| Regulatory Matters |
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 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. 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 cost of 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 2017 – December 2019 | | January 2020 – December 2022 (a) | Base rate changes | | Yr. 1 – $195 million (b)
Yr. 2 – $155 million (b)
Yr. 3 – $155 million (b) | | Yr. 1 – $113 million (c)
Yr. 2 – $370 million (c)
Yr. 3 – $326 million (c) | Amortizations to income of net regulatory (assets) and liabilities | | Yr. 1 – $84 million
Yr. 2 – $83 million
Yr. 3 – $69 million | | Yr. 1 – $267 million (d)
Yr. 2 – $269 million (d)
Yr. 3 – $272 million (d) | Other revenue sources | | 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, 2018 and 2019, the company recorded $13 million, $25 million and $43 million of earnings adjustment mechanism incentives for energy efficiency, respectively. The company also achieved $5 million of incentives for service terminations in 2017, 2018 and 2019 that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018 and 2019, the company recorded $3 million and $7 million of incentives for service terminations, respectively. | | 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 - $69 million
Yr. 2 - $74 million
Yr. 3 - $79 million
| Revenue decoupling mechanisms | | Continuation of reconciliation of actual to authorized electric delivery revenues.
In 2017, 2018 and 2019, the company deferred for customer benefit $45 million, $(6) million and $169 million of revenues, respectively. | | Continuation of reconciliation of actual to authorized electric delivery revenues. | Recoverable energy costs | | Continuation of current rate recovery of purchased power and fuel costs. | | Continuation of current rate recovery of purchased power and fuel costs. | Negative revenue adjustments | | Potential charges 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. In 2019, the company recorded negative revenue adjustments of $15 million. | | Potential charges if certain performance targets relating to service, reliability, safety and other matters are not met:
Yr. 1 - $450 million
Yr. 2 - $461 million
Yr. 3 - $476 million |
| | | | | | Cost reconciliations | | Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates (g).
In 2017, 2018 and 2019, the company deferred $35 million, $189 million and $10 million of net regulatory assets, respectively. | | Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g) | Net utility plant reconciliations | | 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 and 2019, $0.4 and $11.8 million was deferred as a regulatory liability, respectively.
| | Target levels reflected in rates:
Electric average net plant target excluding advanced metering infrastructure (AMI):
Yr. 1 - $24,491 million
Yr. 2 - $25,092 million
Yr. 3 - $25,708 million
AMI:
Yr. 1 - $572 million
Yr. 2 - $740 million
Yr. 3 - $806 million (h) | Average rate base | | Yr. 1 – $18,902 million
Yr. 2 – $19,530 million
Yr. 3 – $20,277 million | | Yr. 1 - $21,660 million
Yr. 2 - $22,783 million
Yr. 3 - $23,926 million | Weighted average cost of capital (after-tax) | | Yr. 1 – 6.82 percent
Yr. 2 – 6.80 percent
Yr. 3 – 6.73 percent | | 6.61 percent | Authorized return on common equity | | 9.0 percent | | 8.80 percent | Actual return on common equity (i) | | Yr. 1 – 9.30 percent
Yr. 2 – 9.36 percent
Yr. 3 – 8.82 percent
| |
| Earnings sharing | | 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 and 2019, the company had no earnings sharing above the threshold. | | Most earnings above an annual earnings threshold of 9.3 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 – 4.93 percent
Yr. 2 – 4.88 percent
Yr. 3 – 4.74 percent | | 4.63 percent | Common equity ratio | | 48 percent | | 48 percent |
| | (a) | In January 2020, the NYSPSC approved the October 2019 Joint Proposal for CECONY's electric rate plan for January 2020 through December 2022. If at the end of any semi-annual period ending June 30 and December 31, Con Edison’s investments in its non-utility businesses exceed 15 percent of its 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. |
| | (b) | The electric base rate increases were 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 were 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 10-year period, including the overall pre-tax rate of return on such costs. |
| | (c) | Base rates reflect recovery by the company of certain costs of its energy efficiency, Reforming the Energy Vision demonstration projects, non-wire alternative projects (including the Brooklyn Queens demand management program), and off-peak electric vehicle charging programs (Yr. 1 - $206 million; Yr. 2 - $245 million; and Yr. 3 - $251 million) over a ten-year period, including the overall pre-tax rate of return on such costs. |
