NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
June 30, 2017
NOTE 1—
GENERAL INFORMATION
WEC Energy Group serves approximately
1.6 million
electric customers and
2.8 million
natural gas customers, and owns approximately
60%
of ATC.
As used in these notes, the term "financial statements" refers to the condensed consolidated financial statements. This includes the income statements, statements of comprehensive income, balance sheets, and statements of cash flows, unless otherwise noted. In this report, when we refer to "the Company," "us," "we," "our," or "ours," we are referring to WEC Energy Group and all of its subsidiaries.
We have prepared the unaudited interim financial statements presented in this Form 10-Q pursuant to the rules and regulations of the SEC and GAAP. Accordingly, these financial statements do not include all of the information and footnotes required by GAAP for annual financial statements. These financial statements should be read in conjunction with the consolidated financial statements and footnotes in our Annual Report on Form 10-K for the year ended
December 31, 2016
. Financial results for an interim period may not give a true indication of results for the year. In particular, the results of operations for the
three and six months ended June 30
,
2017
, are not necessarily indicative of expected results for
2017
due to seasonal variations and other factors.
In management's opinion, we have included all adjustments, normal and recurring in nature, necessary for a fair presentation of our financial results.
NOTE 2—
ACQUISITION
Acquisition of Natural Gas Storage Facilities in Michigan
On June 30, 2017, we completed the acquisition of Bluewater for
$226.0 million
. Bluewater owns natural gas storage facilities in Michigan that will provide approximately one-third of the current storage needs for our Wisconsin natural gas utilities. In addition, we accrued
$4.9 million
of acquisition related costs.
The table below shows the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the date of the acquisition. The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. Bluewater is included in the non-utility energy segment.
See Note 14, Segment Information, for more information
.
|
|
|
|
|
|
|
|
|
(in millions)
|
|
|
|
Current assets
|
|
$
|
2.0
|
|
|
Net property, plant, and equipment
|
|
217.6
|
|
|
Goodwill
|
|
7.3
|
|
|
Current liabilities
|
|
(0.9
|
)
|
|
Total purchase price
|
|
$
|
226.0
|
|
NOTE 3—
DISPOSITIONS
Wisconsin Segment
Sale of Milwaukee County Power Plant
In April 2016, we sold the MCPP steam generation and distribution assets, located in Wauwatosa, Wisconsin. MCPP primarily provided steam to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of
$10.9 million
(
$6.5 million
after tax), which was included in other operation and maintenance on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations of this plant remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.
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|
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|
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|
06/30/2017 Form 10-Q
|
7
|
WEC Energy Group, Inc.
|
Corporate and Other Segment
Sale of Bostco Real Estate Holdings
In March 2017, we sold the remaining real estate holdings of Bostco located in downtown Milwaukee, Wisconsin, which included retail, office, and residential space. During the first quarter of 2017, we recorded an insignificant gain on the sale, which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.
Sale of Certain Assets of Wisvest
In April 2016, as part of the MCPP sale transaction, we sold the chilled water generation and distribution assets of Wisvest, which were used to provide chilled water services to the Milwaukee Regional Medical Center hospitals and other campus buildings. During the second quarter of 2016, we recorded a pre-tax gain on the sale of
$19.6 million
(
$11.8 million
after tax), which was included in other income, net on our income statements. The assets included in the sale were not material and, therefore, were not presented as held for sale. The results of operations associated with these assets remained in continuing operations through the sale date as the sale did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results.
Sale of Integrys Transportation Fuels
Through a series of transactions in the fourth quarter of 2015 and the first quarter of 2016, we sold ITF, a provider of CNG fueling services and a single-source provider of CNG fueling facility design, construction, operation, and maintenance. There was
no
gain or loss recorded on the sales, as ITF's assets and liabilities were adjusted to fair value through purchase accounting. The results of operations of ITF remained in continuing operations through the sale date as the sale of ITF did not represent a shift in our corporate strategy and did not have a major effect on our operations and financial results. The pre-tax profit or loss of this component was not material through the sale date in 2016.
NOTE 4—
COMMON EQUITY
Stock-Based Compensation
During the first quarter of 2017, the Compensation Committee of our Board of Directors awarded the following stock-based compensation awards to our directors, officers, and certain other key employees:
|
|
|
|
|
|
|
|
Award Type
|
|
Number of Awards
|
|
Stock options
(1)
|
|
552,215
|
|
|
Restricted shares
(2)
|
|
82,622
|
|
|
Performance units
|
|
237,650
|
|
|
|
|
|
(1)
|
Stock options awarded had a weighted-average exercise price of
$58.31
and a weighted-average grant date fair value of
$7.45
per option.
|
|
|
|
|
(2)
|
Restricted shares awarded had a weighted-average grant date fair value of
$58.10
per share.
|
|
|
|
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|
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06/30/2017 Form 10-Q
|
8
|
WEC Energy Group, Inc.
|
In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which modifies certain aspects of the accounting for stock-based compensation awards. This ASU became effective for us on January 1, 2017. Under the new guidance, all excess tax benefits and tax deficiencies are recognized as income tax expense or benefit in the income statement on a prospective basis. Prior to January 1, 2017, these amounts were recorded in additional paid in capital on the balance sheet, and the tax benefits could only be recognized to the extent they reduced taxes payable. In the first quarter of 2017, we recorded a
$15.7 million
cumulative-effect adjustment to retained earnings for excess tax benefits that had not been recognized in prior years as they did not reduce taxes payable. The following table shows the changes to our retained earnings for the
six months ended June 30, 2017
:
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Retained Earnings
|
|
Balance at December 31, 2016
|
|
$
|
4,613.9
|
|
|
Net income attributed to common shareholders
|
|
555.7
|
|
|
Common stock dividends
|
|
(328.3
|
)
|
|
Cumulative effect of adoption of ASU 2016-09
|
|
15.7
|
|
|
Balance at June 30, 2017
|
|
$
|
4,857.0
|
|
ASU 2016-09 also requires excess tax benefits to be classified as an operating activity on the statement of cash flows. As we have elected to apply this provision on a prospective basis, the prior year amounts will continue to be reflected as a financing activity. As allowed under this ASU, we have also elected to account for forfeitures as they occur, rather than estimating expected forfeitures and recording them over the vesting period.
Restrictions
Our ability as a holding company to pay common stock dividends primarily depends on the availability of funds received from our utility subsidiaries and our non-utility subsidiary, We Power. Various financing arrangements and regulatory requirements impose certain restrictions on the ability of our subsidiaries to transfer funds to us in the form of cash dividends, loans, or advances. All of our utility subsidiaries, with the exception of MGU, are prohibited from loaning funds to us, either directly or indirectly. See Note 11, Common Equity, in our
2016
Annual Report on Form 10-K for additional information on these and other restrictions.
We do not believe that these restrictions will materially affect our operations or limit any dividend payments in the foreseeable future.
Common Stock Dividends
On July 20, 2017, our Board of Directors declared a quarterly cash dividend of
$0.52
per share, payable on September 1, 2017, to stockholders of record on August 14, 2017.
NOTE 5—
SHORT-TERM DEBT AND LINES OF CREDIT
The following table shows our short-term borrowings and their corresponding weighted-average interest rates:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions, except percentages)
|
|
June 30, 2017
|
|
December 31, 2016
|
|
Commercial paper
|
|
|
|
|
|
Amount outstanding
|
|
$
|
774.8
|
|
|
$
|
860.2
|
|
|
Weighted-average interest rate on amounts outstanding
|
|
1.42
|
%
|
|
0.96
|
%
|
Our average amount of commercial paper borrowings based on daily outstanding balances during the
six months ended June 30, 2017
, was
$655.5 million
with a weighted-average interest rate during the period of
1.09%
.
|
|
|
|
|
|
|
06/30/2017 Form 10-Q
|
9
|
WEC Energy Group, Inc.
|
The information in the table below relates to our revolving credit facilities used to support our commercial paper borrowing programs, including available capacity under these facilities:
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Maturity
|
|
June 30, 2017
|
|
WEC Energy Group
|
|
December 2020
|
|
$
|
1,050.0
|
|
|
WE
|
|
December 2020
|
|
500.0
|
|
|
WPS
|
|
December 2020
|
|
250.0
|
|
|
WG
|
|
December 2020
|
|
350.0
|
|
|
PGL
|
|
December 2020
|
|
350.0
|
|
|
Total short-term credit capacity
|
|
|
|
$
|
2,500.0
|
|
|
Less:
|
|
|
|
|
|
|
Letters of credit issued inside credit facilities
|
|
|
|
$
|
41.3
|
|
|
Commercial paper outstanding
|
|
|
|
774.8
|
|
|
Available capacity under existing agreements
|
|
|
|
$
|
1,683.9
|
|
NOTE 6—
LONG-TERM DEBT
Effective May 2017, the
$500.0 million
of 2007 Junior Notes bear interest at the three-month LIBOR plus 211.25 basis points, and reset quarterly.
In June 2017, MERC issued
$120.0 million
of senior notes. The senior notes were issued in three tranches:
$40.0 million
of
3.11%
Senior Notes due July 15, 2027;
$40.0 million
of
3.41%
Senior Notes due July 15, 2032; and
$40.0 million
of
4.01%
Senior Notes due July 15, 2047. Net proceeds were used to repay MERC's
$78.0 million
aggregate long-term debt obligation to its parent, Integrys. Remaining proceeds were used for general corporate purposes, including repayment of short-term debt borrowed from Integrys.
