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 months ended March 31, 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 product.
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 March 31, 2017 and December
31, 2016:
March 31, 2017
(in thousands)
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate Debt Securities – Held by Captive Insurance Company
|
|
|
|
|
|
$
|
5,590
|
|
|
|
|
|
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company
|
|
|
|
|
|
|
2,345
|
|
|
|
|
|
Other Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan
|
|
$
|
828
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
828
|
|
|
$
|
7,935
|
|
|
|
|
|
December 31, 2016
(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 March 31, 2017 could be as high as $59.7 million, OTP’s 35% share of unrecovered costs.
Inventories
Inventories, valued at the lower of cost or net realizable value,
consist of the following:
|
|
March 31,
|
|
|
December 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Finished Goods
|
|
$
|
24,018
|
|
|
$
|
27,755
|
|
Work in Process
|
|
|
12,801
|
|
|
|
11,754
|
|
Raw Material, Fuel and Supplies
|
|
|
44,654
|
|
|
|
44,231
|
|
Total Inventories
|
|
$
|
81,473
|
|
|
$
|
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 three months of 2017:
(in thousands)
|
|
Gross Balance
December 31, 2016
|
|
|
Accumulated
Impairments
|
|
|
Balance
(net of impairments)
December 31, 2016
|
|
|
Adjustments to
Goodwill in
2017
|
|
|
Balance
(net of impairments)
March 31, 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 March 31, 2017 and December 31, 2016:
March 31, 2017
(in thousands)
|
|
Gross Carrying
Amount
|
|
|
Accumulated
Amortization
|
|
|
Net Carrying
Amount
|
|
|
Remaining
Amortization
Periods
|
Amortizable Intangible Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer Relationships
|
|
$
|
22,491
|
|
|
$
|
8,144
|
|
|
$
|
14,347
|
|
|
33-221 months
|
Covenant not to Compete
|
|
|
590
|
|
|
|
311
|
|
|
|
279
|
|
|
17 months
|
Total
|
|
$
|
23,081
|
|
|
$
|
8,455
|
|
|
$
|
14,626
|
|
|
|
December 31, 2016
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortizable Intangible Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer Relationships
|
|
$
|
22,491
|
|
|
$
|
7,861
|
|
|
$
|
14,630
|
|
|
36-224 months
|
Covenant not to Compete
|
|
|
590
|
|
|
|
262
|
|
|
|
328
|
|
|
20 months
|
Total
|
|
$
|
23,081
|
|
|
$
|
8,123
|
|
|
$
|
14,958
|
|
|
|
The amortization expense for these intangible assets was:
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Amortization Expense – Intangible Assets
|
|
$
|
332
|
|
|
$
|
357
|
|
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
|
|
$
|
1,330
|
|
|
$
|
1,264
|
|
|
$
|
1,133
|
|
|
$
|
1,099
|
|
|
$
|
1,099
|
|
Supplemental Disclosures of Cash Flow Information
|
|
As of March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Noncash Investing Activities:
|
|
|
|
|
|
|
|
|
Transactions Related to Capital Additions not Settled in Cash
|
|
$
|
10,811
|
|
|
$
|
24,618
|
|
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 is
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 Adoption
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. As of March 31, 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 evaluating
transition options. 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
treatment of contributions in aid of construction, which are common to regulated electric utility companies, was determined to
be out of scope from the application of ASC 606 by the American Institute of Certified Public Accountants’ power and
utility industry task force. Therefore, the Company will continue to account for these contributions consistent with current practice.
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. The Company does not plan to adopt the updated
guidance prior to January 1, 2018.
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, developing a list
of all current leases outstanding and identifying key impacts to its businesses to determine areas where the amendments in ASU
2016-02 will be applicable and 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 what adjustments and regulatory assets, if any, may need to be established in order to reflect the effect of the required
regulatory accounting treatment of the affected net periodic benefit costs. At a minimum, the Company anticipates the non-service
cost components of the affected net periodic benefit costs will be reported below the operating income line on its consolidated
income statements upon adoption of the amendments in ASU 2017-07. 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 material and handling trays and
horticultural containers. 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 98.4% and 97.6% of
its operating revenues for the respective three month periods ended March 31, 2017 and 2016 came from sales within the United States.
