant, and equipment, net | 2,286,841 | 2,196,667 | 2,260,900 | |||||||||
Gas reserves | 96,630 | 111,145 | 100,184 | |||||||||
Regulatory assets | 349,057 | 351,390 | 357,530 | |||||||||
Derivative instruments | 46 | 452 | 3,265 | |||||||||
Other investments | 68,729 | 67,490 | 68,376 | |||||||||
Other non-current assets | 3,460 | 2,689 | 1,493 | |||||||||
Total non-current assets | 2,804,763 | 2,729,833 | 2,791,748 | |||||||||
Total assets | $ | 3,070,656 | $ | 3,002,033 | $ | 3,079,801 |
See Notes to Unaudited Consolidated Financial Statements
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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED BALANCE SHEETS (UNAUDITED) | ||||||||||||
March 31, | March 31, | December 31, | ||||||||||
In thousands | 2017 | 2016 | 2016 | |||||||||
Liabilities and equity: | ||||||||||||
Current liabilities: | ||||||||||||
Short-term debt | $ | — | $ | 164,900 | $ | 53,300 | ||||||
Current maturities of long-term debt | 61,994 | 24,980 | 39,989 | |||||||||
Accounts payable | 73,245 | 57,407 | 85,664 | |||||||||
Taxes accrued | 16,653 | 10,256 | 12,149 | |||||||||
Interest accrued | 10,581 | 9,671 | 5,966 | |||||||||
Regulatory liabilities | 33,211 | 35,596 | 40,290 | |||||||||
Derivative instruments | 1,638 | 17,313 | 1,315 | |||||||||
Other current liabilities | 37,697 | 42,100 | 35,844 | |||||||||
Total current liabilities | 235,019 | 362,223 | 274,517 | |||||||||
Long-term debt | 657,716 | 569,745 | 679,334 | |||||||||
Deferred credits and other non-current liabilities: | ||||||||||||
Deferred tax liabilities | 575,451 | 550,731 | 557,085 | |||||||||
Regulatory liabilities | 357,587 | 346,761 | 349,319 | |||||||||
Pension and other postretirement benefit liabilities | 223,253 | 221,291 | 225,725 | |||||||||
Derivative instruments | 2,546 | 1,237 | 913 | |||||||||
Other non-current liabilities | 144,469 | 143,090 | 142,411 | |||||||||
Total deferred credits and other non-current liabilities | 1,303,306 | 1,263,110 | 1,275,453 | |||||||||
Commitments and contingencies (see Note 13) | ||||||||||||
Equity: | ||||||||||||
Common stock - no par value; authorized 100,000 shares; issued and outstanding 28,644, 27,493, and 28,630 at March 31, 2017 and 2016, and December 31, 2016, respectively | 442,647 | 385,232 | 445,187 | |||||||||
Retained earnings | 438,783 | 428,691 | 412,261 | |||||||||
Accumulated other comprehensive loss | (6,815 | ) | (6,968 | ) | (6,951 | ) | ||||||
Total equity | 874,615 | 806,955 | 850,497 | |||||||||
Total liabilities and equity | $ | 3,070,656 | $ | 3,002,033 | $ | 3,079,801 |
See Notes to Unaudited Consolidated Financial Statements
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NORTHWEST NATURAL GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) | ||||||||
Three Months Ended March 31, | ||||||||
In thousands | 2017 | 2016 | ||||||
Operating activities: | ||||||||
Net income | $ | 40,310 | $ | 36,641 | ||||
Adjustments to reconcile net income to cash provided by operations: | ||||||||
Depreciation and amortization | 21,085 | 20,394 | ||||||
Regulatory amortization of gas reserves | 4,107 | 4,075 | ||||||
Deferred income taxes | 20,445 | 23,353 | ||||||
Qualified defined benefit pension plan expense | 1,316 | 1,311 | ||||||
Contributions to qualified defined benefit pension plans | (3,220 | ) | (2,900 | ) | ||||
Deferred environmental (expenditures) recoveries, net | (3,432 | ) | (2,665 | ) | ||||
Regulatory disallowance of prior environmental cost deferrals | — | 3,273 | ||||||
Amortization of environmental remediation | 6,954 | 5,029 | ||||||
Other | 1,695 | 1,169 | ||||||
Changes in assets and liabilities: | ||||||||
Receivables, net | 23,147 | 22,242 | ||||||
Inventories | 5,645 | 10,115 | ||||||
Income taxes | 4,504 | 7,729 | ||||||
Accounts payable | (13,437 | ) | (14,537 | ) | ||||
Interest accrued | 4,615 | 3,798 | ||||||
Deferred gas costs | 13,454 | 8,519 | ||||||
Other, net | 17,978 | 18,592 | ||||||
Cash provided by operating activities | 145,166 | 146,138 | ||||||
Investing activities: | ||||||||
Capital expenditures | (38,924 | ) | (30,054 | ) | ||||
Other | 98 | 24 | ||||||
Cash used in investing activities | (38,826 | ) | (30,030 | ) | ||||
Financing activities: | ||||||||
Repurchases related to stock-based compensation | (1,943 | ) | (996 | ) | ||||
Proceeds from stock options exercised | 686 | 2,995 | ||||||
Change in short-term debt | (53,300 | ) | (105,135 | ) | ||||
Cash dividend payments on common stock | (13,456 | ) | (12,823 | ) | ||||
Other | (1,209 | ) | (39 | ) | ||||
Cash used in financing activities | (69,222 | ) | (115,998 | ) | ||||
Increase in cash and cash equivalents | 37,118 | 110 | ||||||
Cash and cash equivalents, beginning of period | 3,521 | 4,211 | ||||||
Cash and cash equivalents, end of period | $ | 40,639 | $ | 4,321 | ||||
Supplemental disclosure of cash flow information: | ||||||||
Interest paid, net of capitalization | $ | 4,394 | $ | 5,232 | ||||
Income taxes paid (refunded) | 3,040 | (7,900 | ) |
See Notes to Unaudited Consolidated Financial Statements
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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 NWN 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 financial statements are presented after elimination of all intercompany balances and transactions. In this report, the term “utility” is used to describe our regulated gas distribution business, and the term “non-utility” is used to describe our gas storage businesses and other non-utility investments and business activities.
Information presented in these interim consolidated financial statements is unaudited, but includes all material adjustments management considers necessary for fair statement 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 2016 Annual Report on Form 10-K (2016 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.
Certain prior year balances in our 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.
2. SIGNIFICANT ACCOUNTING POLICIES
Our significant accounting policies are described in Note 2 of the 2016 Form 10-K. There were no material changes to those accounting policies during the three months ended March 31, 2017. The following are current updates to certain critical accounting policy estimates and new accounting standards.
Industry Regulation
In applying regulatory accounting principles, we capitalize or defer certain costs and revenues as regulatory assets and liabilities pursuant to orders of the Public Utility Commission of Oregon (OPUC) or Washington Utilities and Transportation Commission (WUTC), which provide for the recovery of revenues or expenses from, or refunds to, utility customers in future periods, including a return or a carrying charge in certain cases.
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Amounts deferred as regulatory assets and liabilities were as follows:
Regulatory Assets | ||||||||||||
March 31, | December 31, | |||||||||||
In thousands | 2017 | 2016 | 2016 | |||||||||
Current: | ||||||||||||
Unrealized loss on derivatives(1) | $ | 1,580 | $ | 17,313 | $ | 1,315 | ||||||
Gas costs | 2,757 | 7,978 | 6,830 | |||||||||
Environmental costs(2) | 7,574 | 9,096 | 9,989 | |||||||||
Decoupling(3) | 10,087 | 13,235 | 13,067 | |||||||||
Other(4) | 12,876 | 13,902 | 11,161 | |||||||||
Total current | $ | 34,874 | $ | 61,524 | $ | 42,362 | ||||||
Non-current: | ||||||||||||
Unrealized loss on derivatives(1) | $ | 2,546 | $ | 1,237 | $ | 913 | ||||||
Pension balancing(5) | 53,105 | 46,247 | 50,863 | |||||||||
Income taxes | 36,591 | 40,106 | 38,670 | |||||||||
Pension and other postretirement benefit liabilities | 179,586 | 180,909 | 183,035 | |||||||||
Environmental costs(2) | 62,227 | 67,999 | 63,970 | |||||||||
Gas costs | 114 | 2,462 | 89 | |||||||||
Decoupling(3) | 2,803 | 2,641 | 5,860 | |||||||||
Other(4) | 12,085 | 9,789 | 14,130 | |||||||||
Total non-current | $ | 349,057 | $ | 351,390 | $ | 357,530 |
Regulatory Liabilities | ||||||||||||
March 31, | December 31, | |||||||||||
In thousands | 2017 | 2016 | 2016 | |||||||||
Current: | ||||||||||||
Gas costs | $ | 13,741 | $ | 22,098 | $ | 8,054 | ||||||
Unrealized gain on derivatives(1) | 2,870 | 1,960 | 16,624 | |||||||||
Other(4) | 16,600 | 11,538 | 15,612 | |||||||||
Total current | $ | 33,211 | $ | 35,596 | $ | 40,290 | ||||||
Non-current: | ||||||||||||
Gas costs | $ | 4,740 | $ | 9,221 | $ | 1,021 | ||||||
Unrealized gain on derivatives(1) | 46 | 452 | 3,265 | |||||||||
Accrued asset removal costs(6) | 345,614 | 331,000 | 341,107 | |||||||||
Other(4) | 7,187 | 6,088 | 3,926 | |||||||||
Total non-current | $ | 357,587 | $ | 346,761 | $ | 349,319 |
(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) | Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and 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, recovery of deferred amounts will be determined in a future proceeding. Current environmental costs represent remediation costs management expects to collect from Oregon customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to the aforementioned earnings test. See Note 13. |
(3) | This deferral represents the margin adjustment resulting from differences between actual and expected volumes. |
(4) | 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. |
(5) | 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 interest income recognized when amounts are collected in rates. |
(6) | Estimated costs of removal on certain regulated properties are collected through rates. |
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We believe all costs incurred and deferred at March 31, 2017 are prudent. We annually review all regulatory assets and liabilities for recoverability and more often if circumstances warrant. If we should determine that all or a portion of these regulatory assets or liabilities no longer meet the criteria for continued application of regulatory accounting, then we would be required to write-off the net unrecoverable balances in the period such determination is made.
