Notes to Consolidated Financial Statements
For the years ended December 31, 2016, 2015 and 2014
1. Summary of Significant Accounting Policies
Principles of Consolidation
The consolidated financial statements of Otter Tail Corporation
and its wholly owned subsidiaries (the Company) include the accounts of the following segments: Electric, Manufacturing and Plastics.
See note 2 to consolidated financial statements for further descriptions of the Company’s business segments. All intercompany
balances and transactions have been eliminated in consolidation except profits on sales to the regulated electric utility company
from nonregulated affiliates, which is in accordance with the requirements of Financial Accounting Standards Board (FASB) Accounting
Standards Codification (ASC) Topic 980,
Regulated Operations
(ASC 980).
Regulation and ASC 980
The Company’s regulated electric utility company, Otter Tail
Power Company (OTP), accounts for the financial effects of regulation in accordance with ASC 980. This standard allows for the
recording of a regulatory asset or liability for costs and revenues that will be collected or refunded through the ratemaking process
in the future. In accordance with regulatory treatment, OTP defers utility debt redemption premiums and amortizes such costs over
the original life of the reacquired bonds. See note 4 to consolidated financial statements for further discussion.
OTP is subject to various state and federal agency regulations.
The accounting policies followed by this business are subject to the Uniform System of Accounts of the Federal Energy Regulatory
Commission (FERC). These accounting policies differ in some respects from those used by the Company’s nonelectric businesses.
Plant, Retirements and Depreciation
Utility plant is stated at original cost. The cost of additions
includes contracted work, direct labor and materials, allocable overheads and allowance for funds used during construction. The
amount of interest capitalized on electric utility plant was $495,000 in 2016, $723,000 in 2015 and $689,000 in 2014. The cost
of depreciable units of property retired less salvage is charged to accumulated depreciation. Removal costs, when incurred, are
charged against the accumulated reserve for estimated removal costs, a regulatory liability. Maintenance, repairs and replacement
of minor items of property are charged to operating expenses. The provisions for utility depreciation for financial reporting purposes
are made on the straight-line method based on the estimated remaining service lives of the properties (5 to 82 years). Such provisions
as a percent of the average balance of depreciable electric utility property were 2.88% in 2016, 2.61% in 2015 and 2.89% in 2014.
Gains or losses on group asset dispositions are taken to the accumulated provision for depreciation reserve and impact current
and future depreciation rates.
Property and equipment of nonelectric operations are carried at
historical cost or at the then-current replacement cost if acquired in a business combination, and are depreciated on a straight-line
basis over the assets’ estimated useful lives (3 to 40 years). The cost of additions includes contracted work, direct labor
and materials, allocable overheads and capitalized interest. No interest was capitalized on nonelectric plant in 2016, 2015 or
2014. Maintenance and repairs are expensed as incurred. Gains or losses on asset dispositions are included in the determination
of operating income.
Recoverability of Long-Lived Assets
The Company reviews its long-lived assets whenever events or changes
in circumstances indicate the carrying amount of the assets may not be recoverable. The Company determines potential impairment
by comparing the carrying amount of the assets with net cash flows expected to be provided by operating activities of the business
or related assets. If the sum of the expected future net cash flows is less than the carrying amount of the assets, the Company
would recognize an impairment loss. Such an impairment loss would be measured as the amount by which the carrying amount exceeds
the fair value of the asset, where fair value is based on the discounted cash flows expected to be generated by the asset.
Jointly Owned Facilities
OTP is a joint owner in two coal-fired steam-powered electric generation
plants: Big Stone Plant near Big Stone City, South Dakota and Coyote Station near Beulah, North Dakota. OTP is also a joint owner,
with other regional utilities, in three major in-service transmission lines and two additional major transmission lines under construction.
The following table provides OTP’s ownership percentages and amounts included in the Company’s December 31, 2016 and
2015 consolidated balance sheets for OTP’s share of jointly owned assets in each of these jointly owned facilities:
Jointly Owned Facilities
(dollars in thousands)
|
|
OTP
Ownership
Percentage
|
|
|
Electric Plant
in Service
|
|
|
Construction
Work in
Progress
|
|
|
Accumulated
Depreciation
|
|
|
Net Plant
|
|
December 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Stone Plant
|
|
|
53.9
|
%
|
|
$
|
328,809
|
|
|
$
|
23
|
|
|
$
|
(65,665
|
)
|
|
$
|
263,167
|
|
Coyote Station
|
|
|
35.0
|
%
|
|
|
176,315
|
|
|
|
113
|
|
|
|
(101,499
|
)
|
|
|
74,929
|
|
Fargo-Monticello 345 kV line
|
|
|
14.2
|
%
|
|
|
78,298
|
|
|
|
—
|
|
|
|
(3,511
|
)
|
|
|
74,787
|
|
Brookings-Southeast Twin Cities 345 kV line
1
|
|
|
4.8
|
%
|
|
|
26,406
|
|
|
|
—
|
|
|
|
(924
|
)
|
|
|
25,482
|
|
Bemidji-Grand Rapids 230 kV line
|
|
|
14.8
|
%
|
|
|
16,331
|
|
|
|
—
|
|
|
|
(1,573
|
)
|
|
|
14,758
|
|
Big Stone South to Brookings 345 kV line
1
|
|
|
50.0
|
%
|
|
|
—
|
|
|
|
45,050
|
|
|
|
—
|
|
|
|
45,050
|
|
Big Stone South to Ellendale 345 kV line
1
|
|
|
50.0
|
%
|
|
|
—
|
|
|
|
49,160
|
|
|
|
—
|
|
|
|
49,160
|
|
December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Big Stone Plant
|
|
|
53.9
|
%
|
|
$
|
327,474
|
|
|
$
|
(305
|
)
|
|
$
|
(57,641
|
)
|
|
$
|
269,528
|
|
Coyote Station
|
|
|
35.0
|
%
|
|
|
165,497
|
|
|
|
7,405
|
|
|
|
(103,822
|
)
|
|
|
69,080
|
|
Fargo-Monticello 345 kV line
|
|
|
14.2
|
%
|
|
|
78,272
|
|
|
|
—
|
|
|
|
(2,213
|
)
|
|
|
76,059
|
|
Brookings-Southeast Twin Cities 345 kV line
1
|
|
|
4.8
|
%
|
|
|
26,189
|
|
|
|
—
|
|
|
|
(486
|
)
|
|
|
25,703
|
|
Bemidji-Grand Rapids 230 kV line
|
|
|
14.8
|
%
|
|
|
16,331
|
|
|
|
—
|
|
|
|
(1,233
|
)
|
|
|
15,098
|
|
Big Stone South to Brookings 345 kV line
1
|
|
|
50.0
|
%
|
|
|
—
|
|
|
|
14,210
|
|
|
|
—
|
|
|
|
14,210
|
|
Big Stone South to Ellendale 345 kV line
1
|
|
|
50.0
|
%
|
|
|
—
|
|
|
|
8,335
|
|
|
|
—
|
|
|
|
8,335
|
|
1
|
Midcontinent Independent
System Operator, Inc. (MISO) Multi-Value Project (MVP) designation provides for a return on invested funds while under construction
under the MISO Open Access Transmission, Energy and Operating Reserve
Markets Tariff (MISO Tariff).
|
The Company’s share of direct revenue and expenses of the
jointly owned facilities is included in operating revenue and expenses in the consolidated statements of income.
Coyote Station Lignite Supply Agreement – Variable Interest
Entity
—In October 2012, the Coyote Station owners, including 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. Coyote Station started taking delivery of coal and paying for coal
and accumulated development fees and capital charges under the LSA in May 2016. 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 December 31, 2016 could be as high as $60.6 million, OTP’s 35% share
of unrecovered costs.
Income Taxes
Comprehensive interperiod income tax allocation is used for substantially
all book and tax temporary differences. Deferred income taxes arise for all temporary differences between the book and tax basis
of assets and liabilities. Deferred taxes are recorded using the tax rates scheduled by tax law to be in effect in the periods
when the temporary differences reverse. The Company amortizes investment tax credits over the estimated lives of related property.
The Company records income taxes in accordance with ASC Topic 740,
Income Taxes,
and has recognized in its consolidated
financial statements the tax effects of all tax positions that are “more-likely-than-not” to be sustained on audit
based solely on the technical merits of those positions as of the balance sheet date. The term “more-likely-than-not”
means a likelihood of more than 50%. The Company
classifies interest and penalties on tax uncertainties as components
of the provision for income taxes. See note 14 to consolidated financial statements regarding the Company’s accounting for
uncertain tax positions.
The Company also is required to assess the realizability of its
deferred tax assets, taking into consideration the Company’s forecast of future taxable income, the reversal of other existing
temporary differences, available net operating loss carryforwards and available tax planning strategies that could be implemented
to realize the deferred tax assets. Based on this assessment, management must evaluate the need for, and amount of, valuation allowances
against the Company’s deferred tax assets. To the extent facts and circumstances change in the future, adjustments to the
valuation allowance may be required.
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 are recorded at the time of the sale based on historical information and
current trends. In the case of derivative instruments, such as OTP’s 2015 forward energy contracts, marked-to-market and
realized gains and losses are recognized on a net basis in revenue in accordance with ASC Topic 815,
Derivatives and Hedging
(ASC 815). Gains and losses on forward energy contracts subject to regulatory treatment, if any, have been 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.
Customer electricity use is metered and bills are rendered monthly.
Revenue is accrued for electricity consumed but not yet billed. Rate schedules applicable to substantially all customers include
a fuel clause adjustment, under which the rates are adjusted to reflect changes in average cost of fuels and purchased power, and
a surcharge for recovery of conservation-related expenses. Revenue is recognized for fuel and purchased power costs incurred in
excess of amounts recovered in base rates but not yet billed through the fuel clause adjustment, for conservation program incentives
and bonuses earned but not yet billed and for renewable resource, transmission-related and environmental incurred costs and investment
returns approved for recovery through riders.
Revenues on wholesale electricity sales from Company-owned
generating units are recognized when energy is delivered. For shared use of transmission facilities with certain regional transmission
cooperatives, revenues are estimated. Bills are rendered based on anticipated usage and settlements are made later based on actual
usage. Estimated revenues may be adjusted prior to settlement, or at the time of settlement, to reflect actual usage.
Under ASC 815, OTP accounts for forward energy contracts as derivatives
subject to mark-to-market accounting unless those contracts meet the definition of a capacity contract or are not subject to unplanned
netting, then OTP accounts for the contracts under the normal purchases and sales exception to mark-to-market accounting.
Manufacturing and Plastics operating revenues are recorded when
products are shipped.
Warranty Reserves
Certain products sold by the Company’s manufacturing and plastics
companies carry product warranties for one year after the shipment date. These companies’ standard product warranty terms
generally include post-sales support and repairs or replacement of a product at no additional charge for a specified period of
time. While these companies engage in extensive product quality programs and processes, including actively monitoring and evaluating
the quality of their component suppliers, they base their estimated warranty obligations on warranty terms, ongoing product failure
rates, repair costs, product call rates, average cost per call, and current period product shipments. The Company’s manufacturing
and plastics companies have not incurred any significant warranty costs over the last three fiscal years in continuing operations.
Shipping and Handling Costs
The Company includes revenues received for shipping and handling
in operating revenues. Expenses paid for shipping and handling are recorded as part of cost of goods sold.
Use of Estimates
The Company uses estimates based on the best information available
in recording transactions and balances resulting from business operations. As better information becomes available (or actual amounts
are known), the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting
estimates.
Cash Equivalents
The Company considers all highly liquid debt instruments purchased
with maturity of 90 days or less to be cash equivalents.
Investments
The following table provides a breakdown of the Company’s
investments at December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Cost Method:
|
|
|
|
|
|
|
|
|
Economic Development Loan Pools
|
|
$
|
54
|
|
|
$
|
81
|
|
Other
|
|
|
115
|
|
|
|
2,088
|
|
Equity Method Partnerships
|
|
|
23
|
|
|
|
22
|
|
Marketable Securities Classified as Available-for-Sale
|
|
|
8,225
|
|
|
|
8,093
|
|
Total Investments
|
|
$
|
8,417
|
|
|
$
|
10,284
|
|
Less: Aevenia, Inc. (AEV, Inc.) Escrow Funds Reported Under Other Current Assets
|
|
|
—
|
|
|
|
(1,500
|
)
|
Foley Company (Foley) Escrow Funds Reported Under Other Current Assets
|
|
|
—
|
|
|
|
(500
|
)
|
Investments
|
|
$
|
8,417
|
|
|
$
|
8,284
|
|
The Company’s marketable securities classified as available-for-sale
are held for insurance purposes and are reflected at their fair values on December 31, 2016. See further discussion below.
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 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 December 31, 2016 and December
31, 2015:
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
|
|
|
|
|
|
December 31, 2015
(in thousands)
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets – Other:
|
|
|
|
|
|
|
|
|
|
|
|
|
Money Market Escrow Accounts – AEV, Inc. and Foley Company Dispositions
|
|
$
|
2,000
|
|
|
|
|
|
|
|
|
|
Investments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Government-Backed and Government-Sponsored Enterprises’ Debt Securities – Held by Captive Insurance Company
|
|
|
|
|
|
$
|
4,235
|
|
|
|
|
|
Corporate Debt Securities – Held by Captive Insurance Company
|
|
|
|
|
|
|
3,858
|
|
|
|
|
|
Other Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
Money Market and Mutual Funds – Nonqualified Retirement Savings Plan
|
|
|
196
|
|
|
|
|
|
|
|
|
|
Total Assets
|
|
$
|
2,196
|
|
|
$
|
8,093
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Accrued Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Liabilities – Forward Gasoline Purchase Contracts
|
|
|
|
|
|
$
|
199
|
|
|
|
|
|
Total Liabilities
|
|
|
|
|
|
$
|
199
|
|
|
|
|
|
The valuation techniques and inputs used for the Level 2 fair value
measurements in the table above are as follows:
Forward Gasoline Purchase Contracts
–These
contracts were priced based on NYMEX quoted prices for Reformulated Blendstock for Oxygenate Blending (RBOB) Gasoline contracts.
Prices used for the fair valuation of these contracts are based on NYMEX daily reporting date quoted prices for RBOB contracts
with the same settlement periods. As of December 31, 2016 OTP held, and currently holds, no RBOB contracts.
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.
Inventories
Electric segment inventories are reported at average cost. The Manufacturing
and Plastics segments’ inventories are stated at the lower of average cost or market. Inventories consist of the following
at December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Finished Goods
|
|
$
|
27,755
|
|
|
$
|
25,971
|
|
Work in Process
|
|
|
11,754
|
|
|
|
12,821
|
|
Raw Material, Fuel and Supplies
|
|
|
44,231
|
|
|
|
46,624
|
|
Total Inventories
|
|
$
|
83,740
|
|
|
$
|
85,416
|
|
Goodwill and Other Intangible Assets
The Company accounts for goodwill and other intangible assets in
accordance with the requirements of ASC Topic 350,
Intangibles—Goodwill and Other,
measuring its goodwill for impairment
annually in the fourth quarter, and more often when events indicate the assets may be impaired. The Company does qualitative assessments
of its reporting units with recorded goodwill to determine if it is more likely than not that the fair value of the reporting unit
exceeds its book value. The Company also does quantitative assessments of its reporting units with recorded goodwill to determine
the fair value of the reporting unit.
In the fourth quarter of 2014 the Company entered into negotiations
to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This
impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first
quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge based on adjustments to the carrying value
of Foley. The fourth quarter 2014 and first quarter 2015 goodwill impairment losses are reflected in the results of discontinued
operations. See note 16 to consolidated financial statements.
On September 1, 2015 Miller Welding & Iron Works, Inc. (BTD-Illinois),
a wholly owned subsidiary of BTD Manufacturing, Inc. (BTD), acquired the assets of Impulse Manufacturing, Inc. (Impulse) of Dawsonville,
Georgia. The acquired business operates under the name BTD-Georgia. Based on the preliminary purchase price allocation, the difference
in the fair value of assets acquired and the price paid for Impulse resulted in an initial estimate of acquired goodwill of $8.2
million. A final determination of the purchase price was agreed to in June 2016 resulting in a $2.2 million reduction in acquired
goodwill in June 2016. See note 2 to the Company’s consolidated financial statements for more information.
The following tables summarize changes to goodwill by business segment
during 2016 and 2015:
(in thousands)
|
|
Gross Balance
December 31, 2015
|
|
|
Accumulated
Impairments
|
|
|
Balance (net of
impairments)
December 31, 2015
|
|
|
Adjustments to
Goodwill in
2016
|
|
|
Balance (net of
impairments)
December 31, 2016
|
|
Manufacturing
|
|
$
|
20,430
|
|
|
$
|
—
|
|
|
$
|
20,430
|
|
|
$
|
(2,160
|
)
|
|
$
|
18,270
|
|
Plastics
|
|
|
19,302
|
|
|
|
—
|
|
|
|
19,302
|
|
|
|
—
|
|
|
|
19,302
|
|
Total
|
|
$
|
39,732
|
|
|
$
|
—
|
|
|
$
|
39,732
|
|
|
$
|
(2,160
|
)
|
|
$
|
37,572
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Gross Balance
December 31, 2014
|
|
|
Accumulated
Impairments
|
|
|
Balance
(net of impairments)
December 31, 2014
|
|
|
Adjustments
and Additions
to Goodwill
in 2015
|
|
|
Balance
(net of impairments)
December 31, 2015
|
|
Manufacturing
|
|
$
|
12,186
|
|
|
$
|
—
|
|
|
$
|
12,186
|
|
|
$
|
8,244
|
|
|
$
|
20,430
|
|
Plastics
|
|
|
19,302
|
|
|
|
—
|
|
|
|
19,302
|
|
|
|
—
|
|
|
|
19,302
|
|
Total
|
|
$
|
31,488
|
|
|
$
|
—
|
|
|
$
|
31,488
|
|
|
$
|
8,244
|
|
|
$
|
39,732
|
|
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
. With the purchase of BTD-Georgia on September 1, 2015, the Company acquired
customer relationships valued at $4,870,000 to be amortized over 20 years and the seller entered into a covenant not to compete
valued at $620,000 to be amortized over three years. The final purchase price adjustment agreed to in June 2016 resulted in an
$810,000 increase in the fair value of acquired customer relationships and a $30,000 reduction in the fair value of the covenant
not to compete. The changes in the value of these intangibles had an insignificant impact on the Company’s consolidated net
income in 2016 related to a change in amortization expense that would have been recorded in 2015 had the adjusted asset values
been established on acquisition in 2015. See note 2 to the Company’s consolidated financial statements for more information.
The following table summarizes the components of the Company’s
intangible assets at December 31, 2016 and December 31, 2015:
December 31, 2016
(in thousands)
|
|
Gross Carrying
Amount
|
|
|
Accumulated
Amortization
|
|
|
Net Carrying
Amount
|
|
|
Remaining
Amortization
Periods
|
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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amortizable Intangible Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customer Relationships
|
|
$
|
21,681
|
|
|
$
|
6,714
|
|
|
$
|
14,967
|
|
|
48-236 months
|
Covenant not to Compete
|
|
|
620
|
|
|
|
69
|
|
|
|
551
|
|
|
32 months
|
Other Intangible Assets
|
|
|
639
|
|
|
|
543
|
|
|
|
96
|
|
|
9 months
|
Emission Allowances
|
|
|
59
|
|
|
|
NA
|
|
|
|
59
|
|
|
Expensed as used
|
Total
|
|
$
|
22,999
|
|
|
$
|
7,326
|
|
|
$
|
15,673
|
|
|
|
The amortization expense for these intangible assets was:
(in thousands)
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Amortization Expense – Intangible Assets
|
|
$
|
1,436
|
|
|
$
|
1,127
|
|
|
$
|
977
|
|
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 December 31,
|
|
(in thousands)
|
|
2016
|
|
|
2015
|
|
Noncash Investing Activities:
|
|
|
|
|
|
|
|
|
Transactions Related to Capital Additions not Settled in Cash
|
|
$
|
13,533
|
|
|
$
|
20,371
|
|
(in thousands)
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Cash Paid (Received) During the Year for:
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest (net of amount capitalized)
|
|
$
|
31,269
|
|
|
$
|
30,512
|
|
|
$
|
26,364
|
|
Income Taxes
|
|
$
|
(1,291
|
)
|
|
$
|
7,322
|
|
|
$
|
145
|
|
New Accounting Standards
Accounting Standards Update (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 December 31, 2016 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,
with the exception of the treatment of contributions in aid of construction in the Electric segment on which consensus treatment
has not been determined and guidance has not been provided. Currently, the Company reduces its investment in fixed assets for the
amount of these contributions. Should the Company be required to recognize these contributions as revenue under ASU 2014-09, it
could result in a significant increase in reported revenues and expenses. 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 2015-03
—In April 2015, the FASB issued ASU No.
2015-03,
Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs
(ASU
2015-03), which requires debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct
deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for interim
and annual reporting periods beginning after December 15, 2015 and must be applied retrospectively to balance sheets presented
for periods prior to adoption. The Company adopted the updated standards in ASU 2015-03 in the first quarter of 2016. In conjunction
with implementing this update, the Company is reclassifying the remaining balance of unamortized line of credit issuance costs
from the deferred debit section of its consolidated balance sheet to other assets, eliminating the deferred debits section of its
consolidated balance sheet and displaying long-term regulatory assets as a separate line item on its consolidated balance sheet.