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 months ended March 31, 2017 and 2016 and total assets by business segment as of March 31, 2017 and
December 31, 2016 are presented in the following tables:
Operating Revenue
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Electric
|
|
$
|
118,551
|
|
|
$
|
112,994
|
|
Manufacturing
|
|
|
58,417
|
|
|
|
59,820
|
|
Plastics
|
|
|
37,157
|
|
|
|
33,437
|
|
Intersegment Eliminations
|
|
|
(8
|
)
|
|
|
(9
|
)
|
Total
|
|
$
|
214,117
|
|
|
$
|
206,242
|
|
Interest Charges
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Electric
|
|
$
|
6,386
|
|
|
$
|
6,284
|
|
Manufacturing
|
|
|
554
|
|
|
|
992
|
|
Plastics
|
|
|
153
|
|
|
|
244
|
|
Corporate and Intersegment Eliminations
|
|
|
369
|
|
|
|
474
|
|
Total
|
|
$
|
7,462
|
|
|
$
|
7,994
|
|
Income Taxes
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Electric
|
|
$
|
6,062
|
|
|
$
|
4,612
|
|
Manufacturing
|
|
|
1,055
|
|
|
|
1,019
|
|
Plastics
|
|
|
1,390
|
|
|
|
1,367
|
|
Corporate
|
|
|
(2,144
|
)
|
|
|
(1,506
|
)
|
Total
|
|
$
|
6,363
|
|
|
$
|
5,492
|
|
Net Income (Loss)
|
|
Three Months Ended
|
|
|
|
March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Electric
|
|
$
|
15,560
|
|
|
$
|
12,538
|
|
Manufacturing
|
|
|
2,172
|
|
|
|
1,853
|
|
Plastics
|
|
|
2,437
|
|
|
|
2,152
|
|
Corporate
|
|
|
(640
|
)
|
|
|
(2,053
|
)
|
Discontinued Operations
|
|
|
56
|
|
|
|
30
|
|
Total
|
|
$
|
19,585
|
|
|
$
|
14,520
|
|
Identifiable Assets
|
|
March 31,
|
|
|
December 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Electric
|
|
$
|
1,630,071
|
|
|
$
|
1,622,231
|
|
Manufacturing
|
|
|
170,805
|
|
|
|
166,525
|
|
Plastics
|
|
|
91,049
|
|
|
|
84,592
|
|
Corporate
|
|
|
38,781
|
|
|
|
39,037
|
|
Total
|
|
$
|
1,930,706
|
|
|
$
|
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
The Big Stone South – Brookings Multi-Value
Transmission Project (MVP) and Capacity Expansion 2020 (CapX2020) Project
—This 345 kiloVolt (kV) transmission line, currently
under construction, will extend 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 (NSP MN), a subsidiary of Xcel Energy
Inc., jointly developed this project 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 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 is expected to be in service in fall 2017. OTP’s capitalized
costs on this project as of March 31, 2017 were approximately $64.0 million, which includes assets that are 100% owned by
OTP.
The 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. (MDU), 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 March 31, 2017 were approximately $57.9
million, which includes assets that are 100% owned by OTP.
Recovery of OTP’s major transmission investments is through
the MISO Tariff (several as MVPs) and, currently, Minnesota, North Dakota and South Dakota Transmission Cost Recovery (TCR) Riders.
Minnesota
2016 General Rate Case
—On February 16, 2016 OTP
filed a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested
an allowed rate of return on rate base of 8.07% and an allowed rate of return on equity of 10.4% based on an equity ratio of 52.5%
of total capital. On April 14, 2016 the MPUC issued an order approving an interim rate increase of 9.56% to the base rate portion
of customers’ bills effective April 16, 2016, as modified and subject to refund. The request and interim rate information
is detailed in the table below:
($ in thousands)
|
|
Annualized or
Test Year
|
|
|
Actual Through
March 31, 2017
|
|
Revenue Increase Requested
|
|
$
|
19,296
|
|
|
|
|
|
Increase Percentage Requested
|
|
|
9.80
|
%
|
|
|
|
|
Jurisdictional Rate Base
|
|
$
|
483,000
|
|
|
|
|
|
Interim Revenue Increase (subject to refund)
|
|
$
|
16,816
|
|
|
$
|
15,335
|
|
The deadline for submission of intervenor direct testimony was
August 16, 2016. Direct testimony of the Minnesota Department of Commerce (MNDOC) included a recommendation for an 8.87% allowed
rate of return on equity, and direct testimony of the Minnesota Office of the Attorney General (OAG) included a recommendation
for a 6.96% allowed rate of return on equity. In response, in rebuttal testimony, OTP modified its request to provide for an allowed
rate of return on equity of 10.05%. In rebuttal testimony, the MNDOC revised its recommendation to an 8.66% allowed rate of return
on equity, and the Minnesota OAG revised its recommendation to a 7.14% allowed rate of return on equity. Hearings before the Administrative
Law Judge (ALJ) occurred in October 2016. On January 5, 2017 the ALJ issued his report which included a recommendation for a 9.54%
allowed rate of return on equity.
Oral arguments before the MPUC occurred February 23, 2017 with
deliberations on March 2, 2017. The MPUC rendered its final decision in March 2017 and issued its written order on May 1, 2017.
The MPUC authorized a revenue increase of approximately $12.3 million through a 6.27% increase in base rate revenues compared
to the authorized interim rate increase of 9.56%. The MPUC’s written order included: (1) an allowed rate of return on equity
of 9.41%, (2) the determination that all costs (including FERC allocated costs and revenues) of the Big Stone South to Brookings
and Big Stone South to Ellendale MVP projects will be included in the Minnesota TCR rider and jurisdictionally allocated to OTP’s
Minnesota customers, and (3) 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 at the time final rates are implemented
at the end of this rate case. 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. 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%. OTP's rate of return will be based on a capital structure of 47.50% long term debt and 52.50% common equity.
Parties may request clarification or reconsideration of the MPUC’s rulings consistent with Minnesota law. Based on the MPUC
deliberations regarding OTP’s 2016 revenue increase request, OTP had recorded an estimated interim rate refund of $5.2 million,
including interest, as of March 31, 2017.
2010 General Rate Case
—A general rate increase
in Minnesota of approximately $5.0 million, or 1.6%, was granted by the MPUC in an order issued on April 25, 2011 and effective
October 1, 2011. Pursuant to the order, OTP’s allowed rate of return on rate base increased from 8.33% to 8.61% and its allowed
rate of return on equity increased from 10.43% to 10.74%.