New Accounting Standards
We consider the applicability and impact of all accounting standards updates (ASUs) issued by the Financial Accounting Standards Board (FASB). Accounting standards updates not listed below were assessed and determined to be either not applicable or are expected to have minimal impact on our consolidated financial position or results of operations.
Recently Adopted Accounting Pronouncements
There were no material changes to the recently adopted accounting policies described in Note 2 of the 2016 Form 10-K during the three months ended March 31, 2017.
Recently Issued Accounting Pronouncements
RETIREMENT BENEFITS. On March 10, 2017, the FASB issued ASU 2017-07, "Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost." The ASU requires entities to disaggregate current service cost from the other components of net periodic benefit cost and present it with other current compensation costs for related employees in the income statement and to present the other components elsewhere in the income statement and outside of income from operations if that subtotal is presented. This ASU also limits capitalization of net periodic benefit cost to the service cost component. The amendments in this update are effective for us beginning January 1, 2018. Upon adoption, the ASU requires that changes to the income statement presentation of net periodic benefit cost be applied retrospectively, while changes to amounts capitalized must be applied prospectively. We are currently assessing the effect of this standard on our financial statements and disclosures and anticipate the service cost component will be recognized in operations and maintenance expense, and the non-service cost component will be recognized in other income (expense), net. While the ASU limits capitalization of net periodic benefit cost to the service cost component, for rate making purposes, we do not expect there to be a change. As a result, we expect that the non-service cost component previously capitalized, will be reclassified to a regulatory asset. We do not anticipate any impact on net income from the adoption of this ASU.
STATEMENT OF CASH FLOWS. On August 26, 2016, the FASB issued ASU 2016-15, "Classification of Certain Cash Receipts and Cash Payments." The ASU adds guidance pertaining to the classification of certain cash receipts and payments on the statement of cash flows. The purpose of the amendment is to clarify issues that have been creating diversity in practice, including the classification of proceeds from the settlement of insurance claims and proceeds from the settlement of corporate-owned life insurance policies. The amendments in this standard are effective for us beginning January 1, 2018. Early adoption is permitted in any interim or annual period. We are currently assessing the effect of this standard and do not expect this standard to materially affect our financial statements and disclosures.
LEASES. On February 25, 2016, the FASB issued ASU 2016-02, "Leases," which revises the existing lease accounting guidance. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases that are greater than 12 months at lease commencement, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Lessor accounting will remain substantially the same under the new standard. Quantitative and qualitative disclosures are also required for users of the financial statements to have a clear understanding of the nature of our leasing activities. The standard is effective for us beginning January 1, 2019, and early adoption is permitted. The new standard must be adopted using a modified retrospective transition and provides for certain practical expedients. Transition will require application of the new guidance at the beginning of the earliest comparative period presented. We are currently assessing the effect of this standard on our financial statements and disclosures. Refer to Note 14 of the 2016 Form 10-K for our current lease commitments.
FINANCIAL INSTRUMENTS. On January 5, 2016, the FASB issued ASU 2016-01, "Financial Instruments - Overall: Recognition and Measurement of Financial Assets and Financial Liabilities." The ASU enhances the reporting model for financial instruments, which includes amendments to address aspects of recognition, measurement, presentation, and disclosure. The new standard is effective for us beginning January 1, 2018. Upon adoption, we will be required
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to make a cumulative-effect adjustment to the consolidated balance sheet in the first quarter of 2018. We do not expect this standard to have a material impact to our financial statements and disclosures.
REVENUE RECOGNITION. On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." Subsequently, the FASB issued additional, clarifying amendments to address issues and questions regarding implementation of the new revenue recognition standard. The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts the entity is expected to be entitled to in exchange for those goods or services. The ASU also prescribes 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 guidance also requires additional disclosures, both qualitative and quantitative, regarding the nature, amount, timing and uncertainty of revenue and cash flows. The new requirements prescribe either a full retrospective or simplified transition adoption method. We are still evaluating the overall impacts of the standard and have not yet made a determination of adoption method. Some aspects we are focused on in our review include considering the impacts this new standard will have on alternative revenue streams and how collectability will be evaluated for certain customer classes. In August 2015, the FASB deferred the effective date by one year to January 1, 2018 for annual reporting periods beginning after December 15, 2017. We plan to adopt the new standard effective January 1, 2018.
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. Antidilutive stock awards are excluded from the calculation of diluted earnings per common share. Diluted earnings per share are calculated as follows:
Three Months Ended March 31, | ||||||||
In thousands, except per share data | 2017 | 2016 | ||||||
Net income | $ | 40,310 | $ | 36,641 | ||||
Average common shares outstanding - basic | 28,633 | 27,448 | ||||||
Additional shares for stock-based compensation plans (See Note 5) | 90 | 112 | ||||||
Average common shares outstanding - diluted | 28,723 | 27,560 | ||||||
Earnings per share of common stock - basic | $ | 1.41 | $ | 1.33 | ||||
Earnings per share of common stock - diluted | $ | 1.40 | $ | 1.33 | ||||
Additional information: | ||||||||
Antidilutive shares | 22 | 22 |
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 are aggregated and reported 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 and our North Mist gas storage expansion in Oregon and NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp. Our gas storage segment includes NWN Gas Storage, which is a wholly-owned subsidiary of NWN Energy, Gill Ranch, which is a wholly-owned subsidiary of NWN Gas Storage, the non-utility portion of Mist, and all third-party asset management services. Other includes NNG Financial and NWN Energy's equity investment in TWH, which is pursuing development of a cross-Cascades transmission pipeline project. See Note 4 in the 2016 Form 10-K for further discussion of our segments.
Inter-segment transactions were insignificant for the periods presented. The following table presents summary financial information concerning the reportable segments:
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Three Months Ended March 31, | ||||||||||||||||
In thousands | Utility | Gas Storage | Other | Total | ||||||||||||
2017 | ||||||||||||||||
Operating revenues | $ | 292,726 | $ | 4,541 | $ | 56 | $ | 297,323 | ||||||||
Depreciation and amortization | 19,624 | 1,461 | — | 21,085 | ||||||||||||
Income (loss) from operations | 75,823 | 606 | (201 | ) | 76,228 | |||||||||||
Net income (loss) | 40,192 | 61 | 57 | 40,310 | ||||||||||||
Capital expenditures | 38,854 | 70 | — | 38,924 | ||||||||||||
Total assets at March 31, 2017 | 2,799,638 | 254,260 | 16,758 | 3,070,656 | ||||||||||||
2016 | ||||||||||||||||
Operating revenues | $ | 250,104 | $ | 5,369 | $ | 56 | $ | 255,529 | ||||||||
Depreciation and amortization | 18,760 | 1,634 | — | 20,394 | ||||||||||||
Income from operations | 72,295 | 1,726 | 51 | 74,072 | ||||||||||||
Net income | 35,852 | 736 | 53 | 36,641 | ||||||||||||
Capital expenditures | 29,177 | 877 | — | 30,054 | ||||||||||||
Total assets at March 31, 2016 | 2,726,696 | 260,535 | 14,802 | 3,002,033 | ||||||||||||
Total assets at December 31, 2016 | 2,806,627 | 256,333 | 16,841 | 3,079,801 |
Utility Margin
Utility margin is a financial measure consisting of utility operating revenues, which are reduced by revenue taxes, the associated cost of gas, and environmental recovery revenues. The cost of gas purchased for utility customers is generally a pass-through cost in the amount of revenues billed to regulated utility customers. Environmental recovery revenues represent collections received from customers through our environmental recovery mechanism in Oregon. These collections are offset by the amortization of environmental liabilities, which is presented as environmental remediation expense in our operating expenses. By subtracting cost of gas and environmental remediation expense 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 | 2017 | 2016 | |||||
Utility margin calculation: | |||||||
Utility operating revenues (1) | $ | 292,726 | $ | 250,104 | |||
Less: Utility cost of gas | 143,611 | 108,411 | |||||
Environmental remediation expense | 6,954 | 5,029 | |||||
Utility margin | $ | 142,161 | $ | 136,664 |
(1) | Utility operating revenues include environmental recovery revenues, which are collections received from customers through our environmental recovery mechanism in Oregon, offset by environmental remediation expense. |
5. STOCK-BASED COMPENSATION
Our stock-based compensation plans are designed to promote stock ownership in NW Natural by employees and officers. These compensation plans include a Long Term Incentive Plan (LTIP), an Employee Stock Purchase Plan (ESPP), and a Restated Stock Option Plan. For additional information on our stock-based compensation plans, see Note 6 in the 2016 Form 10-K and the updates provided below.