In June 2017, MGU issued
$90.0 million
of senior notes. The senior notes were issued in three tranches:
$30.0 million
of
3.11%
Senior Notes due July 15, 2027;
$30.0 million
of
3.41%
Senior Notes due July 15, 2032; and
$30.0 million
of
4.01%
Senior Notes due July 15, 2047. Net proceeds were used to repay MGU's
$71.0 million
aggregate long-term debt obligation to its parent, Integrys. Remaining proceeds were used for general corporate purposes, including repayment of short-term debt borrowed from Integrys.
NOTE 7—
MATERIALS, SUPPLIES, AND INVENTORIES
Our inventory consisted of:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
June 30, 2017
|
|
December 31, 2016
|
|
Natural gas in storage
|
|
$
|
137.8
|
|
|
$
|
223.1
|
|
|
Materials and supplies
|
|
216.3
|
|
|
206.5
|
|
|
Fossil fuel
|
|
155.9
|
|
|
158.0
|
|
|
Total
|
|
$
|
510.0
|
|
|
$
|
587.6
|
|
PGL and NSG price natural gas storage injections at the calendar year average of the cost of natural gas supply purchased. Withdrawals from storage are priced using the LIFO cost method. For interim periods, the difference between current projected replacement cost and the LIFO cost for quantities of natural gas temporarily withdrawn from storage is recorded as a temporary LIFO liquidation debit or credit. The temporary LIFO liquidation amounts were not significant at June 30, 2017.
Substantially all other natural gas in storage, materials and supplies, and fossil fuel inventories are recorded using the weighted-average cost method of accounting.
NOTE 8—
FAIR VALUE MEASUREMENTS
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).
Fair value accounting rules provide a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are defined as follows:
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|
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06/30/2017 Form 10-Q
|
10
|
WEC Energy Group, Inc.
|
Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are observable, either directly or indirectly, but are not quoted prices included within Level 1. Level 2 includes those financial instruments that are valued using external inputs within models or other valuation methods.
Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methods that result in management's best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to customers' needs.
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. We use a mid-market pricing convention (the mid-point price between bid and ask prices) as a practical measure for valuing certain derivative assets and liabilities. We primarily use a market approach for recurring fair value measurements and attempt to use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.
When possible, we base the valuations of our financial assets and liabilities on quoted prices for identical assets and liabilities in active markets. These valuations are classified in Level 1. The valuations of certain contracts not classified as Level 1 may be based on quoted market prices received from counterparties and/or observable inputs for similar instruments. Transactions valued using these inputs are classified in Level 2. Certain derivatives are categorized in Level 3 due to the significance of unobservable or internally-developed inputs.
We recognize transfers between levels of the fair value hierarchy at their value as of the end of the reporting period.
The following tables summarize our financial assets and liabilities that were accounted for at fair value on a recurring basis, categorized by level within the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
(in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
1.2
|
|
|
$
|
3.5
|
|
|
$
|
—
|
|
|
$
|
4.7
|
|
|
Petroleum products contracts
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
FTRs
|
|
—
|
|
|
—
|
|
|
11.8
|
|
|
11.8
|
|
|
Coal contracts
|
|
—
|
|
|
0.7
|
|
|
—
|
|
|
0.7
|
|
|
Total derivative assets
|
|
$
|
1.5
|
|
|
$
|
4.2
|
|
|
$
|
11.8
|
|
|
$
|
17.5
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments held in rabbi trust
|
|
$
|
108.6
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
108.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
2.0
|
|
|
$
|
2.5
|
|
|
$
|
—
|
|
|
$
|
4.5
|
|
|
Petroleum products contracts
|
|
0.1
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
Coal contracts
|
|
—
|
|
|
3.4
|
|
|
—
|
|
|
3.4
|
|
|
Total derivative liabilities
|
|
$
|
2.1
|
|
|
$
|
5.9
|
|
|
$
|
—
|
|
|
$
|
8.0
|
|
|
|
|
|
|
|
|
06/30/2017 Form 10-Q
|
11
|
WEC Energy Group, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2016
|
|
(in millions)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
10.1
|
|
|
$
|
24.2
|
|
|
$
|
—
|
|
|
$
|
34.3
|
|
|
Petroleum products contracts
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|
FTRs
|
|
—
|
|
|
—
|
|
|
5.1
|
|
|
5.1
|
|
|
Coal contracts
|
|
—
|
|
|
2.0
|
|
|
—
|
|
|
2.0
|
|
|
Total derivative assets
|
|
$
|
10.3
|
|
|
$
|
26.2
|
|
|
$
|
5.1
|
|
|
$
|
41.6
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments held in rabbi trust
|
|
$
|
103.9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
103.9
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
0.2
|
|
|
$
|
0.2
|
|
|
$
|
—
|
|
|
$
|
0.4
|
|
|
Petroleum products contracts
|
|
0.1
|
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
Coal contracts
|
|
—
|
|
|
1.9
|
|
|
—
|
|
|
1.9
|
|
|
Total derivative liabilities
|
|
$
|
0.3
|
|
|
$
|
2.1
|
|
|
$
|
—
|
|
|
$
|
2.4
|
|
The derivative assets and liabilities listed in the tables above include options, swaps, futures, physical commodity contracts, and other instruments used to manage market risks related to changes in commodity prices. They also include FTRs, which are used to manage electric transmission congestion costs in the MISO Energy Markets.
The following table summarizes the changes to derivatives classified as Level 3 in the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
Six Months Ended June 30
|
|
(in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
Balance at the beginning of the period
|
|
$
|
1.7
|
|
|
$
|
1.1
|
|
|
$
|
5.1
|
|
|
$
|
3.6
|
|
|
Realized and unrealized losses
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(0.2
|
)
|
|
Purchases
|
|
13.8
|
|
|
15.2
|
|
|
13.8
|
|
|
15.2
|
|
|
Sales
|
|
—
|
|
|
(0.1
|
)
|
|
—
|
|
|
(0.2
|
)
|
|
Settlements
|
|
(3.7
|
)
|
|
(2.8
|
)
|
|
(7.1
|
)
|
|
(5.0
|
)
|
|
Balance at the end of the period
|
|
$
|
11.8
|
|
|
$
|
13.4
|
|
|
$
|
11.8
|
|
|
$
|
13.4
|
|
Unrealized gains and losses on Level 3 derivatives are deferred as regulatory assets or liabilities. Therefore, these fair value measurements have
no
impact on earnings. Realized gains and losses on these instruments flow through cost of sales on the income statements.
Fair Value of Financial Instruments
The following table shows the financial instruments included on our balance sheets that are not recorded at fair value:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
December 31, 2016
|
|
(in millions)
|
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
|
Preferred stock
|
|
$
|
30.4
|
|
|
$
|
30.5
|
|
|
$
|
30.4
|
|
|
$
|
28.8
|
|
|
Long-term debt, including current portion *
|
|
9,479.8
|
|
|
10,128.3
|
|
|
9,285.8
|
|
|
9,818.2
|
|
|
|
|
|
*
|
The carrying amount of long-term debt excludes capital lease obligations of
$28.3 million
and
$29.6 million
at
June 30, 2017
and
|
December 31, 2016
, respectively.
Due to the short-term nature of cash and cash equivalents, net accounts receivable and unbilled revenues, accounts payable, and short-term debt, the carrying amount of each such item approximates fair value. The fair value of our preferred stock is estimated based on the quoted market value for the same issue, or by using a dividend discount model. The fair value of our long-term debt is estimated based upon the quoted market value for the same issue, similar issues, or upon the quoted market prices of United States Treasury issues having a similar term to maturity, adjusted for the issuing company's bond rating and the present value of future cash flows. The fair values of our long-term debt and preferred stock are categorized within Level 2 of the fair value hierarchy.
|
|
|
|
|
|
|
06/30/2017 Form 10-Q
|
12
|
WEC Energy Group, Inc.
|
NOTE 9—
DERIVATIVE INSTRUMENTS
We use derivatives as part of our risk management program to manage the risks associated with the price volatility of purchased power, generation, and natural gas costs for the benefit of our customers and shareholders. Our approach is non-speculative and designed to mitigate risk. Regulated hedging programs are approved by our state regulators.
We record derivative instruments on our balance sheets as an asset or liability measured at fair value unless they qualify for the normal purchases and sales exception, and are so designated. We continually assess our contracts designated as normal and will discontinue the treatment of these contracts as normal if the required criteria are no longer met. Changes in the derivative's fair value are recognized currently in earnings unless specific hedge accounting criteria are met or we receive regulatory treatment for the derivative. For most energy-related physical and financial contracts in our regulated operations that qualify as derivatives, our regulators allow the effects of fair value accounting to be offset to regulatory assets and liabilities.
