Regulatory Matters

Rate Plans

The Utilities provide service to New York customers according to the terms of tariffs approved by the NYSPSC. Tariffs for service to customers of Rockland Electric Company (RECO), O&R’s New Jersey regulated utility subsidiary, are approved by the New Jersey Board of Public Utilities (NJBPU). The tariffs include schedules of rates for service that limit the rates charged by the Utilities to amounts that recover from their customers costs approved by the regulator, including capital costs, of providing service to customers as defined by the tariff. The tariffs implement rate plans adopted by state utility regulators in rate orders issued at the conclusion of rate proceedings. Pursuant to the Utilities’ rate plans, there generally can be no change to the charges to customers during the respective terms of the rate plans other than specified adjustments provided for in the rate plans. The Utilities’ rate plans each cover specified periods, but rates determined pursuant to a plan generally continue in effect until a new rate plan is approved by the state utility regulator.

Common provisions of the Utilities’ New York rate plans include:

Recoverable energy costs that allow the Utilities to recover on a current basis the costs for the energy they supply with no mark-up to their full-service customers.

Cost reconciliations that reconcile pension and other postretirement benefit costs, environmental remediation costs, property taxes, variable rate tax-exempt debt and certain other costs to amounts reflected in delivery rates for such costs. In addition, changes in the Utilities' costs not reflected in rates, in excess of certain amounts, resulting from changes in tax or other law, rule, regulation, order, or other requirement or interpretation are deferred as a regulatory asset or regulatory liability to be reflected in the Utilities' next rate plan or in a manner to be determined by the NYSPSC. See "Other Regulatory Matters," below. Also, the Utilities generally retain the right to petition for recovery or accounting deferral of extraordinary and material cost increases and provision is sometimes made for the utility to retain a share of cost reductions, for example, property tax refunds.

Revenue decoupling mechanisms that reconcile actual energy delivery revenues to the authorized delivery revenues approved by the NYSPSC. The difference is accrued with interest for refund to, or recovery from customers, as applicable.

Earnings sharing that require the Utilities to defer for customer benefit a portion of earnings over specified rates of return on common equity. There is no symmetric mechanism for earnings below specified rates of return on common equity.

Negative revenue adjustments for failure to meet certain performance standards relating to service, reliability, safety and other matters.

Positive revenue adjustments for achievement of performance standards related to achievement of clean energy goals, safety and other matters.

Net utility plant reconciliations that require deferral as a regulatory liability of the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates. There is generally no symmetric mechanism if actual average net utility plant balances are more than amounts reflected in rates.

Rate base, as reflected in the rate plans, is, in general, the sum of the Utilities’ net plant, working capital and certain regulatory assets less deferred taxes and certain regulatory liabilities. For each rate plan, the NYSPSC uses a forecast of the average rate base for each year that new rates would be in effect (“rate year”).

Weighted average cost of capital is determined based on the authorized common equity ratio, return on common equity, cost of long-term debt and customer deposits reflected in each rate plan. For each rate plan, the revenues designed to provide the utility a return on invested capital for each rate year are determined by multiplying each utility rate base by its pre–tax weighted average cost of capital. The Utilities’ actual return on common equity will reflect their actual operations for each rate year, and may be more or less than the authorized return on equity reflected in their rate plans (and if more, may be subject to earnings sharing).

The following tables contain a summary of the Utilities’ rate plans:



CECONY – Electric
Effective period	January 2014 – December 2016	January 2017 – December 2019 (b)
Base rate changes	Yr. 1 – $(76.2) million (a) Yr. 2 – $124.0 million (a) Yr. 3 – None	Yr. 1 – $195 million (c) Yr. 2 – $155 million (c) Yr. 3 – $155 million (c)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 and 2 – $(37) million (d) Yr. 3 – $123 million (d)	Yr. 1 – $84 million Yr. 2 – $83 million Yr. 3 – $69 million