Long Term Incentive Plan
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Performance Shares
LTIP performance shares incorporate a combination of market, performance, and service-based factors. During the three months ended March 31, 2017, 29,380 performance-based shares were granted under the LTIP based on target-level awards with a weighted-average grant date fair value of $57.05 per share. Award share payouts range from a threshold of 0% to a maximum of 200% based on achievement of EPS and Return on Invested Capital (ROIC) factors, which can be modified by a total shareholder return factor (TSR factor) relative to the performance of the Russell 2500 Utilities Index over the three-year performance period and a growth modifier based on a cumulative EBITDA measure. As of March 31, 2017, there was $3.1 million of unrecognized compensation cost from LTIP grants, which is expected to be recognized through 2019. Fair value for the shares granted during the three months ended March 31, 2017, 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 | $ | 59.90 | |
Performance term (in years) | 3.0 | ||
Quarterly dividends paid per share(1) | $ | 0.4700 | |
Expected dividend yield | 3.09 | % | |
Dividend discount factor | 0.9156 |
(1) | In addition to common stock shares, a participant also receives a dividend equivalent cash payment equal to the number of shares of common stock received on the award payout multiplied by the aggregate cash dividends paid per share during the performance period. |
Restricted Stock Units
During the three months ended March 31, 2017, 18,020 RSUs were granted under the LTIP with a weighted-average grant date fair value of $59.90 per share. Generally, the RSUs awarded are forfeitable and include a performance-based threshold as well as a vesting period of four years from the grant date. A RSU obligates us, 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. The fair value of a RSU is equal to the closing market price of our common stock on the grant date. As of March 31, 2017, there was $3.1 million of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through 2022.
6. DEBT
Short-Term Debt
At March 31, 2017, we had no outstanding short-term debt.
Long-Term Debt
At March 31, 2017, we had long-term debt of $719.7 million, which included $7.0 million of unamortized debt issuance costs. Utility long-term debt consists of first mortgage bonds (FMBs) with maturity dates ranging from 2017 through 2046, interest rates ranging from 1.545% to 9.05%, and a weighted-average coupon rate of 5.083%.
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 the 2016 Form 10-K for a description of the fair value hierarchy.
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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 | 2017 | 2016 | 2016 | |||||||||
Gross long-term debt | $ | 726,700 | $ | 601,700 | $ | 726,700 | ||||||
Unamortized debt issuance costs | (6,990 | ) | (6,975 | ) | (7,377 | ) | ||||||
Carrying amount | $ | 719,710 | $ | 594,725 | $ | 719,323 | ||||||
Estimated fair value(1) | 785,980 | 686,159 | 793,339 |
(1) Estimated fair value does not include unamortized debt issuance costs.
7. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS
The following table provides the components of net periodic benefit cost for our pension and other postretirement benefit plans:
Three Months Ended March 31, | ||||||||||||||||
Pension Benefits | Other Postretirement Benefits | |||||||||||||||
In thousands | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Service cost | $ | 1,870 | $ | 1,944 | $ | 98 | $ | 121 | ||||||||
Interest cost | 4,472 | 4,574 | 274 | 300 | ||||||||||||
Expected return on plan assets | (5,113 | ) | (5,017 | ) | — | — | ||||||||||
Amortization of prior service costs | 32 | 58 | (117 | ) | (117 | ) | ||||||||||
Amortization of net actuarial loss | 3,621 | 3,502 | 138 | 192 | ||||||||||||
Net periodic benefit cost | 4,882 | 5,061 | 393 | 496 | ||||||||||||
Amount allocated to construction | (1,521 | ) | (1,548 | ) | (132 | ) | (164 | ) | ||||||||
Amount deferred to regulatory balancing account(1) | (1,527 | ) | (1,627 | ) | — | — | ||||||||||
Net amount charged to expense | $ | 1,834 | $ | 1,886 | $ | 261 | $ | 332 |
(1) | The deferral of defined benefit pension plan 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. The balancing account includes the expectation of higher net periodic benefit costs than costs recovered in rates in the near-term with lower net periodic benefit costs than costs recovered in rates expected in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the equity portion of the interest recognized when amounts are collected in rates. See Note 2 in the 2016 Form 10-K. |
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 | 2017 | 2016 | |||||
Beginning balance | $ | (6,951 | ) | $ | (7,162 | ) | |
Amounts reclassified from AOCL: | |||||||
Amortization of actuarial losses | 225 | 321 | |||||
Total reclassifications before tax | 225 | 321 | |||||
Tax (benefit) expense | (89 | ) | (127 | ) | |||
Total reclassifications for the period | 136 | 194 | |||||
Ending balance | $ | (6,815 | ) | $ | (6,968 | ) |
Employer Contributions to Company-Sponsored Defined Benefit Pension Plans
For the three months ended March 31, 2017, we made cash contributions totaling $3.2 million to our qualified defined benefit pension plans. We expect further plan contributions of $16.2 million during the remainder of 2017.
Defined Contribution Plan
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The Retirement K Savings Plan is a qualified defined contribution plan under Internal Revenue Code Sections 401(a) and 401(k). Employer contributions totaled $1.6 million and $1.4 million for the three months ended March 31, 2017 and 2016, respectively.
See Note 8 in the 2016 Form 10-K for more information concerning these retirement and other postretirement benefit plans.
8. INCOME TAX
An estimate of annual income tax expense is made each interim period using estimates for annual pre-tax income, regulatory flow-through adjustments, tax credits, and other items. The estimated annual effective tax rate is applied to year-to-date, pre-tax income to determine income tax expense for the interim period consistent with the annual estimate.
The effective income tax rate varied from the combined federal and state statutory tax rates due to the following:
Three Months Ended March 31, | ||||||||
Dollars in thousands | 2017 | 2016 | ||||||
Income taxes at statutory rates (federal and state) | $ | 26,600 | $ | 24,608 | ||||
Increase (decrease): | ||||||||
Differences required to be flowed-through by regulatory commissions | 1,518 | 1,518 | ||||||
Other, net | (1,195 | ) | (740 | ) | ||||
Total provision for income taxes | $ | 26,923 | $ | 25,386 | ||||
Effective tax rate | 40.0 | % | 40.9 | % |
The effective income tax rate for the three months ended March 31, 2017, compared to the same period in 2016, decreased primarily as a result of the equity portion of our allowance for funds used during construction (AFUDC) and increased stock-based compensation deductions in 2017. See Note 9 in the 2016 Form 10-K for more detail on income taxes and effective tax rates.
The IRS Compliance Assurance Process (CAP) examination of the 2015 tax year was completed during the quarter. There were no material changes to the return as filed. The 2016 tax year is subject to examination under CAP and the 2017 tax year CAP application has been accepted by the IRS.
9. PROPERTY, PLANT, AND EQUIPMENT
The following table sets forth the major classifications of our property, plant, and equipment and accumulated depreciation:
March 31, | December 31, | |||||||||||
In thousands | 2017 | 2016 | 2016 | |||||||||
Utility plant in service | $ | 2,867,271 | $ | 2,760,188 | $ | 2,843,243 | ||||||
Utility construction work in progress | 76,631 | 51,014 | 62,264 | |||||||||
Less: Accumulated depreciation | 914,179 | 878,364 | 903,096 | |||||||||
Utility plant, net | 2,029,723 | 1,932,838 | 2,002,411 | |||||||||
Non-utility plant in service | 299,324 | 296,826 | 299,378 | |||||||||
Non-utility construction work in progress | 3,951 | 7,826 | 3,931 | |||||||||
Less: Accumulated depreciation | 46,157 | 40,823 | 44,820 | |||||||||
Non-utility plant, net | 257,118 | 263,829 | 258,489 | |||||||||
Total property, plant, and equipment | $ | 2,286,841 | $ | 2,196,667 | $ | 2,260,900 | ||||||
Capital expenditures in accrued liabilities | $ | 11,564 | $ | 8,424 | $ | 9,547 |
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10. GAS RESERVES
We have invested $188 million through our gas reserves program in the Jonah Field located in Wyoming as of March 31, 2017. Gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities on the consolidated balance sheets. Our investment in gas reserves provides long-term price protection for utility customers through the original agreement with Encana Oil & Gas (USA) Inc. under which we invested $178 million and the amended agreement with Jonah Energy LLC under which an additional $10 million was invested.