The following table shows our derivative assets and derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
December 31, 2016
|
|
(in millions)
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
Other current
|
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
4.3
|
|
|
$
|
4.1
|
|
|
$
|
31.4
|
|
|
$
|
0.4
|
|
|
Petroleum products contracts
|
|
0.3
|
|
|
0.1
|
|
|
0.2
|
|
|
0.1
|
|
|
FTRs
|
|
11.8
|
|
|
—
|
|
|
5.1
|
|
|
—
|
|
|
Coal contracts
|
|
0.7
|
|
|
2.3
|
|
|
1.5
|
|
|
1.4
|
|
|
Total other current *
|
|
$
|
17.1
|
|
|
$
|
6.5
|
|
|
$
|
38.2
|
|
|
$
|
1.9
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term
|
|
|
|
|
|
|
|
|
|
Natural gas contracts
|
|
$
|
0.4
|
|
|
$
|
0.4
|
|
|
$
|
2.9
|
|
|
$
|
—
|
|
|
Coal contracts
|
|
—
|
|
|
1.1
|
|
|
0.5
|
|
|
0.5
|
|
|
Total other long-term *
|
|
$
|
0.4
|
|
|
$
|
1.5
|
|
|
$
|
3.4
|
|
|
$
|
0.5
|
|
|
Total
|
|
$
|
17.5
|
|
|
$
|
8.0
|
|
|
$
|
41.6
|
|
|
$
|
2.4
|
|
|
|
|
|
*
|
On our balance sheets, we classify derivative assets and liabilities as other current or other long-term based on the maturities of the underlying contracts.
|
Realized gains (losses) on derivative instruments are primarily recorded in cost of sales on the income statements. Our estimated notional sales volumes and realized gains (losses) were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2017
|
|
Three Months Ended June 30, 2016
|
|
(in millions)
|
|
Volumes
|
|
Gains (Losses)
|
|
Volumes
|
|
Gains (Losses)
|
|
Natural gas contracts
|
|
25.2 Dth
|
|
$
|
1.3
|
|
|
32.7 Dth
|
|
$
|
(20.0
|
)
|
|
Petroleum products contracts
|
|
4.9 gallons
|
|
(0.4
|
)
|
|
3.6 gallons
|
|
(1.0
|
)
|
|
FTRs
|
|
9.4 MWh
|
|
2.2
|
|
|
7.4 MWh
|
|
1.6
|
|
|
Total
|
|
|
|
$
|
3.1
|
|
|
|
|
$
|
(19.4
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2017
|
|
Six Months Ended June 30, 2016
|
|
(in millions)
|
|
Volumes
|
|
Gains (Losses)
|
|
Volumes
|
|
Gains (Losses)
|
|
Natural gas contracts
|
|
59.3 Dth
|
|
$
|
1.0
|
|
|
82.8 Dth
|
|
$
|
(53.5
|
)
|
|
Petroleum products contracts
|
|
9.8 gallons
|
|
(0.9
|
)
|
|
6.6 gallons
|
|
(2.1
|
)
|
|
FTRs
|
|
18.6 MWh
|
|
5.2
|
|
|
15.0 MWh
|
|
4.6
|
|
|
Total
|
|
|
|
$
|
5.3
|
|
|
|
|
$
|
(51.0
|
)
|
On our balance sheets, the amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral are not offset against the fair value amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. At
June 30, 2017
and
December 31, 2016
, we had posted cash collateral of
$25.6 million
and
$16.4 million
, respectively, in our margin accounts. These amounts were recorded on our balance sheets in other current assets. At December 31, 2016, we had also received cash collateral of
$4.4 million
in our margin accounts. This amount was recorded on our balance sheet in other current liabilities.
|
|
|
|
|
|
|
06/30/2017 Form 10-Q
|
13
|
WEC Energy Group, Inc.
|
The following table shows derivative assets and derivative liabilities if derivative instruments by counterparty were presented net on our balance sheets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
December 31, 2016
|
|
(in millions)
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
Gross amount recognized on the balance sheet
|
|
$
|
17.5
|
|
|
$
|
8.0
|
|
|
$
|
41.6
|
|
|
$
|
2.4
|
|
|
Gross amount not offset on the balance sheet
|
|
(3.0
|
)
|
|
(3.8
|
)
|
(1)
|
(4.9
|
)
|
(2)
|
(0.5
|
)
|
|
Net amount
|
|
$
|
14.5
|
|
|
$
|
4.2
|
|
|
$
|
36.7
|
|
|
$
|
1.9
|
|
|
|
|
|
(1)
|
Includes cash collateral posted of
$0.8 million
.
|
|
|
|
|
(2)
|
Includes cash collateral received of
$4.4 million
.
|
Certain of our derivative and nonderivative commodity instruments contain provisions that could require "adequate assurance" in the event of a material change in our creditworthiness, or the posting of additional collateral for instruments in net liability positions, if triggered by a decrease in credit ratings. The aggregate fair value of all derivative instruments with specific credit risk-related contingent features that were in a net liability position was
$2.4 million
and
$0.2 million
at
June 30, 2017
and
December 31, 2016
, respectively. At
June 30, 2017
and
December 31, 2016
, we had not posted any collateral related to the credit risk-related contingent features of these commodity instruments. If all of the credit risk-related contingent features contained in derivative instruments in a net liability position had been triggered at
June 30, 2017
, we would have been required to post collateral of
$0.7 million
. At
December 31, 2016
, we would not have been required to post any collateral.
NOTE 10—
GUARANTEES
The following table shows our outstanding guarantees:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Amounts Committed at
|
|
Expiration
|
|
(in millions)
|
|
June 30, 2017
|
|
Less Than 1 Year
|
|
1 to 3 Years
|
|
Over 3 Years
|
|
Guarantees
|
|
|
|
|
|
|
|
|
|
Guarantees supporting commodity transactions of subsidiaries
(1)
|
|
$
|
8.1
|
|
|
$
|
8.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Standby letters of credit
(2)
|
|
44.2
|
|
|
38.7
|
|
|
5.5
|
|
|
—
|
|
|
Surety bonds
(3)
|
|
9.5
|
|
|
7.8
|
|
|
1.7
|
|
|
—
|
|
|
Other guarantees
(4)
|
|
10.1
|
|
|
0.5
|
|
|
—
|
|
|
9.6
|
|
|
Total guarantees
|
|
$
|
71.9
|
|
|
$
|
55.1
|
|
|
$
|
7.2
|
|
|
$
|
9.6
|
|
|
|
|
|
(1)
|
Consists of
$8.1 million
to support the business operations of Bluewater.
|
|
|
|
|
(2)
|
At our request or the request of our subsidiaries, financial institutions have issued standby letters of credit for the benefit of third parties that have extended credit to our subsidiaries. These amounts are not reflected on our balance sheets.
|
|
|
|
|
(3)
|
Primarily for workers compensation self-insurance programs and obtaining various licenses, permits, and rights-of-way. These amounts are not reflected on our balance sheets.
|
|
|
|
|
(4)
|
Consists of
$10.1 million
related to other indemnifications, for which a liability of
$9.6 million
related to workers compensation coverage was recorded on our balance sheets.
|
|
|
|
|
|
|
|
06/30/2017 Form 10-Q
|
14
|
WEC Energy Group, Inc.
|
NOTE 11—
EMPLOYEE BENEFITS
The following tables show the components of net periodic pension and OPEB costs for our benefit plans.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension Costs
|
|
|
|
Three Months Ended June 30
|
|
Six Months Ended June 30
|
|
(in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
Service cost
|
|
$
|
10.4
|
|
|
$
|
10.7
|
|
|
$
|
22.1
|
|
|
$
|
22.0
|
|
|
Interest cost
|
|
30.2
|
|
|
33.0
|
|
|
61.4
|
|
|
66.2
|
|
|
Expected return on plan assets
|
|
(48.5
|
)
|
|
(49.0
|
)
|
|
(98.1
|
)
|
|
(98.0
|
)
|
|
Loss on plan settlement
|
|
5.3
|
|
|
14.1
|
|
|
5.3
|
|
|
14.1
|
|
|
Amortization of prior service cost
|
|
0.8
|
|
|
0.8
|
|
|
1.5
|
|
|
1.7
|
|
|
Amortization of net actuarial loss
|
|
21.1
|
|
|
20.2
|
|
|
43.0
|
|
|
40.7
|
|
|
Net periodic benefit cost
|
|
$
|
19.3
|
|
|
$
|
29.8
|
|
|
$
|
35.2
|
|
|
$
|
46.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPEB Costs
|
|
|
|
Three Months Ended June 30
|
|
Six Months Ended June 30
|
|
(in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
Service cost
|
|
$
|
5.6
|
|
|
$
|
6.4
|
|
|
$
|
11.9
|
|
|
$
|
13.1
|
|
|
Interest cost
|
|
8.4
|
|
|
9.3
|
|
|
16.9
|
|
|
18.5
|
|
|
Expected return on plan assets
|
|
(13.6
|
)
|
|
(13.3
|
)
|
|
(27.3
|
)
|
|
(26.4
|
)
|
|
Amortization of prior service credit
|
|
(2.8
|
)
|
|
(2.4
|
)
|
|
(5.6
|
)
|
|
(4.7
|
)
|
|
Amortization of net actuarial loss
|
|
0.1
|
|
|
1.9
|
|
|
1.6
|
|
|
4.2
|
|
|
Net periodic benefit (credit) cost
|
|
$
|
(2.3
|
)
|
|
$
|
1.9
|
|
|
$
|
(2.5
|
)
|
|
$
|
4.7
|
|
During the
six months ended June 30, 2017
, we made payments of
$107.2 million
to our pension plans and
$4.3 million
to our OPEB plans. We expect to make payments of
$6.4 million
related to our pension plans and
$5.3 million
related to our OPEB plans during the remainder of
2017
, dependent upon various factors affecting us, including our liquidity position and possible tax law changes.