The effects of applying the guidance in ASU 2015-03 retrospectively to the Company’s December 31, 2015 consolidated balance
sheet and statement of capitalization and of the associated reclassification of unamortized line of credit issuance costs are shown
in the following table:
(in thousands)
|
|
December 31, 2015
Previously Stated
|
|
|
Adjustments
|
|
|
December 31, 2015
Adjusted
|
|
Other Assets
|
|
$
|
31,108
|
|
|
$
|
1,676
|
|
|
$
|
32,784
|
|
Unamortized Debt Expense
|
|
|
3,897
|
|
|
|
(3,897
|
)
|
|
|
—
|
|
Total Assets
|
|
|
1,820,904
|
|
|
|
(2,221
|
)
|
|
|
1,818,683
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Maturities of Long-Term Debt
|
|
|
52,544
|
|
|
|
(122
|
)
|
|
|
52,422
|
|
Total Current Liabilities
|
|
|
271,238
|
|
|
|
(122
|
)
|
|
|
271,116
|
|
Capitalization
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-Term Debt—Net
|
|
|
445,945
|
|
|
|
(2,099
|
)
|
|
|
443,846
|
|
Total Capitalization
|
|
|
1,050,968
|
|
|
|
(2,099
|
)
|
|
|
1,048,869
|
|
Total Liabilities and Equity
|
|
|
1,820,904
|
|
|
|
(2,221
|
)
|
|
|
1,818,683
|
|
ASU 2015-11
—In July 2015, the 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, with early
adoption permitted. The Company does not expect the adoption of the updated standard to have a material impact on its consolidated
financial statements.
ASU 2015-16
—In September 2015, the FASB issued ASU
No. 2015-16,
Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments
(ASU 2015-16)
,
which requires that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period
in the reporting period in which the adjustment amounts are determined. The amendments in ASU 2015-16 require that the acquirer
record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other
income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed
at the acquisition date. The amendments in ASU 2015-16 are effective for fiscal years beginning after December 15, 2015, including
interim periods within those fiscal years and should be applied prospectively to adjustments to provisional amounts that occur
after the effective date, with earlier application permitted for financial statements that have not been issued. The Company elected
to adopt the updated standard in the fourth quarter of 2015 in order to apply the updates to its recent acquisition of BTD-Georgia.
Adoption of the updated standard did not have a material impact on the Company’s consolidated financial statements. The early
adoption of the standard alleviated the need for prior period adjustments of income related to the BTD-Georgia acquisition purchase
price adjustment recorded in June 2016. See note 2 to the Company’s consolidated financial statements for more information.
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,
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 2016-09
— In March 2016, the FASB issued ASU No.
2016-09,
Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting
(ASU
2016-09), which is intended to improve and simplify accounting and reporting requirements related to stock-based compensation programs.
The amendments in ASU 2016-09 change how companies account for certain aspects of share-based payments to employees, including:
(1) changing award classifications from liability to equity as a result of an increase in the permitted level of share withholding
to cover income taxes to satisfy statutory income tax withholding requirements on the awards, (2) recognizing excess tax benefits
as an adjustment to income tax expense when the awards vest rather than directly adjusting stockholders' equity, and (3) introducing
an accounting policy election that permits reporting entities to elect to account for forfeitures as they occur. The amendments
in ASU 2016-09 are effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods,
with early adoption permitted.
In the fourth quarter of 2016, the Company elected to early adopt
the updates in ASU 2016-09. The withholding provisions in the award agreements applicable to the Company’s outstanding performance
awards granted to executive officers in 2014, 2015 and 2016 allow for withholding up to the maximum statutory tax rates in the
applicable jurisdictions. The updates in ASU 2016-09 result in these awards being classified as equity awards rather than liability
awards, requiring the amount of expense recognized for these awards to be based on the grant-date fair value of the awards rather
than the reporting-date fair value of the awards. The reporting-date fair values of the 2014 and 2015 awards outstanding on December
31, 2015 were less than the grant-date fair values of the awards. On adoption of the updates in ASU 2016-09 in the fourth quarter
of 2016, the difference in expense that would have been recognized related to the outstanding 2014 and 2015 awards in 2014 and
2015 had the awards been classified as equity awards instead of liability awards results in a cumulative-effect net-of-tax adjustment
to retained earnings of $623,000, with related adjustments to unvested restricted stock liability, deferred tax and miscellaneous
paid-in capital accounts, effective as of January 1, 2016, as illustrated below:
Balance Sheet Account Affected, Effective January 1, 2016
|
|
Debit
|
|
|
Credit
|
|
Adjustment to Retained Earnings
|
|
$
|
623,000
|
|
|
|
|
|
Long-Term Incentive Payable
|
|
$
|
1,453,000
|
|
|
|
|
|
Deferred Taxes
|
|
$
|
416,000
|
|
|
|
|
|
Miscellaneous Paid-In Capital
|
|
|
|
|
|
$
|
2,492,000
|
|
The impact of adopting the updates in ASU 2016-09 effective January
1, 2016 on 2016 interim reporting periods was not material.
2. Business Combinations, Dispositions and Segment Information
Business Combinations
On September 1, 2015 BTD-Illinois, a wholly owned subsidiary of
BTD, acquired the assets of Impulse of Dawsonville, Georgia for $30.8 million in cash. A post-closing reduction in the purchase
price of $1.5 million was agreed to in June 2016 resulting in an adjusted purchase price of $29.3 million. The acquired business,
operating under the name BTD-Georgia, is a full-service metal fabricator located 30 miles north of Atlanta, Georgia, which offers
a wide range of metal fabrication services ranging from simple laser cutting services and high volume stamping to complex weldments
and assemblies for metal fabrication buyers and original equipment manufacturers. In addition to serving some of BTD’s existing
customers from a location closer to the customers’ manufacturing facilities, this acquisition provides opportunities for
growth in new and existing markets for BTD with complementing production capabilities that expand the capacity of services offered
by BTD. Pro forma results of operations have not been presented for this acquisition because the effect of the acquisition was
not material to the Company.
Below is condensed balance sheet information disclosing the final
allocation of the purchase price assigned to each major asset and liability category of BTD-Georgia:
(in thousands)
|
|
|
|
Assets:
|
|
|
|
|
Current Assets
|
|
$
|
4,906
|
|
Goodwill
|
|
|
6,083
|
|
Other Intangible Assets
|
|
|
6,270
|
|
Other Amortizable Assets
|
|
|
1,380
|
|
Fixed Assets
|
|
|
13,649
|
|
Total Assets
|
|
$
|
32,288
|
|
Liabilities:
|
|
|
|
|
Current Liabilities
|
|
$
|
2,971
|
|
Lease Obligation
|
|
|
11
|
|
Total Liabilities
|
|
$
|
2,982
|
|
Cash Paid
|
|
$
|
29,306
|
|
In the fourth quarter of 2015, the Company elected to early adopt
ASU No. 2015-16,
Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments,
which
requires that an acquirer in a business combination recognize adjustments to provisional amounts that are identified during the
measurement period in the reporting period in which the adjustment amounts are determined. The purchase price adjustment agreed
to in June 2016 resulted in a $2.2 million reduction to the value of acquired goodwill, a $0.8 million increase in the
fair value of acquired customer relationships and a $0.1 million increase in acquired liabilities. The changes in the value of
customer relationships had an immaterial impact on the Company’s consolidated net income in 2016 related to a change in amortization
expense that would have been recorded in 2015 had the adjusted asset values been established on acquisition in 2015.
The Company acquired no new businesses in 2016
or 2014.
In execution of the Company’s announced
strategy of realigning its business portfolio to reduce its risk profile and dedicate a greater portion of its resources toward
electric utility operations, the Company sold several of its holdings in recent years. On December 31, 2014 the Company was in
the process of negotiating the sales of Foley, its mechanical and prime contractor on industrial projects, and AEV, Inc., its electrical
design and construction services company, which resulted in the removal of its Construction segment from continuing operations.
The sale of Foley closed on April 30, 2015 and the sale of the assets of AEV, Inc. closed on February 28, 2015.
The results of operations of the Company’s recently disposed
businesses are reported as discontinued operations in the Company’s consolidated financial statements as of and for the years
ended December 31, 2016, 2015 and 2014, and are summarized in note 16 to consolidated financial statements.
Segment Information
The accounting policies of the segments are described under note
1 – Summary of Significant Accounting Policies. 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, 2015 and 2014. All of the Company’s long-lived assets are within the United States and sales
within the United States accounted for 98.6% of sales in 2016, 97.1% of sales in 2015 and 95.9% of sales in 2014.
The Company evaluates the performance of its business
segments and allocates resources to them based on segment net income contribution and return on total invested capital. Information
on continuing operations for the business segments for 2016, 2015 and 2014 is presented in the following table:
(in thousands)
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Operating Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
427,383
|
|
|
$
|
407,131
|
|
|
$
|
407,743
|
|
Manufacturing
|
|
|
221,289
|
|
|
|
215,011
|
|
|
|
219,583
|
|
Plastics
|
|
|
154,901
|
|
|
|
157,758
|
|
|
|
172,050
|
|
Intersegment Eliminations
|
|
|
(34
|
)
|
|
|
(96
|
)
|
|
|
(114
|
)
|
Total
|
|
$
|
803,539
|
|
|
$
|
779,804
|
|
|
$
|
799,262
|
|
Cost of Products Sold
|
|
|
|
|
|
|
|
|
|
|
|
|
Manufacturing
|
|
$
|
171,732
|
|
|
$
|
171,956
|
|
|
$
|
169,033
|
|
Plastics
|
|
|
123,496
|
|
|
|
123,085
|
|
|
|
139,081
|
|
Intersegment Eliminations
|
|
|
(6
|
)
|
|
|
(9
|
)
|
|
|
(45
|
)
|
Total
|
|
$
|
295,222
|
|
|
$
|
295,032
|
|
|
$
|
308,069
|
|
Other Nonelectric Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Manufacturing
|
|
$
|
21,994
|
|
|
$
|
21,115
|
|
|
$
|
23,340
|
|
Plastics
|
|
|
9,402
|
|
|
|
9,850
|
|
|
|
9,292
|
|
Corporate
|
|
|
8,896
|
|
|
|
9,143
|
|
|
|
13,418
|
|
Intersegment Eliminations
|
|
|
(28
|
)
|
|
|
(87
|
)
|
|
|
(69
|
)
|
Total
|
|
$
|
40,264
|
|
|
$
|
40,021
|
|
|
$
|
45,981
|
|
Depreciation and Amortization
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
53,743
|
|
|
$
|
44,786
|
|
|
$
|
44,076
|
|
Manufacturing
|
|
|
15,794
|
|
|
|
11,853
|
|
|
|
10,518
|
|
Plastics
|
|
|
3,861
|
|
|
|
3,552
|
|
|
|
3,364
|
|
Corporate
|
|
|
47
|
|
|
|
172
|
|
|
|
116
|
|
Total
|
|
$
|
73,445
|
|
|
$
|
60,363
|
|
|
$
|
58,074
|
|
Operating Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
90,131
|
|
|
$
|
87,171
|
|
|
$
|
76,060
|
|
Manufacturing
|
|
|
11,769
|
|
|
|
10,086
|
|
|
|
16,692
|
|
Plastics
|
|
|
18,142
|
|
|
|
21,272
|
|
|
|
20,313
|
|
Corporate
|
|
|
(8,943
|
)
|
|
|
(9,315
|
)
|
|
|
(13,534
|
)
|
Total
|
|
$
|
111,099
|
|
|
$
|
109,214
|
|
|
$
|
99,531
|
|
(in thousands)
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Interest Charges
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
25,069
|
|
|
$
|
24,371
|
|
|
$
|
23,322
|
|
Manufacturing
|
|
|
3,859
|
|
|
|
3,560
|
|
|
|
3,243
|
|
Plastics
|
|
|
1,034
|
|
|
|
1,026
|
|
|
|
1,043
|
|
Corporate and Intersegment Eliminations
|
|
|
1,924
|
|
|
|
2,203
|
|
|
|
2,040
|
|
Total
|
|
$
|
31,886
|
|
|
$
|
31,160
|
|
|
$
|
29,648
|
|
Income Tax Expense (Benefit) – Continuing Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
16,366
|
|
|
$
|
16,067
|
|
|
$
|
11,029
|
|
Manufacturing
|
|
|
2,276
|
|
|
|
2,299
|
|
|
|
4,117
|
|
Plastics
|
|
|
6,538
|
|
|
|
8,187
|
|
|
|
7,301
|
|
Corporate
|
|
|
(5,099
|
)
|
|
|
(4,911
|
)
|
|
|
(5,890
|
)
|
Total
|
|
$
|
20,081
|
|
|
$
|
21,642
|
|
|
$
|
16,557
|
|
Net Income (Loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
49,829
|
|
|
$
|
48,370
|
|
|
$
|
43,684
|
|
Manufacturing
|
|
|
5,694
|
|
|
|
4,247
|
|
|
|
9,361
|
|
Plastics
|
|
|
10,628
|
|
|
|
12,108
|
|
|
|
12,085
|
|
Corporate
|
|
|
(4,114
|
)
|
|
|
(6,136
|
)
|
|
|
(8,247
|
)
|
Discontinued Operations
|
|
|
284
|
|
|
|
756
|
|
|
|
840
|
|
Total
|
|
$
|
62,321
|
|
|
$
|
59,345
|
|
|
$
|
57,723
|
|
Capital Expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
149,648
|
|
|
$
|
135,572
|
|
|
$
|
148,719
|
|
Manufacturing
|
|
|
8,429
|
|
|
|
20,295
|
|
|
|
11,252
|
|
Plastics
|
|
|
3,085
|
|
|
|
4,206
|
|
|
|
3,567
|
|
Corporate
|
|
|
97
|
|
|
|
11
|
|
|
|
44
|
|
Total
|
|
$
|
161,259
|
|
|
$
|
160,084
|
|
|
$
|
163,582
|
|
Identifiable Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
1,622,231
|
|
|
$
|
1,520,887
|
|
|
$
|
1,438,791
|
|
Manufacturing
|
|
|
166,525
|
|
|
|
173,860
|
|
|
|
128,608
|
|
Plastics
|
|
|
84,592
|
|
|
|
81,624
|
|
|
|
86,650
|
|
Corporate
|
|
|
39,037
|
|
|
|
42,312
|
|
|
|
36,508
|
|
Assets of Discontinued Operations
|
|
|
—
|
|
|
|
—
|
|
|
|
47,559
|
|
Total
|
|
$
|
1,912,385
|
|
|
$
|
1,818,683
|
|
|
$
|
1,738,116
|
|
3. Rate and Regulatory Matters
Below are descriptions of OTP’s major capital expenditure
projects and use of reagents and emission allowances 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 FERC, impacting OTP’s revenues in 2016, 2015 and 2014.
Major Capital Expenditure Projects
The Big Stone South – Brookings MVP and 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 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.
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.
Capacity Expansion 2020 (CapX2020) Transmission Line
Projects
—CapX2020 is a joint initiative of eleven investor-owned, cooperative, and municipal utilities in Minnesota and
the surrounding region to upgrade and expand the electric transmission grid to ensure continued reliable and affordable service.
Fargo–Monticello 345 kV CapX2020 Project (the
Fargo Project)
—OTP has invested approximately $81 million and has a 14.2% ownership interest in the jointly-owned assets
of this 240-mile transmission line, and owns 100% of certain assets of the project. The final phase of this project was energized
on April 2, 2015.
Brookings–Southeast Twin Cities 345 kV CapX2020
Project (the Brookings Project)
—OTP has invested approximately $26 million and has a 4.8% ownership interest in
this 250-mile transmission line. The MISO granted unconditional approval of the Brookings Project as an MVP under the MISO Tariff
in December 2011. The final segments of this line were energized on March 26, 2015.
Big Stone Plant Air Quality Control System (AQCS)
—
OTP completed construction and testing of the Big Stone Plant AQCS in the fourth quarter of 2015 and placed the AQCS into commercial
operation on December 29, 2015. OTP’s capitalized cost of the project, excluding allowance for funds used during construction,
was approximately $200 million.
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.
Reagent Costs
OTP’s systemwide costs for reagents are expected to increase
to approximately $2.2 million annually through May 2021 when Hoot Lake Plant is expected to be retired. The Minnesota, North Dakota
and South Dakota share of costs are approximately 50%, 40% and 10%, respectively. Reagent costs for the Big Stone Plant AQCS and
Coyote Station and Hoot Lake Plant Mercury and Air Toxics Standards (MATS) were initially incurred in 2015 when projects went into
service.
Minnesota
2016 General Rate Case
—On February 16, 2016 OTP filed
a request with the MPUC for an increase in revenue recoverable under general rates in Minnesota. In its filing, OTP requested an
allowed rate of return on rate base of 8.07% and an allowed rate of return on equity of 10.4% based on an equity ratio of 52.5%
of total capital. On April 14, 2016 the MPUC issued an order approving an interim rate increase of 9.56% to the base rate portion
of customers’ bills effective April 16, 2016, as modified and subject to refund. The request and interim rate information
is detailed in the table below:
($ in thousands)
|
|
Annualized or
Test Year
|
|
|
Actual Through
December 31, 2016
|
|
Revenue Increase Requested
|
|
$
|
19,296
|
|
|
|
|
|
Increase Percentage Requested
|
|
|
9.80
|
%
|
|
|
|
|
Jurisdictional Rate Base
|
|
$
|
483,000
|
|
|
|
|
|
Interim Revenue Increase (subject to refund)
|
|
$
|
16,816
|
|
|
$
|
10,976
|
|
The major components of the requested rate increase are summarized
below:
Revenue Requirement Deficiency Cost Factors
(in thousands)
|
|
2016 Test Year
Allocation
|
|
Increased Rate Base
|
|
$
|
10,000
|
|
Increased Expenses
|
|
|
7,700
|
|
Other
|
|
|
1,596
|
|
Total Requested Revenue Increase
|
|
$
|
19,296
|
|
Excluded from Interim Rates: Rate Base Effect of Prepaid Pension Asset
|
|
|
(2,480
|
)
|
Approved Interim Revenue Increase (subject to refund)
|
|
$
|
16,816
|
|
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.
Based on OTP’s modifications to its original request and other
expected outcomes in the aforementioned rate case, OTP has recorded an estimated interim rate refund of $3.6 million as of December
31, 2016. Oral arguments before the MPUC are expected to occur in late February 2017. The MPUC is expected to make its final decision
in March 2017 and issue its written order in spring 2017.
2010 General Rate Case
—OTP’s most recently completed
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
—Under Minnesota
law, every regulated public utility that furnishes electric service must make annual investments and expenditures in energy conservation
improvements, or make a contribution to the state's energy and conservation account, in an amount equal to at least 1.5% of its
gross operating revenues from service provided in Minnesota.
The MNDOC may require a utility to make investments and expenditures
in energy conservation improvements whenever it finds that the improvement will result in energy savings at a total cost to the
utility less than the cost to the utility to produce or purchase an equivalent amount of a new supply of energy. Such MNDOC orders
can be appealed to the MPUC. Investments made pursuant to such orders generally are recoverable costs in rate cases, even though
ownership of the improvement may belong to the property owner rather than the utility. OTP recovers conservation related costs
not included in base rates under the Minnesota Conservation Improvement Program (MNCIP) through the use of an annual recovery mechanism
approved by the MPUC.
On September 26, 2014 the MPUC approved OTP’s 2013 financial
incentive request for $4.0 million, an updated surcharge rate to be effective October 1, 2014, as well as a change to the carrying
charge to be equal to the short term cost of debt set in OTP’s most recent general rate case.
OTP recognized a financial incentive for 2014 of $3.0 million
due, in part, to the MPUC lowering the MNCIP financial incentive from approximately $0.09 per kwh saved for 2013-2015 to $0.07
per kwh saved for 2014-2016. Additionally, OTP saved approximately 2 million less kwhs in 2014 compared with 2013 under conservation
improvement programs in Minnesota. On July 9, 2015 the MPUC granted approval of OTP’s 2014 financial incentive of $3.0 million
along with an updated surcharge with an effective date of October 1, 2015.
Based on results from the 2015 MNCIP program year, OTP recognized
a financial incentive of $4.2 million. The 2015 MNCIP program resulted in an approximate 39% increase in energy savings compared
to 2014 program results. On April 1, 2016 OTP requested approval for recovery of its 2015 MNCIP program costs not included in base
rates, a $4.3 million financial incentive and an update to the MNCIP surcharge from the MPUC. On July 19, 2016 the MPUC issued
an order approving OTP’s request with an effective date of October 1, 2016.
Based on results from the 2016 MNCIP program year, OTP recognized
a financial incentive of $5.1 million in 2016. The 2016 program resulted in an approximate 18% increase in energy savings compared
to 2015 program results. OTP will request approval for recovery of its 2016 MNCIP program costs not included in base rates, a $5.1
million financial incentive and an update to the MNCIP surcharge from the MPUC by April 1, 2017.
On May 25, 2016 the MPUC adopted the MNDOC’s proposed changes
to the MNCIP financial incentive. The new model will provide 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.
