CONDENSED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(not audited)
In the opinion of management, Otter Tail Corporation (the Company) has included all adjustments (including normal recurring accruals) necessary for a fair presentation of the consolidated financial statements for the periods presented. The consolidated financial statements and
condensed notes thereto should be read in conjunction with the consolidated financial statements and notes included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2016. Because of seasonal and other factors, the earnings for the three- and nine-month periods ended September 30, 2017 should not be taken as an indication of earnings for all or any part of the balance of the year.
The following
condensed notes are numbered to correspond to numbers of the notes included in the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 2016.
1. Summary of Significant Accounting Policies
Revenue Recognition
Due to the diverse business operations of the Company, revenue recognition depends on the product produced and sold or service performed. The Company recognizes revenue when the earnings process is complete, evidenced by an agreement with the customer, there has been delivery and acceptance, the price is fixed or determinable
and collectability is reasonably assured. In cases where significant obligations remain after delivery, revenue recognition is deferred until such obligations are fulfilled. Provisions for sales returns and warranty costs are recorded at the time of the sale based on historical information and current trends. Gains and losses on forward energy contracts subject to regulatory treatment, if any, are deferred and recognized on a net basis in revenue in the period realized.
For the Company
’s operating companies recognizing revenue on certain products when shipped, those operating companies have no further obligation to provide services related to such products. The shipping terms used in these instances are FOB shipping point.
Agreements Subject to Legally Enforceable Netting Arrangements
The Company does not offset assets and liabilities under legally enforceable netting arrangements on the face of its consolidated balance sheet.
Fair Value Measurements
The Company follows
Accounting Standards Codification (ASC) Topic 820,
Fair Value Measurements and Disclosures
(ASC 820), for recurring fair value measurements. ASC 820 provides a single definition of fair value, requires enhanced disclosures about assets and liabilities measured at fair value and establishes a hierarchal framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. The three levels defined by the hierarchy and examples of each level are as follows:
Level 1
– Quoted prices are available in active markets for identical assets or liabilities as of the reported date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices, such as equities listed by the New York Stock Exchange and commodity derivative contracts listed on the New York Mercantile Exchange (NYMEX).
Level 2
– Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reported date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, such as treasury securities with pricing interpolated from recent trades of similar securities, or priced with models using highly observable inputs, such as commodity options priced using observable forward prices and volatilities.
Level 3
– Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those with inputs requiring significant management judgment or estimation and may include complex and subjective models and forecasts.
The following tables present, for each of the hierarchy levels, the Company
’s assets and liabilities that are measured at fair value on a recurring basis as of September 30, 2017 and December 31, 2016:
September
30
, 201
7
(in thousands)
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Funds
– Held by Captive Insurance Company
|
|
$
|
1,275
|
|
|
|
|
|
|
|
|
|
Corporate Debt Securities
– Held by Captive Insurance Company
|
|
|
|
|
|
$
|
5,039
|
|
|
|
|
|
Government
-Backed and Government-Sponsored
Enterprises
’ Debt Securities
– Held by Captive Insurance Company
|
|
|
|
|
|
|
2,099
|
|
|
|
|
|
Other Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Money Market and Mutual Funds
– Nonqualified Retirement Savings Plan
|
|
|
714
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
1,989
|
|
|
$
|
7,138
|
|
|
|
|
|
December 31, 201
6
(in thousands)
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate Debt Securities
– Held by Captive Insurance Company
|
|
|
|
|
|
$
|
5,280
|
|
|
|
|
|
Government
-Backed and Government-Sponsored
Enterprises
’ Debt Securities
– Held by Captive Insurance Company
|
|
|
|
|
|
|
2,945
|
|
|
|
|
|
Other Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Money Market and Mutual Funds
– Nonqualified Retirement Savings Plan
|
|
$
|
849
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
849
|
|
|
$
|
8,225
|
|
|
|
|
|
The valuation techniques and inputs used for the Level 2 fair value measurements in the table above are as follows:
Government-Backed and Government-Sponsored Enterprises
’ and Corporate Debt Securities Held by the Company’s Captive Insurance Company
– Fair values are determined on the basis of valuations provided by a third-party pricing service which utilizes industry accepted valuation models and observable market inputs to determine valuation. Some valuations or model inputs used by the pricing service may be based on broker quotes.
Coyote Station Lignite Supply Agreement
– Variable Interest Entity
—In October 2012 the Coyote Station owners, including Otter Tail Power Company (OTP), entered into a lignite sales agreement (LSA) with Coyote Creek Mining Company, L.L.C. (CCMC), a subsidiary of The North American Coal Corporation, for the purchase of lignite coal to meet the coal supply requirements of Coyote Station for the period beginning in May 2016 and ending in December 2040. The price per ton paid by the Coyote Station owners under the LSA reflects the cost of production, along with an agreed profit and capital charge. CCMC was formed for the purpose of mining coal to meet the coal fuel supply requirements of Coyote Station from May 2016 through December 2040 and, based on the terms of the LSA, is considered a variable interest entity (VIE) due to the transfer of all operating and economic risk to the Coyote Station owners, as the agreement is structured so that the price of the coal would cover all costs of operations as well as future reclamation costs. The Coyote Station owners are also providing a guarantee of the value of the assets of CCMC as they would be required to buy certain assets at book value should they terminate the contract prior to the end of the contract term and are providing a guarantee of the value of the equity of CCMC in that they are required to buy the entity at the end of the contract term at equity value. Under current accounting standards, the primary beneficiary of a VIE is required to include the assets, liabilities, results of operations and cash flows of the VIE in its consolidated financial statements. No single owner of Coyote Station owns a majority interest in Coyote Station and none, individually, has the power to direct the activities that most significantly impact CCMC. Therefore, none of the owners individually, including OTP, is considered a primary beneficiary of the VIE and the Company is not required to include CCMC in its consolidated financial statements.
If the LSA terminates prior to the expiration of its term or the production period terminates prior to December 31, 2040 and the Coyote Station owners purchase all of the outstanding membership interests of CCMC as required by the LSA, the owners will satisfy, or (if permitted by CCMC
’s applicable lender) assume, all of CCMC’s obligations owed to CCMC’s lenders under its loans and leases. The Coyote Station owners have limited rights to assign their rights and obligations under the LSA without the consent of CCMC’s lenders during any period in which CCMC’s obligations to its lenders remain outstanding. In the event the contract is terminated because regulations or legislation render the burning of coal cost prohibitive and the assets worthless, OTP’s maximum exposure to loss as a result of its involvement with CCMC as of September 30, 2017 could be as high as $58.0 million, OTP’s 35% share of unrecovered costs.
Inventories
Inventories
, valued at the lower of cost or net realizable value, consist of the following:
|
|
September
30,
|
|
|
December 31,
|
|
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
Finished Goods
|
|
$
|
19,500
|
|
|
$
|
27,755
|
|
Work in Process
|
|
|
13,885
|
|
|
|
11,754
|
|
Raw Material, Fuel and Supplies
|
|
|
45,530
|
|
|
|
44,231
|
|
Total Inventories
|
|
$
|
78,915
|
|
|
$
|
83,740
|
|
Goodwill and Other Intangible Assets
An assessment of the carrying amounts of goodwill of the Company
’s operating units as of December 31, 2016 indicated the fair values are substantially in excess of their respective book values and not impaired.
The following table
indicates there were no changes to goodwill by business segment during the first nine months of 2017:
(in thousands)
|
|
Gross Balance
December 31, 2016
|
|
|
Accumulated
Impairments
|
|
|
Balance
(net of impairments)
December 31, 2016
|
|
|
Adjustments to
Goodwill in
201
7
|
|
|
Balance
(net of impairments)
September 30, 2017
|
|
Manufacturing
|
|
$
|
18,270
|
|
|
$
|
--
|
|
|
$
|
18,270
|
|
|
$
|
--
|
|
|
$
|
18,270
|
|
Plastics
|
|
|
19,302
|
|
|
|
--
|
|
|
|
19,302
|
|
|
|
--
|
|
|
|
19,302
|
|
Total
|
|
$
|
37,572
|
|
|
$
|
--
|
|
|
$
|
37,572
|
|
|
$
|
--
|
|
|
$
|
37,572
|
|
Intangible assets with finite lives are amortized over their estimated useful lives and reviewed for impairment in accordance with requirements under ASC
Topic 360-10-35,
Property, Plant, and Equipment—Overall—Subsequent Measurement
.
The following table summarizes the components of the Company
’s intangible assets at September 30, 2017 and December 31, 2016:
September
30
, 2017
(in thousands)
|
|
Gross Carrying Amount
|
|
|
Accumulated Amortization
|
|
|
Net Carrying
Amount
|
|
|
Remaining
Amortization
Periods
(months)
|
|
Amortizable Intangible Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer Relationships
|
|
$
|
22,491
|
|
|
$
|
8,710
|
|
|
$
|
13,781
|
|
|
27
|
-
|
215
|
|
Covenant not to Compete
|
|
|
590
|
|
|
|
410
|
|
|
|
180
|
|
|
|
11
|
|
|
Other
|
|
|
140
|
|
|
|
4
|
|
|
|
136
|
|
|
|
35
|
|
|
Total
|
|
$
|
23,221
|
|
|
$
|
9,124
|
|
|
$
|
14,097
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortizable Intangible Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer Relationships
|
|
$
|
22,491
|
|
|
$
|
7,861
|
|
|
$
|
14,630
|
|
|
36
|
-
|
224
|
|
Covenant not to Compete
|
|
|
590
|
|
|
|
262
|
|
|
|
328
|
|
|
|
20
|
|
|
Total
|
|
$
|
23,081
|
|
|
$
|
8,123
|
|
|
$
|
14,958
|
|
|
|
|
|
|
The amortization expense for these intangible assets was:
|
|
Three Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
|
201
7
|
|
|
201
6
|
|
Amortization Expense
– Intangible Assets
|
|
$
|
336
|
|
|
$
|
348
|
|
|
$
|
1,001
|
|
|
$
|
1,103
|
|
The estimated annual amortization expense for these intangible assets for the next five years is:
(in thousands)
|
|
2017
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
Estimated Amortization Expense
– Intangible Assets
|
|
$
|
1,346
|
|
|
$
|
1,313
|
|
|
$
|
1,181
|
|
|
$
|
1,131
|
|
|
$
|
1,099
|
|
Supplemental Disclosures of Cash Flow Information
|
|
As of
September 30,
|
|
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
Noncash Investing Activities:
|
|
|
|
|
|
|
|
|
Transactions Related to Capital Additions not Settled in Cash
|
|
$
|
17,940
|
|
|
$
|
11,552
|
|
New Accounting Standards
Adopted
Accounting Standards Update (
ASU
)
2015-11
—In July 2015 the Financial Accounting Standards Board (FASB) issued ASU No. 2015-11,
Inventory (Topic 330): Simplifying the Measurement of Inventory,
which requires that inventories be measured at the lower of cost or net realizable value instead of the lower of cost or market value. Net realizable value is defined as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The standards update was effective prospectively for fiscal years and interim periods beginning after December 15, 2016. The Company adopted the updates in ASU 2015-11 in the first quarter of 2017. The adoption of the updated standard did not have a material impact on the Company’s consolidated financial statements as market and net realizable value were substantially the same for the inventories of its manufacturing companies.
New Accounting Standards
Pending
Adopt
ion
ASU 2014-09
—In May 2014 the FASB issued ASU No. 2014-09,
Revenue from Contracts with Customers (Topic 606)
(ASC 606). ASC 606 is a comprehensive, principles-based accounting standard which amends current revenue recognition guidance with the objective of improving revenue recognition requirements by providing a single comprehensive model to determine the measurement of revenue and the timing of revenue recognition. ASC 606 also requires expanded disclosures to enable users of financial statements to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.