| | (d) | Amounts reflect amortization of the 2018 tax savings under the federal Tax Cuts and Jobs Act of 2017 (TCJA) allocable to CECONY’s electric customers ($377 million) over a three-year period ($126 million annually), the protected portion of the regulatory liability for excess deferred income taxes allocable to CECONY’s electric customers ($1,663 million) over the remaining lives of the related assets ($49 million in Yr. 1, $50 million in Yr. 2, and $53 million in Yr. 3) and the unprotected portion of the net regulatory liability ($784 million) over five years ($157 million annually). Amounts also reflect amortization of the regulatory asset for deferred MTA power reliability costs ($238 million) over a five-year period ($48 million annually). |
| | (e) | 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. |
| | (f) | 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, subject to certain conditions, of |
30 percent of the amount reflected in the January 2017-December 2019 rate plan and 15 percent of the amount reflected in the January 2020-December 2022 rate plan. | | (g) | In addition, the NYSPSC staff has commenced a focused operations audit to investigate the income tax accounting of CECONY and other New York utilities. Any NYSPSC-ordered adjustment to CECONY’s income tax accounting will be refunded to or collected from customers, as determined by the NYSPSC. See "Other Regulatory Matters," below. |
| | (h) | Reconciliation of net utility plant for AMI will be done on a combined basis for electric and gas. |
| | (i) | Calculated in accordance with the earnings calculation method prescribed in the rate order. |
| | | | | | CECONY – Gas | | | | | Effective period | | January 2017 - December 2019 | | January 2020 – December 2022 (a) | Base rate changes | | Yr. 1 – $(5) million (b)
Yr. 2 – $92 million
Yr. 3 – $90 million | | Yr. 1 – $84 million (c)
Yr. 2 – $122 million (c)
Yr. 3 – $167 million (c) | Amortizations to income of net regulatory (assets) and liabilities | | Yr. 1 – $39 million
Yr. 2 – $37 million
Yr. 3 – $36 million | | Yr. 1 – $45 million (d)
Yr. 2 – $43 million (d)
Yr. 3 – $10 million (d) | Other revenue sources | | 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, 2018 and 2019, the company achieved incentives of $7 million, $6 million and $7 million, respectively, that, pursuant to the rate plan, is being recorded ratably in earnings from 2018 to 2020. In 2018 and 2019, the company recorded incentives of $5 million and $9 million, respectively, for gas leak backlog, leak prone pipe and service terminations. | | Retention of annual revenues from non-firm customers of up to $65 million and 15 percent of any such revenues above $65 million.
Potential earnings adjusted mechanism incentives for energy efficiency and other potential incentives of up to:
Yr. 1 - $20 million
Yr. 2 - $22 million
Yr. 3 - $25 million | Revenue decoupling mechanisms | | Continuation of reconciliation of actual to authorized gas delivery revenues.
In 2017, 2018 and 2019, the company deferred $3 million, $12 million and $10 million of regulatory liabilities, respectively. | | Continuation of reconciliation of actual to authorized gas delivery revenues, modified to be calculated based upon revenue per customer class instead of revenue per customer. | Recoverable energy costs | | Continuation of current rate recovery of purchased gas costs. | | Continuation of current rate recovery of purchased gas costs. | Negative revenue adjustments | | Potential charges 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 negative revenue adjustments of $5 million and $4 million, respectively. In 2019, the company did not record any negative revenue adjustments. | | Potential charges if performance targets relating to service, safety and other matters are not met:
Yr. 1 - $81 million
Yr. 2 - $88 million
Yr. 3 - $96 million | Cost reconciliations | | Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate tax-exempt debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g)
In 2017, 2018 and 2019, the company deferred $2 million of net regulatory liabilities, $44 million of net regulatory assets and $18 million of net regulatory assets, respectively. | | Continuation of reconciliation of expenses for pension and other postretirement benefits, variable-rate debt, major storms, property taxes (e), municipal infrastructure support costs (f), the impact of new laws and environmental site investigation and remediation to amounts reflected in rates. (g) | Net utility plant reconciliations | | 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. In 2019, the company deferred $1.7 million as a regulatory liability. | | Target levels reflected in rates:
Gas average net plant target excluding AMI:
Yr. 1 - $8,108 million
Yr. 2 - $8,808 million
Yr. 3 - $9,510 million
AMI:
Yr. 1 - $142 million
Yr. 2 - $183 million
Yr. 3 - $211 million (h) | Average rate base | | Yr. 1 – $4,841 million
Yr. 2 – $5,395 million
Yr. 3 – $6,005 million | | Yr. 1 - $7,171 million
Yr. 2 - $7,911 million
Yr. 3 - $8,622 million | Weighted average cost of capital
(after-tax) | | Yr. 1 – 6.82 percent
Yr. 2 – 6.80 percent