Transmission Cost Recovery Rider
—The Minnesota Public
Utilities Act (the MPU Act) provides a mechanism for automatic adjustment outside of a general rate proceeding to recover the costs
of new transmission facilities that have been previously approved by the MPUC in a Certificate of Need (CON) proceeding, certified
by the MPUC as a Minnesota priority
transmission project, made to transmit the electricity generated
from renewable generation sources ultimately used to provide service to the utility's retail customers, or exempt from the requirement
to obtain a Minnesota CON. The MPUC may also authorize cost recovery via such TCR riders for charges incurred by a utility under
a federally approved tariff that accrue from other transmission owners’ regionally planned transmission projects that have
been determined by the MISO to benefit the utility or integrated transmission system. The MPU Act also authorizes TCR riders to
recover the costs of new transmission facilities approved by the regulatory commission of the state in which the new transmission
facilities are to be constructed, to the extent approval is required by the laws of that state, and determined by the MISO to benefit
the utility or integrated transmission system. Finally, under certain circumstances, the MPU Act also authorizes TCR riders to
recover the costs associated with distribution planning and investments in distribution facilities to modernize the utility grid.
Such TCR riders allow 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.
MISO regional cost allocation allows OTP to recover some of the
costs of its transmission investment from other MISO customers.
OTP filed an annual update to its Minnesota TCR rider on February
7, 2013 to include three new projects as well as updated costs associated with existing projects. In a written order issued on
March 10, 2014, the MPUC approved OTP’s 2013 TCR rider update but found capitalized internal costs, costs in excess of CON
estimates and a carrying charge ineligible for recovery through the TCR rider. These items were removed from OTP’s Minnesota
TCR rider effective March 1, 2014. OTP is seeking recovery of the capitalized internal costs and costs in excess of CON estimates
in its current general rate case filing in Minnesota. In response to the MPUC’s approval of OTP’s annual TCR update,
OTP submitted a compliance filing in April 2014 reflecting the TCR rider revenue requirements changes relating to the MPUC’s
ruling and requesting no rate change be implemented at the time. The MPUC approved OTP’s compliance filing on June 19, 2014.
On February 18, 2015 the MPUC approved OTP’s 2014 TCR rider annual update with an effective date of March 1, 2015. OTP filed
an annual update to its Minnesota TCR rider on September 30, 2015 requesting revenue recovery of approximately $7.8 million. A
supplemental filing to the update was made on December 21, 2015 to address an issue surrounding the proration of accumulated deferred
income taxes and, in an unrelated adjustment, the TCR rider update revenue request was reduced to $7.2 million. On March 9,
2016 the MPUC issued an order approving OTP’s annual update to its TCR rider, with an effective date of April 1, 2016.
OTP filed an update to its TCR rider on April 29, 2016 to incorporate
the impact of bonus depreciation for income taxes, an adjusted rate of return on rate base and allocation factors to align with
its 2016 general rate case request. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis,
as recommended by the MNDOC. The proposed rate changes went into effect on September 1, 2016. The MPUC has granted extensions to
the MNDOC to file initial comments in this docket until February 2, 2017.
In OTP’s 2016 general rate case, the MNDOC has argued that
the MPUC should require OTP to include in the TCR rider retail rate base 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. OTP has opposed this treatment, arguing that the projects
are appropriately assigned to the FERC jurisdiction, and the FERC’s determination of the projects’ revenue requirements
should not be altered by forcing the revenues into the retail revenue requirement calculations. In the general rate case proceeding,
the ALJ has recommended that the MPUC should affirm OTP’s treatment. If the MPUC finds that the MNDOC’s treatment should
be followed, it would result in the projects being treated as retail investments for Minnesota retail ratemaking purposes. Because
the FERC’s revenue requirements and authorized returns will vary from the MPUC revenue requirements and authorized returns
for the project investments over the lives of the projects, the impact of this decision will vary over time and be dependent on
the differences between the revenue requirements and returns in the two jurisdictions at any given time.
Environmental Cost Recovery (ECR) Rider
—On December
18, 2013 the MPUC granted approval of OTP’s Minnesota ECR rider for recovery of OTP’s Minnesota jurisdictional share
of the revenue requirements of its investment in the Big Stone Plant AQCS effective January 1, 2014. The ECR rider recoverable
revenue requirements included a return on the project’s construction work in progress (CWIP) balance at the level approved
in OTP’s 2010 general rate case. The MPUC approved OTP’s 2014 ECR rider annual update request on November 24, 2014
with an effective date of December 1, 2014. OTP filed its 2015 annual update on July 31, 2015, with a request to keep the 2014
annual update rate in place. On December 21, 2015 OTP filed a supplemental filing with updated financial information. The MPUC
issued an order on March 9, 2016 approving OTP’s request to leave the 2014 annual update rate in place. OTP filed an update
to its Minnesota ECR rider on April 29, 2016 to incorporate the impact of bonus depreciation for income taxes, an adjusted rate
of return on rate base and allocation factors to align with its 2016 general rate case request, with an effective date of September
1, 2016. On July 5, 2016 the MPUC issued an order approving the proposed rates on a provisional basis and has since granted extensions
to the MNDOC to file initial comments in this docket until February 2, 2017. Reply comments were due from OTP on February 13, 2017.
Reagent Costs and Emission Allowances
—On July 31, 2014
OTP filed a request with the MPUC to revise its Fuel Clause Adjustment (FCA) rider in Minnesota to include recovery of reagent
and emission allowance costs. On March 12, 2015 the MPUC denied OTP’s request to revise its FCA rider to include recovery
of these costs. These costs are included in OTP’s 2016 general rate case in Minnesota and are being considered for recovery
either through the FCA rider or general rates. These costs are currently being expensed as incurred.
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 (NDRRA) 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. The NDPSC approved OTP’s 2013 annual update to its NDRRA on March 12, 2014
with an effective date of April 1, 2014, which resulted in a 13.5% reduction in the NDRRA rate. The NDPSC approved OTP’s
2014 annual update to the NDRRA, including a change in rate design from an amount per kwh consumed to a percentage of a customer’s
bill, on March 25, 2015 with an effective date of April 1, 2015. OTP submitted its 2015 annual update to the NDRRA rider rate on
December 31, 2015 with a requested implementation date of April 1, 2016. On February 25, 2016 OTP made a supplemental filing to
address the impact of bonus depreciation for income taxes and related deferred tax assets on the NDRRA, as well as an adjustment
to the estimated amount of Federal Production Tax Credits used. The NDPSC approved the NDRRA 2015 annual update on June 22, 2016
with an effective date of July 1, 2016. The updated NDRRA reflects a reduction in the return on equity (ROE) component of the rate
from 10.75%, approved in OTP’s most recent general rate case, to 10.50%. OTP submitted its 2016 annual update to the NDRRA
rider rate on December 30, 2016, requesting a decrease to the NDRRA rate from 7.573% to 7.005%, with a requested implementation
date of April 1, 2017.
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. The NDPSC
approved OTP’s 2014 annual update to its TCR rider rate on December 17, 2014 with an effective date of January 1, 2015. On
August 31, 2015 OTP filed its 2015 annual update to its North Dakota TCR rider rate requesting recovery of approximately $10.2
million for 2016 compared with $8.5 million for 2015, including costs assessed by the MISO as well as new costs from the Southwest
Power Pool (SPP) that OTP began incurring January 1, 2016. These new costs are associated with OTP’s load connected to the
transmission system of Central Power Electric Cooperative (CPEC). OTP’s load became subject to SPP transmission-related charges
when CPEC transmission assets were added to the SPP. The NDPSC approved OTP’s 2015 annual update to its TCR rider rate on
December 16, 2015, with an effective date of January 1, 2016. On September 1, 2016 OTP filed its annual update to the TCR rider
requesting a revenue requirement of $5.7 million, which includes a reduction of $2.6 million for a projected over-collection for
2016. Primary drivers of the decrease from the 2015 updated rider rate include the impact of federal bonus depreciation and unresolved
MISO ROE complaint proceedings. OTP filed a supplemental filing on September 14, 2016, requesting that the over-collection balance
be spread over the next two years for purposes of reducing the volatility of the rates from year to year. The NDPSC approved the
update on December 14, 2016. The new rates went into effect on January 1, 2017.
Environmental Cost Recovery Rider
—On December 18, 2013
the NDPSC approved OTP’s request for an ECR rider to recover OTP’s North Dakota jurisdictional share of the revenue
requirements associated with its investment in the Big Stone Plant AQCS. The ECR provides for a current return on CWIP and a return
on investment at the level approved in OTP’s most recent general rate case. On March 31, 2014 OTP filed an annual update
to its North Dakota ECR rider rate. The update included a request to increase the ECR rider rate from 4.319% of base rates to 7.531%
of base rates. The NDPSC approved OTP’s 2014 ECR rider annual update request on July 10, 2014 with an August 1, 2014 implementation
date. On March 31, 2015 OTP filed its annual update to the ECR. This update included a request to increase the ECR rider rate from
7.531% to 9.193% of base rates. The NDPSC approved the annual update on June 17, 2015 with an effective date of July 1, 2015, along
with the approval of recovery of OTP’s North Dakota jurisdictional share of Hoot Lake Plant MATS project costs.
On March 31, 2016 OTP filed its annual update to the ECR rider requesting
a reduction in the rate from 9.193% to 7.904% of base rates, or a revenue requirement reduction from $12.2 million to $10.4 million,
effective July 1, 2016. The rate reduction request was primarily due to the Company’s 2015 bonus depreciation election for
income taxes, which reduces revenue requirements. The filing was approved on June 22, 2016.
Reagent Costs and Emission Allowances
—On July 31, 2014
OTP filed a request with the NDPSC to revise its FCA rider in North Dakota to include recovery of new reagent and emission allowance
costs. On February 25, 2015 the NDPSC approved recovery of these costs through modification of the ECR rider, instead of recovery
through the FCA as OTP had proposed. The ECR rider reagent and emissions allowance charge became effective May 1, 2015.
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. The SDPUC approved OTP’s 2013 annual update
on February 18, 2014 with an effective date of March 1, 2014. The SDPUC approved OTP’s 2014 annual update on February 13,
2015 with an effective date of March 1, 2015. OTP filed its 2015 annual update on October 30, 2015 with a proposed effective date
of March 1, 2016. A supplemental filing was made on February 3, 2016 to true-up the filing to include the impact of bonus depreciation
elected for 2015, the inclusion of a deferred tax asset relating to a net operating loss and the proration of accumulated deferred
income taxes. This update included the recovery of new SPP transmission costs OTP began to incur on January 1, 2016. On February
12, 2016 the SDPUC approved OTP’s annual update to its TCR rider, with an effective date of March 1, 2016. On November 1,
2016 OTP filed the annual update to the South Dakota TCR rider. OTP made a supplemental filing on January 20, 2017 to include
updated costs through December 2016 as well as updated forecast information. The proposed effective date of the new rates is March
1, 2017.
Environmental Cost Recovery Rider
—On November 25, 2014
the SDPUC approved OTP’s ECR rider request to recover OTP’s South Dakota jurisdictional share of revenue requirements
associated with its investment in the Big Stone Plant AQCS and Hoot Lake Plant MATS projects, with an effective date of December
1, 2014. On August 31, 2015 OTP filed its annual update to the South Dakota ECR requesting recovery of approximately $2.7 million
in annual revenue. The SDPUC approved the request on October 15, 2015 with an effective date of November 1, 2015. On August 31,
2016 OTP filed its 2016 update to the ECR rider, requesting recovery of approximately $2.3 million in annual revenue. The SDPUC
approved the request on October 26, 2016 with an effective date of November 1, 2016. The lower revenue requirement is a result
of the implementation of federal bonus depreciation taken on the Big Stone Plant AQCS.
Reagent Costs and Emission Allowances
—On August 1,
2014 OTP filed a request with the SDPUC to revise its FCA rider in South Dakota to include recovery of reagent and emission allowance
costs. On September 16, 2014 the SDPUC approved OTP’s request to include recovery of these costs in its South Dakota FCA
rider.
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 years ended December 31:
Rate Rider
(in thousands)
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Minnesota
|
|
|
|
|
|
|
|
|
|
|
|
|
Conservation Improvement Program Costs and Incentives
1
|
|
$
|
12,920
|
|
|
$
|
10,724
|
|
|
$
|
7,757
|
|
Environmental Cost Recovery
|
|
|
12,443
|
|
|
|
10,238
|
|
|
|
6,891
|
|
Transmission Cost Recovery
|
|
|
5,795
|
|
|
|
5,202
|
|
|
|
6,275
|
|
North Dakota
|
|
|
|
|
|
|
|
|
|
|
|
|
Environmental Cost Recovery
|
|
|
11,089
|
|
|
|
9,502
|
|
|
|
5,872
|
|
Renewable Resource Adjustment
|
|
|
7,800
|
|
|
|
8,409
|
|
|
|
7,484
|
|
Transmission Cost Recovery
|
|
|
7,694
|
|
|
|
6,609
|
|
|
|
5,794
|
|
South Dakota
|
|
|
|
|
|
|
|
|
|
|
|
|
Environmental Cost Recovery
|
|
|
2,538
|
|
|
|
1,967
|
|
|
|
234
|
|
Transmission Cost Recovery
|
|
|
1,820
|
|
|
|
1,290
|
|
|
|
1,207
|
|
Conservation Improvement Program Costs and Incentives
|
|
|
468
|
|
|
|
583
|
|
|
|
435
|
|
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 October 20, 2011 the FERC reaffirmed the MVP cost allocation on rehearing.
Effective January 1, 2012 the FERC authorized OTP to recover 100%
of prudently incurred CWIP and Abandoned Plant Recovery on two projects approved by MISO as MVPs in MISO’s 2011 Transmission
Expansion Plan: the Big Stone South–Brookings MVP and the Big Stone South–Ellendale MVP.
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. On October
16, 2014 the FERC issued an order finding that the current MISO ROE may be unjust and unreasonable and setting the issue for hearing.
Parties, including OTP, sought rehearing of the FERC’s decision to set the November 12, 2013 complaint for hearing. This
rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought appeal to the United States Court
of Appeals for the District of Columbia (D.C. Circuit). 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. Parties, including OTP, sought rehearing of the FERC’s decision to set the November 12,
2013 complaint for hearing. This rehearing was denied on July 21, 2016. On September 19, 2016 the MISO transmission owners sought
appeal to the D.C. Circuit. 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%. The FERC is expected to issue its order not earlier than spring 2017.
Based on a potential reduction by the FERC in the ROE component
of the MISO Tariff, OTP recorded reductions in revenue of $1.6 million in 2016 and $1.1 million in 2015 and has 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.
4. Regulatory Assets and Liabilities
As a regulated entity, OTP accounts for the financial effects of
regulation in accordance with 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:
|
|
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
|
North Dakota Renewable Resource Rider Accrued Revenues
2
|
|
|
1,319
|
|
|
|
482
|
|
|
|
1,801
|
|
|
15 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
|
Minnesota Deferred Rate Case Expenses Subject to Recovery
1
|
|
|
1,082
|
|
|
|
—
|
|
|
|
1,082
|
|
|
12 months
|
Deferred Income Taxes
1
|
|
|
—
|
|
|
|
1,014
|
|
|
|
1,014
|
|
|
asset lives
|
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
|
Revenue for Rate Case Expenses Subject to Refund – Minnesota
|
|
|
711
|
|
|
|
208
|
|
|
|
919
|
|
|
16 months
|
Deferred Income Taxes
|
|
|
—
|
|
|
|
818
|
|
|
|
818
|
|
|
asset lives
|
Minnesota Transmission Cost Recovery Rider Accrued Refund
|
|
|
757
|
|
|
|
—
|
|
|
|
757
|
|
|
12 months
|
South Dakota Environmental Cost Recovery Rider Accrued Refund
|
|
|
285
|
|
|
|
—
|
|
|
|
285
|
|
|
12 months
|
Minnesota Environmental Cost Recovery Rider Accrued Refund
|
|
|
139
|
|
|
|
—
|
|
|
|
139
|
|
|
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.
|
|
December 31, 2015
|
|
|
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
|
|
$
|
7,439
|
|
|
$
|
99,293
|
|
|
$
|
106,732
|
|
|
see below
|
Deferred Marked-to-Market Losses
1
|
|
|
4,063
|
|
|
|
10,530
|
|
|
|
14,593
|
|
|
60 months
|
Conservation Improvement Program Costs and Incentives
2
|
|
|
4,411
|
|
|
|
4,266
|
|
|
|
8,677
|
|
|
18 months
|
Accumulated ARO Accretion/Depreciation Adjustment
1
|
|
|
—
|
|
|
|
5,672
|
|
|
|
5,672
|
|
|
asset lives
|
Big Stone II Unrecovered Project Costs – Minnesota
1
|
|
|
942
|
|
|
|
2,620
|
|
|
|
3,562
|
|
|
84 months
|
North Dakota Renewable Resource Rider Accrued Revenues
2
|
|
|
—
|
|
|
|
1,266
|
|
|
|
1,266
|
|
|
15 months
|
Debt Reacquisition Premiums
1
|
|
|
351
|
|
|
|
1,539
|
|
|
|
1,890
|
|
|
201 months
|
Minnesota Deferred Rate Case Expenses Subject to Recovery
1
|
|
|
291
|
|
|
|
—
|
|
|
|
291
|
|
|
12 months
|
Deferred Income Taxes
1
|
|
|
—
|
|
|
|
1,455
|
|
|
|
1,455
|
|
|
asset lives
|
Big Stone II Unrecovered Project Costs – South Dakota
2
|
|
|
100
|
|
|
|
643
|
|
|
|
743
|
|
|
89 months
|
MISO Schedule 26/26A Transmission Cost Recovery Rider True-up
2
|
|
|
698
|
|
|
|
355
|
|
|
|
1,053
|
|
|
24 months
|
Minnesota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
576
|
|
|
|
—
|
|
|
|
576
|
|
|
12 months
|
South Dakota Transmission Cost Recovery Rider Accrued Revenues
2
|
|
|
33
|
|
|
|
—
|
|
|
|
33
|
|
|
12 months
|
Minnesota Renewable Resource Rider Accrued Revenues
2
|
|
|
—
|
|
|
|
68
|
|
|
|
68
|
|
|
see below
|
Total Regulatory Assets
|
|
$
|
18,904
|
|
|
$
|
127,707
|
|
|
$
|
146,611
|
|
|
|
Regulatory Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated Reserve for Estimated Removal Costs – Net of Salvage
|
|
$
|
—
|
|
|
$
|
74,948
|
|
|
$
|
74,948
|
|
|
asset lives
|
Refundable Fuel Clause Adjustment Revenues
|
|
|
1,834
|
|
|
|
—
|
|
|
|
1,834
|
|
|
12 months
|
North Dakota Transmission Cost Recovery Rider Accrued Refund
|
|
|
132
|
|
|
|
—
|
|
|
|
132
|
|
|
12 months
|
Revenue for Rate Case Expenses Subject to Refund – Minnesota
|
|
|
—
|
|
|
|
1,279
|
|
|
|
1,279
|
|
|
see below
|
Deferred Income Taxes
|
|
|
—
|
|
|
|
1,110
|
|
|
|
1,110
|
|
|
asset lives
|
South Dakota Environmental Cost Recovery Rider Accrued Refund
|
|
|
185
|
|
|
|
—
|
|
|
|
185
|
|
|
12 months
|
Minnesota Environmental Cost Recovery Rider Accrued Refund
|
|
|
777
|
|
|
|
—
|
|
|
|
777
|
|
|
12 months
|
Deferred Gain on Sale of Utility Property – Minnesota Portion
|
|
|
5
|
|
|
|
95
|
|
|
|
100
|
|
|
216 months
|
North Dakota Environmental Cost Recovery Rider Accrued Refund
|
|
|
321
|
|
|
|
—
|
|
|
|
321
|
|
|
12 months
|
North Dakota Renewable Resource Rider Accrued Refund
|
|
|
68
|
|
|
|
—
|
|
|
|
68
|
|
|
12 months
|
Total Regulatory Liabilities
|
|
$
|
3,322
|
|
|
$
|
77,432
|
|
|
$
|
80,754
|
|
|
|
Net Regulatory Asset Position
|
|
$
|
15,582
|
|
|
$
|
50,275
|
|
|
$
|
65,857
|
|
|
|
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 December 31,
2016 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.
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 December 31, 2016.
Debt Reacquisition Premiums are being recovered from OTP customers
over the remaining original lives of the reacquired debt issues, the longest of which is 189 months.
Minnesota Deferred Rate Case Expenses Subject to Recovery relate
to costs incurred in conjunction with OTP’s 2016 rate case in Minnesota currently being recovered over a 24-month period
beginning with the establishment of interim rates in April 2016.
The 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
.
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
December 31, 2016.
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
December 31, 2016.
The North Dakota Environmental Cost Recovery Rider Accrued Revenues
relate to revenues earned on the North Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant
MATS projects that have not been billed to North Dakota customers as of December 31, 2016.
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 December 31, 2016.
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 Transmission Cost Recovery Rider Accrued Refund relates
to amounts collected for qualifying transmission system facilities and operating costs incurred to serve Minnesota customers that
are refundable to Minnesota customers as of December 31, 2016.
The South Dakota Environmental Cost Recovery Rider Accrued Refund
relates to amounts collected on the South Dakota share of OTP’s investments in the Big Stone Plant AQCS and Hoot Lake Plant
MATS projects that are refundable to South Dakota customers as of December 31, 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 December 31, 2016.