The cost of gas, including a carrying cost for the rate base investment made under the original agreement, is included in our annual Oregon PGA filing, which allows us to recover these costs through customer rates. Our investment under the original agreement, less accumulated amortization and deferred taxes, earns a rate of return.
The volumes produced from the wells under the amended agreement with Jonah are included in our Oregon PGA at a fixed rate of $0.4725 per therm, which approximates the 10-year hedge rate plus financing costs at the inception of the investment.
The following table outlines our net gas reserves investment:
March 31, | December 31, | |||||||||||
In thousands | 2017 | 2016 | 2016 | |||||||||
Gas reserves, current | $ | 15,378 | $ | 16,420 | $ | 15,926 | ||||||
Gas reserves, non-current | 172,158 | 171,121 | 171,610 | |||||||||
Less: Accumulated amortization | 75,528 | 59,976 | 71,426 | |||||||||
Total gas reserves(1) | 112,008 | 127,565 | 116,110 | |||||||||
Less: Deferred taxes on gas reserves | 32,179 | 28,547 | 28,119 | |||||||||
Net investment in gas reserves | $ | 79,829 | $ | 99,018 | $ | 87,991 |
(1) | Our net investment in additional wells included in total gas reserves was $6.5 million, $7.6 million and $6.7 million at March 31, 2017 and 2016 and December 31, 2016, respectively. |
Our investment is included in our consolidated balance sheets under gas reserves with our maximum loss exposure limited to our investment balance.
11. INVESTMENTS
Investments in Gas Pipeline
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.
Variable Interest Entity (VIE) Analysis
TWH is a VIE, with our investment in TWP reported under equity method accounting. We have determined we are not the primary beneficiary of TWH’s activities as we only have a 50% share of the entity and there are no stipulations that allow us a disproportionate influence over it. Our investments 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, 2017 and 2016 and December 31, 2016. See Note 12 in the 2016 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 2016 Form 10-K.
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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 | 2017 | 2016 | 2016 | |||||||||
Natural gas (in therms): | ||||||||||||
Financial | 382,850 | 317,100 | 477,430 | |||||||||
Physical | 368,700 | 169,978 | 535,450 | |||||||||
Foreign exchange | $ | 6,629 | $ | 6,852 | $ | 7,497 |
Purchased Gas Adjustment (PGA)
Derivatives entered into by the utility for the procurement or hedging of natural gas for future gas years generally receive regulatory deferral accounting treatment. In general, our commodity hedging for the current gas year is completed prior to the start of the gas year, and hedge prices are reflected in our weighted-average cost of gas in the PGA filing. Hedge contracts entered into after the start of the PGA period are subject to our PGA incentive sharing mechanism in Oregon. As of November 1, 2016 and 2015, we reached our target hedge percentage of approximately 75% for the 2016-17 and 2015-16 gas years. Hedge contracts entered into prior to our PGA filing, in September 2016, were included in the PGA for the 2016-17 gas year. Hedge contracts entered into after our PGA filing, and related to subsequent gas years, may be included in future PGA filings and qualify for regulatory deferral.
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, | ||||||||||||||||
2017 | 2016 | |||||||||||||||
In thousands | Natural gas commodity | Foreign exchange | Natural gas commodity | Foreign exchange | ||||||||||||
Benefit (expense) to cost of gas | $ | (13,094 | ) | $ | 26 | $ | (7,215 | ) | $ | 404 | ||||||
Operating loss | (1,226 | ) | — | — | — | |||||||||||
Amounts deferred to regulatory accounts on balance sheet | 13,893 | (26 | ) | 7,215 | (404 | ) | ||||||||||
Total loss in pre-tax earnings | $ | (427 | ) | $ | — | $ | — | $ | — |
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UNREALIZED GAIN/LOSS. Outstanding derivative instruments related to regulated utility operations are deferred in accordance with regulatory accounting standards. The cost of foreign currency forward and natural gas derivative contracts are recognized immediately in the cost of gas; however, costs above or below the amount embedded in the current year PGA are subject to a regulatory deferral tariff and therefore, are recorded as a regulatory asset or liability.
REALIZED GAIN/LOSS. We realized net losses of $0.3 million and $15.5 million for the three months ended March 31, 2017 and 2016, 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 Derivatives Instruments
No collateral was posted with or by our counterparties as of March 31, 2017 or 2016. 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 were not subject to collateral calls in 2017 or 2016. 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 upon current commodity financial swap and option contracts outstanding, which reflect unrealized losses of $1.4 million at March 31, 2017, 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 | $ | — | $ | — | $ | — | $ | (1,065 | ) | $ | (522 | ) | ||||||||
Without Adequate Assurance Calls | — | — | — | (1,065 | ) | (160 | ) |
Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our consolidated balance sheets. 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 derivative position would result in an asset of $1.7 million and a liability of $2.9 million as of March 31, 2017. As of March 31, 2016, our derivative position would have resulted in an asset of $1.8 million and a liability of $17.9 million. As of December 31, 2016, our derivative position would have resulted in an asset of $18.8 million and a liability of $0.7 million.
We are exposed to derivative credit and liquidity risk primarily through securing fixed price natural gas commodity swaps to hedge the risk of price increases for our natural gas purchases made on behalf of customers. See Note 13 in our 2016 Form 10-K for additional information.
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Fair Value
In accordance with fair value accounting, we include non-performance 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, 2017. As of March 31, 2017 and 2016, and December 31, 2016, the net fair value was a liability of $1.2 million, a liability of $16.1 million, and an asset $18.1 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, 2017 and 2016. See Note 2 in the 2016 Form 10-K.
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 (PRPs). When amounts are prudently expended related to site remediation, of those sites described herein, we have a recovery mechanism in place to collect 96.68% of remediation costs from Oregon customers, and we are allowed to defer environmental remediation costs allocated to customers in Washington annually until they are reviewed for prudence at a subsequent proceeding.
Our sites are subject to the remediation process prescribed by the Environmental Protection Agency (EPA) and the Oregon Department of Environmental Quality (ODEQ). The process begins with a remedial investigation (RI) to determine the nature and extent of contamination and then a risk assessment (RA) to establish whether the contamination at the site poses unacceptable risks to humans and the environment. Next, a feasibility study (FS) or an engineering evaluation/cost analysis (EE/CA) evaluates various remedial alternatives. It is at this point in the process when we are able to estimate a range of remediation costs and record a reasonable potential remediation liability, or make an adjustment to our existing liability. From this study, the regulatory agency selects a remedy and issues a Record of Decision (ROD). After a ROD is issued, we would seek to negotiate a consent decree or consent judgment for designing and implementing the remedy. We would have the ability to further refine estimates of remediation liabilities at that time.
Remediation may include treatment of contaminated media such as sediment, soil and groundwater, removal and disposal of media, institutional controls such as legal restrictions on future property use, or natural recovery. Following construction of the remedy, the EPA and ODEQ also have requirements for ongoing maintenance, monitoring and other post-remediation care that may continue for many years. Where appropriate and reasonably known, we will provide for these costs in our remediation liabilities described below.
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 where a range of potential loss is available. Unless there is an estimate within the 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 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. In addition to remediation costs, we could also be subject to Natural Resource Damages (NRD) claims. We will assess the likelihood and probability of each claim and recognize a liability if deemed appropriate. We received a claim made by the Yakama Nation on January 31, 2017 for costs related to the selection of remedial action and certain declaratory relief regarding NRD. We are currently in the process of assessing the nature of, and our potential liability related to, the claim.