Yr. 3 – 6.73 percent | | 6.61 percent | Authorized return on common equity | | 9.0 percent | | 8.80 percent | Actual return on common equity (i) | | Yr. 1 – 9.22 percent
Yr. 2 – 9.04 percent
Yr. 3 – 8.72 percent
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| | | | | | Earnings sharing | | 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, 2018 and 2019, the company had no earnings above the threshold. | | Most earnings above an annual earnings threshold of 9.3 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 – 4.93 percent
Yr. 2 – 4.88 percent
Yr. 3 – 4.74 percent | | 4.63 percent | Common equity ratio | | 48 percent | | 48 percent |
| | (a) | In January 2020, the NYSPSC approved the October 2019 Joint Proposal for CECONY's gas rate plan for January 2020 through December 2022. If at the end of any semi-annual period ending June 30 and December 31, Con Edison’s investments in its non-utility businesses exceed 15 percent of its 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. |
| | (b) | The gas base rate decrease was offset by a $41 million increase resulting from the December 2016 expiration of a temporary credit under the prior rate plan. |
| | (c) | The gas base rate increases shown above will be implemented with increases of $47 million in Yr. 1; $176 million in Yr. 2; and $170 million in Yr. 3 in order to levelize customer bill impacts. Base rates reflect recovery by the company of certain costs of its energy efficiency program (Yr. 1 - $30 million; Yr. 2 - $37 million; and Yr. 3 - $40 million) over a ten-year period, including the overall pre-tax rate of return on such costs. |
| | (d) | Amounts reflect amortization of the remaining 2018 TCJA tax savings allocable to CECONY’s gas customers ($63 million) over a two year period ($32 annually), the protected portion of the regulatory liability for excess deferred income taxes allocable to CECONY’s gas customers ($725 million) over the remaining lives of the related assets ($14 million in Yr. 1, $14 million in Yr. 2, and $12 million in Yr. 3) and the unprotected portion of the net regulatory liability ($107 million) over five years ($21 million annually) |
| | (e)-(i) | See footnotes (e) - (i) to the table under “CECONY Electric,” above. |
| | | | | | 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
Yr. 6 – 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 charges (up to $1 million annually) if certain steam performance targets are not met. In years 2014 through 2019, the company did not record any negative revenue adjustments. | |
| Cost reconciliations (c) | | In 2014, 2015, 2016, 2017, 2018 and 2019, the company deferred $42 million of net regulatory liabilities, $17 million of net regulatory assets, $8 million and $14 million of net regulatory liabilities, $1 million of net regulatory assets and $8 million of net regulatory liabilities, 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, 2018 and 2019. | |
| 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 (d) | | 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
Yr. 6 – 10.45 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 $16.5 million above the threshold, and an additional $1.1 million related to 2017 was recorded. In 2019 actual earnings were $5 million above the threshold, offset in part by an adjustment related to 2018 of $2.3 million. | |
| 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 | |
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| | (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. |
| | (d) | Calculated in accordance with the earnings calculation method prescribed in the rate order. |
| | | | | | 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
Yr. 3 - $4.2 million
Potential incentive if performance target related to service terminations is met: $0.5 million annually.
In 2019, the company recorded $2.6 million of earnings adjustment mechanism incentives for energy efficiency and $0.2 million of incentives for service terminations. | 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.
In 2019 the company deferred $0.1 million as a regulatory asset. | 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 charges (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 charges if certain performance targets relating to service, reliability and other matters are not met:
Yr. 1 - $4.4 million
Yr. 2 - $4.4 million
Yr. 3 - $4.5 million
In 2019, the company did not record any negative revenue adjustments.
| 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)
In 2019, the company deferred $4.3 million as a net regulatory asset.
| 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
The company increased regulatory asset by an immaterial amount in 2019. | 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 | | 9.0 percent
| Actual return on common equity (k) | | Yr. 1 – 10.8 percent
Yr. 2 – 9.7 percent
Yr. 3 – 7.2 percent
| | Yr. 1 – 9.6 percent
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| | | | | | 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.
