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. Our regulated local gas distribution business, referred to as the utility segment, is our core operating business and serves residential, commercial, and industrial customers in Oregon and southwest Washington. The other category primarily includes the non-utility portion of our Mist gas storage facility that provides storage services for utilities, gas marketers, electric generators, and large industrial users from facilities located in Oregon. In addition, we have investments and other non-utility activities reported 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:
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•
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NW Natural Energy, LLC (NWN Energy);
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◦
|
NW Natural Gas Storage, LLC (NWN Gas Storage);
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▪
|
Gill Ranch Storage, LLC (Gill Ranch), which is presented as a discontinued operation;
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•
|
Northwest Energy Corporation (Energy Corp);
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◦
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NWN Gas Reserves LLC (NWN Gas Reserves);
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•
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NNG Financial Corporation (NNG Financial);
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•
|
NW Natural Water Company, LLC (NWN Water);
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◦
|
Cascadia Water, LLC (Cascadia);
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•
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Northwest Natural Holding Company (NWN Holding); and
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◦
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NWN Merger Sub, Inc. (NWN Holdco Sub).
|
Investments in corporate joint ventures and partnerships we do not directly or indirectly control, and for which we are not the primary beneficiary, include NWN Energy's investment in Trail West Holdings, LLC (TWH), which is accounted for under the equity method, and NNG Financial's investment in Kelso-Beaver 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 the non-utility portion of our Mist gas storage facility 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 a 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
2017
Annual Report on Form 10-K (
2017
Form 10-K), taking into consideration the changes mentioned below in this Note 1 and in Notes 4 and 15. 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.
During the second quarter of 2018, we moved forward with our long-term strategic plans, which include a shift away from our merchant gas storage business. In June 2018, NWN Gas Storage, our wholly-owned subsidiary, entered into a Purchase and Sale Agreement that provides for the sale of all of the membership interests in its wholly-owned subsidiary, Gill Ranch, subject to various regulatory approvals and closing conditions. We have concluded that the pending sale of Gill Ranch qualifies as assets and liabilities held for sale and discontinued operations. As such, for all periods presented, the results of Gill Ranch have been presented as a discontinued operation on the consolidated statements of comprehensive income and cash flows, and the assets and liabilities associated with Gill Ranch have been classified as discontinued operations assets and liabilities on the consolidated balance sheets. See
Note 15
for additional information. Additionally, we reevaluated our reportable segments and concluded that the remaining gas storage activities no longer meet the requirements to be separately reported as a segment. The non-utility portion of our Mist gas storage facility is now reported as other, and all prior periods reflect this change. See Note 4, which provides segment information. These reclassifications had no effect on our prior year's consolidated results of operations, financial condition, or cash flows.
Our notes to the consolidated financial statements reflect the activity of our continuing operations for all periods presented, unless otherwise noted.
Note 15
provides information regarding our discontinued operations.
2. SIGNIFICANT ACCOUNTING POLICIES
Our significant accounting policies are described in
Note 2
of the
2017
Form 10-K. There were no material changes to those accounting policies during the
six months ended June 30, 2018
other than those incorporated in
Note 5
and
Note 15
relating to revenue and discontinued operations, respectively. 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 Oregon Public Utilities Commission (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.
Amounts deferred as regulatory assets and liabilities were as follows:
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Regulatory Assets
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|
June 30,
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|
December 31,
|
In thousands
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|
2018
|
|
2017
|
|
2017
|
Current:
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|
|
|
|
|
Unrealized loss on derivatives
(1)
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|
$
|
11,744
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|
|
$
|
4,625
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|
$
|
18,712
|
|
Gas costs
|
|
273
|
|
|
859
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|
|
154
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|
Environmental costs
(2)
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|
5,594
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|
6,724
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|
|
6,198
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|
Decoupling
(3)
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|
10,232
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|
|
12,136
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|
|
11,227
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|
Income taxes
|
|
2,217
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|
|
4,378
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|
|
2,218
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|
Other
(4)
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|
11,032
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|
|
8,782
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|
|
7,272
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|
Total current
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|
$
|
41,092
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|
|
$
|
37,504
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|
|
$
|
45,781
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|
Non-current:
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|
|
|
|
|
|
Unrealized loss on derivatives
(1)
|
|
$
|
3,913
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|
|
$
|
3,466
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|
|
$
|
4,649
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|
Pension balancing
(5)
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|
67,527
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|
55,358
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|
60,383
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|
Income taxes
|
|
19,267
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|
36,591
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|
|
19,991
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|
Pension and other postretirement benefit liabilities
|
|
171,186
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|
176,136
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|
179,824
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|
Environmental costs
(2)
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|
65,156
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|
|
64,008
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|
|
72,128
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|
Gas costs
|
|
28
|
|
|
87
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|
|
84
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|
Decoupling
(3)
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|
1,636
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|
|
1,993
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|
|
3,970
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Other
(4)
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10,464
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|
|
10,645
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|
15,579
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|
Total non-current
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$
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339,177
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$
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348,284
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$
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356,608
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Regulatory Liabilities
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|
June 30,
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|
December 31,
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In thousands
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|
2018
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|
2017
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|
2017
|
Current:
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|
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|
Gas costs
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|
$
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20,906
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|
|
$
|
15,708
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|
|
$
|
14,886
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|
Unrealized gain on derivatives
(1)
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|
1,938
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|
|
1,459
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|
|
1,674
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Decoupling
(3)
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|
2,153
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|
134
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|
322
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|
Other
(4)
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|
9,278
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|
|
10,740
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|
17,131
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|
Total current
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|
$
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34,275
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|
|
$
|
28,041
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|
|
$
|
34,013
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Non-current:
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Gas costs
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$
|
3,460
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|
|
$
|
2,719
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|
|
$
|
4,630
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|
Unrealized gain on derivatives
(1)
|
|
1,077
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|
162
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|
1,306
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|
Decoupling
(3)
|
|
410
|
|
|
—
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|
957
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|
Income taxes
(6)
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|
222,734
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|
|
—
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|
213,306
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|
Accrued asset removal costs
(7)
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|
370,245
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|
350,828
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|
|
360,929
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|
Other
(4)
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|
4,368
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|
|
5,496
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|
|
4,965
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|
Total non-current
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|
$
|
602,294
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|
|
$
|
359,205
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|
|
$
|
586,093
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(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.
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(2)
|
Refer to footnote (3) per the Deferred Regulatory Asset table in
Note 14
for a description of environmental costs.
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(3)
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This deferral represents the margin adjustment resulting from differences between actual and expected volumes.
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(4)
|
Balances consist of deferrals and amortizations under approved regulatory mechanisms and typically earn a rate of return or carrying charge.
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(5)
|
Refer to footnote (1) of the Net Periodic Benefit Cost table in
Note 8
for information regarding the deferral of pension expenses.
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(6)
|
This balance represents estimated amounts associated with the Tax Cuts and Jobs Act. See
Note 9
.
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(7)
|
Estimated costs of removal on certain regulated properties are collected through rates.
|
We believe all costs incurred and deferred at
June 30, 2018
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). ASUs 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
STOCK COMPENSATION.
On May 10, 2017, the FASB issued ASU 2017-09, "Stock Compensation - Scope of Modification Accounting." The purpose of the amendment is to provide clarity, reduce diversity in practice, and reduce the cost and complexity when applying the guidance in Topic 718, related to a change to the terms or conditions of a share-based payment award. Specifically, an entity would not apply modification accounting if the fair value, vesting conditions, and classification of the awards are the same immediately before and after the modification. The amendments in this update were effective for us beginning January 1, 2018, and will be applied prospectively to any award modified on or after the adoption date. The adoption did not have a material impact to our financial statements or disclosures.
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. Additionally, the other components of net periodic benefit costs are to be presented elsewhere in the income statement and outside of income from operations, if that subtotal is presented. Only the service cost component of the net periodic benefit cost is eligible for capitalization. The amendments in this update were effective for us beginning January 1, 2018.