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 and carried at historical cost in the accompanying balance sheet. 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 December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Derivatives in Gain Positions Subject to Legally Enforceable Netting Arrangements
|
|
$
|
—
|
|
|
$
|
—
|
|
Open Contract Loss Positions Subject to Legally Enforceable Netting Arrangements
|
|
|
(17,382
|
)
|
|
|
(16,070
|
)
|
Net Balance Subject to Legally Enforceable Netting Arrangements
|
|
$
|
(17,382
|
)
|
|
$
|
(16,070
|
)
|
The following table provides a breakdown of OTP’s credit risk
standing on forward energy contracts in marked-to-market loss positions as of December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Loss Contracts Covered by Deposited Funds or Letters of Credit
|
|
$
|
—
|
|
|
$
|
199
|
|
Contracts Requiring Cash Deposits if OTP’s Credit Falls Below Investment Grade
1
|
|
|
17,382
|
|
|
|
15,871
|
|
Total Loss Contracts based on Current Market Values
|
|
$
|
17,382
|
|
|
$
|
16,070
|
|
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
|
|
$
|
17,382
|
|
|
$
|
15,871
|
|
Offsetting Gains with Counterparties under Master Netting Agreements
|
|
|
—
|
|
|
|
—
|
|
Reporting Date Deposit Requirement if Credit Risk Feature Triggered
|
|
$
|
17,382
|
|
|
$
|
15,871
|
|
6. Common Shares and Earnings per Share
Shelf Registration
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.
Common Share Distribution Agreement
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.
Under the Distribution Agreement, the Company will designate the
minimum price and maximum number of shares to be sold through JPMS on any given trading day or over a specified period of trading
days, and JPMS will use commercially reasonable efforts to sell such shares on such days, subject to certain conditions. Sales
of the shares, if any, will be made by means of ordinary brokers’ transactions on the NASDAQ Global Select Market at market
prices or as otherwise agreed with JPMS. The Company may also agree to sell shares to JPMS, as principal for its own account, on
terms agreed by the Company and JPMS in a separate agreement at the time of sale. The Company is not obligated to sell and JPMS
is not obligated to buy or sell any of the shares under the Distribution Agreement. The shares, if issued, will be issued pursuant
to the Company’s existing shelf registration statement.
2016 Common Stock Activity
Following is a reconciliation of the Company’s common shares
outstanding from December 31, 2015 through December 31, 2016:
Common Shares Outstanding, December 31, 2015
|
|
|
37,857,186
|
|
Issuances:
|
|
|
|
|
At-the-Market Offering
|
|
|
1,014,115
|
|
Automatic Dividend Reinvestment and Share Purchase Plan:
|
|
|
|
|
Dividends Reinvested
|
|
|
163,010
|
|
Cash Invested
|
|
|
115,801
|
|
Vesting of Executive Stock Performance Awards
|
|
|
54,700
|
|
Employee Stock Purchase Plan:
|
|
|
|
|
Cash Invested
|
|
|
53,875
|
|
Dividends Reinvested
|
|
|
23,713
|
|
Employee Stock Ownership Plan
|
|
|
23,837
|
|
Restricted Stock Issued to Directors
|
|
|
23,200
|
|
Vesting of Restricted Stock Units
|
|
|
21,825
|
|
Directors Deferred Compensation
|
|
|
542
|
|
Retirements:
|
|
|
|
|
Shares Withheld for Individual Income Tax Requirements
|
|
|
(3,668
|
)
|
Common Shares Outstanding, December 31, 2016
|
|
|
39,348,136
|
|
2014 Stock Incentive Plan
The 2014 Stock Incentive Plan (2014 Incentive Plan), which was approved
by the Company’s shareholders in April 2014, provides for the grant of stock options, stock appreciation rights, restricted
stock, restricted stock units, performance awards, and other stock and stock-based awards. A total of 1,900,000 common shares were
authorized for granting stock awards under the 2014 Incentive Plan, of which 1,356,811 were available for issuance as of December
31, 2016. The 2014 Incentive Plan terminates on December 13, 2023.
Employee Stock Purchase Plan
The 1999 Employee Stock Purchase Plan (Purchase Plan) allows eligible
employees to purchase the Company’s common shares at 85% of the market price at the end of each six-month purchase period.
For purchase periods beginning after January 1, 2017, the purchase price will be 100% of the market price at the end of each six-month
purchase period. On April 16, 2012, the Company’s shareholders approved an amendment to the Purchase Plan, increasing the
number of shares available under the Purchase Plan from 900,000 common shares to 1,400,000 common shares and making certain other
changes to the terms of the Purchase Plan. Of the 1,400,000 common shares authorized to be issued under the Purchase Plan, 384,159
were available for purchase as of December 31, 2016. At the discretion of the Company, shares purchased under the Purchase Plan
can be either new issue shares or shares purchased in the open market. To provide shares for purchases for the Purchase Plan, 53,875
common shares were issued in 2016, 42,253 common shares were issued in 2015 and 39,222 common shares were
issued in 2014. The shares to be purchased by employees participating
in the Purchase Plan were not material to the calculation of diluted earnings per share during the investment period.
Dividend Reinvestment and Share Purchase Plan
The Company’s shelf registration statement filed with the
SEC on May 11, 2015, as amended on October 13, 2015, provides for the issuance of up to 1,500,000 common shares under the Company's
Automatic Dividend Reinvestment and Share Purchase Plan (the Plan), which permits shares purchased by participants in the Plan
to be either new issue common shares or common shares purchased in the open market. New common shares issued under the Plan totaled
278,811 in 2016 and 302,519 in 2015, leaving 918,670 common shares available for issuance under the Plan as of December 31, 2016.
Earnings Per Share
The numerator used in the calculation of both basic and diluted
earnings per common share is net income with no adjustments in 2016, 2015 and 2014. 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:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Weighted Average Common Shares Outstanding – Basic
|
|
|
38,546,459
|
|
|
|
37,494,986
|
|
|
|
36,514,397
|
|
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
|
|
|
118,644
|
|
|
|
100,194
|
|
|
|
135,480
|
|
Underlying Shares Related to Nonvested Restricted Stock Units Granted to Employees
|
|
|
45,712
|
|
|
|
36,180
|
|
|
|
27,540
|
|
Nonvested Restricted Shares
|
|
|
16,778
|
|
|
|
22,848
|
|
|
|
49,998
|
|
Shares Expected to be Issued Under the Deferred Compensation Program for Directors
|
|
|
3,417
|
|
|
|
13,488
|
|
|
|
24,048
|
|
Potentially Dilutive Stock Options
|
|
|
—
|
|
|
|
330
|
|
|
|
1,096
|
|
Total Dilutive Shares
|
|
|
184,551
|
|
|
|
173,040
|
|
|
|
238,162
|
|
Weighted Average Common Shares Outstanding – Diluted
|
|
|
38,731,010
|
|
|
|
37,668,026
|
|
|
|
36,752,559
|
|
The effect of dilutive shares on earnings per share for the years
ended December 31, 2016, 2015 and 2014, resulted in no differences greater than $0.01 between basic and diluted earnings per share
in total or from continuing or discontinued operations in any period.
7. Share-Based Payments
Purchase Plan
Through December 31, 2016, the Purchase Plan allowed employees through
payroll withholding to purchase shares of the Company’s common stock at a 15% discount from the average market price on the
last day of a six month investment period. Under ASC Topic 718,
Compensation—Stock Compensation
(ASC 718)
,
the Company is required to record compensation expense related to the 15% discount. The 15% discount resulted in compensation expense
of $173,000 in 2016, $184,000 in 2015 and $175,000 in 2014. For purchase periods beginning after January 1, 2017, the purchase
price will be 100% of the market price at the end of each six-month purchase period.
Stock Options Granted Under the 1999 Incentive Plan
The Company granted 2,041,500 options for the purchase of the Company’s
common stock under the 1999 Stock Incentive Plan (1999 Incentive Plan). The exercise price of the options granted was the average
market price of the Company’s common stock on the grant date. Under ASC 718 accounting requirements, compensation expense
is recorded based on the estimated fair value of the options on their grant date using a fair-value option pricing model. Under
ASC 718 accounting requirements, the fair value of the options granted has been recorded as compensation expense over the requisite
service period (the vesting period of the options). The estimated fair value of all options granted under the 1999 Incentive Plan
was based on the Black-Scholes option pricing model. There were no options outstanding as of December 31, 2016 or December 31,
2015.
Presented below is a summary of the stock options activity:
Stock Option Activity
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
Options
|
|
|
Average
Exercise
Price
|
|
|
Options
|
|
|
Average
Exercise
Price
|
|
|
Options
|
|
|
Average
Exercise
Price
|
|
Outstanding, Beginning of Year
|
|
|
—
|
|
|
|
|
|
|
|
12,750
|
|
|
$
|
24.93
|
|
|
|
34,700
|
|
|
$
|
25.69
|
|
Exercised
|
|
|
—
|
|
|
|
|
|
|
|
10,250
|
|
|
|
24.93
|
|
|
|
20,800
|
|
|
|
26.11
|
|
Forfeited or Expired
|
|
|
—
|
|
|
|
|
|
|
|
2,500
|
|
|
|
24.93
|
|
|
|
1,150
|
|
|
|
26.495
|
|
Outstanding, End of Year
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
12,750
|
|
|
|
24.93
|
|
Exercisable, End of Year
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
12,750
|
|
|
|
24.93
|
|
Cash Received for Options Exercised
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
256,000
|
|
|
|
|
|
|
$
|
543,000
|
|
Intrinsic Value of Options Exercised
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
75,000
|
|
|
|
|
|
|
$
|
89,000
|
|
Restricted Stock Granted to Directors
Under the 1999 Incentive Plan and the 2014 Incentive Plan, restricted
shares of the Company’s common stock have been granted to members of the Company’s board of directors as a form of
compensation. Under ASC 718 accounting requirements, compensation expense related to restricted shares is based on the fair value
of the restricted shares on their grant dates. On April 11, 2016, 23,200 shares of restricted stock were granted to the Company’s
nonemployee directors. The grant-date fair value of each share of restricted stock granted on April 11, 2016 was $28.66 per share,
the average of the high and low market price on the date of grant. The restricted shares granted in 2016 vest 25% per year on April
8 of each year in the period 2017 through 2020 and are eligible for full dividend and voting rights. Restricted shares not vested
and dividends on those restricted shares are subject to forfeiture under the terms of the restricted stock award agreement.
Presented below is a summary of the status of directors’ restricted
stock awards for the years ended December 31:
Directors’ Restricted Stock Awards
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
Shares
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
|
Shares
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
|
Shares
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
Nonvested, Beginning of Year
|
|
|
38,217
|
|
|
$
|
29.78
|
|
|
|
38,050
|
|
|
$
|
27.47
|
|
|
|
42,483
|
|
|
$
|
25.03
|
|
Granted
|
|
|
23,200
|
|
|
|
28.66
|
|
|
|
15,200
|
|
|
|
31.775
|
|
|
|
16,800
|
|
|
|
29.41
|
|
Vested
|
|
|
15,083
|
|
|
|
28.28
|
|
|
|
15,033
|
|
|
|
25.96
|
|
|
|
21,233
|
|
|
|
24.11
|
|
Forfeited
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
Nonvested, End of Year
|
|
|
46,334
|
|
|
|
29.71
|
|
|
|
38,217
|
|
|
|
29.78
|
|
|
|
38,050
|
|
|
|
27.47
|
|
Compensation Expense Recognized
|
|
|
|
|
|
$
|
491,000
|
|
|
|
|
|
|
$
|
417,000
|
|
|
|
|
|
|
$
|
416,000
|
|
Fair Value of Shares Vested in Year
|
|
|
|
|
|
$
|
427,000
|
|
|
|
|
|
|
$
|
390,000
|
|
|
|
|
|
|
$
|
512,000
|
|
Restricted Stock Granted to Employees
Under the 1999 Incentive Plan and 2014 Incentive Plan, restricted
shares of the Company’s common stock have been granted to employees as a form of compensation. Under ASC 718 accounting requirements,
compensation expense related to restricted shares is based on the fair value of the restricted shares on their grant dates. No
shares of restricted stock were granted to employees in 2016 or 2015.
Presented below is a summary of the status of employees’ restricted
stock awards for the years ended December 31:
Employees’ Restricted Stock Awards
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
Shares
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
|
Shares
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
|
Shares
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
Nonvested, Beginning of Year
|
|
|
13,581
|
|
|
$
|
28.56
|
|
|
|
45,280
|
|
|
$
|
27.46
|
|
|
|
48,315
|
|
|
$
|
25.04
|
|
Granted
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
26,700
|
|
|
|
29.41
|
|
Vested
|
|
|
6,401
|
|
|
|
27.25
|
|
|
|
31,699
|
|
|
|
27.09
|
|
|
|
25,360
|
|
|
|
24.80
|
|
Forfeited
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
4,375
|
|
|
|
28.03
|
|
Nonvested, End of Year
|
|
|
7,180
|
|
|
|
29.72
|
|
|
|
13,581
|
|
|
|
28.56
|
|
|
|
45,280
|
|
|
|
27.46
|
|
Compensation Expense Recognized
|
|
|
|
|
|
$
|
96,000
|
|
|
|
|
|
|
$
|
359,000
|
|
|
|
|
|
|
$
|
998,000
|
|
Fair Value of Awards Vested
|
|
|
|
|
|
$
|
174,000
|
|
|
|
|
|
|
$
|
859,000
|
|
|
|
|
|
|
$
|
629,000
|
|
Restricted Stock Units Granted to Executive Officers
On February 4, 2016, 22,000 restricted stock units under the 2014
Incentive Plan were granted to the Company’s executive officers. The grant-date fair value of each restricted stock unit
was $28.915 per share, the average of the high and low market price on the date of grant. The restricted stock units granted to
executive officers in 2016 vest 25% per year on February 6 of each year in the period 2017 through 2020 and 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 vesting of restricted stock units is accelerated in the event of a
change in control, disability, death or retirement, subject to proration on retirement in certain cases.
Presented below is a summary of the status of restricted stock unit
awards granted to executive officers for the years ended December 31:
Executives’ Restricted Stock Unit Awards
|
|
2016
|
|
|
2015
|
|
|
|
Restricted
Stock
Units
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
|
Restricted
Stock
Units
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
Nonvested, Beginning of Year
|
|
|
24,300
|
|
|
$
|
31.682
|
|
|
|
—
|
|
|
|
|
|
Granted
|
|
|
22,000
|
|
|
|
28.915
|
|
|
|
29,100
|
|
|
$
|
31.681
|
|
Vested
|
|
|
4,475
|
|
|
|
31.69
|
|
|
|
4,800
|
|
|
|
31.675
|
|
Forfeited
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
Nonvested, End of Year
|
|
|
41,825
|
|
|
|
30.23
|
|
|
|
24,300
|
|
|
|
31.682
|
|
Compensation Expense Recognized
|
|
|
|
|
|
$
|
446,000
|
|
|
|
|
|
|
$
|
452,000
|
|
Fair Value of Awards Vested
|
|
|
|
|
|
$
|
142,000
|
|
|
|
|
|
|
$
|
152,000
|
|
Restricted Stock Units Granted to Employees
In 2016 the following restricted stock unit awards under the 2014
Incentive Plan were granted to key employees of the Company who are not executive officers:
|
|
Grant Date
|
|
Units
Granted
|
|
|
Grant-Date
Fair Value
per Award
|
|
Restricted Stock Units Vesting 100% on April 8, 2020
|
|
April 11, 2016
|
|
|
15,800
|
|
|
$
|
24.00
|
|
Restricted Stock Units Vesting 100% on April 8, 2020
|
|
September 21, 2016
|
|
|
1,420
|
|
|
$
|
30.59
|
|
The grant-date fair value of each restricted stock unit was based
on the average of the high and low market price of the Company’s common stock on the date of grant, discounted for the value
of the dividend exclusion over the four-year vesting period. Under the terms of the restricted stock unit award agreements, all
outstanding (unvested) restricted stock units held by a retiring grantee vest immediately on normal retirement.
Presented below is a summary of the status of employees’ restricted
stock unit awards for the years ended December 31:
Employees’ Restricted Stock Unit Awards
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
Restricted
Stock
Units
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
|
Restricted
Stock
Units
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
|
Restricted
Stock
Units
|
|
|
Weighted
Average
Grant-Date
Fair Value
|
|
Nonvested, Beginning of Year
|
|
|
46,600
|
|
|
$
|
23.75
|
|
|
|
45,900
|
|
|
$
|
21.82
|
|
|
|
56,180
|
|
|
$
|
19.79
|
|
Granted
|
|
|
17,220
|
|
|
|
24.54
|
|
|
|
15,650
|
|
|
|
25.89
|
|
|
|
11,800
|
|
|
|
24.95
|
|
Reinstated
|
|
|
—
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
75
|
|
|
|
30.81
|
|
Vested
|
|
|
12,250
|
|
|
|
19.03
|
|
|
|
12,250
|
|
|
|
19.46
|
|
|
|
14,305
|
|
|
|
18.05
|
|
Forfeited
|
|
|
4,200
|
|
|
|
24.51
|
|
|
|
2,700
|
|
|
|
22.84
|
|
|
|
7,850
|
|
|
|
18.90
|
|
Nonvested, End of Year
|
|
|
47,370
|
|
|
|
25.19
|
|
|
|
46,600
|
|
|
|
23.75
|
|
|
|
45,900
|
|
|
|
21.82
|
|
Compensation Expense Recognized
|
|
|
|
|
|
$
|
307,000
|
|
|
|
|
|
|
$
|
304,000
|
|
|
|
|
|
|
$
|
194,000
|
|
Fair Value of Awards Vested
|
|
|
|
|
|
$
|
233,000
|
|
|
|
|
|
|
$
|
238,000
|
|
|
|
|
|
|
$
|
258,000
|
|
Stock Performance Awards granted to Executive Officers
Stock performance award agreements have been granted under the 1999
Incentive Plan and the 2014 Incentive Plan for the Company’s executive officers. Under these agreements, the officers could
be awarded shares of the Company’s common stock based on the Company’s total shareholder return relative to that of
its peer group of companies in the Edison Electric Institute (EEI) Index over a three-year period beginning on January 1 of the
year the awards are granted. Awards granted in 2016 and 2015 also included a performance incentive based on the Company’s
average 3-year adjusted return on equity relative to a targeted average 3-year adjusted return on equity. The number of shares
earned, if any, will be awarded and issued at the end of each three-year performance measurement period. The participants have
no voting or dividend rights under these award agreements until the shares are issued at the end of the performance measurement
period.
On February 4, 2016 performance share awards were granted to the
Company’s executive officers under the 2014 Incentive Plan for the 2016-2018 performance measurement period. Under the 2016
performance share award agreements the aggregate award for performance at target is 81,500 shares. For target performance the Company’s
executive officers would earn an aggregate of 54,333 common shares based on the Company’s total shareholder return relative
to the total shareholder return of the companies that comprise the EEI Index over the performance measurement period of January
1, 2016 through December 31, 2018. The Company’s executive officers would also earn an aggregate of 27,167 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 122,250 common shares.
Under the 2016 performance award agreements, 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 the target amount at the
date of any such event. The vesting of these performance award agreements is accelerated and paid at target in the event of a change
in control, disability or death (and upon retirement at or after age 62 for certain officers who are parties to executive employment
agreements with the Company).
Through December 31, 2015, the income tax withholding terms applicable
to outstanding performance awards dictated that the awards be classified and accounted for as liability awards, in accordance with
the requirements of ASC 718, with compensation measured over the performance period based on the fair value of the award at the
end of each reporting period subsequent to the grant date. In the fourth quarter of 2016, the Company elected to early adopt the
updates in ASU 2016-09, resulting in the outstanding 2015 and 2016 performance awards being now classified as equity awards. See
note 1 for additional information on the impact of the adoption of ASU 2016-09.
The table below provides a summary of stock performance awards granted
and amounts expensed related to the stock performance awards:
Performance
Period
|
|
Maximum
Shares Subject
To Award
|
|
|
Target
Shares
|
|
|
Expense Recognized
in the Year Ended December 31,
1
|
|
|
Earned
Shares
|
|
|
|
|
|
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
|
2016-2018
|
|
|
122,250
|
|
|
|
81,500
|
|
|
$
|
798,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2015-2017
|
|
|
126,450
|
|
|
|
84,300
|
|
|
|
535,000
|
|
|
$
|
943,000
|
|
|
|
|
|
|
|
|
|
2014-2016
|
|
|
159,450
|
|
|
|
106,300
|
|
|
|
332,000
|
|
|
|
(64,000
|
)
|
|
$
|
1,422,000
|
|
|
|
121,491
|
|
2013-2015
|
|
|
90,600
|
|
|
|
45,300
|
|
|
|
—
|
|
|
|
(445,000
|
)
|
|
|
458,000
|
|
|
|
22,500
|
|
2012-2014
|
|
|
148,400
|
|
|
|
74,200
|
|
|
|
—
|
|
|
|
—
|
|
|
|
142,000
|
|
|
|
89,991
|
|
Total
|
|
|
|
|
|
|
|
|
|
$
|
1,665,000
|
|
|
$
|
434,000
|
|
|
$
|
2,022,000
|
|
|
|
233,982
|
|
1
Expenses prior to 2016 are not restated to reflect
what would have been expensed had the performance-to-date value of the outstanding awards been based on the grant-date fair value
of the awards rather than the reporting-date fair value of the awards.
Stock-based payment expense recognized in 2016 and 2015 for the
2016-2018 and 2015-2017 performance awards reflects the accelerated recognition of expense for outstanding and unvested awards
of executives who are eligible for retirement and whose awards vest on normal retirement, as defined in the performance award agreements,
prior to the vesting dates of the awards.
