Source: https://www.scribd.com/document/111735276/NMPC-Term-Sheet-2
Timestamp: 2017-02-25 02:29:16
Document Index: 741171861

Matched Legal Cases: ['§ 113', '§ 113', '§25', 'ART 255', 'ART 261', 'ART 255', 'ART 261']

NMPC Term Sheet (2) | Deferral
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October 31, 2012 Honorable Jaclyn A. Brilling, Secretary State of New York Public Service Commission Office of the Secretary, 19th Floor Three Empire State Plaza Albany, New York 12223-1350 CASE 12-E-0201 - Proceeding on Motion of the Commission as to the Rates, Charges, Rules and Regulations of Niagara Mohawk Power Corporation d/b/a National Grid for Electric Service CASE 12-G-0202 - Proceeding on Motion of the Commission as to the Rates, Charges, Rules and Regulations of Niagara Mohawk Power Corporation d/b/a National Grid for Gas Service Dear Secretary Brilling: Pursuant to the Order issued by the Administrative Law Judges on October 22, 2012 in the above referenced proceedings, attached for filing is the Term Sheet that sets forth the key terms of the settlement agreement among Niagara Mohawk Power Corporation d/b/a National Grid, Department of Public Service Staff, Multiple Intervenors and other parties that may execute the Joint Proposal. This Term Sheet does not reflect the final agreement of the parties and is subject to modification. The parties acceptance of the terms set forth in this Term Sheet is conditioned upon execution of a Joint Proposal.
Respectfully submitted, Catherine L. Nesser_________ Catherine L. Nesser
One MetroTech Center, Brooklyn, New York 11201 T: 718.403.3073catherine.nesser@us.ngrid.com www.nationalgrid.com
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal.
Niagara Mohawk Power Corporation d/b/a National Grid Cases 12-E-0201 and 12-G-0202 Settlement Term Sheet
This Term Sheet sets forth a summary of the principal terms to be included in a joint proposal (“Joint Proposal”) that resolves all aspects of Niagara Mohawk Power Corporation’s (“Company” or “Niagara Mohawk”) electric and gas rate filings in Cases 12-E-0201 and 12-G0202. The Joint Proposal will cover a three-year period commencing April 1, 2013. It will provide for an increase in the electric revenue requirement of $43.395 million for the period April 1, 2013 through March 31, 2014 (“Rate Year One”), $51.361 million for the period April 1, 2014 through March 31, 2015 (“Rate Year Two”), and $28.342 million for the period April 1, 2015 through March 31, 2016 (“Rate Year Three”). It also will provide for a decrease in the gas revenue requirement of $3.290 million in Rate Year One and increases of $5.854 million and $6.268 million in Rate Year Two and Rate Year Three, respectively. The rate plan is timed such that new electric delivery rates will replace a portion of an expiring annualized electric surcharge. The net result is a decrease in electric delivery revenues, continued rate stability and, for most customers, lower electric delivery bills. In addition, a portion of the forecast balance of electric and gas deferred credits will be amortized to mitigate rate impacts on electric and gas customers. II. Revenue Requirements A. Attached as Appendix A is a spreadsheet that sets forth the derivation of the settlement electric (Schedule 1) and gas (Schedule 2) revenue requirements. The settlement revenue requirements are based on the following parameters: 1. 2. A return on equity of 9.3%. The 9.3% includes a stay out premium reflecting the three year term of the rate plan. A capital structure and overall cost of capital consisting of the following components and cost rates:
Rate Year One
% of Capital Long Term Debt Short Term Debt Total Debt Customer Deposits Preferred Stock Common Equity Total Capital 49.71% 1.01% 50.72% 0.72% 0.56% 48.00% 100.00%
Annual Cost 4.04% 0.46% 1.65% 3.66% 9.30%
Weighted Cost Percent 2.01% 0.00% 0.01% 0.02% 4.46% 6.50%
Weighted Cost Pre Tax 2.01% 0.00% 0.01% 0.03% 7.39% 9.44%
Rate Year Two % of Capital Long Term Debt Short Term Debt Total Debt Customer Deposits Preferred Stock Common Equity Total Capital 49.95% 0.83% 50.78% 0.69% 0.53% 48.00% 100.00% Annual Cost 4.32% 0.46% 1.65% 3.66% 9.30% Weighted Cost Percent 2.16% 0.00% 0.01% 0.02% 4.46% 6.65% Weighted Cost Pre Tax 2.16% 0.00% 0.01% 0.03% 7.39% 9.59%
Rate Year Three % of Capital Long Term Debt Short Term Debt Total Debt Customer Deposits Preferred Stock Common Equity Total Capital 48.71% 2.16% 50.87% 0.64% 0.49% 48.00% 100.00% Annual Cost 4.82% 0.46% 1.65% 3.66% 9.30% Weighted Cost Percent 2.35% 0.01% 0.01% 0.02% 4.46% 6.85% Weighted Cost Pre Tax 2.35% 0.01% 0.01% 0.03% 7.39% 9.79%
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. 3. As set forth in Appendix A, a Rate Year One electric rate base of $4,107.2 million and a gas rate base of $1,086.0 million, a Rate Year Two electric rate base of $4,365.4 million and a gas rate base of $1,122.3 million, and a Rate Year Three electric rate base of $4,625.9 million and a gas rate base of $1,162.8 million. The Company will credit to customers a portion of the forecast electric deferral balance in the amount of $16.137 million in Rate Year One and $19.578 million in Rate Year Two. In addition, the Company will credit to customers a portion of the forecast gas deferral balance in the amount of $21.990 million in Rate Year One and $10.788 million in Rate Year Two. The deferral credits will be calculated by taking a pro rata share from the overall deferred credit balances (including pension and other post employment benefits (“OPEB”)). The gas transmission and distribution depreciation rates, as proposed by Staff, are set forth in Appendix B. There are no changes to the electric, common and gas general depreciation rates.
Electric Revenue Allocation and Rate Design A. Revenue Forecast 1. The load forecast will be the forecast presented in the Company’s corrections and updates filing with one minor revision to correct the customer count. Late Payment Charge Revenues – The agreed to revenue requirement includes late payment charge revenues, which will be calculated consistent with the Company’s rebuttal filing.
Electric and Lighting Rate Design 1. Historic demand will be eliminated for New York Power Authority (“NYPA”) Replacement and Expansion customers beginning April 1, 2013. The billing determinants used to design rates include historic demand, and therefore the reduction in transmission and delivery revenue resulting from the elimination of historic demand will be recovered through the Company’s RDM based on the parent service class. Reduced surcharge revenue will be collected through the reconciliation mechanisms already in place for the respective surcharges. The Company and NYPA agree to pursue any contract amendments that may be necessary to effectuate this provision.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. 2. The following customer charges will change from their current level: a. b. c. 3. 4. 5. The SC-3A secondary/primary customer charge will increase from $902 to $1,000 per month. The SC-3A transmission customer charge will increase from $3,172 to $3,500 per month. The SC-1 customer charge will increase from $16.21 to $17.00 per month.
The SC-2ND – Veterans Organization Option Time of Use offering will be closed and existing customers will be migrated to SC-1 or SC-2ND. The SC-2D – Veterans Organization Time of Use offering will be closed and existing customers will be migrated to SC-1 or SC-2ND. Lighting SC-2 – charge single price for all concrete foundations and restructure underground circuitry charges to simplify current rates and make a phased transition to charging all customers the same rate regardless of type of circuit. Lighting SC-3 LED option (energy only) – each LED light will be assigned a specified billable wattage; volume of electricity billed will be determined by multiplying the assigned wattage amount by the number of hours the light is assumed to be in service.
Electric and Lighting Revenue Allocation 1. Rate Year One – Allocate revenue to achieve the following Service Class delivery rate increases. The information in column two is based on an assumed delivery revenue increase of $42.202 million (exclusive of other revenue changes) and a system average increase of 3.26 percent.
(2) Delivery Revenue Increase 3.88% 1.86% 1.86%
Service Class SC-1 SC-1C SC-2
SC-2D SC-3 Sec SC-3 Pri SC-3 SubT/Tran SC-3A Sec/Pri SC3-A SubT SC-3A Tran Outdoor Lighting
2.33% 2.33% 2.33% 3.26% 3.26% 3.26% 3.10% 1.86%
Rate Year Two and Three – All classes are allocated system average increases. The estimated delivery revenue increase in Rate Year Two is 3.72% when compared to Rate Year One. The estimated delivery revenue increase in Rate Year Three is 1.96% when compared to Rate Year Two. These increases are exclusive of the deferral credit.
Deferral Credit 1. The parties’ preferred approach is as follows: Approximately $35.715 million of the Company’s forecast deferral balance will be credited to customers as follows: a. b. c. 2. Rate Year One - $16.137 million Rate Year Two - $19.578 million Rate Year Three - $0.000
Allocation to service class voltage delivery levels will be based on the ratio of transmission and distribution revenue at present rates as shown in Appendix C, as supported by the Company’s Corrections and Updates filing. The Company will use the same allocators for Rate Years Two and Three as for Rate Year One. The deferral credits will apply to all customers, including the delivery of NYPA allocations. Service class deferral credit will be on a per kWh basis for non-demand classes and on a per kW basis for demand classes. As an alternative, the Joint Proposal will set forth an option of flat rates for the Commission’s consideration.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. E. RDM 1. The RDM will include all customers with SC-12 contracts that provide exclusively for an alternative billing methodology for a NYPA allocation. The RDM does not apply to the NYPA portion of these customers’ load. No RDM surcharges will be allocated to the NYPA portion of these customers’ load. The Company will reconcile on a rate year basis. The Company will reconcile the period from January 1, 2013 through March 31, 2013 to account for the period between the current calendar year reconciliation period and Rate Year One reconciliation period.
Merchant Function Charge 1. Credit and collections component kWh rates will be based on a forecast of full service sales (excluding SC-12 customers) and ESCO customers participating in the purchase of receivables (“POR”) program. Rates will be set for Rate Year One using the Company’s Embedded Cost of Service Study (“ECOSS”) and held constant thereafter. The Company will reconcile commodity-related credit and collections expense on a rate year basis. In addition, the Company will reconcile the period from January 1, 2013 through March 31, 2013 to account for the period between the current calendar year reconciliation period and the Rate Year One reconciliation period. The uncollectibles component will be differentiated between non-demand, demand and street lighting and will be based on the overall uncollectible expense rate of 1.4963 percent. Working capital will be calculated using the Company’s pre-tax WACC. The supply procurement expense component will be updated for Rate Year One, consistent with the Company’s ECOSS, and held constant thereafter. The Company will reconcile supply procurement expenses on a rate year basis. In addition, the Company will reconcile the period from January 1, 2013 through March 31, 2013 to account for the period between the current calendar year reconciliation period and Rate Year One reconciliation period.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. G. Miscellaneous Electric and Lighting Provisions 1. 2. Paperless Billing: Customers electing paperless bills will receive a $0.40 credit per service period. Billing Backout Credit: Updated ESCO billing charges will be $1.24 to an ESCO that supplies electricity to an electric-only customer and $0.62 to an ESCO that supplies electricity to a gas and electric customer. The customer backout credit will equal the ESCO billing charge. Time differentiated delivery rates: Company, Staff, and other interested parties to meet to discuss; provide report on feasibility to Commission by the end of Rate Year One. Time of use commodity rates expanded to include SC-1. Expiration date for Exemption C for SC-7 to be eliminated. NYPA load share for installed capacity (or ICAP) will be determined at the beginning of the next capability period (May 2013) by the ratio of the NYPA Expansion Power/Replacement Power customer’s contract demand to the customer’s peak demand during the month of the New York Control Area system peak (i.e., the non-coincident peak).
Gas Revenue Allocation and Rate Design A. Revenue Forecast 1. 2. The load forecast will be the forecast presented in the Company’s initial testimony. Late Payment Charge Revenues – The agreed to revenue requirement includes late payment charge revenues, which will be calculated consistent with the Company’s rebuttal filing.