Other revenue sources	Retention of $90 million of annual transmission congestion revenues.	Retention of $75 million of annual transmission congestion revenues. Potential earnings adjustment mechanism incentives for energy efficiency and other potential incentives of up to: Yr. 1 – $28 million Yr. 2 – $47 million Yr. 3 – $64 million In 2017 and 2018, the company recorded $13 million and $25 million of earnings adjustment mechanism incentives for energy efficiency, respectively. The company also achieved other incentives of $5 million in 2017 and 2018 that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018, the company recorded $3 million for service terminations.
Revenue decoupling mechanisms	In 2014, 2015 and 2016, the company deferred for customer benefit $146 million, $98 million and $101 million of revenues, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues. In 2017 and 2018, the company deferred for customer benefit $45 million and $(6) million of revenues, respectively.
Recoverable energy costs (e)	Current rate recovery of purchased power and fuel costs.	Continuation of current rate recovery of purchased power and fuel costs.
Negative revenue adjustments	Potential penalties (up to $400 million annually) if certain performance targets are not met. In 2014, the company recorded a $5 million negative revenue adjustment. In 2015 and 2016, the company did not record any negative revenue adjustments.	Potential penalties if certain performance targets relating to service, reliability, safety and other matters are not met: Yr. 1 – $376 million Yr. 2 – $341 million Yr. 3 – $352 million In 2017 and 2018, the company did not record any negative revenue adjustments.
Cost reconciliations	In 2014, 2015 and 2016, the company deferred $57 million, $26 million and $68 million of net regulatory liabilities, respectively (f).	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (f), municipal infrastructure support costs (g), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates (h). In 2017 and 2018, the company deferred $35 million and $189 million of net regulatory assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Transmission and distribution: Yr. 1 – $16,869 million Yr. 2 – $17,401 million Yr. 3 – $17,929 million Storm hardening: Yr. 1 – $89 million; Yr. 2 – $177 million; Yr. 3 – $268 million Other: Yr. 1 – $2,034 million; Yr. 2 – $2,102 million; Yr. 3 – $2,069 million The company deferred $6 million and $17 million as a regulatory liability in 2014 and 2015, respectively. In 2016, $9 million was deferred as a regulatory asset.	Target levels reflected in rates: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 – $21,689 million Yr. 2 – $22,338 million Yr. 3 – $23,002 million AMI: Yr. 1 – $126 million Yr. 2 – $257 million Yr. 3 – $415 million The company deferred $0.4 million as a regulatory asset in 2017. In 2018, $0.4 was deferred as a regulatory liability.
Average rate base	Yr. 1 – $17,323 million Yr. 2 – $18,113 million Yr. 3 – $18,282 million	Yr. 1 – $18,902 million Yr. 2 – $19,530 million Yr. 3 – $20,277 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.05 percent Yr. 2 – 7.08 percent Yr. 3 – 6.91 percent	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent
Authorized return on common equity	Yrs. 1 and 2 – 9.2 percent Yr. 3 – 9.0 percent	9.0 percent
Actual return on common equity	Yr. 1 – 9.04 percent Yr. 2 – 10.16 percent Yr. 3 – 9.66 percent	Yr. 1 – 9.30 percent Yr. 2 – 9.36 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.8 percent for Yrs. 1 and 2 and 9.6 percent for Yr. 3 are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014 the company had no earnings above the threshold. Actual earnings were $44.4 million and $6.5 million above the threshold for 2015 and 2016, respectively.	Most earnings above an annual earnings threshold of 9.5 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2017, the company had no earnings above the threshold but recorded a positive adjustment related to 2016 of $5.7 million in earnings. In 2018, the company had no earnings sharing above the threshold.
Cost of long-term debt	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.09 percent	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent
Common equity ratio	48 percent	48 percent


(a)	The impact of these base rate changes was deferred; this amount was amortized to $0 at December 31, 2016.

(b)

In January 2017, the NYSPSC approved the September 2016 Joint Proposal for CECONY's electric rate plan for January 2017 through December 2019. If at the end of any year, Con Edison’s investments in its non-utility businesses exceed 15 percent of Con Edison’s total consolidated revenues, assets or cash flow, or if the ratio of holding company debt to total consolidated debt rises above 20 percent, CECONY is required to notify the NYSPSC and submit a ring-fencing plan or a demonstration why additional ring-fencing measures (see Note S) are not necessary.

(c)

The electric base rate increases are in addition to a $48 million increase resulting from the December 2016 expiration of a temporary credit under the prior rate plan. At the NYSPSC’s option, these increases are being implemented with increases of $199 million in each rate year. Base rates reflect recovery by the company of certain costs of its energy efficiency, system peak reduction and electric vehicle programs (Yr. 1 - $20.5 million; Yr. 2 - $49 million; and Yr. 3 - $107.5 million) over a ten-year period, including the overall pre-tax rate of return on such costs.

(d)

Amounts reflect annual amortization of $107 million of the regulatory asset for deferred Superstorm Sandy and other major storm costs. The costs recoverable from customers were reduced by $4 million. The costs are no longer subject to NYSPSC staff review and the recovery of the costs is no longer subject to refund. In 2016, an additional $123 million of net regulatory liabilities were amortized to income.

(e)

For transmission service provided pursuant to the open access transmission tariff of PJM Interconnection LLC (PJM), unless and until changed by the NYSPSC, the company will recover all charges incurred associated with the transmission service. In April 2017, the transmission service terminated because CECONY did not exercise its option to continue the service. See "Other Regulatory Matters," below.


(f)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a maximum number of basis points (5.0, 7.5 or 10.0 basis points, depending on the year).

(g)

In general, if actual expenses for municipal infrastructure support (other than company labor) are below the amounts reflected in rates the company will defer the difference for credit to customers, and if the actual expenses are above the amount reflected in rates the company will defer for recovery from customers 80 percent of the difference subject to a maximum deferral of 30 percent of the amount reflected in rates.

(h)

In addition, amounts reflected in rates relating to the regulatory asset for future income tax and the excess deferred federal income tax liability are subject to reconciliation. The NYSPSC staff is to audit the regulatory asset and the tax liability. Differences resulting from the NYSPSC staff review will be deferred for NYSPSC determination of any amounts to be refunded or collected from customers. See "Other Regulatory Matters," below.

In January 2019, CECONY filed a request with the NYSPSC for an electric rate increase of $485 million, effective January 2020. The filing reflects a return on common equity of 9.75 percent and a common equity ratio of 50 percent.

The company is requesting provisions pursuant to which expenses for pension and other postretirement benefits, variable-rate debt, storms, property taxes and municipal infrastructure support, the impact of new laws and environmental site investigation and remediation are reconciled to amounts reflected in rates. The company is also proposing full reconciliation of capital interference costs. In addition, the company is, among other things, proposing continuation of earnings opportunities from Earnings Adjustment Mechanisms (EAM) for meeting energy efficiency goals. The proposed EAM earnings opportunities are at 100 basis points of common equity annually. The filing also reflects continuation of the revenue decoupling mechanism and the provisions pursuant to which the company recovers its purchased power and fuel costs from customers. The requested rate increase was mitigated, in part, by the TCJA, including reduced tax rate, and amortization of excess deferred income taxes and 2018 tax savings. See "Other Regulatory Matters," below.

The filing includes supplemental information regarding electric rate plans for 2021 and 2022, which the company is not requesting but would consider through settlement discussions. For purposes of illustration, rate increases of $352 million and $263 million effective January 2021 and 2022, respectively, were calculated based upon an assumed return on common equity of 9.75 percent and a common equity ratio of 50 percent.