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Environmental Sites
The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other current liabilities and other noncurrent liabilities on the balance sheet:
Current Liabilities | Non-Current Liabilities | |||||||||||||||||||||||
March 31, | December 31, | March 31, | December 31, | |||||||||||||||||||||
In thousands | 2017 | 2016 | 2016 | 2017 | 2016 | 2016 | ||||||||||||||||||
Portland Harbor site: | ||||||||||||||||||||||||
Gasco/Siltronic Sediments | $ | 1,573 | $ | 2,747 | $ | 869 | $ | 43,200 | $ | 42,079 | $ | 43,972 | ||||||||||||
Other Portland Harbor | 1,804 | 1,655 | 1,970 | 3,940 | 4,775 | 4,148 | ||||||||||||||||||
Gasco/Siltronic Upland site | 10,335 | 10,626 | 10,657 | 50,189 | 51,403 | 49,183 | ||||||||||||||||||
Central Service Center site | 68 | 25 | 73 | — | — | — | ||||||||||||||||||
Front Street site | 858 | 1,071 | 906 | 7,777 | 7,746 | 7,786 | ||||||||||||||||||
Oregon Steel Mills | — | — | — | 179 | 179 | 179 | ||||||||||||||||||
Total | $ | 14,638 | $ | 16,124 | $ | 14,475 | $ | 105,285 | $ | 106,182 | $ | 105,268 |
PORTLAND HARBOR SITE. The Portland Harbor is an EPA listed Superfund site that is approximately 10 miles long on the Willamette River and is adjacent to NW Natural's Gasco uplands sites. We are one of over one hundred PRPs to the Superfund site. In January 2017, the EPA issued its Record of Decision, which outlines its determination of a cleanup approach for the Portland Harbor site (Portland Harbor ROD). The Portland Harbor ROD presents the EPA's decision on remedial alternatives and outlines the clean-up plan for the entire Portland Harbor. The Portland Harbor ROD estimates the present value total cost at approximately $1.05 billion with an accuracy between -30% and +50% of actual costs.
Our potential liability is a portion of the costs of the remedy for the entire Portland Harbor Superfund site. The cost of that remedy is expected to be allocated among more than 100 PRPs. In addition, we are actively pursuing clarification and flexibility under the ROD in order to better understand our obligation under the clean-up. We are also participating in a non-binding allocation process in an effort to resolve our potential liability. The Portland Harbor ROD does not provide any additional clarification around allocation of costs among PRPs and, as a result of issuance of the Portland Harbor ROD, we have not modified any of our recorded liabilities at this time.
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. We submitted a draft EE/CA to the EPA in May 2012 to provide the estimated cost of potential remedial alternatives for this site. At this time, the estimated costs for the various sediment remedy alternatives in the draft EE/CA as well as costs for the additional studies and design work needed before the cleanup can occur, and for regulatory oversight throughout the clean-up range from $44.8 million to $350 million. We have recorded a liability of $44.8 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. While we still believe liabilities associated with Gasco/Siltronic sediments site represent our largest exposure, we do have other potential exposures associated with the Portland Harbor ROD, including NRD costs and harbor wide clean-up costs (including downstream petroleum contamination), for which the allocations among the PRP's have not yet been determined.
The Company and other parties have signed a cooperative agreement with the Portland Harbor Natural Resource Trustee council to participate in a phased NRD assessment to estimate liabilities to support an early restoration-based settlement of NRD claims. One member of this Trustee council, the Yakama Nation, withdrew from the council in June 2009, and in January 2017, filed suit against the Company and 31 other parties seeking remedial costs and NRD assessment costs associated with the Portland Harbor, set forth in the complaint. The complaint
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seeks recovery of alleged costs totaling $0.3 million in connection with the selection of a remedial action for the Portland Harbor as well as declaratory judgment for unspecified future remedial action costs and for costs to assess the injury, loss or destruction of natural resources resulting from the release of hazardous substances at and from the Portland Harbor site. We have recorded 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. The NRD liability is not included in the range of costs provided in the Portland Harbor ROD.
GASCO UPLANDS SITE. A predecessor of NW Natural, Portland Gas and Coke Company, owned 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 ODEQ Voluntary Clean-Up Program (VCP). 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.
We submitted a revised Remedial Investigation Report for the uplands to ODEQ in May 2007. In March 2015, ODEQ approved the RA NW Natural submitted in 2010, enabling us to begin work on the FS in 2016. 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.
In October 2016, ODEQ and NW Natural agreed to amend their VCP agreement to incorporate a portion of the Siltronic property adjacent to the Gasco site formerly owned by Portland Gas & Coke between 1939 and 1960 into the Gasco RA and FS. Previously we were conducting an investigation of manufactured gas plant constituents on the entire Siltronic uplands for ODEQ. Siltronic will be working with ODEQ directly on environmental impacts to the remainder of its property.
In September 2013, we completed construction of a groundwater source control system, including a water treatment station, at 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 is highly dependent on the remedy determined for both the upland portion as well as the final remedy for our Gasco sediment exposure.
OTHER SITES. In addition to those sites above, we have environmental exposures at three other sites: Central Service Center, Front Street and Oregon Steel Mills. We may have exposure at other sites that have not been identified at this time. Due to the uncertainty of the design of remediation, regulation, timing of the remediation 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 at this time.
Central Service Center site. We are currently performing an environmental investigation of the property under 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 (the former Portland Gas Manufacturing site, or PGM). At ODEQ’s request, we conducted a sediment and source control investigation and provided findings to ODEQ. In December 2015, we completed a FS on the former Portland Gas Manufacturing site. The FS provided a range of $7.6 million to $12.9 million for remedial costs. We have recorded a liability at the low end of the range of possible loss as no alternative in the range is considered more likely than another. Further, we have recognized an additional liability of $1.0 million for additional studies and design costs as well as regulatory oversight throughout the clean-up that will be required to assist in ODEQ making a remedy selection and completing a design.
Oregon Steel Mills site. Refer to the “Legal Proceedings,” below.
Site Remediation and Recovery Mechanism (SRRM)
We have a SRRM through which we track and have the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test, for those sites identified herein. In the February 2015 Order establishing the SRRM (2015 Order), the OPUC addressed outstanding issues
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related to the SRRM, which required us to forego the collection of $15 million out of approximately $95 million in total environmental remediation expenses and associated carrying costs. As a follow-up to the 2015 Order, the OPUC issued an additional Order in January 2016 (2016 Order) regarding the SRRM implementation which resulted in a $3.3 million non-cash charge primarily due to the disallowance of interest earned on the original allowance.
COLLECTIONS FROM OREGON CUSTOMERS. Under the SRRM collection process there are three types of deferred environmental remediation expense:
• | Pre-review - This class of costs represents remediation spend that has not yet been deemed prudent by the OPUC. Carrying costs on these remediation expenses are recorded at our authorized cost of capital. The Company anticipates the prudence review for annual costs and approval of the earnings test prescribed by the OPUC to occur by the third quarter of the following year. |
• | Post-review - This class of costs represents remediation spend that has been deemed prudent and allowed after applying the earnings test, but is not yet included in amortization. We earn a carrying cost on these amounts at a rate equal to the five-year treasury rate plus 100 basis points. |
• | Amortization - This class of costs represents amounts included in current customer rates for collection and is generally calculated as one-fifth of the post-review deferred balance. We earn a carrying cost equal to the amortization rate determined annually by the OPUC, which approximates a short-term borrowing rate. |
In addition to the collection amount noted above, the Order also provides for the annual collection of $5 million from Oregon customers through a tariff rider. As we collect amounts from customers, we recognize these collections as revenue and separately amortize an equal and offsetting amount of our deferred regulatory asset balance through the environmental remediation operating expense line shown separately in the operating expense section of the income statement.
We 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 2015 OPUC Order, one-third of the Oregon allocated proceeds were applied to costs deferred through 2012 with the remaining two-thirds applied to costs at a rate of $5 million per year plus interest over the following 20 years. We accrue interest on the insurance proceeds in the customer’s favor at a rate equal to the five-year treasury rate plus 100 basis points. As of March 31, 2017, we have applied $63.2 million of insurance proceeds to prudently incurred remediation costs.
The following table presents information regarding the total regulatory asset deferred:
March 31, | December 31, | |||||||||||
In thousands | 2017 | 2016 | 2016 | |||||||||
Deferred costs and interest (1) | $ | 49,373 | $ | 57,359 | $ | 53,039 | ||||||
Accrued site liabilities (2) | 119,623 | 122,306 | 119,443 | |||||||||
Insurance proceeds and interest | (99,195 | ) | (102,570 | ) | (98,523 | ) | ||||||
Total regulatory asset deferral(1) | $ | 69,801 | $ | 77,095 | $ | 73,959 | ||||||
Current regulatory assets(3) | 7,574 | 9,096 | 9,989 | |||||||||
Long-term regulatory assets(3) | 62,227 | 67,999 | 63,970 |
(1) | Includes pre-review and post-review deferred costs, amounts currently in amortization, and interest, net of amounts collected from customers. |
(2) | Excludes $0.3 million, or 3.32% of the Front Street site liability as the OPUC allows recovery of 96.68% of costs for those sites allocable to Oregon, including those that historically served only Oregon customers. |
(3) | Environmental costs relate to specific sites approved for regulatory deferral by the OPUC and 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. Current environmental costs represent remediation costs management expects to collect from customers in the next 12 months. Amounts included in this estimate are still subject to a prudence and earnings test review by the OPUC and do not include the $5 million tariff rider. The amounts allocable to Oregon are recoverable through utility rates, subject to an earnings test. |
ENVIRONMENTAL EARNINGS TEST. To the extent the utility earns at or below its authorized Return on Equity (ROE), remediation expenses and interest in excess of the $5 million tariff rider and $5 million insurance proceeds are recoverable through the SRRM. To the extent the utility earns more than its authorized ROE in a year, the utility
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is required to cover environmental expenses and interest on expenses greater than the $10 million with those earnings that exceed its authorized ROE.