Rate Design 1. SC-1 monthly minimum delivery service charge will be set at $20.35 for Rate Years One, Two and Three, which includes the year-to-year increases for the low income program surcharge. If the low income program surcharge increases after Rate Year One, any corresponding decrease in the base customer charge component will be recovered through the usage charge, and the total SC-1 monthly minimum delivery service charge (i.e., low income surcharge plus base customer charge) will remain the same.
For Rate Year One, the total monthly minimum delivery service charge will be equal to the low income surcharge plus the base customer charge. The total minimum delivery service charges for Rate Year One are set forth on Appendix D. For service classes other than SC-1, SC-5 and SC-8, base customer charges in Rate Years Two and Three will remain at Rate Year One levels. The total minimum delivery service charge for those classes will be the base customer charges plus the low income surcharges for Rate Years Two and Three, respectively. For SC-5 and SC-8 customers, the delivery rate increases for Rate Years Two and Three will be assessed in equal percentages to the base customer charge and volumetric block rates. The total minimum delivery service charge for those classes will be the base customer charges plus the low income surcharges for Rate Years Two and Three, respectively.
Revenue Allocation 1. 2. Rate Year One – The distribution rate decrease will be allocated to SC-2, SC-3, and SC-7 on a pro rata basis proportionate to delivery revenues. Rate Years Two and Three – The Joint Proposal will set forth the revenue allocation by class. SC-5 will not receive percentage increases in excess of approximately 2.45% and 2.66% in Rate Years Two and Three, respectively. SC-8 will not receive percentage increases in excess of approximately 2.99% and 3.24% in Rate Years Two and Three, respectively.
Deferral Credit 1. The parties’ preferred approach is as follows: the Company’s forecast deferral balance to be credited to customers will total $32.778 million over the three year rate plan. a. b. c. 2. Rate Year One - $21.990M Rate Year Two -$10.788M Rate Year Three -$0
The Company will allocate deferral credits to firm service classes (excluding SC-9 negotiated transportation and SC-10 natural gas vehicle service) proportionate to delivery revenues as described in the Company’s initial testimony, but including NYSEG, using the
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. allocators set forth in Appendix E, which was included in the Company’s Direct Testimony. The Company will use the same allocators for Rate Years Two and Three as for Rate Year One. A unitized dollar per therm credit will be determined for each service class. 3. E. As an alternative, the Joint Proposal will set forth an option of flat rates for the Commission’s consideration.
Low Income Discount Program 1. Monthly Discount to Minimum Delivery Service Charge a. b. 2. Rate Year One - $10.00 Rate Years Two and Three - minimum of $10.00. Proposal will address the specific discount. The Joint
Monthly Surcharge to Customer Charge a. b. The program will be funded via a surcharge to the customer charge (excluding SC-9 and SC-10). The surcharge to be added to the Company’s proposed customer charges for all service classes except SC-1 (which will be fixed at a monthly minimum delivery service charge of $20.35, inclusive of the low income surcharge – see Section IV(B) Rate Design above) is as follows: i. ii. Rate Year One - $1.17 Rate Years Two and Three - The Joint Proposal will address the specific charge.
Lost And Unaccounted For Gas (“LAUF”) 1. 2. Effective September 1, 2013, the Company will modify the LAUF mechanism consistent with Staff’s draft LAUF White Paper. The current LAUF mechanism remains effective through August 31, 2013. The current LAUF target of 1.62% will remain in effect through March 31, 2013. Thereafter, the effective adjusted target will be 1.841%.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. G. Merchant Function Charge (“MFC”) 1. The following service classifications will be charged all components of the MFC: SC-1, SC-2, SC-3, SC-12, and SC-13. In addition, ESCOs that participate in the POR program will be subject to the commodity-related credit and collections component of the MFC. Return Requirement on Gas Storage Inventory a. Calculation of the return requirement will be modified to reflect actual storage inventory balances. b. The return requirement will be calculated using the Company’s pre-tax WACC on the entire storage balance. c. The Company will reconcile on a rate year basis. d. The period from June 1, 2012 through March 31, 2013 will be reconciled to account for the period between the current June 1 – May 31 reconciliation period and Rate Year One reconciliation period. 3. Gas Purchase Related Working Capital - Implement a new charge to recover the return requirement on gas purchase related working capital using the Company’s pre-tax WACC. Commodity Related Credit and Collection Expenses a. The commodity-related credit and collections annual expense component of the MFC will be based on a forecast of full service sales and sales for ESCO customers participating in the POR program. The rates will be set for Rate Year One using Company’s ECOSS and will be held constant thereafter. b. The unitized dollar per therm rate for commodity-related credit and collection expenses will be determined each year based on an updated sales forecast. c. Recoveries of commodity-related credit and collection expenses will be reconciled to an annual target. d. The unitized charge will be differentiated for residential and nonresidential customers.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. 5. Commodity Related Uncollectible Expenses – The overall uncollectible rate will be 2.6857 percent and will be differentiated for residential and non-residential customers. Gas Supply Procurement Expenses – The supply procurement component will be updated for Rate Year One, consistent with the Company’s ECOSS, and held constant thereafter. a. b. The Company will reconcile on a rate year basis. The Company will reconcile the period from June 1, 2012 through March 31, 2013 to account for the period between the current June 1 - May 31 reconciliation period and Rate Year One reconciliation period.
RDM 1. 2. 3. The RDM will continue to exclude the customer charges associated with the low income program and exclude low income discount. The Company will continue tracking its customer count surrogate. Interest will continue to be applied at the Commission’s Other Customer Capital Rate to the RDM annual reconciliation balance over the amortization period rather than within the year monthly balances. If the annual RDM over or under recovery for any service classification exceeds a five percent materiality threshold based on allowed earnings, the Company will include in its RDM reconciliation filing an analysis of the reasons for the variance and, if appropriate, a proposal to modify its RDM mechanism and targets. Reconciliation will be done on a rate year basis. The Company will reconcile the period from June 1, 2012 through March 31, 2013 to account for the period between the current June 1 – May 31 reconciliation period and Rate Year One reconciliation period.
Net Revenue Sharing Mechanism 1. 2. SC-4 will be eliminated from the delivery revenue targets. The delivery revenue targets for SC-6 will be set at $7.199 million. The SC-9 delivery revenue target will be revised to include SC-14 delivery
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. revenues in the Net Revenue Sharing Mechanism. The combined SC9/SC-14 delivery revenue target will be set at $10.864 million. 3. 4. Participation in the mechanism will be expanded to include all of the firm service classifications. The Net Revenue Sharing Mechanism will be reconciled on a rate year basis. The Company will reconcile the period from June 1, 2012 through March 31, 2013 to account for the period between the current June 1 – May 31 reconciliation period and Rate Year One reconciliation period.
Statements to be Eliminated 1. 2. 3. 4. Appliance Repair Statement Inspection Fee Statement Balancing Service Cost Recovery Statement Late Payment Charge Statement
Tariff Modifications 1. 2. 3. Terminate SC-4 – Interruptible Sales Service. Eliminate ratchet usage from SC-3. Implement monthly gas cost imbalance surcharge or refund to adjust filed monthly cost of gas.
Miscellaneous 1. Billing Backout Credit – The updated ESCO billing charges will be $1.24 to an ESCO that supplies gas to a gas-only customer and $0.62 to an ESCO that supplies gas to a dual gas and electric customer. The customer backout credit will equal the ESCO billing charge. Paperless Billing - Customers electing paperless bills will receive a $0.40 credit per service period.
Deferral/Reconciliation Mechanisms Including Certain Program Descriptions A. The following modifications): existing electric deferrals will continue (with certain
Pension and OPEB costs a. The electric pension expense level is $45.002 million for Rate Year One, $28.080 million for Rate Year Two, and $18.578 million for Rate Year Three. The electric OPEB expense level is $36.133 million for Rate Year One, $34.722 million for Rate Year Two, and $25.938 million for Rate Year Three. The Company will continue the reconciliation procedures set forth in the Commission’s Statement of Policy on Pensions and Other Post Employment Benefits and the Rate Plan Provisions approved in Case 10-E-0050.
Low Income Discount Program a. Full reconciliation of low income discount program costs reflected in rates to the actual discounts provided. For under expenditures, the balance will be deferred for future low income customer use. The rate allowance is based on a $5.00 per month bill credit for non-heating electric customers receiving Home Energy Assistance Program (“HEAP”) assistance and a $15.00 per month bill credit for electric-heating customers receiving HEAP assistance.
Economic Development Fund a. b. Full true up of economic development discounts, including Empire Zone Rider (“EZR”) discounts. The target amounts for EZR and SC-11/SC-12 discounts are as follows: i. ii. iii. Rate Year One - $12.106 million Rate Year Two - $15.956 million Rate Year Three - $16.506 million
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. 4. Economic Development Grant Program a. b. The economic development grant program for electric will be funded at $11.000 million per year. Any under expenditures in a given year will be deferred for future use in the grant program. In the event of any anticipated over expenditures, the Company may petition the Commission for deferral treatment and will have no obligation to make any additional expenditure unless and until the Commission authorizes the Company to defer amounts in excess of the rate allowance for future recovery.
Auction Rate Debt True Up Service Quality Negative Revenue Adjustments Legislative or Regulatory Changes Aggregation Fee Voltage Migration Fee NYISO Tariff Schedule Costs – Schedules 1 and 2 for any NYISO Rebills Generation Stranded Cost Adjustments External and Internal Tax and Accounting Changes Electric Net Utility Plant and Depreciation Expense Reconciliation Mechanism a. One-way, downward only true up of the combined actual electric average net utility plant and depreciation expense revenue requirement to the target electric average net utility plant and depreciation expense revenue requirement. The combined electric average net utility plant and depreciation expense revenue requirement is calculated by applying the Company’s pre-tax WACC in the respective rate year (9.44 percent in Rate Year One, 9.59 percent in Rate Year Two, and 9.79 percent in Rate Year Three) to the electric average net utility plant balance and adding the electric depreciation expense to the product.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. c. The target revenue requirement of electric average net utility plant and depreciation expense is $690.511 million for Rate Year One, $733.450 million for Rate Year Two, and $783.501 million for Rate Year Three. See Appendix F, Page 1, which illustrates how the electric target revenue requirement was determined. The reconciliation mechanism will apply to the Company’s aggregate total electric average net plant and depreciation expense combined, and not to individual components.
Major Storm Expense a. Annual $29.000 million base rate allowance for major storm expense based on the Company’s 10 year average of incremental major storm costs. The rate allowance is subject to reserve accounting. The Company will defer the difference between the base rate allowance and actual incremental major storm costs for future refund or recovery from customers. The definitions of major storm and incremental costs in the Rate Plan Provisions will continue to apply. All incremental costs incurred within 10 days of restoration of the last customer are subject to deferral with no per storm deductible. A per storm deductible of $0.750 million applies only for storms that require post-restoration efforts more than 10 days beyond restoration of the last customer. The Company will perform an analysis of costs following a storm event with more than 10 days post-restoration work to gather information for deductible levels in future rate proceedings. The contractor disallowance is modified to include only the following job titles: (i) Chief Line Mechanic B Hotstick; (ii) Chief Line Mechanic A Hotstick; (iii) Line Mechanic Hotstick; (iv) Line Mechanic C; (v) Line Mechanic B; (vi) Line Mechanic A; (vii) Line Mechanic Helper; (viii) One Person Line/Trouble Mechanic; (ix) Trouble Mechanic C Hotstick; (x) Trouble Mechanic D Hotstick; (xi) Cable Splicer A; (xii) Cable Splicer B; (xiii) Cable Splicer C; (xiv) Cable Splicer Helper; and (xv) Chief Cable Splicer.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. 15. Site Investigation and Remediation (“SIR”) Expense a. Any difference between the actual SIR expense and the level reflected in electric rates ($35.700 million annually) will be deferred and recovered or credited to customers. The 80/20 sharing mechanism is eliminated. The Company will follow the “General Principles of the SIR Deferral Mechanism” set forth in Attachment 4 of the Rate Plan Provisions.
Transmission Revenue Adjustment Clause - rate allowance of $104.902 million in Rate Year One, $91.414 million in Rate Year Two, and $91.357 million in Rate Year Three. The following existing electric reconciliation mechanisms will continue outside of base rates: RPS Program Costs; SBC Program Costs; Temporary State Assessment 18-A; NYPA Residential Hydropower Benefit Reconciliation; Electric Supply Reconciliation Mechanism; New Hedge Adjustment; and Legacy Transition Charge f/k/a Commodity Adjustment Charge.