Amendments to the ASC in ASU 2014-09, as amended, are effective for fiscal years beginning after December 15, 2017. Early adoption is permitted, but not any earlier than January 1, 2017. Application methods permitted are: (1) full retrospective, (2) retrospective using one or more practical expedients and (3) retrospective with the cumulative effect of initial application recognized at the date of initial
application. The Company does not plan to adopt the updated guidance prior to January 1, 2018. As of September 30, 2017 the Company has reviewed its revenue streams and contracts to determine areas where the amendments in ASU 2014-09 will be applicable and is developing controls for new processes that will be required to track and report revenues where the timing of revenue recognition will change under ASU 2014-09. Based on review of the Company’s revenue streams, the Company does not anticipate a significant change in the levels or timing of revenue recognition over an annual or interim period as a result of the adoption of ASU 2014-09. The Company will adopt the updates in ASU 2014-09 on a modified retrospective basis with the cumulative effect of initial application on retained earnings and other balance sheet accounts, if any, recognized on January 1, 2018, the date of initial application. Adoption of ASU 2014-09 will result in additional disclosures related to the nature, timing and certainty of revenues and any contract assets or liabilities that may be required to be reported under the updated standard.
ASU 2016-02
—In February 2016 the FASB issued ASU No. 2016-02,
Leases (Topic 842)
(ASU 2016-02). ASU 2016-02 is a comprehensive amendment of the ASC, creating Topic 842, which will supersede the current requirements under ASC Topic 840 on leases and require the recognition of lease assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. Topic 842 affects any entity that enters into a lease, with some specified scope exemptions. The main difference between previous Generally Accepted Accounting Principles in the United States (GAAP) and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous GAAP. Topic 842 retains a distinction between finance leases and operating leases. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the classification criteria for distinguishing between capital leases and operating leases in the previous guidance. Topic 842 also requires qualitative and specific quantitative disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. The amendments in ASU 2016-02 are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments in ASU 2016-02 is permitted. The Company is currently reviewing ASU 2016-02, has developed a list of all current leases outstanding and is identifying key impacts to its businesses to determine areas where the amendments in ASU 2016-02 will be applicable and is evaluating transition options. The Company does not currently plan to apply the amendments in ASU 2016-02 to its consolidated financial statements prior to 2019.
ASU 2017-04
—In January 2017 the FASB issued ASU No. 2017-04,
Intangibles—Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment
(ASU 2017-04), which
simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measured a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill.
In computing the implied fair value of goodwill under Step 2, an entity had to perform procedures to determine the fair value at the impairment testing date of its assets and liabilities (including unrecognized assets and liabilities) following the procedure that would be required in determining the fair value of assets acquired and liabilities assumed in a business combination.
Under the amendments in ASU 2017-04, an entity will perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity will recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized will not exceed the total amount of goodwill allocated to that reporting unit. Additionally, an entity will consider income tax effects from any tax deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable.
The amendments in
ASU 2017-04 modify the concept of impairment from the condition that exists when the carrying amount of goodwill exceeds its implied fair value to the condition that exists when the carrying amount of a reporting unit exceeds its fair value. An entity no longer will determine goodwill impairment by calculating the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. Because these amendments eliminate Step 2 from the goodwill impairment test, they should reduce the cost and complexity of evaluating goodwill for impairment. The amendments in ASU 2017-04 are effective for annual or any interim goodwill impairment tests in fiscal years beginning after December 15, 2019.
Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017.
ASU 2017-07
—In March 2017 the FASB issued ASU No. 2017-07,
Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
(ASU 2017-07), which
is intended
to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost.
ASC
Topic 715,
Compensation—Retirement Benefits
(ASC 715)
,
does not prescribe where the amount of net benefit cost should be presented in an employer’s income statement and does not require entities to disclose by line item the amount of net benefit cost that is included in the income statement or capitalized in assets.
The amendments in ASU 2017-07 require that an employer report the service cost component of periodic benefit costs in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit cost as defined in ASC 715 are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The amendments in ASU 2017-07 also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of internally manufactured inventory or a self-constructed asset). The amendments in ASU 2017-07 are effective for annual periods beginning after December 15, 2017, including interim periods within those annual periods. The amendments will be applied retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets.
The majority of the Company
’s benefit costs to which the amendments in ASU 2017-07 apply are related to benefit plans in place at OTP, the Company’s regulated provider of electric utility services. The amendments in ASU 2017-07 deviate significantly from current prescribed ratemaking and regulatory accounting treatment of postretirement benefit costs, which require the capitalization of a portion of all the components of net periodic benefit costs be included in rate base additions and provide for rate recovery of the non-capitalized portion of all of the components of net periodic pension costs as recoverable operating expenses. The Company currently is assessing the impact adoption of the amendments in ASU 2017-07 may have on its consolidated financial statements, financial position and results of operations and is determining the adjustments and regulatory assets to be established in order to reflect the effect of the required regulatory accounting treatment of the non-service cost components that cannot be capitalized to plant in service under the ASU 2017-07 amendments to GAAP. The non-service cost components of the affected net periodic benefit costs will be reported below the operating income line on the Company’s consolidated income statements upon adoption of the amendments in ASU 2017-07.
T
he Company’s non-service costs components of net periodic post-retirement benefit costs that will be capitalized to plant in service in 2017 but that would be recorded as regulatory assets if the amendments in ASU 2017-07 were applicable in 2017 are expected to be $0.7 million. The Company’s non-service costs components of net periodic post-retirement benefit costs included in operating expense in 2017 that would be included in other income and deductions under ASU 2017-07 are expected to be $5.7 million. The Company does not plan to adopt the updates in ASU 2017-07 prior to the first quarter of 2018, the required effective period for application of the updates by the Company.
2.
Segment Information
Segment Information
The accounting policies of the segments are described under note 1
– Summary of Significant Accounting Policies. The Company's businesses have been classified into three segments to be consistent with its business strategy and the reporting and review process used by the Company’s chief operating decision makers.
These businesses sell products and provide services to customers primarily in the United States. The Company’s business structure currently includes the following three segments: Electric, Manufacturing and Plastics. The chart below indicates the companies included in each segment.
Electric includes the production, transmission, distribution and sale of electric energy in Minnesota, North Dakota and South Dakota by OTP. In addition, OTP is a participant in the Midcontinent Independent System Operator, Inc. (MISO) markets. OTP
’s operations have been the Company’s primary business since 1907.
Manufacturing consists of businesses in the following manufacturing activities: contract machining, metal parts stamping, fabrication and painting, and production of
plastic thermoformed horticultural containers, life science and industrial packaging, and material handling components. These businesses have manufacturing facilities in Georgia, Illinois and Minnesota and sell products primarily in the United States.
Plastics consists of businesses producing polyvinyl chloride (PVC) pipe at plants in North Dakota and Arizona. The PVC pipe is sold primarily in the upper Midwest and Southwest regions of the United States.
OTP is a wholly owned subsidiary of the Company. All of the Company
’s other businesses are owned by its wholly owned subsidiary, Varistar Corporation (Varistar). The Company’s Corporate operating costs include items such as corporate staff and overhead costs, the results of the Company’s captive insurance company and other items excluded from the measurement of operating segment performance. Corporate assets consist primarily of cash, prepaid expenses, investments and fixed assets. Corporate is not an operating segment. Rather, it is added to operating segment totals to reconcile to totals on the Company’s consolidated financial statements.
No single customer accounted for over 10% of the Company
’s consolidated revenues in 2016. All of the Company’s long-lived assets are within the United States and sales within the United States accounted for 97.9% and 98.5% of its operating revenues for the respective three-month periods ended September 30, 2017 and 2016, and 98.2% and 98.6% of its operating revenues for the respective nine-month periods ended September 30, 2017 and 2016.
The Company evaluates the performance of its business segments and allocates resources to them based on earnings contribution and return on total invested capital. Information for the business segments for
the three- and nine-month periods ended September 30, 2017 and 2016 and total assets by business segment as of September 30, 2017 and December 31, 2016 are presented in the following tables:
Operating Revenue
|
|
Three Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
|
201
7
|
|
|
201
6
|
|
Electric
|
|
$
|
103,399
|
|
|
$
|
102,723
|
|
|
$
|
324,186
|
|
|
$
|
313,642
|
|
Manufacturing
|
|
|
54,355
|
|
|
|
52,171
|
|
|
|
172,076
|
|
|
|
170,443
|
|
Plastics
|
|
|
58,708
|
|
|
|
42,292
|
|
|
|
146,416
|
|
|
|
122,841
|
|
Intersegment Eliminations
|
|
|
(5
|
)
|
|
|
(11
|
)
|
|
|
(18
|
)
|
|
|
(27
|
)
|
Total
|
|
$
|
216,457
|
|
|
$
|
197,175
|
|
|
$
|
642,660
|
|
|
$
|
606,899
|
|
Interest Charges
|
|
Three Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
|
201
7
|
|
|
201
6
|
|
Electric
|
|
$
|
6,362
|
|
|
$
|
6,304
|
|
|
$
|
19,187
|
|
|
$
|
18,744
|
|
Manufacturing
|
|
|
555
|
|
|
|
974
|
|
|
|
1,662
|
|
|
|
2,972
|
|
Plastics
|
|
|
157
|
|
|
|
273
|
|
|
|
483
|
|
|
|
796
|
|
Corporate and Intersegment Eliminations
|
|
|
319
|
|
|
|
475
|
|
|
|
1,050
|
|
|
|
1,484
|
|
Total
|
|
$
|
7,393
|
|
|
$
|
8,026
|
|
|
$
|
22,382
|
|
|
$
|
23,996
|
|
Income Taxes
|
|
Three Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
|
201
7
|
|
|
201
6
|
|
Electric
|
|
$
|
3,548
|
|
|
$
|
4,730
|
|
|
$
|
12,052
|
|
|
$
|
11,262
|
|
Manufacturing
|
|
|
676
|
|
|
|
182
|
|
|
|
3,304
|
|
|
|
2,992
|
|
Plastics
|
|
|
3,826
|
|
|
|
1,577
|
|
|
|
8,074
|
|
|
|
5,206
|
|
Corporate
|
|
|
(1,015
|
)
|
|
|
(1,326
|
)
|
|
|
(4,135
|
)
|
|
|
(3,722
|
)
|
Total
|
|
$
|
7,035
|
|
|
$
|
5,163
|
|
|
$
|
19,295
|
|
|
$
|
15,738
|
|
Net Income (Loss)
|
|
Three Months Ended
|
|
|
Nine
Months Ended
|
|
|
|
September
30,
|
|
|
September
30,
|
|
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
|
201
7
|
|
|
201
6
|
|
Electric
|
|
$
|
10,869
|
|
|
$
|
12,513
|
|
|
$
|
36,563
|
|
|
$
|
34,199
|
|
Manufacturing
|
|
|
1,608
|
|
|
|
1,246
|
|
|
|
6,735
|
|
|
|
6,108
|
|
Plastics
|
|
|
6,092
|
|
|
|
2,346
|
|
|
|
13,166
|
|
|
|
7,983
|
|
Corporate
|
|
|
(796
|
)
|
|
|
(1,511
|
)
|
|
|
(2,445
|
)
|
|
|
(3,650
|
)
|
Discontinued Operations
|
|
|
(39
|
)
|
|
|
22
|
|
|
|
78
|
|
|
|
171
|
|
Total
|
|
$
|
17,734
|
|
|
$
|
14,616
|
|
|
$
|
54,097
|
|
|
$
|
44,811
|
|
Identifiable
Assets
|
|
September
30,
|
|
|
December 31,
|
|
(in
thousands)
|
|
201
7
|
|
|
201
6
|
|
Electric
|
|
$
|
1,660,591
|
|
|
$
|
1,622,231
|
|
Manufacturing
|
|
|
167,004
|
|
|
|
166,525
|
|
Plastics
|
|
|
98,283
|
|
|
|
84,592
|
|
Corporate
|
|
|
41,019
|
|
|
|
39,037
|
|
Total
|
|
$
|
1,966,897
|
|
|
$
|
1,912,385
|
|
3. Rate and Regulatory Matters
Below are descriptions of OTP
’s major capital expenditure projects that have had, or will have, a significant impact on OTP’s revenue requirements, rates and alternative revenue recovery mechanisms, followed by summaries of specific electric rate or rider proceedings with the Minnesota Public Utilities Commission (MPUC), the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission (SDPUC) and the Federal Energy Regulatory Commission (FERC) impacting OTP’s revenues in 2017 and 2016.
Major Capital Expenditure Projects
Big Stone South
–Brookings
Multi-Value Transmission Project (
MVP
)
and
Capacity Expansion 2020 (
CapX2020
)
Project
—This 345 kiloVolt (kV) transmission line extends approximately 70 miles between a substation near Big Stone City, South Dakota and the Brookings County Substation near Brookings, South Dakota. OTP and Northern States Power – MN, a subsidiary of Xcel Energy Inc., jointly developed this project and the parties have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Open Access Transmission, Energy and Operating Reserve Markets Tariff (MISO Tariff) in December 2011.
MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple areas within the MISO region. The cost allocation is designed to ensure the costs of transmission projects with regional benefits are properly assigned to those who benefit. Construction began on this line in the third quarter of 2015 and the line was energized on September 8, 2017.
OTP’s capitalized costs on this project as of September 30, 2017 were approximately $70.0 million, which includes assets that are 100% owned by OTP.
Big Stone South
–Ellendale MVP
—This is a 345 kV transmission line that will extend 163 miles between a substation near Big Stone City, South Dakota and a substation near Ellendale, North Dakota. OTP jointly developed this project with Montana-Dakota Utilities Co., a division of MDU Resources Group, Inc., and the parties will have equal ownership interest in the transmission line portion of the project. MISO approved this project as an MVP under the MISO Tariff in December 2011. Construction began on this line in the second quarter of 2016 and is expected to be completed in 2019. OTP’s capitalized costs on this project as of September 30, 2017 were approximately $78.4 million, which includes assets that are 100% owned by OTP.
Recovery of OTP
’s major transmission investments is through the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.
Minnesota
2016 General Rate Case
—The MPUC rendered its final decision in OTP’s 2016 general rate case in March 2017 and issued its written order on May 1, 2017. Pursuant to the order, OTP’s allowed rate of return on rate base will decrease from 8.61% to 7.5056% and its allowed rate of return on equity will decrease from 10.74% to 9.41%. On July 6, 2017 the MPUC denied OTP’s request for reconsideration of certain of the MPUC’s rulings in the rate case and confirmed details of its May 1, 2017 order approving OTP’s request for a revenue increase in Minnesota.
The MPUC
’s order also included: (1) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South-Brookings and Big Stone South-Ellendale MVP projects will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s Minnesota customers, and (2) approval of OTP’s proposal to transition rate base, expenses and revenues from Environmental Cost Recovery (ECR) and TCR riders to base rate recovery, with the transition occurring when final rates are implemented. The rate base balances, expense levels and revenue levels existing in the riders at the time of implementation of final rates will be used to establish the amounts transitioned to base rates. Certain MISO expenses and revenues will remain in the TCR rider to allow for the ongoing refund or recovery of these variable revenues and costs.
Information on
interim and final rate increases and interim revenue refund accrued is detailed in the tables below:
($ in thousands)
|
|
Interim Rates Authorized
April 14, 2016
|
|
|
Final Rates
|
|
Revenue
Increase – Annualized based on Test Year Data
|
|
$
|
16,816
|
|
|
$
|
12,100
|
|
Revenue
Percent Increase
|
|
|
9.56
|
%
|
|
|
6.23
|
%
|
Return on Rate Base
|
|
|
8.07
|
%
|
|
|
7.5056
|
%
|
Jurisdictional Rate Base
based on Test Year Data
|
|
$
|
483,000
|
|
|
$
|
471,000
|
|
Return on Equity
|
|
|
10.1
|
%
|
|
|
9.41
|
%
|
Based on Equity to Total Capital of
|
|
|
52.50
|
%
|
|
|
52.50
|
%
|
Debt to Total Capital
|
|
|
47.50
|
%
|
|
|
47.50
|
%
|
Interim Revenue
(in thousands)
|
April 16, 2016 through
September 30, 2017
|
|
Billed
|
|
$
|
21,847
|
|
Accrued
Refund
|
|
$
|
8,237
|
|
Net Interim Revenue
|
|
$
|
13,610
|
|
Interest on Refundable Amount
|
|
$
|
233
|
|
Refund Liability as of
September 30, 2017
|
|
$
|
8,470
|
|
In addition to the interim rate refund, OTP will be required to refund the difference
between (1) amounts collected under its Minnesota
ECR and TCR riders based on the return on equity (ROE) approved in its most recent rider update and (2) amounts that would have been collected based on the lower 9.41% ROE approved in its 2016 general rate case going back to April 16, 2016, the date interim rates were implemented. As of September 30, 2017 the revenues collected under the Minnesota ECR and TCR riders subject to refund due to the lower ROE rate and other adjustments were $0.9 million and $1.4 million, respectively. These amounts will be refunded to Minnesota customers over a 12-month period through reductions in the Minnesota ECR and TCR rider rates that take effect November 1, 2017, as approved by the MPUC. The TCR rate is provisional and subject to revision under a separate docket.
OTP will continue to accrue the interim
and rider rate refunds until final rates become effective, for bills rendered on and after November 1, 2017.
The interim rate refund, including interest, will be applied as a credit to Minnesota customers’ electric bills beginning November 17, 2017.
Minnesota Conservation Improvement Programs
(MNCIP)
—OTP recovers conservation related costs not included in base rates under the MNCIP through the use of an annual recovery mechanism approved by the MPUC. On May 25, 2016 the MPUC adopted the Minnesota Department of Commerce’s (MNDOC’s) proposed changes to the MNCIP financial incentive. The new model provides utilities an incentive of 13.5% of 2017 net benefits, 12% of 2018 net benefits and 10% of 2019 net benefits, assuming the utility achieves 1.7% savings compared to retail sales. OTP estimates the impact of the new model will reduce the MNCIP financial incentive by approximately 50% compared to the previous incentive mechanism. MNCIP incentives include $5.0 million approved for 2016, $4.3 million approved for 2015 and $3.0 million approved for 2014.
Transmission Cost Recovery Rider
—The Minnesota Public Utilities Act provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs of new transmission facilities that meet certain criteria, plus a return on investment at the level approved in a utility’s last general rate case. Additionally, following approval of the rate schedule, the MPUC may approve annual rate adjustments filed pursuant to the rate schedule.
In OTP
’s 2016 general rate case order issued on May 1, 2017, the MPUC ordered OTP to include, in the TCR rider retail rate base, Minnesota’s jurisdictional share of OTP’s investment in the Big Stone South–Brookings and Big Stone South–Ellendale MVP Projects and all revenues received from other utilities under MISO’s tariffed rates as a credit in its TCR revenue requirement calculations. In doing so, the Commission’s Order diverts interstate wholesale revenues that have been approved by FERC to offset FERC-approved expenses, effectively reducing OTP’s recovery of those FERC-approved expense levels. The MPUC-ordered treatment will result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. On August 18, 2017 OTP filed an appeal of the MPUC order with the Minnesota Court of Appeals
to contest the portion of the order requiring OTP to allocate costs between jurisdictions of the FERC MVP transmission projects in the TCR rider. OTP believes the MPUC-ordered treatment conflicts with federal authority over transmission of electricity in interstate commerce and rates for the transmission of electricity subject to the jurisdiction of the FERC as set forth in the Federal Power Act of 1935, as amended (Federal Power Act).
Environmental Cost Recovery Rider
—OTP has an ECR rider for recovery of OTP’s Minnesota jurisdictional share of the revenue requirements of its investment in the Big Stone Plant Air Quality Control System (AQCS). The ECR rider provides for a return on the project’s construction work in progress (CWIP) balance at the level approved in OTP’s 2010 general rate case. In OTP’s 2016 general rate case, the MPUC approved OTP’s proposal to transition eligible rate base and expense recovery from the ECR rider to base rate recovery, with the transition occurring when final rates are implemented.
North Dakota
General Rates
—
O
n November 2, 2017 OTP filed a request with the NDPSC for a rate review and an increase in annual revenues from non-fuel base rates of $13.1 million or 8.7%. In the request, OTP proposed an allowed return on rate base of 7.97% and an allowed rate of return on equity of 10.30%. Pursuant to the request, an interim rate increase is expected to go into effect on January 1, 2018.
OTP
’s most recent general rate increase in North Dakota of $3.6 million, or approximately 3.0%, was granted by the NDPSC in an order issued on November 25, 2009 and effective December 2009. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.62%, and its allowed rate of return on equity was set at 10.75%.
Renewable Resource Adjustment
—OTP has a North Dakota Renewable Resource Adjustment which enables OTP to recover its North Dakota jurisdictional share of investments in renewable energy facilities. This rider allows OTP to recover costs associated with new renewable energy projects as they are completed, along with a return on investment.
Transmission Cost Recovery Rider
—North Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities. For qualifying projects, the law authorizes a current return on CWIP and a return on investment at the level approved in the utility's most recent general rate case.
Environmental Cost Recovery Rider
—OTP has an ECR rider in North Dakota to recover its North Dakota jurisdictional share of the revenue requirements associated with its investment in the Big Stone Plant AQCS
and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) projects. The ECR rider provides for a current return on CWIP and a return on investment at the level approved in OTP’s most recent general rate case.
South Dakota
2010 General Rate Case
—OTP’s most recent general rate increase in South Dakota of approximately $643,000 or approximately 2.32% was granted by the SDPUC in an order issued on April 21, 2011 and effective with bills rendered on and after June 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base was set at 8.50%.
Transmission Cost Recovery Rider
—South Dakota law provides a mechanism for automatic adjustment outside of a general rate proceeding to recover jurisdictional capital and operating costs incurred by a public utility for new or modified electric transmission facilities.
Environmental Cost Recovery Rider
—OTP has an ECR rider in South Dakota to recover its South Dakota jurisdictional share of revenue requirements associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects.
Rate
Rider Updates
The following table provides summary information on the status of updates
since January 1, 2015 for the rate riders described above:
Rate Rider
|
|
R - Request Date
A - Approval Date
|
|
Effective Date
Requested or Approved
|
|
Annual
Revenue
($000s)
|
|
Rate
|
Minnesota
|
|
|
|
|
|
|
|
|
|
Conservation Improvement Program
|
|
|
|
|
|
|
|
|
|
2016 Incentive and Cost Recovery
|
|
A
– September 15, 2017
|
|
October 1, 201
7
|
|
$
|
9,868
|
|
$0.00
536/kwh
|
2015 Incentive and Cost Recovery
|
|
A
– July 19, 2016
|
|
October 1, 2016
|
|
$
|
8,590
|
|
$0.00275/kwh
|
2014 Incentive and Cost Recovery
|
|
A
– July 10, 2015
|
|
October 1, 2015
|
|
$
|
8,689
|
|
$0.00287/kwh
|
Transmission Cost Recovery
|
|
|
|
|
|
|
|
|
|
2017 Rate Reset
1
|
|
A
– October 30, 2017
|
|
November 1, 2017
|
|
$
|
(3,311
|
)
|
Various
|
2016 Annual Update
|
|
A
– July 5, 2016
|
|
September 1, 2016
|
|
$
|
4,736
|
|
Various
|
2015 Annual Update
|
|
A
– March 9, 2016
|
|
April 1, 2016
|
|
$
|
7,203
|
|
Various
|
2014 Annual Update
|
|
A
– February 18, 2015
|
|
March 1, 2015
|
|
$
|
8,388
|
|
Various
|
Environmental Cost Recovery
|
|
|
|
|
|
|
|
|
|
2017 Rate Reset
|
|
A
– October 30, 2017
|
|
November 1, 2017
|
|
$
|
(1,943
|
)
|
-
0.935% of Rev
|
2016 Annual Update
|
|
A
– July 5, 2016
|
|
September 1, 2016
|
|
$
|
11,884
|
|
6.927% of Rev
|
2015 Annual Update
|
|
A
– March 9, 2016
|
|
October 1, 2015
|
|
$
|
12,104
|
|
7.006% of Rev
|
North Dakota
|
|
|
|
|
|
|
|
|
|
Renewable Resource Adjustment
|
|
|
|
|
|
|
|
|
|
201
6 Annual Update
|
|
A
– March 15, 2017
|
|
April 1, 2017
|
|
$
|
9,156
|
|
7.00
5% of Rev
|
2015 Annual Update
|
|
A
– June 22, 2016
|
|
July 1, 2016
|
|
$
|
9,262
|
|
7.