Upon adoption, the ASU required that changes to the income statement presentation of net periodic benefit cost be applied retrospectively, while changes to amounts capitalized must be applied prospectively. As such, the interest cost, expected return on assets, amortization of prior service costs, and other costs have been reclassified from operations and maintenance expense to other income (expense), net on our consolidated statement of comprehensive income for the three and six months ended
June 30, 2017
. We did not elect the practical expedient which would have allowed us to reclassify amounts disclosed previously in the pension and other postretirement benefits footnote disclosure as the basis for applying retrospective presentation. As mentioned above, on a prospective basis, the other components of net periodic benefit cost will not be eligible for capitalization, however, they will continue to be included in our pension regulatory balancing mechanism.
The retrospective presentation requirement related to the other components of net periodic benefit cost affected the operations and maintenance expense and other income (expense), net lines on our consolidated statement of comprehensive income. For the three months and six months ended
June 30, 2017
,
$1.3 million
and
$2.6 million
of expense was reclassified from operations and maintenance expense and included in other income (expense), net, respectively.
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. The amendments in this standard were effective for us beginning January 1, 2018, and the adoption did not have a material impact to our financial statements or disclosures as our historical practices and presentation were consistent with the directives of this ASU.
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 was effective for us beginning January 1, 2018, and the adoption did not have a material impact to our financial statements or disclosures.
REVENUE RECOGNITION.
On May 28, 2014, the FASB issued ASU 2014-09 "Revenue From Contracts with Customers." The underlying principle of the guidance requires entities to recognize revenue depicting the transfer of goods or services to customers at amounts 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 accounting standard and all related amendments were effective for us beginning January 1, 2018. We applied the accounting standard to all contracts using the modified retrospective method. The new standard is primarily reflected in our consolidated statement of comprehensive income and
Note 5
. The implementation of the new revenue standard did not result in
changes to how we currently recognize revenue, and therefore, we did not have a cumulative effect or adjustment to the opening balance of retained earnings. The implementation did result in changes to our disclosures and presentation of revenue and expenses. The comparative information for prior years has not been restated. There is no material impact to our financial results and no significant changes to our control environment due to the adoption of the new revenue standard on an ongoing basis.
As previously discussed, the adoption of the new revenue standard did not impact our consolidated balance sheet or statement of cash flows but did result in changes to the presentation of our consolidated statements of comprehensive income. Had the adoption of the new revenue standard not occurred, our operating revenues for the
three and six months ended June 30, 2018
would have been
$119.8 million
and
$371.0 million
, compared to the reported amounts of
$124.6 million
and
$388.2 million
under the new revenue standard, respectively. Similarly, absent the impact of the new revenue standard, our operating expenses would have been
$111.5 million
and
$295.0 million
, compared to the reported amounts of
$116.3 million
and
$312.2 million
under the new revenue standard for the
three and six months ended June 30, 2018
, respectively. The effect of the change was an increase in both operating revenues and operating expenses of
$4.8 million
and
$17.2 million
for the
three and six months ended June 30, 2018
, respectively, due to the change in presentation of revenue taxes. As part of the adoption of the new revenue standard, we evaluated the presentation of revenue taxes under the new guidance and across our peer group and concluded that the gross presentation of revenue taxes provides the greatest level of consistency and transparency. Prior to the adoption of the new revenue standard, a portion of revenue taxes was presented net in operating revenues and a portion was recorded directly on the balance sheet. During the
three and six months ended June 30, 2018
, we recognized
$4.8 million
and
$17.2 million
in revenue taxes in operating revenues and operating expenses, respectively. In comparison, for the three and six months ended June 30, 2017, we recognized
$5.6 million
and
$19.3 million
in revenue taxes, of which
$3.2 million
and
$11.0 million
were recorded in operating revenues and
$2.4 million
and
$8.3 million
were recorded on the balance sheet, respectively. The change in presentation of revenue taxes had no impact on utility margin, net income or earnings per share.
Recently Issued Accounting Pronouncements
ACCUMULATED OTHER COMPREHENSIVE INCOME.
On February 14, 2018, the FASB issued ASU 2018-02, "Income Statement—Reporting Comprehensive Income: Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income." This update was issued in response to concerns from certain stakeholders regarding the current requirements under U.S. GAAP that deferred tax assets and liabilities are adjusted for a change in tax laws or rates, and the effect is to be included in income from continuing operations in the period of the enactment date. This requirement is also applicable to items in accumulated other comprehensive income where the related tax effects were originally recognized in other comprehensive income. The adjustment of deferred taxes due to the new corporate income tax rate enacted through the Tax Cuts and Jobs Act (TCJA) on December 22, 2017 recognized in income from continuing operations causes the tax effects of items within accumulated other comprehensive income (referred to as stranded tax effects) to not reflect the appropriate tax rate. The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA and require certain disclosures about stranded tax effects. The amendments in this update are effective for us beginning January 1, 2019, and should be applied either in the period of adoption or retrospectively to each period in which the effect of the change in the federal corporate income tax rate in the TCJA is recognized. The reclassification allowed in this update is elective, and we are currently assessing whether we will make the reclassification. This update is not expected to have a material impact on our financial condition.
DERIVATIVES AND HEDGING.
On August 28, 2017, the FASB issued ASU 2017-12, "Derivatives and Hedging: Targeted Improvements to Accounting for Hedging Activities." The purpose of the amendment is to more closely align hedge accounting with companies’ risk management strategies. The ASU amends the accounting for risk component hedging, the hedged item in fair value hedges of interest rate risk, and amounts excluded from the assessment of hedge effectiveness. The guidance also amends the recognition and presentation of the effect of hedging instruments and includes other simplifications of hedge accounting. The amendments in this update are effective for us beginning January 1, 2019. Early adoption is permitted. The amended presentation and disclosure guidance is required prospectively. We are currently assessing the effect of this standard on 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. On November 29, 2017, the FASB proposed an additional practical expedient that would allow entities to apply the transition requirements on the effective date of the standard. Additionally, on January 25, 2018, the FASB issued ASU 2018-01, "Land Easement Practical Expedient for Transition to Topic 842", to address the costs and complexity of applying the transition provisions of the new lease standard to land easements. This ASU provides an optional practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under the current lease guidance. The standard and associated ASUs are effective for us beginning January 1, 2019. We are currently assessing our lease population and material contracts to determine the effect of this standard on our financial statements and disclosures. Refer to
Note 14
of the
2017
Form 10-K for our current lease commitments.
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 using 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 (loss) from continuing operations per share are calculated as follows:
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
In thousands, except per share data
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Net income (loss) from continuing operations
|
|
$
|
(339
|
)
|
|
$
|
4,075
|
|
|
$
|
41,672
|
|
|
$
|
45,472
|
|
Average common shares outstanding - basic
|
|
28,791
|
|
|
28,648
|
|
|
28,772
|
|
|
28,641
|
|
Additional shares for stock-based compensation plans (See Note 6)
|
|
—
|
|
|
69
|
|
|
53
|
|
|
81
|
|
Average common shares outstanding - diluted
|
|
28,791
|
|
|
28,717
|
|
|
28,825
|
|
|
28,722
|
|
Earnings (loss) from continuing operations per share of common stock - basic
|
|
$
|
(0.01
|
)
|
|
$
|
0.14
|
|
|
$
|
1.45
|
|
|
$
|
1.58
|
|
Earnings (loss) from continuing operations per share of common stock - diluted
|
|
$
|
(0.01
|
)
|
|
$
|
0.14
|
|
|
$
|
1.45
|
|
|
$
|
1.58
|
|
Additional information:
|
|
|
|
|
|
|
|
|
Antidilutive shares
|
|
53
|
|
|
32
|
|
|
10
|
|
|
21
|
|
4. SEGMENT INFORMATION
We primarily operate in one reportable business segment, which is our local gas distribution business and which is referred to as the utility segment. During the second quarter of 2018, we moved forward with our long-term strategic plans, which include a shift away from our merchant gas storage business, by entering into a Purchase and Sale Agreement that provides for the sale of all of the membership interests in Gill Ranch, subject to various regulatory approvals and closing conditions. As such, we reevaluated our reportable segments and concluded that the gas storage activities no longer meet the requirements of a reportable segment. Our ongoing, non-utility gas storage activities, which include our interstate storage and optimization activities at our Mist gas storage facility, are now reported as other. We also have other investments and business activities not specifically related to our utility segment, which are aggregated and reported as other. We refer to our local gas distribution business as the utility and all other activities as non-utility.