CECONY – Gas
Effective period	January 2014 – December 2016	January 2017 - December 2019 (b)
Base rate changes	Yr. 1 – $(54.6) million (a) Yr. 2 – $38.6 million (a) Yr. 3 – $56.8 million (a)	Yr. 1 – $(5) million (b) Yr. 2 – $92 million (b) Yr. 3 – $90 million (b)
Amortizations to income of net regulatory (assets) and liabilities	$4 million over three years	Yr. 1 – $39 million Yr. 2 – $37 million Yr. 3 – $36 million
Other revenue sources	Retention of revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. The company retained $70 million, $66 million and $65 million of such revenues in 2014, 2015 and 2016, respectively.	Retention of annual revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million. Potential incentives if performance targets related to gas leak backlog, leak prone pipe and service terminations are met: Yr. 1 – $7 million Yr. 2 – $8 million Yr. 3 – $8 million In 2017 and 2018, the company achieved incentives of $7 million and $6 million, respectively that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018, the company recorded $5 million for gas leak backlog, leak prone pipe and service terminations.
Revenue decoupling mechanisms	In 2014, 2015 and 2016, the company deferred $28 million, $54 million and $71 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues. In 2017 and 2018, the company deferred $3 million and $12 million of regulatory liabilities, respectively.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $33 million in 2014, $44 million in 2015, and $56 million in 2016) if certain gas performance targets are not met. In 2014, 2015 and 2016, the company did not record any negative revenue adjustments.	Potential penalties if performance targets relating to service, safety and other matters are not met: Yr. 1 – $68 million Yr. 2 – $63 million Yr. 3 – $70 million In 2017 and 2018, the company recorded $5 million and $4 million of negative revenue adjustments, respectively.
Cost reconciliations	In 2014, 2015 and 2016, the company deferred $38 million, $11 million, and $32 million of net regulatory liabilities, respectively. (c)	Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes, municipal infrastructure support costs, the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (d) In 2017 and 2018, the company deferred $2 million of net regulatory liabilities and $44 million of net regulatory assets, respectively.
Net utility plant reconciliations	Target levels reflected in rates were: Gas delivery Yr. 1 – $3,899 million; Yr. 2 – $4,258 million; Yr. 3 – $4,698 million Storm hardening: Yr. 1 – $3 million; Yr. 2 – $8 million; Yr. 3 – $30 million In 2015 $1 million was deferred as a regulatory liability. In 2014 and 2016 the company deferred an immaterial amount.	Target levels reflected in rates: Gas average net plant target excluding AMI: Yr. 1 – $5,844 million Yr. 2 – $6,512 million Yr. 3 – $7,177 million AMI: Yr. 1 – $27 million Yr. 2 – $57 million Yr. 3 – $100 million In 2017 and 2018 the company deferred $2.2 million as regulatory liabilities.
Average rate base	Yr. 1 – $3,521 million Yr. 2 – $3,863 million Yr. 3 – $4,236 million	Yr. 1 – $4,841 million Yr. 2 – $5,395 million Yr. 3 – $6,005 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent	Yr. 1 – 6.82 percent Yr. 2 – 6.80 percent Yr. 3 – 6.73 percent
Authorized return on common equity	9.3 percent	9.0 percent
Actual return on common equity	Yr. 1 – 8.02 percent Yr. 2 – 8.13 percent Yr. 3 – 7.83 percent	Yr. 1 – 9.22 percent Yr. 2 – 9.04 percent



Earnings sharing	Most earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, 2015 and 2016, the company had no earnings above the threshold.	Most earnings above an annual earnings threshold of 9.5 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year. In 2017 and 2018, the company had no earnings above the threshold.
Cost of long-term debt	Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent	Yr. 1 – 4.93 percent Yr. 2 – 4.88 percent Yr. 3 – 4.74 percent
Common equity ratio	48 percent	48 percent


(a)	The impact of these base rate changes was deferred which resulted in a $32 million regulatory liability at December 31, 2016.


(b)	In January 2017, the NYSPSC approved the September 2016 Joint Proposal for CECONY's gas rate plan for January 2017 through December 2019. The gas base rate decrease is offset by a $41 million increase resulting from the December 2016 expiration of a temporary credit under the prior rate plan.


(c)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity


(d)	See footnotes (e), (f), (g) and (h) to the table under "CECONY - Electric" above.

In January 2019, CECONY filed a request with the NYSPSC for a gas rate increase of $210 million, effective January 2020. The filing reflects a return on common equity of 9.75 percent and a common equity ratio of 50 percent.

The company is requesting provisions pursuant to which expenses for pension and other postretirement benefits, variable-rate debt, property taxes and municipal infrastructure support, the impact of new laws and environmental site investigation and remediation are reconciled to amounts reflected in rates. The company is also proposing full reconciliation of capital interference costs. In addition, the company is, among other things, proposing continuation of earnings opportunities from Earnings Adjustment Mechanisms (EAM) for meeting energy efficiency goals. The proposed EAM earnings opportunities are at 70 basis points of common equity annually. The filing also reflects continuation of the revenue decoupling mechanism (RDM) and provisions pursuant to which the company recovers its purchased gas costs from customers. Within the filing, the company is proposing to change the gas RDM from a revenue per customer methodology to a revenue per class methodology. The requested rate increase was mitigated, in part, by the TCJA, including reduced tax rate, and amortization of excess deferred income taxes and 2018 tax savings. See "Other Regulatory Matters," below.