573% of Rev
|
201
4 Annual Update
|
|
A
– March 25, 2015
|
|
April 1, 2015
|
|
$
|
5,441
|
|
4.069% of Rev
|
Transmission Cost Recovery
|
|
|
|
|
|
|
|
|
|
201
7 Annual Update
|
|
R
– August 31, 2017
|
|
January 1, 2018
|
|
$
|
8,593
|
|
Various
|
201
6 Annual Update
|
|
A
– December 14, 2016
|
|
January 1, 2017
|
|
$
|
6,916
|
|
Various
|
2015 Annual Update
|
|
A
– December 16, 2015
|
|
January 1, 2016
|
|
$
|
9,985
|
|
Various
|
Environmental Cost Recovery
|
|
|
|
|
|
|
|
|
|
201
7 Annual Update
|
|
A
– July 12, 2017
|
|
August 1,
2017
|
|
$
|
9,917
|
|
7.633% of base
|
201
6 Annual Update
|
|
A
– June 22, 2016
|
|
July 1, 2016
|
|
$
|
10,359
|
|
7.
904% of base
|
2015 Annual Update
|
|
A
– June 17, 2015
|
|
July 1, 2015
|
|
$
|
12,249
|
|
9.193
% of base
|
South Dakota
|
|
|
|
|
|
|
|
|
|
Transmission Cost Recovery
|
|
|
|
|
|
|
|
|
|
201
6 Annual Update
|
|
A
– February 17, 2017
|
|
March 1, 2017
|
|
$
|
2,053
|
|
Various
|
2015 Annual Update
|
|
A
– February 12, 2016
|
|
March 1, 2016
|
|
$
|
1,895
|
|
Various
|
2014 Annual Update
|
|
A
– February 13, 2015
|
|
March 1, 2015
|
|
$
|
1,538
|
|
Various
|
Environmental Cost Recovery
|
|
|
|
|
|
|
|
|
|
2017 Annual Update
|
|
A
– October 13, 2017
|
|
November 1, 2017
|
|
$
|
2,082
|
|
$0.00
483/kwh
|
201
6 Annual Update
|
|
A
– October 26, 2016
|
|
November 1, 2016
|
|
$
|
2,238
|
|
$0.00536/kwh
|
201
5 Annual Update
|
|
A
– October 15, 2015
|
|
November 1, 2015
|
|
$
|
2,728
|
|
$0.00643/kwh
|
1
Approved on a provisional basis
in the Minnesota general rate case docket
and subject to
revision
in a separate docket
.
The following table presents revenue recorded by OTP under
rate riders in place in Minnesota, North Dakota and South Dakota:
Revenues
Recorded under Rider Rates
|
|
Three Months Ended
September 30,
|
|
|
Nine
Months Ended
September 30,
|
|
Rate Rider
(in thousands)
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
2016
|
|
Minnesota
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conservation Improvement Program Costs and Incentives
1
|
|
$
|
2,499
|
|
|
$
|
2,839
|
|
|
$
|
6,567
|
|
|
$
|
7,554
|
|
Transmission Cost Recovery
|
|
|
(594
|
)
|
|
|
779
|
|
|
|
2,849
|
|
|
|
4,188
|
|
Environmental Cost Recovery
|
|
|
1,669
|
|
|
|
3,127
|
|
|
|
7,305
|
|
|
|
9,362
|
|
North Dakota
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Renewable Resource Adjustment
|
|
|
2,213
|
|
|
|
2,170
|
|
|
|
5,822
|
|
|
|
6,151
|
|
Transmission Cost Recovery
|
|
|
2,410
|
|
|
|
1,950
|
|
|
|
6,305
|
|
|
|
6,155
|
|
Environmental Cost Recovery
|
|
|
2,396
|
|
|
|
2,762
|
|
|
|
7,272
|
|
|
|
8,344
|
|
South Dakota
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission Cost Recovery
|
|
|
596
|
|
|
|
335
|
|
|
|
1,324
|
|
|
|
1,397
|
|
Environmental Cost Recovery
|
|
|
613
|
|
|
|
691
|
|
|
|
1,755
|
|
|
|
1,951
|
|
Conservation Improvement Program Costs and Incentives
|
|
|
104
|
|
|
|
135
|
|
|
|
520
|
|
|
|
418
|
|
1
Includes MNCIP costs recovered in base rates.
FERC
Wholesale power sales and transmission rates are subject to the jurisdiction of the FERC under the Federal Power Act. The FERC is an independent agency with jurisdiction over rates for wholesale electricity sales, transmission and sale of electric energy in interstate commerce, interconnection of facilities, and accounting policies and practices. Filed rates are effective after a one day suspension period, subject to ultimate approval by the FERC.
Multi-Value Transmission Projects
—On December 16, 2010 the FERC approved the cost allocation for a new classification of projects in the MISO region called MVPs. MVPs are designed to enable the region to comply with energy policy mandates and to address reliability and economic issues affecting multiple transmission zones within the MISO region. The cost allocation is designed to ensure that the costs of transmission projects with regional benefits are properly assigned to those who benefit.
On November 12, 2013 a group of industrial customers and other stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff. The complainants sought to reduce the 12.38% ROE used in MISO
’s transmission rates to a proposed 9.15%. The complaint established a 15-month refund period from November 12, 2013 to February 11, 2015. A non-binding decision by the presiding Administrative Law Judge (ALJ) was issued on December 22, 2015 finding that the MISO transmission owners’ ROE should be 10.32%, and the FERC issued an order on September 28, 2016 setting the base ROE at 10.32%. A number of parties requested rehearing of the September 2016 order and the requests are pending FERC action.
On November 6, 2014 a group of MISO transmission owners, including OTP, filed for a FERC incentive of an additional 50-basis points for Regional Transmission Organization participation (RTO Adder). On January 5, 2015 the FERC granted the request, deferring collection of the RTO Adder until the FERC issued its order in the ROE complaint proceeding. Based on the FERC adjustment to the MISO Tariff ROE resulting from the November 12, 2013 complaint and OTP
’s incentive rate filing, OTP’s ROE will be 10.82% (a 10.32% base ROE plus the 0.5% RTO Adder) effective September 28, 2016.
On February 12, 2015 another group of stakeholders filed a complaint with the FERC seeking to reduce the ROE component of the transmission rates that MISO transmission owners, including OTP, may collect under the MISO Tariff from 12.38% to a proposed 8.67%. This second complaint established a second 15-month refund period from February 12, 2015 to May 11, 2016. The FERC issued an order on June 18, 2015 setting the complaint for hearings before an ALJ, which were held the week of February 16, 2016. A non-binding decision by the presiding ALJ was issued on June 30, 2016 finding that the MISO transmission owners
’ ROE should be 9.7%. OTP is currently waiting for the issuance of a FERC order on the second complaint.
Based on
the probable reduction by the FERC in the ROE component of the MISO Tariff, OTP had a $2.7 million liability on its balance sheet as of December 31, 2016, representing OTP’s best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on a reduced ROE. MISO processed the refund for the FERC ordered reduction in the MISO tariff allowed ROE for the first 15-month refund period in its February and June 2017 billings. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, has resulted in a reduction in OTP’s accrued MISO tariff ROE refund liability from $2.7 million on December 31, 2016 to $1.6 million as of September 30, 2017.
In June 2014, the FERC adopted a two-step ROE methodology for electric utilities in an order issued in a complaint
proceeding involving New England Transmission Owners (NETOs). The issue of how to apply the FERC ROE methodology has been contested in various complaint proceedings, including the two ROE complaints involving MISO transmission owners discussed above. In April 2017 the Court of Appeals for the District of Columbia (D.C. Circuit) vacated and remanded the FERC’s June 2014 ROE order in the NETOs’ complaint. The D.C. Circuit found that the FERC had not properly determined that the ROE authorized for NETOs prior to June 2014 was unjust and unreasonable. The D.C. Circuit also found that the FERC failed to justify the new ROE methodology. OTP will await the FERC response to the April 2017 action of the D.C. Circuit before determining if an adjustment to its accrued refund liability is required.
On September 29, 2017 the MISO transmission owners filed a motion to dismiss the second complaint based on the D.C. Circuit decision in the NETO complaint. If FERC grants the motion to dismiss, it would eliminate the refund obligation from the second complaint and the ROE from the first complaint would remain in effect.
4. Regulatory Assets and Liabilities
As a regulated
entity, OTP accounts for the financial effects of regulation in accordance with ASC Topic 980,
Regulated Operations
(ASC 980). This accounting standard allows for the recording of a regulatory asset or liability for costs that will be collected or refunded in the future as required under regulation. Additionally, ASC 980-605-25 provides for the recognition of revenues authorized for recovery outside of a general rate case under alternative revenue programs which provide for recovery of costs and incentives or returns on investment in such items as transmission infrastructure, renewable energy resources or conservation initiatives. The following tables indicate the amount of regulatory assets and liabilities recorded on the Company’s consolidated balance sheets:
|
|
September
30, 2017
|
|
|
Remaining Recovery/
|
|
(in thousands)
|
|
Current
|
|
|
Long-Term
|
|
|
Total
|
|
|
|
Refund Period
(months)
|
|
Regulatory Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
1
|
|
$
|
6,444
|
|
|
$
|
103,434
|
|
|
$
|
109,878
|
|
|
see below
|
|
Conservation Improvement Program Costs and Incentives
2
|
|
|
8,230
|
|
|
|
2,351
|
|
|
|
10,581
|
|
|
|
24
|
|
Deferred Marked-to-Market Losses
1
|
|
|
4,063
|
|
|
|
3,420
|
|
|
|
7,483
|
|
|
|
39
|
|
Accumulated ARO Accretion/Depreciation Adjustment
1
|
|
|
--
|
|
|
|
6,525
|
|
|
|
6,525
|
|
|
asset lives
|
|
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
2
|
|
|
88
|
|
|
|
2,432
|
|
|
|
2,520
|
|
|
|
27
|
|
Big Stone II Unrecovered Project Costs
– Minnesota
1
|
|
|
658
|
|
|
|
1,597
|
|
|
|
2,255
|
|
|
|
43
|
|
Debt Reacquisition Premiums
1
|
|
|
252
|
|
|
|
1,026
|
|
|
|
1,278
|
|
|
|
180
|
|
Recoverable Fuel and Purchased Power Costs
1
|
|
|
885
|
|
|
|
--
|
|
|
|
885
|
|
|
|
12
|
|
Deferred Income Taxes
1
|
|
|
--
|
|
|
|
833
|
|
|
|
833
|
|
|
asset lives
|
|
North Dakota Renewable Resource Rider Accrued Revenues
2
|
|
|
189
|
|
|
|
585
|
|
|
|
774
|
|
|
|
18
|
|
Big Stone II Unrecovered Project Costs
– South Dakota
2
|
|
|
100
|
|
|
|
467
|
|
|
|
567
|
|
|
|
68
|
|
Minnesota Deferred Rate Case Expenses Subject to Recovery
1
|
|
|
496
|
|
|
|
--
|
|
|
|
496
|
|
|
|
7
|
|
North Dakota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
142
|
|
|
|
--
|
|
|
|
142
|
|
|
|
3
|
|
South Dakota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
35
|
|
|
|
--
|
|
|
|
35
|
|
|
|
3
|
|
Total Regulatory Assets
|
|
$
|
21,582
|
|
|
$
|
122,670
|
|
|
$
|
144,252
|
|
|
|
|
|
Regulatory Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Reserve for Estimated Removal Costs
– Net of Salvage
|
|
$
|
--
|
|
|
$
|
82,485
|
|
|
$
|
82,485
|
|
|
asset lives
|
|
Minnesota
Transmission Cost Recovery Rider Accrued Refund
|
|
|
1,808
|
|
|
|
616
|
|
|
|
2,424
|
|
|
|
24
|
|
Minnesota Environmental Cost Recovery Rider Accrued Refund
|
|
|
1,722
|
|
|
|
--
|
|
|
|
1,722
|
|
|
|
12
|
|
North Dakota Transmission Cost Recovery Rider Accrued Refund
|
|
|
716
|
|
|
|
342
|
|
|
|
1,058
|
|
|
|
15
|
|
Deferred Income Taxes
|
|
|
--
|
|
|
|
720
|
|
|
|
720
|
|
|
asset lives
|
|
Revenue for Rate Case Expenses Subject to Refund
– Minnesota
|
|
|
385
|
|
|
|
--
|
|
|
|
385
|
|
|
|
7
|
|
South Dakota Environmental Cost Recovery Rider Accrued Refund
|
|
|
252
|
|
|
|
--
|
|
|
|
252
|
|
|
|
12
|
|
Sout
h Dakota Transmission Cost Recovery Rider Accrued Refund
|
|
|
172
|
|
|
|
--
|
|
|
|
172
|
|
|
|
12
|
|
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
|
|
|
99
|
|
|
|
33
|
|
|
|
132
|
|
|
|
15
|
|
Other
|
|
|
6
|
|
|
|
85
|
|
|
|
91
|
|
|
|
195
|
|
Nort
h Dakota Environmental Cost Recovery Rider Accrued Refund
|
|
|
43
|
|
|
|
--
|
|
|
|
43
|
|
|
|
12
|
|
Total Regulatory Liabilities
|
|
$
|
5,203
|
|
|
$
|
84,281
|
|
|
$
|
89,484
|
|
|
|
|
|
Net Regulatory Asset Position
|
|
$
|
16,379
|
|
|
$
|
38,389
|
|
|
$
|
54,768
|
|
|
|
|
|
1
Costs subject to recovery without a rate of return.