Local Gas Distribution
Our local gas distribution segment is a regulated utility principally engaged in the purchase, sale, and delivery of natural gas and related services to customers in Oregon and southwest Washington. As a regulated utility, we are responsible for building and maintaining a safe and reliable pipeline distribution system, purchasing sufficient gas supplies from producers and marketers, contracting for firm and interruptible transportation of gas over interstate pipelines to bring gas from the supply basins into our service territory, and re-selling the gas to customers subject to rates, terms, and conditions approved by the OPUC or WUTC.
Gas distribution also includes taking customer-owned gas and transporting it from interstate pipeline connections, or city gates, to the customers’ end-use facilities for a fee, which is approved by the OPUC or WUTC. As of December 31, 2017, approximately 89% of our customers are located in Oregon and 11% in Washington. On an annual basis, residential and commercial customers typically account for around 60% of our utility’s total volumes delivered and 90% of our utility’s margin. Industrial customers largely account for the remaining volumes and utility margin. A small amount of utility margin is also derived from miscellaneous services, gains or losses from an incentive gas cost sharing mechanism, and other service fees.
Industrial sectors we serve include: pulp, paper, and other forest products; the manufacture of electronic, electrochemical and electrometallurgical products; the processing of farm and food products; the production of various mineral products; metal fabrication and casting; the production of machine tools, machinery, and textiles; the manufacture of asphalt, concrete, and rubber; printing and publishing; nurseries; government and educational institutions; and electric generation.
In addition to our local gas distribution business, our utility segment also includes the utility portion of our Mist underground storage facility, our North Mist gas storage expansion in Oregon, and NWN Gas Reserves, which is a wholly-owned subsidiary of Energy Corp.
Other
We have non-utility investments and other business activities, which are aggregated and reported as other. Other includes NWN Gas Storage, a wholly-owned subsidiary of NWN Energy, and the non-utility portion of our Mist facility in Oregon and third-party
asset management services. Earnings from non-utility assets at our Mist facility are primarily related to firm storage capacity revenues. Earnings from the Mist facility also include revenue, net of amounts shared with utility customers, from management of utility assets at Mist and upstream pipeline capacity when not needed to serve utility customers. Under the Oregon sharing mechanism, we retain 80% of the pre-tax income from these services when the costs of the capacity have not been included in utility rates, or 33% of the pre-tax income when the costs have been included in utility rates. The remaining 20% and 67%, respectively, are recorded to a deferred regulatory account for crediting back to utility customers.
Other also includes NNG Financial, non-utility appliance retail center operations, NWN Water, which is pursuing investments in the water sector itself and through its wholly-owned subsidiaries FWC Merger Sub, Inc. and Cascadia, NWN Energy's equity investment in TWH, which is pursuing development of a cross-Cascades transmission pipeline project and NWN Holding, which is pursuing the holding company reorganization of NW Natural through its wholly-owned subsidiary NWN Holdco Sub.
All prior period amounts have been retrospectively adjusted to reflect the change in our reportable segments and the designation of Gill Ranch as a discontinued operation.
Inter-segment transactions were immaterial for the periods presented. The following table presents summary financial information concerning the reportable segments of our continuing operations. See
Note 15
for information regarding our discontinued operation, Gill Ranch Storage.
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|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
In thousands
|
|
Utility
|
|
Other
|
|
Total
|
2018
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
118,515
|
|
|
$
|
6,052
|
|
|
$
|
124,567
|
|
Depreciation and amortization
|
|
20,766
|
|
|
381
|
|
|
21,147
|
|
Income from operations
|
|
4,545
|
|
|
3,724
|
|
|
8,269
|
|
Net income (loss) from continuing operations
|
|
(2,970
|
)
|
|
2,631
|
|
|
(339
|
)
|
Capital expenditures
|
|
43,801
|
|
|
1,239
|
|
|
45,040
|
|
2017
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
130,095
|
|
|
$
|
4,381
|
|
|
$
|
134,476
|
|
Depreciation and amortization
|
|
19,894
|
|
|
330
|
|
|
20,224
|
|
Income from operations
|
|
13,158
|
|
|
3,277
|
|
|
16,435
|
|
Net income from continuing operations
|
|
2,137
|
|
|
1,938
|
|
|
4,075
|
|
Capital expenditures
|
|
54,265
|
|
|
1,142
|
|
|
55,407
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
In thousands
|
|
Utility
|
|
Other
|
|
Total
|
2018
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
376,448
|
|
|
$
|
11,754
|
|
|
$
|
388,202
|
|
Depreciation and amortization
|
|
41,309
|
|
|
713
|
|
|
42,022
|
|
Income from operations
|
|
69,301
|
|
|
6,719
|
|
|
76,020
|
|
Net income from continuing operations
|
|
36,913
|
|
|
4,759
|
|
|
41,672
|
|
Capital expenditures
|
|
100,695
|
|
|
1,675
|
|
|
102,370
|
|
Total assets at June 30, 2018
(1)
|
|
2,907,724
|
|
|
66,293
|
|
|
2,974,017
|
|
2017
|
|
|
|
|
|
|
|
Operating revenues
|
|
$
|
422,821
|
|
|
$
|
7,379
|
|
|
$
|
430,200
|
|
Depreciation and amortization
|
|
39,518
|
|
|
659
|
|
|
40,177
|
|
Income from operations
|
|
90,285
|
|
|
5,231
|
|
|
95,516
|
|
Net income from continuing operations
|
|
42,329
|
|
|
3,143
|
|
|
45,472
|
|
Capital expenditures
|
|
93,119
|
|
|
1,214
|
|
|
94,333
|
|
Total assets at June 30, 2017
(1)
|
|
2,792,011
|
|
|
66,139
|
|
|
2,858,150
|
|
Total assets at December 31, 2017
(1)
|
|
2,961,326
|
|
|
64,546
|
|
|
3,025,872
|
|
|
|
(1)
|
Total assets exclude assets related to discontinued operations of
$12.7 million
,
$207.0 million
, and
$13.9 million
as of
June 30, 2018
,
June 30, 2017
, and
December 31, 2017
, respectively.
|
Utility Margin
Utility margin is a financial measure used by our chief operating decision maker (CODM) consisting of utility operating revenues, reduced by the associated cost of gas, environmental recovery revenues, and revenue taxes. 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. Revenue taxes are collected from our utility customers and remitted to our taxing authorities. The collections from customers are offset by the expense recognition of the obligation to the taxing authority. By subtracting cost of gas, environmental remediation expense, and revenue taxes from utility operating revenues, utility margin provides a key metric used by our CODM in assessing the performance of the utility segment.