The filing includes supplemental information regarding gas rate plans for 2021 and 2022, which the company is not requesting but would consider through settlement discussions. For purposes of illustration, rate increases of $138 million and $155 million effective January 2021 and 2022, respectively, were calculated based upon an assumed return on common equity of 9.75 percent and a common equity ratio of 50 percent.



CECONY – Steam
Effective period		January 2014 – December 2016 (a)
Base rate changes		Yr. 1 – $(22.4) million (b) Yr. 2 – $19.8 million (b) Yr. 3 – $20.3 million (b) Yr. 4 – None Yr. 5 – None
Amortizations to income of net regulatory (assets) and liabilities		$37 million over three years
Recoverable energy costs		Current rate recovery of purchased power and fuel costs.
Negative revenue adjustments		Potential penalties (up to $1 million annually) if certain steam performance targets are not met. In 2014, 2015, 2016 and 2017 and 2018, the company did not record any negative revenue adjustments.
Cost reconciliations (c)		In 2014, 2015, 2016 2017 and 2018, the company deferred $42 million of net regulatory liabilities, $17 million of net regulatory assets, $8 million and $14 million of net regulatory liabilities, and $1 million of net regulatory assets, respectively.
Net utility plant reconciliations		Target levels reflected in rates were: Production: Yr. 1 – $1,752 million; Yr. 2 – $1,732 million; Yr. 3 – $1,720 million Distribution: Yr. 1 – $6 million; Yr. 2 – $11 million; Yr. 3 – $25 million The company reduced its regulatory liability by $0.1 million in 2014 and immaterial amounts in 2015 and 2016 and no deferrals were recorded in 2017 and 2018.
Average rate base		Yr. 1 – $1,511 million Yr. 2 – $1,547 million Yr. 3 – $1,604 million
Weighted average cost of capital (after-tax)		Yr. 1 – 7.10 percent Yr. 2 – 7.13 percent Yr. 3 – 7.21 percent
Authorized return on common equity		9.3 percent
Actual return on common equity		Yr. 1 – 9.82 percent Yr. 2 – 10.88 percent Yr. 3 – 10.54 percent Yr. 4 – 9.51 percent Yr. 5 – 11.73 percent
Earnings sharing		Weather normalized earnings above an annual earnings threshold of 9.9 percent are to be applied to reduce regulatory assets for environmental remediation and other costs. In 2014, the company had no earnings above the threshold. Actual earnings were $11.5 million and $7.8 million above the threshold in 2015 and 2016, respectively. In 2017, actual earnings were $8.5 million above the threshold, offset in part by a positive adjustment related to 2016 of $4 million. In 2018, actual earnings were $14.2 million above the threshold, and an additional $1.1 million related to 2017 was recorded.
Cost of long-term debt		Yr. 1 – 5.17 percent Yr. 2 – 5.23 percent Yr. 3 – 5.39 percent
Common equity ratio		48 percent


(a)	Rates determined pursuant to this rate plan continue in effect until a new rate plan is approved by the NYSPSC.


(b)	The impact of these base rate changes was deferred which resulted in an $8 million regulatory liability at December 31, 2016.


(c)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a 10 basis point impact on return on common equity.

In November 2018, O&R, the staff of the NYSPSC and other parties entered into a Joint Proposal for new electric and gas rate plans for the three-year period January 2019 through December 2021 (the Joint Proposal). The Joint Proposal is subject to NYSPSC approval. The following tables contain a summary of the current and proposed rate plans.



O&R New York – Electric
Effective period	November 2015 - October 2017 (a)	January 2019 – December 2021 (d)
Base rate changes	Yr. 1 – $9.3 million Yr. 2 – $8.8 million Yr. 3 – None	Yr. 1 – $13.4 million (e) Yr. 2 – $8.0 million (e) Yr. 3 – $5.8 million (e)
Amortizations to income of net regulatory (assets) and liabilities	Yr. 1 – $(8.5) million (b) Yr. 2 – $(9.4) million (b) Yr. 3 – None	Yr. 1 – $(1.5) million (f) Yr. 2 – $(1.5) million (f) Yr. 3 – $(1.5) million (f)
Other revenue sources		Potential earnings adjustment mechanism incentives for peak reduction, energy efficiency, Distributed Energy Resources utilization and other potential incentives of up to: Yr. 1 - $3.6 million; Yr. 2 - $4.0 million; and Yr. 3 - $4.2 million. Potential incentive if performance target related to service terminations is met: $0.5 million annually.
Revenue decoupling mechanisms	In 2015, 2016, 2017 and 2018, the company deferred for the customer’s benefit an immaterial amount, $6.3 million as regulatory liabilities, $11.2 million as regulatory asset and $0.5 million as regulatory asset, respectively.	Continuation of reconciliation of actual to authorized electric delivery revenues.
Recoverable energy costs	Continuation of current rate recovery of purchased power costs.	Continuation of current rate recovery of purchased power costs.
Negative revenue adjustments	Potential penalties (up to $4 million annually) if certain performance targets are not met. In 2015 the company recorded $1.25 million in negative revenue adjustments. In 2016, 2017 and 2018, the company did not record any negative revenue adjustments.	Potential penalties if certain performance targets relating to service, reliability and other matters are not met: Yr. 1 - $4.4 million; Yr. 2 - $4.4 million; and Yr. 3 - $4.5 million.
Cost reconciliations	In 2015, 2016 and 2017, the company deferred $0.3 million, $7.4 million and $3.2 million as net decreases to regulatory assets, respectively. In 2018, the company deferred $5 million as a net regulatory asset.	Reconciliation of expenses for pension and other postretirement benefits, environmental remediation costs, property taxes (g), energy efficiency program (h), major storms, the impact of new laws and certain other costs to amounts reflected in rates.(i)
Net utility plant reconciliations	Target levels reflected in rates are: Yr. 1 – $928 million (c) Yr. 2 – $970 million (c) The company increased/(reduced) its regulatory asset by $2.2 million, $(1.9) million, $(1.9) million and $1.4 million in 2015, 2016, 2017 and 2018, respectively.	Target levels reflected in rates were: Electric average net plant target excluding advanced metering infrastructure (AMI): Yr. 1 - $1,008 million; Yr. 2 - $1,032 million; Yr. 3 - $1,083 million AMI (j): Yr. 1 - $48 million; Yr. 2 - $58 million; Yr. 3 - $61 million
Average rate base	Yr. 1 – $763 million Yr. 2 – $805 million Yr. 3 – $805 million	Yr. 1 – $878 million Yr. 2 – $906 million Yr. 3 – $948 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent	Yr. 1 – 6.97 percent Yr. 2 – 6.96 percent Yr. 3 – 6.96 percent
Authorized return on common equity	9.0 percent	9.00 percent
Actual return on common equity	Yr. 1 – 10.8 percent Yr. 2 – 9.7 percent Yr. 3 – 7.2 percent
Earnings sharing	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold. Actual earnings were $6.1 million, $0.3 million above the threshold for 2016 and 2017, respectively. In 2018, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year.
Cost of long-term debt	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.14 percent Yr. 3 – 5.14 percent
Common equity ratio	48 percent	48 percent