2
Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
|
|
December 31, 2016
|
|
|
Remaining
Recovery/
|
|
(in thousands)
|
|
Current
|
|
|
Long-Term
|
|
|
Total
|
|
|
|
|
|
Regulatory Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
1
|
|
$
|
6,443
|
|
|
$
|
108,267
|
|
|
$
|
114,710
|
|
|
see below
|
|
Conservation Improvement Program Costs and Incentives
2
|
|
|
4,836
|
|
|
|
5,158
|
|
|
|
9,994
|
|
|
|
21
|
|
Deferred Marked-to-Market Losses
1
|
|
|
4,063
|
|
|
|
6,467
|
|
|
|
10,530
|
|
|
|
48
|
|
Accumulated ARO Accretion/Depreciation Adjustment
1
|
|
|
--
|
|
|
|
6,153
|
|
|
|
6,153
|
|
|
asset lives
|
|
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
2
|
|
|
333
|
|
|
|
--
|
|
|
|
333
|
|
|
|
12
|
|
Big Stone II Unrecovered Project Costs
– Minnesota
1
|
|
|
778
|
|
|
|
2,087
|
|
|
|
2,865
|
|
|
|
52
|
|
Debt Reacquisition Premiums
1
|
|
|
325
|
|
|
|
1,214
|
|
|
|
1,539
|
|
|
|
189
|
|
Recoverable Fuel and Purchased Power Costs
1
|
|
|
1,798
|
|
|
|
--
|
|
|
|
1,798
|
|
|
|
12
|
|
Deferred Income Taxes
1
|
|
|
--
|
|
|
|
1,014
|
|
|
|
1,014
|
|
|
asset lives
|
|
North Dakota Renewable Resource Rider Accrued Revenues
2
|
|
|
1,319
|
|
|
|
482
|
|
|
|
1,801
|
|
|
|
15
|
|
Big Stone II Unrecovered Project Costs
– South Dakota
2
|
|
|
100
|
|
|
|
543
|
|
|
|
643
|
|
|
|
77
|
|
Minnesota Deferred Rate Case Expenses Subject to Recovery
1
|
|
|
1,082
|
|
|
|
--
|
|
|
|
1,082
|
|
|
|
12
|
|
North Dakota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
--
|
|
|
|
568
|
|
|
|
568
|
|
|
|
24
|
|
South Dakota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
73
|
|
|
|
141
|
|
|
|
214
|
|
|
|
14
|
|
North Dakota Environmental Cost Recovery Rider Accrued Revenues
2
|
|
|
113
|
|
|
|
--
|
|
|
|
113
|
|
|
|
12
|
|
Minnesota Renewable Resource Rider Accrued Revenues
2
|
|
|
34
|
|
|
|
--
|
|
|
|
34
|
|
|
|
9
|
|
Total Regulatory Assets
|
|
$
|
21,297
|
|
|
$
|
132,094
|
|
|
$
|
153,391
|
|
|
|
|
|
Regulatory Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Reserve for Estimated Removal Costs
– Net of Salvage
|
|
$
|
--
|
|
|
$
|
80,404
|
|
|
$
|
80,404
|
|
|
asset lives
|
|
Minnesota Transmission Cost Recovery Rider Accrued Refund
|
|
|
757
|
|
|
|
--
|
|
|
|
757
|
|
|
|
12
|
|
Minnesota Environmental Cost Recovery Rider Accrued Refund
|
|
|
139
|
|
|
|
--
|
|
|
|
139
|
|
|
|
12
|
|
North Dakota Transmission Cost Recovery Rider Accrued Refund
|
|
|
1,381
|
|
|
|
782
|
|
|
|
2,163
|
|
|
|
24
|
|
Deferred Income Taxes
|
|
|
--
|
|
|
|
818
|
|
|
|
818
|
|
|
asset lives
|
|
Revenue for Rate Case Expenses Subject to Refund
– Minnesota
|
|
|
711
|
|
|
|
208
|
|
|
|
919
|
|
|
|
16
|
|
South Dakota Environmental Cost Recovery Rider Accrued Refund
|
|
|
285
|
|
|
|
--
|
|
|
|
285
|
|
|
|
12
|
|
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
|
|
|
--
|
|
|
|
132
|
|
|
|
132
|
|
|
|
24
|
|
Other
|
|
|
21
|
|
|
|
89
|
|
|
|
110
|
|
|
|
204
|
|
Total Regulatory Liabilities
|
|
$
|
3,294
|
|
|
$
|
82,433
|
|
|
$
|
85,727
|
|
|
|
|
|
Net Regulatory Asset Position
|
|
$
|
18,003
|
|
|
$
|
49,661
|
|
|
$
|
67,664
|
|
|
|
|
|
1
Costs subject to recovery without a rate of return.
2
Amount eligible for recovery under an alternative revenue program which includes an incentive or rate of return.
The regulatory asset related to prior service costs and actuarial losses on pensions and other postretirement benefits represents benefit costs and actuarial losses subject to recovery through rates as they are expensed over the remaining service lives of active employees included in the plans. These unrecognized benefit costs and actuarial losses are required to be recognized as components of Accumulated Other Comprehensive Income in equity under ASC Topic 715,
Compensation—Retirement Benefits
, but are eligible for treatment as regulatory assets based on their probable recovery in future retail electric rates.
Conservation Improvement Program Costs and Incentives represent mandated conservation expenditures and incentives recoverable through retail electric rates.
All Deferred Marked-to-Market Losses recorded as of
September 30, 2017 relate to forward purchases of energy scheduled for delivery through December 2020.
The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.
MISO Schedule 26/26A Transmission Cost Recovery Rider True-ups relate to the over/under collection of revenue based on comparison of the expected versus actual construction on eligible projects in the period. The true-ups also include the state jurisdictional portion of MISO Schedule 26/26A for regional transmission cost recovery that was included in the calculation of the state transmission riders and subsequently adjusted to reflect actual billing amounts in the schedule.
Big Stone II Unrecovered Project Costs
– Minnesota are the Minnesota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project.
Debt Reacquisition Premiums are being recovered from OTP customers over the remaining original lives of the reacquired debt issues, the longest of which is 18
0 months.
The regulatory assets and liabilities related to Deferred Income Taxes result from changes in statutory tax rates accounted for in accordance with ASC Topic 740,
Income Taxes
.
North Dakota Renewable Resource Rider Accrued Revenues relate to qualifying renewable resource costs incurred to serve North Dakota customers that have not been billed to North Dakota customers as of
September 30, 2017.
Big Stone II Unrecovered Project Costs
– South Dakota are the South Dakota share of generation and transmission plant-related costs incurred by OTP related to its participation in the abandoned Big Stone II project.
Minnesota Deferred Rate Case Expenses Subject to Recovery relate to costs incurred in conjunction with OTP
’s 2016 rate case in Minnesota currently being recovered over a 24-month period beginning with the establishment of interim rates in April 2016.
The North Dakota Transmission
Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to North Dakota customers as of September 30, 2017.
The South Dakota Transmission
Cost Recovery Rider Accrued Revenues relate to revenues earned on qualifying transmission system facilities that have not been billed to South Dakota customers as of September 30, 2017.
Minnesota Renewable Resource Rider Accrued Revenues relate to revenues earned on qualifying renewable resource costs incurred to serve Minnesota customers that have not been billed to Minnesota customers. On April 4, 2013 the MPUC approved OTP
’s request to set the rider rate to zero effective May 1, 2013 and authorized that any unrecovered balance be retained as a regulatory asset to be recovered over an 18-month period beginning with the establishment of interim rates in April 2016.
The Accumulated Reserve for Estimated Removal Costs
– Net of Salvage is reduced as actual removal costs, net of salvage revenues, are incurred.
The
Minnesota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that are refundable to Minnesota customers as of September 30, 2017.
The Minnesota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the Minnesota share of OTP
’s investment in the Big Stone Plant AQCS project
that are refundable to Minnesota customers as of September 30, 2017.
The North Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve North Dakota customers that are refundable to North Dakota customers as of
September 30, 2017.
Revenue for Rate Case Expenses Subject to Refund
– Minnesota relates to revenues collected under general rates to recover costs related to prior rate case proceedings in excess of the actual costs incurred, which are subject to refund over a 24-month period beginning with the establishment of interim rates in April 2016.
The South Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the South Dakota share of OTP
’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to South Dakota customers as of September 30, 2017.
The
South Dakota Transmission Cost Recovery Rider Accrued Refund relates to amounts collected for qualifying transmission system facilities and operating costs incurred to serve South Dakota customers that are refundable to South Dakota customers as of September 30, 2017.
The
North Dakota Environmental Cost Recovery Rider Accrued Refund relates to amounts collected on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects that are refundable to North Dakota customers as of September 30, 2017.
If for any reason OTP ceases to meet the criteria for application of guidance under ASC 980 for all or part of its operations, the regulatory assets and liabilities that no longer meet such criteria would be removed from the consolidated balance sheet and included in the consolidated statement of income as an expense or income item in the period in which the application of guidance under ASC 980 ceases.
5.
Open
Contract
Position
s
Subject to Legally Enforceable Netting Arrangements
OTP has certain derivative contracts that are designated as normal purchases. Individual counterparty exposures for these contracts can be offset according to legally enforceable netting arrangements. The following table shows the current fair value of these forward contract positions subject to legally enforceable netting arrangements as of
September 30, 2017 and December 31, 2016:
(in thousands)
|
|
September
30,
201
7
|
|
|
December 31,
201
6
|
|
Open Contract Gain Positions
Subject to Legally Enforceable Netting Arrangements
|
|
$
|
--
|
|
|
$
|
--
|
|
Open Contract Loss Positions
Subject to Legally Enforceable Netting Arrangements
|
|
|
(13,591
|
)
|
|
|
(17,382
|
)
|
Net Balance
Subject to Legally Enforceable Netting Arrangements
|
|
$
|
(13,591
|
)
|
|
$
|
(17,382
|
)
|
The following table provides a breakdown of OTP
’s credit risk standing on forward energy contracts in marked-to-market loss positions as of September 30, 2017 and December 31, 2016:
(in thousands)
|
|
September
30,
2017
|
|
|
December 31,
2016
|
|
Loss Contracts Covered by Deposited Funds or Letters of Credit
|
|
$
|
--
|
|
|
$
|
--
|
|
Contracts Requiring Cash Deposits if OTP
’s Credit Falls Below Investment Grade
1
|
|
|
13,591
|
|
|
|
17,382
|
|
Total Loss Contracts based on Current Market Values
|
|
$
|
13,591
|
|
|
$
|
17,382
|
|
1
Certain OTP derivative energy contracts contain provisions that require an investment grade credit rating from each of the major credit rating agencies on OTP’s debt. If OTP’s debt ratings were to fall below investment grade, the counterparties to these forward energy contracts could request the immediate deposit of cash to cover contracts in net liability positions.
|
|
|
|
|
|
|
|
|
Contracts Requiring Cash Deposits if OTP
’s Credit Falls Below Investment Grade
|
|
$
|
13,591
|
|
|
$
|
17,382
|
|
Offsetting Gains with Counterparties under Master Netting Agreements
|
|
|
--
|
|
|
|
--
|
|
Reporting Date Deposit Requirement if Credit Risk Feature Triggered
|
|
$
|
13,591
|
|
|
$
|
17,382
|
|
6. Reconciliation of Common Shareholders
’ Equity, Common Shares and Earnings Per Share
Reconciliation of Common Shareholders
’ Equity
(in thousands)
|
|
Par Value,
Common
Shares
|
|
|
Premium
on
Common
Shares
|
|
|
Retained
Earnings
|
|
|
Accumulated
Other Comprehensive Income/(Loss)
|
|
|
Total
Common
Equity
|
|
Balance, December 31, 201
6
|
|
$
|
196,741
|
|
|
$
|
337,684
|
|
|
$
|
139,479
|
|
|
$
|
(3,800
|
)
|
|
$
|
670,104
|
|
Common Stock Issuances, Net of Expenses
|
|
|
1,285
|
|
|
|
3,684
|
|
|
|
|
|
|
|
|
|
|
|
4,969
|
|
Common Stock Retirements
|
|
|
(239
|
)
|
|
|
(1,560
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,799
|
)
|
Net Income
|
|
|
|
|
|
|
|
|
|
|
54,097
|
|
|
|
|
|
|
|
54,097
|
|
Other Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
341
|
|
|
|
341
|
|
Employee Stock Incentive Plan
s Expense
|
|
|
|
|
|
|
2,765
|
|
|
|
|
|
|
|
|
|
|
|
2,765
|
|
Common Dividends ($0.