The following table presents additional segment information concerning utility margin:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
In thousands
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Utility margin calculation:
|
|
|
|
|
|
|
|
|
Utility operating revenues
|
|
$
|
118,515
|
|
|
$
|
130,095
|
|
|
$
|
376,448
|
|
|
$
|
422,821
|
|
Less: Utility cost of gas
|
|
42,107
|
|
|
53,005
|
|
|
150,271
|
|
|
196,616
|
|
Environmental remediation expense
|
|
1,882
|
|
|
2,611
|
|
|
6,506
|
|
|
9,565
|
|
Revenue taxes
(1)
|
|
4,780
|
|
|
—
|
|
|
17,209
|
|
|
—
|
|
Utility margin
|
|
$
|
69,746
|
|
|
$
|
74,479
|
|
|
$
|
202,462
|
|
|
$
|
216,640
|
|
|
|
(1)
|
The change in presentation of revenue taxes was a result of the adoption of ASU 2014-09 "Revenue From Contracts with Customers" and all related amendments on January 1, 2018. This change had no impact on utility margin results as revenue taxes were previously presented net in utility operating revenue. For additional information, see
Note 2
.
|
5. REVENUE
The following table presents our disaggregated revenue from continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended June 30, 2018
|
In thousands
|
|
Utility
|
|
Other
|
|
Total
|
Local gas distribution revenue
|
|
$
|
114,725
|
|
|
$
|
—
|
|
|
$
|
114,725
|
|
Gas storage revenue, net
|
|
—
|
|
|
2,736
|
|
|
2,736
|
|
Asset management revenue, net
|
|
—
|
|
|
2,140
|
|
|
2,140
|
|
Appliance retail center revenue
|
|
—
|
|
|
1,176
|
|
|
1,176
|
|
Revenue from contracts with customers
|
|
114,725
|
|
|
6,052
|
|
|
120,777
|
|
|
|
|
|
|
|
|
Alternative revenue
|
|
3,663
|
|
|
—
|
|
|
3,663
|
|
Leasing revenue
|
|
127
|
|
|
—
|
|
|
127
|
|
Total operating revenues
|
|
$
|
118,515
|
|
|
$
|
6,052
|
|
|
$
|
124,567
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six months ended June 30, 2018
|
In thousands
|
|
Utility
|
|
Other
|
|
Total
|
Local gas distribution revenue
|
|
$
|
372,954
|
|
|
$
|
—
|
|
|
$
|
372,954
|
|
Gas storage revenue, net
|
|
—
|
|
|
5,314
|
|
|
5,314
|
|
Asset management revenue, net
|
|
—
|
|
|
3,719
|
|
|
3,719
|
|
Appliance retail center revenue
|
|
—
|
|
|
2,721
|
|
|
2,721
|
|
Revenue from contracts with customers
|
|
372,954
|
|
|
11,754
|
|
|
384,708
|
|
|
|
|
|
|
|
|
Alternative revenue
|
|
3,291
|
|
|
—
|
|
|
3,291
|
|
Leasing revenue
|
|
203
|
|
|
—
|
|
|
203
|
|
Total operating revenues
|
|
$
|
376,448
|
|
|
$
|
11,754
|
|
|
$
|
388,202
|
|
Revenue is recognized when our obligation to our customer is satisfied and in the amount we expect to receive in exchange for transferring goods or providing services. Our revenue from contracts with customers contain one performance obligation that is generally satisfied over time, using the output method based on time elapsed, due to the continuous nature of the service provided. The transaction price is determined per a set price agreed upon in the contract or dependent on regulatory tariffs.
Customer accounts are settled on a monthly basis or paid at time of sale and based on historical experience. It is probable that we will collect substantially all of the consideration to which we are entitled to receive.
We do not have any material contract assets as our net accounts receivable and accrued unbilled revenue balances are unconditional and only involve the passage of time until such balances are billed and collected. We do not have any material contract liabilities.
Revenue-based taxes are primarily franchise taxes, which are collected from utility customers and remitted to taxing authorities. Beginning January 1, 2018, revenue taxes are included in operating revenues with an equal and offsetting expense recognized in operating expenses in the consolidated statement of comprehensive income.
Utility Segment
Local gas distribution revenue.
Our primary source of revenue is providing natural gas to the customers in our service territory, which include residential, commercial, industrial and transportation customers. Gas distribution revenue is generally recognized over time upon delivery of the gas commodity or service to the customer, and the amount of consideration we receive and recognize as revenue is dependent on the Oregon and Washington tariffs. Customer accounts are to be paid in full each month, and there is no right of return or warranty for services provided. Revenues include firm and interruptible sales and transportation services, franchise taxes recovered from the customer, late payment fees, service fees, and accruals for gas delivered but not yet billed (accrued unbilled revenue). Our accrued unbilled revenue balance is based on estimates of deliveries during the period from the last meter reading and management judgment is required for a number of factors used in this calculation, including customer use and weather factors.
We applied the significant financing practical expedient and we have not adjusted the consideration we expect to receive from our utility customers for the effects of a significant financing component as all payment arrangements are settled annually. Due to the election of the right to invoice practical expedient, we do not disclose the value of unsatisfied performance obligations as of
June 30, 2018
.
Alternative revenue.
Our weather normalization mechanism (WARM) and decoupling mechanism are considered to be alternative revenue programs. Alternative revenue programs are considered to be contracts between us and our regulator and are excluded from revenue from contracts with customers.
Leasing revenue.
Leasing revenue primarily consists of rental revenue for small leases of our utility-owned property to third parties. The transactions are accounted for as operating leases and the revenue is recognized on a straight-line basis over the term of the lease agreement. Lease revenue is excluded from revenue from contracts with customers.
Other
Gas storage revenue.
Our gas storage activity includes the non-utility portion of our Mist facility, which is used to store natural gas for customers. Gas storage revenue is generally recognized over time as the gas storage service is provided to the customer and the amount of consideration we receive and recognize as revenue is dependent on set rates defined per the storage agreements. Noncash consideration in the form of dekatherms of natural gas is received as consideration for providing gas injection services to our gas storage customers. This noncash consideration is measured at fair value using the average spot rate. Customer accounts are generally paid in full each month, and there is no right of return or warranty for services provided. Revenues include firm and interruptible storage services, net of the profit sharing amount refunded to our utility customers.
Asset management revenue.
Asset management revenue is generally recognized over time using a straight-line approach over the term of each contract, and the amount of consideration we receive and recognize as revenue is dependent on a variable pricing model. Variable revenues earned above guaranteed amounts are estimated and recognized at the end of each period using the most likely amount approach. Revenues include the optimization of the storage assets and pipeline capacity provided, net of the profit sharing amount refunded to our utility customers. Asset management accounts are settled on a monthly basis.
As of
June 30, 2018
, unrecognized revenue for the fixed component of the transaction price related to our gas storage and asset management revenue was approximately
$43.4 million
. Of this amount, approximately
$8.1 million
will be recognized during the remainder of
2018
,
$10.2 million
in
2019
,
$8.5 million
in
2020
,
$7.5 million
in
2021
,
$4.3 million
in
2022
and
$4.8 million
thereafter.
Appliance retail center revenue.
We own and operate an appliance store that is open to the public, where customers can purchase natural gas home appliances. Revenue from the sale of appliances is recognized at the point in time in which the appliance is transferred to the third party responsible for delivery and installation services and when the customer has legal title to the appliance. It is required that the sale be paid for in full prior to transfer of legal title. The amount of consideration we receive and recognize as revenue varies with changes in marketing incentives and discounts that we offer to our customers.
6. 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
2017
Form 10-K and the updates provided below.
Long Term Incentive Plan
Performance Shares
LTIP performance shares incorporate a combination of market, performance, and service-based factors. During the
six months ended June 30, 2018
,
no
performance-based shares were granted under the LTIP for accounting purposes. In February 2018, the 2018 LTIP was awarded to participants; however, the agreement allows for one of the performance factors to remain variable until the first quarter of the third year of the award period. As the performance factor will not be approved until the first quarter of 2020, there is not a mutual understanding of the award’s key terms and conditions between the Company and the participants as of
June 30, 2018
and therefore no expense was recognized for the 2018 award. We will calculate the grant date fair value and recognize expense once the final performance factor has been approved.