(a)	Rates determined pursuant to this rate plan continue in effect until a new rate plan is approved by the NYSPSC.

(b)

$59.3 million of the regulatory asset for deferred storm costs is to be recovered from customers over a five year period, including $11.85 million in each of years 1 and 2, $1 million of the regulatory asset for such costs will not be recovered from customers, and all outstanding issues related to Superstorm Sandy and other past major storms prior to November 2014 are resolved. Approximately $4 million of regulatory assets for property tax and interest rate reconciliations will not be recovered from customers. Amounts that will not be recovered from customers were charged-off in June 2015.


(c)	Excludes electric AMI as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $1 million in year 1 and $9 million in year 2.

(d)

If at the end of any year, Con Edison’s investments in its non-utility businesses exceed 15 percent of Con Edison’s total consolidated revenues, assets or cash flow, or if the ratio of holding company debt to total consolidated debt rises above 20 percent, O&R is required to notify the NYSPSC and submit a ring-fencing plan or a demonstration why additional ring-fencing measures (see Note S) are not necessary.


(e)	The Joint Proposal recommends that these base rate changes may be implemented with increases of: Yr. 1 - $8.6 million; Yr. 2 - $12.1 million; and Yr. 3 - $12.2 million.

(f)

Reflects amortization of, among other things, the Company’s net benefits under the TCJA prior to January 1, 2019, amortization of net regulatory liability for future income taxes and reduction of previously incurred regulatory assets for environmental remediation costs. Also, for electric, reflects amortization over a six year period of previously incurred incremental major storm costs. See "Other Regulatory Matters," below.


(g)	Deferrals for property taxes are limited to 90 percent of the difference from amounts reflected in rates, subject to an annual maximum for the remaining difference of not more than a maximum number of basis points impact on return on common equity: Yr. 1 - 10.0 basis points; Yr. 2 - 7.5 basis points; and Yr. 3 - 5.0 basis points.


(h)	Energy efficiency costs are expensed as incurred. Such costs are subject to a downward-only reconciliation over the terms of the electric and gas rate plans. The Company will defer for the benefit of customers any cumulative shortfall over the terms of the electric and gas rate plans between actual expenditures and the levels provided in rates.


(i)	In addition, amounts reflected in rates relating to income taxes and excess deferred federal income tax liability balances will be reconciled (i.e., refunded to or collected from customers) to any final, non-appealable NYSPSC-ordered findings in its investigation of O&R’s income tax accounting. See “Other Regulatory Matters,” in Note B.


(j)	Net plant reconciliation for AMI expenditures will be implemented for a single category of AMI capital expenditures that includes amounts allocated to both electric and gas customers.