The following existing gas deferrals will continue (with certain modifications): 1. Pension and OPEB costs a. The gas pension expense level is $9.207 million for Rate Year One, $5.741 million for Rate Year Two, and $3.791 million for Rate Year Three. The gas OPEB expense level is $7.389 million for Rate Year One, $7.098 million for Rate Year Two, and $5.295 million for Rate Year Three. The Company will continue the reconciliation procedures set forth in the Commission’s Statement of Policy on Pensions and Other Post Employment Benefits and the Rate Plan Provisions.
Low Income Discount Program a. Provided the Company is not earning above its allowed ROE, full reconciliation of low income discount program costs in excess of the amount assumed in rates to the actual discounts provided. For
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. under expenditures, the balance will be deferred for future low income customer use. b. The allowance is based on an escalating bill credit for HEAP recipients. The bill credits are $10.00 per month in Rate Year One. The bill credits for Rate Years Two and Three will be included in the Joint Proposal.
Regulatory, Legislative, and Accounting Changes a. Utilize the language in Section 1.2.2 of the Rate Plan Provisions with the exception that the threshold for gas remains at $2.283 million per year.
SIR Expense a. Any difference between the actual SIR expense and the level reflected in gas rates ($6.300 million annually) will be deferred and recovered or credited to customers. The Company will follow the “General Principles of the SIR Deferral Mechanism” set forth in Attachment 4 of the Rate Plan Provisions.
Service Quality Negative Revenue Adjustments Auction Rate Debt True Up Net Revenue Sharing (see above) Accrued Unbilled Revenue Deferral The following gas reconciliation mechanisms will continue outside of base rates: SBC Program Costs; Temporary State Assessment 18-A; Millennium Fund; and GAC Surcharge/ Refund Adjustment Deferral.
The following new deferral mechanisms will be implemented for electric: 1. NYPA Discount Reconciliation a. The amount of NYPA Expansion Power, Replacement Power, and High Load Factor Power discounts will be fully reconciled.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. b. Any difference between the actual discounts and the level reflected in rates will be deferred and recovered from or credited to customers. The target amounts for the discounts are as follows: i. ii. iii. 2. Rate Year One - $2.707 million Rate Year Two - $2.401 million Rate Year Three $1.401 million
Transmission and Sub-Transmission Tower Painting Expense Downward Reconciliation a. The Company will reconcile for refund to customers any difference between the annual rate allowance for transmission ($2.448 million) and sub-transmission ($0.500 million) tower painting and the actual expense. Footer Inspection Expense
Transmission and Sub-Transmission Downward Reconciliation a.
The Company will reconcile for refund to customers any difference between the annual rate allowance for transmission ($2.441 million) and sub-transmission ($0.773 million) footer inspections and the actual expense.
Federal Income Tax – Repair Cost Deferral a. In Case 10-E-0050, the Commission ordered the Company to establish a credit of $28.89 million to its electric deferral balance to reflect the cash flow effect of the repair tax deduction for the electric business. The $28.89 million credit will be subject to true up to the actual amount of the deduction approved by the IRS.
Variable Pay a. The variable pay amount provided in rates is $13.737 million for Rate Year One, $14.124 million for Rate Year Two, and $14.522 million for Rate Year Three.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. b. The Company will defer for return to customers any unpaid variable pay compensation amounts reflected in rates that are not paid to employees.
Property Tax Expense a. If the level of actual property tax expense varies in any rate year from the level provided in rates ($150.1 million in Rate Year One, $153.8 million in Rate Year Two, and $158.1 million in Rate Year Three), the difference will be deferred for future recovery from or refund to customers on an 80% customer/20% Company basis. The Company will petition the Commission for allocation of any refunds pursuant to Public Service Law § 113(2).
The following new deferral mechanisms will be implemented for gas: 1. Economic Development Grant Program a. b. The economic development grant program for gas will be funded at $1 million per year. Any under expenditures in a given year will be deferred for future use in the grant program. In the event of any anticipated over expenditures, the Company may petition the Commission for deferral treatment and shall have no obligation to make any additional expenditures unless and until the Commission authorizes the Company to defer all such amounts for future recovery.
EZR Program a. The Company will reconcile EZR program discounts to the base rate allowance in Rate Year One of $1.248 million, Rate Year Two of $2.214 million and Rate Year Three of $3.995 million and debit or credit the difference to the gas EZR Program deferral.
External and Internal Tax and Accounting Changes Federal Income Tax – Repair Cost Deferral a. The Company will establish a deferred credit of $30.113 million to reflect the cash flow effect of the repair tax deduction for the gas business.
The $30.113 million credit will be subject to true up to the actual amount of the deduction approved by the IRS.
Variable Pay a. The variable pay amount provided in rates is $2.508 million for Rate Year One, $2.578 million for Rate Year Two, and $2.650 million for Rate Year Three. The Company will defer for return to customers any unpaid variable pay compensation amounts reflected in rates that are not paid to employees.
Property Tax Expense a. If the level of actual property tax expense varies in any rate year from the level provided in rates ($40.6 million in Rate Year One, $41.7 million in Rate Year Two, and $43.0 million in Rate Year Three), the difference will be deferred for future recovery from or refund to customers on an 80% customer/20% Company basis. The Company will petition the Commission for allocation of any refunds pursuant to Public Service Law § 113(2).
Gas Net Utility Plant and Depreciation Expense Reconciliation Mechanism a. One-way, downward only true up of the combined actual gas average net utility plant and depreciation expense revenue requirement to the target gas average net utility plant and depreciation expense revenue requirement. The combined gas average net utility plant and depreciation expense revenue requirement is calculated by applying the Company’s pre-tax WACC in the respective rate year (9.44 percent in Rate Year One, 9.59 percent in Rate Year Two, and 9.79 percent in Rate Year Three) to the gas average net utility plant balance and adding the depreciation expense to the product. The target revenue requirement of gas average net utility plant and depreciation expense is $165.883 million for Rate Year One, $173.923 million for Rate Year Two, and $183.516 million for
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. Rate Year Three. See Appendix F, Page 2, which illustrates how the gas target revenue requirement was determined. d. The reconciliation mechanism will apply to the Company’s aggregate total gas average net plant and depreciation expense combined, and not to individual components.
Oil to Gas Conversion Program (discussed below).
Carrying Charges on Deferral Balances 1. The Company will accrue carrying charges calculated using the pre-tax weighted average cost of capital for the respective rate year on the electric and gas deferral balances, with the exception of non-cash pension and OPEB items, beginning April 1, 2013.
Capital Investment Levels The electric, gas and common capital investment levels underlying the rates in this settlement (exclusive of cost of removal) are as follows: Segment Electric Transmission Electric SubTransmission Electric Distribution DOE Smart Grid Project Gas IS Facilities Fleet & IM-IR Total Capex FY13 $142,250,000 $46,000,000 $235,000,000 $7,000,000 $65,398,220 $10,950,000 $10,288,000 $966,000 $517,852,220 RY1 RY2 RY3 $142,849,000 $153,049,000 $155,432,000 $50,000,000 $48,526,000 $50,708,000 $233,430,000 $245,730,000 $246,590,000 $2,000,000 $0 $0 $80,509,265 $85,515,569 $92,377,472 $3,625,000 $200,000 $956,000 $6,888,000 $6,888,000 $6,888,000 $542,000 $542,000 $542,000 $519,843,265 $540,450,569 $553,493,472
Notwithstanding the agreed segment-level spending amounts, the parties agree the Company may reprioritize funds among the electric segments to address emergent needs. Cost of removal and O&M costs related to capital investment are functions of the levels of agreed capital spending within each segment. Electric cost of removal levels were developed based on the Company’s initial filing of electric cost of removal projects compared to electric capital investment levels. Gas cost of removal levels were developed based on a comparison of historic percentages of gas cost of removal to total gas capital project costs.
Customer Service Metrics A. The customer service metrics for the electric and gas businesses are as follows:
Customer Service Metrics PSC Complaint Rate Residential Transaction Satisfaction Index Small/Medium C&I Satisfaction Index % Calls Answered within 30 Seconds Totals B. C.
Minimum Revenue Adjustment Performance Amount 1.5 $1,117,500 82.0 $577,500 75.1 78.0 $577,500 $577,500 $2,850,000
Maximum Revenue Adjustment Performance Amount 2.5 $7,830,000 78.0 $3,990,000 71.1 72.0 $3,990,000 $3,990,000 $19,800,000
These customer service metrics are described in the Rate Plan Provisions. The negative revenue adjustments will be allocated to the electric and gas businesses based on the current ratio of 75 percent electric and 25 percent gas and will not be recalculated annually. The Company will also institute a missed appointment metric for electric and gas residential and non-residential customers. Under this metric, the Company will provide a service guarantee for appointments made at the customer’s request. If the Company does not keep an appointment within the scheduled timeframe, a $30 credit will be credited to the customer’s next bill. Appointment guarantees will not apply to appointments made for the same day the customer requests service or if events beyond the Company’s control (e.g., severe weather) prevent the Company from keeping the scheduled appointment.
VIII. Performance Metrics A. Electric Reliability Performance Metrics 1. 2. The SAIFI, CAIDI and Standardized Interconnection Requirements performance metrics will continue without modification. The Estimating performance metric will be modified as follows:
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. For each distribution or sub-transmission project initiated after January 1, 2013 with an individual total project cost over $100,000, the Company is subject to a $1 million negative revenue adjustment if actual costs of over 20 percent of such projects vary from their respective final engineering estimates by more than plus or minus 10 percent; and the Company is subject to an additional $1 million negative revenue adjustment if actual costs of over 30 percent of such projects vary from their respective final engineering estimates by more than plus or minus 10 percent, for a possible total negative revenue adjustment of $2 million. The Company has the right to request exceptions for discrete projects where there are scope changes or significant circumstances. 3. There will be an Inspection and Maintenance (“I&M”) Program Repair performance metric as follows: The Company is subject to a negative revenue adjustment of $1 million if it fails to repair at least 85 percent of Level II deficiencies that have a repair due date within the respective calendar year within the time period allowed for such repairs under the Safety Orders in Case 04-M-0159 (i.e., one year). The Company is subject to an additional negative revenue adjustment of $1 million if it fails to repair at least 75 percent of Level III deficiencies that have a repair due date within the respective calendar year within the time period allowed for such repairs under the Safety Orders in Case 04-M-0159 (i.e., three years). The Company will meet with Staff periodically to discuss I&M program repair performance. 4. The overall pre-tax potential negative revenue adjustments for the electric reliability performance metrics will be increased from $18 million to $20 million to reflect the new I&M Program Repair metric. Section 2.3(2) of the Rate Plan Provisions will be deleted in its entirety and replaced with the following: Abnormal operating conditions, including during any period of catastrophe, natural disaster or other unusual event not in the Company’s control, affecting more than ten percent of the customers in an operating area. Niagara Mohawk may petition for the exclusion of performance data associated with such an event. The petition should include justification for exclusion, actions taken by the Company to minimize or avoid customer impact (both prior to the event and/or in response to the event), a summary of resources used to restore services, as well as a detailed analysis of the Company’s performance prior to and subsequent to the event. The Commission will evaluate Niagara Mohawk’s proposal using established standards and policies applicable to those requests.
Gas Safety Metrics The Company’s gas safety performance will be measured annually against a set of Gas Safety Performance Metrics. A total of 150 pre-tax basis points will be at risk per calendar year for the Company’s performance under the Gas Safety Performance Metrics as follows: 1. Leak Prone Pipe (“LPP”) Removal a. b. 8 basis points at risk per calendar year. The Company will target LPP removal of 35 miles in CY13, 40 miles in CY14 and 45 miles in CY15. The Company will incur a negative revenue adjustment should it fail to remove from service a minimum of 35 miles in CY13, 35 miles in CY14, or a cumulative three-year total of 120 miles by the end of CY15. The Company will use its risk based prioritization model to identify and rank segments of pipe to be removed from service. The Company will submit a semi-annual report to Staff detailing LPP removal mileage, main locations and costs. The Company will submit semi-annual reports no later than 30 days following the six-month reporting periods ending June 30th and December 31st.