The earned shares shown in the table above for the 2014-2016 performance
period include shares received in 2017 by participants in the plan, based on the Company achieving a total shareholder return ranking
of 19 out of 43 companies in the EEI Index and a resulting payout at 114.29% of target. The earned shares also include shares for
a portion of the award that vested on normal retirement of the Company’s former CEO on July 1, 2015 that were issued in 2016
following the 180 day deferral period required under the Internal Revenue Code at a value of $26.35 per share or $848,000.
The earned shares shown in the table above for the 2013-2015 performance
period reflect shares that vested on normal retirement of the Company’s former CEO on July 1, 2015 that were issued in 2016
following the 180 day deferral period required under the Internal Revenue Code at a value of $26.35 per share or $593,000.
The earned shares shown in the table above for the 2012-2014 performance
period reflect shares received in 2015 by active participants in the plan on December 31, 2014, based on the Company achieving
a total shareholder return ranking of 21 out of 48 companies in the EEI Index and a resulting payout at 121.28% of target.
In connection with the resignation of executive officers in May
2014 and March 2012, the following unvested stock performance awards were forfeited: 8,900 granted in 2014, 4,900 granted in 2013,
and 6,600 granted in 2012.
As of December 31, 2016 the total remaining unrecognized amount
of compensation expense related to stock-based compensation for all of the Company’s stock-based payment programs was approximately
$4.0 million (before income taxes), which will be amortized over a weighted average period of 2.2 years.
8. Retained Earnings and Dividend 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 credit 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 December 31, 2016 the Company was in compliance with these financial
covenants. See note 10 to consolidated financial statements 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 December 31, 2016 OTP’s equity-to-total-capitalization ratio
including short-term debt was 52.9% and its net assets restricted from distribution totaled approximately $440,000,000. Total capitalization
for OTP cannot currently exceed $1,123,168,000.
9. Commitments and Contingencies of Continuing Operations
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.
Electric Utility Capacity and Energy Requirements and Coal Contracts
OTP has commitments for the purchase of capacity and energy requirements
under agreements extending into 2040. OTP has commitments under contracts providing for the purchase of a significant portion of
its current coal requirements. Current coal purchase agreements for Big Stone Plant and Coyote Station expire in 2017 and 2040,
respectively. In January 2016, OTP entered into 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.
The dollar amounts of OTP’s estimated purchase requirements under this agreement are excluded from the table below because
OTP has not committed to any minimum level of purchases under the agreement. Fuel clause adjustment mechanisms lessen the risk
of loss from market price changes because they provide for recovery of most fuel costs. See table below for schedule of commitments.
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. Rent expense from continuing operations was
$7,565,000, $6,447,000 and $10,165,000 for 2016, 2015 and 2014, respectively.
The amounts of the Company’s construction program and other
commitments and commitments under capacity and energy agreements, coal and coal delivery contracts and operating leases for continuing
operations as of December 31, 2016, are as follows:
|
|
Construction
Program and Other
|
|
|
Capacity and
Energy
|
|
|
Coal
Purchase
|
|
|
Operating Leases
|
|
(in thousands)
|
|
Commitments
|
|
|
Requirements
|
|
|
Commitments
|
|
|
OTP
|
|
|
Nonelectric
|
|
|
Total
|
|
2017
|
|
$
|
74,328
|
|
|
$
|
23,711
|
|
|
$
|
30,699
|
|
|
$
|
2,374
|
|
|
$
|
4,760
|
|
|
$
|
7,134
|
|
2018
|
|
|
7,139
|
|
|
|
24,356
|
|
|
|
21,563
|
|
|
|
1,513
|
|
|
|
4,129
|
|
|
|
5,642
|
|
2019
|
|
|
3,331
|
|
|
|
24,925
|
|
|
|
22,102
|
|
|
|
1,237
|
|
|
|
2,598
|
|
|
|
3,835
|
|
2020
|
|
|
—
|
|
|
|
24,844
|
|
|
|
22,331
|
|
|
|
1,251
|
|
|
|
2,259
|
|
|
|
3,510
|
|
2021
|
|
|
—
|
|
|
|
12,988
|
|
|
|
22,840
|
|
|
|
1,103
|
|
|
|
1,996
|
|
|
|
3,099
|
|
Beyond 2021
|
|
|
—
|
|
|
|
166,137
|
|
|
|
550,719
|
|
|
|
9,396
|
|
|
|
7,320
|
|
|
|
16,716
|
|
Total
|
|
$
|
84,798
|
|
|
$
|
276,961
|
|
|
$
|
670,254
|
|
|
$
|
16,874
|
|
|
$
|
23,062
|
|
|
$
|
39,936
|
|
Contingencies
Based on the reduction by the FERC in the ROE component of the MISO
Tariff, OTP has a $2.7 million liability on its balance sheet as of December 31, 2016 representing OTP’s best estimate of
its current refund obligation related to amounts collected under the MISO Tariff, net of amounts that would be subject to recovery
under state jurisdictional TCR riders.
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. These consolidated cases are currently held in abeyance while the parties
engage in mediation before the D.C. Circuit. OTP is an intervenor in these cases and a participant in mediation. 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 fossil fuel-fired power plants, proposed CO
2
emission guidelines for existing fossil fuel-fired power plants and proposed CO
2
standards of performance for CO
2
emissions from reconstructed and modified fossil fuel-fired power plants 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 CO
2
emission guidelines
for existing fossil fuel-fired power plants, 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 CO
2
emission guidelines on September 27, 2016 before the full court,
and a decision will likely be rendered in the first half of 2017. In addition, members of Congress and the new administration have
been very critical of the Clean Power Plan (CPP) and may take actions that could impact the rule or the litigation. Therefore,
while the CPP remains stayed, there is uncertainty regarding the future of the rule. The final outcome of this rulemaking process
could have an adverse impact on the Company’s business and results of operations.
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 December 31, 2016 will not be material.
10. Short-Term and Long-Term Borrowings
Short-Term Debt
The following table presents the status of the Company’s
lines of credit as of December 31, 2016 and December 31, 2015:
(in thousands)
|
|
Line Limit
|
|
|
In Use on
December 31,
2016
|
|
|
Restricted due to
Outstanding
Letters of Credit
|
|
|
Available on
December 31,
2016
|
|
|
Available on
December 31,
2015
|
|
Otter Tail Corporation Credit Agreement
|
|
$
|
130,000
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
130,000
|
|
|
$
|
90,334
|
|
OTP Credit Agreement
|
|
|
170,000
|
|
|
|
42,883
|
|
|
|
50
|
|
|
|
127,067
|
|
|
|
148,694
|
|
Total
|
|
$
|
300,000
|
|
|
$
|
42,883
|
|
|
$
|
50
|
|
|
$
|
257,067
|
|
|
$
|
239,028
|
|
Under the Otter Tail Corporation Credit Agreement (as defined below),
the maximum amount of debt outstanding in 2016 was $63,757,000 on January 4, 2016 and the average daily balance of debt outstanding
during 2016 was $16,200,000. The weighted average interest rate paid on debt outstanding under the Otter Tail Corporation Credit
Agreement during 2016 was 2.3% compared with 2.0% in 2015. Under the OTP Credit Agreement (as defined below), the maximum amount
of debt outstanding in 2016 was $51,885,000 on December 16, 2016 and the average daily balance of debt outstanding during 2016
was $32,576,000. The weighted average interest rate paid on debt outstanding under the OTP Credit Agreement during 2016 was 1.8%
compared with 1.5% in 2015. The maximum amount of consolidated short-term debt outstanding in 2016 was $87,211,000 on January 25,
2016 and the average daily balance of consolidated short-term debt outstanding during 2016 was $48,776,000. The weighted average
interest rate on consolidated short-term debt outstanding on December 31, 2016 was 1.9%.
On October 29, 2012 the Company entered into a Third Amended and
Restated Credit Agreement (the Otter Tail Corporation Credit Agreement), which is an unsecured $130 million revolving credit facility
that may be increased to $250 million on the terms and subject to the conditions described in the Otter Tail Corporation Credit
Agreement. On October 31, 2016 the Otter Tail Corporation Credit Agreement was amended to extend its expiration date by one year
from October 29, 2020 to October 29, 2021 and the unsecured revolving credit facility was reduced from $150 million to $130
million. The Company can draw on this credit facility to refinance certain indebtedness and support its operations and the operations
of its subsidiaries. Borrowings under the Otter Tail Corporation Credit Agreement bear interest at LIBOR plus 1.75%, subject to
adjustment based on the Company’s senior unsecured credit ratings. The Company is required to pay commitment fees based on
the average daily unused amount available to be drawn under the revolving credit facility. The Otter Tail Corporation Credit Agreement
contains a number of restrictions on the Company and the businesses of its wholly owned subsidiary, Varistar Corporation (Varistar)
and its subsidiaries, including restrictions on the Company’s and Varistar’s ability to merge, sell assets, make investments,
create or incur liens on assets, guarantee the obligations of certain other parties and engage in transactions with related parties.
The Otter Tail Corporation Credit Agreement also contains affirmative covenants and events of default, and financial covenants
as described below under the heading “Financial Covenants.” The Otter Tail Corporation Credit Agreement does not include
provisions for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s
credit ratings. The Company’s obligations under the Otter Tail Corporation Credit Agreement are guaranteed by certain of
the Company’s subsidiaries. Outstanding letters of credit issued by the Company under the Otter Tail Corporation Credit Agreement
can reduce the amount available for borrowing under the line by up to $40 million.
On October 29, 2012 OTP entered into a Second Amended and Restated
Credit Agreement (the OTP Credit Agreement), providing for an unsecured $170 million revolving credit facility that may be increased
to $250 million on the terms and subject to the conditions described in the OTP Credit Agreement. On October 31, 2016 the OTP Credit
Agreement was amended to extend its expiration date by one year from October 29, 2020 to October 29, 2021. OTP can draw on this
credit facility to support the working capital needs and other capital requirements of its operations, including letters of credit
in an aggregate amount not to exceed $50 million outstanding at any time. Borrowings under this line of credit bear interest at
LIBOR plus 1.25%, subject to adjustment based on the ratings of OTP’s senior unsecured debt. OTP is required to pay commitment
fees based on the average daily unused amount available to be drawn under the revolving credit facility. The OTP Credit Agreement
contains a number of restrictions on the business of OTP, including restrictions on its ability to merge, sell assets, make investments,
create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related parties.
The OTP Credit Agreement also contains affirmative covenants and events of default, and financial covenants as described below
under the heading “Financial Covenants.” The OTP Credit Agreement does not include provisions for the termination of
the agreement or the acceleration of repayment of amounts outstanding due to changes in OTP’s credit ratings. OTP’s
obligations under the OTP Credit Agreement are not guaranteed by any other party.
Long-Term Debt Issuances and Retirements
2016 Note Purchase Agreement
On September 23, 2016 the Company entered into a Note Purchase Agreement
(the 2016 Note Purchase Agreement) with the purchasers named therein, pursuant to which the Company agreed to issue to the purchasers,
in a private placement transaction, $80 million aggregate principal amount of our 3.55% Guaranteed Senior Notes due December 15,
2026 (the 2026 Notes). The 2026 Notes were issued on December 13, 2016. The Company’s obligations under the 2016 Note Purchase
Agreement and the 2026 Notes are guaranteed by its Material Subsidiaries (as defined in the 2016 Note Purchase Agreement, but specifically
excluding OTP). The proceeds from the issuance of the 2026 Notes were used to repay the remaining $52,330,000 of our 9.000% Senior
Notes due December 15, 2016, and to pay down a portion of the $50 million in funds borrowed in February 2016 under the Company’s
term loan agreement.
The Company may prepay all or any part of the 2026 Notes (in an
amount not less than 10% of the aggregate principal amount of the 2026 Notes then outstanding in the case of a partial prepayment)
at 100% of the principal amount prepaid, together with unpaid accrued interest and a make-whole amount; provided that if no default
or event of default exists under the 2016 Note Purchase Agreement, any optional prepayment made by the Company of all of the 2026
Notes on or after September 15, 2026 will be made without any make-whole amount. The Company is required to offer to prepay all
of the outstanding 2026 Notes at 100% of the principal amount together with unpaid accrued interest in the event of a Change of
Control (as defined in the 2016 Note Purchase Agreement) of the Company. In addition, if the Company and its Material Subsidiaries
sell a “substantial part” of its or their assets and use the proceeds to prepay or retire senior Interest-bearing Debt
(as defined in the 2016 Note Purchase Agreement) of the Company and/or a Material Subsidiary in accordance with the terms of the
2016 Note Purchase Agreement, we are required to offer to prepay a Ratable Portion (as defined in the 2016 Note Purchase Agreement)
of the 2026 Notes held by each holder of the 2026 Notes.
The 2016 Note Purchase Agreement contains a number of restrictions
on the business of the Company and the Material Subsidiaries that became effective on execution of the 2016 Note Purchase Agreement.
These include restrictions on the Company’s and the Material Subsidiaries’ abilities to merge, sell assets, create
or incur liens on assets, guarantee the obligations of any other party, engage in transactions with related parties, redeem or
pay dividends on the Company’s and the Material Subsidiaries’ shares of capital stock, and make investments. The 2016
Note Purchase Agreement also contains other negative covenants and events of default, as well as certain financial covenants as
described below under the heading “Financial Covenants.” The 2016 Note Purchase Agreement does not include provisions
for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s
or the Material Subsidiaries’ credit ratings.
Term Loan Agreement
On February 5, 2016 the Company entered into a Term Loan Agreement
(the Term Loan Agreement) with the Banks named therein, JPMorgan Chase Bank, N.A., as administrative agent, and JPMS, as Lead Arranger
and Book Runner. The Term Loan Agreement provides for an unsecured term loan with an aggregate commitment of $50 million that the
Company may use for purposes of funding working capital, capital expenditures and other corporate purposes of the Company and certain
of our subsidiaries. Under the Term Loan Agreement, the Company may, on up to two occasions, enter into additional tranches of
term loans in minimum increments of $10 million, subject to the consent of the lenders and so long as the aggregate amount of outstanding
term loans does not exceed $100 million at any time. Borrowings under the Term Loan Agreement will bear interest at either (1)
LIBOR plus 0.90% or (2) the greater of (a) the Prime Rate, (b) the Federal Reserve Bank of New York Rate plus 0.50% and (c) LIBOR
multiplied by the Statutory Reserve Rate plus 1%. The applicable interest rate will depend on the Company’s election of whether
to make the advance a LIBOR advance. The Term Loan Agreement terminates on February 5, 2018.
On February 5, 2016 the Company borrowed $50 million under the Term
Loan Agreement at an interest rate based on the 30 day LIBOR plus 90 basis points and used the proceeds to pay down borrowings
under the Otter Tail Corporation Credit Agreement that were used to fund the expansion of BTD’s Minnesota facilities in 2015
and to fund the September 1, 2015 acquisition of BTD-Georgia.
The Term Loan Agreement contains a number of restrictions on the
Company, Varistar and certain subsidiaries of Varistar, including restrictions on its and their ability to merge, sell assets,
make investments, create or incur liens on assets, guarantee the obligations of any other party and engage in transactions with
related parties. The Term Loan Agreement also contains affirmative covenants and events of default, as well as certain financial
covenants as described below under the heading “Financial Covenants.” The Term Loan Agreement does not include provisions
for the termination of the agreement or the acceleration of repayment of amounts outstanding due to changes in the Company’s
credit ratings. The Company’s obligations under the Term Loan Agreement are guaranteed by Varistar and certain of its subsidiaries.
2013 Note Purchase Agreement
On August 14, 2013 OTP entered into a Note Purchase Agreement (the
2013 Note Purchase Agreement) pursuant to which OTP has agreed to issue to the purchasers named therein, in a private placement
transaction, $60 million aggregate principal amount of OTP’s 4.68% Series A Senior Unsecured Notes due February 27, 2029
(the Series A Notes) and $90 million aggregate principal amount of OTP’s 5.47% Series B Senior Unsecured Notes due February
27, 2044 (the Series B Notes and, together with the Series A Notes, the Notes). The Notes were issued on February 27, 2014. OTP
used a portion of the proceeds of the Notes to retire early a $40.9 million term loan then outstanding and to repay OTP’s
short-term debt outstanding on February 27, 2014. The remaining proceeds of the Notes were used to pay fees and expenses related
to the issuance of the Notes and for other general purposes, including construction program expenditures.
The 2013 Note Purchase Agreement states that OTP may prepay all
or any part of the Notes (in an amount not less than 10% of the aggregate principal amount of the Notes then outstanding in the
case of a partial prepayment) at 100% of the principal amount prepaid, together with accrued interest and a make-whole amount,
provided that if no default or event of default under the 2013 Note Purchase Agreement exists, any optional prepayment made by
OTP of (i) all of the Series A Notes then outstanding on or after November 27, 2028 or (ii) all of the Series B Notes then outstanding
on or after November 27, 2043, will be made at 100% of the principal prepaid but without any make-whole amount. In addition, the
2013 Note Purchase Agreement states OTP must offer to prepay all of the outstanding Notes at 100% of the principal amount together
with unpaid accrued interest in the event of a change of control of OTP.
The 2013 Note Purchase Agreement contains a number of restrictions
on the business of OTP, including restrictions on OTP’s ability to merge, sell assets, create or incur liens on assets, guarantee
the obligations of any other party, and engage in transactions with related parties. The 2013 Note Purchase Agreement also contains
affirmative covenants and events of default, as well as certain financial covenants as described below under the heading “Financial
Covenants.” The 2013 Note Purchase Agreement does not include provisions for the termination of the agreement or the acceleration
of repayment of amounts outstanding due to changes in OTP’s credit ratings. The 2013 Note Purchase Agreement includes a “most
favored lender” provision generally requiring that in the event OTP’s existing credit agreement or any renewal, extension
or replacement thereof, at any time contains any financial covenant or other provision providing for limitations on interest expense
and such a covenant is not contained in the 2013 Note Purchase Agreement under substantially similar terms or would be more beneficial
to the holders of the Notes than any analogous provision contained in the 2013 Note Purchase Agreement (an “Additional Covenant”),
then unless waived by the Required Holders (as defined in the 2013 Note Purchase Agreement), the Additional Covenant will be deemed
to be incorporated into the 2013 Note Purchase Agreement. The 2013 Note Purchase Agreement also provides for the amendment, modification
or deletion of an Additional Covenant if such Additional Covenant is amended or modified under or deleted from the OTP credit agreement,
provided that no default or event of default has occurred and is continuing.
2007 and 2011 Note Purchase Agreements
On December 1, 2011, OTP issued $140 million aggregate principal
amount of its 4.63% Senior Unsecured Notes due December 1, 2021 pursuant to a Note Purchase Agreement dated as of July 29, 2011
(the 2011 Note Purchase Agreement). OTP also has outstanding its $155 million senior unsecured notes issued in four series consisting
of $33 million aggregate principal amount of 5.95% Senior Unsecured Notes, Series A, due 2017; $30 million aggregate principal
amount of 6.15% Senior Unsecured Notes, Series B, due 2022; $42 million aggregate principal amount of 6.37% Senior Unsecured Notes,
Series C, due 2027; and $50 million aggregate principal amount of 6.47% Senior Unsecured Notes, Series D, due 2037 (collectively,
the 2007 Notes). The 2007 Notes were issued pursuant to a Note Purchase Agreement dated as of August 20, 2007 (the 2007 Note Purchase
Agreement).
The 2011 Note Purchase Agreement and the 2007 Note Purchase Agreement
each states that OTP may prepay all or any part of the notes issued thereunder (in an amount not less than 10% of the aggregate
principal amount of the notes then outstanding in the case of a partial prepayment) at 100% of the principal amount prepaid, together
with accrued interest and a make-whole amount. The 2011 Note Purchase Agreement states in the event of a transfer of utility assets
put event, the noteholders thereunder have the right to require OTP to repurchase the notes held by them in full, together with
accrued interest and a make-whole amount, on the terms and conditions specified in the 2011 Note Purchase Agreement. The 2011 Note
Purchase Agreement and the 2007 Note Purchase Agreement each also states that OTP must offer to prepay all of the outstanding notes
issued thereunder at 100% of the principal amount together with unpaid accrued interest in the event of a change of control of
OTP. The note purchase agreements contain a number of restrictions on OTP, including restrictions on OTP’s ability to merge,
sell assets, create or incur liens on assets, guarantee the obligations of any other party, and engage in transactions with related
parties. The note purchase agreements also include affirmative covenants and events of default, and certain financial covenants
as described below under the heading “Financial Covenants.”
Shelf Registration
On May 11, 2015 the Company filed a shelf registration statement
with the SEC 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, which expires on May 11, 2018.