NOTE 12—
GOODWILL
Goodwill represents the excess of the cost of an acquisition over the fair value of the identifiable net assets acquired. The following table shows changes to our goodwill balances by segment during the
six months ended June 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Non-Utility Energy
|
|
Total
|
|
Goodwill balance as of January 1, 2017
|
|
$
|
2,104.3
|
|
|
$
|
758.7
|
|
|
$
|
183.2
|
|
|
$
|
—
|
|
|
$
|
3,046.2
|
|
|
Acquisition of Bluewater
(1)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7.3
|
|
|
7.3
|
|
|
Goodwill balance as of June 30, 2017
(2)
|
|
$
|
2,104.3
|
|
|
$
|
758.7
|
|
|
$
|
183.2
|
|
|
$
|
7.3
|
|
|
$
|
3,053.5
|
|
|
|
|
|
(1)
|
See Note 2, Acquisition, for more information
on the acquisition of Bluewater.
|
|
|
|
|
(2)
|
We had
no
accumulated impairment losses related to our goodwill as of
June 30, 2017
.
|
|
|
|
|
|
|
|
06/30/2017 Form 10-Q
|
15
|
WEC Energy Group, Inc.
|
NOTE 13—
INVESTMENT IN AMERICAN TRANSMISSION COMPANY
We own approximately
60%
of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. The following table shows changes to our investment in ATC:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
Six Months Ended June 30
|
|
|
(in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
|
Balance at beginning of period
|
|
$
|
1,513.3
|
|
|
$
|
1,422.5
|
|
|
$
|
1,443.9
|
|
|
$
|
1,380.9
|
|
|
|
Add: Earnings from equity method investment
|
|
41.8
|
|
|
30.9
|
|
|
83.7
|
|
|
69.4
|
|
|
|
Add: Capital contributions
|
|
22.9
|
|
|
3.1
|
|
|
50.5
|
|
|
12.1
|
|
|
|
Add: Acquisition of Integrys's investment in ATC
|
|
—
|
|
|
(1.0
|
)
|
(1)
|
—
|
|
|
(1.0
|
)
|
(1)
|
|
Add: Adjustment to equity method goodwill
|
|
—
|
|
|
1.1
|
|
|
—
|
|
|
10.4
|
|
|
|
Less: Distributions
|
|
34.0
|
|
|
31.6
|
|
|
34.0
|
|
(2)
|
46.7
|
|
|
|
Less: Other
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
|
Balance at end of period
|
|
$
|
1,544.0
|
|
|
$
|
1,425.0
|
|
|
$
|
1,544.0
|
|
|
$
|
1,425.0
|
|
|
|
|
|
|
(1)
|
Amount reflects an adjustment to the allocation of the purchase price for Integrys made in the second quarter of 2016.
|
|
|
|
|
(2)
|
Distributions of
$35.2 million
, received in the first quarter of 2017, were approved and recorded in December 2016.
|
We pay ATC for transmission and other related services it provides. In addition, we provide a variety of operational, maintenance, and project management work for ATC, which are reimbursed by ATC. We are required to pay the cost of needed transmission infrastructure upgrades for new generation projects while the projects are under construction. ATC reimburses us for these costs when the new generation is placed in service.
The following table summarizes our significant related party transactions with ATC:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
Six Months Ended June 30
|
|
(in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
Charges to ATC for services and construction
|
|
$
|
3.7
|
|
|
$
|
4.3
|
|
|
$
|
7.9
|
|
|
$
|
8.4
|
|
|
Charges from ATC for network transmission services
|
|
87.3
|
|
|
91.1
|
|
|
174.6
|
|
|
182.1
|
|
|
Refund from ATC per FERC ROE order
|
|
—
|
|
|
—
|
|
|
(28.3
|
)
|
|
—
|
|
Our balance sheets included the following receivables and payables related to ATC:
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
June 30, 2017
|
|
December 31, 2016
|
|
Accounts receivable
|
|
|
|
|
|
Services provided to ATC
|
|
$
|
1.2
|
|
|
$
|
2.2
|
|
|
Accounts payable
|
|
|
|
|
|
Services received from ATC
|
|
29.1
|
|
|
28.7
|
|
Summarized financial data for ATC is included in the following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
Six Months Ended June 30
|
|
(in millions)
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
|
Income statement data
|
|
|
|
|
|
|
|
|
|
Revenues
|
|
$
|
176.6
|
|
|
$
|
154.3
|
|
|
$
|
351.3
|
|
|
$
|
318.5
|
|
|
Operating expenses
|
|
82.7
|
|
|
81.7
|
|
|
165.1
|
|
|
160.8
|
|
|
Other expense
|
|
25.7
|
|
|
23.7
|
|
|
52.1
|
|
|
47.7
|
|
|
Net income
|
|
$
|
68.2
|
|
|
$
|
48.9
|
|
|
$
|
134.1
|
|
|
$
|
110.0
|
|
|
|
|
|
|
|
|
06/30/2017 Form 10-Q
|
16
|
WEC Energy Group, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
June 30, 2017
|
|
December 31, 2016
|
|
Balance sheet data
|
|
|
|
|
|
Current assets
|
|
$
|
86.2
|
|
|
$
|
75.8
|
|
|
Noncurrent assets
|
|
4,489.3
|
|
|
4,312.9
|
|
|
Total assets
|
|
$
|
4,575.5
|
|
|
$
|
4,388.7
|
|
|
|
|
|
|
|
|
Current liabilities
|
|
$
|
640.3
|
|
|
$
|
495.1
|
|
|
Long-term debt
|
|
1,740.6
|
|
|
1,865.3
|
|
|
Other noncurrent liabilities
|
|
291.4
|
|
|
271.5
|
|
|
Shareholders' equity
|
|
1,903.2
|
|
|
1,756.8
|
|
|
Total liabilities and shareholders' equity
|
|
$
|
4,575.5
|
|
|
$
|
4,388.7
|
|
NOTE 14—
SEGMENT INFORMATION
At
June 30, 2017
, we reported
six
segments, which are described below.
|
|
|
|
•
|
The Wisconsin segment includes the electric and natural gas utility operations of WE, WG, and WPS, including WE's and WPS's electric and natural gas operations in the state of Michigan that were transferred to UMERC effective January 1, 2017.
|
|
|
|
|
•
|
The Illinois segment includes the natural gas utility and non-utility operations of PGL and NSG.
|
|
|
|
|
•
|
The other states segment includes the natural gas utility and non-utility operations of MERC and MGU.
|
|
|
|
|
•
|
The electric transmission segment includes our approximate
60%
ownership interest in ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions.
|
|
|
|
|
•
|
Following the acquisition of Bluewater, our We Power segment was renamed the non-utility energy segment. This segment includes We Power, which owns and leases generating facilities to WE, and Bluewater, which owns underground natural gas storage facilities in Michigan.
See Note 2, Acquisition, for more information
on the Bluewater transaction.
|
|
|
|
|
•
|
The corporate and other segment includes the operations of the WEC Energy Group holding company, the Integrys holding company, the Peoples Energy, LLC holding company, Wispark LLC, Bostco, Wisvest, Wisconsin Energy Capital Corporation, WBS, WPS Power Development LLC, and ITF. In the first quarter of 2017, we sold substantially all of the remaining assets of Bostco and in the second quarter of 2016, we sold certain assets of Wisvest. The sale of ITF was completed in the first quarter of 2016. See
Note 3, Dispositions
, for more information on these sales.