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 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
requested for 2016, $4.3 million approved for 2015 and $3.0 million approved for 2014. The MNDOC recently granted two large customers’
requests for exemption from OTP’s MNCIP pursuant to Minnesota Law. With the exemption of these two customers, recovery of
the portion of OTP’s MNCIP costs previously recovered from these two customers has shifted to OTP’s other Minnesota
customers.
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, the MPUC ordered OTP
to include, in the TCR rider retail rate base, Minnesota’s share of 100% 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, despite an ALJ recommendation that the MPUC affirm OTP’s
proposed treatment. The MPUC ordered treatment will result in the projects being treated as retail investments for Minnesota retail
ratemaking purposes.
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.
North Dakota
General Rates
—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 the North Dakota share of its investments in renewable energy facilities
it owns in North Dakota. 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. 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 Mercury and Air Toxics Standards (MATS) projects.
Rate Rider Updates
The following table provides summary information on the status
of updates for the previous two years for the various 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
|
|
R – March 31, 2017
|
|
October 1, 2017
|
|
$
|
9,868
|
|
|
$0.00754/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
|
|
|
|
|
|
|
|
|
|
|
2016 Annual Update
1
|
|
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
|
|
|
|
|
|
|
|
|
|
|
2016 Annual Update
1
|
|
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
|
|
|
|
|
|
|
|
|
|
|
2016 Annual Update
|
|
A – March 15, 2017
|
|
April 1, 2017
|
|
$
|
9,156
|
|
|
7.005% of Rev
|
2015 Annual Update
|
|
A – June 22, 2016
|
|
July 1, 2016
|
|
$
|
9,262
|
|
|
7.573% of Rev
|
2014 Annual Update
|
|
A – March 25, 2015
|
|
April 1, 2015
|
|
$
|
5,441
|
|
|
4.069% of Rev
|
Transmission Cost Recovery
|
|
|
|
|
|
|
|
|
|
|
2016 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
|
|
|
|
|
|
|
|
|
|
|
2017 Annual Update
|
|
R – March 31, 2017
|
|
July 1 2017
|
|
$
|
9,917
|
|
|
7.633% of base
|
2016 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
|
|
|
|
|
|
|
|
|
|
|
2016 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
|
|
|
|
|
|
|
|
|
|
|
2016 Annual Update
|
|
A – October 26, 2016
|
|
November 1, 2016
|
|
$
|
2,238
|
|
|
$0.00536/kwh
|
2015 Annual Update
|
|
A – October 15, 2015
|
|
November 1, 2015
|
|
$
|
2,728
|
|
|
$0.00643/kwh
|
1
Approved on a provisional basis and subject to
change based on comments from the MNDOC.
Revenues Recorded under Rate Riders
The following table presents revenue recorded by OTP under rate
riders in place in Minnesota, North Dakota and South Dakota for the three month periods ended March 31:
Rate Rider
(in thousands)
|
|
2017
|
|
|
2016
|
|
Minnesota
|
|
|
|
|
|
|
|
|
Conservation Improvement Program Costs and Incentives
1
|
|
$
|
1,966
|
|
|
$
|
2,506
|
|
Transmission Cost Recovery
|
|
|
2,170
|
|
|
|
2,276
|
|
Environmental Cost Recovery
|
|
|
2,824
|
|
|
|
3,082
|
|
North Dakota
|
|
|
|
|
|
|
|
|
Renewable Resource Adjustment
|
|
|
1,770
|
|
|
|
2,059
|
|
Transmission Cost Recovery
|
|
|
2,511
|
|
|
|
2,236
|
|
Environmental Cost Recovery
|
|
|
2,488
|
|
|
|
2,811
|
|
South Dakota
|
|
|
|
|
|
|
|
|
Transmission Cost Recovery
|
|
|
441
|
|
|
|
651
|
|
Environmental Cost Recovery
|
|
|
597
|
|
|
|
633
|
|
Conservation Improvement Program Costs and Incentives
|
|
|
240
|
|
|
|
159
|
|
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 of 1935, as amended. 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 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%.
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%. A lack of a quorum at FERC will delay the issuance of an order in the second complaint
for an uncertain period of time.
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 90% of the FERC ordered reduction in the MISO tariff allowed
ROE for the first 15-month refund period in its February 2017 billings. 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 on December 31, 2016 to $1.7 million as of March 31, 2017.