The following tables provide a breakdown of the assignment of
the Company’s consolidated short-term and long-term debt outstanding as of December 31, 2016 and December 31, 2015:
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
|
|
December 31, 2015
(in thousands)
|
|
OTP
|
|
Otter Tail
Corporation
|
|
Otter Tail
Corporation
Consolidated
|
Short-Term Debt
|
|
$
|
21,006
|
|
|
$
|
59,666
|
|
|
$
|
80,672
|
|
Long-Term Debt:
|
|
|
|
|
|
|
|
|
|
|
|
|
9.000% Notes, due December 15, 2016
|
|
|
|
|
|
$
|
52,330
|
|
|
$
|
52,330
|
|
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
|
|
|
|
|
|
|
182
|
|
|
|
182
|
|
PACE Note, 2.54%, due March 18, 2021
|
|
|
|
|
|
|
977
|
|
|
|
977
|
|
Total
|
|
$
|
445,000
|
|
|
$
|
53,489
|
|
|
$
|
498,489
|
|
Less: Current Maturities net of Unamortized Debt Issuance Costs
|
|
|
|
|
|
|
52,422
|
|
|
|
52,422
|
|
Unamortized Long-Term Debt Issuance Costs
|
|
|
2,099
|
|
|
|
122
|
|
|
|
2,221
|
|
Total Long-Term Debt net of Unamortized Debt Issuance Costs
|
|
$
|
442,901
|
|
|
$
|
945
|
|
|
$
|
443,846
|
|
Total Short-Term and Long-Term Debt (with current maturities)
|
|
$
|
463,907
|
|
|
$
|
113,033
|
|
|
$
|
576,940
|
|
The aggregate amounts of maturities on bonds outstanding and
other long-term obligations at December 31, 2016 for each of the next five years are:
(in thousands)
|
|
2017
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
Aggregate Amounts of Debt Maturities
|
|
$
|
33,231
|
|
|
$
|
15,187
|
|
|
$
|
172
|
|
|
$
|
185
|
|
|
$
|
140,171
|
|
Financial Covenants
The Company and OTP were in compliance with the financial covenants
in these debt agreements as of December 31, 2016.
No Credit or Note Purchase Agreement contains any provisions
that would trigger an acceleration of the related debt as a result of changes in the credit rating levels assigned to the related
obligor by rating agencies.
The Company’s and OTP’s borrowing agreements are
subject to certain financial covenants. Specifically:
|
·
|
Under the Otter Tail Corporation Credit Agreement, the Term Loan Agreement and the 2016 Note Purchase Agreement, the Company
may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest
and Dividend Coverage Ratio to be less than 1.50 to 1.00 (each measured on a consolidated basis) as provided in the agreements.
|
|
|
|
|
·
|
Under the 2016 Note Purchase Agreement, the Company may not permit its Priority Indebtedness to exceed 10% of its Total Capitalization.
The Company had no Priority Indebtedness outstanding as of December 31, 2016.
|
|
|
|
|
·
|
Under the OTP Credit Agreement, OTP may not permit the ratio of its Interest-bearing Debt to Total Capitalization to be greater
than 0.60 to 1.00.
|
|
|
|
|
·
|
Under the 2007 Note Purchase Agreement and 2011 Note Purchase Agreement, OTP may not permit the ratio of its Consolidated Debt
to Total Capitalization to be greater than 0.60 to 1.00 or permit its Interest and Dividend Coverage Ratio to be less than 1.50
to 1.00, in each case as provided in the related borrowing agreement, and OTP may not permit its Priority Debt to exceed 20% of
its Total Capitalization, as provided in the related agreement.
|
|
|
|
|
·
|
Under the 2013 Note Purchase Agreement, OTP may not permit its Interest-bearing Debt to exceed 60% of Total Capitalization
and may not permit its Priority Indebtedness to exceed 20% of its Total Capitalization, each as provided in the 2013 Note Purchase
Agreement. OTP had no Priority Indebtedness outstanding as of December 31, 2016.
|
11. Pension Plan and Other Postretirement Benefits
For valuation of the Company’s pension and other postretirement
benefit plans’ projected benefit obligations as of December 31, 2016, the Company adopted updated and modified mortality
tables and an updated and modified mortality improvement scale that projects lower mortality improvements in the future for plan
participants. The adoption of the updated and modified mortality tables and mortality improvement scale in 2016 decreased the Company’s
pension and other postretirement benefit obligations from projected benefit obligations that would have been rendered using the
mortality tables the Company had been using since 2014. Although the adoption of the updated and modified tables and improvement
scale will have the effect of decreasing the estimated and recognized cost of future benefit payments in the near term, the ultimate
cost recognized will be determined by the actual level and duration of future benefit payments.
Pension Plan
The Company's noncontributory funded pension plan covers substantially
all corporate employees and OTP nonunion employees hired prior to September 1, 2006, and all union employees of OTP hired prior
to November 1, 2013, excluding Coyote Station employees. Coyote Station employees hired before January 1, 2009 are covered under
the plan. The plan provides 100% vesting after five vesting years of service and for retirement compensation at age 65, with reduced
compensation in cases of retirement prior to age 62. The Company reserves the right to discontinue the plan but no change or discontinuance
may affect the pensions theretofore vested.
The pension plan has a trustee who is responsible for pension
payments to retirees and a separate pension fund manager responsible for managing the plan's assets. An independent actuary assists
the Company in performing the necessary actuarial valuations for the plan.
The plan assets consist of common stock and
bonds of public companies, U.S. government securities, cash and cash equivalents and alternative investments. None of the plan
assets are invested in common stock or debt securities of the Company.
The following table lists components of net periodic pension
benefit cost for the year ended December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Service Cost–Benefit Earned During the Period
|
|
$
|
5,518
|
|
|
$
|
6,059
|
|
|
$
|
4,666
|
|
Interest Cost on Projected Benefit Obligation
|
|
|
14,195
|
|
|
|
13,344
|
|
|
|
13,111
|
|
Expected Return on Assets
|
|
|
(19,454
|
)
|
|
|
(18,383
|
)
|
|
|
(16,743
|
)
|
Amortization of Prior Service Cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
189
|
|
|
|
188
|
|
|
|
257
|
|
From Other Comprehensive Income
1
|
|
|
5
|
|
|
|
5
|
|
|
|
7
|
|
Amortization of Net Actuarial Loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
5,153
|
|
|
|
6,676
|
|
|
|
3,400
|
|
From Other Comprehensive Income
1
|
|
|
127
|
|
|
|
171
|
|
|
|
83
|
|
Net Periodic Pension Cost
|
|
$
|
5,733
|
|
|
$
|
8,060
|
|
|
$
|
4,781
|
|
1
Corporate cost included in Other Nonelectric Expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average assumptions used to determine net periodic
pension cost for the year ended December 31:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Discount Rate
|
|
|
4.76
|
%
|
|
|
4.35
|
%
|
|
|
5.30
|
%
|
Long-Term Rate of Return on Plan Assets
|
|
|
7.75
|
%
|
|
|
7.75
|
%
|
|
|
7.75
|
%
|
Rate of Increase in Future Compensation Level
|
|
|
3.13
|
%
|
|
|
3.13
|
%
|
|
|
3.13
|
%
|
The following table presents amounts recognized in the consolidated
balance sheets as of December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Regulatory Assets:
|
|
|
|
|
|
|
|
|
Unrecognized Prior Service Cost
|
|
$
|
141
|
|
|
$
|
329
|
|
Unrecognized Actuarial Loss
|
|
|
98,039
|
|
|
|
101,974
|
|
Total Regulatory Assets
|
|
$
|
98,180
|
|
|
$
|
102,303
|
|
Accumulated Other Comprehensive Loss:
|
|
|
|
|
|
|
|
|
Unrecognized Prior Service Cost
|
|
$
|
12
|
|
|
$
|
16
|
|
Unrecognized Actuarial Loss
|
|
|
406
|
|
|
|
820
|
|
Total Accumulated Other Comprehensive Loss
|
|
$
|
418
|
|
|
$
|
836
|
|
Noncurrent Liability
|
|
$
|
60,292
|
|
|
$
|
69,101
|
|
Funded status as of December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Accumulated Benefit Obligation
|
|
$
|
(281,414
|
)
|
|
$
|
(268,387
|
)
|
Projected Benefit Obligation
|
|
$
|
(314,637
|
)
|
|
$
|
(302,740
|
)
|
Fair Value of Plan Assets
|
|
|
254,345
|
|
|
|
233,639
|
|
Funded Status
|
|
$
|
(60,292
|
)
|
|
$
|
(69,101
|
)
|
The following tables provide a reconciliation
of the changes in the fair value of plan assets and the plan’s benefit obligations over the two-year period ended December
31, 2016:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Reconciliation of Fair Value of Plan Assets:
|
|
|
|
|
|
|
|
|
Fair Value of Plan Assets at January 1
|
|
$
|
233,639
|
|
|
$
|
244,589
|
|
Actual Return on Plan Assets
|
|
|
23,794
|
|
|
|
(9,160
|
)
|
Discretionary Company Contributions
|
|
|
10,000
|
|
|
|
10,000
|
|
Benefit Payments
|
|
|
(13,088
|
)
|
|
|
(11,790
|
)
|
Fair Value of Plan Assets at December 31
|
|
$
|
254,345
|
|
|
$
|
233,639
|
|
Estimated Asset Return
|
|
|
10.1
|
%
|
|
|
(3.7
|
)%
|
Reconciliation of Projected Benefit Obligation:
|
|
|
|
|
|
|
|
|
Projected Benefit Obligation at January 1
|
|
$
|
302,740
|
|
|
$
|
311,650
|
|
Service Cost
|
|
|
5,518
|
|
|
|
6,059
|
|
Interest Cost
|
|
|
14,195
|
|
|
|
13,344
|
|
Benefit Payments
|
|
|
(13,088
|
)
|
|
|
(11,790
|
)
|
Actuarial Loss (Gain)
|
|
|
5,272
|
|
|
|
(16,523
|
)
|
Projected Benefit Obligation at December 31
|
|
$
|
314,637
|
|
|
$
|
302,740
|
|
Weighted average assumptions used to determine benefit obligations
at December 31:
|
|
2016
|
|
|
2015
|
|
Discount Rate
|
|
|
4.60
|
%
|
|
|
4.76
|
%
|
Rate of Increase in Future Compensation Level
|
|
|
3.00
|
%
|
|
|
3.13
|
%
|
The assumed rate of return on pension fund
assets used for the determination of 2017 net periodic pension cost is 7.50%. The assumed long-term rate of return on plan assets
is based primarily on asset category studies using historical market return and volatility data with forward looking estimates
based on existing financial market conditions and forecasts of capital markets. Modest excess return expectations versus some market
indices are incorporated into the return projections based on the actively managed structure of the investment programs and their
records of achieving such returns historically. The Company reviews its rate of return on plan asset assumptions annually. The
assumptions are largely based on the asset category rate-of-return assumptions developed annually with the Company’s pension
plan investment advisors, as well as input from actuaries who work with the pension plan.
Market-related
value of plan assets
—
The Company’s expected return
on plan assets is determined based on the expected long-term rate of return on plan assets and the market-related value of plan
assets.
The Company bases actuarial determination
of pension plan expense or income on a market-related valuation of assets, which reduces year-to-year volatility. This market-related
valuation calculation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment
gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets
and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses
over a five-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses
are recognized.
Measurement Dates:
|
2016
|
2015
|
Net Periodic Pension Cost
|
January 1, 2016
|
January 1, 2015
|
End of Year Benefit Obligations
|
January 1, 2016 projected to
December 31, 2016
|
January 1, 2015 projected to
December 31, 2015
|
Market Value of Assets
|
December 31, 2016
|
December 31, 2015
|
The estimated amounts of unrecognized net
actuarial losses and prior service costs to be amortized from regulatory assets and accumulated other comprehensive loss into the
net periodic pension cost in 2017 are:
(in thousands)
|
|
2017
|
|
Decrease in Regulatory Assets:
|
|
|
|
|
Amortization of Unrecognized Prior Service Cost
|
|
$
|
120
|
|
Amortization of Unrecognized Actuarial Loss
|
|
|
5,090
|
|
Decrease in Accumulated Other Comprehensive Loss:
|
|
|
|
|
Amortization of Unrecognized Prior Service Cost
|
|
|
3
|
|
Amortization of Unrecognized Actuarial Loss
|
|
|
125
|
|
Total Estimated Amortization
|
|
$
|
5,338
|
|
Cash
flows
—
The Company had no minimum funding requirement
as of December 31, 2016 and will continue to evaluate if discretionary plan contributions will be made in 2017.
The following benefit payments, which reflect
expected future service, as appropriate, are expected to be paid out from plan assets:
(in thousands)
|
|
2017
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
|
Years
2022-2026
|
|
|
|
$
|
13,413
|
|
|
$
|
14,140
|
|
|
$
|
14,806
|
|
|
$
|
15,564
|
|
|
$
|
16,335
|
|
|
$
|
92,083
|
|
The following objectives guide the investment
strategy of the Company’s pension plan (the Plan):
|
·
|
The assets of the Plan will be invested in accordance with all applicable
laws in a manner consistent with fiduciary standards including Employee Retirement Income Security Act standards (if applicable).
Specifically:
|
|
o
|
The safeguards and diversity that a prudent investor would adhere
to must be present in the investment program.
|
|
o
|
All transactions undertaken on behalf of the Plan must be in the best
interest of plan participants and their beneficiaries.
|
|
·
|
The primary objective of the Plan is to provide a source of retirement
income for its participants and beneficiaries.
|
|
·
|
The near-term primary financial objective of the Plan is to improve
the funded status of the Plan.
|
|
·
|
A secondary financial objective is to minimize pension funding and
expense volatility where possible.
|
The asset allocation strategy developed by
the Company’s Retirement Plans Administration Committee (the Committee) is based on the current needs of the Plan and the
objectives listed above. An asset/liability review is conducted annually or as often as necessary to assess the impact of various
asset allocations on funded status and other financial variables. The current needs of the Plan, the overall investment objectives
above, the investment preferences and risk tolerance of the Committee and the desired degree of diversification suggest the need
for an investment allocation including multiple asset classes.
The asset allocation in the table below contains guideline percentages,
at market value, of the total Plan invested in various asset classes. The Permitted Range is a guide and will at times not reflect
the actual asset allocation as this will be dictated by market conditions, the independent actions of the Committee and/or Investment
Managers and required cash flows to and from the Plan. The Permitted Range anticipates this fluctuation and provides flexibility
for the Investment Managers’ portfolios to vary around the target without the need for immediate rebalancing. The Investment
Manager will proactively monitor the asset allocation and will direct the purchases and sales to remain within the stated ranges.
The policy of the Plan is to invest assets
in accordance with the allocations shown below:
|
|
Permitted Range
|
Asset Class / PBO Funded Status
|
|
< 100% PBO
|
|
100% PBO
|
|
105% PBO
|
|
>=110% PBO
|
Equity
|
|
30% - 65%
|
|
25% - 60%
|
|
20% - 55%
|
|
15% - 50%
|
Investment Grade Fixed Income
|
|
35% - 75%
|
|
40% - 80%
|
|
45% - 85%
|
|
50% - 90%
|
Below Investment Grade Fixed Income*
|
|
0% - 15%
|
|
0% - 15%
|
|
0% - 15%
|
|
0% - 15%
|
Other**
|
|
0% - 20%
|
|
0% - 20%
|
|
0% - 20%
|
|
0% - 20%
|
* Includes (but not limited to) High Yield Bond Fund and
Emerging Markets Debt funds.
** Other category may include cash, alternatives, and/or other investment strategies
that may be classified other than equity or fixed income, such as the Dynamic Asset Allocation fund.
|
The Company’s pension plan asset allocations
at December 31, 2016 and 2015, by asset category are as follows:
Asset Allocation
|
|
2016
|
|
|
2015
|
|
Large Capitalization Equity Securities
|
|
|
21.4
|
%
|
|
|
21.2
|
%
|
International Equity Securities
|
|
|
22.0
|
%
|
|
|
21.6
|
%
|
Small and Mid-Capitalization Equity Securities
|
|
|
9.0
|
%
|
|
|
8.1
|
%
|
SEI Dynamic Asset Allocation Fund
|
|
|
5.4
|
%
|
|
|
5.6
|
%
|
Equity Securities
|
|
|
57.8
|
%
|
|
|
56.5
|
%
|
Fixed-Income Securities and Cash
|
|
|
34.3
|
%
|
|
|
35.8
|
%
|
Other – SEI Energy Debt Collective Fund
|
|
|
4.1
|
%
|
|
|
3.6
|
%
|
Other – SEI Special Situation Collective Investment Trust
|
|
|
3.8
|
%
|
|
|
4.1
|
%
|
|
|
|
100.0
|
%
|
|
|
100.0
|
%
|
The following table presents the Company’s pension fund
assets measured at fair value and included in Level 1 of the fair value hierarchy and assets measured using the NAV practical expedient
to fair valuation as of December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Assets in Level 1 of the Fair Value Hierarchy
|
|
$
|
234,303
|
|
|
$
|
215,676
|
|
SEI Energy Debt Collective Fund at NAV
|
|
|
10,441
|
|
|
|
8,342
|
|
SEI Special Situation Collective Investment Trust Fund at NAV
(1)
|
|
|
9,601
|
|
|
|
9,621
|
|
Total Assets
|
|
$
|
254,345
|
|
|
$
|
233,639
|
|
(1)
On December 30, 2016
the Company instructed the pension fund manager to sell the pension fund investment in the SEI
Special Situation Collective Investment Trust Fund. The cash value of the investment on settlement of the sale in
January 2017 was $9,679,000.
Fair Value Measurements of Pension Fund Assets
ASC 715,
Compensation – Retirement Benefits,
requires
disclosures about pension plan assets identified by the three levels of the fair value hierarchy established by ASC 820-10-35.
The following table presents, the Company’s pension fund
assets measured at fair value and included in Level 1 of the fair value hierarchy as of December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Large Capitalization Equity Securities Mutual Fund
|
|
$
|
54,483
|
|
|
$
|
49,513
|
|
International Equity Securities Mutual Funds
|
|
|
55,916
|
|
|
|
50,504
|
|
Small and Mid-Capitalization Equity Securities Mutual Fund
|
|
|
23,011
|
|
|
|
18,823
|
|
SEI Dynamic Asset Allocation Mutual Fund
|
|
|
13,622
|
|
|
|
13,004
|
|
Fixed Income Securities Mutual Funds
|
|
|
87,268
|
|
|
|
83,830
|
|
Cash Management – Money Market Fund
|
|
|
3
|
|
|
|
2
|
|
Total Assets
|
|
$
|
234,303
|
|
|
$
|
215,676
|
|
The investments held by the SEI Special Situation Collective
Investment Trust on December 31, 2016 and 2015 consisted of investments primarily in hedge funds that pursue alternative strategies,
private equity funds and hybrid funds, as well as investments directly in other securities and financial instruments, with the
objective of achieving high returns balanced against an appropriate level of volatility and market exposure over a full market
cycle. The NAV of the SEI Special Situations Collective Investment Trust is determined by using the fair value of the portfolio
as of the close of business at the end of the year. The fair value of the fund is calculated independently by the fund’s
administrator and is reviewed by the Company.
The investments held by the SEI Energy Debt Collective Fund
on December 31, 2016 and 2015 consist mainly of below investment grade high yielding bonds and loans of U.S. energy companies which
trade at a discount to fair value. Redemptions are allowed semi-annually with a 95-day notice period, subject to fund director
consent and certain gate, holdback and suspension restrictions. Subscriptions are allowed monthly with a three-year lock up on
subscriptions. The Company invested $10.0 million in the SEI Energy Debt Fund in July 2015. The fund’s assets are valued
in accordance with valuations reported by the fund’s sub-advisor or the fund’s underlying investments or other independent
third party sources, although SEI in its discretion may use other valuation methods, subject to compliance with ERISA (as applicable).
The fund’s assets are valued as of the close of business on the last business day of each calendar month and are available
30 days after the end of a calendar quarter. On an annual basis, as determined by the investment manager in its sole discretion,
an independent valuation agent is retained to provide a valuation of the illiquid assets of the fund and of any other asset of
the fund, as determined by the investment manager in its sole discretion. The Company reviews and verifies the reasonableness of
the year-end valuations.
Executive Survivor and Supplemental Retirement Plan (ESSRP)
The ESSRP is an unfunded, nonqualified benefit plan for executive
officers and certain key management employees. The ESSRP provides defined benefit payments to these employees on their retirements
for life or to their beneficiaries on their deaths for a 15-year postretirement period. Life insurance carried on certain plan
participants is payable to the Company on the employee's death. There are no plan assets in this nonqualified benefit plan due
to the nature of the plan.