In 2019, earnings did not exceed the earnings threshold.
| 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 continued in effect until the subsequent rate plan became effective. |
| | (b) | $59.3 million of the regulatory asset for deferred storm costs is to be recovered from customers over a 5 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 electric base rate increases shown above will 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. |
| | (k) | Calculated in accordance with the earnings calculation method prescribed in the rate order. |
| | | | | | 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.
In 2019, the company recorded $0.3 million of earnings adjustment mechanism incentives for energy efficiency and $0.7 million of incentives for gas leak backlog, leak prone pipe and service terminations. | 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.
In 2019, the company deferred $0.8 million of regulatory assets. | Recoverable energy costs | | Current rate recovery of purchased gas costs. | | Continuation of current rate recovery of purchased gas costs. | Negative revenue adjustments | | Potential charges (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 charges 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.
In 2019, the company recorded a $0.2 million negative revenue adjustment.
| 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)
In 2019, the company deferred $6 million as net regulatory liabilities.
| 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
In 2019, the company deferred an immaterial amount as regulatory asset.
| 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 | | 9.0 percent | Actual return on common equity (k) | | Yr. 1 – 11.2 percent
Yr. 2 – 9.7 percent
Yr. 3 – 8.1 percent
| | Yr. 1 – 8.9 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. In 2019, earnings did not exceed the earnings threshold.
| 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 continued in effect until the subsequent rate plan became effective. |
| | (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) | 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 gas base rate changes shown above will be implemented with changes of: Yr. 1 - $(5.9) million; Yr. 2 - $1.0 million; and Yr. 3 - $1.0 million. |
(f)-(k) See footnotes (f) - (k) to the table under “O&R New York - Electric,” above.
In January 2020, the NJBPU approved an electric rate increase, effective February 1, 2020, of $12 million for RECO. The following table contains a summary of the terms of the distribution rate plans. | | | | | | RECO | | | | | Effective period | | March 2017 – January 2020 | | February 2020 | Base rate changes | | Yr. 1 – $1.7 million | | Yr. 1 – $12 million | Amortization to income of net regulatory (assets) and liabilities | | $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 (a) | | $4.8 million over four years. | Recoverable energy costs | | Current rate recovery of purchased power costs. | | Current rate recovery of purchased power costs. | Cost reconciliations | | None | | None | Average rate base | | Yr. 1 – $178.7 million | | Yr. 1 – $229.9 million | Weighted average cost of capital (after-tax) | | 7.47 percent | | 7.11 percent | Authorized return on common equity | | 9.6 percent | | 9.5 percent | Actual return on common equity | | Yr. 1 – 7.5 percent
Yr. 2 – 5.7 percent
| |
| Cost of long-term debt | | 5.37 percent | | 4.88 percent | Common equity ratio | | 49.7 percent | | 48.32 percent |
| | (a) | 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 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 federal Tax Cuts and Jobs Act of 2017 (TCJA) as measured based on amounts reflected in its rate plans prior to the enactment of the TCJA in December 2017. 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, under its electric rate plan that was approved in January 2020, is amortizing its TCJA net benefits prior to January 1, 2019 allocable to its electric customers ($377 million) over a three-year period, the “protected” portion of its net regulatory liability for future income taxes related to certain accelerated tax depreciation benefits allocable to its electric customers ($1,663 million) over the remaining lives of the related assets and the remainder, or “unprotected” portion of the net regulatory liability allocable to its electric customers ($784 million) over a five-year period. CECONY, under its gas rate plan that was approved in January 2020, is amortizing its remaining TCJA net benefits prior to January 1, 2019 allocable to its gas customers ($63 million) over a two-year period, the protected portion of its net regulatory liability for future income taxes allocable to its gas customers ($725 million) over the remaining lives of the related assets and the unprotected portion of the net regulatory liability allocable to its gas customers ($107 million) over a five-year period. See footnote (d) to the CECONY - Electric and Gas tables under “Rate Plans,” above.
CECONY's net benefits prior to October 1, 2018 allocable to the company’s steam customers ($15 million) are being 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 steam customers ($185 million) is being amortized over the remaining lives of the related assets (with the amortization period for the unprotected portion subject to review in its next steam rate proceeding).
O&R, under its current electric and gas rate plans, has reflected its TCJA net benefits in its electric and gas rates beginning as of January 1, 2019. Under the rate plans, O&R is amortizing its net benefits prior to January 1, 2019 ($22 million) over a three-year period, the protected portion of its net regulatory liability for future income taxes ($123 million) over the remaining lives of the related assets and the unprotected portion ($30 million) over a fifteen-year period. See "Rate Plans," above.