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:
|
|
March 31, 2017
|
|
|
Remaining
Recovery/
|
(in thousands)
|
|
Current
|
|
|
Long-Term
|
|
|
Total
|
|
|
Refund Period
|
Regulatory Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
1
|
|
$
|
6,443
|
|
|
$
|
106,656
|
|
|
$
|
113,099
|
|
|
see below
|
Deferred Marked-to-Market Losses
1
|
|
|
4,063
|
|
|
|
5,452
|
|
|
|
9,515
|
|
|
45 months
|
Conservation Improvement Program Costs and Incentives
2
|
|
|
3,745
|
|
|
|
5,735
|
|
|
|
9,480
|
|
|
30 months
|
Accumulated ARO Accretion/Depreciation Adjustment
1
|
|
|
—
|
|
|
|
6,276
|
|
|
|
6,276
|
|
|
asset lives
|
Big Stone II Unrecovered Project Costs – Minnesota
1
|
|
|
739
|
|
|
|
1,926
|
|
|
|
2,665
|
|
|
49 months
|
Debt Reacquisition Premiums
1
|
|
|
301
|
|
|
|
1,150
|
|
|
|
1,451
|
|
|
186 months
|
Deferred Income Taxes
1
|
|
|
—
|
|
|
|
1,020
|
|
|
|
1,020
|
|
|
asset lives
|
Minnesota Deferred Rate Case Expenses Subject to Recovery
1
|
|
|
954
|
|
|
|
—
|
|
|
|
954
|
|
|
12 months
|
North Dakota Renewable Resource Rider Accrued Revenues
2
|
|
|
727
|
|
|
|
62
|
|
|
|
789
|
|
|
24 months
|
Big Stone II Unrecovered Project Costs – South Dakota
2
|
|
|
100
|
|
|
|
517
|
|
|
|
617
|
|
|
74 months
|
North Dakota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
426
|
|
|
|
59
|
|
|
|
485
|
|
|
21 months
|
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
2
|
|
|
251
|
|
|
|
115
|
|
|
|
366
|
|
|
21 months
|
South Dakota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
106
|
|
|
|
—
|
|
|
|
106
|
|
|
11 months
|
Minnesota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
95
|
|
|
|
—
|
|
|
|
95
|
|
|
12 months
|
Minnesota Renewable Resource Rider Accrued Revenues
2
|
|
|
23
|
|
|
|
—
|
|
|
|
23
|
|
|
6 months
|
Total Regulatory Assets
|
|
$
|
17,973
|
|
|
$
|
128,968
|
|
|
$
|
146,941
|
|
|
|
Regulatory Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Reserve for Estimated Removal Costs – Net of Salvage
|
|
$
|
—
|
|
|
$
|
81,314
|
|
|
$
|
81,314
|
|
|
asset lives
|
Refundable Fuel Clause Adjustment Revenues
|
|
|
2,119
|
|
|
|
—
|
|
|
|
2,119
|
|
|
12 months
|
North Dakota Transmission Cost Recovery Rider Accrued Refund
|
|
|
1,545
|
|
|
|
—
|
|
|
|
1,545
|
|
|
12 months
|
Deferred Income Taxes
|
|
|
—
|
|
|
|
785
|
|
|
|
785
|
|
|
asset lives
|
Revenue for Rate Case Expenses Subject to Refund – Minnesota
|
|
|
711
|
|
|
|
30
|
|
|
|
741
|
|
|
13 months
|
Minnesota Environmental Cost Recovery Rider Accrued Refund
|
|
|
631
|
|
|
|
—
|
|
|
|
631
|
|
|
12 months
|
South Dakota Environmental Cost Recovery Rider Accrued Refund
|
|
|
354
|
|
|
|
—
|
|
|
|
354
|
|
|
12 months
|
North Dakota Environmental Cost Recovery Rider Accrued Refund
|
|
|
299
|
|
|
|
—
|
|
|
|
299
|
|
|
12 months
|
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
|
|
|
33
|
|
|
|
99
|
|
|
|
132
|
|
|
21 months
|
South Dakota Transmission Cost Recovery Rider Accrued Refund
|
|
|
8
|
|
|
|
—
|
|
|
|
8
|
|
|
12 months
|
Other
|
|
|
6
|
|
|
|
88
|
|
|
|
94
|
|
|
201 months
|
Total Regulatory Liabilities
|
|
$
|
5,706
|
|
|
$
|
82,316
|
|
|
$
|
88,022
|
|
|
|
Net Regulatory Asset Position
|
|
$
|
12,267
|
|
|
$
|
46,652
|
|
|
$
|
58,919
|
|
|
|
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
|
|
|
Refund Period
|
Regulatory Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior Service Costs and Actuarial Losses on Pensions and Other Postretirement Benefits
1
|
|
$
|
6,443
|
|
|
$
|
108,267
|
|
|
$
|
114,710
|
|
|
see below
|
Deferred Marked-to-Market Losses
1
|
|
|
4,063
|
|
|
|
6,467
|
|
|
|
10,530
|
|
|
48 months
|
Conservation Improvement Program Costs and Incentives
2
|
|
|
4,836
|
|
|
|
5,158
|
|
|
|
9,994
|
|
|
21 months
|
Accumulated ARO Accretion/Depreciation Adjustment
1
|
|
|
—
|
|
|
|
6,153
|
|
|
|
6,153
|
|
|
asset lives
|
Big Stone II Unrecovered Project Costs – Minnesota
1
|
|
|
778
|
|
|
|
2,087
|
|
|
|
2,865
|
|
|
52 months
|
Recoverable Fuel and Purchased Power Costs
1
|
|
|
1,798
|
|
|
|
—
|
|
|
|
1,798
|
|
|
12 months
|
Debt Reacquisition Premiums
1
|
|
|
325
|
|
|
|
1,214
|
|
|
|
1,539
|
|
|
189 months
|
Deferred Income Taxes
1
|
|
|
—
|
|
|
|
1,014
|
|
|
|
1,014
|
|
|
asset lives
|
Minnesota Deferred Rate Case Expenses Subject to Recovery
1
|
|
|
1,082
|
|
|
|
—
|
|
|
|
1,082
|
|
|
12 months
|
North Dakota Renewable Resource Rider Accrued Revenues
2
|
|
|
1,319
|
|
|
|
482
|
|
|
|
1,801
|
|
|
15 months
|
Big Stone II Unrecovered Project Costs – South Dakota
2
|
|
|
100
|
|
|
|
543
|
|
|
|
643
|
|
|
77 months
|
North Dakota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
—
|
|
|
|
568
|
|
|
|
568
|
|
|
24 months
|
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
2
|
|
|
333
|
|
|
|
—
|
|
|
|
333
|
|
|
12 months
|
South Dakota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
73
|
|
|
|
141
|
|
|
|
214
|
|
|
14 months
|
North Dakota Environmental Cost Recovery Rider Accrued Revenues
2
|
|
|
113
|
|
|
|
—
|
|
|
|
113
|
|
|
12 months
|
Minnesota Renewable Resource Rider Accrued Revenues
2
|
|
|
34
|
|
|
|
—
|
|
|
|
34
|
|
|
9 months
|
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
|
North Dakota Transmission Cost Recovery Rider Accrued Refund
|
|
|
1,381
|
|
|
|
782
|
|
|
|
2,163
|
|
|
24 months
|
Deferred Income Taxes
|
|
|
—
|
|
|
|
818
|
|
|
|
818
|
|
|
asset lives
|
Revenue for Rate Case Expenses Subject to Refund – Minnesota
|
|
|
711
|
|
|
|
208
|
|
|
|
919
|
|
|
16 months
|
Minnesota Transmission Cost Recovery Rider Accrued Refund