For the 2018 LTIP, award share payouts range from a threshold of
0%
to a maximum of
200%
based on achievement of pre-established goals. The performance criteria for the 2018 performance shares consists of
a three-year Return on Invested Capital (ROIC) threshold that must be satisfied and a cumulative EPS factor, which can be modified by a total shareholder return factor (TSR modifier) relative to the performance of the Russell 2500 Utilities Index
over the
three
-year performance period. If the target was achieved for the 2018 award, we would grant
34,702
shares in the first quarter of 2020.
As of
June 30, 2018
, there was
$2.1 million
of unrecognized compensation cost associated with the 2016 and 2017 LTIP grants, which is expected to be recognized through
2019
.
Restricted Stock Units
During the
six months ended June 30, 2018
,
26,087
RSUs were granted under the LTIP with a weighted-average grant date fair value of
$55.16
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. Generally, an 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 an RSU is equal to the closing market price of our common stock on the grant date. As of
June 30, 2018
, there was $
3.3 million
of unrecognized compensation cost from grants of RSUs, which is expected to be recognized over a period extending through
2022
.
7. DEBT
Short-Term Debt
At
June 30, 2018
, we had short-term debt of
$47.1 million
, which was comprised entirely of commercial paper. The carrying cost of our commercial paper approximates fair value using Level 2 inputs. See
Note 2
in the
2017
Form 10-K for a description of the fair value hierarchy. At
June 30, 2018
, our commercial paper had a maximum remaining maturity of
12
days and average remaining maturity of
7
days.
Long-Term Debt
At
June 30, 2018
, we had long-term debt of
$758.7 million
, which included
$6.0 million
of unamortized debt issuance costs. Utility long-term debt consists of first mortgage bonds (FMBs) with maturity dates ranging from
2018
through
2047
, interest rates ranging from
1.545%
to
9.05%
, and a weighted average coupon rate of
4.728%
. In
March
2018
, we retired
$22.0 million
of FMBs with a coupon rate of
6.60%
.
Fair Value of Long-Term Debt
Our outstanding debt does not trade in active markets. We estimate the fair value of our long-term debt using utility companies with similar credit ratings, terms, and remaining maturities to our long-term 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
2017
Form 10-K for a description of the fair value hierarchy.
The following table provides an estimate of the fair value of our long-term debt, including current maturities of long-term debt, using market prices in effect on the valuation date:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
December 31,
|
In thousands
|
|
2018
|
|
2017
|
|
2017
|
Gross long-term debt
|
|
$
|
764,700
|
|
|
$
|
726,700
|
|
|
$
|
786,700
|
|
Unamortized debt issuance costs
|
|
(6,020
|
)
|
|
(6,591
|
)
|
|
(6,813
|
)
|
Carrying amount
|
|
$
|
758,680
|
|
|
$
|
720,109
|
|
|
$
|
779,887
|
|
Estimated fair value
(1)
|
|
$
|
792,623
|
|
|
$
|
791,885
|
|
|
$
|
853,339
|
|
(1)
Estimated fair value does not include unamortized debt issuance costs.
8. PENSION AND OTHER POSTRETIREMENT BENEFIT COSTS
We recognize the service cost component of net periodic benefit cost for our pension and other postretirement benefit plans in operations and maintenance expense in our consolidated statements of comprehensive income. The other non-service cost components are recognized in other income (expense), net in our consolidated statements of comprehensive income. The following table provides the components of net periodic benefit cost for our pension and other postretirement benefit plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
Pension Benefits
|
|
Other Postretirement
Benefits
|
|
Pension Benefits
|
|
Other Postretirement
Benefits
|
In thousands
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Service cost
|
|
$
|
1,807
|
|
|
$
|
1,870
|
|
|
$
|
79
|
|
|
$
|
99
|
|
|
$
|
3,614
|
|
|
$
|
3,740
|
|
|
$
|
159
|
|
|
$
|
197
|
|
Interest cost
|
|
4,183
|
|
|
4,472
|
|
|
241
|
|
|
274
|
|
|
8,366
|
|
|
8,944
|
|
|
482
|
|
|
548
|
|
Expected return on plan assets
|
|
(5,150
|
)
|
|
(5,112
|
)
|
|
—
|
|
|
—
|
|
|
(10,301
|
)
|
|
(10,225
|
)
|
|
—
|
|
|
—
|
|
Amortization of prior service costs
|
|
10
|
|
|
31
|
|
|
(117
|
)
|
|
(117
|
)
|
|
21
|
|
|
63
|
|
|
(234
|
)
|
|
(234
|
)
|
Amortization of net actuarial loss
|
|
4,524
|
|
|
3,622
|
|
|
112
|
|
|
139
|
|
|
9,047
|
|
|
7,243
|
|
|
222
|
|
|
277
|
|
Net periodic benefit cost
|
|
5,374
|
|
|
4,883
|
|
|
315
|
|
|
395
|
|
|
10,747
|
|
|
9,765
|
|
|
629
|
|
|
788
|
|
Amount allocated to construction
|
|
(685
|
)
|
|
(1,558
|
)
|
|
(28
|
)
|
|
(135
|
)
|
|
(1,367
|
)
|
|
(3,079
|
)
|
|
(55
|
)
|
|
(267
|
)
|
Amount deferred to regulatory balancing account
(1)
|
|
(2,747
|
)
|
|
(1,508
|
)
|
|
—
|
|
|
—
|
|
|
(5,503
|
)
|
|
(3,035
|
)
|
|
—
|
|
|
—
|
|
Net amount charged to expense
|
|
$
|
1,942
|
|
|
$
|
1,817
|
|
|
$
|
287
|
|
|
$
|
260
|
|
|
$
|
3,877
|
|
|
$
|
3,651
|
|
|
$
|
574
|
|
|
$
|
521
|
|
|
|
(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
2017
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 June 30,
|
|
Six Months Ended June 30,
|
In thousands
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Beginning balance
|
|
$
|
(8,284
|
)
|
|
$
|
(6,815
|
)
|
|
$
|
(8,438
|
)
|
|
$
|
(6,951
|
)
|
Amounts reclassified from AOCL:
|
|
|
|
|
|
|
|
|
Amortization of actuarial losses
|
|
209
|
|
|
225
|
|
|
418
|
|
|
450
|
|
Total reclassifications before tax
|
|
209
|
|
|
225
|
|
|
418
|
|
|
450
|
|
Tax (benefit) expense
|
|
(56
|
)
|
|
(88
|
)
|
|
(111
|
)
|
|
(177
|
)
|
Total reclassifications for the period
|
|
153
|
|
|
137
|
|
|
307
|
|
|
273
|
|
Ending balance
|
|
$
|
(8,131
|
)
|
|
$
|
(6,678
|
)
|
|
$
|
(8,131
|
)
|
|
$
|
(6,678
|
)
|
Employer Contributions to Company-Sponsored Defined Benefit Pension Plans
For the
six months ended June 30, 2018
, we made cash contributions totaling
$5.6 million
to our qualified defined benefit pension plans. We expect further plan contributions of
$10.0 million
during the remainder of
2018
.
Defined Contribution Plan
The Retirement K Savings Plan is a qualified defined contribution plan under Internal Revenue Code Sections 401(a) and 401(k). Employer contributions totaled
$3.5 million
and
$2.8 million
for the
six months ended June 30, 2018
and
2017
, respectively.
See
Note 8
in the
2017
Form 10-K for more information concerning these retirement and other postretirement benefit plans.
9. INCOME TAX
An estimate of annual income tax expense is made each interim period using estimates for annual pre-tax income, regulatory flow-through adjustments, tax credits, and other items. The estimated annual effective tax rate is applied to year-to-date, pre-tax income to determine income tax expense for the interim period consistent with the annual estimate.