The following table lists components of net periodic pension
benefit cost for the year ended December 31:
(in thousands)
|
|
2016
|
|
|
|
2015
|
|
|
|
2014
|
|
Service Cost–Benefit Earned During the Period
|
|
$
|
252
|
|
|
$
|
189
|
|
|
$
|
51
|
|
Interest Cost on Projected Benefit Obligation
|
|
|
1,667
|
|
|
|
1,523
|
|
|
|
1,520
|
|
Amortization of Prior Service Cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
16
|
|
|
|
16
|
|
|
|
22
|
|
From Other Comprehensive Income
1
|
|
|
38
|
|
|
|
38
|
|
|
|
51
|
|
Amortization of Net Actuarial Loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
293
|
|
|
|
334
|
|
|
|
142
|
|
From Other Comprehensive Income
2
|
|
|
446
|
|
|
|
602
|
|
|
|
46
|
|
Net Periodic Pension Cost
|
|
$
|
2,712
|
|
|
$
|
2,702
|
|
|
$
|
1,832
|
|
1
Amortization of Prior Service Costs from Other Comprehensive
Income Charged to:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric Operation and Maintenance Expenses
|
|
$
|
15
|
|
|
$
|
15
|
|
|
$
|
20
|
|
Other Nonelectric Expenses
|
|
|
23
|
|
|
|
23
|
|
|
|
31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2
Amortization of Net Actuarial Loss from Other Comprehensive Income
Charged to:
|
|
|
|
|
|
|
|
|
|
|
|
|
Electric Operation and Maintenance Expenses
|
|
$
|
272
|
|
|
$
|
310
|
|
|
$
|
132
|
|
Other Nonelectric Expenses
|
|
|
174
|
|
|
|
292
|
|
|
|
(86
|
)
|
Weighted average assumptions used to determine net periodic
pension cost for the year ended December 31:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Discount Rate
|
|
|
4.76
|
%
|
|
|
4.35
|
%
|
|
|
5.30
|
%
|
Rate of Increase in Future Compensation Level
|
|
|
3.13
|
%
|
|
|
3.15
|
%
|
|
|
3.18
|
%
|
The following table presents amounts recognized
in the consolidated balance sheets as of December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Regulatory Assets:
|
|
|
|
|
|
|
|
|
Unrecognized Prior Service Cost
|
|
$
|
58
|
|
|
$
|
75
|
|
Unrecognized Actuarial Loss
|
|
|
2,890
|
|
|
|
2,936
|
|
Total Regulatory Assets
|
|
$
|
2,948
|
|
|
$
|
3,011
|
|
Projected Benefit Obligation Liability – Net Amount Recognized
|
|
$
|
(37,335
|
)
|
|
$
|
(35,811
|
)
|
Accumulated Other Comprehensive Loss:
|
|
|
|
|
|
|
|
|
Unrecognized Prior Service Cost
|
|
$
|
134
|
|
|
$
|
172
|
|
Unrecognized Actuarial Loss
|
|
|
5,915
|
|
|
|
5,815
|
|
Total Accumulated Other Comprehensive Loss
|
|
$
|
6,049
|
|
|
$
|
5,987
|
|
The following tables provide a reconciliation of the changes
in the fair value of plan assets and the plan’s projected benefit obligations over the two-year period ended December 31,
2016 and a statement of the funded status as of December 31 of both years:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Reconciliation of Fair Value of Plan Assets:
|
|
|
|
|
|
|
|
|
Fair Value of Plan Assets at January 1
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual Return on Plan Assets
|
|
|
—
|
|
|
|
—
|
|
Employer Contributions
|
|
|
1,188
|
|
|
|
1,119
|
|
Benefit Payments
|
|
|
(1,188
|
)
|
|
|
(1,119
|
)
|
Fair Value of Plan Assets at December 31
|
|
$
|
—
|
|
|
$
|
—
|
|
Reconciliation of Projected Benefit Obligation:
|
|
|
|
|
|
|
|
|
Projected Benefit Obligation at January 1
|
|
$
|
35,811
|
|
|
$
|
35,650
|
|
Service Cost
|
|
|
252
|
|
|
|
189
|
|
Interest Cost
|
|
|
1,667
|
|
|
|
1,523
|
|
Benefit Payments
|
|
|
(1,188
|
)
|
|
|
(1,119
|
)
|
Plan Amendments
|
|
|
—
|
|
|
|
—
|
|
Actuarial Loss (Gain)
|
|
|
793
|
|
|
|
(432
|
)
|
Projected Benefit Obligation at December 31
|
|
$
|
37,335
|
|
|
$
|
35,811
|
|
Weighted average assumptions used to determine benefit obligations
at December 31:
|
|
2016
|
|
|
2015
|
|
Discount Rate
|
|
|
4.60
|
%
|
|
|
4.76
|
%
|
Rate of Increase in Future Compensation Level
|
|
|
3.00
|
%
|
|
|
3.13
|
%
|
The estimated amounts of unrecognized net
actuarial losses and prior service costs to be amortized from regulatory assets and accumulated other comprehensive loss into the
net periodic pension cost for the ESSRP in 2017 are:
(in thousands)
|
|
2017
|
|
Decrease in Regulatory Assets:
|
|
|
|
|
Amortization of Unrecognized Prior Service Cost
|
|
$
|
16
|
|
Amortization of Unrecognized Actuarial Loss
|
|
|
285
|
|
Decrease in Accumulated Other Comprehensive Loss:
|
|
|
|
|
Amortization of Unrecognized Prior Service Cost
|
|
|
38
|
|
Amortization of Unrecognized Actuarial Loss
|
|
|
440
|
|
Total Estimated Amortization
|
|
$
|
779
|
|
Cash
flows
—
The ESSRP is unfunded and has no assets; contributions
are equal to the benefits paid to plan participants. The following benefit payments, which reflect future service, as appropriate,
are expected to be paid:
|
|
Years
|
|
(in thousands)
|
|
2017
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
|
2022-2026
|
|
|
|
$
|
1,253
|
|
|
$
|
1,487
|
|
|
$
|
1,562
|
|
|
$
|
1,544
|
|
|
$
|
1,754
|
|
|
$
|
12,700
|
|
Other Postretirement Benefits
The Company provides a portion of health insurance and life
insurance benefits for retired OTP and corporate employees. Substantially all of the Company's electric utility and corporate employees
may become eligible for health insurance benefits if they reach age 55 and have 10 years of service. There are no plan assets.
The following table lists components of net periodic postretirement benefit cost for the year ended December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Service Cost–Benefit Earned During the Period
|
|
$
|
1,301
|
|
|
$
|
1,297
|
|
|
$
|
1,055
|
|
Interest Cost on Projected Benefit Obligation
|
|
|
2,503
|
|
|
|
2,097
|
|
|
|
2,200
|
|
Amortization of Prior Service Cost
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
134
|
|
|
|
205
|
|
|
|
205
|
|
From Other Comprehensive Income
1
|
|
|
3
|
|
|
|
5
|
|
|
|
5
|
|
Amortization of Net Actuarial Loss
|
|
|
|
|
|
|
|
|
|
|
|
|
From Regulatory Asset
|
|
|
379
|
|
|
|
—
|
|
|
|
—
|
|
From Other Comprehensive Income
1
|
|
|
9
|
|
|
|
—
|
|
|
|
—
|
|
Net Periodic Postretirement Benefit Cost
|
|
$
|
4,329
|
|
|
$
|
3,604
|
|
|
$
|
3,465
|
|
Effect of Medicare Part D Subsidy
|
|
$
|
(923
|
)
|
|
$
|
(1,487
|
)
|
|
$
|
(948
|
)
|
1
Corporate cost included in Other Nonelectric Expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average assumptions used to determine net periodic
postretirement benefit cost for the year ended December 31:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Discount Rate
|
|
|
4.57
|
%
|
|
|
4.20
|
%
|
|
|
5.10
|
%
|
The following table presents amounts recognized
in the consolidated balance sheets as of December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Regulatory Asset:
|
|
|
|
|
|
|
|
|
Unrecognized Prior Service Cost
|
|
$
|
(4
|
)
|
|
$
|
129
|
|
Unrecognized Net Actuarial Loss
|
|
|
13,586
|
|
|
|
1,289
|
|
Net Regulatory Asset
|
|
$
|
13,582
|
|
|
$
|
1,418
|
|
Projected Benefit Obligation Liability – Net Amount Recognized
|
|
$
|
(62,571
|
)
|
|
$
|
(48,730
|
)
|
Accumulated Other Comprehensive (Income) Loss:
|
|
|
|
|
|
|
|
|
Unrecognized Prior Service Cost
|
|
$
|
4
|
|
|
$
|
8
|
|
Unrecognized Net Actuarial Gain
|
|
|
(171
|
)
|
|
|
(347
|
)
|
Accumulated Other Comprehensive Income
|
|
$
|
(167
|
)
|
|
$
|
(339
|
)
|
The following tables provide a reconciliation
of the changes in the fair value of plan assets and the plan’s projected benefit obligations and accrued postretirement benefit
cost over the two-year period ended December 31, 2016:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Reconciliation of Fair Value of Plan Assets:
|
|
|
|
|
|
|
|
|
Fair Value of Plan Assets at January 1
|
|
$
|
—
|
|
|
$
|
—
|
|
Actual Return on Plan Assets
|
|
|
—
|
|
|
|
—
|
|
Company Contributions
|
|
|
2,825
|
|
|
|
2,365
|
|
Benefit Payments (Net of Medicare Part D Subsidy)
|
|
|
(5,908
|
)
|
|
|
(5,324
|
)
|
Participant Premium Payments
|
|
|
3,083
|
|
|
|
2,959
|
|
Fair Value of Plan Assets at December 31
|
|
$
|
—
|
|
|
$
|
—
|
|
Reconciliation of Projected Benefit Obligation:
|
|
|
|
|
|
|
|
|
Projected Benefit Obligation at January 1
|
|
$
|
48,730
|
|
|
$
|
53,638
|
|
Service Cost (Net of Medicare Part D Subsidy)
|
|
|
1,301
|
|
|
|
1,297
|
|
Interest Cost (Net of Medicare Part D Subsidy)
|
|
|
2,503
|
|
|
|
2,097
|
|
Benefit Payments (Net of Medicare Part D Subsidy)
|
|
|
(5,908
|
)
|
|
|
(5,324
|
)
|
Participant Premium Payments
|
|
|
3,083
|
|
|
|
2,959
|
|
Actuarial Loss (Gain)
|
|
|
12,862
|
|
|
|
(5,937
|
)
|
Projected Benefit Obligation at December 31
|
|
$
|
62,571
|
|
|
$
|
48,730
|
|
Reconciliation of Accrued Postretirement Cost:
|
|
|
|
|
|
|
|
|
Accrued Postretirement Cost at January 1
|
|
$
|
(47,652
|
)
|
|
$
|
(46,413
|
)
|
Expense
|
|
|
(4,329
|
)
|
|
|
(3,604
|
)
|
Net Company Contribution
|
|
|
2,825
|
|
|
|
2,365
|
|
Accrued Postretirement Cost at December 31
|
|
$
|
(49,156
|
)
|
|
$
|
(47,652
|
)
|
Weighted average assumptions used to determine benefit obligations
at December 31:
|
|
2016
|
|
|
2015
|
|
Discount Rate
|
|
|
4.46
|
%
|
|
|
4.57
|
%
|
Assumed healthcare cost-trend rates as of December 31:
|
|
2016
|
|
|
2015
|
|
Healthcare Cost-Trend Rate Assumed for Next Year Pre-65
|
|
|
6.01
|
%
|
|
|
6.16
|
%
|
Healthcare Cost-Trend Rate Assumed for Next Year Post-65
|
|
|
6.23
|
%
|
|
|
6.43
|
%
|
Rate to Which the Cost-Trend Rate is Assumed to Decline
|
|
|
4.50
|
%
|
|
|
4.50
|
%
|
Year the Rate Reaches the Ultimate Trend Rate
|
|
|
2038
|
|
|
|
2038
|
|
Assumed healthcare cost-trend rates have a significant effect
on the amounts reported for healthcare plans. A one-percentage-point change in assumed healthcare cost-trend rates for 2016 would
have the following effects:
(in thousands)
|
|
1 Point
Increase
|
|
|
1 Point
Decrease
|
|
Effect on the Postretirement Benefit Obligation
|
|
$
|
7,151
|
|
|
$
|
(7,492
|
)
|
Effect on Total of Service and Interest Cost
|
|
$
|
653
|
|
|
$
|
(519
|
)
|
Effect on Expense
|
|
$
|
1,454
|
|
|
$
|
(907
|
)
|
Measurement Dates:
|
2016
|
2015
|
Net Periodic Postretirement Benefit Cost
|
January 1, 2016
|
January 1, 2015
|
|
|
|
End of Year Benefit Obligations
|
January 1, 2016 projected to
December 31, 2016
|
January 1, 2015 projected to
December 31, 2015
|
The estimated net amounts of unrecognized
prior service cost to be amortized from regulatory assets and accumulated other comprehensive loss into the net periodic postretirement
benefit cost in 2017 are:
(in thousands)
|
|
2017
|
|
Decrease in Regulatory Assets:
|
|
|
|
|
Amortization of Unrecognized Prior Service Cost
|
|
$
|
—
|
|
Amortization of Unrecognized Actuarial Loss
|
|
|
932
|
|
Decrease in Accumulated Other Comprehensive Loss:
|
|
|
|
|
Amortization of Unrecognized Prior Service Cost
|
|
|
—
|
|
Amortization of Unrecognized Actuarial Loss
|
|
|
23
|
|
Total Estimated Amortization
|
|
$
|
955
|
|
Cash
flows
—
The Company expects to contribute $3.5 million
net of expected employee contributions for the payment of retiree medical benefits and Medicare Part D subsidy receipts in 2017.
The Company expects to receive a Medicare Part D subsidy from the Federal government of approximately $416,000 in 2017. The following
benefit payments, which reflect expected future service, as appropriate, net of expected Medicare Part D subsidy receipts and participant
premium payments, are expected to be paid:
|
|
Years
|
|
(in thousands)
|
|
2017
|
|
|
2018
|
|
|
2019
|
|
|
2020
|
|
|
2021
|
|
|
2022-2026
|
|
|
|
$
|
3,512
|
|
|
$
|
3,669
|
|
|
$
|
3,828
|
|
|
$
|
3,912
|
|
|
$
|
4,046
|
|
|
$
|
20,377
|
|
401K Plan
The Company sponsors a 401K plan for the benefit of all corporate
and subsidiary company employees. Contributions made to these plans by the Company and its subsidiary companies included in continuing
operations totaled $3,877,000 for 2016, $3,602,000 for 2015 and $3,171,000 for 2014.
Employee Stock Ownership Plan
The Company has a stock ownership plan for the benefit of all
its electric utility employees. Contributions made by the Company were $647,000 for 2016, $674,000 for 2015 and $696,000 for 2014.
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 December 31, 2016 and December 31, 2015
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%, for the respective entities, 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 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.
|
|
December 31, 2016
|
|
|
December 31, 2015
|
|
(in thousands)
|
|
Carrying
Amount
|
|
|
Fair Value
|
|
|
Carrying
Amount
|
|
|
Fair Value
|
|
Cash and Cash Equivalents
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Short-Term Debt
|
|
|
(42,883
|
)
|
|
|
(42,883
|
)
|
|
|
(80,672
|
)
|
|
|
(80,672
|
)
|
Long-Term Debt including Current Maturities
|
|
|
(538,542
|
)
|
|
|
(583,835
|
)
|
|
|
(496,268
|
)
|
|
|
(561,245
|
)
|
13. Property, Plant and Equipment
(in thousands)
|
|
December 31,
2016
|
|
|
December 31,
2015
|
|
Electric Plant in Service
|
|
|
|
|
|
|
|
|
Production
|
|
$
|
891,330
|
|
|
$
|
879,121
|
|
Transmission
|
|
|
410,679
|
|
|
|
391,941
|
|
Distribution
|
|
|
466,285
|
|
|
|
451,820
|
|
General
|
|
|
92,063
|
|
|
|
97,881
|
|
Electric Plant in Service
|
|
|
1,860,357
|
|
|
|
1,820,763
|
|
Construction Work in Progress
|
|
|
149,997
|
|
|
|
64,117
|
|
Total Gross Electric Plant
|
|
|
2,010,354
|
|
|
|
1,884,880
|
|
Less Accumulated Depreciation and Amortization
|
|
|
622,657
|
|
|
|
592,001
|
|
Net Electric Plant
|
|
$
|
1,387,697
|
|
|
$
|
1,292,879
|
|
Nonelectric Operations Plant
|
|
|
|
|
|
|
|
|
Equipment
|
|
$
|
155,809
|
|
|
$
|
155,715
|
|
Buildings and Leasehold Improvements
|
|
|
51,323
|
|
|
|
41,149
|
|
Land
|
|
|
4,694
|
|
|
|
4,479
|
|
Nonelectric Operations Plant
|
|
|
211,826
|
|
|
|
201,343
|
|
Construction Work in Progress
|
|
|
3,264
|
|
|
|
15,495
|
|
Total Gross Nonelectric Plant
|
|
|
215,090
|
|
|
|
216,838
|
|
Less Accumulated Depreciation and Amortization
|
|
|
125,562
|
|
|
|
121,903
|
|
Net Nonelectric Operations Plant
|
|
$
|
89,528
|
|
|
$
|
94,935
|
|
Net Plant
|
|
$
|
1,477,225
|
|
|
$
|
1,387,814
|
|
The estimated service lives for rate-regulated properties is
5 to 82 years. For nonelectric property the estimated useful lives are from 3 to 40 years.
|
|
Service Life Range
|
|
(years)
|
|
Low
|
|
|
High
|
|
Electric Fixed Assets:
|
|
|
|
|
|
|
|
|
Production Plant
|
|
|
9
|
|
|
|
82
|
|
Transmission Plant
|
|
|
42
|
|
|
|
70
|
|
Distribution Plant
|
|
|
5
|
|
|
|
68
|
|
General Plant
|
|
|
5
|
|
|
|
50
|
|
Nonelectric Fixed Assets:
|
|
|
|
|
|
|
|
|
Equipment
|
|
|
3
|
|
|
|
12
|
|
Buildings and Leasehold Improvements
|
|
|
7
|
|
|
|
40
|
|
14. Income Taxes
The total income tax expense differs from the amount computed
by applying the federal income tax rate (35% in 2016, 2015 and 2014) to net income before total income tax expense for the following
reasons:
(in thousands)
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Tax Computed at Federal Statutory Rate – Continuing Operations
|
|
$
|
28,741
|
|
|
$
|
28,081
|
|
|
$
|
25,704
|
|
Increases (Decreases) in Tax from:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal PTCs
|
|
|
(7,175
|
)
|
|
|
(6,962
|
)
|
|
|
(7,517
|
)
|
State Income Taxes Net of Federal Income Tax Expense
|
|
|
2,848
|
|
|
|
4,945
|
|
|
|
1,993
|
|
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes
|
|
|
(850
|
)
|
|
|
(850
|
)
|
|
|
(849
|
)
|
Corporate-owned Life Insurance
|
|
|
(680
|
)
|
|
|
(167
|
)
|
|
|
(354
|
)
|
Dividend Received/Paid Deduction
|
|
|
(537
|
)
|
|
|
(560
|
)
|
|
|
(622
|
)
|
Section 199 Domestic Production Activities Deduction
|
|
|
(482
|
)
|
|
|
—
|
|
|
|
(1,026
|
)
|
Investment Tax Credit Amortization
|
|
|
(350
|
)
|
|
|
(571
|
)
|
|
|
(597
|
)
|
Allowance for Funds Used During Construction – Equity
|
|
|
(280
|
)
|
|
|
(426
|
)
|
|
|
(505
|
)
|
Differences Reversing in Excess of Federal Rates
|
|
|
77
|
|
|
|
(1,143
|
)
|
|
|
(106
|
)
|
Permanent and Other Differences
|
|
|
(1,231
|
)
|
|
|
(705
|
)
|
|
|
436
|
|
Total Income Tax Expense – Continuing Operations
|
|
$
|
20,081
|
|
|
$
|
21,642
|
|
|
$
|
16,557
|
|
Income Tax Expense – Discontinued Operations – U.S.
|
|
|
138
|
|
|
|
2,991
|
|
|
|
3,952
|
|
Income Tax Expense – Continuing and Discontinued Operations
|
|
$
|
20,219
|
|
|
$
|
24,633
|
|
|
$
|
20,509
|
|
Overall Effective Federal, State and Foreign Income Tax Rate
|
|
|
24.5
|
%
|
|
|
29.3
|
%
|
|
|
26.2
|
%
|
Income Tax Expense From Continuing Operations Includes the Following:
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Federal Income Taxes
|
|
$
|
1,070
|
|
|
$
|
211
|
|
|
$
|
124
|
|
Current State Income Taxes
|
|
|
1,211
|
|
|
|
1
|
|
|
|
5
|
|
Deferred Federal Income Taxes
|
|
|
23,586
|
|
|
|
23,050
|
|
|
|
21,044
|
|
Deferred State Income Taxes
|
|
|
2,589
|
|
|
|
6,763
|
|
|
|
4,347
|
|
Federal PTCs
|
|
|
(7,175
|
)
|
|
|
(6,962
|
)
|
|
|
(7,517
|
)
|
North Dakota Wind Tax Credit Amortization – Net of Federal Taxes
|
|
|
(850
|
)
|
|
|
(850
|
)
|
|
|
(849
|
)
|
Investment Tax Credit Amortization
|
|
|
(350
|
)
|
|
|
(571
|
)
|
|
|
(597
|
)
|
Total
|
|
$
|
20,081
|
|
|
$
|
21,642
|
|
|
$
|
16,557
|
|
Total Income Before Income Taxes – Continuing and Discontinued Operations
|
|
$
|
82,540
|
|
|
$
|
83,978
|
|
|
$
|
78,232
|
|
The Company's deferred tax assets and liabilities were composed
of the following on December 31:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Deferred Tax Assets
|
|
|
|
|
|
|
|
|
Benefit Liabilities
|
|
$
|
44,381
|
|
|
$
|
41,788
|
|
Federal PTCs
|
|
|
43,433
|
|
|
|
39,505
|
|
Retirement Benefits Liabilities
|
|
|
38,390
|
|
|
|
41,958
|
|
North Dakota Wind Tax Credits
|
|
|
32,962
|
|
|
|
32,962
|
|
Cost of Removal
|
|
|
31,636
|
|
|
|
29,463
|
|
Differences Related to Property
|
|
|
9,876
|
|
|
|
10,177
|
|
Net Operating Loss Carryforward
|
|
|
3,865
|
|
|
|
22,824
|
|
Vacation Accrual
|
|
|
2,725
|
|
|
|
2,500
|
|
Investment Tax Credits
|
|
|
818
|
|
|
|
1,109
|
|
Other
|
|
|
7,793
|
|
|
|
7,617
|
|
Total Deferred Tax Assets
|
|
$
|
215,879
|
|
|
$
|
229,903
|
|
Deferred Tax Liabilities
|
|
|
|
|
|
|
|
|
Differences Related to Property
|
|
$
|
(371,761
|
)
|
|
$
|
(366,234
|
)
|
Retirement Benefits Regulatory Asset
|
|
|
(38,390
|
)
|
|
|
(41,958
|
)
|
Excess Tax over Book Pension
|
|
|
(15,509
|
)
|
|
|
(13,775
|
)
|
North Dakota Wind Tax Credits
|
|
|
(3,654
|
)
|
|
|
(3,179
|
)
|
Impact of State Net Operating Losses on Federal Taxes
|
|
|
(1,352
|
)
|
|
|
(1,596
|
)
|
Other
|
|
|
(11,804
|
)
|
|
|
(10,830
|
)
|
Total Deferred Tax Liabilities
|
|
$
|
(442,470
|
)
|
|
$
|
(437,572
|
)
|
Deferred Income Taxes
|
|
$
|
(226,591
|
)
|
|
$
|
(207,669
|
)
|
Federal PTCs are earned as wind energy is generated based on
a per kwh rate prescribed in applicable federal statutes. OTP’s kwh generation from its wind turbines eligible for PTCs increased
3.6% in 2016 compared with 2015. North Dakota wind energy credits are based on dollars invested in qualifying facilities and are
being recognized on a straight-line basis over 25 years.