|
|
|
757
|
|
|
|
—
|
|
|
|
757
|
|
|
12 months
|
Minnesota Environmental Cost Recovery Rider Accrued Refund
|
|
|
139
|
|
|
|
—
|
|
|
|
139
|
|
|
12 months
|
South Dakota Environmental Cost Recovery Rider Accrued Refund
|
|
|
285
|
|
|
|
—
|
|
|
|
285
|
|
|
12 months
|
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
|
|
|
—
|
|
|
|
132
|
|
|
|
132
|
|
|
24 months
|
Other
|
|
|
21
|
|
|
|
89
|
|
|
|
110
|
|
|
204 months
|
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.
All Deferred Marked-to-Market Losses recorded as of March 31,
2017 relate to forward purchases of energy scheduled for delivery through December 2020.
Conservation Improvement Program Costs and Incentives represent
mandated conservation expenditures and incentives recoverable through retail electric rates.
The Accumulated Asset Retirement Obligation (ARO) Accretion/Depreciation
Adjustment will accrete and be amortized over the lives of property with asset retirement obligations.
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 186 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
.
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.
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 March 31, 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.
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
March 31, 2017.
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.
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
March 31, 2017.
The Minnesota Transmission Cost Recovery Rider Accrued Revenues
relate to revenues earned on qualifying transmission system facilities that have not been billed to Minnesota customers as of March
31, 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 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 March 31, 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 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 March 31, 2017.
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 March 31, 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 March 31, 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 March 31, 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 Positions 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 March 31, 2017 and December 31, 2016:
(in thousands)
|
|
March 31,
2017
|
|
|
December 31,
2016
|
|
Open Contract Gain Positions Subject to Legally Enforceable Netting Arrangements
|
|
$
|
—
|
|
|
$
|
—
|
|
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements
|
|
|
(14,590
|
)
|
|
|
(17,382
|
)
|
Net Balance Subject to Legally Enforceable Netting Arrangements
|
|
$
|
(14,590
|
)
|
|
$
|
(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 March 31, 2017 and December 31, 2016:
(in thousands)
|
|
March 31,
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
|
|
|
14,590
|
|
|
|
17,382
|
|
Total Loss Contracts based on Current Market Values
|
|
$
|
14,590
|
|
|
$
|
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
|
|
$
|
14,590
|
|
|
$
|
17,382
|
|
Offsetting Gains with Counterparties under Master Netting Agreements
|
|
|
—
|
|
|
|
—
|
|
Reporting Date Deposit Requirement if Credit Risk Feature Triggered
|
|
$
|
14,590
|
|
|
$
|
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, 2016
|
|
$
|
196,741
|
|
|
$
|
337,684
|
|
|
$
|
139,479
|
|
|
$
|
(3,800
|
)
|
|
$
|
670,104
|
|
Common Stock Issuances, Net of Expenses
|
|
|
837
|
|
|
|
1,727
|
|
|
|
|
|
|
|
|
|
|
|
2,564
|
|
Common Stock Retirements
|
|
|
(234
|
)
|
|
|
(1,525
|
)
|
|
|
|
|
|
|
|
|
|
|
(1,759
|
)
|
Net Income
|
|
|
|
|
|
|
|
|
|
|
19,585
|
|
|
|
|
|
|
|
19,585
|
|
Other Comprehensive Income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
105
|
|
|
|
105
|
|
Employee Stock Incentive Plans Expense
|
|
|
|
|
|
|
1,150
|
|
|
|
|
|
|
|
|
|
|
|
1,150
|
|
Common Dividends ($0.32 per share)
|
|
|
|
|
|
|
|
|
|
|
(12,626
|
)
|
|
|
|
|
|
|
(12,626
|
)
|
Balance, March 31, 2017
|
|
$
|
197,344
|
|
|
$
|
339,036
|
|
|
$
|
146,438
|
|
|
$
|
(3,695
|
)
|
|
$
|
679,123
|
|
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 March 31, 2017:
Common Shares Outstanding, December 31, 2016
|
|
|
39,348,136
|
|
Issuances:
|
|
|
|
|
Executive Stock Performance Awards (2014 shares earned)
|
|
|
89,291
|
|
Automatic Dividend Reinvestment and Share Purchase Plan:
|
|
|
|
|
Dividends Reinvested
|
|
|
36,320
|
|
Cash Invested
|
|
|
11,750
|
|
Employee Stock Ownership Plan
|
|
|
14,835
|
|
Vesting of Restricted Stock Units
|
|
|
9,975
|
|
Employee Stock Purchase Plan:
|
|
|
|
|
Cash Invested
|
|
|
—
|
|
Dividends Reinvested
|
|
|
5,131
|
|
Retirements:
|
|
|
|
|
Shares Withheld for Individual Income Tax Requirements
|
|
|
(46,634
|
)
|
Common Shares Outstanding, March 31, 2017
|
|
|
39,468,804
|
|
Earnings Per Share
The numerator used in the calculation of both basic and diluted
earnings per common share is net income for the three month periods ended March 31, 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
for the three month periods ended March 31:
|
|
2017
|
|
|
2016
|
|
Weighted Average Common Shares Outstanding – Basic
|
|
|
39,350,802
|
|
|
|
37,936,943
|
|
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
|
|
|
201,639
|
|
|
|
46,885
|
|
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees
|
|
|
57,873
|
|
|
|
39,841
|
|
Nonvested Restricted Shares
|
|
|
27,069
|
|
|
|
17,776
|
|
Shares Expected to be Issued Under the Deferred Compensation Program for Directors
|
|
|
3,342
|
|
|
|
3,763
|
|
Total Dilutive Shares
|
