The accompanying notes are an integral part of our condensed consolidated financial statements.
The accompanying notes are an integral part of our condensed consolidated financial statements.
The accompanying notes are an integral part of our condensed consolidated financial statements.
The accompanying notes are an integral part of our condensed consolidated financial statements.
The accompanying notes are an integral part of our condensed consolidated financial statements.
The accompanying notes are an integral part of our condensed consolidated financial statements.
Notes to Condensed Consolidated Financial Statements
(unaudited)
Note 1. Background and Nature of Operations
Avangrid, Inc., formerly Iberdrola USA, Inc. (AVANGRID, we or the Company), is an energy services holding company engaged in the regulated energy distribution business through its principal subsidiaries Avangrid Networks, Inc. (Networks) and UIL Holdings Corporation (UIL). AVANGRID is also in the renewable energy generation and gas storage and trading businesses through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables LLC (Renewables) and Enstor Gas, LLC (Gas). AVANGRID is an 81.5% owned subsidiary of Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. AVANGRID was organized in 1997 as NGE Resources, Inc. under the laws of New York as the holding company for the principal operating utility companies.
On March 31, 2016, we completed the sale of our interest in Iroquois Gas Transmission System L.P. (Iroquois) to an unaffiliated third party for proceeds of $53.8 million and an impact to net income of $19.0 million.
Note 2. Basis of Presentation
The accompanying notes should be read in conjunction with the notes to the combined and consolidated financial statements of Avangrid, Inc. and subsidiaries as of December 31, 2015 and 2014 and for the three years ended December 31, 2015 included in AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015.
The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries Networks, UIL and ARHI. UIL’s consolidated accounts have been included in the consolidated financial statements of AVANGRID since December 16, 2015, the date of acquisition of UIL. Intercompany accounts and transactions have been eliminated in consolidation. The year-end balance sheet data was derived from audited financial statements. The unaudited condensed consolidated financial statements for the interim periods have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the interim condensed consolidated financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements.
We believe the disclosures made are adequate to make the information presented not misleading. In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated balance sheets, condensed consolidated statements of income, comprehensive income, cash flows and changes in equity for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three months ended March, 31 2016 are not necessarily indicative of the results for the entire fiscal year ending December 31, 2016.
Revision of estimated useful lives of wind power station assets at Renewables
Renewables’ wind power station assets in service less salvage value, if any, are depreciated using the straight-line method over their estimated useful lives. Renewables’ effective depreciation rate, excluding decommissioning, was 4.0% in both 2015 and 2014. Renewables reviews the estimated useful lives of its fixed assets on an ongoing basis. In the first quarter of 2016, this review indicated that the actual lives of certain assets at wind power stations are expected to be longer than the previously estimated useful lives used for depreciation purposes. As a result, effective January 1, 2016, Renewables changed the estimates of the useful lives of certain assets from 25 years to 40 years to better reflect the estimated periods during which these assets are expected to remain in service. The weighted average useful life of our wind farm assets is now approximately 31 years. The effect of this change in estimate was to reduce depreciation and amortization expense by approximately $17 million, reduce asset retirement obligation accretion expense recorded within operations and maintenance by approximately $1 million, increase earnings from equity method investments by approximately $1 million, increase net income by $13 million and increase basic and diluted earnings per share by approximately $0.04 for the three months ended March 31, 2016. For the full year 2016, the effect of this change on income before income tax and net income is estimated to be an increase of approximately $75 million and approximately $46 million, respectively, and the impact on earnings per share is estimated to be an increase of approximately $0.15 per share on a basic and diluted basis
.
Note 3. Significant Accounting Policies and New Accounting Pronouncements
As of March 31, 2016 there have been no material changes to any significant accounting policies described in our combined and consolidated financial statements as of December 31, 2015 and 2014 and for the three years ended December 31, 2015. There have been no new accounting pronouncements issued since the filing of the combined and consolidated financial statements as of
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
December 31, 20
15 and 2014 and for the three years ended December 31, 2015, that we expect to have a material effect on our condensed consolidated interim financial statements.
Note 4. Acquisition of UIL
On December 16, 2015 (acquisition date) we completed our acquisition of UIL, a diversified energy company with its portfolio of regulated utility companies in Connecticut and Massachusetts that is expected to provide us with a greater flexibility to grow the combined regulated businesses through project development and create an enhanced platform to develop transmission and distribution projects in the Northeastern United States. In connection with the acquisition we issued 309,490,839 shares of common stock of AVANGRID, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share and 57,255,850 shares (including those held in trust as Treasury Stock) were issued to UIL shareowners in addition to payment of $595 million in cash. Following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID, and Iberdrola owned the remaining shares.
The acquisition was accounted for as a business combination. This method requires, among other things, that assets acquired and liabilities assumed in a business combination, with certain exceptions, be recognized at their fair values as of the acquisition date.
As UIL’s common stock was publicly traded in an active market until the acquisition date, we determined that UIL’s common stock is more reliably measurable than the common stock of AVANGRID to determine the fair value of the consideration transferred in the transaction.
The purchase consideration for UIL under the acquisition method is based on the stock price of UIL on the acquisition date multiplied by the number of shares issued by AVANGRID to the UIL shareowners after applying an equity exchange factor to the shares of vested restricted common stock of UIL (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other shares awards under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan. The “equity exchange factor” is the sum of one plus a fraction, (i) the numerator of which is the cash consideration and (ii) the denominator of which is the average of the volume weighted averages of the trading prices of UIL common stock on each of the ten consecutive trading days ending on (and including) the trading day that immediately precedes the closing date of the acquisition minus $10.50. The determination of the purchase price is based on a UIL stock price of $50.10 per share, which represents the closing stock price on the acquisition date.
11
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
The fair value of AVANGRID common stock issued to the UIL shareowners in the business combination represents the purchase consideration in the business combination, which was computed as follows:
|
|
|
(millions, except
share and unit data)
|
|
|
Common shares
(1)
|
|
|
56,629,377
|
|
|
Price per share of UIL common stock as of the
acquisition date
|
|
$
|
50.10
|
|
|
Subtotal value of common shares
|
|
$
|
2,837
|
|
|
Restricted stock units
(2)
|
|
|
476,198
|
|
|
Other shares
(3)
|
|
|
12,999
|
|
|
Equity exchange factor
|
|
|
1.2806
|
|
|
Total restricted and other shares(3) after applying
an equity exchange factor
|
|
|
626,473
|
|
|
Price per share used
(5)
|
|
$
|
39.60
|
|
|
Subtotal value of restricted and other shares
|
|
$
|
25
|
|
|
Total shares of AVANGRID common stock issued to UIL
shareowners (including held in trust as Treasury Stock)
|
|
|
57,255,850
|
|
|
Performance shares
(4)
|
|
|
211,904
|
|
|
Equity exchange factor
|
|
|
1.2806
|
|
|
Total performance shares after applying an equity
exchange factor
|
|
|
271,368
|
|
|
Price per share used
(5)
|
|
$
|
39.60
|
|
|
Subtotal value of performance shares
|
|
$
|
11
|
|
|
Total consideration
|
|
$
|
2,873
|
|
|
(1)
|
Based on UIL’s common shares outstanding on December 16, 2015
|
|
(2)
|
Based on UIL’s shares of vested restricted stock.
|
|
(3)
|
Based on UIL’s restricted shares vested upon the change in control.
|
|
(4)
|
Based on UIL’s vested performance shares award.
|
|
(5)
|
Based on the closing share price of UIL common stock on December 16, 2015 less the cash component of $10.50, which is not applicable to restricted shares (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other awards under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan.
|
The following is a summary of the components of the consideration transferred to UIL’s shareowners:
|
|
|
(millions, except
share data)
|
|
|
Cash ($10.50 x number of UIL common shares
outstanding at the acquisition date - 56,629,377)
|
|
$
|
595
|
|
|
Equity
|
|
|
2,278
|
|
|
Total consideration
|
|
$
|
2,873
|
|
UIL’s financial results have been included in our consolidated financial results for the periods subsequent to the December 16, 2015 acquisition date. The following table represents summarized unaudited pro forma financial information as if UIL had been included in our financial results for the three months ended March 31, 2015. The unaudited pro forma results include: (i) elimination of accrued transaction costs representing non-recurring expenses directly related to the transaction, and (ii) the associated tax impact on this unaudited pro forma adjustment.
The unaudited pro forma results do not reflect any cost saving synergies from operating efficiencies or the effect of the incremental costs incurred in integrating the two companies. Accordingly, these unaudited pro forma results are presented for informational
12
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
purpose only and are not necessarily indicative of what the actual results of operations of the combined company
would have been if the acquisition had occurred at the beginning of the period presented, nor are they indicative of future results of operations:
|
|
|
Three Months Ended
March 31, 2015
|
|
|
|
|
(millions)
|
|
|
Revenue
|
|
$
|
1,811
|
|
|
Net income
|
|
$
|
172
|
|
The fair value of assets acquired and liabilities assumed from our acquisition of UIL was based on a preliminary valuation and our estimates and assumptions are subject to change within the measurement period. For the majority of UIL’s assets and liabilities, primarily property, plant and equipment, fair value was determined to be the respective carrying amounts of the predecessor entity. UIL’s operations are conducted in a regulated environment where the regulatory authority allows an approved rate of return on the carrying amount of the regulated asset base. The primary areas of the purchase price that are not yet finalized include, but are not limited to contracts, equity method investments, provisions, contingent liabilities related to certain environmental sites, income taxes and goodwill. We will finalize these amounts no later than December 16, 2016. Under U.S. GAAP, the measurement period shall not exceed one year from the acquisition date. Measurement period adjustments that we determine to be material will be recognized in future periods in our consolidated financial statements.
The following is a summary of the preliminary allocation of the purchase price as of the acquisition date:
|
|
|
(millions)
|
|
|
Current assets, including cash of $48 million
|
|
$
|
500
|
|
|
Other investments
|
|
|
114
|
|
|
Property, plant and equipment, net
|
|
|
3,552
|
|
|
Regulatory assets
|
|
|
966
|
|
|
Other assets
|
|
|
52
|
|
|
Current liabilities
|
|
|
(493
|
)
|
|
Regulatory liabilities
|
|
|
(493
|
)
|
|
Non-current debt
|
|
|
(1,878
|
)
|
|
Other liabilities
|
|
|
(1,201
|
)
|
|
Total net assets acquired at fair value
|
|
|
1,119
|
|
|
Goodwill – consideration transferred in excess of fair
value assigned
|
|
|
1,754
|
|
|
Total estimated consideration
|
|
$
|
2,873
|
|
Goodwill generated from the acquisition of UIL has been assigned to the reporting units under the Networks reportable segment and is primarily attributable to expected future growth of the combined regulated businesses and enhanced platform to develop transmission and distribution projects in the Northeastern United States. The goodwill generated from this acquisition is not deductible for tax purposes. As part of the preliminary allocation of the purchase price we have determined a fair value of contingent liabilities of approximately $44.0 million relating to certain environmental sites.