Leak Management a. b. 12 basis points at risk per calendar year. In CY13 and CY14, the Company will incur a negative revenue adjustment for failure to achieve total year end leak backlog targets for Type 1, 2 and 2A leaks; CY13 year-end target of 35 Type 1, 2 and 2A leaks in the backlog; CY14 year-end target of 30 Type 1, 2 and 2A leaks in the backlog. In CY15, the Company will incur a negative revenue adjustment for failure to achieve a year end total leak backlog target of 1,000 for all leaks (Type 1, 2, 2A and 3) in the backlog. The Company will submit an annual report to Staff detailing all leaks in its year-end backlog by type. The Company will submit the annual report no later than 30 days following the end of each calendar year.
Damage Prevention a. b. 18 basis points at risk per calendar year. The Company will incur a negative revenue adjustment in the event its year end damage prevention statistics fail to meet the following minimum targets: CY14 2.7 .48 .10 CY15 2.5 .48 .10
Damage Prevention Measure CY13 Overall Damages per 1,000 one-call 2.9 tickets (4 basis pts) Damages due to Mismarks per 1,000 .48 one-call tickets (10 basis pts) Damages due to Company and Contractors per 1,000 one-call tickets (4 .10 basis pts) c.
The Company will continue to collect damage data and compute damage performance in accordance with the criteria for the Gas Safety Performance Measures Report.
Emergency Response a. b. 12 basis points at risk per calendar year. The Company’s existing Emergency Response metric will continue (with a reduction to the associated negative revenue adjustments) as follows: i. Respond to 75% of all gas leak and odor calls within 30 minutes (6 basis points); ii. Respond to 90% of all gas leak and odor calls within 45 minutes (4 basis points); and iii. Respond to 95% of all gas leak and odor calls within 60 minutes (2 basis points).
Gas Safety Violations Metric a. b. 100 basis points at risk per calendar year. The Company will incur a negative revenue adjustment for instances of noncompliance (violations) of certain pipeline safety regulations identified during Staff’s annual field and records
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. audits. See Appendix G for a list of identified high risk and other risk pipeline safety regulations pertaining to this metric. c. The Company will be assessed a negative revenue adjustment for each high risk and other risk violation as follows: Occurrences 1-50 51+ CY 14 1-40 41+ CY 15 1-30 31+ other risk violation CY13 51+ CY 14 1-40 41+ CY 15 1-30 31+ 1/3 1/9 1/3 1/9 1/3 Occurrences 1-50 Basis Points ¼ ½ ½ 1 ½ 1 Basis Points 1/9
high risk violation CY13
i. This metric will be effective as of the start of Rate Year One, but will then be measured on calendar years, as identified above. ii. With respect to violations, only documentation or actions performed, or required to be documented or performed, on or after April 1, 2013 will count towards the metric. iii. At the conclusion of each audit, Staff and the Company will have a compliance meeting where Staff will present its findings to the Company. The Company will have five business days
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. from the date the audit findings are presented to cure the document deficiency. Only official Company records as defined in the Company’s Operating and Maintenance plan will be considered by Staff as a cure to a deficiency. Staff will copy its final audit report with the Secretary under Case 12-G0202. If the Company disputes any of Staff’s final audit results, the Company may appeal Staff’s finding to the Commission. The Company will not incur a negative revenue adjustment on the contested findings until such time as the Commission has issued a final decision on the contested findings. The Company does not waive its right to seek an appeal of any Commission determination regarding a violation or penalty under applicable law. iv. If an alleged high risk or other risk violation as set forth in Appendix G is the subject of a separate penalty proceeding by the Commission under PSL §25, that instance will not count under the performance metric. IX. Miscellaneous Issues A. Reliability Support Services (“RSS”) Costs 1. Up to $57 million of electric deferral credits will be used to offset RSS costs associated with RSS agreements relating to the Dunkirk plant or other RSS agreements with other generators. Any RSS costs above $57 million relating to the Dunkirk plant or any other RSS agreements with other generators will be recovered through a generic RSS surcharge that will be implemented on April 1, 2013. To qualify for recovery through this surcharge, the RSS agreements must be approved by the authority having jurisdiction over such agreement, including but not limited to the Commission or other regulatory entity. The surcharge will be calculated on a forecast basis and assessed to customers on a current basis beginning April 1, 2013 with an annual reconciliation, including interest at the other customer deposit rate. RSS costs collected through the surcharge will be allocated to service classifications based on the most recent transmission plant allocator and assessed on a volumetric basis; per kWh for non-demand service classifications and per kW for demand service classifications.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. 5. The RSS surcharge will be applicable to all customers with the exception of those customers whose rates are developed using marginal costs (Empire Zone qualifying load and Excelsior Jobs Program qualifying load).
Low Income Reconnect Fee Waiver Program – Electric and Gas Business 1. The Company will provide a one time $46 reconnect fee waiver for electric and gas customers receiving HEAP assistance.
Customer Outreach and Education Program 1. Increase funding for the Company’s customer outreach and education program.
Earnings Sharing Mechanism 1. If Niagara Mohawk’s earned return on equity exceeds 9.3 percent in any of the three rate years (“Earnings Sharing Threshold”), the Company will defer, with interest calculated using the customer provided capital rate, for refund to customers a credit as set forth below: a. For the first 100 basis points above the Earnings Sharing Threshold (i.e., > 9.3 percent, but ≤ 10.3 percent), 50 percent of the revenue equivalent of earnings above the Earnings Sharing Threshold will be deferred for the benefit of customers and 50 percent will be retained by the Company. For the next 100 basis points (i.e., > 10.3 percent but ≤ 11.3 percent), 75 percent of the revenue equivalent of earnings above the Earnings Sharing Threshold will be deferred for the benefit of customers and 25 percent will be retained by the Company. 90 percent of the revenue equivalent of earnings in excess of 11.3 percent will be deferred for the benefit of customers and 10 percent will be retained by the Company.
Miscellaneous Gas Provisions 1. Oil to Gas Conversion Program a. The Company will implement an oil to gas conversion program in Rate Year One, the annual cost of which is not to exceed $1.000 million. Any cost will be shared 50/50 between the Company and
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. customers. Costs to be borne by customers will be deferred for future recovery. 2. Gas Expansion Collaborative a. The Company will convene a collaborative to explore approaches to increase the availability of gas service, as well as opportunities to expand the Company’s current gas franchise area.
Inside Gas Services a. Within 60 days of the Commission’s order adopting the Joint Proposal, the Company will develop a policy for relocating inside meters in conjunction with regular work activities performed inside customer premises. The Company will file subsequent periodic reports on the progress of this effort.
ESCO Issues 1. Collaborative to Provide Information to Residential ESCO Customers a. The Company will convene a collaborative as soon as practicable but no later than 60 days following the Commission’s order adopting the Joint Proposal to develop the materials (including a bill calculator and other materials discussed in the collaborative) to be provided to residential ESCO customers concerning the amount the customer would have been billed if they had purchased commodity from the Company. The collaborative will also discuss what bill comparison tools could be provided to residential nonESCO customers. The incremental costs that the Company will incur to develop and provide the information identified in the above paragraph will not exceed $0.298 million and will be recovered by offsetting the costs against the electric deferral credits.
If an ESCO requests an ICAP tag for any account, including accounts that have an incentive allocation (i.e., Recharge NY), the Company will respond via email with the serviceable load (i.e., the load that can be served by the ESCO) and the ICAP tag for that load along with the notation “Reported ICAP Tag Adjusted for Special Programs” if applicable.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. 3. The Company confirms that the enrollment of a customer with insufficient Gas usage history will be provided and manually enrolled by National Grid. The Company confirms that, in accordance with the Joint Proposal dated December 19, 2005 in Case 05-M-0333 (“Competitive Opportunities Development Plan”), under the existing Purchase of Receivables program for customers in SC-3 and SC-3A, the ESCO has the option to use either a one-bill option or two-bill option for individual customers. However, if the ESCO seeks to move a customer from the two-bill option to a one-bill option, the Company’s purchase of the accounts receivable of such customer will be subject to the conditions set forth in the Competitive Opportunities Development Plan.
Electric Capital Investment and O&M Issues 1. Electric Capital Investment Reporting – The Company will continue to submit periodic reports regarding its electric infrastructure planning and investment to the Commission and Staff. The Company also will meet with Staff within 60 days of the Commission’s Order adopting the Joint Proposal to determine whether different or additional information would be useful to include in those reports, including discussion of the type of available information related to O&M programs. Spare Transformer Program Analysis – The Company will perform a sensitivity analysis to consider how assumptions about factors such as future lead times, forecast capacity needs, and incremental reliability and availability benefits versus costs may affect recommended spare transformer levels. Northeast Region Reinforcement – Spier- Rotterdam 115 kV Line – To the extent the Company incurs any incremental costs related to the pole straightness issues related to the Spier-Rotterdam 115 kV line, the Company will expense those costs below the line to exclude them from future revenue requirements and/or earnings sharing calculations. Buffalo Street Light Cable Replacement – The Company will develop and submit to Staff a comprehensive long-term street light refurbishment program plan for the City of Buffalo by April 15, 2013.
Gas Capital Investment and O&M Issues 1. The Company agrees to provide Staff enhanced capital and O&M reporting on a quarterly basis in a mutually agreeable format.
The Company is authorized to capitalize gas general equipment purchases of $2,500 or more. Purchases less than $2,500 will be expensed.
Rate Plan Provisions 1. The Rate Plan Provisions in Case 10-E-0050 will be modified consistent with the terms of this Settlement and attached as an appendix to the Joint Proposal.
Management Audit 1. The Parties agree that savings related to the implementation of Management Audit recommendations are reflected in the stipulated electric and gas revenue requirements. The Company will continue to work towards timely implementation of the remaining open Management Audit recommendations, and will continue to provide status update reports every four months and to participate in mid-cycle review meetings with Staff until all recommendations are implemented.
Service Company Investigation of Cost Allocations (Overland Audit) 1. In its compliance filing following the Commission’s January 24, 2011 Order in Case 10-E-0050, the Company filed a credit mechanism for refunding to electric customers any amounts determined to have been overcharged to Niagara Mohawk customers as a result of the Overland review of service company allocations. This credit mechanism, which was established to address temporary rates and approved by the Commission, remains in place and will be used to refund to electric customers any overcharged amounts following the Commission’s determination in Case 10-M-0451. The Company will be subject to the Commission’s findings in that proceeding regarding its policies, procedures, governance and controls relating to service company charges. The parties agree that the testimony, exhibits and discovery conducted in these proceedings do not support the collection of temporary rates.
All of the provisions of the Joint Proposal will continue beyond Rate Year Three until modified by the Commission. Unless otherwise specified herein, any targets, goals, deferral thresholds or other similar items set forth in the Joint Proposal will continue beyond Rate Year Three on a year-to-year basis at the level set forth for Rate Year Three until modified by the Commission.
This Term Sheet summarizes the principal terms of settlement reached by the parties and is not intended to be a definitive agreement. The parties’ agreement will be memorialized in an executed Joint Proposal. M. While this Term Sheet summarizes the principal terms of settlement reached by the parties, the parties’ assent to these terms is subject to their acceptance of the provisions of the Joint Proposal. The Joint Proposal will include other customary provisions (e.g., dispute resolution). If the Company seeks to establish new rates to go into effect prior to April 1, 2016, the Company will be required to defer for the benefit of customers $10.1 million annually and/or $2.7 million annually for the electric and gas businesses, respectively, prorated to represent the difference in duration between the three year rate plan contemplated by the Joint Proposal and the period between the effective date of the Joint Proposal and the date new rates go into effect. If the Company files for new base rates that go into effect after April 1, 2016, this deferral will not apply.