|
|
289,923
|
|
|
|
108,265
|
|
Weighted Average Common Shares Outstanding – Diluted
|
|
|
39,640,725
|
|
|
|
38,045,208
|
|
The effect of dilutive shares on earnings per share for the
three month periods ended March 31, 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
On February 2, 2017 the following stock incentive awards were
granted to officers under the 2014 Incentive Plan:
Award
|
|
Shares/Units
Granted
|
|
|
Weighted
Average
Grant-Date
Fair Value
per Award
|
|
|
Vesting
|
Restricted Stock Units Granted
|
|
|
15,900
|
|
|
$
|
37.65
|
|
|
25% per year through February 6, 2021
|
Stock Performance Awards Granted
|
|
|
59,500
|
|
|
$
|
31.00
|
|
|
December 31, 2019
|
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 was the average of the high and low market price per share on the date of grant.
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 return on equity. 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 terms of these awards are such that the entire award will be classified and accounted
for as equity, as required under ASC 718, and will be measured over the performance period based on the grant-date fair value of
the award.
Under the 2017 Performance Award Agreements, payment and 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 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 March 31, 2017 the remaining unrecognized compensation
expense related to outstanding, unvested stock-based compensation was approximately $5.3 million (before income taxes) which will
be amortized over a weighted-average period of 2.3 years.
Amounts of compensation expense recognized under the Company’s
six stock-based payment programs for the three month periods ended March 31, 2017 and 2016 are presented in the table below:
|
|
Three months ended
|
|
|
|
March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Stock Performance Awards Granted to Executive Officers
|
|
$
|
649
|
|
|
$
|
537
|
|
Restricted Stock Units Granted to Executive Officers
|
|
|
264
|
|
|
|
245
|
|
Restricted Stock Granted to Executive Officers
|
|
|
22
|
|
|
|
29
|
|
Restricted Stock Granted to Directors
|
|
|
128
|
|
|
|
107
|
|
Restricted Stock Units Granted to Non-Executive Employees
|
|
|
87
|
|
|
|
64
|
|
Employee Stock Purchase Plan (15% discount)
|
|
|
—
|
|
|
|
44
|
|
Totals
|
|
$
|
1,150
|
|
|
$
|
1,026
|
|
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 March 31, 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 47.5% and 58.1% based on OTP’s 2016 capital structure
petition approved by order of the MPUC on August 2, 2016. As of March 31, 2017 OTP’s equity-to-total-capitalization ratio
including short-term debt was 52.9% and its net assets restricted from distribution totaled approximately $443,000,000. Total capitalization
for OTP cannot currently exceed $1,123,168,000.
9. Commitments and Contingencies
Construction and Other Purchase Commitments
At December 31, 2016 OTP had commitments under contracts, including
its share of construction program commitments extending into 2019, of approximately $84.8 million. At March 31, 2017 OTP had commitments
under contracts, including its share of construction program commitments, extending into 2019, of approximately $114.6 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 OTP rolled forward a portion of its coal supply for Big Stone
Plant that it expected to take delivery of in 2016 into 2018 and entered into an agreement to purchase additional tons in 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 for the period
of January 1, 2016 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 2017 MISO billings MISO processed
the refund of 90% 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 $1.7 million as of March 31,
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 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. These consolidated cases are currently
held in abeyance while the parties engage in mediation before the D.C. Circuit. The parties have been unable to settle the issues
on appeal and the cases will likely revert to the active calendar of the D.C. Circuit. The scope of the issues that will be subject
to appeal at the D.C. Circuit have not yet been finalized. In addition, 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. Although the Company cannot
estimate OTP’s exposure at this time, a final order reversing the relevant FERC orders could have a material adverse 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
proposed standards of performance for carbon dioxide (CO
2
) emissions from new, reconstructed and modified fossil fuel-fired
power plants and proposed CO
2
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. All of these
rules have been challenged on legal grounds and are currently pending before the D.C. Circuit. 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 and, if a petition
for a writ of certiorari seeking review by the U.S. Supreme Court were granted, any final Supreme Court determination. 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 CO
2
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 has now issued orders holding in abeyance both the appeals on new, reconstructed
and modified fossil fuel-fired power plants and the Clean Power Plan, pending EPA review. Therefore, while the Clean Power Plan
remains stayed, there is uncertainty regarding its future, and each of the CO
2
rules could change, at least to some
extent, through future agency action.