Schedule of expiration of tax credits and tax net operating
losses available as of December 31, 2016:
(in thousands)
|
|
Amount
|
|
|
2017
|
|
|
2027-36
|
|
United States
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal Net Operating Losses
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Federal Tax Credits
|
|
|
46,435
|
|
|
|
—
|
|
|
|
46,435
|
|
State Net Operating Losses
|
|
|
3,865
|
|
|
|
—
|
|
|
|
3,865
|
|
State Tax Credits
|
|
|
33,993
|
|
|
|
389
|
|
|
|
33,604
|
|
The carryforward period on a portion of the North Dakota wind
tax credits from the Langdon wind project is five years. OTP has adjusted its deferred tax assets and deferred tax credits by $0.4
million for potential unused North Dakota wind tax credits related to the Langdon wind project.
The following table summarizes the activity related to our unrecognized
tax benefits:
(in thousands)
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Balance on January 1
|
|
$
|
468
|
|
|
$
|
222
|
|
|
$
|
4,239
|
|
Increases Related to Tax Positions for Prior Years
|
|
|
406
|
|
|
|
236
|
|
|
|
120
|
|
Decreases Related to Tax Positions for Prior Years
|
|
|
—
|
|
|
|
—
|
|
|
|
(4,142
|
)
|
Increases Related to Tax Positions for Current Year
|
|
|
114
|
|
|
|
10
|
|
|
|
5
|
|
Uncertain Positions Resolved During Year
|
|
|
(97
|
)
|
|
|
—
|
|
|
|
—
|
|
Balance on December 31
|
|
$
|
891
|
|
|
$
|
468
|
|
|
$
|
222
|
|
The balance of unrecognized tax benefits as of December 31,
2016 would reduce the Company’s effective tax rate if recognized. The total amount of unrecognized tax benefits as of December
31, 2016 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 our consolidated statement of income. There was no amount
accrued for interest on tax uncertainties as of December 31, 2016.
The Company and its subsidiaries file a consolidated U.S. federal
income tax return and various state income tax returns. As of December 31, 2016, 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.
15. Asset Retirement Obligations (AROs)
The Company’s AROs are related to OTP’s coal-fired
generation plants and its 92 wind turbines located in North Dakota. The AROs include items such as site restoration, closure of
ash pits, and removal of certain structures, generators, asbestos and storage tanks. The Company has legal obligations associated
with the retirement of a variety of other long-lived tangible assets used in electric operations where the estimated settlement
costs are individually and collectively immaterial. The Company has no assets legally restricted for the settlement of any of its
AROs.
On December 19, 2014 the EPA’s rule regulating coal combustion
residuals (CCR) went into effect. The final rule regulates CCR as a non-hazardous solid waste under Subtitle D of the Resource
Conservation and Recovery Act. In the second quarter of 2015, subsequent to publication of the CCR rule, OTP completed an assessment
of its ash handling and storage facilities at Hoot Lake Plant, Coyote Station and Big Stone Plant and determined that it had no
immediate obligation under the rules to close or modify any existing ash handling facilities or storage sites but has discontinued
the use of one pit at Coyote Station to avoid the potential for future obligations related to this site under the CCR rule. Additionally,
OTP identified a slag sluice pond and slag stockpile area at Big Stone Plant that will need to be reclaimed at a future date to
comply with the CCR rule. OTP established an ARO liability of approximately $0.5 million for its share of the estimated future
costs to reclaim this site. Although identified as a new ARO resulting from the issuance of the CCR rule, the slag sluice pond
and slag stockpile are currently in use, so the cost of the new ARO was capitalized. Therefore, the establishment of the ARO will
have no impact on current year consolidated operating expenses but will result in an offsetting charge to the removal cost component
of the accumulated provision for depreciation on the Company’s consolidated balance sheet. Future reclamation costs, when
incurred, will be charged against, and reduce, the accumulated ARO liability.
OTP recorded no new AROs in 2016.
Reconciliations of carrying amounts of the present value of
the Company’s legal AROs, capitalized asset retirement costs and related accumulated depreciation and a summary of settlement
activity for the years ended December 31, 2016 and 2015 are presented in the following table:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Asset Retirement Obligations
|
|
|
|
|
|
|
|
|
Beginning Balance
|
|
$
|
8,084
|
|
|
$
|
7,721
|
|
New Obligations Recognized
|
|
|
—
|
|
|
|
451
|
|
Adjustments Due to Revisions in Cash Flow Estimates
|
|
|
(103
|
)
|
|
|
(424
|
)
|
Accrued Accretion
|
|
|
360
|
|
|
|
336
|
|
Settlements
|
|
|
—
|
|
|
|
—
|
|
Ending Balance
|
|
$
|
8,341
|
|
|
$
|
8,084
|
|
Asset Retirement Costs Capitalized
|
|
|
|
|
|
|
|
|
Beginning Balance
|
|
$
|
3,086
|
|
|
$
|
3,059
|
|
New Obligations Recognized
|
|
|
—
|
|
|
|
451
|
|
Adjustments Due to Revisions in Cash Flow Estimates
|
|
|
(103
|
)
|
|
|
(424
|
)
|
Settlements
|
|
|
—
|
|
|
|
—
|
|
Ending Balance
|
|
$
|
2,983
|
|
|
$
|
3,086
|
|
Accumulated Depreciation – Asset Retirement Costs Capitalized
|
|
|
|
|
|
|
|
|
Beginning Balance
|
|
$
|
673
|
|
|
$
|
527
|
|
New Obligations Recognized
|
|
|
—
|
|
|
|
—
|
|
Adjustments Due to Revisions in Cash Flow Estimates
|
|
|
—
|
|
|
|
—
|
|
Depreciation Expense
|
|
|
122
|
|
|
|
146
|
|
Settlements
|
|
|
—
|
|
|
|
—
|
|
Ending Balance
|
|
$
|
795
|
|
|
$
|
673
|
|
Settlements
|
|
|
None
|
|
|
|
None
|
|
Original Capitalized Asset Retirement Cost – Retired
|
|
$
|
—
|
|
|
$
|
—
|
|
Accumulated Depreciation
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
Asset Retirement Obligation
|
|
$
|
—
|
|
|
$
|
—
|
|
Settlement Cost
|
|
|
—
|
|
|
|
—
|
|
Gain on Settlement – Deferred Under Regulatory Accounting
|
|
$
|
—
|
|
|
$
|
—
|
|
16. Discontinued Operations
On April 30, 2015 the Company sold Foley for $12.0 million in
cash, plus $6.3 million in adjustments for working capital and other related items received in October 2015, less $1.0 million
in selling expenses. On February 28, 2015 the Company sold the assets of AEV, Inc. for $22.3 million in cash, plus $0.6 million
in adjustments for working capital and fixed assets received in October 2015, less $0.8 million in selling expenses. Foley and
AEV, Inc. were formerly included in the Company’s Construction segment.
On February 8, 2013 the Company completed the sale of substantially
all the assets of its dock and boatlift company, formerly included in our Manufacturing segment. On November 30, 2012 the Company
completed the sale of the assets of our wind tower manufacturing business. This business was the only remaining entity in the Company’s
former Wind Energy segment.
The Company’s Wind Energy and Construction segments were
eliminated as a result of the sales of its wind tower manufacturing business, Foley and AEV, Inc. The financial position, results
of operations and cash flows of Foley, AEV, Inc., the Company’s wind tower manufacturing business and its dock and boatlift
company are reported as discontinued operations in the Company’s consolidated financial statements.
Following are summary presentations of the results of discontinued
operations for the years ended December 31, 2016, 2015 and 2014:
|
|
For the Year Ended December 31, 2016
|
|
(in thousands)
|
|
Foley
|
|
|
AEV, Inc.
|
|
|
Wind
Tower
Business
|
|
|
Dock and
Boatlift
Business
|
|
|
Intercompany
Transactions
Adjustment
|
|
|
Total
|
|
Operating Expenses
|
|
$
|
250
|
|
|
$
|
—
|
|
|
$
|
(757
|
)
|
|
$
|
85
|
|
|
$
|
—
|
|
|
$
|
(422
|
)
|
Income Tax (Benefit) Expense
|
|
|
(136
|
)
|
|
|
5
|
|
|
|
303
|
|
|
|
(34
|
)
|
|
|
—
|
|
|
|
138
|
|
Net (Loss) Income
|
|
$
|
(114
|
)
|
|
$
|
(5
|
)
|
|
$
|
454
|
|
|
$
|
(51
|
)
|
|
$
|
—
|
|
|
$
|
284
|
|
|
|
For the Year Ended December 31, 2015
|
|
(in thousands)
|
|
Foley
|
|
|
AEV, Inc.
|
|
|
Wind
Tower
Business
|
|
|
Dock and
Boatlift
Business
|
|
|
Intercompany
Transactions
Adjustment
|
|
|
Total
|
|
Operating Revenues
|
|
$
|
21,625
|
|
|
$
|
2,998
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
24,623
|
|
Operating Expenses
|
|
|
26,839
|
|
|
|
4,532
|
|
|
|
(462
|
)
|
|
|
966
|
|
|
|
(240
|
)
|
|
|
31,635
|
|
Asset Impairment Charge
|
|
|
1,000
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,000
|
|
Interest Expense
|
|
|
177
|
|
|
|
27
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(204
|
)
|
|
|
—
|
|
Other Income (Deductions)
|
|
|
(42
|
)
|
|
|
2
|
|
|
|
111
|
|
|
|
—
|
|
|
|
(2
|
)
|
|
|
69
|
|
Income Tax (Benefit) Expense
|
|
|
(921
|
)
|
|
|
(638
|
)
|
|
|
229
|
|
|
|
(386
|
)
|
|
|
177
|
|
|
|
(1,539
|
)
|
Net (Loss) Income from Operations
|
|
|
(5,512
|
)
|
|
|
(921
|
)
|
|
|
344
|
|
|
|
(580
|
)
|
|
|
265
|
|
|
|
(6,404
|
)
|
(Loss) Gain on Disposition Before Taxes
|
|
|
(204
|
)
|
|
|
11,894
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
11,690
|
|
Income Tax (Benefit) Expense on Disposition
|
|
|
(227
|
)
|
|
|
4,757
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
4,530
|
|
Net Gain on Disposition
|
|
|
23
|
|
|
|
7,137
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
7,160
|
|
Net (Loss) Income
|
|
$
|
(5,489
|
)
|
|
$
|
6,216
|
|
|
$
|
344
|
|
|
$
|
(580
|
)
|
|
$
|
265
|
|
|
$
|
756
|
|
|
|
For the Year Ended December 31, 2014
|
|
(in thousands)
|
|
Foley
|
|
|
AEV, Inc.
|
|
|
Wind
Tower
Business
|
|
|
Dock and
Boatlift
Business
|
|
|
Intercompany
Transactions
Adjustment
|
|
|
Total
|
|
Operating Revenues
|
|
$
|
105,333
|
|
|
$
|
44,527
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
149,860
|
|
Operating Expenses
|
|
|
100,826
|
|
|
|
40,297
|
|
|
|
19
|
|
|
|
(180
|
)
|
|
|
(960
|
)
|
|
|
140,002
|
|
Asset Impairment Charge
|
|
|
5,605
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
5,605
|
|
Interest Expense
|
|
|
510
|
|
|
|
184
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(694
|
)
|
|
|
—
|
|
Other (Deductions) Income
|
|
|
(38
|
)
|
|
|
304
|
|
|
|
—
|
|
|
|
277
|
|
|
|
(4
|
)
|
|
|
539
|
|
Income Tax Expense (Benefit)
|
|
|
1,388
|
|
|
|
1,729
|
|
|
|
(8
|
)
|
|
|
183
|
|
|
|
660
|
|
|
|
3,952
|
|
Net (Loss) Income
|
|
$
|
(3,034
|
)
|
|
$
|
2,621
|
|
|
$
|
(11
|
)
|
|
$
|
274
|
|
|
$
|
990
|
|
|
$
|
840
|
|
Foley and AEV, Inc. entered into fixed-price construction contracts.
Revenues under these contracts were recognized on a percentage-of-completion basis. The method used to determine the progress of
completion was based on the ratio of costs incurred to total estimated costs on construction projects. An increase in estimated
costs on one large job in progress at Foley in excess of previous period cost estimates resulted in pretax charges of $4.4 million
in 2015.
In the fourth quarter of 2014 the Company entered into negotiations
to sell Foley and, as a result of an impairment indicator, the Company recorded a $5.6 million goodwill impairment charge. This
impairment charge was based on the indicated offering price in a signed letter of intent for the purchase of Foley. In the first
quarter of 2015, Foley recorded an additional $1.0 million goodwill impairment charge based on adjustments to the carrying value
of Foley. The fourth quarter 2014 and first quarter 2015 goodwill impairment losses are reflected in the results of discontinued
operations.
Following are summary presentations of the major components
of assets and liabilities of discontinued operations as of December 31, 2016 and December 31, 2015:
|
|
December 31, 2016
|
|
(in thousands)
|
|
Foley
|
|
|
AEV, Inc.
|
|
|
Wind
Tower
Business
|
|
|
Dock and
Boatlift
Business
|
|
|
Total
|
|
Current Liabilities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
589
|
|
|
$
|
774
|
|
|
$
|
1,363
|
|
Liabilities of Discontinued Operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
589
|
|
|
$
|
774
|
|
|
$
|
1,363
|
|
|
|
December 31, 2015
|
|
(in thousands)
|
|
Foley
|
|
|
AEV, Inc.
|
|
|
Wind
Tower
Business
|
|
|
Dock and
Boatlift
Business
|
|
|
Total
|
|
Current Liabilities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,299
|
|
|
$
|
799
|
|
|
$
|
2,098
|
|
Liabilities of Discontinued Operations
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,299
|
|
|
$
|
799
|
|
|
$
|
2,098
|
|
Included in current liabilities of discontinued operations are
warranty reserves. Details regarding the warranty reserves follow:
(in thousands)
|
|
2016
|
|
|
2015
|
|
Warranty Reserve Balance, January 1
|
|
$
|
2,103
|
|
|
$
|
2,527
|
|
Additional Provision for Warranties Made During the Year
|
|
|
—
|
|
|
|
—
|
|
Settlements Made During the Year
|
|
|
(24
|
)
|
|
|
(124
|
)
|
Decrease in Warranty Estimates for Prior Years
|
|
|
(710
|
)
|
|
|
(300
|
)
|
Warranty Reserve Balance, December 31
|
|
$
|
1,369
|
|
|
$
|
2,103
|
|
The warranty reserve balances as of December 31, 2016 relate
entirely 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.
17. Subsequent Events
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 EEI 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 these shares until the 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.
Supplementary Financial Information
Quarterly Information (not audited
)
Because of changes in the number of common
shares outstanding and the impact of diluted shares, the sum of the quarterly earnings (loss) per common share may not equal total
earnings (loss) per common share.
Three Months Ended
|
|
March 31
|
|
|
June 30
|
|
|
September 30
|
|
|
December 31
|
|
(in thousands, except per share data)
|
|
2016
|
|
|
2015
1
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
|
2016
|
|
|
2015
|
|
Operating Revenues–Continuing Operations
|
|
$
|
206,242
|
|
|
$
|
202,841
|
|
|
$
|
203,482
|
|
|
$
|
188,153
|
|
|
$
|
197,175
|
|
|
$
|
200,023
|
|
|
$
|
196,640
|
|
|
$
|
188,787
|
|
Operating Income–Continuing Operations
|
|
$
|
27,576
|
|
|
$
|
25,025
|
|
|
$
|
27,083
|
|
|
$
|
24,800
|
|
|
$
|
27,284
|
|
|
$
|
29,626
|
|
|
$
|
29,156
|
|
|
$
|
29,763
|
|
Net Income (Loss):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations
|
|
$
|
14,490
|
|
|
$
|
13,781
|
|
|
$
|
15,556
|
|
|
$
|
13,657
|
|
|
$
|
14,594
|
|
|
$
|
15,709
|
|
|
$
|
17,397
|
|
|
$
|
15,442
|
|
Discontinued Operations
|
|
$
|
30
|
|
|
$
|
4,154
|
|
|
$
|
119
|
|
|
$
|
(2,221
|
)
|
|
$
|
22
|
|
|
$
|
(317
|
)
|
|
$
|
113
|
|
|
$
|
(860
|
)
|
Total Net Income
|
|
$
|
14,520
|
|
|
$
|
17,935
|
|
|
$
|
15,675
|
|
|
$
|
11,436
|
|
|
$
|
14,616
|
|
|
$
|
15,392
|
|
|
$
|
17,510
|
|
|
$
|
14,582
|
|
Basic Earnings (Loss) Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations
|
|
$
|
.38
|
|
|
$
|
.37
|
|
|
$
|
.41
|
|
|
$
|
.37
|
|
|
$
|
.38
|
|
|
$
|
.42
|
|
|
$
|
.45
|
|
|
$
|
.41
|
|
Discontinued Operations
|
|
$
|
—
|
|
|
$
|
.11
|
|
|
$
|
—
|
|
|
$
|
(.06
|
)
|
|
$
|
—
|
|
|
$
|
(.01
|
)
|
|
$
|
—
|
|
|
$
|
(.02
|
)
|
Total Basic Earnings Per Share
|
|
$
|
.38
|
|
|
$
|
.48
|
|
|
$
|
.41
|
|
|
$
|
.31
|
|
|
$
|
.38
|
|
|
$
|
.41
|
|
|
$
|
.45
|
|
|
$
|
.39
|
|
Diluted Earnings (Loss) Per Share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Continuing Operations
|
|
$
|
.38
|
|
|
$
|
.37
|
|
|
$
|
.41
|
|
|
$
|
.36
|
|
|
$
|
.37
|
|
|
$
|
.42
|
|
|
$
|
.44
|
|
|
$
|
.41
|
|
Discontinued Operations
|
|
$
|
—
|
|
|
$
|
.11
|
|
|
$
|
—
|
|
|
$
|
(.06
|
)
|
|
$
|
—
|
|
|
$
|
(.01
|
)
|
|
$
|
—
|
|
|
$
|
(.02
|
)
|
Total Diluted Earnings Per Share
|
|
$
|
.38
|
|
|
$
|
.48
|
|
|
$
|
.41
|
|
|
$
|
.30
|
|
|
$
|
.37
|
|
|
$
|
.41
|
|
|
$
|
.44
|
|
|
$
|
.39
|
|
Dividends Declared Per Common Share
|
|
$
|
.3125
|
|
|
$
|
.3075
|
|
|
$
|
.3125
|
|
|
$
|
.3075
|
|
|
$
|
.3125
|
|
|
$
|
.3075
|
|
|
$
|
.3125
|
|
|
$
|
.3075
|
|
Price Range:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High
|
|
|
29.73
|
|
|
|
33.44
|
|
|
|
33.50
|
|
|
|
32.76
|
|
|
|
36.42
|
|
|
|
28.34
|
|
|
|
42.55
|
|
|
|
28.76
|
|
Low
|
|
|
25.80
|
|
|
|
30.60
|
|
|
|
27.77
|
|
|
|
26.14
|
|
|
|
32.89
|
|
|
|
24.82
|
|
|
|
33.08
|
|
|
|
25.20
|
|
Average Number of Common Shares Outstanding—Basic
|
|
|
37,937
|
|
|
|
37,243
|
|
|
|
38,179
|
|
|
|
37,433
|
|
|
|
38,833
|
|
|
|
37,575
|
|
|
|
39,236
|
|
|
|
37,728
|
|
Average Number of Common Shares Outstanding—Diluted
|
|
|
38,045
|
|
|
|
37,498
|
|
|
|
38,321
|
|
|
|
37,653
|
|
|
|
39,006
|
|
|
|
37,795
|
|
|
|
39,552
|
|
|
|
37,868
|
|
1
Results include
pre-tax goodwill impairment charges of $1.0 million at Foley in discontinued operations.