|
All of our operations are located within the United States. The following tables show summarized financial information related to our reportable segments for the
three and six months ended June 30
,
2017
and
2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Operations
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Electric Transmission
|
|
Non-Utility Energy
|
|
Corporate
and Other
|
|
Reconciling
Eliminations
|
|
WEC Energy Group Consolidated
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External revenues
|
|
$
|
1,303.2
|
|
|
$
|
253.2
|
|
|
$
|
65.7
|
|
|
$
|
1,622.1
|
|
|
$
|
—
|
|
|
$
|
6.2
|
|
|
$
|
3.2
|
|
|
$
|
—
|
|
|
$
|
1,631.5
|
|
|
Intersegment revenues
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
112.6
|
|
|
—
|
|
|
(112.6
|
)
|
|
—
|
|
|
Other operation and maintenance
|
|
458.7
|
|
|
104.9
|
|
|
23.3
|
|
|
586.9
|
|
|
—
|
|
|
2.7
|
|
|
2.8
|
|
|
(112.6
|
)
|
|
479.8
|
|
|
Depreciation and amortization
|
|
130.3
|
|
|
37.5
|
|
|
6.1
|
|
|
173.9
|
|
|
—
|
|
|
17.4
|
|
|
6.4
|
|
|
—
|
|
|
197.7
|
|
|
Operating income (loss)
|
|
223.6
|
|
|
41.4
|
|
|
4.7
|
|
|
269.7
|
|
|
—
|
|
|
98.7
|
|
|
(6.2
|
)
|
|
—
|
|
|
362.2
|
|
|
Equity in earnings of transmission affiliate
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41.8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41.8
|
|
|
Interest expense
|
|
48.2
|
|
|
10.9
|
|
|
1.9
|
|
|
61.0
|
|
|
—
|
|
|
15.2
|
|
|
26.8
|
|
|
(1.1
|
)
|
|
101.9
|
|
|
|
|
|
|
|
|
06/30/2017 Form 10-Q
|
17
|
WEC Energy Group, Inc.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Operations
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Electric Transmission
|
|
Non-Utility Energy
|
|
Corporate
and Other
|
|
Reconciling
Eliminations
|
|
WEC Energy Group Consolidated
|
|
Three Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External revenues
|
|
$
|
1,304.5
|
|
|
$
|
222.8
|
|
|
$
|
64.0
|
|
|
$
|
1,591.3
|
|
|
$
|
—
|
|
|
$
|
6.3
|
|
|
$
|
4.4
|
|
|
$
|
—
|
|
|
$
|
1,602.0
|
|
|
Intersegment revenues
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|
—
|
|
|
107.6
|
|
|
—
|
|
|
(107.8
|
)
|
|
—
|
|
|
Other operation and maintenance
|
|
487.8
|
|
|
116.2
|
|
|
29.4
|
|
|
633.4
|
|
|
—
|
|
|
2.7
|
|
|
(6.3
|
)
|
|
(107.8
|
)
|
|
522.0
|
|
|
Depreciation and amortization
|
|
122.7
|
|
|
33.1
|
|
|
5.2
|
|
|
161.0
|
|
|
—
|
|
|
17.0
|
|
|
12.0
|
|
|
—
|
|
|
190.0
|
|
|
Operating income (loss)
|
|
214.7
|
|
|
22.6
|
|
|
2.3
|
|
|
239.6
|
|
|
—
|
|
|
94.1
|
|
|
(1.6
|
)
|
|
—
|
|
|
332.1
|
|
|
Equity in earnings of transmission affiliate
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30.9
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30.9
|
|
|
Interest expense
|
|
44.4
|
|
|
9.8
|
|
|
2.1
|
|
|
56.3
|
|
|
—
|
|
|
15.6
|
|
|
30.2
|
|
|
(2.0
|
)
|
|
100.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Operations
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Electric Transmission
|
|
Non-Utility Energy
|
|
Corporate
and Other
|
|
Reconciling
Eliminations
|
|
WEC Energy Group Consolidated
|
|
Six Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External revenues
|
|
$
|
2,915.3
|
|
|
$
|
778.5
|
|
|
$
|
223.6
|
|
|
$
|
3,917.4
|
|
|
$
|
—
|
|
|
$
|
12.5
|
|
|
$
|
6.1
|
|
|
$
|
—
|
|
|
$
|
3,936.0
|
|
|
Intersegment revenues
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
221.6
|
|
|
—
|
|
|
(221.6
|
)
|
|
—
|
|
|
Other operation and maintenance
|
|
921.6
|
|
|
225.8
|
|
|
51.6
|
|
|
1,199.0
|
|
|
—
|
|
|
3.1
|
|
|
1.2
|
|
|
(221.6
|
)
|
|
981.7
|
|
|
Depreciation and amortization
|
|
259.6
|
|
|
73.7
|
|
|
12.1
|
|
|
345.4
|
|
|
—
|
|
|
34.9
|
|
|
12.0
|
|
|
—
|
|
|
392.3
|
|
|
Operating income (loss)
|
|
555.9
|
|
|
196.8
|
|
|
38.1
|
|
|
790.8
|
|
|
—
|
|
|
196.1
|
|
|
(7.4
|
)
|
|
—
|
|
|
979.5
|
|
|
Equity in earnings of transmission affiliate
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
83.7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
83.7
|
|
|
Interest expense
|
|
96.9
|
|
|
22.0
|
|
|
4.2
|
|
|
123.1
|
|
|
—
|
|
|
30.5
|
|
|
55.9
|
|
|
(2.9
|
)
|
|
206.6
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Utility Operations
|
|
|
|
|
|
|
|
|
|
|
|
(in millions)
|
|
Wisconsin
|
|
Illinois
|
|
Other States
|
|
Total Utility
Operations
|
|
Electric Transmission
|
|
Non-Utility Energy
|
|
Corporate
and Other
|
|
Reconciling
Eliminations
|
|
WEC Energy Group Consolidated
|
|
Six Months Ended
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External revenues
|
|
$
|
2,884.3
|
|
|
$
|
671.3
|
|
|
$
|
212.4
|
|
|
$
|
3,768.0
|
|
|
$
|
—
|
|
|
$
|
12.5
|
|
|
$
|
16.3
|
|
|
$
|
—
|
|
|
$
|
3,796.8
|
|
|
Intersegment revenues
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
—
|
|
|
212.1
|
|
|
—
|
|
|
(212.4
|
)
|
|
—
|
|
|
Other operation and maintenance
|
|
979.1
|
|
|
234.1
|
|
|
59.4
|
|
|
1,272.6
|
|
|
—
|
|
|
3.1
|
|
|
(9.8
|
)
|
|
(212.4
|
)
|
|
1,053.5
|
|
|
Depreciation and amortization
|
|
245.6
|
|
|
65.9
|
|
|
10.3
|
|
|
321.8
|
|
|
—
|
|
|
34.0
|
|
|
22.1
|
|
|
—
|
|
|
377.9
|
|
|
Operating income (loss)
|
|
542.2
|
|
|
159.6
|
|
|
34.1
|
|
|
735.9
|
|
|
—
|
|
|
187.4
|
|
|
(1.9
|
)
|
|
—
|
|
|
921.4
|
|
|
Equity in earnings of transmission affiliate
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
69.4
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
69.4
|
|
|
Interest expense
|
|
88.9
|
|
|
19.5
|
|
|
4.6
|
|
|
113.0
|
|
|
—
|
|
|
31.2
|
|
|
61.5
|
|
|
(4.7
|
)
|
|
201.0
|
|
NOTE 15—
VARIABLE INTEREST ENTITIES
The primary beneficiary of a variable interest entity must consolidate the entity's assets and liabilities. In addition, certain disclosures are required for significant interest holders in variable interest entities.
We assess our relationships with potential variable interest entities, such as our coal suppliers, natural gas suppliers, coal transporters, natural gas transporters, and other counterparties related to power purchase agreements, investments, and joint
|
|
|
|
|
|
|
06/30/2017 Form 10-Q
|
18
|
WEC Energy Group, Inc.
|
ventures. In making this assessment, we consider, along with other factors, the potential that our contracts or other arrangements provide subordinated financial support, the obligation to absorb the entity's losses, the right to receive residual returns of the entity, and the power to direct the activities that most significantly impact the entity's economic performance.
American Transmission Company
We own approximately
60%
of ATC, a for-profit, electric transmission company regulated by the FERC and certain state regulatory commissions. We have determined that ATC is a variable interest entity but that consolidation is not required since we are not ATC's primary beneficiary. As a result of our limited voting rights, we do not have the power to direct the activities that most significantly impact ATC's economic performance. We account for ATC as an equity method investment.
See Note 13, Investment in American Transmission Company, for more information
.
The significant assets and liabilities related to ATC recorded on our balance sheets included our equity investment, distributions receivable, and accounts payable. At
June 30, 2017
and
December 31, 2016
, our equity investment was
$1,544.0 million
and
$1,443.9 million
, respectively, which approximates our maximum exposure to loss as a result of our involvement with ATC. In addition, we had a receivable of
$35.2 million
recorded at
December 31, 2016
for distributions from ATC. We also had
$29.1 million
and
$28.7 million
of accounts payable due to ATC at
June 30, 2017
and
December 31, 2016
, respectively, for network transmission services
Purchased Power Agreement
We have identified a purchased power agreement that represents a variable interest. This agreement is for
236
MWs of firm capacity from a natural gas-fired cogeneration facility, and we account for it as a capital lease. The agreement includes
no
minimum energy requirements over the remaining term of approximately
five years
. We have examined the risks of the entity, including operations, maintenance, dispatch, financing, fuel costs, and other factors, and have determined that we are not the primary beneficiary of the entity. We do not hold an equity or debt interest in the entity, and there is
no
residual guarantee associated with the purchased power agreement.
We have approximately
$78.4 million
of required payments over the remaining term of this agreement. We believe that the required lease payments under this contract will continue to be recoverable in rates. Total capacity and lease payments under this contract for the
six months ended June 30, 2017
and
2016
were
$9.0 million
and
$26.9 million
, respectively. Our maximum exposure to loss is limited to the capacity payments under the contract.
NOTE 16—
COMMITMENTS AND CONTINGENCIES
We and our subsidiaries have significant commitments and contingencies arising from our operations, including those related to unconditional purchase obligations, environmental matters, and enforcement and litigation matters.
Unconditional Purchase Obligations
Our electric utilities have obligations to distribute and sell electricity to their customers, and our natural gas utilities have obligations to distribute and sell natural gas to their customers. The utilities expect to recover costs related to these obligations in future customer rates. In order to meet these obligations, we routinely enter into long-term purchase and sale commitments for various quantities and lengths of time. Our minimum future commitments related to these purchase obligations as of
June 30, 2017
, including those of our subsidiaries, were
$12,065.4 million
.
Environmental Matters
Consistent with other companies in the energy industry, we face significant ongoing environmental compliance and remediation obligations related to current and past operations. Specific environmental issues affecting us include, but are not limited to, current and future regulation of air emissions such as SO
2
, NOx, fine particulates, mercury, and GHGs; water discharges; disposal of coal combustion products such as fly ash; and remediation of impacted properties, including former manufactured gas plant sites.