96 per share)
|
|
|
|
|
|
|
|
|
|
|
(37,958
|
)
|
|
|
|
|
|
|
(37,958
|
)
|
Balance,
September 30, 2017
|
|
$
|
197,787
|
|
|
$
|
342,573
|
|
|
$
|
155,618
|
|
|
$
|
(3,459
|
)
|
|
$
|
692,519
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shelf Registration
and Common Share Distribution Agreement
The Company
’s shelf registration statement filed with the Securities and Exchange Commission on May 11, 2015, under which the Company may offer for sale, from time to time, either separately or together in any combination, equity, debt or other securities described in the shelf registration statement, including common shares of the Company, expires on May 11, 2018.
On May 11, 2015, the Company entered into a Distribution Agreement with J.P. Morgan Securities (JPMS) under which it may offer and sell its common shares from time to time in an At-the-Market offering program through JPMS, as its distribution agent, up to an aggregate sales price of $75 million.
Common Shares
Following is a reconciliation of the Company
’s common shares outstanding from December 31, 2016 through September 30, 2017:
Common Shares Outstanding December 31, 201
6
|
|
|
39,348,136
|
|
Issuances:
|
|
|
|
|
Executive Stock Performance Awards
(2014 shares earned)
|
|
|
89,291
|
|
Automatic Dividend Reinvestment and Share Purchase Plan:
|
|
|
|
|
Dividends Reinvested
|
|
|
68,235
|
|
Cash Invested
|
|
|
29,463
|
|
Vesting of Restricted Stock Units
|
|
|
22,225
|
|
Restricted Stock
Issued to Directors
|
|
|
17,600
|
|
Employee Stock Ownership Plan
|
|
|
14,835
|
|
Employee Stock Purchase Plan:
|
|
|
|
|
Dividends Reinvested
|
|
|
9,566
|
|
Cash Invested
|
|
|
5,284
|
|
Directors Deferred Compensation
|
|
|
560
|
|
Retirements:
|
|
|
|
|
Shares Withheld for Individual Income Tax Requirements
|
|
|
(47,704
|
)
|
Common Shares Outstanding
September 30, 2017
|
|
|
39,557,491
|
|
Earnings Per Share
The numerator used in the calculation of both basic and diluted earnings per common share is net income for the three
- and nine-month periods ended September 30, 2017 and 2016. The denominator used in the calculation of basic earnings per common share is the weighted average number of common shares outstanding during the period excluding nonvested restricted shares granted to the Company’s directors and employees, which are considered contingently returnable and not outstanding for the purpose of calculating basic earnings per share. The denominator used in the calculation of diluted earnings per common share is derived by adjusting basic shares outstanding for the items listed in the following reconciliation:
|
|
Three Months ended
September
30
|
|
|
Nine
Months ended
September
30
|
|
|
|
201
7
|
|
|
201
6
|
|
|
201
7
|
|
|
201
6
|
|
Weighted Average Common Shares Outstanding
– Basic
|
|
|
39,507,581
|
|
|
|
38,832,659
|
|
|
|
39,440,416
|
|
|
|
38,316,324
|
|
Plus Outstanding Share Awards net of Share Reductions for Unrecognized Stock-Based Compensation Expense and Excess Tax Benefits:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares Expected to be Awarded for Stock Performance Awards Granted to Executive Officers based on Measurement Period-to-Date Performance
|
|
|
211,996
|
|
|
|
103,084
|
|
|
|
195,869
|
|
|
|
80,450
|
|
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees
|
|
|
55,975
|
|
|
|
48,645
|
|
|
|
54,645
|
|
|
|
42,620
|
|
Nonvested Restricted Shares
|
|
|
16,982
|
|
|
|
18,029
|
|
|
|
18,923
|
|
|
|
14,556
|
|
Shares Expected to be Issued Under the Deferred Compensation Program for Directors
|
|
|
2,832
|
|
|
|
3,289
|
|
|
|
3,009
|
|
|
|
3,451
|
|
Total Dilutive Shares
|
|
|
287,785
|
|
|
|
173,047
|
|
|
|
272,446
|
|
|
|
141,077
|
|
Weighted Average Common Shares Outstanding
– Diluted
|
|
|
39,795,366
|
|
|
|
39,005,706
|
|
|
|
39,712,862
|
|
|
|
38,457,401
|
|
The effect of dilutive shares on earnings per share for the three
- and nine-month periods ended September 30, 2017 and 2016, resulted in no differences greater than $0.01 between basic and diluted earnings per share in total or from continuing or discontinued operations in either period.
7. Share-Based Payments
Stock Incentive Awards
T
he following stock incentive awards were granted under the 2014 Stock Incentive Plan during the nine-month period ended September 30, 2017:
Award
|
Grant-Date
|
|
Shares/Units
Granted
|
|
|
Weighted Average Grant-Date Fair Value per Award
|
|
Vesting
|
Stock Performance Awards Granted
to Executive Officers
|
February 2, 2017
|
|
|
59,500
|
|
|
$
|
31.00
|
|
December 31, 2019
|
Restricted Stock Units Granted
to Executive Officers
|
February 2, 2017
|
|
|
15,900
|
|
|
$
|
37.65
|
|
25% per year through February 6, 2021
|
Restricted Stock Units Granted to Key Employees
|
April 10, 2017
|
|
|
9,995
|
|
|
$
|
32.78
|
|
100% on April 8, 20
21
|
|
September 25, 2017
|
|
|
1,000
|
|
|
$
|
38.29
|
|
100% on April 8, 2021
|
Restricted Stock Granted to Nonemployee Directors
|
April 10, 2017
|
|
|
17,600
|
|
|
$
|
37.75
|
|
25% per year through April 8, 20
21
|
Under the performance share awards
, the aggregate award for performance at target is 59,500 shares. For target performance the participants would earn an aggregate of 39,667 common shares based on the Company’s total shareholder return relative to the total shareholder return of the companies that comprise the Edison Electric Institute Index over the performance measurement period of January 1, 2017 through December 31, 2019, with the beginning and ending share values based on the average closing price of a share of the Company’s common stock for the 20 trading days immediately following January 1, 2017 and the average closing price for the 20 trading days immediately preceding January 1, 2020. The participants would also earn an aggregate of 19,833 common shares for achieving the target set for the Company’s 3-year average adjusted ROE. Actual payment may range from zero to 150% of the target amount, or up to 89,250 common shares. There are no voting or dividend rights related to the performance shares until common shares, if any, are issued at the end of the performance measurement period. The amount of payment in the event of retirement, resignation for good reason or involuntary termination without cause is to be made at the end of the performance period based on actual performance, subject to proration in certain cases, except that the payment of performance awards granted to certain officers who are parties to Executive Employment Agreements with the Company is to be made at target at the date of any such event. The vesting of these performance awards is accelerated and paid at target in the event of a change in control, disability or death and on retirement at or after age 62 for certain officers who are parties to executive employment agreements with the Company. The terms of these awards are such that the entire award will be classified and accounted for as equity, as required under ASC 718, and recognized over the grantee’s requisite service period based on the grant-date fair value of the award.
The vesting of restricted stock units is accelerated in the event of a change in control, disability, death or retirement, subject to proration in certain cases. All restricted stock units granted to executive officers are eligible to receive dividend equivalent payments on all unvested awards over the awards respective vesting periods, subject to forfeiture under the terms of the restricted stock unit award agreements. The grant-date fair value of each restricted stock unit
granted to an executive officer was the average of the high and low market price of one share of the Company’s common stock on the date of grant.
The grant-date fair value of each restricted stock unit granted to a key employee that is not an executive officer was based on the average of the high and low market price of one share of the Company’s common stock on the date of grant, discounted for the value of the dividend exclusion on those restricted stock units over the respective vesting periods.
The restricted shares granted to the Company
’s nonemployee directors are eligible for full dividend and voting rights. Restricted shares not vested and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreements. The grant-date fair value of each restricted share was the average of the high and low market price of one share of the Company’s common stock on the date of grant.
The end of the period over which compensation expense is recognized for the above share-based awards for the individual grantees is the shorter of the indicated vesting period for the respective awards or the date the grantee becomes eligible for retirement as defined in their award agreement.
As of
September 30, 2017 the remaining unrecognized compensation expense related to outstanding, unvested stock-based compensation was approximately $4.9 million (before income taxes) which will be amortized over a weighted-average period of 2.2 years.
Amounts of compensation expense recognized under the Company
’s six stock-based payment programs for the three- and nine-month periods ended September 30, 2017 and 2016 are presented in the table below:
|
|
Three Months Ended
September 30,
|
|
|
Nine
Months Ended
September 30,
|
|
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
|
201
7
|
|
|
201
6
|
|
Stock Performance Awards Granted to Executive Officers
|
|
$
|
494
|
|
|
$
|
455
|
|
|
$
|
1,568
|
|
|
$
|
1,296
|
|
Restricted Stock Units Granted to Executive Officers
|
|
|
104
|
|
|
|
64
|
|
|
|
472
|
|
|
|
373
|
|
Restricted Stock Granted to Executive Officers
|
|
|
16
|
|
|
|
22
|
|
|
|
54
|
|
|
|
73
|
|
Restricted Stock Granted to
Nonemployee Directors
|
|
|
144
|
|
|
|
128
|
|
|
|
416
|
|
|
|
363
|
|
Restricted Stock Units Granted to
Key Employees
|
|
|
87
|
|
|
|
62
|
|
|
|
255
|
|
|
|
207
|
|
Employee Stock Purchase Plan (15% discount)
|
|
|
--
|
|
|
|
47
|
|
|
|
--
|
|
|
|
135
|
|
Totals
|
|
$
|
845
|
|
|
$
|
778
|
|
|
$
|
2,765
|
|
|
$
|
2,447
|
|
8. Retained Earnings Restriction
The Company is a holding company with no significant operations of its own. The primary source of funds for payments of dividends to the Company
’s shareholders is from dividends paid or distributions made by the Company’s subsidiaries. As a result of certain statutory limitations or regulatory or financing agreements, restrictions could occur on the amount of distributions allowed to be made by the Company’s subsidiaries.
Both the Company and OTP
debt agreements contain restrictions on the payment of cash dividends upon a default or event of default. An event of default would be considered to have occurred if the Company did not meet certain financial covenants. As of September 30, 2017 the Company was in compliance with these financial covenants. See note 10 to the Company’s consolidated financial statements on Form 10-K for the year ended December 31, 2016 for further information on the covenants.
Under the Federal Power Act, a public utility may not pay dividends from any funds properly included in a capital account. What constitutes “funds properly included in a capital account” is undefined in the Federal Power Act or the related regulations; however, the FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials.
The MPUC indirectly limits the amount of dividends OTP can pay to the Company by requiring an equity
-to-total-capitalization ratio between 47.4% and 58.0% based on OTP’s 2017 capital structure petition approved by order of the MPUC on September 1, 2017. As of September 30, 2017 OTP’s equity-to-total-capitalization ratio including short-term debt was 51.8% and its net assets restricted from distribution totaled approximately $462,000,000. Total capitalization for OTP cannot currently exceed $1,178,024,000.
9. Commitments and Contingencies
Construction and Other Purchase Commitments
At December 31, 201
6 OTP had commitments under contracts extending into 2019, including its share of construction program commitments, totaling approximately $84.8 million. At September 30, 2017 OTP had commitments under contracts extending into 2019, including its share of construction program commitments, totaling approximately $82.6 million.