Appendix A Schedule 1
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Statement of Electric Operating Income For the Rate Year Ending March 31, 2014 ($000's) Corrections & Updates Filing Rate Year Ending March 31, 2014 Adjustments (1) $ (25) $ 2,428,181 $ 43,395 $ Rate Year Ending March 31, 2014 Base Revenue Increase Required $ 2,428,206 Rate Year Ending March 31, 2014 with Base Revenue Requirement 2,471,576
Deductions Purchased Power Costs 722,981 29,245 752,226 1,675,980 1,005,223 2,134 180,049 177,114 1,364,520 311,460 36,911 (36,936) (4) (10,000) (3) 157 0 2,134 180,206 167,114 1,327,584 348,371 (2) (27,093) 978,130 (25) 1,675,955 0 29,245 752,226 722,981
722,981 738 738 42,657 649 29,983 752,964 1,718,612 978,779 2,134 180,206 167,114 649 42,008 1,328,233 390,379
Revenue Taxes Total Deductions
Amortization of Regulatory Deferrals
Depreciation, Amort. & Loss on Disposition
Taxes Other Than Revenue & Income Taxes
Income Taxes Federal Income Taxes State Income Taxes 76,997 16,477 93,474 $ 217,986 $
10,914 2,383 13,297 23,614 $
87,911 18,860 106,771 241,600 $
13,659 2,983 16,642 25,366 $
101,570 21,843 123,413 266,966
4,104,201 5.31%
4,107,173 5.88%
4,107,173 6.50%
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 1 of 19
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 2 of 19
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Electric - Operation & Maintenance Expenses ($000's) Corrections & Updates Rate Year Ending March 31, 2014 Operation & Maintenance Expenses: Departmental Items: Consultants Contractors Rate Case Expense Employee Expenses Hardware Software Other Rents Service Co. Equity Construction Reimbursement Co Contributions/Cr to Jobs Bill Interface Expense Type Capital Overheads Supervision & Admin Service Co Operating Costs Sales Tax FAS 106 FAS 112 Health Care Group Life Insurance Other Benefits Pension Thrift Plan Workers Comp Payroll Taxes Materials Outside Vendor Materials From Inventory Materials Stores Handling Total Labor Variable Pay Storm Fund Renewable Portfolio Standard Legal Accounting Vegetation US Restructuring (Savings) E&Y Analysis Transportation Energy Efficiency Program Ex Pat Proxy Injuries & Damages New Initiatives Productivity Adjustment Regulatory Assessment Fees Site Investigation & Remediation Expenses System Benefits Charge Blank Synergy Savings Allocation Reclassification Inflation Miscellaneous Expense (1 item) Uncollectible Accounts Sub Total - Departmental Non-Departmental Items: Purchased Power TOTAL $
Rate Year Ending March 31, 2014
7,797 61,482 669 6,745 3,320 6,255 24,472 45,497 0 (582) 56 (2,528) 267 424 0 5,188 36,586 4,421 24,967 1,712 621 45,446 6,012 3,549 0 18,601 5,326 1,017 235,512 0 29,000 75,398 5,321 3,136 55,727 (11,921) 2,420 20,742 80,525 (458) 9,413 27,664 (5,393) 94,235 35,700 19,321 0 (652) (13,382) 0 0 35,595 1,005,223
t u v $
0 0 0 0 0 (2,265) (1,936) 0 0 0 0 0 0 0 0 (583) (64) (316) (20) 0 (598) 40 (54) 0 (281) 0 0 (8,315) 0 0 0 0 0 (3,300) (440) (2,420) 650 0 (845) 0 (2,875) 198 0 0 0 0 0 0 (222) (878) (2,571) (27,093)
7,797 61,482 669 6,745 3,320 6,255 22,207 43,561 0 (582) 56 (2,528) 267 424 0 5,188 36,003 4,357 24,652 1,693 621 44,849 6,052 3,496 0 18,320 5,326 1,017 227,198 0 29,000 75,398 5,321 3,136 52,427 (12,361) 0 21,392 80,525 (1,303) 9,413 24,789 (5,195) 94,235 35,700 19,321 0 (652) (13,382) (222) (878) 33,024 978,130
722,981 1,728,204 $
0 (27,093) $
722,981 1,701,111
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Federal Income Taxes For the Rate Year Ending March 31, 2014 ($000's)
Adjusted Rate Case
Deferrable Basis Adjustments
DFIT Reversals
NET INCOME BEFORE FEDERAL & STATE INCOME TAXES
Electric - as Adj. Federal Taxable Income 348,370,609 Book Taxable Income 348,370,609 @ the Statutory Rate 121,930,000
Net FIT Before Rev Req 121,930,000
180,350,022 150,098,000 291,000
180,507,022 150,098,000 291,000
63,177,000 52,534,000 102,000
(3,344,000)
36,549,644 25,366,030 (157,000)
ADDITIONS PROVISION FOR DEPRECIATION REAL ESTATE TAXES PER BOOKS BUSINESS MEALS 50% DISALLOWANCE DEDUCTIONS GAIN ON REDEMPTION BONDS V-M BOOK GAIN AMORTIZATION INTEREST NEW YORK STATE INCOME TAXES - CURRENT PROVISION OTHER STATE INCOME TAXES COST OF REMOVAL GAS CONTINGENCY RESERVE TAX DEPRECIATION REAL ESTATE TAXES FOR TAX DIVIDENDS PAID ON CERTAIN PREF STOCK OF PUBLIC UTILITIES TOTAL FIT EXPENSE (60,460) 0 (79,621,000) (18,860,000) 0 (45,687,055) 0 (158,928,173) (150,098,000) (339,784) 225,515,159 61,915,674 (60,460) 0 (82,965,000) (18,860,000) 0 (9,137,411) 0 (133,719,143) (150,098,000) (339,784) 284,086,833 (21,000) 0 (29,038,000) (6,601,000) 0 (3,198,000) 0 (46,802,000) (52,534,000) (119,000) 99,430,000 (11,894,000) (11,519,000)
(21,000) 375,000 (29,038,000) (6,601,000) 0 (15,092,000) 0 (46,802,000) (52,534,000) (119,000) 87,911,000
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 State Income Taxes For the Rate Year Ending March 31, 2014 ($000's)
Deferrable Basis
DSIT Reversals
Electric - as Adj. State Taxable Income 348,370,609
Book Taxable Income 348,370,609
@ the Statutory Rate 24,734,000
Net SIT Before Rev Req 24,734,000
150,098,000 291,000
10,657,000 21,000
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 3 of 19
ADDITIONS REAL ESTATE TAXES PER BOOKS BUSINESS MEALS 50% DISALLOWANCE DEDUCTIONS GAIN ON REDEMPTION BONDS OTHER POST RETIREMENT BENEFIT LIABILITY-MEDICARE PIECE INTEREST GAS CONTINGENCY RESERVE IBM CUSTOMER SYSTEM SETTLEMENT REAL ESTATE TAXES FOR TAX TOTAL SIT EXPENSE
(60,460) 0 (79,621,000) (3,344,000) 0 0 (150,098,000) 268,980,149 (3,344,000) 7.1% eff Apr 2007
(60,460) 0 (82,965,000) 0 0 (150,098,000) 265,636,149
(4,000) 0 (5,891,000) 0 0 (10,657,000) 18,860,000
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Summary of Electric Rate Base For the Rate Year Ending March 31, 2014 ($000's)
Corrections & Updates Rate Year Ending March 31, 2014 Adj. a Adjustments 6,441 0 (382) (92) 5,399,334 (16,035) (1,104,493) (193,422)
Rate Year Ending March 31, 2014 5,405,775 (16,035) (1,104,875) (193,514)
Regulatory Assets / Liabilities
Accumulated Deferred Income Taxes - Federal
Accumulated Deferred Income Taxes - State
Working Capital Blank Materials and supplies Prepayments O&M Cash Allowance (1/8 O&M exp) Supply Cash Allowance (Sep 09 lead/lag study) Change in Supply Cash Allowance (3.64% x RY Gas exp) subtotal Working Capital
0 31,108 31 108 (105,344) 88,866 34,443 (6,791) 42,282 4,127,666 (23,465) 4,104,201
0 (30) 100 (3,065) 0 (2,995) 2,972 0 2,972
0 31,078 31 078 (105,244) 85,801 34,443 (6,791) 39,287 4,130,638 (23,465) 4,107,173
subtotal avg. before EBCAP adj.
Excess Earnings Base adjustment
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 4 of 19
Total Electric Rate Base
Niagara Mohawk, a National Grid Company PSC Case No. 12-E-0201 Capital Structure Forecast For the Rate year Ending March 31, 2014
Capital Structure Forecast
Long Term Debt Notes Payable Gas Supplier Refunds Customer Deposits Preferred Stock Common Equity $5,194,523 100.00%
Total NM Annual Avg 2,582,209 52,399 37,559 28,985 2,493,371 Cost 4.04% 0.46% 0.00% 1.65% 3.66% 9.30% 6.50%
Weighting Percent 49.71% 1.01% 0.00% 0.72% 0.56% 48.00%
Weighted Cost 2.01% 0.00% 0.00% 0.01% 0.02% 4.46%
Pre-Tax Weighted Cost 2.01% 0.00% 0.00% 0.01% 0.03% 7.39% 9.44%
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 5 of 19
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 6 of 19
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Adjustments for the Rate Year Ending March 31, 2014 ($000's) Adj. 1.a (1) (2) (3) Adj. 1.b Operating Revenues To adjust Sales To reflect Company update in rebuttal To remove sales adjustment Purchased Power Costs To reflect change in commodity expenses on adjustment 1.a To remove change in commodity expenses Revenue Taxes To reflect change in revenue taxes on adjustment 1.a To remove change in revenue taxes Operating and Maintenance Expenses Consultant Expense To reflect staffs normalizing adjustments To update staffs normalizing adjustments for Company rebuttal Other Expense To eliminate 50% of annual EEI membership fees for activities related to lobbying To reflect staff's normalizing adjustments To reduce other expense for Glens Falls savings per DAG-83 To adjust for incorrect allocation code per DAG-56 Supp To update adj 2.b(1) for Company rebuttal To update staffs normalizing adjustments for Company rebuttal
(8,162) (25) 8,162
(1,889) 1,889
Adj. 1.c
Adj. 2 a. (1) (2) b. (1) (2) (3) (4) (5) (6)
(482) 482
(213) (3,373) (26) 13 213 1,121
c. (1) (2) (3) (4) (5) (6) d. (1) (2) e. (1) (2) f. (1) (2) (3) (4)
Rent Expense To reflect Staff service company return allowance of 8.63% which is based on Staff Capital Structure. To reflect change in bill pool 603 allocation, as per DPS-52 (DAG-5) To reflect correction for Glens Falls lease expense (DAG-83) To reflect correction for IS rent expense (DAGINF-6) To update adj 2.c(1) for agreed upon capital structure To update adj 2.c(2) for bill pool allocation, as per DPS-490 (GRL-32) FAS 106 - OPEB Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% FAS 112 Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% Health Care Use latest benefit capitalization rate thru 7/31/2012 of 40.78% Remove 1 additional FTE for US Restructuring per DAG-50 Company update to remove 2 additional FTE per RMD-18 To adjust the capitalization rate to 39.72%
(1,562) (1,585) 238 68 319 586
(1,166) 583
(128) 64
(589) (6) (15) 295
g. (1) (2)
Group Life Insurance Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72%
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 7 of 19
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Adjustments for the Rate Year Ending March 31, 2014 ($000's)
h. (1) (2) i. (1) (2) j. (1) (2) k.
Pension Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% Thrift Plan Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% Workers Comp. Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% Materials Outside Vendors To reflect agreed upon postage as per DPS-491 (DAG-81) Labor Expense To limit management pay increases to 2.9% per year To adjust management compensation to reflect pay differential by regions Adj. backfilling vacancies created by internal promotions at lower pay levels Adj. labor capitalization rate to reflect latest known actuals thru 7/31/2012 of 38.1% Remove 1 additional FTE for US Restructuring per DAG-50 Allocate RY variable pay between expense and capital in same manner as base pay Company update to remove 2 additional FTE per RMD-18 To update adj 2. l (2) To adjust the capitalization rate to 37.05% Flow through adj for 2. l (6) for updated capitalization rate Vegetation To adjust Vegetation Management - Transmission To adjust Vegetation Management - Distribution To update adj 2. m (1) for Company rebuttal To update adj 2. m (2) for Company rebuttal U.S. Restructuring Reflect additional savings per DAG-49 DAG -81 E&Y Analysis To remove O&M charges resulting from E&Y analysis Transportation Company update to correct inflation calculation error in DAG-74 To accept Company's updated forecast of fuel index prices Ex Pat Proxy To reflect HTY normalization adj. as per DAG-48 To reflect expats ending assignment prior to 1/1/12 as per DAG-48 To reflect additional expats ending assignment prior to or during RYE 3/14 To update adj 2.q (3)
(1,195) 598
(107) 54
l. (1) (2) (3) (4) (5) (6) (7) (8) (9) (10) m. (1) (2) (3) (4) n.