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Air Quality
Cross-State Air Pollution Rule
In July 2011, the EPA issued the CSAPR, which replaced a previous rule, the Clean Air Interstate Rule. The purpose of the CSAPR was to limit the interstate transport of NOx and SO
2
that contribute to fine particulate matter and ozone nonattainment in downwind states through a proposed allowance allocation and trading plan. After several lawsuits and related appeals, in October 2014, the D.C. Circuit Court of Appeals issued a decision that allowed the EPA to begin implementing CSAPR on January 1, 2015. The emissions budgets of Phase I of the rule applied in 2015 and 2016, while the Phase II emissions budgets apply to 2017 and beyond.
The EPA published its proposed update to the CSAPR for the 2008 ozone NAAQS in December 2015, and issued the final rule in September 2016. We remain well positioned to meet the rule requirements and do not expect to incur significant costs to comply with this rule.
Sulfur Dioxide National Ambient Air Quality Standards
The EPA issued a revised 1-Hour SO
2
NAAQS that became effective in August 2010. The EPA issued a final rule in August 2015 describing the implementation requirements and established a compliance timeline for the revised standard. The final rule affords state agencies some latitude in rule implementation. A nonattainment designation could have negative impacts for a localized geographic area, including additional permitting requirements for new or existing sources in the area. In June 2016, we provided modeling to the WDNR that shows the area around the Weston Power Plant to be in compliance. Based upon the submittal, the WDNR provided final modeling to the EPA demonstrating the area around the Weston Power Plant to be in compliance. We expect that the EPA will consider the WDNR's recommendation and will finalize its designation by the end of 2017. We believe our fleet overall is well positioned to meet the regulation and do not expect to incur significant costs to comply with this regulation.
8-Hour Ozone National Ambient Air Quality Standards
Sheboygan County and the eastern portion of Kenosha County are currently designated as nonattainment with the 2008 ozone standard. In response, Wisconsin has updated the 2008 ozone NAAQS attainment plan for Kenosha County and submitted it to the EPA for approval. The plan concluded that Wisconsin will not need to implement any new regulatory measures or programs. The area is forecasted to meet the standard by the 2018 compliance date due to emission control measures already in place. Wisconsin has prepared a draft attainment plan for Sheboygan County, which is out for public comment and is expected to submit a final plan to the EPA for approval this summer. A final EPA action regarding Wisconsin's attainment plan is expected later in 2017.
After completing its review of the 2008 ozone standard, the EPA released a final rule in October 2015, which lowered the limit for ground-level ozone, creating a more stringent standard than the 2008 NAAQS. This is expected to cause nonattainment for Wisconsin's Lake Michigan shoreline counties (or partial counties), with potential future impacts for our fossil-fueled power plant fleet. In January 2017, the EPA released preliminary interstate ozone transport modeling for the 2015 ozone NAAQS. The EPA is currently scheduled to finalize designations in October 2017. For nonattainment areas, the state of Wisconsin will have to develop a state implementation plan to bring the areas back into attainment. We will be required to comply with this state implementation plan no earlier than 2020. We will not know the potential impacts for complying with the 2015 ozone NAAQS until the designations are final and until the state prepares a draft attainment plan.
Although we are still in the process of reviewing and determining potential impacts resulting from this rule, we believe we are well positioned to meet the ozone standard and do not expect to incur significant costs to comply.
Climate Change
In 2015, the EPA issued a final rule regulating GHG emissions from existing generating units, referred to as the Clean Power Plan (CPP), a proposed federal plan and model trading rules as alternatives or guides to state compliance plans, and final performance standards for modified and reconstructed generating units and new fossil-fueled power plants. In October 2015, following publication of the CPP, numerous states (including Wisconsin and Michigan) and other parties, filed lawsuits challenging the final rule, including a request to stay the implementation of the final rule pending the outcome of these legal challenges. The D.C. Circuit Court of Appeals denied the stay request, but in February 2016, the Supreme Court stayed the effectiveness of the CPP until disposition of the litigation in the D.C. Circuit Court of Appeals and to the extent that further appellate review is sought, at the Supreme Court. The D.C. Circuit Court of Appeals heard
one
case in September 2016, and the other case is still pending. In April
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2017, pursuant to motions made by the EPA, the D.C. Circuit Court of Appeals ordered the cases to be held in abeyance. Supplemental briefs were provided addressing whether the cases should be remanded to the EPA rather than held in abeyance. The EPA argued that the cases should continue to be held in abeyance pending the conclusion of the EPA's review of the CPP and any resulting rulemaking.
The CPP seeks to achieve state-specific GHG emission reduction goals by 2030, and would have required states to submit plans by September 2016. The goal of the final rule is to reduce nationwide GHG emissions by
32%
from 2005 levels. The rule is seeking GHG emission reductions in Wisconsin and Michigan of
41%
and
39%
, respectively, below 2012 levels by 2030. Interim goals starting in 2022 would require states to achieve about
two-thirds
of the 2030 required reduction.
In March 2017, President Trump issued an executive order that, among other things, specifically directs the EPA to review, and if appropriate, initiate proceedings to suspend, revise, or rescind the CPP and related GHG regulations for new, reconstructed, or modified fossil-fueled power plants. The EPA announced that it has initiated this review. As a result of this order and related EPA review, as well as the ongoing legal proceedings, the timelines for the GHG emission reduction goals and all other aspects of the CPP are uncertain. In April 2017, the EPA withdrew the proposed rule for a federal plan and model trading rules that were published in October 2015 for use in developing state plans to implement the CPP or for use in states where a plan is not submitted or approved. In addition, the Governor of Wisconsin issued an executive order in February 2016, which prohibits state agencies, departments, boards, commissions, or other state entities from developing or promoting the development of a state plan.
Notwithstanding the uncertain future of the CPP, and given current fuel and technology markets, we continue to evaluate opportunities and actions that preserve fuel diversity, lower costs for our customers, and contribute towards long-term GHG reductions. Our plan is to work with our industry partners, environmental groups, and the State of Wisconsin, with a goal of reducing CO
2
emissions by approximately
40%
below 2005 levels by 2030. We continue to evaluate numerous options in order to meet our CO
2
reduction goal, such as increased use of existing natural gas combined cycle units, co-firing or switching to natural gas in existing coal-fired units, reduced operation or retirement of existing coal-fired units, addition of new renewable energy resources (wind, solar), and consideration of supply and demand-side energy efficiency and distributed generation.
Water Quality
Clean Water Act Cooling Water Intake Structure Rule
In August 2014, the EPA issued a final regulation under Section 316(b) of the Clean Water Act, which requires that the location, design, construction, and capacity of cooling water intake structures at existing power plants reflect the Best Technology Available (BTA) for minimizing adverse environmental impacts from both impingement (entrapping organisms on water intake screens) and entrainment (drawing organisms into water intake). The rule became effective in October 2014, and applies to all of our existing generating facilities with cooling water intake structures, except for the ERGS units, which were permitted under the rules governing new facilities.
Facility owners must select from
seven
compliance options available to meet the impingement mortality (IM) reduction standard. The rule requires state permitting agencies to make BTA determinations, subject to EPA oversight, for IM reduction over the next several years as facility permits are reissued. Based on our assessment, we believe that existing technologies at our generating facilities, except for Pulliam Units 7 and 8 and Weston Unit 2, satisfy the IM BTA requirements. We plan to evaluate the available IM options for Pulliam Units 7 and 8. We also expect that limited studies will be required to support the future WDNR BTA determinations for Weston Unit 2. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the IM BTA requirements based on low capacity use of the unit.
BTA determinations must also be made by the WDNR and MDEQ to address entrainment mortality (EM) reduction on a site-specific basis taking into consideration several factors. We have received an EM BTA determination by the WDNR, with EPA concurrence, for our intake modification at VAPP. BTA determinations for EM will be made in future permit reissuances for Pulliam Units 7 and 8, Weston Units 2 through 4, Port Washington Generating Station, Pleasant Prairie Power Plant, PIPP, and OC 5 through OC 8.
During 2017 and 2018, we will continue to complete studies and evaluate options to address the EM BTA requirements at these plants. With the exception of Pleasant Prairie Power Plant and Weston Units 3 and 4 (which all have existing cooling towers that meet EM BTA requirements), we cannot yet determine what, if any, intake structure or operational modifications will be required to meet the new EM BTA requirements at the facilities. We also expect that limited studies to support WDNR BTA determinations will be conducted at the Weston facility. Based on preliminary discussions with the WDNR, we anticipate that the WDNR will not require physical modifications to the Weston Unit 2 intake structure to meet the EM BTA requirements based on low capacity use of the unit.
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Based on discussions with the MDEQ, if we provide information about unit retirements with our next National Pollutant Discharge Elimination System permit application and then submit a signed certification by August 2017 stating that PIPP will be retired no later than the end of the next permit cycle (assumed to be October 1, 2022), then the EM BTA requirements will be waived. We expect to submit entrainment studies being conducted at Pulliam Units 7 and 8 to the WDNR by June 2018.
We believe our fleet overall is well positioned to meet the new regulation and do not expect to incur significant costs to comply with this regulation.
Steam Electric Effluent Limitation Guidelines
The EPA's final steam electric effluent limitation guidelines (ELG) rule took effect in January 2016. In April 2017, the EPA issued an administrative stay of certain compliance deadlines while further reviewing the rule. In June 2017, the EPA issued a proposed rule to codify this stay. This rule applies to wastewater discharges from our power plant processes in Wisconsin and Michigan. While the ELG compliance deadlines are postponed, the WDNR and the MDEQ have indicated that they will refrain from incorporating certain new requirements into any reissued discharge permits between 2018 and 2023.