Under the 2015 Order, the OPUC will revisit the deferral and amortization of future remediation expenses, as well as the treatment of remaining insurance proceeds three years from the original Order, or earlier if the Company gains greater certainty about its future remediation costs, to consider whether adjustments to the mechanism may be appropriate.
WASHINGTON DEFERRAL. 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 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.
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, we do not expect that 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 Evraz 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 the ultimate disposition of this matter will have a material effect on our financial condition, results of operations or cash flows.
For additional information regarding other commitments and contingencies, see Note 14 in the 2016 Form 10-K.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is management’s assessment of Northwest Natural Gas Company’s (NW Natural or the Company) financial condition, including the principal factors that affect results of operations. The discussion refers to our consolidated results for the quarters ended March 31, 2017 and 2016. References in this discussion 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 2016 Annual Report on Form 10-K (2016 Form 10-K).
The consolidated financial statements include NW Natural and its direct and indirect wholly-owned subsidiaries including:
• | 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 |
• | NWN Gas Reserves, LLC (NWN Gas Reserves). |
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 Holding, 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). 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 2016 environmental order, which are non-GAAP financial measures. We present net income and earnings per share (EPS) excluding the regulatory disallowances along with the U.S. GAAP measures to illustrate the magnitude of this disallowance on ongoing business and operational results. Although the excluded amounts are properly included in the determination of net income and earnings per share under U.S. GAAP, we believe the amount and nature of such disallowances make period to period comparisons of operations difficult or potentially confusing. Financial measures are expressed in cents per share as these amounts reflect factors that directly impact earnings, including income taxes. All references in this section to EPS are on the basis of diluted shares (see Note 3). We use such non-GAAP financial 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.
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EXECUTIVE SUMMARY
We manage our business and strategic initiatives with a long-term view of providing natural gas service safely and reliably to customers, working with regulators on key policy initiatives, and remaining focused on growing our business. See "2017 Outlook" in our 2016 Form 10-K for more information. Highlights include:
• | added over 12,000 customers during the past twelve months for a growth rate of 1.7% at March 31, 2017; |
• | invested $39 million in our distribution system and facilities for growth and reliability, including $8 million for our North Mist gas storage expansion project; and |
• | received acknowledgment of our 2016 Integrated Resource Plans (IRP), which outlines long-term capital investment requirements based on projected customer growth and infrastructure needs. |
Key financial highlights include:
Three Months Ended March 31, | ||||||||||||||||||
2017 | 2016 | $ | ||||||||||||||||
In thousands, except per share data | Amount | Per Share | Amount | Per Share | Change | |||||||||||||
Consolidated net income | $ | 40,310 | $ | 1.40 | $ | 36,641 | $ | 1.33 | $ | 3,669 | ||||||||
Adjustments: | ||||||||||||||||||
Regulatory environmental disallowance, net of taxes ($1.3 million for 2016)(1) | — | — | 1,996 | 0.07 | (1,996 | ) | ||||||||||||
Adjusted consolidated net income(1) | $ | 40,310 | $ | 1.40 | $ | 38,637 | $ | 1.40 | $ | 1,673 | ||||||||
Utility margin | $ | 142,161 | $ | 136,664 | $ | 5,497 | ||||||||||||
Gas storage operating revenues | 4,541 | 5,369 | (828 | ) |
(1) Regulatory environmental disallowance of $3.3 million in 2016 includes $2.8 million recorded in utility other income (expense), net and $0.5 million recorded in utility operations and maintenance expense. Adjusted consolidated net income and EPS are non-GAAP financial measures based on the after-tax disallowance using the combined federal and state statutory tax rate of 39.5%. EPS is calculated using 28.7 million and 27.6 million diluted shares for three months ended March 31, 2017 and 2016, respectively.
THREE MONTHS ENDED MARCH 31, 2017 COMPARED TO MARCH 31, 2016. Consolidated net income increased $3.7 million during the three months ended March 31, 2017 primarily due to the environmental disallowance associated with a January 2016 OPUC Order in our SRRM docket described in the table above. Excluding the impact of this non-cash charge from the SRRM docket, adjusted consolidated net income increased $1.7 million primarily due to the following factors:
• | a $5.5 million increase in utility margin primarily due to customer growth and the effects of colder than average weather in 2017 compared to a warmer than average winter in the prior period; partially offset by |
• | a $2.0 million increase in operating and maintenance expense largely from payroll and benefits due to increased headcount and higher non-payroll expenses related to system integrity maintenance; and |
• | a $0.8 million decrease in gas storage revenues largely due to lower revenues from our asset management agreements. |
DIVIDENDS
Dividend highlights include:
Three Months Ended March 31, | ||||||||||||
Per common share | 2017 | 2016 | QTR Change | |||||||||
Dividends paid | $ | 0.4700 | $ | 0.4675 | $ | 0.0025 |
The Board of Directors declared a quarterly dividend on our common stock of $0.4700 cents per share, payable on May 15, 2017, to shareholders of record on April 28, 2017, reflecting an indicated annual dividend rate of $1.88 per share.
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RESULTS OF OPERATIONS
Regulatory Matters
Regulation and Rates
UTILITY. Our utility business is subject to regulation by the OPUC, WUTC, and 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. In 2016, approximately 89% of our utility gas customers were located in Oregon, with the remaining 11% in Washington. Earnings and cash flows from utility operations are largely determined by rates set in general rate cases and other proceedings in Oregon and Washington. They 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 "Most Recent General Rate Cases" below.
GAS STORAGE. Our gas storage business is subject to regulation by the OPUC, WUTC, CPUC, and FERC with respect to, among other matters, rates and terms of service. The OPUC and CPUC also regulate the issuance of securities, system of accounts, and regulate intrastate storage services. The FERC regulates interstate storage services. The FERC uses 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 their last regulatory filing. The OPUC Schedule 80 rates are tied to the FERC rates, and are updated whenever we modify our FERC maximum rates. 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 2016, approximately 69% of our storage revenues were derived from FERC, Oregon, and Washington regulated operations and approximately 31% from California operations.
Most Recent General Rate Cases
OREGON. Effective November 1, 2012, the OPUC authorized rates to customers based on an ROE of 9.5%, an overall rate of return of 7.78%, and a capital structure of 50% common equity and 50% long-term debt.
WASHINGTON. Effective January 1, 2009, the WUTC authorized rates to customers based on an ROE of 10.1% and an overall rate of return of 8.4% with a capital structure of 51% common equity, 5% short-term debt, and 44% long-term debt.
FERC. We are required under our Mist interstate storage certificate authority and rate approval orders to file every five years either a petition for rate approval or a cost and revenue study to change or justify maintaining the existing rates for our interstate storage services. In December 2013, we filed a rate petition, which was approved in 2014, and allows for the maximum cost-based rates for our interstate gas storage services. These rates were effective January 1, 2014, with the rate changes having no significant impact on our revenues.
We continuously monitor the utility and evaluate the need for a rate case. Currently, we are contemplating filing an Oregon rate case in late 2017 or in 2018 with a Washington rate case thereafter.
Regulatory Proceeding Updates
During 2017, we were involved in the regulatory activities discussed below.
SYSTEM INTEGRITY PROGRAM (SIP). Upon completion of our bare-steel replacement program, we filed a request to extend the SIP program. The OPUC suspended our filing and ordered additional processes, including involvement of other local distribution companies' (LDCs) in the state, before making a final decision. In 2016, we withdrew our request to extend the SIP program and instead focused our efforts on establishing guidelines for future safety cost trackers with the OPUC. In 2016, an all-party agreement establishing guidelines was filed with the OPUC and on March 6, 2017, the Commission issued an order adopting the agreement. The order allows LDCs to request safety cost recovery mechanisms under the guidelines established by the parties and requires LDCs to file annual safety project plans for OPUC and stakeholder review.
HEDGING. In 2014 the OPUC opened a docket to discuss broader gas hedging practices across gas utilities in Oregon. This docket was divided into two phases. The first phase was focused on an analytical review of hedging and hedging practices. We are currently working through the second phase regarding potential hedging guidelines, and seeking an agreement through discussions with the parties. After the second phase is complete, a status report
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or other filing will be submitted to the OPUC, and the remainder of the process will be determined at that time. Currently, we anticipate resolution of the docket in the second half of 2017.