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. The Utilities are unable to estimate the amount or range of their possible loss related to this matter. At December 31, 2019, the Utilities had not accrued a liability related to this matter.
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. At December 31, 2019, CECONY's costs related to March 2018 storms, including Riley and Quinn, amounted to $134 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 ($84 million), capital expenditures ($29 million) and removal costs ($6 million). At December 31, 2019, O&R and RECO costs related to 2018 storms amounted to $43 million and $17 million, respectively, most of which were deferred as regulatory assets pursuant to their electric rate plans. In January 2019, O&R began recovering its deferred storm costs over a six-year period in accordance with its New York electric rate plan. The NYSPSC investigated 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. In April 2019, following the issuance of a NYSPSC staff report on the investigation, the NYSPSC ordered the utilities to show cause why the NYSPSC should not commence a penalty action against them for violating their emergency response plans. The Utilities are unable to estimate the amount or range of their possible loss related to this matter. At December 31, 2019, the Utilities had not accrued a liability related to this matter.
In July 2018, the NYSPSC commenced an investigation into the rupture of a CECONY steam main located on Fifth Avenue and 21st Street in Manhattan. Debris from the incident included dirt and mud containing asbestos. The response to the incident required the closing of buildings and streets for various periods. The NYSPSC has commenced an investigation. As of December 31, 2019, with respect to the incident, the company incurred operating costs of $17 million for property damage, clean-up and other response costs and invested $9 million in capital and retirement costs. The company is unable to estimate the amount or range of its possible loss related to the incident. At December 31, 2019, the company had not accrued a liability related to the incident.
In March 2019, the NYSPSC ordered CECONY to show cause why the NYSPSC should not commence a penalty action and prudence proceeding against CECONY for alleged violations of gas operator qualification, performance, and inspection requirements. At December 31, 2019, the company had accrued a $10 million liability related to this matter.
On July 13, 2019, electric service was interrupted to approximately 72,000 CECONY customers on the west side of Manhattan. The NYSPSC and the Northeast Power Coordinating Council, a regional reliability entity, are investigating the July 13, 2019 power outage. Pursuant to the major outage reliability performance provisions of its electric rate plan, as a result of the July 13, 2019 power outage, the company recorded a $5 million negative revenue adjustment. The NYSPSC is also investigating other CECONY power outages that occurred in July 2019, primarily in the Flatbush area of Brooklyn. Primarily due to these outages, pursuant to the rate plan’s annual non-network outage frequency and non-network outage duration reliability performance provisions, the company recorded a $10 million negative revenue adjustment. The company is unable to estimate the amount or range of its possible additional loss related to these power outages. Regulatory Assets and Liabilities Regulatory assets and liabilities at December 31, 2019 and 2018 were comprised of the following items: | | | | | | | | | | Con Edison | CECONY | (Millions of Dollars) | 2019 |
| 2018 | 2019 |
| 2018 |
| Regulatory assets | | | | | Unrecognized pension and other postretirement costs | $2,541 | $2,238 | $2,403 | $2,111 | Environmental remediation costs | 732 | 810 | 647 | 716 | Revenue taxes | 321 | 291 | 308 | 278 | MTA power reliability deferral | 248 | 229 | 248 | 229 | Property tax reconciliation | 219 | 101 | 210 | 86 | System peak reduction and energy efficiency programs | 131 | 72 | 130 | 70 | Deferred derivative losses | 83 | 17 | 76 | 11 | Municipal infrastructure support costs | 75 | 67 | 75 | 67 | Pension and other postretirement benefits deferrals | 71 | 73 | 47 | 56 | Deferred storm costs | 77 | 76 | — |
| — |