(360) (1,725) (412) (6,056) (41) (3,434) (45) 863 3,028 (132)
(2,140) (1,750) 300 290
p. (1) (2) q. (1) (2) (3) (4)
(42) 692
(399) (358) (578) 490
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 8 of 19
r. (1) (2) (3) (4) (5) (6) (7) s. (1) (2) (3) (4)
New Initiatives To adjust UG Network Inspections To adjust Recloser/Capacitor Inspections To adjust Footer Inspection/Repair - Transmission To adjust Footer Inspection/Repair - Sub-Transmission To adjust OPEX related to CAPEX Company update to adjust AFV grants To further adjust OPEX related to CAPEX Productivity Adjustment Flow adjustment related to labor adjustments above Remove 1 additional FTE for US Restructuring per DAG-50 Company update to remove 2 additional FTE per RMD-18 To reflect flow through for additional labor adjustments
(301) (166) (1,000) (227) (1,004) (200) 23
288 1 1 (92)
t. (1) (2) u. (1) (2) v. (1) (2) (3) w (1) (2)
Regulatory Assessment Fees To reflect change in 18A assessment surcharge related to adjustment 1.a To not reflect change in 18A assessment surcharge Inflation To reflect staff updated inflation factor. To reflect staff corrected calculation for updated inflation factor Miscellaneous Expense To reduce Outreach & Education Proposal To reflect additional IS Transformation adj. per DAG-80 To reflect correction of additional IS Transformation adj. Uncollectible Accounts Use of a three year average uncollectible rate vs the Company's one year rate To reflect uncollectible rate of 1.4963%. Total Operating & Maintenance Expense Adjustments
(705) 705
(413) 191
(250) (757) 129
(7,501) 4,930
(2,571) (27,093)
Adj. 3 (a) (b)
Depreciation Expense To reflect Staff's proposed depreciation To adjust Staff's depreciation adjustment
(22) 179
Adj. 4 a. (1) (2) (3) (4) (5) (6) b. (1) (2) (3)
Taxes Other Than Revenue & Income Taxes Real Estate Taxes To reduce property taxes related to incremental additions to Plant in Service To reduce property taxes for a change in forecast growth rate To correct adjustment (1) for electric / gas split To reduce property taxes for Glens Falls savings per DAG-83 Flow through adjs to PIS for changes in CAPEX To reflect additional flow through adjs to PIS for changes in CAPEX Payroll Taxes Tracking labor adjustments loading factor of 7.39% Remove 1 additional FTE for US Restructuring per DAG-50 Flow through adjustment for additional labor adjs
(2,042) (6,290) (1,273) (17) 283 (46)
(886) (3) 274
Total Taxes Other Than Revenue & Income Taxes
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 9 of 19
Adj. 5 a. (1) (2) (3) b. (1) (2) c. (1) (2)
Rate Base Net Utility Plant Update Electric Plant based on Staff's forecast Company update per rebuttal To adjust Staff's plant adjustment Accumulated Deferred Income Taxes To reflect flow through changes to Net Plant - Federal To reflect flow through changes to Net Plant - State Inflation Adjustment Materials and Supplies Prepayments Total Rate Base Adjustments
(909) 7,466 (116)
(382) (92)
70 6,037
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Statement of Electric Operating Income For the Rate Year Ending March 31, 2015 ($000's)
Settlement Rate Year Ending March 31, 2014 Adjustments $ (9,551) $ 2,462,025 $ 51,361 $ Rate Year Ending March 31, 2015 $ 2,471,576
Base Revenue Increase Required
Rate Year Ending March 31, 2015 with Base Revenue Requirement 2,513,386
Deductions Purchased Power Costs 722,981 29,983 752,964 1,718,612 978,779 2,134 180,206 167,114 1,328,233 390,379 (18,800) (13,702) 4,024 7,310 0 2,134 187,516 171,138 1,314,531 371,579 (25,036) 953,743 (32,502) 1,686,110 (568) 22,951 29,415 775,915 23,519 746,500
746,500 873 873 50,488 768 30,288 776,788 1,736,598 954,511 2,134 187,516 171,138 768 49,720 1,315,299 421,299
Income Taxes Federal Income Taxes State Income Taxes 101,569 21,843 123,412 $ 266,967 $
(9,938) (2,170) (12,108) (6,692) $
91,631 19,673 111,304 260,275 $
16,166 3,530 19,696 30,023 $
107,797 23,203 131,000 290,299
4,365,389 5.96%
4,365,389 6.65%
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 10 of 19
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Electric - Operation & Maintenance Expenses ($000's)
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 11 of 19
Settlement Rate Year Ending March 31, 2014 Operation & Maintenance Expenses: Departmental Items: Consultants Contractors Rate Case Expense Employee Expenses Hardware Software Other Rents Conservation Load Management Construction Reimbursement Co Contributions/Cr to Jobs Bill Interface Expense Type Capital Overheads Supervision & Admin Service Co Operating Costs Sales Tax FAS 106 FAS 112 Health Care Group Life Insurance Other Benefits Pension Thrift Plan Workers Comp Payroll Taxes Materials Outside Vendor Materials From Inventory Materials Stores Handling Total Labor Variable Pay Storm Fund Renewable Portfolio Standard Legal Accounting Vegetation US Restructuring (Savings) E&Y Analysis Transportation Energy Efficiency Program Ex Pat Proxy Injuries & Damages New Initiatives Productivity Adjustment Regulatory Assessment Fees Site Investigation & Remediation Expenses System Benefits Charge Blank Synergy Savings Allocation Reclassification Inflation Miscellaneous Expense (1 item) Uncollectible Accounts Sub Total - Departmental Non-Departmental Items: Purchased Power TOTAL Inflation Factor 2.13% $
Rate Year Ending March 31, 2015
7,797 61,482 669 6,745 3,320 6,255 22,207 43,561 0 (582) 56 (2,528) 267 424 0 5,188 36,003 4,357 24,652 1,693 621 44,849 6,052 3,496 0 18,320 5,326 1,017 227,198 0 29,000 75,398 5,321 3,136 52,427 (12,361) 0 21,392 80,525 (1,303) 9,413 24,789 (5,195) 94,235 35,700 19,321 0 (652) (13,382) (222) (878) 33,673 978,779
i i s i i i i s i i i i i i i i s i i i i s i i i i i i s i s s i i i i i i s i i s s s s s i i i i i s
166 1,310 144 71 133 473 7,802 (12) 1 (54) 6 9 111 (1,421) 93 525 36 13 (16,927) 129 74 390 113 22 6,398 11,080 113 67 1,117 (263) 119 31,948 (28) 200 (1,595) (2,778) (63,589) (2,631) (14) (285) (5) 878 1,025 (25,036)
7,963 62,792 669 6,889 3,391 6,388 22,680 51,363 0 (594) 57 (2,582) 273 433 0 5,299 34,582 4,450 25,177 1,729 634 27,922 6,181 3,570 0 18,710 5,439 1,039 233,595 0 29,000 86,478 5,434 3,203 53,544 (12,624) 0 21,511 112,473 (1,331) 9,613 23,194 (7,973) 30,646 35,700 16,690 0 (666) (13,667) (227) 0 34,698 953,743
722,981 1,701,760 $
23,518 (1,518) $
746,499 1,700,242
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Federal Income Taxes For the Rate Year Ending March 31, 2015 ($000's)
Electric - as Adj. Federal Taxable Income 371,578,587 Book Taxable Income 371,578,587 @ the Statutory Rate 130,053,000 Net FIT Before Rev Req 130,053,000
187,822,336 153,849,760 291,000
65,738,000 53,847,000 102,000
(11,764,000)
36,041,950 27,684,488
ADDITIONS PROVISION FOR DEPRECIATION REAL ESTATE TAXES PER BOOKS BUSINESS MEALS 50% DISALLOWANCE DEDUCTIONS GAIN ON REDEMPTION BONDS V-M BOOK GAIN AMORTIZATION INTEREST NEW YORK STATE INCOME TAXES - CURRENT PROVISION OTHER STATE INCOME TAXES COST OF REMOVAL GAS CONTINGENCY RESERVE TAX DEPRECIATION REAL ESTATE TAXES FOR TAX DIVIDENDS PAID ON CERTAIN PREF STOCK OF PUBLIC UTILITIES TOTAL FIT EXPENSE (60,460) 0 (82,965,000) (19,673,000) 0 (45,052,438) 0 (167,806,488) (153,849,760) (346,571) 243,787,966 (12,257,000) 51,962,438 (11,882,000) (60,460) 0 (94,729,000) (19,673,000) 0 (9,010,488) 0 (140,122,000) (153,849,760) (346,571) 295,750,404 (21,000) 0 (33,155,000) (6,886,000) 0 (3,154,000) 0 (49,043,000) (53,847,000) (121,000) 103,513,000
(21,000) 375,000 (33,155,000) (6,886,000) 0 (15,411,000) 0 (49,043,000) (53,847,000) (121,000) 91,631,000
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 State Income Taxes For the Rate Year Ending March 31, 2015 ($000's)
Electric - as Adj. State Taxable Income 371,578,587
Book Taxable Income 371,578,587
@ the Statutory Rate 26,382,000
Net SIT Before Rev Req 26,382,000
153,849,760 291,000
10,923,000 21,000
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 12 of 19
(60,460) 0 (82,965,000) 0 0 (153,849,760) 288,844,127 0 7.1% eff Apr 2007
(60,460) 0 (94,729,000) 0 0 (153,849,760) 277,080,127
(4,000) 0 (6,726,000) 0 0 (10,923,000) 19,673,000
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 13 of 19
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Summary of Electric Rate Base For the Rate Year Ending March 31, 2015 ($000's)
Settlement Rate Year Ending March 31, 2014 Net Utility Plant Regulatory Assets / Liabilities Accumulated Deferred Income Taxes - Federal Accumulated Deferred Income Taxes - State Working Capital Blank Materials and supplies Prepayments O&M Cash Allowance (1/8 O&M exp) Supply Cash Allowance (Sep 09 lead/lag study) Change in Supply Cash Allowance (3.64% x RY Gas exp) subtotal Working Capital subtotal avg. before EBCAP adj. Excess Earnings Base adjustment Total Electric Rate Base 5,405,775 (16,035) (1,104,875) (193,514)
Adjustments 286,977 (6,051) (14,454) (7,192)
Rate Year Ending March 31, 2015 5,692,752 (22,086) (1,119,329) (200,706)
0 31,078 (105,244) 85,801 34,443 (6,791) 39,287 4,130,638 (23,465) 4,107,173
0 660 (2,237) (359) 0 872 (1,064) 258,216 0 258,216
0 31,738 (107,481) 85,442 34,443 (5,919) 38,223 4,388,854 (23,465) 4,365,389
Niagara Mohawk, a National Grid Company PSC Case No. 12-E-0201 Capital Structure Forecast For the Rate year Ending March 31, 2015
Long Term Debt Notes Payable Gas Supplier Refunds Customer Deposits Preferred Stock Common Equity $4,365,382 100.00%
Total NM Annual Avg $ 2,180,508 $ 36,233 $ $ 30,121 $ 23,137 $ 2,095,383 Cost 4.32% 0.46% 0.00% 1.65% 3.66% 9.30% 6.65%
Weighting Percent 49.95% 0.83% 0.00% 0.69% 0.53% 48.00%
Weighted Cost 2.16% 0.00% 0.00% 0.01% 0.02% 4.46%
Pre-Tax Weighted Cost 2.16% 0.00% 0.00% 0.01% 0.03% 7.39% 9.59%
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 14 of 19
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Statement of Electric Operating Income For the Rate Year Ending March 31, 2016 ($000's)
Settlement Rate Year Ending March 31, 2015 Adjustments $ 12,401 $ 2,525,787 $ 28,342 $ Rate Year Ending March 31, 2016 $ 2,513,386
Rate Year Ending March 31, 2016 with Base Revenue Requirement 2,554,129