Note 5. Regulatory Assets and Liabilities
Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific order we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. Substantially all assets or liabilities for which funds have been expended or received are either included in the rate base or are accruing a carrying cost until they will be included in the rate base. The primary items that are not included in the rate base or accruing carrying costs are the regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses, debt premium, environmental remediation costs which is primarily the
13
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
offset of accrued liabilities for future spending, unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded
,
asset retirement obligations, hedge losses and contracts f
or differences. The total amount of these items is $2,823 million.
Regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment.
Most of the items related to New York State Electric and Gas Corporation (NYSEG) have been addressed in the Joint Proposal (Proposal) filed with the New York State Public Service Commission (NYPSC) on February 19, 2016 in connection with a three-year rate plan for electric and gas service at NYSEG and Rochester Gas and Electric Corporation (RGE) commencing May 1, 2016. If the Proposal is approved, most of these items would be amortized over a five-year period, except the portion of storm costs to be recovered over ten years, plant related tax items which will be amortized over the life of associated plant and unfunded deferred taxes which will be amortized over fifty years. Annual amortization expense for NYSEG would be approximately $16.5 million per rate year. RGE items that would begin to be amortized are plant related taxes and unfunded deferred taxes. A majority of the other items related to RGE, which net to a regulatory liability, will remain deferred and will not be amortized until future proceedings or will be used to recover costs of the Ginna Reliability Support Services Agreement (Ginna RSSA).
Current and non-current regulatory assets as of March 31, 2016 and December 31, 2015 consisted of:
|
As of
|
|
March 31,
2016
|
|
|
December 31,
2015
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
Pension and other postretirement benefits cost deferrals
|
|
$
|
3
|
|
|
$
|
8
|
|
|
Pension and other postretirement benefits
|
|
|
6
|
|
|
|
13
|
|
|
Storm costs
|
|
|
4
|
|
|
|
8
|
|
|
Temporary supplemental assessment surcharge
|
|
|
6
|
|
|
|
7
|
|
|
Hedges losses
|
|
|
28
|
|
|
|
37
|
|
|
Contracts for differences
|
|
|
18
|
|
|
|
18
|
|
|
Hardship programs
|
|
|
13
|
|
|
|
13
|
|
|
Deferred purchased gas
|
|
|
6
|
|
|
|
12
|
|
|
Deferred transmission expense
|
|
|
18
|
|
|
|
12
|
|
|
Environmental remediation costs
|
|
|
38
|
|
|
|
37
|
|
|
Other
|
|
|
63
|
|
|
|
54
|
|
|
Total Current Regulatory Assets
|
|
|
203
|
|
|
|
219
|
|
|
Non-current
|
|
|
|
|
|
|
|
|
|
Pension and other postretirement benefits cost deferrals
|
|
|
164
|
|
|
|
151
|
|
|
Pension and other postretirement benefits
|
|
|
1,484
|
|
|
|
1,509
|
|
|
Storm costs
|
|
|
254
|
|
|
|
251
|
|
|
Deferred meter replacement costs
|
|
|
32
|
|
|
|
34
|
|
|
Unamortized losses on reacquired debt
|
|
|
22
|
|
|
|
23
|
|
|
Environmental remediation costs
|
|
|
257
|
|
|
|
271
|
|
|
Unfunded future income taxes
|
|
|
532
|
|
|
|
549
|
|
|
Asset retirement obligation
|
|
|
22
|
|
|
|
24
|
|
|
Deferred property tax
|
|
|
50
|
|
|
|
45
|
|
|
Federal tax depreciation normalization adjustment
|
|
|
166
|
|
|
|
158
|
|
|
Merger capital expense target customer credit
|
|
|
15
|
|
|
|
15
|
|
|
Debt premium
|
|
|
135
|
|
|
|
141
|
|
|
Contracts for differences
|
|
|
73
|
|
|
|
50
|
|
|
Hardship programs
|
|
|
25
|
|
|
|
29
|
|
|
Other
|
|
|
75
|
|
|
|
64
|
|
|
Total Non-current Regulatory Assets
|
|
$
|
3,306
|
|
|
$
|
3,314
|
|
14
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
“Pension and other postretirement benefits” represent the actuarial losses on the pension and other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. The recovery of these amounts will be determined in future proceedings.
“Storm costs” for Central Maine Power (CMP), NYSEG and RGE are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration.
“Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters.
“Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt.
“Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates.
“Asset retirement obligations” (ARO) represent the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.
“Deferred property taxes” represents the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The amortization period is awaiting a future NYPSC rate proceeding.
“Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rates years covering 2011 forward. The recovery period will be determined in future NYPSC and Maine Public Utility Commission (MPUC) rate proceedings.
“Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.
“Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates.
“Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base.
“Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability.
“Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized over the remaining term of the related outstanding debt instruments.
“Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements.
15
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
Current and non-current regulatory liabilities as of March 31, 2016 and December 31, 2015 consisted of:
|
As of
|
|
March 31,
2016
|
|
|
December 31,
2015
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
Reliability support services (Cayuga)
|
|
$
|
14
|
|
|
$
|
16
|
|
|
Non by-passable charges
|
|
|
6
|
|
|
|
7
|
|
|
Energy efficiency portfolio standard
|
|
|
32
|
|
|
|
33
|
|
|
Gas supply charge and deferred natural gas cost
|
|
|
16
|
|
|
|
6
|
|
|
Transmission revenue reconciliation mechanism
|
|
|
12
|
|
|
|
16
|
|
|
Yankee DOE Refund
|
|
|
—
|
|
|
|
5
|
|
|
Merger related rate credits
|
|
|
—
|
|
|
|
20
|
|
|
Revenue decoupling mechanism
|
|
|
21
|
|
|
|
14
|
|
|
Other
|
|
|
26
|
|
|
|
30
|
|
|
Total Current Regulatory Liabilities
|
|
|
127
|
|
|
|
147
|
|
|
Non-current
|
|
|
|
|
|
|
|
|
|
Accrued removal obligations
|
|
|
1,096
|
|
|
|
1,084
|
|
|
Asset sale gain account
|
|
|
9
|
|
|
|
8
|
|
|
Carrying costs on deferred income tax bonus depreciation
|
|
|
124
|
|
|
|
116
|
|
|
Economic development
|
|
|
39
|
|
|
|
36
|
|
|
Merger capital expense target customer credit account
|
|
|
17
|
|
|
|
17
|
|
|
Pension and other postretirement benefits
|
|
|
94
|
|
|
|
90
|
|
|
Positive benefit adjustment
|
|
|
49
|
|
|
|
51
|
|
|
New York state tax rate change
|
|
|
17
|
|
|
|
17
|
|
|
Post term amortization
|
|
|
3
|
|
|
|
25
|
|
|
Theoretical reserve flow thru impact
|
|
|
33
|
|
|
|
31
|
|
|
Deferred property tax
|
|
|
16
|
|
|
|
15
|
|
|
Net plant reconciliation
|
|
|
10
|
|
|
|
10
|
|
|
Variable rate debt
|
|
|
33
|
|
|
|
32
|
|
|
Carrying costs on deferred income tax - Mixed Services
263(a)
|
|
|
33
|
|
|
|
31
|
|
|
Rate refund – FERC ROE proceeding
|
|
|
21
|
|
|
|
21
|
|
|
Merger related rate credits
|
|
|
24
|
|
|
|
24
|
|
|
Accumulated deferred investment tax credits
|
|
|
10
|
|
|
|
10
|
|
|
Asset retirement obligation
|
|
|
13
|
|
|
|
13
|
|
|
Middletown/Norwalk local transmission network service collections
|
|
|
20
|
|
|
|
19
|
|
|
Excess generation service charge
|
|
|
1
|
|
|
|
21
|
|
|
Low income programs
|
|
|
45
|
|
|
|
42
|
|
|
Unfunded future income taxes
|
|
|
—
|
|
|
|
27
|
|
|
Non-firm margin sharing credits
|
|
|
11
|
|
|
|
8
|
|
|
Deferred income taxes regulatory
|
|
|
551
|
|
|
|
519
|
|
|
Other
|
|
|
89
|
|
|
|
93
|
|
|
Total Non-current Regulatory Liabilities
|
|
$
|
2,358
|
|
|
$
|
2,360
|
|
“Reliability support services (Cayuga)” represents the difference between actual expenses for reliability support services and the amount provided for in rates. This will be refunded to customers within the next year.
“Non by-passable charges” represent the non by-passable charge paid by all customers. An asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered. This liability will be refunded to customers within the next year.
16
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
“Energy efficiency portfolio standard” represents the difference
between revenue billed to customers through an energy efficiency charge and the costs of our energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year.
“Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant.
“Asset sale gain account” represents the gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station. The net proceeds from the Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is included in the pending Proposal before the NYPSC.
“Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. The amortization period is included in the pending Proposal before the NYPSC.
“Economic development” represents the economic development program which enables NYSEG and RGE to foster economic development through attraction, expansion, and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RGE varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is included in the pending Proposal before the NYPSC.
“Merger capital expense target customer credit” account was created as a result of NYSEG and RGE not meeting certain capital expenditure requirements established in the order approving the purchase of Energy East by Iberdrola. The amortization period is included in the pending Proposal before the NYPSC.
“Pension and other postretirement benefits” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future expenses. Because no funds have yet been received for this a regulatory liability is not reflected within rate base. They also represent the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these amounts will be determined in future proceedings.
“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of Energy East. This is being used to moderate increases in rates. The amortization period is included in the pending Proposal before the NYPSC and included in the Ginna RSSA settlement.
“New York state tax rate change” represents excess funded accumulated deferred income tax balance caused by the 2014 New York state tax rate change from 7.1% to 6.5%. The amortization period is included in the pending Proposal before the NYPSC.
“Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is included in the pending Proposal before the NYPSC.
“Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. The amortization period is included in the pending Proposal before the NYPSC.
“Merger related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In the three month period ended March 31, 2016 $20 million of rate credits was applied against customer bills.