| Brooklyn Queens demand management program | 39 | 39 | 39 | 39 | Meadowlands heater odorization project | 35 | 36 | 35 | 36 | Unamortized loss on reacquired debt | 28 | 36 | 26 | 34 | Preferred stock redemption | 22 | 23 | 22 | 23 | Recoverable REV demonstration project costs | 21 | 20 | 19 | 18 | Gate station upgrade project | 19 | 17 | 19 | 17 | Non-wire alternative projects | 14 | 3 | 14 | 3 | Workers’ compensation | 3 | 5 | 3 | 5 | O&R transition bond charges | — |
| 2 | — |
| — |
| Other | 180 | 139 | 166 | 124 | Regulatory assets – noncurrent | 4,859 | 4,294 | 4,487 | 3,923 | Deferred derivative losses | 128 | 36 | 113 | 29 | Recoverable energy costs | — |
| 40 | — |
| 35 | Regulatory assets – current | 128 | 76 | 113 | 64 | Total Regulatory Assets | $4,987 | $4,370 | $4,600 | $3,987 | Regulatory liabilities | | | | | Future income tax* | $2,426 | $2,515 | $2,275 | $2,363 | Allowance for cost of removal less salvage | 989 | 928 | 843 | 790 | TCJA net benefits | 471 | 434 | 454 | 411 | Net unbilled revenue deferrals | 199 | 117 | 199 | 117 | Net proceeds from sale of property | 173 | 6 | 173 | 6 | Energy efficiency portfolio standard unencumbered funds | 122 | 127 | 118 | 122 | Pension and other postretirement benefit deferrals | 75 | 62 | 46 | 40 | System benefit charge carrying charge | 48 | 27 | 44 | 24 | Property tax refunds | 45 | 45 | 45 | 45 | BQDM and REV Demo reconciliations | 27 | 18 | 26 | 18 | Earnings sharing - electric, gas and steam | 22 | 36 | 15 | 27 | Settlement of gas proceedings | 10 | 15 | 10 | 15 | Unrecognized other postretirement costs | 9 | 7 | — |
| 7 | Settlement of prudence proceeding | 8 | 37 | 8 | 37 | Property tax reconciliation | — |
| 36 | — |
| 36 | Other | 203 | 231 | 171 | 200 | Regulatory liabilities – noncurrent | 4,827 | 4,641 | 4,427 | 4,258 | Refundable energy costs | 44 | 31 | 12 | 8 | Deferred derivative gains | 34 | 30 | 34 | 29 | Revenue decoupling mechanism | 24 | 53 | 17 | 36 | Regulatory liabilities—current | 102 | 114 | 63 | 73 | Total Regulatory Liabilities | $4,929 | $4,755 | $4,490 | $4,331 |
* 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.
MTA power reliability deferral represents CECONY’s costs in excess of those reflected in its prior electric rate plan to take certain actions relating to the electrical equipment that serves the Metropolitan Transportation Authority (MTA) subway system. The company is recovering this regulatory asset pursuant to its current electric rate plan. See footnote (d) to the CECONY - Electric table under “Rate Plans,” above. 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 O&R.
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 $199 million and $117 million at December 31, 2019 and 2018, respectively, for the difference between the unbilled revenues and energy cost liabilities. Electricity Purchase AgreementsThe Utilities have electricity purchase agreements with non-utility generators and others for generating capacity. The Utilities recover their purchased power costs in accordance with provisions approved by the applicable state public utility regulators. See “Recoverable Energy Costs” in Note A. The Utilities also conducted auctions and have entered into various other electricity purchase agreements. Assuming performance by the parties to the electricity purchase agreements, the Utilities are obligated over the terms of the agreements to make capacity and other fixed payments. The future capacity and other fixed payments under the electricity purchase agreements are estimated to be as follows: | | | | | | | | | | | | | (Millions of Dollars) | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | All Years Thereafter | Con Edison | $172 | | $101 | | $62 | | $57 | | $55 | | $546 | CECONY | 169 | | 99 | | 62 | | 57 | | 55 | | 546 |
For energy delivered under most of the electricity purchase agreements, CECONY is obligated to pay variable prices. The company’s payments under its agreements for capacity, energy and other fixed payments in 2019, 2018 and 2017 were as follows: | | | | | | | | | | | For the Years Ended December 31, | (Millions of Dollars) | 2019 |
| | 2018 |
| | 2017 | Indian Point (a) |
| $— |
| | $6 | | $211 | Linden Cogeneration (b) | — |
| | — |
| | 114 | Astoria Generating Company (c) | 116 | | 179 | | 92 | Brooklyn Navy Yard (d) | 115 | | 124 | | 117 | Cogen Technologies | — |
| | 9 | | 18 | Total | $231 | | $318 | | $552 |
(a) Contract term ended in 2018. (b) Contract term ended in 2017. (c) Capacity purchase agreements with terms ending in 2020 and 2021. (d) Contract for plant output, which started in 1996 and ends in 2036.
|