Deductions Purchased Power Costs 746,500 30,288 776,788 1,736,598 954,510 2,134 187,516 171,138 1,315,298 421,300 6,808 (33,122) 4,505 8,234 15 2,149 195,750 175,643 1,282,176 428,108 (45,876) 908,634 (26,314) 1,710,284 248 38,715 30,536 815,503 38,467 784,967
784,967 482 482 27,860 424 31,018 815,985 1,738,144 909,058 2,149 195,750 175,643 424 27,436 1,282,600 455,544
Income Taxes Federal Income Taxes State Income Taxes 107,797 23,203 131,000 $ 290,300 $
(2,628) (573) (3,201) 10,008 $
105,169 22,630 127,799 300,309 $
8,921 1,948 10,869 16,567 $
114,090 24,578 138,668 316,876
4,365,372 6.65%
4,625,927 6.49%
4,625,927 6.85%
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 15 of 19
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Page 16 of 19
Electric - Operation & Maintenance Expenses ($000's)
Settlement Rate Year Ending March 31, 2015 Operation & Maintenance Expenses: Departmental Items: Consultants Contractors Rate Case Expense Employee Expenses Hardware Software Other Rents Conservation Load Management Construction Reimbursement Co Contributions/Cr to Jobs Bill Interface Expense Type Capital Overheads Supervision & Admin Service Co Operating Costs Sales Tax FAS 106 FAS 112 Health Care Group Life Insurance Other Benefits Pension Thrift Plan Workers Comp Payroll Taxes Materials Outside Vendor Materials From Inventory Materials Stores Handling Total Labor Variable Pay Storm Fund Renewable Portfolio Standard Legal Accounting Vegetation US Restructuring (Savings) E&Y Analysis Transportation Energy Efficiency Program Ex Pat Proxy Injuries & Damages New Initiatives Productivity Adjustment Regulatory Assessment Fees Site Investigation & Remediation Expenses System Benefits Charge Blank Synergy Savings Allocation Reclassification Inflation Miscellaneous Expense (1 item) Uncollectible Accounts Sub Total - Departmental Non-Departmental Items: Purchased Power TOTAL Inflation Factor 2.20% $
Rate Year Ending March 31, 2016
7,963 62,792 669 6,889 3,391 6,388 22,680 51,363 0 (594) 57 (2,582) 273 433 0 5,299 34,582 4,450 25,177 1,729 634 27,922 6,181 3,570 0 18,710 5,439 1,039 233,595 0 29,000 86,478 5,434 3,203 53,545 (12,624) 0 21,511 112,473 (1,331) 9,613 23,194 (7,973) 30,645 35,700 16,690 0 (666) (13,667) (227) 0 35,464 954,510
175 1,381 152 75 141 499 (13) 1 (57) 6 10 117 (8,807) 98 554 38 14 (9,524) 136 79 412 120 23 6,570 (7,646) 120 70 1,178 (278) (1,052) (13,883) (29) 211 317 (2,885) (19,866) 5,510 (15) (301) (5) 480 (45,876)
8,138 64,173 669 7,040 3,465 6,529 23,179 51,363 0 (607) 58 (2,639) 279 443 0 5,415 25,775 4,548 25,730 1,767 648 18,398 6,317 3,648 0 19,122 5,559 1,062 240,165 0 29,000 78,832 5,554 3,273 54,599 (12,902) 0 20,459 98,590 (1,360) 9,825 23,511 (10,858) 10,779 35,700 22,200 0 (681) (13,968) (232) 0 35,944 908,634
746,499 1,701,009 $
38,468 (7,408) $
784,967 1,693,601
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Federal Income Taxes For the Rate Year Ending March 31, 2016 ($000's)
Electric - as Adj. Federal Taxable Income 428,107,955 Book Taxable Income 428,107,955 @ the Statutory Rate 149,838,000 Net FIT Before Rev Req 149,838,000
196,061,006 158,085,876 291,000
68,621,000 55,330,000 102,000
(14,469,000)
39,543,057 27,900,520 0
ADDITIONS PROVISION FOR DEPRECIATION REAL ESTATE TAXES PER BOOKS BUSINESS MEALS 50% DISALLOWANCE DEDUCTIONS GAIN ON REDEMPTION BONDS V-M BOOK GAIN AMORTIZATION INTEREST NEW YORK STATE INCOME TAXES - CURRENT PROVISION OTHER STATE INCOME TAXES COST OF REMOVAL GAS CONTINGENCY RESERVE TAX DEPRECIATION REAL ESTATE TAXES FOR TAX DIVIDENDS PAID ON CERTAIN PREF STOCK OF PUBLIC UTILITIES TOTAL FIT EXPENSE (43,971) 0 (95,165,000) (22,630,000) 0 (49,428,821) 0 (177,137,364) (158,085,876) (349,753) 279,705,052 (11,643,804) 52,974,577 (11,268,804) (43,971) 0 (109,634,000) (22,630,000) 0 (9,885,764) 0 (149,236,844) (158,085,876) (349,753) 332,679,629 (15,000) 0 (38,372,000) (7,921,000) 0 (3,460,000) 0 (52,233,000) (55,330,000) (122,000) 116,438,000
(15,000) 375,000 (38,372,000) (7,921,000) 0 (15,103,804) 0 (52,233,000) (55,330,000) (122,000) 105,169,196
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 State Income Taxes For the Rate Year Ending March 31, 2016 ($000's)
Electric - as Adj. State Taxable Income 428,107,955
Book Taxable Income 428,107,955
@ the Statutory Rate 30,396,000
Net SIT Before Rev Req 30,396,000
158,085,876 291,000
11,224,000 21,000
ADDITIONS REAL ESTATE TAXES PER BOOKS BUSINESS MEALS 50% DISALLOWANCE DEDUCTIONS GAIN ON REDEMPTION BONDS OTHER POST RETIREMENT BENEFIT LIABILITY-MEDICARE PIECE INTEREST GAS CONTINGENCY RESERVE IBM CUSTOMER SYSTEM SETTLEMENT REAL ESTATE TAXES FOR TAX TOTAL SIT EXPENSE (43,971) 0 (95,165,000) 0 0 (158,085,876) 333,189,984 7.1% eff Apr 2007 0
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 17 of 19
(43,971) 0 (109,634,000) 0 0 (158,085,876) 318,720,984
(3,000) 0 (7,784,000) 0 0 (11,224,000) 22,630,000
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 18 of 19
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-E-0201 Summary of Electric Rate Base For the Rate Year Ending March 31, 2016 ($000's)
Settlement Rate Year Ending March 31, 2015 Net Utility Plant Regulatory Assets / Liabilities Accumulated Deferred Income Taxes - Federal Accumulated Deferred Income Taxes - State Working Capital Blank Materials and supplies Prepayments O&M Cash Allowance (1/8 O&M exp) Supply Cash Allowance (Sep 09 lead/lag study) Change in Supply Cash Allowance (3.64% x RY Gas exp) subtotal Working Capital subtotal avg. before EBCAP adj. Excess Earnings Base adjustment Total Electric Rate Base 5,692,752 (22,086) (1,119,329) (200,706)
Adjustments 310,838 (6,792) (28,559) (13,400)
Rate Year Ending March 31, 2016 6,003,590 (28,878) (1,147,888) (214,106)
0 31,738 (107,481) 85,425 34,443 (5,919) 38,206 4,388,837 (23,465) 4,365,372
0 698 (2,365) (1,291) 1,426 (1,532) 260,555 0 260,555
0 32,436 (109,846) 84,134 34,443 (4,493) 36,674 4,649,392 (23,465) 4,625,927
Niagara Mohawk, a National Grid Company PSC Case No. 12-E-0201 Capital Structure Forecast For the Rate year Ending March 31, 2016
Long Term Debt Notes Payable Gas Supplier Refunds Customer Deposits Preferred Stock Common Equity $4,625,917 100.00%
Total NM Annual Avg $ 2,253,284 99,920 29,606 22,667 2,220,440 Cost 4.82% 0.46% 0.00% 1.65% 3.66% 9.30% 6.85%
Weighting Percent 48.71% 2.16% 0.00% 0.64% 0.49% 48.00%
Weighted Cost 2.35% 0.01% 0.00% 0.01% 0.02% 4.46%
Pre-Tax Weighted Cost 2.35% 0.01% 0.00% 0.01% 0.03% 7.39% 9.79%
Cases 12-E-0201 & 12-G-0202 Appendix A Schedule 1 Page 19 of 19
Appendix A Schedule 2
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Statement of Gas Operating Income For the Rate Year Ending March 31, 2014 ($000's) Corrections & Updates Filing Rate Year Ending March 31, 2014 Adjustments (1) $ 1,609 $ 609,122 $ (3,290) $ Rate Year Ending March 31, 2014 Base Revenue Increase Required $ 607,513 Rate Year Ending March 31, 2014 with Base Revenue Requirement 605,832
Deductions Purchased Gas Costs 228,094 8,370 236,464 371,049 185,577 (1,580) 50,243 44,904 279,144 91,905 14,423 (12,841) (4) (1,182) (3) (6,264) 43,979 43,722 266,303 106,328 (1,580) (2) (5,395) 180,182 1,582 372,631 27 27 8,397 236,491 228,094
228,094 (56) (56) (3,234) (88) 8,341 236,435 369,397 180,094 (1,580) 43,979 43,722 (88) (3,146) 266,215 103,182
Income Taxes Federal Income Taxes State Income Taxes 23,441 5,034 28,475 $ 63,430 $ 5,364 9,059 $ 4,403 961
27,844 5,996 33,840 72,488 $
(1,023) (223) (1,246) (1,899) $
26,821 5,773 32,594 70,588
Rate Base 5.84%
1,085,985 6.67%
1,085,985 6.50%
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 1 of 18
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 2 of 18
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Gas - Operation & Maintenance Expenses ($000's) Corrections & Updates Rate Year Ending March 31, 2014 Operation & Maintenance Expenses: Departmental Items: Consultants Contractors Rate Case Expense Employee Expenses Hardware Software Other Rents Service Co. Equity Construction Reimbursement Co Contributions/Cr to Jobs Bill Interface Expense Type Capital Overheads Supervision & Admin Service Co Operating Costs Sales Tax FAS 106 FAS 112 Health Care Group Life Insurance Other Benefits Pension Thrift Plan Workers Comp Payroll Taxes Materials Outside Vendor Materials From Inventory Materials Stores Handling Total Labor Variable Pay Regular Pay Monthly Base OT Pay Weekly Legal Accounting Vegetation US Restructuring (Savings) E&Y Analysis Transportation Energy Efficiency Program Ex Pat Proxy Injuries & Damages New Initiatives Productivity Adjustment Regulatory Assessment Fees Site Investigation & Remediation Expenses Synergy Savings Allocation Reclassification Uncollectible Accounts Inflation Miscellaneous Expense Sub Total - Departmental Non-Departmental Items: Purchased Gas TOTAL $
1,317 11,868 137 1,054 468 1,278 5,911 6,273 0 (32) 0 (20) 0 4 0 666 7,494 935 5,152 358 127 9,308 1,241 726 0 3,543 1,679 285 44,662 0 0 0 750 640 444 (2,370) (673) 4,726 16,713 (92) 1,810 7,092 (969) 28,891 6,300 (161) 374 17,668 0 0 185,577
q r s $
0 0 0 0 0 (245) 181 0 0 0 0 0 0 0 0 (120) (13) (65) (4) 0 (123) 8 (11) 0 (57) 0 0 (1,611) 0 0 0 0 0 0 (100) 673 149 0 (78) 0 (1,500) 38 0 0 0 0 (2,102) (38) (379) (5,395)
1,317 11,868 137 1,054 468 1,278 5,666 6,454 0 (32) 0 (20) 0 4 0 666 7,375 922 5,088 354 127 9,186 1,249 715 0 3,486 1,679 285 43,051 0 0 0 750 640 444 (2,470) 0 4,875 16,713 (170) 1,810 5,592 (931) 28,891 6,300 (161) 374 15,567 (38) (379) 180,182
228,094 413,671 $
0 (5,395) $
228,094 408,276
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Federal Income Tax For the Rate Year Ending March 31, 2014 ($000's)
Staff Adj
Gas - As Adjusted Federal Taxable Income 106,328,008 Book Taxable Income 106,328,008 @ the Statutory Rate 37,214,803
Net FIT Before Rev Req 37,214,803
50,243,000 40,644,000 59,600
(6,264,000)
43,979,000 40,644,000 59,600
15,392,650 14,225,400 20,860
6,672,235 6,264,000 (3,553,135)