O&R New York – Gas
Effective period	November 2015 – October 2018 (a)	January 2019 – December 2021 (d)
Base rate changes	Yr. 1 – $16.4 million Yr. 2 – $16.4 million Yr. 3 – $5.8 million Yr. 3 – $10.6 million collected through a surcharge	Yr. 1 – $(7.5) million (e) Yr. 2 – $3.6 million (e) Yr. 3 – $0.7 million (e)
Amortization to income of net regulatory (assets) and liabilities	Yr. 1 – $(1.7) million (b) Yr. 2 – $(2.1) million (b) Yr. 3 – $(2.5) million (b)	Yr. 1 – $1.8 million (f) Yr. 2 – $1.8 million (f) Yr. 3 – $1.8 million (f)
Other revenue sources		Continuation of retention of annual revenues from non-firm customers of up to $4.0 million, with variances to be shared 80 percent by customers and 20 percent by company. Potential earnings adjustment mechanism incentives of up to $0.3 million annually. Potential incentives if performance targets related to gas leak backlog, leak prone pipe, emergency response, damage prevention and service terminations are met: Yr. 1 - $1.2 million; Yr. 2 - $1.3 million; and Yr. 3 - $1.3 million.
Revenue decoupling mechanisms	In 2015, 2016 2017 and 2018, the company deferred $0.8 million of regulatory assets, $6.2 million of regulatory liabilities, $1.7 million of regulatory liabilities and $6.3 million of regulatory liabilities, respectively.	Continuation of reconciliation of actual to authorized gas delivery revenues.
Recoverable energy costs	Current rate recovery of purchased gas costs.	Continuation of current rate recovery of purchased gas costs.
Negative revenue adjustments	Potential penalties (up to $3.7 million in Yr. 1, $4.7 million in Yr. 2 and $4.9 million in Yr. 3) if certain performance targets are not met. In 2015, 2016 and 2017, the company did not record any negative revenue adjustments. In 2018, the company recorded a $0.1 million negative revenue adjustment.	Potential penalties if performance targets relating to service, safety and other matters are not met: Yr. 1 - $5.5 million; Yr. 2 - $5.7 million; and Yr. 3 - $6.0 million.
Cost reconciliations	In 2015 and 2016, the company deferred $4.5 million and $6.6 million as net regulatory liabilities and assets, respectively. In 2017 and 2018, the company deferred $3.5 million and $7.4 million as net regulatory liabilities, respectively.	Reconciliation of expenses for pension and other postretirement benefits, environmental remediation costs, property taxes (g), energy efficiency program (h), the impact of new laws and certain other costs to amounts reflected in rates.(i)
Net utility plant reconciliations	Target levels reflected in rates are: Yr. 1 – $492 million (c) Yr. 2 – $518 million (c) Yr. 3 – $546 million (c) No deferral was recorded for 2015 and immaterial amounts were recorded as regulatory liabilities in 2016 and 2017. In 2018, the company deferred $0.4 million as regulatory asset.	Target levels reflected in rates were: Gas average net plant target excluding AMI: Yr. 1 - $593 million; Yr. 2 - $611 million; Yr. 3 - $632 million AMI (j): Yr. 1 - $20 million; Yr. 2 - $24 million; Yr. 3 - $25 million
Average rate base	Yr. 1 – $366 million Yr. 2 – $391 million Yr. 3 – $417 million	Yr. 1 – $454 million Yr. 2 – $476 million Yr. 3 – $498 million
Weighted average cost of capital (after-tax)	Yr. 1 – 7.10 percent Yr. 2 – 7.06 percent Yr. 3 – 7.06 percent	Yr. 1 – 6.97 percent Yr. 2 – 6.96 percent Yr. 3 – 6.96 percent
Authorized return on common equity	9.0 percent	9.00 percent
Actual return on common equity	Yr. 1 – 11.2 percent Yr. 2 – 9.7 percent Yr. 3 – 8.1 percent
Earnings sharing	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets. In 2015, earnings did not exceed the earnings threshold. Actual earnings were $4 million, $0.2 million above the threshold for 2016 and 2017, respectively. In 2018, earnings did not exceed the earnings threshold.	Most earnings above an annual earnings threshold of 9.6 percent are to be applied to reduce regulatory assets for environmental remediation and other costs accumulated in the rate year.
Cost of long-term debt	Yr. 1 – 5.42 percent Yr. 2 – 5.35 percent Yr. 3 – 5.35 percent	Yr. 1 – 5.17 percent Yr. 2 – 5.14 percent Yr. 3 – 5.14 percent
Common equity ratio	48 percent	48 percent


(a)	Rates pursuant to this rate plan continue in effect until a new rate plan is approved by the NYSPSC.


(b)	Reflects that the company will not recover from customers a total of approximately $14 million of regulatory assets for property tax and interest rate reconciliations. Amounts that will not be recovered from customers were charged-off in June 2015.


(c)	Excludes gas AMI as to which the company will be required to defer as a regulatory liability the revenue requirement impact of the amount, if any, by which actual average net utility plant balances are less than amounts reflected in rates: $0.5 million in year 1, $4.2 million in year 2 and $7.2 million in year 3.

(d)


(e)	The Joint Proposal recommends that these base rate changes may be implemented with changes of: Yr. 1 - $(5.9) million; Yr. 2 - $1.0 million; and Yr. 3 - $1.0 million.

Footnotes (f) through (j) to this table are the same as footnotes (f) through (j) to the table under “O&R New York - Electric,” above.



RECO
Effective period	August 2014 – February 2017	March 2017 (a)
Base rate changes	Yr. 1 – $13.0 million	Yr. 1 – $1.7 million
Amortization to income of net regulatory (assets) and liabilities	$0.4 million over three years and $(25.6) million of deferred storm costs over four years	$0.2 million over three years and continuation of $(25.6) million of deferred storm costs over four years which expired on July 31, 2018 (b)
Recoverable energy costs	Current rate recovery of purchased power costs.	Current rate recovery of purchased power costs.
Cost reconciliations	None	None
Average rate base	$172.2 million	Yr. 1 – $178.7 million
Weighted average cost of capital (after-tax)	7.83 percent	7.47 percent
Authorized return on common equity	9.75 percent	9.6 percent
Actual return on common equity	Yr. 1 – 9.2 percent Yr. 2 – 8.7 percent	Yr. 1 – 7.5 percent
Cost of long-term debt	5.89 percent	5.37 percent
Common equity ratio	50 percent	49.7 percent


(a)	Effective until a new rate plan approved by the NJBPU goes into effect.


(b)	In January 2016, the NJBPU approved RECO’s plan to spend $15.7 million in capital over three years to harden its electric system against storms, the costs of which RECO, beginning in 2017, is collecting through a customer surcharge.

In November 2017, FERC approved a September 2017 settlement agreement among RECO, the New Jersey Division of Rate Counsel and the NJBPU that increases RECO's annual transmission revenue requirement from $11.8 million to $17.7 million, effective April 2017. The revenue requirement reflects a return on common equity of 10.0 percent.