Electric Utility Capacity and Energy Requirements and Coal and Delivery Contracts
OTP has commitments for the purchase of capacity and energy requirements under agreements extending into 2040. OTP has contracts providing for the purchase and delivery of a significant portion of its current coal requirements. OTP
’s current coal purchase agreements for Big Stone Plant and Coyote Station expire at the end of 2019 and 2040, respectively. In the first quarter of 2017
a portion of the coal supply for Big Stone Plant contracted for delivery in 2016 was rolled into 2018
and some additional coal was contracted for delivery in 2018 and 2019. These arrangements result in an additional commitment for the purchase of coal in 2018 and 2019 totaling approximately $3.0 million. OTP has an agreement with Cloud Peak Energy Resources LLC for the purchase of subbituminous coal for Hoot Lake Plant through December 31, 2023. OTP has no fixed minimum purchase requirements under the agreement, but all of Hoot Lake Plant’s coal requirements for the period covered must be purchased under this agreement.
Operating Leases
OTP has obligations to make future operating lease payments primarily related to land leases and coal rail-car leases. The Company
’s nonelectric companies have obligations to make future operating lease payments primarily related to leases of buildings and manufacturing equipment.
Contingencies
OTP had a $2.7 million
refund liability on its balance sheet as of December 31, 2016 representing its best estimate of the refund obligations that would arise, net of amounts that would be subject to recovery under state jurisdictional TCR riders, based on the likelihood of FERC reducing the ROE component of the MISO Tariff and ordering MISO to refund amounts charged in excess of the lower rate. In the February and June 2017 MISO billings, MISO processed the refund of the FERC-ordered reduction in the MISO tariff allowed ROE for the first 15-month refund period. The refund, in combination with a decision in the 2016 Minnesota general rate case that affected the Minnesota TCR rider, resulted in a reduction in OTP’s accrued MISO tariff ROE refund liability from $2.7 million as of December 31, 2016 to $1.6 million as of September 30, 2017.
Together with as many as 200 utilities, generators and power marketers, OTP participated in proceedings before the FERC regarding the calculation, assessment and implementation of MISO Revenue Sufficiency Guarantee (RSG) charges for entities participating in the MISO wholesale energy market since that market
’s start on April 1, 2005 until the conclusion of the proceedings on May 2, 2015. The proceedings fundamentally concerned MISO’s application of its MISO RSG rate on file with the FERC to market participants, revisions to the RSG rate based on several FERC orders, and the FERC’s decision to not resettle the markets based on MISO application of the RSG rate to market participants. Several of the FERC’s orders are on review in a set of consolidated cases before the D.C. Circuit. The consolidated petitions at the D.C. Circuit involve multiple petitioners and intervenors. OTP is an intervenor in these cases. The D.C. Circuit
has set a briefing schedule with final briefs due in January 2018. MISO has not made available past billing or resettlement data necessary for determining amounts that might be payable if the FERC’s decisions are reversed. Therefore, the Company cannot estimate OTP’s exposure at this time from a final order reversing the relevant FERC orders, which could have a material effect on the Company’s results of operations.
Contingencies, by their nature, relate to uncertainties that require the Company
’s management to exercise judgment both in assessing the likelihood a liability has been incurred as well as in estimating the amount of potential loss. The most significant contingencies impacting the Company’s consolidated financial statements are those related to environmental remediation, risks associated with indemnification obligations under divestitures of discontinued operations and litigation matters. Should all of these known items result in liabilities being incurred, the loss could be as high as $1.0 million, excluding any liability for RSG charges for which an estimate cannot be made at this time.
In 2014 the Environmental Protection Agency (EPA) published
both proposed standards of performance for carbon dioxide (CO2) emissions from new, reconstructed and modified fossil fuel-fired power plants (New Source Performance Standards), and proposed CO2 emission guidelines for existing fossil fuel-fired power plants (the Clean Power Plan) under section 111 of the Clean Air Act. The EPA published final rules for each of these proposals on October 23, 2015. Both rules were challenged on legal grounds. On February 9, 2016 the U.S. Supreme Court granted a stay of the Clean Power Plan, pending disposition of petitions for review in the D.C. Circuit. The D.C. Circuit heard oral argument on challenges to the Clean Power Plan on September 27, 2016 before the full court, and a decision was expected in the first half of 2017. However, pursuant to Executive Order 13783,
Promoting Energy Independence and Economic Growth
, the EPA was directed to consider suspending, revising or rescinding the CO2 rules discussed above. Thereafter, the EPA issued notices in the Federal Register of its intent to review these rules pursuant to the Executive Order, and it filed motions to stay the pending litigation. The D.C. Circuit subsequently issued orders holding in abeyance the appeals of both the New Source Performance Standards and the Clean Power Plan, pending EPA review. On October 16, 2017 the EPA published a proposed rule to rescind the Clean Power Plan. Therefore, there is uncertainty regarding the future of both rules.
Other
The Company is a party to litigation and regulatory enforcement matters arising in the normal course of business. The Company regularly analyzes current information and, as necessary, provides accruals for liabilities that are probable of occurring and that can be reasonably estimated. The Company believes the effect on its consolidated results of operations, financial position and cash flows, if any, for the disposition of all matters pending as of
September 30, 2017 will not be material.
10. Short-Term and Long-Term Borrowings
The following table presents the status of our lines of credit as of
September 30, 2017 and December 31, 2016:
(in thousands)
|
|
Line Limit
|
|
|
In Use on
September
30,
2017
|
|
|
Restricted due to Outstanding
Letters of Credit
|
|
|
Available on
September
30,
2017
|
|
|
Available on
December 31,
201
6
|
|
Otter Tail Corporation Credit Agreement
|
|
$
|
130,000
|
|
|
$
|
1,417
|
|
|
$
|
--
|
|
|
$
|
128,583
|
|
|
$
|
130,000
|
|
OTP Credit Agreement
|
|
|
170,000
|
|
|
|
102,220
|
|
|
|
300
|
|
|
|
67,480
|
|
|
|
127,067
|
|
Total
|
|
$
|
300,000
|
|
|
$
|
103,637
|
|
|
$
|
300
|
|
|
$
|
196,063
|
|
|
$
|
257,067
|
|
On October 31, 2017
both credit agreements were amended to extend the expiration dates by one year from October 29, 2021 to October 31, 2022.
Debt Retirements
On February 5, 2016 the Company borrowed $50 million under
a Term Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points.
The Company repaid $35.0 million of the $50 million in the fourth quarter of 2016 and made additional repayments of $3.0 million in January 2017, $3.0 million in June 2017 and $9.0 million on August 7, 2017. As of September 30, 2017 the Company had no borrowings under the Term Loan Agreement.
On August 21, 2017 OTP used borrowings under the OTP
Credit Agreement to retire its $33 million 5.95%, Series A Senior Unsecured Notes, which matured on August 20, 2017.
The following tables provide a breakdown of the assignment of the Company
’s consolidated short-term and long-term debt outstanding as of September 30, 2017 and December 31, 2016:
September
30
, 201
7
(in thousands)
|
|
OTP
|
|
|
Otter Tail
Corporation
|
|
|
Otter Tail
Corporation
Consolidated
|
|
Short-Term Debt
|
|
$
|
102,220
|
|
|
$
|
1,417
|
|
|
$
|
103,637
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
Term Loan, LIBOR plus 0.90%, due February 5, 2018
|
|
|
|
|
|
$
|
--
|
|
|
$
|
--
|
|
3.55% Guaranteed Senior Notes, due December 15, 2026
|
|
|
|
|
|
|
80,000
|
|
|
|
80,000
|
|
Senior Unsecured Notes 4.63%, due December 1, 2021
|
|
$
|
140,000
|
|
|
|
|
|
|
|
140,000
|
|
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
|
|
|
30,000
|
|
|
|
|
|
|
|
30,000
|
|
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
|
|
|
42,000
|
|
|
|
|
|
|
|
42,000
|
|
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
|
|
|
60,000
|
|
|
|
|
|
|
|
60,000
|
|
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
|
|
|
50,000
|
|
|
|
|
|
|
|
50,000
|
|
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
|
|
|
90,000
|
|
|
|
|
|
|
|
90,000
|
|
North Dakota Development Note, 3.95%, due April 1, 2018
|
|
|
|
|
|
|
47
|
|
|
|
47
|
|
P
artnership in Assisting Community Expansion (PACE) Note, 2.54%,
due March 18, 2021
|
|
|
|
|
|
|
723
|
|
|
|
723
|
|
Total
|
|
$
|
412,000
|
|
|
$
|
80,770
|
|
|
$
|
492,770
|
|
Less: Current Maturities net of Unamortized Debt Issuance Costs
|
|
|
--
|
|
|
|
197
|
|
|
|
197
|
|
Unamortized Long-Term Debt Issuance Costs
|
|
|
1,687
|
|
|
|
480
|
|
|
|
2,167
|
|
Total Long-Term Debt net of Unamortized Debt Issuance Costs
|
|
$
|
410,313
|
|
|
$
|
80,093
|
|
|
$
|
490,406
|
|
Total Short-Term and Long-Term Debt (with current maturities)
|
|
$
|
512,533
|
|
|
$
|
81,707
|
|
|
$
|
594,240
|
|
December 31, 2016
(in thousands)
|
|
OTP
|
|
|
Otter Tail
Corporation
|
|
|
Otter Tail
Corporation
Consolidated
|
|
Short-Term Debt
|
|
$
|
42,883
|
|
|
$
|
--
|
|
|
$
|
42,883
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
Term Loan, LIBOR plus 0.90%, due February 5, 2018
|
|
|
|
|
|
$
|
15,000
|
|
|
$
|
15,000
|
|
3.55% Guaranteed Senior Notes, due December 15, 2026
|
|
|
|
|
|
|
80,000
|
|
|
|
80,000
|
|
Senior Unsecured Notes 5.95%, Series A, due August 20, 2017
|
|
$
|
33,000
|
|
|
|
|
|
|
|
33,000
|
|
Senior Unsecured Notes 4.63%, due December 1, 2021
|
|
|
140,000
|
|
|
|
|
|
|
|
140,000
|
|
Senior Unsecured Notes 6.15%, Series B, due August 20, 2022
|
|
|
30,000
|
|
|
|
|
|
|
|
30,000
|
|
Senior Unsecured Notes 6.37%, Series C, due August 20, 2027
|
|
|
42,000
|
|
|
|
|
|
|
|
42,000
|
|
Senior Unsecured Notes 4.68%, Series A, due February 27, 2029
|
|
|
60,000
|
|
|
|
|
|
|
|
60,000
|
|
Senior Unsecured Notes 6.47%, Series D, due August 20, 2037
|
|
|
50,000
|
|
|
|
|
|
|
|
50,000
|
|
Senior Unsecured Notes 5.47%, Series B, due February 27, 2044
|
|
|
90,000
|
|
|
|
|
|
|
|
90,000
|
|
North Dakota Development Note, 3.95%, due April 1, 2018
|
|
|
|
|
|
|
106
|
|
|
|
106
|
|
PACE Note, 2.54%, due March 18, 2021
|
|
|
|
|
|
|
836
|
|
|
|
836
|
|
Total
|
|
$
|
445,000
|
|
|
$
|
95,942
|
|
|
$
|
540,942
|
|
Less: Current Maturities net of Unamortized Debt Issuance Costs
|
|
|
32,970
|
|
|
|
231
|
|
|
|
33,201
|
|
Unamortized Long-Term Debt Issuance Costs
|
|
|
1,861
|
|
|
|
539
|
|
|
|
2,400
|
|
Total Long-Term Debt net of Unamortized Debt Issuance Costs
|
|
$
|
410,169
|
|
|
$
|
95,172
|
|
|
$
|
505,341
|
|
Total Short-Term and Long-Term Debt (with current maturities)
|
|
$
|
486,022
|
|
|
$
|
95,403
|
|
|
$
|
581,425
|
|
1
1
.