The WUTC also conducted an investigation into the hedging practices of gas utilities operating in Washington, and considered whether it should require gas utilities to implement certain hedging practices. During 2016, the WUTC received and reviewed comments from all parties and issued a policy statement on March 13, 2017 outlining their expectations. The policy statement supports risk-responsive hedging strategies that are adaptable to variability in the market and requires gas utilities to submit with their 2017 PGA a preliminary hedging plan that outlines the utilities' intended path to incorporate risk-responsive hedging strategies. Beginning with the 2018 PGA, gas utilities must submit an annual comprehensive hedging plan that supports integration of risk responsive strategies into their hedging framework. Beginning with the 2019 PGA filing, utilities must provide a full strategy implementation plan for years 2020 and beyond. We are currently evaluating the WUTC order to determine its impact to our current hedging practices, and plan to submit our preliminary hedging plan with our 2017 PGA, as directed by the WUTC.
INTERSTATE STORAGE AND OPTIMIZATION SHARING. We received an Order from the OPUC in March 2015 on their review of the current revenue sharing arrangement that allocates a portion of the net revenues generated from non-utility Mist storage services and third-party asset management services to utility customers. The Order requires a third-party cost study to be performed and the results of the cost study may initiate a new docket or the re-opening of the original docket. In 2017, all parties agreed and hired a third-party consultant to perform the study and are continuing to facilitate completion of the work directed by the OPUC. We expect completion of this study in the second half of 2017.
CARBON SOLUTIONS PROGRAM. Oregon Senate Bill 844 (SB 844) required the OPUC to develop rules and programs to reduce carbon emissions in Oregon. In June 2015, we submitted our first project related to Combined Heat and Power (CHP) for OPUC approval. The submitted CHP program would pay owners of new commercial- and industrial-scale CHP systems for verified carbon emission reductions. In April 2016, the OPUC issued an order declining our program as submitted and provided guidance on program structure for potential future submissions. We have worked with the stakeholders to reach common ground and are contemplating our next steps for this program.
INTEGRATED RESOURCE PLAN (IRP). We filed our 2016 Oregon and Washington IRPs on August 26, 2016. We received a letter of compliance from the WUTC in December 2016 and acknowledgment by the OPUC in February 2017. The IRP included analysis of different growth scenarios and corresponding resource acquisition strategies. The 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.
GAS INCIDENT INVESTIGATION. On October 19, 2016, there was a natural gas explosion in Portland, Oregon after a third-party contractor damaged a NW Natural service line. The contractor was not working for NW Natural at the time. NW Natural and local authorities responded to the event and evacuated the necessary building prior to the ignition. No fatalities or life-threatening injuries were sustained. On March 30, 2017, the OPUC released its investigation report regarding the incident, finding that NW Natural followed federal emergency response requirements. NW Natural did not receive any fines or penalties as a result of the report or the incident. We continue to focus on safety and enhancements to our incident response and reporting procedures, both of which are operational priorities. We will also continue to partner with other first responders in our community for on-site emergency response coordination.
DEPRECIATION STUDY. Under OPUC regulations, the utility is required to file a depreciation study every five years to update or justify maintaining the existing depreciation rates. In December 2016, we filed the required depreciation study with the Commission and it is currently under review. We do not anticipate the study to materially change our current depreciation rates.
HOLDING COMPANY APPLICATION. In February 2017, we filed applications with the OPUC, WUTC, and CPUC for approval to reorganize under a holding company structure. The filing of regulatory applications is the first of many steps required to form a holding company. We expect that the regulatory process will take six to nine months, and will result in the OPUC, WUTC and CPUC authorizing a holding company structure subject to certain restrictions, or "ring-fencing" provisions applicable to NW Natural, the entity that currently, and would continue to, house our utility operations. We do not expect a material operational or financial impact to our business as a result of the contemplated reorganization. For further discussion of our holding company application, see Part II, Item 7
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"Results of Operations—Regulatory Matters—Regulatory Proceeding Updates" in our 2016 Form 10-K.
Rate Mechanisms
PURCHASED GAS ADJUSTMENT. Rate changes are established for the utility each year under PGA mechanisms in Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases. This includes gas costs under spot purchases as well as contract supplies, gas costs hedged with financial derivatives, gas costs from the withdrawal of storage inventories, the production of gas reserves, interstate pipeline demand costs, temporary rate adjustments, which amortize balances of deferred regulatory accounts, and the removal of temporary rate adjustments effective for the previous year.
Each year, 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 2016-17 gas year (November 1, 2016 - October 31, 2017) hedged at 75% of our forecasted sales volumes, including 48% in financial swap and option contracts and 27% in physical gas supplies. As part of the guidance issued by the WUTC on hedging and our open hedge docket with the OPUC, we are evaluating our hedge strategies for Oregon and Washington.
In addition to the amount hedged for the current gas contract year, we are also hedged in future years at approximately 46% for the 2017-18 gas year and between 4% and 18% for annual requirements over the subsequent five gas years as of March 31, 2017. Our hedge levels are subject to change based on actual load volumes, which depend to a certain extent on weather, economic conditions, and estimated gas reserve production. Also, our gas storage inventory levels may increase or decrease with storage expansion, changes in storage contracts with third parties, variations in the heat content of the gas, and/or storage recall by the utility.
Under the current PGA mechanism in Oregon, there is an incentive sharing provision whereby we are required to select each year 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. For the 2015-16 and 2016-17 gas years, we selected the 80% and 90% deferral option, 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 TEST REVIEW. We are subject to an annual earnings review in Oregon to determine if the utility is earning above its authorized ROE threshold. If utility earnings exceed a specific ROE level, then 33% of the amount above that level is required to be deferred or refunded to customers. Under this provision, if we select the 80% deferral gas cost 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. For the 2015-16 and 2016-17 periods, we selected the 80% and 90% deferral option, respectively. The ROE threshold is subject to adjustment annually based on movements in long-term interest rates. For calendar years 2015 and 2016, the ROE threshold was 10.60%, and 11.06%, respectively. There were no refunds required for 2015. We filed the 2016 earnings test in May 2017 and do not expect a customer refund adjustment for 2016 based on our results.
GAS RESERVES. In 2011, the OPUC approved the Encana gas reserves transaction to provide long-term gas price protection for our utility customers and determined our costs under the agreement would be recovered, on an ongoing basis through our annual PGA mechanism. Gas produced from our interests is sold at then prevailing market prices, and revenues from such sales, net of associated operating and production costs and amortization, are included in our cost of gas. The cost of gas, including a carrying cost for the rate base investment made under the original agreement, is included in our 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.
In March 2014, we amended the original gas reserves agreement in response to Encana's sale of its interest in the Jonah field located in Wyoming to Jonah Energy. Under our amended agreement with Jonah Energy, we have the option 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 did not have the opportunity to participate in additional wells during 2015, 2016, or the three months ended March 31, 2017, but we may have the opportunity in the future.
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DECOUPLING. In Oregon, we have a decoupling mechanism. Decoupling is intended to break the link between utility earnings and the quantity of gas consumed by customers, removing any financial incentive by the utility to discourage customers’ efforts to conserve energy.
The Oregon decoupling mechanism was reauthorized and the baseline expected usage per customer was set in the 2012 Oregon general rate case. This mechanism employs a use-per-customer decoupling calculation, which adjusts margin revenues to account for the difference between actual and expected customer volumes. The margin adjustment resulting from differences between actual and expected volumes under the decoupling component is recorded to a deferral account, which is included in the annual PGA filing. In Washington, customer use is not covered by such a tariff. See "Business Segments—Local Gas Distribution Utility Operations" below.
WARM. In Oregon, we have an approved weather normalization mechanism, which is applied to residential and commercial customer bills. This mechanism is designed to help stabilize the collection of fixed costs by adjusting residential and commercial customer billings based on temperature variances from average weather, with rate decreases when the weather is colder than average and rate increases when the weather is warmer than average. The mechanism is applied to bills from December through May of each heating season. The mechanism adjusts the margin component of customers’ rates to reflect average weather, which uses the 25-year average temperature for each day of the billing period. Daily average temperatures and 25-year average temperatures are based on a set point temperature of 59 degrees Fahrenheit for residential customers and 58 degrees Fahrenheit for commercial customers. The collections of any unbilled WARM amounts are deferred and earn a carrying charge until collected in the PGA the following year. This weather normalization mechanism was reauthorized in the 2012 Oregon general rate case without an expiration date. Residential and commercial customers in Oregon are allowed to opt out of the weather normalization mechanism, and as of March 31, 2017, 9% of total customers had opted out. We do not have a weather normalization mechanism approved for residential and commercial Washington customers, which account for about 11% of total customers. See "Business Segments—Local Gas Distribution Utility Operations" below.