After a final rule is back in effect, the WDNR and MDEQ have indicated that they will modify the state rules as necessary and incorporate the new requirements into our facility permits, which are renewed every
five years
. Our power plant facilities already have advanced wastewater treatment technologies installed that meet many of the discharge limits established by this rule. However, as currently constructed, the ELG rule will require additional wastewater treatment retrofits as well as installation of other equipment to minimize process water use.
The final rule would phase in new or more stringent requirements related to limits of arsenic, mercury, selenium, and nitrogen in wastewater discharged from wet scrubber systems. New requirements for wet scrubber wastewater treatment would require additional zero liquid discharge or other advanced treatment capital improvements for the Oak Creek site and Pleasant Prairie facilities. The rule also would require dry fly ash handling, which is already in place at all of our power plants. Dry bottom ash transport systems are required by the new rule, and modifications would be required at OC 7, OC 8, the Pleasant Prairie units, Pulliam Units 7 and 8, and Weston Unit 3. We are beginning preliminary engineering for compliance with the rule and estimate a total cost range of
$80 million
to
$110 million
for these advanced treatment and bottom ash transport systems. A similar system would be required at PIPP if we were not expecting to retire the plant. See the UMERC discussion in
Note 18, Regulatory Environment
, regarding the potential retirement of PIPP.
Land Quality
Manufactured Gas Plant Remediation
We have identified sites at which our utilities or a predecessor company owned or operated a manufactured gas plant or stored manufactured gas. We have also identified other sites that may have been impacted by historical manufactured gas plant activities. Our natural gas utilities are responsible for the environmental remediation of these sites, some of which are in the EPA Superfund Alternative Approach Program. We are also working with various state jurisdictions in our investigation and remediation planning. These sites are at various stages of investigation, monitoring, remediation, and closure.
In addition, we are coordinating the investigation and cleanup of some of these sites subject to the jurisdiction of the EPA under what is called a "multisite" program. This program involves prioritizing the work to be done at the sites, preparation and approval of documents common to all of the sites, and use of a consistent approach in selecting remedies. At this time, we cannot estimate future remediation costs associated with these sites beyond those described below.
The future costs for detailed site investigation, future remediation, and monitoring are dependent upon several variables including, among other things, the extent of remediation, changes in technology, and changes in regulation. Historically, our regulators have allowed us to recover incurred costs, net of insurance recoveries and recoveries from potentially responsible parties, associated with the remediation of manufactured gas plant sites. Accordingly, we have established regulatory assets for costs associated with these sites.
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We have established the following regulatory assets and reserves related to manufactured gas plant sites:
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(in millions)
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June 30, 2017
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December 31, 2016
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Regulatory assets
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$
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683.8
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$
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702.7
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Reserves for future remediation
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622.4
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633.4
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Enforcement and Litigation Matters
We and our subsidiaries are involved in legal and administrative proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Although we are unable to predict the outcome of these matters, management believes that appropriate reserves have been established and that final settlement of these actions will not have a material effect on our financial condition or results of operations.
Consent Decrees
Wisconsin Public Service Corporation Consent Decree – Weston and Pulliam
In November 2009, the EPA issued a NOV to WPS, which alleged violations of the CAA's New Source Review requirements relating to certain projects completed at the Weston and Pulliam plants from 1994 to 2009. WPS entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Eastern District of Wisconsin in March 2013.
Also, in May 2010, WPS received from the Sierra Club a Notice of Intent to file a civil lawsuit based on allegations that WPS violated the CAA at the Weston and Pulliam plants. WPS entered into a Standstill Agreement with the Sierra Club by which the parties agreed to negotiate as part of the EPA NOV process, rather than litigate. The Standstill Agreement ended in October 2012, but no further action has been taken by the Sierra Club as of
June 30, 2017
. It is unknown whether the Sierra Club will take further action in the future.
Joint Ownership Power Plants Consent Decree – Columbia and Edgewater
In December 2009, the EPA issued a NOV to Wisconsin Power and Light, the operator of the Columbia and Edgewater plants, and the other joint owners of these plants, including Madison Gas and Electric, WE (former co-owner of an Edgewater unit), and WPS. The NOV alleged violations of the CAA's New Source Review requirements related to certain projects completed at those plants. WPS, along with Wisconsin Power and Light, Madison Gas and Electric, and WE, entered into a Consent Decree with the EPA resolving this NOV. This Consent Decree was entered by the United States District Court for the Western District of Wisconsin in June 2013.
The Consent Decree contains a requirement to, among other things, refuel, repower, or retire Edgewater Unit 4, of which WPS is a joint owner, by no later than December 31, 2018. Management of the joint owners has recommended that Edgewater Unit 4 be retired in December 2018. However, a final decision on how to address the requirement for this unit has not yet been made by the joint owners, as early retirement is contingent on various operational and market factors, and other alternatives to retirement are still available.
NOTE 17—
SUPPLEMENTAL CASH FLOW INFORMATION
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Six Months Ended June 30
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(in millions)
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2017
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2016
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Cash (paid) for interest, net of amount capitalized
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$
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(209.3
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)
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$
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(209.2
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)
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Cash received for income taxes, net
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9.5
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7.4
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Significant non-cash transactions
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Accounts payable related to construction costs
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155.5
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114.0
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Increase (decrease) in restricted cash from the sale (purchase) of investments held in the rabbi trust
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4.6
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(1.5
|
)
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Portion of Bostco real estate holdings sale financed with note receivable *
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7.0
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—
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Amortization of deferred revenue
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12.4
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12.3
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*
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See Note 3, Dispositions, for more information
on this sale.
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At
June 30, 2017
, and
December 31, 2016
, restricted cash of
$21.8 million
and
$33.6 million
, respectively, was recorded within other long-term assets on our balance sheets. The majority of this amount was held in the Integrys rabbi trust and represents a portion of the required funding that was triggered by the announcement of the Integrys acquisition. Withdrawals of restricted cash from the rabbi trust for qualifying payments are shown as an investing activity on the statements of cash flows. Changes in restricted cash due to the sale or purchase of investments held in the rabbi trust are non-cash transactions and are included in the table above.
NOTE 18—
REGULATORY ENVIRONMENT
Wisconsin Electric Power Company, Wisconsin Gas LLC, and Wisconsin Public Service Corporation
2018 and 2019 Rates
During April 2017, WE, WG, and WPS filed an application with the PSCW for approval of a settlement agreement they made with several of their commercial and industrial customers regarding 2018 and 2019 base rates. In this proposed settlement agreement, WE, WG, and WPS agreed to keep electric and natural gas base rates frozen for their customers through 2019. In addition, WE and WPS agreed to extend and expand the electric real-time pricing options for large commercial and industrial customers, and WE agreed to prevent the continued growth of certain escrowed costs. Deferral by WE, WG, and WPS of the revenue requirement impacts of any federal corporate tax reform enacted in 2017, or during the rate freeze period, was included in the agreement as well. Additionally, the agreement allows WPS to extend, through 2019, the deferral for the revenue requirement of ReACT™ costs above the authorized
$275.0 million
level. The total cost of the ReACT™ project, excluding
$51 million
of AFUDC, is currently estimated to be
$342 million
. The agreement also included an extension, through 2019, of other deferrals related to WPS's electric real-time pricing program and network transmission expenses.
Pursuant to the settlement agreement, WPS also agreed to adopt, beginning in 2018, the earnings sharing mechanism currently in place for WE and WG, and all
three
utilities agreed to keep the mechanism in place through 2019. Under this earnings sharing mechanism, if WE, WG, or WPS earns above its authorized ROE,
50%
of the first
50
basis points of additional utility earnings must be shared with customers. All utility earnings above the first
50
basis points must also be shared with customers.
In July 2017, the PSCW staff issued a commission memorandum in response to the settlement agreement, and we expect the PSCW to issue a final order on the agreement during the third quarter of 2017. If the PSCW rejects the proposed settlement agreement, we expect we will file a traditional rate proceeding.
Natural Gas Storage Facilities in Michigan
In January 2017, we signed an agreement for the acquisition of Bluewater. Bluewater owns natural gas storage facilities in Michigan that would provide approximately
one-third
of the current storage needs for the natural gas distribution service customers of WE, WG, and WPS. As a result of this agreement, WE, WG, and WPS filed a request with the PSCW in February 2017 for a declaratory ruling on various items associated with the storage facilities. In the filing, WE, WG, and WPS requested that the PSCW review and confirm the reasonableness and prudency of their potential long-term storage service agreements and interstate natural gas transportation contracts related to the storage facilities. WE, WG, and WPS also requested approval to amend our Affiliated Interest Agreement to ensure WBS and our other subsidiaries could provide services to the storage facilities. During June 2017, the PSCW granted, subject to various conditions, these declarations and approvals, and we acquired Bluewater on June 30, 2017.
See Note 2, Acquisition, for more information
.
The Peoples Gas Light and Coke Company and North Shore Gas Company
Illinois Proceedings
In March 2015, the ICC opened a docket, naming PGL as respondent, to investigate the veracity of certain allegations included in anonymous letters that the ICC staff received regarding PGL's SMP. PGL and the ICC staff filed a settlement agreement related to these anonymous letters with the ICC during March 2017. In this agreement, we agreed to modify our code of business conduct to address certain concerns regarding conflicts of interest, and PGL agreed to provide a quarterly report to the ICC for
four
years identifying code of conduct and conflict of interest allegations. The agreement also requested that PGL provide semi-annual quality assurance reports to the ICC for
four
years on the SMP capital construction performed by PGL crews and contractors. During May
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2017, the ICC issued a final order approving the settlement agreement. The period to appeal this order has expired, and
no
appeals were filed.