Pension Plan and Other Postretirement Benefits
Pension Plan
—Components of net periodic pension benefit cost of the Company's noncontributory funded pension plan are as follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine
Months Ended September 30,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
201
6
|
|
Service Cost
—Benefit Earned During the Period
|
|
$
|
1,407
|
|
|
$
|
1,376
|
|
|
$
|
4,221
|
|
|
$
|
4,139
|
|
Interest Cost on Projected Benefit Obligation
|
|
|
3,534
|
|
|
|
3,603
|
|
|
|
10,604
|
|
|
|
10,646
|
|
Expected Return on Assets
|
|
|
(4,807
|
)
|
|
|
(4,857
|
)
|
|
|
(14,421
|
)
|
|
|
(14,590
|
)
|
Amortization of Prior-Service Cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
30
|
|
|
|
48
|
|
|
|
89
|
|
|
|
142
|
|
From Other Comprehensive Income
1
|
|
|
1
|
|
|
|
1
|
|
|
|
3
|
|
|
|
3
|
|
Amortization of Net Actuarial Loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
1,273
|
|
|
|
1,411
|
|
|
|
3,818
|
|
|
|
3,865
|
|
From Other Comprehensive Income
1
|
|
|
31
|
|
|
|
32
|
|
|
|
94
|
|
|
|
95
|
|
Net Periodic Pension Cost
|
|
$
|
1,469
|
|
|
$
|
1,614
|
|
|
$
|
4,408
|
|
|
$
|
4,300
|
|
1
Corporate cost included in Other Nonelectric Expenses.
Cash flows
—The Company currently is not required and does not anticipate making a contribution to its pension plan in 2017. The Company made a discretionary plan contribution totaling $10.0 million in January 2016.
Executive Survivor and Supplemental Retirement Plan
—Components of net periodic pension benefit cost of the Company’s unfunded, nonqualified benefit plan for executive officers and certain key management employees are as follows:
|
|
Three Months Ended
September 30,
|
|
|
Nine
Months Ended September 30,
|
|
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
|
201
7
|
|
|
201
6
|
|
Service Cost
—Benefit Earned During the Period
|
|
$
|
73
|
|
|
$
|
63
|
|
|
$
|
218
|
|
|
$
|
189
|
|
Interest Cost on Projected Benefit Obligation
|
|
|
421
|
|
|
|
417
|
|
|
|
1,264
|
|
|
|
1,251
|
|
Amortization of Prior-Service Cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
4
|
|
|
|
4
|
|
|
|
12
|
|
|
|
12
|
|
From Other Comprehensive Income
1
|
|
|
10
|
|
|
|
9
|
|
|
|
29
|
|
|
|
28
|
|
Amortization of Net Actuarial Loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
70
|
|
|
|
74
|
|
|
|
213
|
|
|
|
220
|
|
From Other Comprehensive Income
2
|
|
|
110
|
|
|
|
111
|
|
|
|
330
|
|
|
|
334
|
|
Net Periodic Pension Cost
|
|
$
|
688
|
|
|
$
|
678
|
|
|
$
|
2,066
|
|
|
$
|
2,034
|
|
1
Amortization of Prior Service Costs from Other Comprehensive Income Charged to:
|
|
Electric Operation and Maintenance
Expenses
|
|
$
|
4
|
|
|
$
|
3
|
|
|
$
|
12
|
|
|
$
|
11
|
|
Other Nonelectric Expenses
|
|
|
6
|
|
|
|
6
|
|
|
|
17
|
|
|
|
17
|
|
2
Amortization of Net Actuarial Loss from Other Comprehensive Income Charged to:
|
|
Electric Operation and Maintenance Expenses
|
|
$
|
67
|
|
|
$
|
68
|
|
|
$
|
199
|
|
|
$
|
204
|
|
Other Nonelectric Expenses
|
|
|
43
|
|
|
|
43
|
|
|
|
131
|
|
|
|
130
|
|
Postretirement Benefits
—Components of net periodic postretirement benefit cost for health insurance and life insurance benefits for retired OTP and corporate employees, net of the effect of Medicare Part D Subsidy:
|
|
Three Months Ended
September 30,
|
|
|
Nine
Months Ended September 30,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
|
2017
|
|
|
201
6
|
|
Service Cost
—Benefit Earned During the Period
|
|
$
|
357
|
|
|
$
|
365
|
|
|
$
|
1,069
|
|
|
$
|
976
|
|
Interest Cost on Projected Benefit Obligation
|
|
|
678
|
|
|
|
794
|
|
|
|
2,034
|
|
|
|
1,877
|
|
Amortization of Prior-Service Cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
--
|
|
|
|
34
|
|
|
|
--
|
|
|
|
100
|
|
From Other Comprehensive Income
1
|
|
|
--
|
|
|
|
1
|
|
|
|
--
|
|
|
|
3
|
|
Amortization of Net Actuarial Loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
233
|
|
|
|
284
|
|
|
|
699
|
|
|
|
284
|
|
From Other Comprehensive Income
1
|
|
|
5
|
|
|
|
7
|
|
|
|
17
|
|
|
|
7
|
|
Net Periodic Postretirement Benefit Cost
|
|
$
|
1,273
|
|
|
$
|
1,485
|
|
|
$
|
3,819
|
|
|
$
|
3,247
|
|
Effect of Medicare Part D Subsidy
|
|
$
|
(141
|
)
|
|
$
|
(177
|
)
|
|
$
|
(421
|
)
|
|
$
|
(692
|
)
|
1
Corporate cost included in Other Nonelectric Expenses.
|
|
1
2
. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value:
Cash
Equivalents
—The carrying amount approximates fair value because of the short-term maturity of those instruments.
Short-Term Debt
—The carrying amount approximates fair value because the debt obligations are short-term and the balances outstanding as of September 30, 2017 and December 31, 2016 related to the Otter Tail Corporation Credit Agreement and the OTP Credit Agreement were subject to variable interest rates of LIBOR plus 1.75% and LIBOR plus 1.25%, respectively, which approximate market rates.
Long
-Term Debt
including Current Maturities
—The fair value of the Company's and OTP’s long-term debt is estimated based on the current market indications of rates available to the Company for the issuance of debt. The Company’s long-term debt subject to variable interest rates approximates fair value. The fair value measurements of the Company’s long-term debt issues fall into level 2 of the fair value hierarchy set forth in ASC 820.
|
|
September
30, 2017
|
|
|
December 31, 20
16
|
|
(in thousands)
|
|
Carrying
Amount
|
|
|
Fair Value
|
|
|
Carrying
Amount
|
|
|
Fair
Value
|
|
Cash and Cash Equivalents
|
|
|
826
|
|
|
|
826
|
|
|
|
--
|
|
|
|
--
|
|
Short
-Term Debt
|
|
|
(103,637
|
)
|
|
|
(103,637
|
)
|
|
|
(42,883
|
)
|
|
|
(42,883
|
)
|
Long
-Term Debt including Current Maturities
|
|
|
(490,603
|
)
|
|
|
(543,870
|
)
|
|
|
(538,542
|
)
|
|
|
(583,835
|
)
|
1
4
. Income Tax Expense
– Continuing Operations
The following table provides a reconciliation of income tax expense calculated at the net composite federal and state statutory rate on income from continuing operations before income taxes and income tax expense for continuing operations reported on the Company
’s consolidated statements of income:
|
|
Three Months Ended
September 30,
|
|
|
Nine
Months Ended
September 30,
|
|
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
|
201
7
|
|
|
201
6
|
|
Income Before Income Taxes
– Continuing Operations
|
|
$
|
24,808
|
|
|
$
|
19,757
|
|
|
$
|
73,314
|
|
|
$
|
60,378
|
|
Tax Computed at Company
’s Net Composite Federal and State
Statutory Rate (39%)
|
|
|
9,675
|
|
|
|
7,705
|
|
|
|
28,592
|
|
|
|
23,547
|
|
Increases (Decreases) in Tax from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal Production Tax Credits
|
|
|
(1,349
|
)
|
|
|
(1,423
|
)
|
|
|
(5,411
|
)
|
|
|
(4,994
|
)
|
Section 199 Domestic Production Activities Deduction
|
|
|
(330
|
)
|
|
|
(9
|
)
|
|
|
(990
|
)
|
|
|
(207
|
)
|
Excess Tax Deduction
– 2014 Performance Share Awards
|
|
|
--
|
|
|
|
--
|
|
|
|
(697
|
)
|
|
|
--
|
|
North Dakota Wind Tax Credit Amortization –
Net of Federal Taxes
|
|
|
(212
|
)
|
|
|
(212
|
)
|
|
|
(637
|
)
|
|
|
(637
|
)
|
Corporate
-Owned Life Insurance
|
|
|
(118
|
)
|
|
|
(92
|
)
|
|
|
(620
|
)
|
|
|
(664
|
)
|
Employee Stock Ownership Plan Dividend Deduction
|
|
|
(172
|
)
|
|
|
(157
|
)
|
|
|
(517
|
)
|
|
|
(472
|
)
|
R&D Tax Credits
|
|
|
(148
|
)
|
|
|
(223
|
)
|
|
|
(454
|
)
|
|
|
(445
|
)
|
Investment Tax Credits
|
|
|
(41
|
)
|
|
|
(87
|
)
|
|
|
(122
|
)
|
|
|
(262
|
)
|
Other Items
– Net
|
|
|
(270
|
)
|
|
|
(339
|
)
|
|
|
151
|
|
|
|
(128
|
)
|
Income Tax Expense
–
Continuing Operations
|
|
$
|
7,035
|
|
|
$
|
5,163
|
|
|
$
|
19,295
|
|
|
$
|
15,738
|
|
Effective Income Tax Rate
– Continuing Operations
|
|
|
28.4
|
%
|
|
|
26.1
|
%
|
|
|
26.3
|
%
|
|
|
26.1
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the activity related to
our unrecognized tax benefits:
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
Balance on January 1
|
|
$
|
891
|
|
|
$
|
468
|
|
Increases Related to Tax Positions for Prior Years
|
|
|
28
|
|
|
|
40
|
|
Increases Related to Tax Positions for Current Year
|
|
|
220
|
|
|
|
26
|
|
Uncertain Positions Resolved During Year
|
|
|
(206
|
)
|
|
|
(97
|
)
|
Balance on
September 30
|
|
$
|
933
|
|
|
$
|
437
|
|
The balance of unrecognized tax benefits as of
September 30, 2017 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of September 30, 2017 is not expected to change significantly within the next 12 months. The Company classifies interest and penalties on tax uncertainties as components of the provision for income taxes in its consolidated statement of income. There was no amount accrued for interest on tax uncertainties as of September 30, 2017.
The Company and its subsidiaries file a consolidated U.S. federal income tax return and various state income tax returns. As of
September 30, 2017, with limited exceptions, the Company is no longer subject to examinations by taxing authorities for tax years prior to 2014 for federal and North Dakota state income taxes and prior to 2013 for Minnesota
state income taxes.
1
6
. Discontinued Operations
Included in discontinued operations are activities related to
the Company’s former wind tower manufacturing, dock and boatlift and construction companies. Included in liabilities of discontinued operations are warranty reserves. Details regarding the warranty reserves follow:
(in thousands)
|
|
201
7
|
|
|
201
6
|
|
Warranty Reserve Balance, January 1
|
|
$
|
1,369
|
|
|
$
|
2,103
|
|
Additional Provision for Warranties Made During the Year
|
|
|
--
|
|
|
|
--
|
|
Settlements Made During the Year
|
|
|
(112
|
)
|
|
|
(24
|
)
|
Decrease in Warranty Estimates for Prior Years
|
|
|
(400
|
)
|
|
|
(530
|
)
|
Warranty Reserve Balance,
September 30
|
|
$
|
857
|
|
|
$
|
1,549
|
|
The warranty reserve balances as of
September 30, 2017 relate to products produced by the Company’s former wind tower and dock and boatlift manufacturing companies. Certain products sold by the companies carried fifteen year warranties. Although the assets of these companies have been sold and their operating results are reported under discontinued operations in the Company’s consolidated statements of income, the Company retains responsibility for warranty claims related to the products they produced prior to the sales of these companies.
Expenses associated with remediation activities of these companies could be substantial. For wind towers, the potential exists for multiple claims based on one defect repeated throughout the production process or for claims where the cost to repair or replace the defective part is highly disproportionate to the original cost of the part. For example, if the Company is required to cover remediation expenses in addition to regular warranty coverage, the Company could be required to accrue additional expenses and experience additional unplanned cash expenditures which could adversely affect the Company
’s consolidated net income and financial condition.