The effective income tax rate varied from the combined federal and state statutory tax rates due to the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
Dollars in thousands
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Income taxes at statutory rates (federal and state)
|
|
$
|
(135
|
)
|
|
$
|
2,603
|
|
|
$
|
15,233
|
|
|
$
|
29,912
|
|
Increase (decrease):
|
|
|
|
|
|
|
|
|
|
Differences required to be flowed-through by regulatory commissions
|
|
(14
|
)
|
|
66
|
|
|
835
|
|
|
1,584
|
|
Other, net
|
|
(7
|
)
|
|
(122
|
)
|
|
(592
|
)
|
|
(1,318
|
)
|
Total provision for income taxes on continuing operations
|
|
$
|
(156
|
)
|
|
$
|
2,547
|
|
|
$
|
15,476
|
|
|
$
|
30,178
|
|
Effective tax rate for continuing operations
|
|
31.5
|
%
|
|
38.5
|
%
|
|
27.1
|
%
|
|
39.9
|
%
|
The effective income tax rate for the three and
six months ended June 30, 2018
compared to the same periods in
2017
decreased primarily as a result of the TCJA and lower pre-tax income. See "U.S. Federal TCJA Matters" below and
Note 9
in the
2017
Form 10-K for more detail on income taxes and effective tax rates.
The IRS Compliance Assurance Process (CAP) examination of the 2016 tax year was completed during the first quarter of 2018. There were no material changes to the return as filed. The 2017 tax year is subject to examination under CAP and the 2018 tax year CAP application has been accepted by the IRS.
U.S. Federal TCJA Matters
On December 22, 2017, the TCJA was enacted and permanently lowered the U.S. federal corporate income tax rate to
21%
from the previous maximum rate of
35%
, effective for our tax year beginning January 1, 2018. The TCJA includes specific provisions related to regulated public utilities that provide for the continued deductibility of interest expense and the elimination of bonus depreciation for property acquired and placed in service after September 27, 2017.
Under pre-TCJA law, business interest expense was generally deductible in the determination of taxable income. The TCJA imposes a new limitation on the deductibility of net business interest expense in excess of approximately 30% of adjusted taxable income. Taxpayers operating in the trade or business of public regulated utilities are excluded from these new interest expense limitations. There is ongoing uncertainty with regards to the application of the new interest expense limitation to our non-regulated operations. See Note 9 in the
2017
Form 10-K.
The TCJA generally provides for immediate full expensing for qualified property acquired and placed in service after September 27, 2017 and before January 1, 2023. This would generally provide for accelerated cost recovery for capital investments. However, the definition of qualified property excludes property used in the trade or business of a public regulated utility. The definition of utility trade or business is the same as that used by the TCJA with respect to the imposition of the net interest expense limitation discussed above. As a result, ongoing uncertainty exists with respect to the application of full expensing to our non-regulated activities, and the availability of bonus depreciation for utility assets acquired before September 28, 2017 and placed in service after September 27, 2017. See Note 9 in the
2017
Form 10-K.
At
June 30, 2018
and
December 31, 2017
, we had an estimated regulatory liability of
$213.3 million
for the change in regulated utility deferred taxes as a result of the TCJA, which included a gross-up for income taxes of
$56.5 million
. It is possible that this estimated balance may increase or decrease in the future as additional authoritative interpretation of the TCJA becomes available, or as a result of regulatory guidance from the OPUC or WUTC. We anticipate that until such time that customers receive the direct benefit of this regulatory liability, the balance, net of the additional gross-up for income taxes, will continue to provide an indirect benefit to customers by reducing the utility rate base which is a component of customer rates. It is not yet certain when the final resolution of these regulatory proceedings will occur, and as result, this regulatory liability is classified as long-term.
Utility rates in effect include an allowance to provide for the recovery of the anticipated provision for income taxes incurred as a result of providing regulated services. As a result of the newly enacted
21%
federal corporate income tax rate, we are recording an additional regulatory liability in 2018 reflecting the estimated net reduction in our provision for income taxes. This revenue deferral is based on the estimated net benefit to customers using forecasted regulated utility earnings, considering average weather and associated volumes, and includes a gross-up for income taxes. As of
June 30, 2018
, a regulatory liability of
$9.4 million
has been recorded including accrued interest to reflect this estimated revenue deferral.
10. PROPERTY, PLANT, AND EQUIPMENT
The following table sets forth the major classifications of our property, plant, and equipment and accumulated depreciation of our continuing operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
December 31,
|
In thousands
|
|
2018
|
|
2017
|
|
2017
|
Utility plant in service
|
|
$
|
3,035,089
|
|
|
$
|
2,901,791
|
|
|
$
|
2,975,217
|
|
Utility construction work in progress
|
|
192,496
|
|
|
127,383
|
|
|
159,924
|
|
Less: Accumulated depreciation
|
|
966,766
|
|
|
925,589
|
|
|
942,879
|
|
Utility plant, net
|
|
2,260,819
|
|
|
2,103,585
|
|
|
2,192,262
|
|
Non-utility plant in service
|
|
65,743
|
|
|
63,964
|
|
|
65,372
|
|
Non-utility construction work in progress
|
|
5,528
|
|
|
4,974
|
|
|
4,122
|
|
Less: Accumulated depreciation
|
|
18,232
|
|
|
16,969
|
|
|
17,598
|
|
Non-utility plant, net
(1)
|
|
53,039
|
|
|
51,969
|
|
|
51,896
|
|
Total property, plant, and equipment
|
|
$
|
2,313,858
|
|
|
$
|
2,155,554
|
|
|
$
|
2,244,158
|
|
|
|
|
|
|
|
|
Capital expenditures in accrued liabilities
(2)
|
|
$
|
22,112
|
|
|
$
|
42,574
|
|
|
$
|
34,761
|
|
|
|
(1)
|
Previously reported non-utility balances were restated due to the assets and liabilities associated with Gill Ranch now being classified as discontinued operations assets and liabilities on the consolidated balance sheets. See
Note 15
for further discussion.
|
|
|
(2)
|
Previously reported capital expenditures in accrued liabilities were restated due to the assets and liabilities associated with Gill Ranch now being classified as discontinued operations assets and liabilities on the consolidated balance sheets. Capital expenditures in accrued liabilities related to Gill Ranch were approximately
$0.3 million
,
$0.1 million
, and
$0.2 million
as of
June 30, 2018
,
June 30, 2017
, and
December 31, 2017
, respectively.
|
Build-to-suit Assets
In October 2017, we entered into a
20
-year operating lease agreement commencing in
2020
for our new headquarters location in Portland, Oregon. Our existing headquarters lease expires in
2020
. Our search and evaluation process focused on seismic preparedness, safety, reliability, least cost to our customers, and a continued commitment to our employees and the communities we serve. The lease was analyzed in consideration of build-to-suit lease accounting guidance, and we concluded that we are the accounting owner of the asset during construction. As a result, we have recognized
$7.6 million
and
$0.5 million
in property, plant and equipment and an obligation in other non-current liabilities for the same amount in our consolidated balance sheet at
June 30, 2018
and
December 31, 2017
, respectively. In
2019
, pursuant to the new lease standard issued by the FASB, we expect to de-recognize the associated build-to-suit asset and liability. See
Note 14
in our
2017
Form 10-K.
11. GAS RESERVES
We have invested approximately
$188 million
through our gas reserves program in the Jonah Field located in Wyoming as of
June 30, 2018
. Gas reserves are stated at cost, net of regulatory amortization, with the associated deferred tax benefits recorded as liabilities in 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 approximately
$178 million
and the amended agreement with Jonah Energy LLC under which an approximate additional
$10 million
was invested.
The cost of gas, including a carrying cost for the rate base investment, 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.