In December 2015, the ICC ordered a series of stakeholder workshops to evaluate PGL's SMP. This ICC action did not impact PGL's ongoing work to modernize and maintain the safety of its natural gas distribution system, but it instead provided the ICC with an opportunity to analyze long-term elements of the program through the stakeholder workshops. The workshops commenced in January 2016 and were completed in March 2016. In July 2016, the ICC initiated a proceeding to review, among other things, the planning, reporting, and monitoring of the program, including the target end date for the program. In March 2017, the ICC issued an order directing that additional hearings be held before the ALJ on certain issues to further develop the evidentiary record in the case. This proceeding is expected to result in a final order by the ICC in 2017. We are currently unable to determine what, if any, long-term impact there will be on the SMP.
Qualifying Infrastructure Plant Rider
In July 2013, Illinois Public Act 98-0057, The Natural Gas Consumer, Safety & Reliability Act, became law. The Act provides PGL with a cost recovery mechanism that allows collection, through a surcharge on customer bills, of prudently incurred costs to upgrade Illinois natural gas infrastructure. This Act eliminated a requirement for PGL to file biennial rate proceedings under existing Illinois coal-to-gas legislation. In September 2013, PGL filed with the ICC requesting the proposed rider, which was approved in January 2014.
PGL's QIP rider is subject to an annual reconciliation whereby costs are reviewed for accuracy and prudency. In March 2017, PGL filed its 2016 reconciliation with the ICC, which, along with the 2015 reconciliation, is still pending. For PGL's 2014 reconciliation, the ICC staff and the Illinois Attorney General's office filed testimony in June 2017. PGL filed rebuttal testimony in July 2017, and we expect to receive an order related to the 2014 reconciliation in the fourth quarter of 2017. As of
June 30, 2017
, there can be
no
assurance that all costs incurred under PGL's QIP rider during the open reconciliation years will be recoverable.
Minnesota Energy Resources Corporation
2016 Minnesota Rate Order
In September 2015, MERC initiated a rate proceeding with the MPUC. In October 2016, the MPUC issued a final written order for MERC, effective March 1, 2017. The order authorized a retail natural gas rate increase of
$6.8 million
(
3.0%
). The rates reflect a
9.11%
ROE and a common equity component average of
50.32%
. The order approved MERC's request to continue the use of its currently authorized decoupling mechanism for another
three years
. The final approved rate increase was lower than the interim rates collected from customers during 2016. Therefore, we refunded
$4.1 million
to MERC's customers during the second quarter of 2017.
Upper Michigan Energy Resources Corporation
Formation of Upper Michigan Energy Resources Corporation
In December 2016, both the MPSC and the PSCW approved the operation of UMERC as a stand-alone utility in the Upper Peninsula of Michigan, and UMERC became operational effective January 1, 2017. This utility holds the electric and natural gas distribution assets, previously held by WE and WPS, located in the Upper Peninsula of Michigan.
In August 2016, we entered into an agreement with the Tilden Mining Company (Tilden), under which Tilden will purchase electric power from UMERC for its iron ore mine for
20 years
. The agreement also calls for UMERC to construct and operate approximately
180
MWs of natural gas-fired generation located in the Upper Peninsula of Michigan. During January 2017, UMERC filed an application with the MPSC for a certificate of necessity to begin construction of the proposed generation. The estimated cost of this project is approximately
$265 million
(
$275 million
with AFUDC),
50%
of which is expected to be recovered from Tilden, with the remaining
50%
expected to be recovered from utility customers located in the Upper Peninsula of Michigan. Subject to regulatory approval of both the agreement with Tilden and the construction of the proposed generation, the new units are expected to begin commercial operation in 2019 and should allow for the retirement of PIPP no later than 2020. Tilden will remain a customer of WE until this new generation begins commercial operation. We expect the MPSC to issue final orders on the Tilden agreement and the proposed generation during the fourth quarter of 2017.
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2015 Michigan Rate Order
Prior to the formation of UMERC, in October 2014, WPS initiated a rate proceeding with the MPSC. In April 2015, the MPSC issued a final written order for WPS, effective April 24, 2015, approving a settlement agreement. As a result of the formation of UMERC, the terms and conditions of this WPS rate order now apply to UMERC, including the deferrals described below. The order authorized a retail electric rate increase of
$4.0 million
to be implemented over
three
years to recover costs for the 2013 acquisition of the Fox Energy Center as well as other capital investments associated with the Crane Creek wind farm and environmental upgrades at generation plants. The rates reflected a
10.2%
ROE and a common equity component average of
50.48%
. The increase reflected the continued deferral of costs associated with the Fox Energy Center until the second anniversary of the order. The increase also reflected the deferral of Weston Unit 3 ReACT™ environmental project costs. On the second anniversary of the order, the Fox Energy Center costs deferral was discontinued and amortization of this deferral began, along with the amortization of the deferral associated with the termination of the Fox Energy Center tolling agreement. In the order, the MPSC also approved the deferral and amortization of the undepreciated book value of the retired plant associated with Pulliam Units 5 and 6 and Weston Unit 1 starting with the actual retirement date, June 1, 2015, and concluding by 2023. UMERC will not seek an increase to retail electric base rates that would become effective prior to January 1, 2018.
NOTE 19—
NEW ACCOUNTING PRONOUNCEMENTS
Revenue Recognition
In May 2014, the FASB and the International Accounting Standards Board issued their joint revenue recognition standard, ASU 2014-09, Revenue from Contracts with Customers. Several amendments were issued subsequent to the standard to clarify the guidance. The core principle of the guidance is to recognize revenue in an amount that an entity is entitled to receive in exchange for goods and services. The guidance also requires additional disclosures about the nature, amount, timing, and uncertainty of revenues and the related cash flows arising from contracts with customers.
We intend to adopt this standard for interim and annual periods beginning January 1, 2018, as required, and plan to use the modified retrospective method of adoption. If applicable, this method requires a cumulative-effect adjustment to be recorded on the balance sheet as of the beginning of 2018, as if the standard had always been in effect. If applicable, disclosures in 2018 will include a reconciliation of results under the new revenue recognition guidance compared with what would have been reported in 2018 under the old revenue recognition guidance in order to help facilitate comparability with the prior periods.
We are currently reviewing our contracts with customers and related financial disclosures to evaluate the impact of the amended guidance on our existing revenue recognition policies and procedures. We consider tariff sales at our regulated utilities, excluding the revenue component related to alternative revenue programs, to be in the scope of the new standard. We have evaluated the nature of these revenues and do not expect that there will be a significant shift in the timing or pattern of revenue recognition for such sales. However, in our evaluation, we are also monitoring unresolved implementation issues for our industry. The final resolution of these issues could impact our current accounting policies and revenue recognition.
Recognition and Measurement of Financial Instruments
In January 2016, the FASB issued ASU 2016-01, Recognition and Measurement of Financial Assets and Liabilities. This guidance is effective for fiscal years and interim periods beginning after December 15, 2017, and will be recorded with a cumulative-effect adjustment to beginning retained earnings as of the beginning of the fiscal year in which the guidance is effective. This guidance requires equity investments, including other ownership interests such as partnerships, unincorporated joint ventures, and limited liability companies, to be measured at fair value with changes in fair value recognized in net income. It also simplifies the impairment assessment of equity investments without readily determinable fair values and amends certain disclosure requirements associated with the fair value of financial instruments. This ASU does not apply to investments accounted for under the equity method of accounting. We do not believe the adoption of this guidance will have a significant impact on our financial statements.
Leases
In February 2016, the FASB issued ASU 2016-02, Leases. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and will be applied using a modified retrospective approach. The main provision of this ASU is that lessees will be required to recognize lease assets and lease liabilities for most leases, including those classified as operating leases under GAAP. We are currently assessing the effects this guidance may have on our financial statements.
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Financial Instruments Credit Losses
In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. This ASU introduces a new impairment model known as the current expected credit loss model. The ASU requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. Previously, recognition of the full amount of credit losses was generally delayed until the loss was probable of occurring. We are currently assessing the effects this guidance may have on our financial statements.
Classification of Certain Cash Receipts and Cash Payments
In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, and will be applied using a retrospective transition method. There are eight main provisions of this ASU for which current GAAP either is unclear or does not include specific guidance. We do not believe the adoption of this guidance will have a significant impact on our financial statements.
Restricted Cash
In November 2016, the FASB issued ASU 2016-18, Restricted Cash. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-the period and end-of-the period total amounts shown on the statements of cash flows. We do not believe the adoption of this guidance will have a significant impact on our financial statements.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. This guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Under this ASU, an employer is required to disaggregate the service cost component from the other components of the net benefit cost. The amendments provide explicit guidance on how to present the service cost component and the other components of the net benefit cost in the income statement and allow only the service cost component of the net benefit cost to be eligible for capitalization. The amendments should be applied retrospectively for the presentation of the service cost component and the other components of the net benefit cost in the income statement, and prospectively for the capitalization of the service cost component in assets. We are currently assessing the effects this guidance may have on our financial statements.
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06/30/2017 Form 10-Q
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27
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WEC Energy Group, Inc.
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