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 March 31, 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 March 31, 2017 and December 31, 2016:
(in thousands)
|
|
Line Limit
|
|
|
In Use on
March 31,
2017
|
|
|
Restricted due to
Outstanding
Letters of Credit
|
|
|
Available on
March 31,
2017
|
|
|
Available on
December 31,
2016
|
|
Otter Tail Corporation Credit Agreement
|
|
$
|
130,000
|
|
|
$
|
12,825
|
|
|
$
|
—
|
|
|
$
|
117,175
|
|
|
$
|
130,000
|
|
OTP Credit Agreement
|
|
|
170,000
|
|
|
|
46,351
|
|
|
|
50
|
|
|
|
123,599
|
|
|
|
127,067
|
|
Total
|
|
$
|
300,000
|
|
|
$
|
59,176
|
|
|
$
|
50
|
|
|
$
|
240,774
|
|
|
$
|
257,067
|
|
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 repaid an additional $3.0 million in the first quarter of 2017.
The following tables provide a breakdown of the assignment of
the Company’s consolidated short-term and long-term debt outstanding as of March 31, 2017 and December 31, 2016:
March 31, 2017
(in thousands)
|
|
OTP
|
|
|
Otter Tail
Corporation
|
|
|
Otter Tail
Corporation
Consolidated
|
|
Short-Term Debt
|
|
$
|
46,351
|
|
|
$
|
12,825
|
|
|
$
|
59,176
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
Term Loan, LIBOR plus 0.90%, due February 5, 2018
|
|
|
|
|
|
$
|
12,000
|
|
|
$
|
12,000
|
|
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
|
|
|
|
|
|
|
86
|
|
|
|
86
|
|
Partnership in Assisting Community Expansion (PACE) Note, 2.54%, due March 18, 2021
|
|
|
|
|
|
|
799
|
|
|
|
799
|
|
Total
|
|
$
|
445,000
|
|
|
$
|
92,885
|
|
|
$
|
537,885
|
|
Less: Current Maturities net of Unamortized Debt Issuance Costs
|
|
|
32,981
|
|
|
|
12,211
|
|
|
|
45,192
|
|
Unamortized Long-Term Debt Issuance Costs
|
|
|
1,801
|
|
|
|
520
|
|
|
|
2,321
|
|
Total Long-Term Debt net of Unamortized Debt Issuance Costs
|
|
$
|
410,218
|
|
|
$
|
80,154
|
|
|
$
|
490,372
|
|
Total Short-Term and Long-Term Debt (with current maturities)
|
|
$
|
489,550
|
|
|
$
|
105,190
|
|
|
$
|
594,740
|
|
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
|
|
11. 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 March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Service Cost—Benefit Earned During the Period
|
|
$
|
1,407
|
|
|
$
|
1,382
|
|
Interest Cost on Projected Benefit Obligation
|
|
|
3,534
|
|
|
|
3,522
|
|
Expected Return on Assets
|
|
|
(4,807
|
)
|
|
|
(4,867
|
)
|
Amortization of Prior-Service Cost:
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
30
|
|
|
|
47
|
|
From Other Comprehensive Income
1
|
|
|
1
|
|
|
|
1
|
|
Amortization of Net Actuarial Loss:
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
1,273
|
|
|
|
1,227
|
|
From Other Comprehensive Income
1
|
|
|
31
|
|
|
|
31
|
|
Net Periodic Pension Cost
|
|
$
|
1,469
|
|
|
$
|
1,343
|
|
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 March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Service Cost—Benefit Earned During the Period
|
|
$
|
73
|
|
|
$
|
63
|
|
Interest Cost on Projected Benefit Obligation
|
|
|
422
|
|
|
|
417
|
|
Amortization of Prior-Service Cost:
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
4
|
|
|
|
4
|
|
From Other Comprehensive Income
1
|
|
|
9
|
|
|
|
9
|
|
Amortization of Net Actuarial Loss:
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
71
|
|
|
|
73
|
|
From Other Comprehensive Income
2
|
|
|
110
|
|
|
|
112
|
|
Net Periodic Pension Cost
|
|
$
|
689
|
|
|
$
|
678
|
|
1
Amortization of Prior
Service Costs from Other Comprehensive Income Charged to:
|
|
|
|
|
|
|
|
|
Electric Operation and Maintenance Expenses
|
|
$
|
4
|
|
|
$
|
4
|
|
Other Nonelectric Expenses
|
|
|
5
|
|
|
|
5
|
|
2
Amortization of Net
Actuarial Loss from Other Comprehensive Income Charged to:
|
|
|
|
|
|
|
|
|
Electric Operation and Maintenance Expenses
|
|
$
|
66
|
|
|
$
|
68
|
|
Other Nonelectric Expenses
|
|
|
44
|
|
|
|
44
|
|
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 March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Service Cost—Benefit Earned During the Period
|
|
$
|
356
|
|
|
$
|
306
|
|
Interest Cost on Projected Benefit Obligation
|
|
|
678
|
|
|
|
541
|
|
Amortization of Prior-Service Costs:
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
—
|
|
|
|
33
|
|
From Other Comprehensive Income
1
|
|
|
—
|
|
|
|
1
|
|
Amortization of Net Actuarial Loss:
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
233
|
|
|
|
—
|
|
From Other Comprehensive Income
1
|
|
|
6
|
|
|
|
—
|
|
Net Periodic Postretirement Benefit Cost
|
|
$
|
1,273
|
|
|
$
|
881
|
|
Effect of Medicare Part D Subsidy
|
|
$
|
(140
|
)
|
|
$
|
(257
|
)
|
1
Corporate cost included in Other Nonelectric Expenses.