“Excess generation service charge” represents deferred generation-related and non by-passable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.
“Low Income Programs” represent various hardship and payment plan programs approved for recovery.
“Other” includes cost of removal being amortized through rates and various items subject to reconciliation including variable rate debt, Medicare subsidy benefits and stray voltage collections.
17
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
Note 6. Fair Value of Financial Instrument
s and Fair Value Measurements
We determine the fair value of our derivative assets and liabilities and available for sale non-current investments associated with Networks’ activities utilizing market approach valuation techniques:
|
·
|
We measure the fair value of our noncurrent investments using quoted market prices in active markets for identical assets and include the measurements in Level 1. The available for sale investments, which are Rabbi Trusts for deferred compensation plans, primarily consist of money market funds and are included in Level 1 fair value measurement.
|
|
·
|
NYSEG and RGE enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the New York Independent System Operator (NYISO). RGE hedges all its electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value RGE’s open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1. NYSEG has a combination of Level 1 and Level 2 fair values for its electric energy derivative contracts. A portion of its electric load obligations are exchange traded contracts in a NYISO location where an active market exists. The forward market prices used to value NYSEG’s open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1. A portion of NYSEG’s electric energy derivative contracts are non-exchange traded contracts that are valued using inputs that are directly observable for the asset or liability, or indirectly observable through corroboration with observable market data and therefore we include the fair value in Level 2.
|
|
·
|
NYSEG and RGE enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange (NYMEX). Because we use prices quoted in an active market we include the fair value measurements in Level 1.
|
|
·
|
NYSEG, RGE and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used but because an unobservable basis adjustment is added to the forward prices we include the fair value measurement for these contracts in Level 3.
|
|
·
|
Contracts for differences (CfDs) entered into by The United Illuminating Company (UI) are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion on CfDs).
|
We determine the fair value of our derivative assets and liabilities associated with Renewables and Gas activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical product with no adjustment are included in the Level 1 fair value. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed price physical and basis and index trades are included in Level 2 fair value. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in Level 3 fair value. The unobservable inputs include historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists.
18
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
The financial instruments measured at fair value as of March 31, 2016 and December 31, 2015 consisted of:
|
As of March 31, 2016
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Netting
|
|
|
Total
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Securities portfolio (available for sale)
|
|
$
|
43
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
43
|
|
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - power
|
|
10
|
|
|
97
|
|
|
49
|
|
|
|
(84
|
)
|
|
72
|
|
|
Derivative financial instruments - gas
|
|
151
|
|
|
24
|
|
|
63
|
|
|
|
(165
|
)
|
|
73
|
|
|
Contracts for differences (CfDs)
|
|
|
—
|
|
|
|
—
|
|
|
26
|
|
|
|
—
|
|
|
26
|
|
|
Total
|
|
161
|
|
|
121
|
|
|
138
|
|
|
|
(249
|
)
|
|
171
|
|
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - power
|
|
|
(44
|
)
|
|
|
(22
|
)
|
|
|
(16
|
)
|
|
|
65
|
|
|
|
(17
|
)
|
|
Derivative financial instruments - gas
|
|
|
(159
|
)
|
|
|
(38
|
)
|
|
|
(47
|
)
|
|
|
185
|
|
|
|
(59
|
)
|
|
Contracts for differences (CfDs)
|
|
|
—
|
|
|
|
—
|
|
|
|
(118
|
)
|
|
|
—
|
|
|
|
(118
|
)
|
|
Derivative financial instruments - other
|
|
|
—
|
|
|
|
—
|
|
|
|
(2
|
)
|
|
|
—
|
|
|
|
(2
|
)
|
|
Total
|
|
$
|
(203
|
)
|
|
$
|
(60
|
)
|
|
$
|
(183
|
)
|
|
$
|
250
|
|
|
$
|
(196
|
)
|
|
As of December 31, 2015
|
|
Level 1
|
|
|
Level 2
|
|
|
Level 3
|
|
|
Netting
|
|
|
Total
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Securities portfolio (available for sale)
|
|
$
|
39
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
39
|
|
|
Derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - power
|
|
|
10
|
|
|
|
81
|
|
|
|
48
|
|
|
|
(71
|
)
|
|
|
68
|
|
|
Derivative financial instruments - gas
|
|
|
267
|
|
|
|
25
|
|
|
|
68
|
|
|
|
(280
|
)
|
|
|
80
|
|
|
Contracts for differences (CfDs)
|
|
|
—
|
|
|
|
—
|
|
|
|
29
|
|
|
|
—
|
|
|
|
29
|
|
|
Total
|
|
|
277
|
|
|
|
106
|
|
|
|
145
|
|
|
|
(351
|
)
|
|
|
177
|
|
|
Derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative financial instruments - power
|
|
|
(43
|
)
|
|
|
(12
|
)
|
|
|
(14
|
)
|
|
|
55
|
|
|
|
(14
|
)
|
|
Derivative financial instruments - gas
|
|
|
(193
|
)
|
|
|
(40
|
)
|
|
|
(51
|
)
|
|
|
212
|
|
|
|
(72
|
)
|
|
Contracts for differences (CfDs)
|
|
|
—
|
|
|
|
—
|
|
|
|
(96
|
)
|
|
|
—
|
|
|
|
(96
|
)
|
|
Derivative financial instruments - other
|
|
|
—
|
|
|
|
—
|
|
|
|
(3
|
)
|
|
|
—
|
|
|
|
(3
|
)
|
|
Total
|
|
$
|
(236
|
)
|
|
$
|
(52
|
)
|
|
$
|
(164
|
)
|
|
$
|
267
|
|
|
$
|
(185
|
)
|
19
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2016 and 2
015 is as follows:
|
|
|
Three Months Ended
March 31,
|
|
|
(Millions)
|
|
2016
|
|
|
2015
|
|
|
Fair Value Beginning of Period,
|
|
$
|
(19
|
)
|
|
$
|
57
|
|
|
Gains recognized in operating revenues
|
|
|
9
|
|
|
|
11
|
|
|
(Losses) recognized in operating revenues
|
|
|
(6
|
)
|
|
|
(1
|
)
|
|
Total gains (losses) recognized in operating revenues
|
|
|
3
|
|
|
|
10
|
|
|
Gains recognized in OCI
|
|
|
1
|
|
|
|
1
|
|
|
(Losses) recognized in OCI
|
|
|
—
|
|
|
|
(1
|
)
|
|
Total Gains (Losses) Recognized in OCI
|
|
|
1
|
|
|
|
—
|
|
|
Net change recognized in regulatory assets and liabilities
|
|
|
(25
|
)
|
|
|
—
|
|
|
Purchases
|
|
|
—
|
|
|
|
(1
|
)
|
|
Settlements
|
|
|
(5
|
)
|
|
|
(3
|
)
|
|
Transfers out of Level 3(a)
|
|
|
—
|
|
|
|
(9
|
)
|
|
Fair Value as of March 31,
|
|
$
|
(45
|
)
|
|
$
|
54
|
|
|
Gains (losses) for the period included in operating revenues
attributable to the change in unrealized gains (losses)
relating to financial instruments still held at the reporting
date
|
|
$
|
3
|
|
|
$
|
10
|
|
(a)
Transfers out of Level 3 were the result of increased
observability of market data.
For assets and liabilities that are recognized in the condensed consolidated financial statements at fair value on a recurring basis, we determine whether transfers have occurred between levels in the hierarchy by re-assessing categorization based on the lowest level of input that is significant to the fair value measurement as a whole at the end of each reporting period. There have been no transfers between Level 1 and Level 2 during the periods reported.
Level 3 Fair Value Measurement
The tables below illustrate the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives. They represent the variability in prices for those transactions that fall into the illiquid period (beyond 2 years), using past and current views of prices for those future periods.
|
As of March 31, 2016
|
|
|
|
|
|
|
|
|
|
Variability
|
|
|
Instruments
|
|
Instrument
Description
|
|
Valuation
Technique
|
|
Valuation
Inputs
|
|
Index
|
|
Avg.
|
|
|
Max.
|
|
|
Min.
|
|
|
Fixed price power
and gas swaps
|
|
Transactions
with
delivery
periods
|
|
Transactions
are
valued
against
forward
market
prices
|
|
Observable
and
extrapolated
forward
gas
and
power
prices
not
all
of
which
can
be
|
|
NYMEX
($/MMBtu)
|
|
$
|
4.23
|
|
|
$
|
7.37
|
|
|
$
|
1.48
|
|
|
with delivery
|
|
exceeding two
|
|
on a
|
|
corroborated by
|
|
SP15
($/MWh)
|
|
$
|
43.91
|
|
|
$
|
80.28
|
|
|
$
|
13.15
|
|
|
period > two
|
|
years
|
|
discounted
|
|
market data for
|
|
Mid C
($/MWh)
|
|
$
|
35.13
|
|
|
$
|
83.93
|
|
|
$
|
4.10
|
|
|
years
|
|
|
|
basis
|
|
identical or
|
|
Cinergy
($/MWh)
|
|
$
|
36.23
|
|
|
$
|
77.49
|
|
|
$
|
18.53
|
|
|
|
|
|
|
|
|
similar
products
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2017. The gas swaps are used to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are traded at liquid hubs in the West and Midwest and are used to hedge merchant wind production in those regions.
20
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
We performed a sensitivity analysis around the Level 3 gas and power posi
tions to changes in the valuation inputs and concluded that no material change to the financial statements is expected given the following: (i) any changes in the fair value of the gas swaps hedging inventory would be expected to be largely offset by chang
es in the value of the inventory; (ii) any changes in the fair value of the gas swaps hedging merchant generation would be expected to be significantly offset by changes in the value of future power generation.
Future commodity prices are the significant unobservable inputs to fair value. Any significant increases in prices would result in a lower fair value of derivatives. Conversely, significant reductions in prices would result in a higher fair value of derivatives.
Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in calculation of market value and the models themselves. Authorized trading points and associated forward price curves are maintained and documented by the Middle Office. Models used in valuation of the various products are developed and documented by the Structuring and Market Analysis group.
Transaction models are valued in part on the basis of forward price, correlation, and volatility curves. Descriptions of these curves and their derivations are maintained and documented by the Structuring and Market Analysis group. Forward price curves used in valuing the models are applied to the full duration of transactional models to a maximum of approximately thirty years.
The carrying amounts for cash and cash equivalents, accounts receivable, accounts payable, notes payable and interest accrued approximate their estimated fair values and are considered as Level 1.