Other Regulatory Matters

In August and November 2017, the NYSPSC issued orders in its proceeding investigating an April 21, 2017 Metropolitan Transportation Authority (MTA) subway power outage. The orders indicated that the investigation determined that the outage was caused by a failure of CECONY’s electricity supply to a subway station, which led to a loss of the subway signals, and that one of the secondary services to the MTA facility had been improperly rerouted and was not properly documented by the company. The orders also indicated that the loss of power to the subway station affected multiple subway lines and caused widespread delays across the subway system. Pursuant to the orders, the company is required to take certain actions, including inspecting, repairing and installing certain electrical equipment that serves the subway system, analyzing power supply and power quality events affecting the MTA’s signaling services, and filing monthly reports with the NYSPSC on all of the company's activities related to the subway system. The company completed the required actions in 2018. Through December 31, 2018, the company incurred costs related to this matter of $260 million. Included in this amount is $31 million in capital and operating and maintenance costs reflected in the company's electric rate plan and $229 million deferred as a regulatory asset pursuant to the rate plan.

In December 2017, the NYSPSC issued an order initiating a proceeding to study the potential effects of the federal Tax Cuts and Jobs Act of 2017 (TCJA) on income tax expense and liabilities of New York State utilities and the regulatory treatment to preserve the resulting benefits for customers. Upon enactment of the TCJA in December 2017, CECONY and O&R re-measured their deferred tax assets and liabilities and accrued net regulatory liabilities for future income taxes of $3,513 million and $161 million, respectively. In 2018, CECONY and O&R accrued additional net regulatory liabilities for future income tax of $49 million and $2 million, respectively (see Note L). Under the rate normalization requirements continued by the TCJA, the "protected" portion of their net regulatory liabilities related to certain accelerated tax depreciation benefits ($2,593 million and $128 million, respectively) is to be amortized over the remaining lives of the related assets. The remainder of the net regulatory liabilities, or "unprotected" portion, ($969 million and $35 million, respectively) is to be amortized as determined by the NYSPSC.

In August 2018, the NYSPSC ordered CECONY to begin on January 1, 2019 to credit the company's electric and gas customers, and to begin on October 1, 2018 to credit its steam customers, with the net benefits of the TCJA as measured based on amounts reflected in its rate plans prior to the enactment of the TCJA. The net benefits include the revenue requirement impact of the reduction in the corporate federal income tax rate to 21 percent, the elimination for utilities of bonus depreciation and the amortization of excess deferred federal income taxes.

CECONY estimates that its credit of net benefits of the TCJA to its electric, gas and steam customers in 2019 will amount to $259 million, $113 million and $25 million, respectively. CECONY's credit of net benefits to its steam customers in the fourth quarter of 2018 was $6 million. CECONY’s net benefits prior to January 1, 2019 allocable to the company’s electric customers ($307 million) are to be deferred and addressed in its next electric rate proceeding. CECONY’s net benefits prior to January 1, 2019 allocable to the company’s gas customers ($90 million) and net benefits prior to October 1, 2018 allocable to the company’s steam customers ($15 million) are to be amortized over a three-year period. CECONY’s net regulatory liability for future income taxes, including both the protected and unprotected portions, allocable to the company’s electric customers ($2,516 million) is to continue to be deferred until its next electric rate proceeding and the amounts allocable to its gas and steam customers ($841 million and $193 million, respectively) are to be amortized over the remaining lives of the related assets (with the amortization period for the unprotected portion subject to review in its next gas and steam rate proceedings). O&R, under its November 2018 joint proposal for new electric and gas rate plans (which is subject to NYSPSC approval), is to reflect its TCJA net benefits in its electric and gas rates beginning as of January 1, 2019, to amortize its net benefits prior to January 1, 2019 ($22 million) over a three-year period and to amortize the protected portion of its net regulatory liability for future income taxes over the remaining lives of the related assets and the unprotected portion over a fifteen-year period. See "Rate Plans," above.

In 2018, the Utilities deferred as regulatory liabilities estimated net benefits of the TCJA of $434 million.

In January 2018, the NYSPSC issued an order initiating a focused operations audit of the income tax accounting of certain utilities, including CECONY and O&R.

In January 2018, the NJBPU issued an order initiating a proceeding to consider the TCJA. In June 2018, the NJBPU made permanent its previously approved $2.9 million interim decrease in Rockland Electric Company's (RECO) electric base rates, effective April 1, 2018, and ordered RECO to pay to its customers in July 2018 its approximately $1 million of net benefits of the TCJA for the three-month period ended March 31, 2018 and to begin in July 2018 to refund to its customers the unprotected portion of its net regulatory liability for future income taxes over a three-year period. Also in November 2018, the Federal Energy Regulatory Commission (FERC) issued an order directing RECO to refund $0.6 million to its transmission customers and reducing its annual transmission revenue requirement by an immaterial amount to reflect the TCJA. RECO’s net regulatory liability for future income taxes resulting from its re-measurement of its deferred tax asset and liabilities is $28 million (including $16 million subject to the normalization requirements continued by the TCJA).

In March 2018, Winter Storms Riley and Quinn caused damage to the Utilities’ electric distribution systems and interrupted service to approximately 209,000 CECONY customers, 93,000 O&R customers and 44,000 RECO customers. Through December 31, 2018, CECONY's costs related to March 2018 storms, including Riley and Quinn, amounted to $133 million, including operation and maintenance expenses reflected in its electric rate plan ($15 million), operation and maintenance expenses charged against a storm reserve pursuant to its electric rate plan ($83 million), capital expenditures ($29 million) and removal costs ($6 million). O&R and RECO had storm-related costs of $43 million and $17 million, respectively, most of which were deferred as regulatory assets pursuant to their electric rate plans. Recovery of CECONY and O&R storm-related costs is subject to review by the NYSPSC, and recovery of RECO storm-related costs is subject to review by the NJBPU. The NYSPSC is investigating the preparation and response to the storms by CECONY, O&R, and other New York electric utilities, including all aspects of their emergency response plans, and may penalize them. In July 2018, the NJBPU adopted NJBPU staff's recommendations to increase requirements for New Jersey utilities, including RECO, relating to pre-storm preparations, restoration of service and communications and outreach. The Companies are unable to estimate the amount or range of their possible loss in connection with the storms.