|
|
|
|
|
|
|
|
|
12. 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:
Short-Term Debt
—The carrying amount approximates
fair value because the debt obligations are short-term and the balances outstanding as of March 31, 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.
|
|
March 31, 2017
|
|
|
December 31, 2016
|
|
(in thousands)
|
|
Carrying
Amount
|
|
|
Fair Value
|
|
|
Carrying
Amount
|
|
|
Fair Value
|
|
Short-Term Debt
|
|
|
(59,176
|
)
|
|
|
(59,176
|
)
|
|
|
(42,883
|
)
|
|
|
(42,883
|
)
|
Long-Term Debt including Current Maturities
|
|
|
(535,564
|
)
|
|
|
(582,743
|
)
|
|
|
(538,542
|
)
|
|
|
(583,835
|
)
|
14. 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 for the three
month periods ended March 31, 2017 and 2016:
|
|
Three Months Ended March 31,
|
|
(in thousands)
|
|
2017
|
|
|
2016
|
|
Income Before Income Taxes – Continuing Operations
|
|
$
|
25,892
|
|
|
$
|
19,982
|
|
Tax Computed at Company’s Net Composite Federal and State Statutory Rate (39%)
|
|
|
10,098
|
|
|
|
7,793
|
|
Increases (Decreases) in Tax from:
|
|
|
|
|
|
|
|
|
Federal Production Tax Credits
|
|
|
(2,052
|
)
|
|
|
(1,686
|
)
|
Excess Tax Deduction – 2014 Performance Share Awards
|
|
|
(697
|
)
|
|
|
—
|
|
Section 199 Domestic Production Activities Deduction
|
|
|
(330
|
)
|
|
|
(104
|
)
|
Corporate Owned Life Insurance
|
|
|
(294
|
)
|
|
|
(92
|
)
|
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes
|
|
|
(212
|
)
|
|
|
(212
|
)
|
Employee Stock Ownership Plan Dividend Deduction
|
|
|
(172
|
)
|
|
|
(158
|
)
|
Other Items – Net
|
|
|
22
|
|
|
|
(49
|
)
|
Income Tax Expense – Continuing Operations
|
|
$
|
6,363
|
|
|
$
|
5,492
|
|
Effective Income Tax Rate – Continuing Operations
|
|
|
24.6
|
%
|
|
|
27.5
|
%
|
The following table summarizes the activity related to our unrecognized
tax benefits:
(in thousands)
|
|
2017
|
|
|
2016
|
|
Balance on January 1
|
|
$
|
891
|
|
|
$
|
468
|
|
Increases Related to Tax Positions for Prior Years
|
|
|
—
|
|
|
|
—
|
|
Increases Related to Tax Positions for Current Year
|
|
|
43
|
|
|
|
16
|
|
Uncertain Positions Resolved During Year
|
|
|
—
|
|
|
|
—
|
|
Balance on March 31
|
|
$
|
934
|
|
|
$
|
484
|
|
The balance of unrecognized tax benefits as of March 31, 2017
would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of March 31,
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 March 31, 2017.
The Company and its subsidiaries file a consolidated U.S. federal
income tax return and various state income tax returns. As of March 31, 2017, with limited exceptions, the Company is no longer
subject to examinations by taxing authorities for tax years prior to 2013 for federal and Minnesota and North Dakota state income
taxes.
16. Discontinued Operations
Included in discontinued operations are activities related to
the Company’s former wind tower manufacturing business and dock and boatlift company. Included in liabilities of discontinued
operations are warranty reserves. Details regarding the warranty reserves follow:
(in thousands)
|
|
2017
|
|
|
2016
|
|
Warranty Reserve Balance, January 1
|
|
$
|
1,369
|
|
|
$
|
2,103
|
|
Additional Provision for Warranties Made During the Year
|
|
|
—
|
|
|
|
—
|
|
Settlements Made During the Year
|
|
|
(1
|
)
|
|
|
—
|
|
Decrease in Warranty Estimates for Prior Years
|
|
|
(100
|
)
|
|
|
—
|
|
Warranty Reserve Balance, March 31
|
|
$
|
1,268
|
|
|
$
|
2,103
|
|
The warranty reserve balances as of March 31, 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 one to 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.