The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extended over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows:
|
Unobservable Input
|
|
Range at
March 31,
2016
|
|
Risk of non-performance
|
|
0.02% - 0.79%
|
|
Discount rate
|
|
0.87% - 1.78%
|
|
Forward pricing ($ per MW)
|
|
$3.15 - $9.55
|
Fair Value of Debt
As of March 31, 2016 and December 31, 2015 debt consisted of first mortgage bonds, fixed and variable unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt amounted to $5,100 million and $4,985 million as of March 31, 2016 and December 31, 2015, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value hierarchy pertaining to the fair value of debt is considered as Level 2, except for unsecured pollution control notes-variable with a fair value of $204 million as of both March 31, 2016 and December 31, 2015, which are considered Level 3. The fair value of these unsecured pollution control notes-variable are determined using unobservable interest rates as the market for these notes is inactive.
Note 7. Derivative Instruments and Hedging
Our Networks (including UIL), Renewables and Gas activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on the condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities.
21
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
(a) Networks activities
NYSEG and RGE have an electric commodity charge that passes through rates costs for the market price of electricity. They use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and / or liabilities with an offset to regulatory assets and / or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations.
The amount recognized in regulatory assets for electricity derivatives was a gain of $34.6 million as of March 31, 2016, and a loss of $34.3 million as of December 31, 2015. The amount reclassified from regulatory assets and liabilities into income, which is included in electricity purchased, was a loss of $34.8 million and $2.6 million for the three months ended March 31, 2016 and 2015, respectively.
NYSEG and RGE have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. NYSEG and RGE use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and / or liabilities with an offset to regulatory assets and / or regulatory liabilities in accordance with the accounting requirements for regulated operations.
The amount recognized in regulatory assets for natural gas hedges was a gain of $0.2 million as of March 31, 2016, and a loss of $3.1 million as of December 31, 2015. The amount reclassified from regulatory assets into income, which is included in natural gas purchased, was a loss of $3.4 million and $1.6 million for the three months ended March 31, 2016 and 2015, respectively.
Contracts for Differences (CfDs)
Pursuant to Connecticut statute and requirements of the Connecticut Public Utilities Regulatory Authority (PURA), UI and Connecticut’s other electric utility, The Connecticut Light and Power Company (CL&P), each executed two long-term contracts for differences (CfDs) with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers.
PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability). For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of March 31, 2016 UI has recorded a gross derivative asset of $26 million ($0.2 million of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $91 million, a gross derivative liability of $118 million ($85 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $1 million. As of December 31, 2015, UI had recorded a gross derivative asset of $29 million ($1 million of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $68 million, a gross derivative liability of $96 million ($61 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $1 million.
The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the three months ended March 31, 2016, were as follows:
|
Three Months Ended March 31,
|
|
2016
|
|
|
(Millions)
|
|
|
|
|
|
Regulatory Assets - Derivative liabilities
|
|
$
|
(3
|
)
|
|
Regulatory Liabilities - Derivative assets
|
|
$
|
(22
|
)
|
22
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
The net notional volumes of the outstanding derivative instruments
associated with Networks activities as of March 31, 2016 and December 31, 2015 consisted of:
|
As of
|
|
March 31,
2016
|
|
|
December 31,
2015
|
|
(Millions)
|
|
|
|
|
|
|
|
Wholesale electricity purchase contracts (MWh)
|
|
|
7.0
|
|
|
6.7
|
|
Natural gas purchase contracts (Dth)
|
|
|
5.1
|
|
|
4.8
|
|
Fleet fuel purchase contracts (Gallons)
|
|
|
3.4
|
|
|
3.8
|
The offsetting of derivatives, location and amounts of derivatives designated as hedging instruments associated with Networks (including UIL) activities as of March 31, 2016 and December 31, 2015 consisted of:
|
As of March 31, 2016
|
|
Current
Assets
|
|
|
Noncurrent
Assets
|
|
|
Current
Liabilities
|
|
|
Noncurrent
Liabilities
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
$
|
11
|
|
|
$
|
16
|
|
|
$
|
(29
|
)
|
|
$
|
(89
|
)
|
|
Derivative liabilities
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
11
|
|
|
|
16
|
|
|
|
(29
|
)
|
|
|
(89
|
)
|
|
Designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
|
6
|
|
|
|
4
|
|
|
|
6
|
|
|
|
4
|
|
|
Derivative liabilities
|
|
|
(6
|
)
|
|
|
(4
|
)
|
|
|
(35
|
)
|
|
|
(12
|
)
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(29
|
)
|
|
|
(8
|
)
|
|
Total derivatives before offset of cash collateral
|
|
|
11
|
|
|
|
16
|
|
|
|
(58
|
)
|
|
|
(97
|
)
|
|
Cash collateral receivable (payable)
|
|
|
—
|
|
|
|
—
|
|
|
|
28
|
|
|
|
7
|
|
|
Total derivatives as presented in the balance sheet
|
|
$
|
11
|
|
|
$
|
16
|
|
|
$
|
(30
|
)
|
|
$
|
(90
|
)
|
|
As of December 31, 2015
|
|
Current
Assets
|
|
|
Noncurrent
Assets
|
|
|
Current
Liabilities
|
|
|
Noncurrent
Liabilities
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
$
|
11
|
|
|
$
|
18
|
|
|
$
|
(28
|
)
|
|
$
|
(68
|
)
|
|
Derivative liabilities
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
11
|
|
|
|
18
|
|
|
|
(28
|
)
|
|
|
(68
|
)
|
|
Designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
|
3
|
|
|
|
6
|
|
|
|
3
|
|
|
|
6
|
|
|
Derivative liabilities
|
|
|
(3
|
)
|
|
|
(6
|
)
|
|
|
(42
|
)
|
|
|
(7
|
)
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(39
|
)
|
|
|
(1
|
)
|
|
Total derivatives before offset of cash collateral
|
|
|
11
|
|
|
|
18
|
|
|
|
(67
|
)
|
|
|
(69
|
)
|
|
Cash collateral receivable (payable)
|
|
|
—
|
|
|
|
—
|
|
|
|
37
|
|
|
|
—
|
|
|
Total derivatives as presented in the balance sheet
|
|
$
|
11
|
|
|
$
|
18
|
|
|
$
|
(30
|
)
|
|
$
|
(69
|
)
|
23
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
The effect of derivatives in cash
flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2016 and 2015 consisted of:
|
Three Months Ended March 31,
|
|
(Loss) Recognized
in OCI on Derivatives
|
|
|
Location of
(Loss) Reclassified
from Accumulated
OCI into Income
|
|
(Loss)
Reclassified
from Accumulated
OCI into Income
|
|
|
(Millions)
|
|
Effective Portion (a)
|
|
|
Effective Portion (a)
|
|
|
2016
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
$
|
—
|
|
|
Interest expense
|
|
$
|
(2
|
)
|
|
Commodity contracts
|
|
|
—
|
|
|
Operating expenses
|
|
|
(1
|
)
|
|
Total
|
|
$
|
—
|
|
|
|
|
$
|
(3
|
)
|
|
2015
|
|
|
|
|
|
|
|
|
|
|
|
Interest rate contracts
|
|
$
|
—
|
|
|
Interest expense
|
|
$
|
(2
|
)
|
|
Commodity contracts
|
|
|
(1
|
)
|
|
Operating expenses
|
|
|
(1
|
)
|
|
Total
|
|
$
|
(1
|
)
|
|
|
|
$
|
(3
|
)
|
(a)
Changes in OCI are reported on a pre-tax basis. The reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the condensed consolidated statements of income.
The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $82.9 million and $84.9 million as of March 31, 2016 and December 31, 2015, respectively. We recorded $2.0 million and $2.2 in net derivative losses related to discontinued cash flow hedges for the three months ended March 31, 2016 and 2015, respectively. We will amortize approximately $8.0 million of discontinued cash flow hedges in 2016. During the three months ended March 31, 2016 and 2015, there was no ineffective portion for cash flow hedges.
The unrealized loss of $2.3 million on hedge activities is reported in OCI because the forecasted transaction is considered to be probable as of March 31, 2016. We expect that $1.7 million of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twenty-one months.
(b) Renewables and Gas activities
We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities.
Our gas business purchases and sells both fixed-price gas and basis swaps to hedge the value of contracted storage positions. The intent of entering into these swaps is to fix the margin of gas injected into storage for subsequent resale in future periods. We also enter into basis swaps to hedge the value of our contracted transport positions. The intent of buying and selling these basis swaps is to fix the location differential between the price of gas at the receipt and delivery point of the contracted transport in future periods.
Both Renewables and Gas have proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets.
Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future power sales and gas purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and AECO basis swaps that hedge the fuel requirements of its Klamath facility. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms.
Gas also periodically designates NYMEX fixed price derivative contracts as cash flow hedges related to its firm storage trading activities. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future gas
24
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
sales and purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness i
s recorded in current period earnings. Derivative contracts entered into to hedge the gas transport trading activities are not designated as cash flow hedges, with all changes in fair value of such derivative contracts recorded in current period earnings.