Gas produced from the additional wells is 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
December 31,
|
In thousands
|
|
2018
|
|
2017
|
|
2017
|
Gas reserves, current
|
|
$
|
16,579
|
|
|
$
|
16,072
|
|
|
$
|
15,704
|
|
Gas reserves, non-current
|
|
170,958
|
|
|
171,464
|
|
|
171,832
|
|
Less: Accumulated amortization
|
|
95,596
|
|
|
79,444
|
|
|
87,779
|
|
Total gas reserves
(1)
|
|
91,941
|
|
|
108,092
|
|
|
99,757
|
|
Less: Deferred taxes on gas reserves
|
|
20,381
|
|
|
31,074
|
|
|
22,712
|
|
Net investment in gas reserves
|
|
$
|
71,560
|
|
|
$
|
77,018
|
|
|
$
|
77,045
|
|
|
|
(1)
|
Our net investment in additional wells included in total gas reserves was $
5.5 million
, $
6.3 million
and $
5.8 million
at
June 30, 2018
and
2017
and
December 31,
2017
, respectively.
|
Our investment is included in our consolidated balance sheets under gas reserves with our maximum loss exposure limited to our investment balance.
12. 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 in our balance sheet. If we do not develop this investment, our maximum loss exposure related to TWH is limited to our equity investment balance, less our share of any cash or other assets available to us as a
50%
owner. Our investment balance in TWH was
$13.4 million
at
June 30, 2018
and
2017
and
December 31, 2017
. See
Note 12
in our
2017
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 our
2017
Form 10-K.
13. 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, net of amounts shared with utility customers.
Notional Amounts
The following table presents the absolute notional amounts related to open positions on our derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
December 31,
|
In thousands
|
|
2018
|
|
2017
|
|
2017
|
Natural gas (in therms):
|
|
|
|
|
|
|
Financial
|
|
473,900
|
|
|
490,780
|
|
|
429,100
|
|
Physical
|
|
724,450
|
|
|
495,751
|
|
|
520,268
|
|
Foreign exchange
|
|
$
|
7,804
|
|
|
$
|
7,788
|
|
|
$
|
7,669
|
|
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. We entered the
2017-18
and
2016-17
gas year with our forecasted sales volumes hedged at
49%
and
48%
in financial swap and option contracts, and
26%
and
27%
in physical gas supplies, respectively. Hedge contracts entered into prior to our PGA filing, in September
2017
, were included in the PGA for the
2017-18
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 June 30,
|
|
|
2018
|
|
2017
|
In thousands
|
|
Natural gas commodity
|
|
Foreign exchange
|
|
Natural gas commodity
|
|
Foreign exchange
|
Benefit (expense) to cost of gas
|
|
$
|
2,658
|
|
|
$
|
(56
|
)
|
|
$
|
(5,172
|
)
|
|
$
|
216
|
|
Operating revenues
|
|
391
|
|
|
—
|
|
|
(109
|
)
|
|
—
|
|
Amounts deferred to regulatory accounts on balance sheet
|
|
(2,915
|
)
|
|
56
|
|
|
5,263
|
|
|
(216
|
)
|
Total gain (loss) in pre-tax earnings
|
|
$
|
134
|
|
|
$
|
—
|
|
|
$
|
(18
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
|
In thousands
|
|
Natural gas commodity
|
|
Foreign exchange
|
|
Natural gas commodity
|
|
Foreign exchange
|
Benefit (expense) to cost of gas
|
|
$
|
(3,089
|
)
|
|
$
|
(210
|
)
|
|
$
|
(16,515
|
)
|
|
$
|
224
|
|
Operating revenues
|
|
164
|
|
|
—
|
|
|
(1,277
|
)
|
|
—
|
|
Amounts deferred to regulatory accounts on balance sheet
|
|
2,980
|
|
|
210
|
|
|
17,347
|
|
|
(224
|
)
|
Total gain (loss) in pre-tax earnings
|
|
$
|
55
|
|
|
$
|
—
|
|
|
$
|
(445
|
)
|
|
$
|
—
|
|
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
$4.7 million
and
$13.7 million
for the
three and six months ended June 30, 2018
, respectively, from the settlement of natural gas financial derivative contracts. Whereas, we realized net gains of
$0.3 million
and remained flat for the
three and six months ended
June 30, 2017
, respectively. 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
June 30, 2018
or
2017
. 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
2018
or
2017
. 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
$14.3 million
at
June 30, 2018
, 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
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(3,605
|
)
|
|
$
|
(11,211
|
)
|
Without Adequate Assurance Calls
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,605
|
)
|
|
(6,987
|
)
|
Our financial derivative instruments are subject to master netting arrangements; however, they are presented on a gross basis in our consolidated balance sheets. We and our counterparties have the ability to set-off 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 physical and financial derivative position would result in an asset of
$2.5 million
and a liability of
$15.0 million
as of
June 30, 2018
, an asset of $
0.9 million
and a liability of $
7.4 million
as of
June 30, 2017
, and an asset of
$2.9 million
and a liability of
$23.3 million
as of
December 31, 2017
.
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
2017
Form 10-K for additional information.
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
June 30, 2018
. Using significant other observable or Level 2 inputs, the net fair value was
a liability
of $
12.5 million
, $
6.5 million
, and
$20.3 million
as of
June 30, 2018
and
2017
, and
December 31, 2017
, respectively.
No
Level 3 inputs were used in our derivative valuations, and there were
no
transfers between Level 1 or Level 2 during the
six months ended June 30, 2018
and
2017
. See
Note 2
in the
2017
Form 10-K.
14. 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. Refer to "
Other Portland Harbor
" below.
Environmental Sites
The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other current liabilities and other noncurrent liabilities in the balance sheet:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
Non-Current Liabilities
|
|
|
June 30,
|
|
December 31,
|
|
June 30,
|
|
December 31,
|
In thousands
|
|
2018
|
|
2017
|
|
2017
|
|
2018
|
|
2017
|
|
2017
|
Portland Harbor site:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gasco/Siltronic Sediments
|
|
$
|
2,174
|
|
|
$
|
1,485
|
|
|
$
|
2,683
|
|
|
$
|
45,330
|
|
|
$
|
43,376
|
|
|
$
|
45,346
|
|
Other Portland Harbor
|
|
1,444
|
|
|
1,435
|
|
|
1,949
|
|
|
3,871
|
|
|
3,906
|
|
|
4,163
|
|
Gasco/Siltronic Upland site
|
|
9,947
|
|
|
9,441
|
|
|
13,422
|
|
|
45,578
|
|
|
49,319
|
|
|
47,835
|
|
Central Service Center site
|
|
25
|
|
|
31
|
|
|
25
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Front Street site
|
|
906
|
|
|
829
|
|
|
1,009
|
|
|
10,683
|
|
|
10,788
|
|
|
10,757
|
|
Oregon Steel Mills
|
|
—
|
|
|
—
|
|
|
—
|
|
|
179
|
|
|
179
|
|
|
179
|
|
Total
|
|
$
|
14,496
|
|
|
$
|
13,221
|
|
|
$
|
19,088
|
|
|
$
|
105,641
|
|
|
$
|
107,568
|
|
|
$
|
108,280
|
|
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 selects the remedy for the clean-up of the Portland Harbor site (Portland Harbor ROD). 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 with the other PRPs 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 for the additional studies and design work needed before the cleanup can occur, and for regulatory oversight throughout the clean-up range from
$47.5 million
to
$350 million
. We have recorded a liability of
$47.5 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 the Gasco/Siltronic sediments site represent our largest exposure, we do have other potential exposures associated with the Portland Harbor ROD, including NRD costs and harborwide clean-up costs (including downstream petroleum contamination), for which allocations among the PRPs 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 2009, and in 2017, filed suit
against the Company and
29
other parties seeking remedial costs and NRD assessment costs associated with the Portland Harbor, set forth in the complaint. The complaint 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. The Yakama Nation has filed
two
amended complaints addressing certain pleading defects and dismissing the State of Oregon. We have recorded a liability for NRD 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 aforementioned 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, 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 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.