In May 2018, FERC denied a complaint the NJBPU filed with FERC seeking the re-allocation to CECONY of certain PJM Interconnection LLC (PJM) transmission costs that had been allocated to the company prior to April 2017 when transmission service provided to the company pursuant to the PJM open access transmission tariff terminated. The transmission service terminated because the company did not exercise its option to continue the service following a series of requests PJM had submitted to FERC that substantially increased the charges for the transmission service. CECONY challenged each of these requests. FERC rejected all but one of CECONY’s protests. In June 2015 and May 2016, CECONY filed appeals of certain FERC decisions with the U.S. Court of Appeals. In July 2018, FERC established a settlement proceeding relating to the allocation of PJM transmission costs. Under CECONY’s electric rate plan, unless and until changed by the NYSPSC, the company will recover all charges incurred associated with the transmission service.

In July 2018, the NYSPSC commenced an investigation into the rupture of a CECONY steam main (see Note H).

Regulatory Assets and Liabilities

Regulatory assets and liabilities at December 31, 2018 and 2017 were comprised of the following items:



	Con Edison		CECONY
(Millions of Dollars)	2018	2017	2018	2017
Regulatory assets
Unrecognized pension and other postretirement costs	$2,238	$2,526	$2,111	$2,376
Environmental remediation costs	810	793	716	677
Revenue taxes	291	260	278	248
MTA power reliability deferral	229	50	229	50
Property tax reconciliation	101	51	86	25
Deferred storm costs	76	38	—	—
Pension and other postretirement benefits deferrals	73	79	56	58
Municipal infrastructure support costs	67	56	67	56
System peak reduction and energy efficiency programs	72	14	70	14
Brooklyn Queens demand management program	39	37	39	37
Unamortized loss on reacquired debt	36	37	34	35
Meadowlands heater odorization project	36	18	36	18
Preferred stock redemption	23	24	23	24
Recoverable REV demonstration project costs	20	19	18	17
Deferred derivative losses	17	44	11	37
Gate station upgrade project	17	13	17	13
Indian Point Energy Center program costs	13	29	13	29
Workers’ compensation	5	10	5	10
Recoverable energy costs	3	60	—	52
O&R transition bond charges	2	9	—	—
Surcharge for New York State assessment	—	2	—	2
Other	126	97	114	85
Regulatory assets – noncurrent	4,294	4,266	3,923	3,863
Recoverable energy costs	40	27	35	25
Deferred derivative losses	36	40	29	37
Regulatory assets – current	76	67	64	62
Total Regulatory Assets	$4,370	$4,333	$3,987	$3,925
Regulatory liabilities
Future income tax*	$2,515	$2,545	$2,363	$2,390
Allowance for cost of removal less salvage	928	846	790	719
TCJA net benefits	434	—	411	—
Energy efficiency portfolio standard unencumbered funds	127	127	122	122
Net unbilled revenue deferrals	117	183	117	183
Pension and other postretirement benefit deferrals	62	207	40	181
Property tax refunds	45	44	45	44
Settlement of prudence proceeding	37	66	37	66
Property tax reconciliation	36	107	36	107
Earnings sharing - electric, gas and steam	36	29	27	19
System benefit charge carrying charge	27	12	24	11
Carrying charges on repair allowance and bonus depreciation	21	43	21	42
BQDM and REV Demo reconciliations	18	9	18	9
New York State income tax rate change	17	36	17	35
Settlement of gas proceedings	15	27	15	27
Base rate change deferrals	10	21	10	21
Unrecognized other postretirement costs	7	92	7	92
Net utility plant reconciliations	3	12	1	8
Variable-rate tax-exempt debt - cost rate reconciliation	1	30	1	26
Other	185	141	156	117
Regulatory liabilities – noncurrent	4,641	4,577	4,258	4,219
Revenue decoupling mechanism	53	29	36	21
Refundable energy costs	31	41	8	16
Deferred derivative gains	30	31	29	28
Regulatory liabilities—current	114	101	73	65
Total Regulatory Liabilities	$4,755	$4,678	$4,331	$4,284

* See "Federal Income Tax" in Note A, "Other Regulatory Matters," above, and Note L.

Unrecognized pension and other postretirement costs represent the net regulatory asset associated with the accounting rules for retirement benefits. See Note A.

Revenue taxes represent the timing difference between taxes collected and paid by the Utilities to fund mass transportation.

Deferred storm costs represent response and restoration costs, other than capital expenditures, in connection with Superstorm Sandy and other major storms that were deferred by the Utilities.

Settlement of prudence proceeding represents the remaining amount to be credited to customers pursuant to a Joint Proposal, approved by the NYSPSC in April 2016, with respect to the prudence of certain CECONY expenditures and related matters.

Settlement of gas proceedings represents the amount to be credited to customers pursuant to a settlement agreement approved by the NYSPSC in February 2017 related to CECONY’s practices of qualifying persons to perform plastic fusions on gas facilities and alleged violations of gas safety violations identified by the NYSPSC staff in its investigation of a March 2014 Manhattan explosion and fire (see Note H).

The NYSPSC has authorized CECONY to accrue unbilled electric, gas and steam revenues. CECONY has deferred the net margin on the unbilled revenues for the future benefit of customers by recording a regulatory liability of $117 million and $183 million at December 31, 2018 and 2017, respectively, for the difference between the unbilled revenues and energy cost liabilities.