The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of March 31, 2016 and December 31, 2015 consisted of:
|
As of
|
|
March 31,
2016
|
|
|
December 31,
2015
|
|
|
(MWh/Dth in millions)
|
|
|
|
|
|
|
|
|
|
Wholesale electricity purchase contracts
|
|
|
3
|
|
|
|
3
|
|
|
Wholesale electricity sales contracts
|
|
|
6
|
|
|
|
6
|
|
|
Foreign exchange forward purchase contracts
|
|
|
1
|
|
|
|
4
|
|
|
Natural gas and other fuel purchase contracts
|
|
|
280
|
|
|
|
332
|
|
|
Financial power contracts
|
|
|
5
|
|
|
|
7
|
|
|
Basis swaps – purchases
|
|
|
41
|
|
|
|
67
|
|
|
Basis swaps – sales
|
|
|
48
|
|
|
|
80
|
|
The fair values of derivative contracts associated with Renewables and Gas activities as of March 31, 2016 and December 31, 2015 consisted of:
|
As of
|
|
March 31,
2016
|
|
|
December 31,
2015
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
Wholesale electricity purchase contracts
|
|
$
|
(17
|
)
|
|
$
|
(13
|
)
|
|
Wholesale electricity sales contracts
|
|
|
39
|
|
|
|
35
|
|
|
Foreign exchange forward purchase contracts
|
|
|
1
|
|
|
|
(1
|
)
|
|
Natural gas and other fuel purchase contracts
|
|
|
19
|
|
|
|
10
|
|
|
Financial power contracts
|
|
|
32
|
|
|
|
32
|
|
|
Basis swaps – purchases
|
|
|
39
|
|
|
|
1
|
|
|
Basis swaps – sales
|
|
|
(45
|
)
|
|
|
(2
|
)
|
|
Total
|
|
$
|
68
|
|
|
$
|
62
|
|
The effect of trading and non-trading derivatives, respectively, associated with Renewables and Gas activities for the three months ended March 31, 2016 and 2015 consisted of:
|
Three Months Ended March 31,
|
|
2016
|
|
|
2015
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
Wholesale electricity purchase contracts
|
|
$
|
—
|
|
|
$
|
7
|
|
|
Wholesale electricity sales contracts
|
|
|
(1
|
)
|
|
|
(5
|
)
|
|
Financial power contracts
|
|
|
1
|
|
|
|
(1
|
)
|
|
Financial and natural gas contracts
|
|
|
(30
|
)
|
|
|
(55
|
)
|
|
Total Loss
|
|
$
|
(30
|
)
|
|
$
|
(54
|
)
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2016
|
|
|
2015
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
Wholesale electricity purchase contracts
|
|
$
|
(3
|
)
|
|
$
|
(1
|
)
|
|
Wholesale electricity sales contracts
|
|
|
6
|
|
|
|
(3
|
)
|
|
Financial power contracts
|
|
|
1
|
|
|
|
5
|
|
|
Financial and natural gas contracts
|
|
|
(9
|
)
|
|
|
6
|
|
|
Total (Loss) Gain
|
|
$
|
(5
|
)
|
|
$
|
7
|
|
Such gains and losses are included in revenues and in “Purchased power, natural gas and fuel used” operating expenses in the condensed consolidated statements of income, depending upon the nature of the transaction.
25
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
The offsetting of derivatives, location and amounts of derivatives designated as hedging instruments associated with Renewables and Gas activities as of March 31, 2016 and December 31, 2015 consisted of:
|
As of March 31, 2016
|
|
Current
Assets
|
|
|
Noncurrent
Assets
|
|
|
Current
Liabilities
|
|
|
Noncurrent
Liabilities
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
$
|
165
|
|
|
$
|
102
|
|
|
$
|
84
|
|
|
$
|
3
|
|
|
Derivative liabilities
|
|
|
(80
|
)
|
|
|
(11
|
)
|
|
|
(139
|
)
|
|
|
(33
|
)
|
|
|
|
|
85
|
|
|
|
91
|
|
|
|
(55
|
)
|
|
|
(30
|
)
|
|
Designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
|
24
|
|
|
|
6
|
|
|
|
—
|
|
|
|
—
|
|
|
Derivative liabilities
|
|
|
—
|
|
|
|
—
|
|
|
|
(18
|
)
|
|
|
(1
|
)
|
|
|
|
|
24
|
|
|
|
6
|
|
|
|
(18
|
)
|
|
|
(1
|
)
|
|
Total derivatives before offset of cash collateral
|
|
|
109
|
|
|
|
97
|
|
|
|
(73
|
)
|
|
|
(31
|
)
|
|
Cash collateral receivable (payable)
|
|
|
(26
|
)
|
|
|
(36
|
)
|
|
|
22
|
|
|
|
6
|
|
|
Total derivatives as presented in the balance sheet
|
|
$
|
83
|
|
|
$
|
61
|
|
|
$
|
(51
|
)
|
|
$
|
(25
|
)
|
|
As of December 31, 2015
|
|
Current
Assets
|
|
|
Noncurrent
Assets
|
|
|
Current
Liabilities
|
|
|
Noncurrent
Liabilities
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
$
|
186
|
|
|
$
|
113
|
|
|
$
|
117
|
|
|
$
|
4
|
|
|
Derivative liabilities
|
|
|
(85
|
)
|
|
|
(14
|
)
|
|
|
(169
|
)
|
|
|
(29
|
)
|
|
|
|
|
101
|
|
|
|
99
|
|
|
|
(52
|
)
|
|
|
(25
|
)
|
|
Designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative assets
|
|
|
56
|
|
|
|
13
|
|
|
|
—
|
|
|
|
—
|
|
|
Derivative liabilities
|
|
|
—
|
|
|
|
—
|
|
|
|
(9
|
)
|
|
|
—
|
|
|
|
|
|
56
|
|
|
|
13
|
|
|
|
(9
|
)
|
|
|
—
|
|
|
Total derivatives before offset of cash collateral
|
|
|
157
|
|
|
|
112
|
|
|
|
(61
|
)
|
|
|
(25
|
)
|
|
Cash collateral receivable (payable)
|
|
|
(80
|
)
|
|
|
(41
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Total derivatives as presented in the balance sheet
|
|
$
|
77
|
|
|
$
|
71
|
|
|
$
|
(61
|
)
|
|
$
|
(25
|
)
|
The effect of derivatives in cash flow hedging relationships on OCI and income for the three months ended March 31, 2016 and 2015 consisted of:
|
Three Months Ended March 31, 2016
|
|
Gain Recognized
in OCI on Derivatives
|
|
|
Location of
Gain Reclassified
from Accumulated
OCI into Income
|
|
Gain
Reclassified
from Accumulated
OCI into Income
|
|
|
(Millions)
|
|
Effective Portion (a)
|
|
|
Effective Portion (a)
|
|
|
Commodity contracts
|
|
$
|
3
|
|
|
Revenues
|
|
$
|
(46
|
)
|
|
Total
|
|
$
|
3
|
|
|
|
|
$
|
(46
|
)
|
(a)
Changes in OCI are reported on a pre-tax basis.
|
Three Months Ended March 31, 2015
|
|
Gain Recognized
in OCI on Derivatives
|
|
|
Location of
Gain Reclassified
from Accumulated
OCI into Income
|
|
Gain
Reclassified
from Accumulated
OCI into Income
|
|
|
(Millions)
|
|
Effective Portion (a)
|
|
|
Effective Portion (a)
|
|
|
Commodity contracts
|
|
$
|
1
|
|
|
Revenues
|
|
$
|
—
|
|
|
Total
|
|
$
|
1
|
|
|
|
|
$
|
—
|
|
|
|
(a)
|
Changes in OCI are reported on a pre-tax basis.
|
26
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
Amounts will be
reclassified from accumulated OCI into income in the period(s) during which the transaction being hedged affects earnings or when it becomes probable that a forecasted transaction being hedged would not occur. Notwithstanding future changes in prices, app
roximately $7.5 million of gains included in accumulated OCI at March 31, 2016 is expected to be reclassified into earnings within the next 12 months. During the three months ended March 31, 2016 and 2015 we recorded a net loss of $4.4 million and a net ga
in of $3.0 million, respectively, in earnings as a result of ineffectiveness from cash flow hedges.
(c) Counterparty credit risk management
NYSEG and RGE face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are dependent on the counterparty’s or the counterparty’s guarantor’s applicable credit rating, normally Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold.
The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit rating on senior debt were to fall below investment grade. If such an event had occurred as of March 31, 2016, UI would have had to post an aggregate of approximately $13.2 million in collateral.
We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. The amounts of cash collateral under master netting arrangements that have not been offset against net derivative positions were $14 million and $11 million as of March 31, 2016 and December 31, 2015, respectively. Derivate instruments settlements and collateral payments are included in “Other assets” and “Other liabilities” of operating activities in the condensed consolidated statements of cash flows.
Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of March 31, 2016 is $37 million, for which we have posted collateral.
Note 8. Contingencies
We are party to various legal disputes arising as part of our normal business activities. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency.
MNG Rate Case
On March 5, 2015, MNG filed a rate case in order to further recover future investments and provide safe and adequate service. MNG requested a 10.0% ROE and 50.0% equity ratio. The MPUC Staff has recommended a separate revenue requirement for MNG’s Augusta customers and MNG’s non-Augusta customers. The Staff also recommended a $19.95 million disallowance of the August Expansion investment based upon the Staff’s conclusion that MNG’s management of the Augusta Expansion Project was imprudent.
On November 6, 2015, a stipulation was filed with the MPUC, which was executed by MNG, the Office of Public Advocate and the City of Augusta. The stipulation contained a combined revenue requirement for Augusta and Non-Augusta based on a 9.55% ROE and 50% equity ratio. The stipulation also provided for an initial Augusta investment disallowance of $6 million and an investment phase-in of $10 million. On December 22, 2015, the MPUC rejected the proposed Stipulation as not in the public interest. In January 2016, the Administrative Law Judge established a new litigation schedule. The litigation was suspended at the end of January 2016 for settlement discussions.
27
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
On May 3, 2016, all active parties to the case filed a stipulation which sett
led all matters at issue in the case. Subject to MPUC approval of the stipulation, MNG’s new 10-year rate plan will take effect on June 1, 2016 and continue through April 30, 2026. The settlement structure for non-Augusta customers includes a 34.6% deliver
y revenue increase over five years with an allowed 9.55% ROE and 50% common equity ratio. The settlement structure for Augusta customers includes a 10-year rate plan with existing Augusta customers being charged rates equal to non-Augusta customers plus a
surcharge which increases annually for five years. New Augusta customers will have rates set based on an alternate fuel market model. In year seven of the rate plan MNG will submit a cost of service filing for the Augusta area to determine if the rate pla
n should continue. The cost of service filing will exclude $15 million of initial 2012/2013 gross plant investment. If the Augusta area’s cost of service filing illustrates results above a 14.55% ROE then the rate plan may cease, otherwise the rate plan wo
uld continue. We expect the MPUC to rule on the stipulation in May 2016
. We cannot predict the outcome of the proceeding. We reserved $6 million for this case at the end of 2015. The reserve remained unchanged at March 31, 2016.
Transmission - ROE Complaint – CMP and UI
On September 30, 2011, the Massachusetts Attorney General, Massachusetts Department of Public Utilities, Connecticut Public Utilities Regulatory Authority, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a complaint (Complaint I) with the FERC pursuant to sections 206 and 306 of the Federal Power Act. The filing parties seek an order from the FERC reducing the 11.14% base return on equity used in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) to a just and reasonable level of 9.2%. CMP and UI are New England Transmission Owners (NETOs) with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint.
On June 19, 2014, the FERC issued its initial decision in the first complaint, establishing a methodology and setting the issues for a paper hearing. On October 16, 2014, FERC issued its final decision in the first complaint (Complaint I) setting the base ROE at 10.57%, and a maximum total ROE of 11.74% for the October 2011 – December 2012 period and ordered the NETOs to file a refund report. On November 17, 2014 the NETOs filed a refund report.