INDUSTRIAL TARIFFS. The OPUC and WUTC have approved tariffs covering utility service to our major industrial customers, including terms, which are intended to give us certainty in the level of gas supplies we need to acquire to serve this customer group. The terms include, among other things, an annual election period, special pricing provisions for out-of-cycle changes, and a requirement that industrial customers complete the term of their service election under our annual PGA tariff.
ENVIRONMENTAL COST DEFERRAL AND SRRM. We have a SRRM through which we track and have the ability to recover past deferred and future prudently incurred environmental remediation costs allocable to Oregon, subject to an earnings test.
Under the SRRM collection process there are three types of deferred environmental remediation expense:
• | Pre-review - This class of costs represents remediation spend that has not yet been deemed prudent by the OPUC. Carrying costs on these remediation expenses are recorded at our authorized cost of capital. We anticipate the prudence review for annual costs and approval of the earnings test prescribed by the OPUC to occur by the third quarter of the following year. |
• | Post-review - This class of costs represents remediation spend that has been deemed prudent and allowed after applying the earnings test, but is not yet included in amortization. We earn a carrying cost on these amounts at a rate equal to the five-year treasury rate plus 100 basis points. |
• | Amortization - This class of costs represents amounts included in current customer rates for collection and is generally calculated as one-fifth of the post-review deferred balance. We earn a carrying cost equal to the amortization rate determined annually by the OPUC, which approximates a short-term borrowing rate. |
In addition, as a result of the 2015 and 2016 Orders, the Order also provides for the annual collection of $5 million from Oregon customers through a tariff rider. As we collect amounts from customers, we recognize these collections as revenue and separately amortize an equal and offsetting amount of our deferred regulatory asset balance through the environmental remediation operating expense line shown separately in the operating expense section of the income statement. See Note 13 in our 2016 Form 10-K.
The SRRM earnings test is an annual review of our adjusted utility ROE compared to our authorized utility ROE, which is currently 9.5%. To apply the earnings test first we must determine what if any costs are subject to the test through the following calculation:
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Annual spend |
Less: $5 million base rate rider(1) |
Prior year carry-over(2) |
$5 million insurance + interest on insurance |
Total deferred annual spend subject to earnings test |
Less: over-earnings adjustment, if any |
Add: deferred interest on annual spend(3) |
Total amount transferred to post-review |
(1) | Base rate rider went into Oregon customer rates beginning November 1, 2015. |
(2) | Prior year carry-over results when the prior year amount transferred to post-review is negative. The negative amount is carried over to offset annual spend in the following year. |
(3) | Deferred interest is added to annual spend to the extent the spend is recoverable. |
To the extent the utility earns at or below its authorized Return on Equity (ROE), remediation expenses and interest in excess of the $5 million tariff rider and $5 million of insurance proceeds are recoverable through the SRRM. To the extent the utility earns more than its authorized ROE in a year, the utility is required to cover environmental expenses and interest on expenses greater than the $10 million with those earnings that exceed its authorized ROE.
For 2016, we have performed this test, which we submitted to the OPUC in May 2017, and we do not expect an earnings test adjustment for 2016 based on our results.
The WUTC has also previously authorized the deferral of environmental costs, if any, that are appropriately allocated to Washington customers. This Order was effective in January 2011 with 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 all or a portion of these regulatory assets no longer met 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 was made.
PENSION COST DEFERRAL AND PENSION BALANCING ACCOUNT. Effective January 1, 2011, the OPUC approved our request to defer annual pension expenses above the amount set in rates, with recovery of these deferred amounts 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 on the account balance at the utility’s authorized rate of return, which is currently 7.78%. Future years’ deferrals will depend on changes in plan assets and projected benefit liabilities based on a number of key assumptions, and our pension contributions. Pension expense deferrals, excluding interest, were $1.5 million and $1.6 million during the three months ended March 31, 2017 and 2016, respectively.
INTERSTATE STORAGE AND OPTIMIZATION SHARING. In 2017, we filed for regulatory approval to refund an interstate storage credit of $11.7 million to our Oregon utility customers. In June of 2016, we received regulatory approval to provide an interstate storage credit of $9.4 million to our Oregon utility customers, which was reflected in their June 2016 bills. The 2017 and 2016 customer credits are part of our regulatory incentive sharing mechanism related to non-utility Mist storage and asset management services. The Washington portion of these credits is included in the Washington PGA.
GAS COST SHARING CUSTOMER CREDITS. In addition, in June of 2016, we credited $19.4 million to customers for their portion of the gas cost sharing incentive for the 2015-16 gas year, resulting from lower projected gas costs, which were driven by warmer weather, lower volume usage, and lower market prices.
For a discussion of other rate mechanisms, see Part II, Item 7, “Results of Operations—Regulatory Matters—Rate Mechanisms in our 2016 Form 10-K.
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,
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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, WARM, 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, but not eliminate, the volatility of customer bills and our utility’s earnings. See "Regulatory Matters—Rate Mechanisms" above.
Utility segment highlights include:
Three Months Ended March 31, | ||||||||||||
Dollars and therms in thousands, except EPS data | 2017 | 2016 | QTR Change | |||||||||
Utility net income | $ | 40,192 | $ | 35,852 | $ | 4,340 | ||||||
EPS - utility segment | 1.40 | 1.30 | 0.10 | |||||||||
Gas sold and delivered (in therms) | 467,639 | 372,549 | 95,090 | |||||||||
Utility margin(1) | $ | 142,161 | $ | 136,664 | $ | 5,497 |
(1) See Utility Margin Table below for a reconciliation and additional detail.
THREE MONTHS ENDED MARCH 31, 2017 COMPARED TO MARCH 31, 2016. The primary factors contributing to the $4.3 million or $0.10 per share increase in utility net income were as follows:
• | a $5.5 million increase in utility margin primarily due to: |
▪ | a $2.4 million increase from customer growth; offset by |
▪ | a $2.7 million decrease in gains from gas cost incentive sharing due to actual gas prices that were comparatively higher than the prior year, but lower than those estimated in the 2016-17 PGA. |
▪ | the majority of the remaining increase was due to the effects of colder than average weather in 2017 compared to a warmer than average winter in the prior period. Weather impacts utility margins from our Washington customers where we do not have a weather normalization mechanism in place, and 9% of our Oregon customers who opted out of weather normalization; |
• | a $3.0 million increase in other income (expense), net, primarily due to the environmental interest disallowance recognized in 2016; partially offset by |
• | a $0.9 million increase in operations and maintenance expense largely from payroll and benefits due to increased headcount over the past twelve months; and |
• | a $0.9 million increase in depreciation expense primarily due to additional capital expenditures. |
Total utility volumes sold and delivered in 2017 increased 26% over 2016 as weather was 37% colder during the first quarter of 2017 compared to the same period last year and 17% colder than average.
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UTILITY MARGIN TABLE. The following table summarizes the composition of utility gas volumes, revenues, and cost of sales:
Three Months Ended March 31, | Favorable/(Unfavorable) | |||||||||||
In thousands, except degree day and customer data | 2017 | 2016 | QTR Change | |||||||||
Utility volumes (therms): | ||||||||||||
Residential and commercial sales | 327,523 | 242,874 | 84,649 | |||||||||
Industrial sales and transportation | 140,116 | 129,675 | 10,441 | |||||||||
Total utility volumes sold and delivered | 467,639 | 372,549 | 95,090 | |||||||||
Utility operating revenues: | ||||||||||||
Residential and commercial sales | $ | 280,277 | $ | 237,672 | $ | 42,605 | ||||||
Industrial sales and transportation | 18,903 | 17,664 | 1,239 | |||||||||
Other revenues | 1,375 | 1,411 | (36 | ) | ||||||||
Less: Revenue taxes | 7,829 | 6,643 | 1,186 | |||||||||
Total utility operating revenues | 292,726 | 250,104 | 42,622 | |||||||||
Less: Cost of gas | 143,611 | 108,411 | (35,200 | ) | ||||||||
Less: Environmental remediation expense | 6,954 | 5,029 | (1,925 | ) | ||||||||
Utility margin | $ | 142,161 | $ | 136,664 | $ | 5,497 | ||||||
Utility margin:(1) | ||||||||||||
Residential and commercial sales | $ | 131,040 | $ | 123,484 | $ | 7,556 | ||||||
Industrial sales and transportation | 8,692 | 8,201 | 491 | |||||||||
Miscellaneous revenues | 1,373 | 1,406 | (33 | ) | ||||||||
Gain from gas cost incentive sharing | 951 | 3,654 | (2,703 | ) | ||||||||
Other margin adjustments | 105 | (81 | ) | 186 | ||||||||
Utility margin | $ | 142,161 | $ | 136,664 | $ | 5,497 | ||||||
Degree days | ||||||||||||
Average(2) | 1,855 | 1,871 | (16 | ) | ||||||||
Actual | 2,169 | 1,585 | 37 | % | ||||||||
Percent colder (warmer) than average weather(2) | 17 | % | (15 | )% | ||||||||