In July 2017, ODEQ issued the PGM ROD. The ROD specifies the selected remedy, which requires a combination of dredging, capping, treatment, and natural recovery. In addition, the selected remedy also requires institutional controls and long-term inspection and maintenance. We revised the liability in the second quarter of 2017 to incorporate the estimated undiscounted cost of approximately
$10.5 million
for the selected remedy. Further, we have recognized an additional liability of
$1.1 million
for additional studies and design costs as well as regulatory oversight throughout the clean-up. We plan to complete the remedial design in 2018 and expect to construct the remedy details during 2019.
Oregon Steel Mills site.
Refer to the “Legal Proceedings,” below.
Site Remediation and Recovery Mechanism (SRRM)
We have an 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 therein. See Note 15 in the
2017
Form 10-K for a description of the SRRM collection process.
The following table presents information regarding the total regulatory asset deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
December 31,
|
In thousands
|
|
2018
|
|
2017
|
|
2017
|
Deferred costs and interest
(1)
|
|
$
|
46,862
|
|
|
$
|
50,131
|
|
|
$
|
45,546
|
|
Accrued site liabilities
(2)
|
|
119,712
|
|
|
120,485
|
|
|
126,950
|
|
Insurance proceeds and interest
|
|
(95,824
|
)
|
|
(99,884
|
)
|
|
(94,170
|
)
|
Total regulatory asset deferral
(1)
|
|
$
|
70,750
|
|
|
$
|
70,732
|
|
|
$
|
78,326
|
|
Current regulatory assets
(3)
|
|
5,594
|
|
|
6,724
|
|
|
6,198
|
|
Long-term regulatory assets
(3)
|
|
65,156
|
|
|
64,008
|
|
|
72,128
|
|
|
|
(1)
|
Includes pre-review and post-review deferred costs, amounts currently in amortization, and interest, net of amounts collected from customers.
|
|
|
(2)
|
Excludes
3.32%
of the Front Street site liability, or
$0.4
million in
2018
and
$0.4
million in
2017
, as the OPUC only 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
$5.0 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
$5.0 million
tariff rider and
$5.0 million
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
$10.0 million
with those earnings that exceed its authorized ROE.
Under the 2015 Order, the OPUC stated they would 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 we gain greater certainty about our future remediation costs, to consider whether adjustments to the mechanism may be appropriate. As it has been three years from the 2015 Order, we filed an update with the OPUC in March 2018 and recommended no changes.
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.
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.
See Note 15 in the
2017
Form 10-K.
For additional information regarding other commitments and contingencies, see
Note 14
in the
2017
Form 10-K.
15. DISCONTINUED OPERATIONS
On June 20, 2018, NWN Gas Storage, our wholly owned subsidiary, entered into a Purchase and Sale Agreement (the Agreement) that provides for the sale by NWN Gas Storage of all of the membership interests in Gill Ranch. Gill Ranch owns a
75%
interest in the natural gas storage facility located near Fresno, California known as the Gill Ranch Gas Storage Facility. Pacific Gas and Electric Company (PG&E) owns the remaining
25%
interest in the Gill Ranch Gas Storage Facility.
The Agreement provides for an initial cash purchase price of
$25.0 million
(subject to a working capital adjustment), plus potential additional payments to NWN Gas Storage of up to
$26.5 million
in the aggregate if Gill Ranch achieves certain economic performance levels for the first three full gas storage years (April 1 of one year through March 31 of the following year) occurring after the closing and the remaining portion of the gas storage year during which the closing occurs.
We expect the transaction to close within 12 months of signing and in 2019. The closing of the transaction is subject to approval by the California Public Utilities Commission (CPUC) and other customary closing conditions.
As a result of our strategic shift away from merchant gas storage and the significance of Gill Ranch's financial results in 2017, we have concluded that the pending sale of Gill Ranch qualifies as assets and liabilities held for sale and discontinued
operations. As such, the assets and liabilities associated with Gill Ranch have been classified as discontinued operations assets and discontinued operations liabilities, respectively, and, the results of Gill Ranch are presented separately, net of tax, as discontinued operations from the results of continuing operations for all periods presented. The expenses included in the results of discontinued operations are the direct operating expenses incurred by Gill Ranch that may be reasonably segregated from the costs of our continuing operations.
The following table presents the carrying amounts of the major components of Gill Ranch that are classified as discontinued operations assets and liabilities on our consolidated balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
December 31,
|
In thousands
|
|
2018
|
|
2017
|
|
2017
|
Assets:
|
|
|
|
|
|
|
Accounts receivable
|
|
$
|
497
|
|
|
$
|
1,130
|
|
|
$
|
2,126
|
|
Inventories
|
|
646
|
|
|
402
|
|
|
396
|
|
Other current assets
|
|
413
|
|
|
391
|
|
|
535
|
|
Property, plant, and equipment
|
|
10,948
|
|
|
235,556
|
|
|
10,816
|
|
Less: Accumulated depreciation
|
|
6
|
|
|
30,526
|
|
|
—
|
|
Other non-current assets
|
|
245
|
|
|
51
|
|
|
1
|
|
Discontinued operations - current assets
(1)
|
|
12,743
|
|
|
1,923
|
|
|
3,057
|
|
Discontinued operations - non-current assets
(1)
|
|
—
|
|
|
205,081
|
|
|
10,817
|
|
Total discontinued operations assets
|
|
$
|
12,743
|
|
|
$
|
207,004
|
|
|
$
|
13,874
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
Accounts payable
|
|
$
|
572
|
|
|
$
|
635
|
|
|
$
|
1,287
|
|
Other current liabilities
|
|
436
|
|
|
668
|
|
|
306
|
|
Other non-current liabilities
|
|
11,914
|
|
|
12,167
|
|
|
12,043
|
|
Discontinued operations - current liabilities
(1)
|
|
12,922
|
|
|
1,303
|
|
|
1,593
|
|
Discontinued operations - non-current liabilities
(1)
|
|
—
|
|
|
12,167
|
|
|
12,043
|
|
Total discontinued operations liabilities
|
|
$
|
12,922
|
|
|
$
|
13,470
|
|
|
$
|
13,636
|
|
|
|
(1)
|
The total assets and liabilities of Gill Ranch are classified as current as of June 30, 2018 because it is probable that the sale will be completed within one year.
|
The following table presents the operating results of Gill Ranch, which was reported within our gas storage segment historically, and is presented net of tax on our consolidated statements of comprehensive income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
In thousands, except per share data
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Revenues
|
|
$
|
1,006
|
|
|
$
|
1,762
|
|
|
$
|
2,083
|
|
|
$
|
3,361
|
|
Expenses:
|
|
|
|
|
|
|
|
|
Operations and maintenance
|
|
1,554
|
|
|
2,251
|
|
|
2,590
|
|
|
3,921
|
|
Depreciation and amortization
|
|
108
|
|
|
1,131
|
|
|
218
|
|
|
2,263
|
|
Other expenses and interest
|
|
239
|
|
|
604
|
|
|
814
|
|
|
1,196
|
|
Total expenses
|
|
1,901
|
|
|
3,986
|
|
|
3,622
|
|
|
7,380
|
|
Loss from discontinued operations before income taxes
|
|
(895
|
)
|
|
(2,224
|
)
|
|
(1,539
|
)
|
|
(4,019
|
)
|
Income tax benefit
|
|
236
|
|
|
878
|
|
|
406
|
|
|
1,586
|
|
Loss from discontinued operations, net of tax
|
|
$
|
(659
|
)
|
|
$
|
(1,346
|
)
|
|
$
|
(1,133
|
)
|
|
$
|
(2,433
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Loss from discontinued operations per share of common stock:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.02
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
(0.08
|
)
|
Diluted
|
|
$
|
(0.02
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
(0.04
|
)
|
|
$
|
(0.08
|
)
|