On March 3, 2015, the FERC issued an order on requests for rehearing of its October 16, 2014 decision. The March order upheld the FERC’s initial decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average return. In June 2015 the NETOs filed an appeal in the U.S. Court of Appeals for the District of Columbia of the FERC’s final order. We cannot predict the outcome of this appeal.
On December 26, 2012, a second, related, complaint (Complaint II) for a subsequent rate period was filed requesting the ROE be reduced to 8.7%. On June 19, 2014, FERC accepted the second complaint, established a refund effective date of December 27, 2012, and set the matter for hearing using the methodology established in the first complaint.
On July 31, 2014, the Complainants filed a third, related, complaint (Complaint III) for a subsequent rate period requesting the ROE be reduced to 8.84%. On November 24, 2014, FERC accepted the third complaint, established a refund effective date of July 31, 2014, and set for consolidated hearing with Complaint II in June 2015. Hearings were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge, relating to the refund periods and going forward. On July 29, 2015, post-hearing briefs were filed by parties and on August 26, 2015 reply briefs were filed by parties. On July 13, 2015, the New England transmission owners filed a petition for review of FERC’s orders establishing hearing and consolidation procedures for Complaints II and III with the U.S. Court of Appeals. The Administrative Law Judge issued an Initial Decision on March 22, 2016. The Initial Decision determined that, 1) for the 15 month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and 2) for the 15 month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The Initial Decision is the Administrative Law Judge’s recommendation to the FERC Commissioners. The FERC is expected to make its final decision in late 2016 or early 2017.
CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 final Complaint I decision. The CMP and UI total reserve associated with Complaints I, II and III is $21.9 million and $4.2 million, respectively, as of March 31, 2016. If adopted as final, the impact of the initial decision would be an additional aggregate reserve for Complaints II and III of $10.2 million, net of tax, which is based upon currently available information for these proceedings. We cannot predict the outcome of Complaint II and III proceedings.
28
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
On
April 29, 2016, the Complainants filed a fourth, related, ROE complaint (Complaint IV) for a rate period subsequent to prior complaints requesting the base ROE be 8.61% and RO
E Cap be 11.24%. We cannot predict the outcome of the Complaint IV proceeding.
Yankee Nuclear Spent Fuel Disposal Claim
CMP has an ownership interest in Maine Yankee Atomic Power Company, Connecticut Yankee Atomic Power Company, and Yankee Atomic Electric Company, (the Yankee Companies), three New England single-unit decommissioned nuclear reactor sites, and UI has an ownership interest in Connecticut Yankee Atomic Power Company. Every six years, pursuant to the statute of limitations, the Yankee companies file a lawsuit to recover damages from the Department of Energy (DOE or Government) for breach of the Nuclear Spent Fuel Disposal Contract to remove Spent Nuclear Fuel (SNF) and Greater than Class C Waste (GTCC) as required by contract and the Nuclear Waste Policy Act beginning in 1998. The damages are the incremental costs for the Government’s failure to take the spent nuclear fuel.
In 2012, the U.S. Court of Appeals issued a favorable decision in the Yankee Companies’ claim for the first six year period (Phase I). Total damages awarded to the Yankee Companies were nearly $160 million. The Yankee Companies won on all appellate points in the U.S. Court of Appeals for the Federal Circuit’s unanimous decision. The Federal Appeals Court affirmed the September 2010 U.S. Court of Federal Claims award of $40.3 million to Connecticut Yankee Atomic Power Company; affirmed the Court of Federal Claims award of $65 million to Maine Yankee Atomic Power Company; and increased Yankee Atomic Electric Company’s damages award from $21.4 million to $37.8 million. The Phase I damage award became final on December 4, 2012. The Yankee Companies received payment from the DOE in January 2013. CMP’s share of the award was approximately $36.5 million which was credited back to customers. UI’s share of the award was $3.8 million which was credited back to customers.
In November 2013 the U.S. Court of Claims issued its decision in the Phase II case (the second 6-year period). The court’s decision awarded the Yankee Companies a combined $235.4 million (Connecticut Yankee $126.3 million, Maine Yankee $37.7 million, and Yankee Atomic $73.3 million). The Phase II period covers January 1, 2002 through December 31, 2008 for Connecticut Yankee and Yankee Atomic, and January 1, 2003 through December 31, 2008 for Maine Yankee. Maine Yankee’s damage award was lower because it recovered a larger amount in the Phase I case ($82 million) and its decommissioning was both less expensive and completed sooner than the other Yankee Companies. The damage awards flow through the Yankee Companies to shareholders (including CMP and UI) to reduce retail customer charges. In January 2014 the Government informed the Yankee Companies it would not appeal the court’s decision. As a result the Yankee Companies received full payment in April 2014. CMP’s share of the award was approximately $28.2 million which was credited back to customers. UI received approximately $12 million of such award which was applied, in part, against its remaining storm regulatory asset balance. The remaining regulatory liability balance was applied to UI’s generation service charge (GSC) “working capital allowance” and will be returned to customers through the non-by-passable federally mandated congestion charge.
In August 2013, the Yankee Companies filed a third round of claims against the Government seeking damages for the years 2009-2014 (Phase III). The Phase III trial was completed in July 2015 and the court issued its decision on March 25, 2016 awarding the Yankee Companies a combined $76.8 million (Connecticut Yankee $32.6 million, Maine Yankee $24.6 million and Yankee Atomic $19.6 million). The damage awards will potentially flow through the Yankee Companies to shareholders, including CMP and UI, upon FERC approval, and will reduce retail customer charges or otherwise as specified by law. CMP and UI will receive their proportionate share of the awards that flow through based on percentage ownership. We cannot predict the timing or amount of damage awards that may ultimately flow through to customers.
NYPSC Staff Review of Earnings Sharing Calculations and Other Regulatory Deferrals
In December 2012, the NYPSC Staff (Staff) informed NYSEG and RGE that the Staff had conducted an audit of the companies’ annual compliance filings (ACF) for 2009 through August 31, 2010, and the first rate year of the current rate plan, September 1, 2010 through August 31, 2011. The Staff’s preliminary findings indicated adjustments to deferred balances primarily associated with storm costs and the treatment of certain incentive compensation costs for purposes of the 2011 ACF. The Staff’s findings approximate $9.8 million of adjustments to deferral balances and customer earnings sharing accruals. NYSEG and RGE reviewed the Staff’s adjustments and work papers and provided a response in early 2013. NYSEG and RGE disagreed with certain Staff conclusions and as a result recorded a $3.4 million reserve in December 2012 in anticipation of settling the Staff issues. In the Proposal filed with the NYPSC (see Note 5) the parties agreed that in full and final resolution of all years through 2012, and in full and final resolution of storm-related deferrals through 2014, the companies will add $2.4 million to the customer share of earnings sharing.
29
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
California Energy
Crisis Litigation
Two California agencies brought a complaint against a long-term power purchase agreement entered into by Renewables as seller to the California Department of Water Resources as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed FERC's dismissal of Renewables.
Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014 FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC Trial Staff recommended that the complaint against Renewables be dismissed.
A hearing was held before an administrative law judge of FERC in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market contract that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that price of the power purchase agreements imposed an excessive burden on customers in the amount of $259 million. Renewables position, as presented at hearings and agreed by FERC Trial Staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties will have an opportunity to submit briefs to FERC before FERC issues its decision, expected in late 2016. We cannot predict the outcome of this proceeding.
Note 9. Environmental Liabilities
Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies.
Waste sites
The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-four waste sites, which do not include sites where gas was manufactured in the past. Fifteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; six sites are included in Maine’s Uncontrolled Sites Program and one site is included on the Massachusetts Non- Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, nine of the twenty-four sites are also included on the National Priorities list. Any liability may be joint and severable for certain sites.
We have recorded an estimated liability of $6 million related to ten of the twenty-four sites. We have paid remediation costs related to the remaining fourteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $8 million related to another ten sites where we believe it is probable that we will incur remediation costs and or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the portion of remediation attributed to us.
Manufactured Gas Plants
We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Eight sites are included in the New York State Registry; eleven sites are included in the New York Voluntary Cleanup Program; three sites are part of Maine’s Voluntary Response Action Program with two of such sites being part of Maine’s Uncontrolled Sites Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and where necessary remediate forty-seven of the fifty-three sites.
30
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $235 million to $468 million as of March 31, 2016. Our estimate could change materially based on facts and ci
rcumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives, and changes to current laws and regulations.
As of March 31, 2016 and December 31, 2015 the liability associated with MGP sites, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates, was $99 million.
The liability to investigate and perform remediation at the known inactive MGP sites was $393 million and $397 million as of March 31, 2016 and December 31, 2015, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2048.
Our Connecticut and Massachusetts regulated gas companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the companies has or had an ownership interest in one or more such properties contaminated as a result of MGP-related activities. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; no liability was recorded in respect of these sites as of March 31, 2016 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites.
FirstEnergy
NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at sixteen former manufactured gas sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s favor. Based on past and future clean-up costs at the sixteen sites in dispute, FirstEnergy would be required to pay NYSEG approximately $60 million if the decision were upheld on appeal. On September 9, 2011, FirstEnergy paid NYSEG $30 million, representing their share of past costs of $27 million and pre-judgment interest of $3 million.
FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million, excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November 2014.
FirstEnergy remains liable for a substantial share of clean up expenses at nine MPG sites. In January 2015, NYSEG sent FirstEnergy a demand for $16 million representing FirstEnergy’s share of clean-up expenses incurred by NYSEG at the nine sites from January 2010 to November 2014 while the District Court appeal was pending. Nearly all of this amount has been paid by FirstEnergy. FirstEnergy would also be liable for a share of post 2014 costs, which, based on current projections, would be $26 million. This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the environmental provision.
Century Indemnity and OneBeacon
On August 14, 2013, NYSEG filed suit in federal court against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at twenty-two former manufactured gas plants. Based on estimated clean-up costs of $282 million, the carriers’ allocable share could equal or exceed approximately $89 million, excluding pre-judgment interest, although this amount may change substantially depending upon the determination of various factual matters and legal issues during the case. Any recovery will be flowed through to NYSEG ratepayers.
Century and One Beacon have answered admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s. We cannot predict the outcome of this matter.
31
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
English Station
In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then and current owners of a former generation site on the Mill River in New Haven (the English Station site) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut against UI seeking, among other things: (i) an order directing UI to reimburse the plaintiffs for costs they have incurred and will incur for the testing, investigation and remediation of hazardous substances at the English Station site and (ii) an order directing UI to investigate and remediate the site. In December 2013, Evergreen and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the property; (ii) reimbursement of remediation costs; (iii) termination of UI’s easement rights; (iv) reimbursement for costs associated with securing the property; and (v) punitive damages.
On April 8, 2013, the Connecticut Department of Energy and Environmental Protection (DEEP) issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions related to investigating and remediating the English Station site. Mediation of the matter began in the fourth quarter of 2013 and concluded unsuccessfully in April 2015.
On September 16, 2015, UI signed a Proposed Partial Consent Order that, when issued by the Commissioner of DEEP, and subject to its terms and conditions, would require UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. Under the Proposed Partial Consent Order, to the extent that the cost of this investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between such cost and $30 million to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut, and the Commissioner of DEEP. Pursuant to the Proposed Partial Consent Order, upon its issuance and subject to its terms and conditions, UI would be obligated to comply with the Proposed Partial Consent Order, even if the cost of such compliance exceeds $30 million. The State will discuss options with UI on recovering or funding any cost above $30 million such as through public funding or recovery from third parties, however it is not bound to agree to or support any means of recovery or funding. On September 30, 2015, the Hearing Officer in DEEP’s administrative proceeding approved a Motion for Stay of further proceedings filed by DEEP, staying all proceedings on the administrative order for 120 days. On January 26, 2016 the Stay was extended for an additional 90 days and in April 2016, the Stay was further extended to September 1, 2016. A status conference is scheduled for September 1, 2016. We cannot predict the outcome of this matter. As of December 31, 2015 we reserved $20.5 million for this case and have accrued the remaining $9.5 million in accordance with the settlement with PURA approving the acquisition. As of March 31, 2016 the reserve amount remained unchanged.
Note 10. Post-retirement and Similar Obligations
We made no pension contributions for the three months ended March 31, 2016. We expect to make $43 million of contributions for the remainder of 2016.
The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2016 and 2015 consisted of:
|
Three Months Ended March 31,
|
|
2016
|
|
|
2015
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
11
|
|
|
$
|
9
|
|
|
Interest cost
|
|
|
35
|
|
|
|
24
|
|
|
Expected return on plan assets
|
|
|
(51
|
)
|
|
|
(39
|
)
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
|
—
|
|
|
|
1
|
|
|
Actuarial loss
|
|
|
38
|
|
|
|
32
|
|
|
Net Periodic Benefit Cost
|
|
$
|
33
|
|
|
$
|
27
|
|
32
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
The components of net periodic benefit cost for postretirement benefits for the three months ended March
31, 2016 and 2015 consisted of:
|
Three Months Ended March 31,
|
|
2016
|
|
|
2015
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
Service cost
|
|
$
|
1
|
|
|
$
|
1
|
|
|
Interest cost
|
|
|
6
|
|
|
|
4
|
|
|
Expected return on plan assets
|
|
|
(3
|
)
|
|
|
(2
|
)
|
|
Amortization of:
|
|
|
|
|
|
|
|
|
|
Prior service costs
|
|
|
(2
|
)
|
|
|
(2
|
)
|
|
Actuarial loss
|
|
|
2
|
|
|
|
2
|
|
|
Net Periodic Benefit Cost
|
|
$
|
4
|
|
|
$
|
3
|
|
Note 11. Equity
As of March 31, 2016 our share capital consisted of 500,000,000 shares of common stock authorized, 309,588,561 shares issued and 309,094,888 shares outstanding, 81.5% owned by Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $13,653 million. As of December 31, 2015 our share capital consisted of 500,000,000 shares of common stock authorized, 309,491,082 shares issued and 308,864,609 shares outstanding, 81.5% owned by Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $13,653 million. We had 493,673 and 626,473 treasury shares and no convertible preferred shares outstanding as of March 31, 2016 and December 31, 2015, respectively. During the three months ended March 31, 2016 we issued 97,479 shares of common stock and 132,800 shares of common stock out of treasury stock each having a par value of $0.01. On December 15, 2015, the Board of Directors approved our common stock dividend, accounted for as a stock split. The stock split, effected through a stock dividend, resulted in the issuance of 252,234,989 shares, which in addition to the 243 previously existing shares increased the total shares outstanding to 252,235,232. The stock dividend was effective upon the Board’s approval. All share and per share information included in the condensed consolidated financial statements have been retroactively adjusted to reflect the impact of the stock dividend.
Accumulated Other Comprehensive Income (Loss)
Accumulated OCI for the three months ended March 31, 2016 and 2015 consisted of:
|
Accumulated Other Comprehensive Income (Loss)
|
|
As of
December
31,
2014
|
|
|
Three Months Ended
March 31, 2015
|
|
|
As of
March 31,
2015
|
|
|
As of
December 31,
2015
|
|
|
Three Months Ended
March 31, 2016
|
|
|
As of
March 31,
2016
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on revaluation of defined benefit plans, net of
income tax expense (benefit) of $(0.9) for 2015 and
$2.8 for 2016
|
|
$
|
(25
|
)
|
|
$
|
(1
|
)
|
|
$
|
(26
|
)
|
|
$
|
(21
|
)
|
|
$
|
4
|
|
|
$
|
(17
|
)
|
|
Loss for nonqualified pension plans
|
|
|
(11
|
)
|
|
|
—
|
|
|
|
(11
|
)
|
|
|
(8
|
)
|
|
|
—
|
|
|
|
(8
|
)
|
|
Unrealized gain (loss) during period on derivatives
qualifying as cash flow hedges, net of income tax
expense of $1.2 for 2016
|
|
|
(2
|
)
|
|
|
—
|
|
|
|
(2
|
)
|
|
|
31
|
|
|
|
2
|
|
|
|
33
|
|
|
Reclassification to net income of losses (gains) on
cash flow hedges, net of income tax expense
(benefit) of $1 for 2015 and $(16.6) for 2016(a)
|
|
|
(61
|
)
|
|
|
2
|
|
|
|
(59
|
)
|
|
|
(54
|
)
|
|
|
(26
|
)
|
|
|
(80
|
)
|
|
Gain (loss) on derivatives qualifying as cash flow
hedges
|
|
|
(63
|
)
|
|
|
2
|
|
|
|
(61
|
)
|
|
|
(23
|
)
|
|
|
(24
|
)
|
|
|
(47
|
)
|
|
Accumulated Other Comprehensive (Loss) Income
|
|
$
|
(99
|
)
|
|
$
|
1
|
|
|
$
|
(98
|
)
|
|
$
|
(52
|
)
|
|
$
|
(20
|
)
|
|
$
|
(72
|
)
|
|
(a)
|
Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income
|
33
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
Note 12. Net Income Per Share
Basic net income per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three months ended March 31, 2016, while we did have securities that were dilutive, these securities did not result in a change on our net income per share calculation result for the three months ended March 31, 2016. We did not have any potentially-dilutive securities for the three months ended March 31, 2015. In accordance with Accounting Standards Codification (ASC) Topic 260, Earnings per Share, we retroactively applied the stock split to prior period.
The calculations of basic and diluted earnings per share attributable to AVANGRID, including a reconciliation of the numerators and denominators for the three months ended March 31, 2016 and 2015 consisted of:
|
Three Months Ended March 31,
|
|
2016
|
|
|
2015
|
|
|
(Millions, except for number of shares and per share data)
|
|
|
|
|
|
|
|
|
|
Numerator:
|
|
|
|
|
|
|
|
|
|
Net income attributable to AVANGRID
|
|
$
|
212
|
|
|
$
|
106
|
|
|
Denominator:
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares outstanding - basic
|
|
|
309,538,215
|
|
|
|
252,235,232
|
|
|
Weighted average number of shares outstanding - diluted
|
|
|
309,808,006
|
|
|
|
252,235,232
|
|
|
Earnings per share attributable to AVANGRID
|
|
|
|
|
|
|
|
|
|
Earnings Per Common Share, Basic
|
|
$
|
0.69
|
|
|
$
|
0.42
|
|
|
Earnings Per Common Share, Diluted
|
|
$
|
0.69
|
|
|
$
|
0.42
|
|
Note 13. Segment Information
Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following three reportable segments:
|
·
|
Networks: including all the energy transmission and distribution activities, and any other regulated activity originating in New York and Maine, and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes eight rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment.
|
|
·
|
Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities.
|
|
·
|
Gas: including gas trading and storage businesses carried on by the AVANGRID Group.
|
Products and services are sold between reportable segments and affiliate companies at cost. The Chief Operating Decision Maker evaluates segment performance based on segment adjusted EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) defined as net income adding back net income attributable to other noncontrolling interests, income tax expense, depreciation and amortization and interest expense net of capitalization, and then subtracting other income and (expense) and earnings from equity method investments per segment. Segment income, expense, and assets presented in the accompanying tables include all intercompany transactions that are eliminated in the condensed consolidated financial statements.
34
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
Segment information as of and for the three months ended March 31, 2016 consisted of:
|
Three Months Ended March 31, 2016
|
|
Networks
|
|
|
Renewables
|
|
|
Gas
|
|
|
Other (a)
|
|
|
AVANGRID
Consolidated
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue - external
|
|
$
|
1,390
|
|
|
$
|
276
|
|
|
$
|
3
|
|
|
$
|
1
|
|
|
$
|
1,670
|
|
|
Revenue - intersegment
|
|
|
—
|
|
|
|
2
|
|
|
|
9
|
|
|
|
(11
|
)
|
|
|
—
|
|
|
Depreciation and amortization
|
|
|
118
|
|
|
|
80
|
|
|
|
7
|
|
|
|
—
|
|
|
|
205
|
|
|
Operating income (loss)
|
|
|
312
|
|
|
|
49
|
|
|
|
(10
|
)
|
|
|
(2
|
)
|
|
|
349
|
|
|
Adjusted EBITDA
|
|
|
430
|
|
|
|
129
|
|
|
|
(3
|
)
|
|
|
(2
|
)
|
|
|
554
|
|
|
Earnings (losses) from equity method investments
|
|
|
3
|
|
|
|
(1
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
2
|
|
|
Capital expenditures
|
|
$
|
206
|
|
|
$
|
70
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
276
|
|
|
As of March 31, 2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
|
12,432
|
|
|
|
7,757
|
|
|
|
509
|
|
|
|
—
|
|
|
|
20,698
|
|
|
Equity method investments
|
|
|
108
|
|
|
|
252
|
|
|
|
—
|
|
|
|
—
|
|
|
|
360
|
|
|
Total assets
|
|
$
|
20,014
|
|
|
$
|
10,338
|
|
|
$
|
1,168
|
|
|
$
|
(981
|
)
|
|
$
|
30,539
|
|
|
(a)
|
Does not represent a segment. It mainly includes Corporate and intersegment eliminations.
|
Included in revenue-external for the three months ended March 31, 2016 are: $913 million from regulated electric operations, $477 million from regulated gas operations and no amounts from other operations of Networks; $276 million from renewable energy generation of Renewables; $7 million from gas storage services and $(4) million from gas trading operations of Gas.
Segment information for the three months ended March 31, 2015 consisted of:
|
Three Months Ended March 31, 2015
|
|
Networks
|
|
|
Renewables
|
|
|
Gas
|
|
|
Other (a)
|
|
|
AVANGRID
Consolidated
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue - external
|
|
$
|
998
|
|
|
$
|
239
|
|
|
$
|
(10
|
)
|
|
$
|
—
|
|
|
$
|
1,227
|
|
|
Revenue – intersegment
|
|
|
—
|
|
|
|
1
|
|
|
|
9
|
|
|
|
(10
|
)
|
|
|
—
|
|
|
Depreciation and amortization
|
|
|
86
|
|
|
|
83
|
|
|
|
5
|
|
|
|
1
|
|
|
|
175
|
|
|
Operating income (loss)
|
|
|
189
|
|
|
|
26
|
|
|
|
(15
|
)
|
|
|
(4
|
)
|
|
|
196
|
|
|
Adjusted EBITDA
|
|
|
275
|
|
|
|
109
|
|
|
|
(10
|
)
|
|
|
(3
|
)
|
|
|
371
|
|
|
Earnings from equity method investments
|
|
|
—
|
|
|
|
1
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1
|
|
|
Capital expenditures
|
|
$
|
177
|
|
|
$
|
186
|
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
364
|
|
|
As of December 31, 2015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
|
12,363
|
|
|
|
7,835
|
|
|
|
513
|
|
|
|
—
|
|
|
|
20,711
|
|
|
Equity method investments
|
|
|
110
|
|
|
|
253
|
|
|
|
—
|
|
|
|
22
|
|
|
|
385
|
|
|
Total assets
|
|
$
|
20,126
|
|
|
$
|
10,685
|
|
|
$
|
1,265
|
|
|
$
|
(1,333
|
)
|
|
$
|
30,743
|
|
|
(a)
|
Does not represent a segment. It mainly includes Corporate and intersegment eliminations.
|
Included in revenue-external for the three months ended March 31, 2015 are: $728 million from regulated electric operations, $272 million from regulated gas operations and $(2) million from other operations of Networks; $239 million from renewable energy generation of Renewables; $2 million from gas storage services and $(12) million from gas trading operations of Gas.
35
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Income Before Income Tax for the three months ended March 31, 2016 and 2015 is as follows:
|
Three Months Ended March 31,
|
|
2016
|
|
|
2015
|
|
|
(Millions)
|
|
|
|
|
|
|
|
|
|
Consolidated Adjusted EBITDA
|
|
$
|
554
|
|
|
$
|
371
|
|
|
Less:
|
|
|
|
|
|
|
|
|
|
Depreciation and amortization
|
|
|
205
|
|
|
|
175
|
|
|
Interest expense, net of capitalization
|
|
|
84
|
|
|
|
61
|
|
|
Add:
|
|
|
|
|
|
|
|
|
|
Other income and (expense)
|
|
|
49
|
|
|
|
12
|
|
|
Earnings from equity method investments
|
|
|
2
|
|
|
|
1
|
|
|
Consolidated Income Before Income Tax
|
|
$
|
316
|
|
|
$
|
148
|
|
Note 14. Related Party Transactions
We engage in related party transactions which are generally billed at cost and in accordance with applicable state and federal commission regulations.
Related party transactions for the three months ended March 31, 2016 and 2015 consisted of:
|
Three Months Ended March 31,
|
|
2016
|
|
|
2015
|
|
|
(Millions)
|
|
Sales To
|
|
|
Purchases
From
|
|
|
Sales To
|
|
|
Purchases
From
|
|
|
Iberdrola Canada Energy Services, Ltd
|
|
$
|
—
|
|
|
$
|
(5
|
)
|
|
$
|
—
|
|
|
$
|
(12
|
)
|
|
Iberdrola Renovables Energía, S.L.
|
|
|
—
|
|
|
|
(3
|
)
|
|
|
—
|
|
|
|
(2
|
)
|
|
Iberdrola, S.A.
|
|
|
—
|
|
|
|
(8
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Other
|
|
$
|
1
|
|
|
$
|
—
|
|
|
|
1
|
|
|
|
(6
|
)
|
In addition to the statements of income items above we made purchases of turbines for wind farms from Gamesa Corporación Tecnológica, S.A. (Gamesa), in which our ultimate parent Iberdrola has a 20% ownership. The amounts capitalized for these transactions were $28 million and $70 million as of March 31, 2016 and December 31, 2015, respectively.
Related party balances as of March 31, 2016 and December 31, 2015 consisted of:
|
As of
|
|
March 31, 2016
|
|
|
December 31, 2015
|
|
|
(Millions)
|
|
Owed By
|
|
|
Owed To
|
|
|
Owed By
|
|
|
Owed To
|
|
|
Iberdrola Canada Energy Services, Ltd.
|
|
$
|
2
|
|
|
$
|
(4
|
)
|
|
$
|
7
|
|
|
$
|
(5
|
)
|
|
Gamesa Corporación Tecnológica, S.A.
|
|
|
60
|
|
|
|
(58
|
)
|
|
|
68
|
|
|
|
(77
|
)
|
|
Iberdrola, S.A.
|
|
|
—
|
|
|
|
(11
|
)
|
|
|
—
|
|
|
|
(3
|
)
|
|
Iberdrola Energy Projects, Inc.
|
|
|
1
|
|
|
|
—
|
|
|
|
1
|
|
|
|
(3
|
)
|
|
Iberdrola Renovables Energía, S.L.
|
|
|
—
|
|
|
|
(3
|
)
|
|
|
—
|
|
|
|
—
|
|
|
Other
|
|
|
1
|
|
|
|
(1
|
)
|
|
|
—
|
|
|
|
(2
|
)
|
Transactions with our parent company, Iberdrola, relate predominantly to allocation of corporate services and management fees. Also included within the Purchases From category are charges for credit support relating to guarantees Iberdrola has provided to third parties guaranteeing our performance. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID any costs remaining after direct charge are allocated using agreed upon cost allocation methods designed to allocate those costs. We believe that the allocation method used is reasonable.
Transactions with Iberdrola Canada Energy Services predominantly relate to the purchase of gas for ARHI’s gas-fired generation facility at Klamath.
There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances. The collectability of amounts receivable from Gamesa are contingent upon other related parties fulfilling certain payments to Gamesa.
36
Avangrid, Inc. and Subsidiaries
Notes to Condensed Consolidated Financial Statements
(unaudited)
AVANGRID manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a cash pooling agreement with Bank Mendes Gans, N.V., similar to other Iberdrola subsidiaries. Cash surpluses remaining after meeti
ng the liquidity requirements of AVANGRID and its subsidiaries may be deposited in the cash pooling account where such funds are available to meet the liquidity needs of other affiliates within the Iberdrola Group. Under the cash pooling agreement, affilia
tes with credit balances have pledged those balances to cover the debit balances of the other affiliated parties to the agreement.
Note 15. Accounts Receivable
Accounts receivable include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time, which generally exceeds one year, by negotiating mutually acceptable payment terms and not bearing interest. The utility company generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within thirty days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as current.
We establish provisions for uncollectible accounts for DPA’s by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collection efforts have been exhausted. DPA receivable balances were $62 million at both March 31, 2016 and December 31, 2015. The allowance for doubtful accounts for DPAs at March 31, 2016 and December 31, 2015 were $34 million and $35 million, respectively. Furthermore, the provision for bad debts associated with the DPAs for the three months ended March 31, 2016 and 2015 approximated $(1) million and $(9) million, respectively.
Note 16. Subsequent Events
New Credit Facility
On April 5, 2016, AVANGRID and its subsidiaries, NYSEG, RGE, CMP, UI, Connecticut Natural Gas Corporation (CNG), The Southern Connecticut Gas Company (SCG) and The Berkshire Gas Company (BGC) entered into a revolving credit facility with a syndicate of banks (the Credit Facility), that provides for maximum borrowings of up to $1.5 billion in the aggregate.
Under the terms of the Credit Facility, each joint borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit established by the banks. AVANGRID’s maximum sublimit is $1 billion, NYSEG, RGE, CMP and UI have maximum sublimits of $250 million, CNG, and SCG have maximum sublimits of $150 million and BGC has a maximum sublimit of $25 million. Under the Credit Facility, each of the borrowers will pay an annual facility fee that is dependent on its credit rating. The facility fees will range from 10.0 to 17.5 basis points. The maturity date for the Credit Facility is April 5, 2021.
As a condition of closing on the new Credit Facility, the AVANGRID revolving credit facility, the joint utility revolving credit facility, and the UIL credit facility were terminated and all amounts payable under the terminated facilities were repaid in full.
Quarterly Dividends
On April 20, 2016, the Board of Directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable July 1, 2016 to shareholders of record at the close of business on June 10, 2016.
Stock Repurchase Program
On
April 28, 2016, pursuant to action of the Board of Directors of AVANGRID authorizing AVANGRID to repurchase up to 97,479 shares of its common stock under an open market stock repurchase program, AVANGRID entered into a Repurchase Agreement (Agreement) with J.P. Morgan Securities, LLC. (JPM). Under the Agreement, JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of this program is to allow AVANGRID to maintain the relative ownership percentage of Iberdrola at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice.
Transfer of UIL under Networks
Effective as of April 30, 2016, and in compliance with a regulatory commitment, the ownership of UIL and its subsidiaries, a heretofore wholly owned subsidiary of AVANGRID, has been transferred to a newly created special purpose entity named UIL Group, LLC, which is a wholly-owned subsidiary of Networks.
Repurchase of AVANGRID Common Stock
In May 2016, pursuant to the stock repurchase program, we repurchased
97,479 shares of AVANGRID common stock in the open market. The total cost of repurchase, including commissions, was $4 million.
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