ADDITIONS PROVISION FOR DEPRECIATION REAL ESTATE TAXES PER BOOKS BUSINESS MEALS 50% DISALLOWANCE DEDUCTIONS GAIN ON REDEMPTION BONDS OTHER POST RETIREMENT BENEFIT LIABILITY-MEDICARE PIECE INTEREST NEW YORK STATE INCOME TAXES - CURRENT PROVISION OTHER STATE INCOME TAXES COST OF REMOVAL GAS CONTINGENCY RESERVE TAX DEPRECIATION REAL ESTATE TAXES FOR TAX DIVIDENDS PAID ON CERTAIN PREF STOCK OF PUBLIC UTILITIES TOTAL FIT EXPENSE (5,878) 0 (21,056,000) (5,995,576) 0 (8,340,294) 0 (39,743,715) (40,644,000) (84,416) 81,404,729 4,000,100 (5,878) 0 (21,937,000) (5,995,576) 0 (1,668,059) 0 (37,032,850) (40,644,000) (84,416) 83,642,829 (2,057) 0 (7,677,950) (2,098,452) 0 (583,821) 0 (12,961,498) (14,225,400) (29,546) 29,274,990
(1,431,000) 0
(2,057) 0 (7,677,950) (2,098,452) 0 (2,014,821) 0 (12,961,498) (14,225,400) (29,546) 27,843,990
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 State Income Tax For the Rate Year Ending March 31, 2014 ($000's)
Gas - As Adjusted State Taxable Income 106,328,008
Book Taxable Income 106,328,008
@ the Statutory Rate 7,549,289
Net SIT Before Rev Req 7,549,289
40,644,000 59,600
2,885,724 4,232
0 881,000 0
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 3 of 18
(5,878) 0 (21,056,000) 0 0 (40,644,000) 85,325,730 7.1%
881,000 eff Apr 2007
(5,878) 0 (21,937,000) 0 0 (40,644,000) 84,444,730
(417) 0 (1,557,527) 0 0 (2,885,724) 5,995,576
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Summary of Gas Rate Base For the Rate Year Ending March 31, 2014 ($000's) Corrections & Updates Rate Year Ending March 31, 2014 Adj. a 2,168 0 b (891) (197) Adjustments 1,289,184 7,320 (223,140) (40,348)
Rate Year Ending March 31, 2014 1,291,352 7,320 (224,031) (40,545)
Working Capital Gas Storage Materials and supplies (inc. Gas Inventory & def. Fuel) Prepayments O&M Cash Allowance (1/8 O&M exp) Supply Cash Allowance (2007 lead/lag study) Change in Supply Cash Allowance (3.64% x RY Gas exp) subtotal Working Capital 0 62,278 (19,705) 15,687 21,654 (8,539) 71,375 1,104,391 (19,034) 1,085,357
0 (59) 19 (412) 0 (452) 628 0 628
0 62,219 (19,686) 15,275 21,654 (8,539) 70,923 1,105,019 (19,034) 1,085,985
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 4 of 18
Total Gas Rate Base
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Capital Structure Forecast For the Rate Year Ending March 31, 2014
Capital Structure Forecast Total NM Annual Avg $ 2,582,209 52,399 37,559 28,985 2,493,371 Cost 4.04% 0.46% 0.00% 1.65% 3.66% 9.30% 6.50% $5,194,523 100.00% Weighting Percent 49.71% 1.01% 0.00% 0.72% 0.56% 48.00% Weighted Cost 2.01% 0.00% 0.00% 0.01% 0.02% 4.46% Pre-Tax Weighted Cost 2.01% 0.00% 0.00% 0.01% 0.03% 7.39% 9.44%
Long Term Debt Notes Payable Gas Supplier Refunds Customer Deposits Preferred Stock Common Equity
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 5 of 18
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 6 of 18
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Adjustments for the Rate Year Ending March 31, 2014 ($000's) Adj. 1.a Operating Revenues Reconcile funding of Low Income Program Revenue Taxes To reflect change in revenue taxes on adjustment 1.a Adj. 2 a. (1) (2) b. (1) (2) (3) (4) (5) (6) c. (1) (2) (3) (4) (5) (6) (7) Operating and Maintenance Expenses Consultant Expense To reflect staff's normalizing adjustments To update staff's normalizing adjustments for Company rebuttal Other Expense To eliminate 50% of annual AGA and NGA membership fees for activities related to lobbying To reflect staff's normalizing adjustments To reduce other expense for Glens Falls savings per DAG-83 To adjust for incorrect allocation code per DAG-56 Supp To update adj 2.b(1) for Company rebuttal To update staffs normalizing adjustments for Company rebuttal Rent Expense To reflect Staff service company return allowance of 8.63% which is based on Staff Capital Structure. To reflect change in bill pool 603 allocation, as per DPS-52 (DAG-5) To reflect correction for Glens Falls lease expense (DAG-83) To reflect correction for IS rent expense (DAGINF-6) To correct Staff's calculation on service company return To update adj 2.c(1) for agreed upon capital structure To update adj 2.c(2) for bill pool allocation, as per DPS-490 (GRL-32) (45) 49 15 74 33 343 181 (288) (111) (598) (5) (6) 111 364 (245) 27
Adj. 1.b
d. (1) (2) e.
FAS 106 - OPEB Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% FAS 112 Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% (26) 13 (13) (239) 120 (120)
f. (1) (2) (3) (4) g. (1) (2) h. (1) (2) i. (1) (2)
Health Care Use latest benefit capitalization rate thru 7/31/2012 of 40.78% Remove 1 additional FTE for US Restructuring per DAG-50 Company update to remove 2 additional FTE per RMD-18 To adjust the capitalization rate to 39.72% Group Life Insurance Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% FAS 87 - Pension Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% Thrift Plan Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% 16 (8) 8 (245) 123 (123) (8) 4 (4) (121) (1) (3) 61 (65)
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 7 of 18
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Adjustments for the Rate Year Ending March 31, 2014 ($000's) j. (1) (2) k. (1) l. (1) (2) (3) (4) (5) (6) (7) (8) (9) m. Workers Comp Use latest benefit capitalization rate thru 7/31/2012 of 40.78% To adjust the capitalization rate to 39.72% Materials Outside Vendor To reflect agreed upon postage as per DPS-491 (DAG-81) Labor Expense To limit management pay increases to 2.9% per year To adjust management compensation to reflect pay differential by regions Adjust labor capitalization rate to reflect latest known actuals through 7/31/2012 of 38.1% Allocate RY variable pay between expense and capital in same manner as base pay Remove 1 additional FTE for US Restructuring per DAG-50 Company update to remove 2 additional FTE per RMD-18 To update adj 2. l (2) To adjust the capitalization rate to 37.05% Flow through adj for 2. l (4) for updated capitalization rate US Restructuring (Savings) Reflect additional savings per DAG-49 DAG -81 E & Y Analysis To remove O&M charges resulting from E&Y analysis Transportation Company update to correct inflation calculation error in DAG-74 To accept Company's updated forecast of fuel index prices Ex Pat Proxy To reflect HTY normalization adjustment as per DAG-48 To reflect expats ending assignment prior to 1/1/12 as per DAG-48 To reflect additional expats ending assignment prior to or during RYE 3/14 To update adj 2.p (3) New Initiatives Company update to adjust AFV grants Productivity Adjustment Flow adjustment related to labor adjustments above To reflect flow through for additional labor adjustments Uncollectible Accounts Use of a three year average uncollectible rate vs the Company's one year rate To reflect uncollectible rate of 2.6857% (4,839) 2,738 (2,102) t. (1) (2) u. (1) (2) Inflation To reflect staff updated inflation factor. To reflect staff corrected calculation for updated inflation factor Miscellaneous Expense To reflect additional IS Transformation adj. per DAG-80 To reduce Outreach and Education Total O&M Adjustments (72) 34 (38) 57 (19) 38 (31) (30) (85) 68 (78) (9) 158 149 (8) (5) 177 621 (24) (1,611) (703) (74) (353) (1,241) (22) 11 (11)
o. (1) (2) p (1) (2) (3) (4) q.
r. (1) (2) s. (1) (2)
(129) (250)
(379) (5,395)
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 8 of 18
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Adjustments for the Rate Year Ending March 31, 2014 ($000's) Adj. 3 (a) (b) Adj. 4 a. (1) (2) (3) (4) (5) b. (1) (2) (3) Depreciation Expense To reflect Staff's proposed depreciation To adjust Staff's depreciation adjustment Taxes Other Than Revenue & Income Taxes Real Estate Taxes To reduce property taxes related to incremental additions to Plant in Service To reduce property taxes for a change in forecast growth rate. To correct adjustment (1) for electric / gas split To reduce property taxes for Glens Falls savings per DAG-83 Flow through to PIS for changes in CAPEX Payroll Taxes Tracking labor adjustments loading factor of 7.39% Remove 1 additional FTE for US Restructuring per DAG-50 Flow through adjustment for additional labor adjs Total Taxes Other Than Revenue & Income Taxes Adj. 5 a. (1) (2) (3) (4) b. (1) (2) Rate Base Net Utility Plant Decrease to Gas Plant in Service Adjustment to Non-Interest Bearing CWIP Decrease in Reserve for Depreciation To adjust Staff Plant adjustment Accumulated Deferred Federal Income Taxes To reflect flow through changes to Net Plant - Federal To reflect flow through changes to Net Plant - State
(6,364) 100
(566) (1,743) 1,273 (5) (22)
(175) (1) 57
(119) (1,182)
(712) (15) 2,945 (50)
(891) (197)
Inflation Adjustment Materials and Supplies Prepayments Total Rate Base Adjustments
(40) 2,168
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Statement of Gas Operating Income For the Rate Year Ending March 31, 2015 ($000's)
Settlement Rate Year Ending March 31, 2014 Adjustments $ (4,148) $ 601,684 $ 5,854 $ 607,538 $ Rate Year Ending March 31, 2015 Deferral Credit $ 605,832
Rate Year Ending March 31, 2015 with Base Revenue Requirement $
Rate Year Ending March 31, 2015 and Deferral 607,538
Deductions Purchased Gas Costs 228,094 8,341 236,435 369,397 180,094 (1,580) 43,979 43,722 266,215 103,182 (480) 102,702 (15,082) 251,133 1,127 44,849 157 5,597 1,552 45,531 (1,580) (17,761) 162,333 157 (15,562) 353,835 5,754 359,589 162,490 (1,580) 45,531 44,849 251,290 108,299 (157) 11,414 8,184 247,849 100 100 8,284 247,949 11,571 239,665 239,665
239,665 8,284 247,949 359,589 162,490 (1,580) 45,531 44,849 251,290 108,299
Income Taxes Federal Income Taxes State Income Taxes 26,821 5,773 32,594 $ 70,588 $ 666 $ (1,146) (940) (206) 25,881 5,567 31,448 71,254
1,820 397 2,217 $ 3,380 $
27,701 5,964 33,665 74,634 $
27,701 5,964 33,665 74,634
Rate Base 6.50%
1,122,314 6.35%
1,122,314 6.65%
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 9 of 18
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 10 of 18
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Gas - Operation & Maintenance Expenses ($000's)
Settlement Rate Year Ending March 31, 2014 Operation & Maintenance Expenses: Departmental Items: Consultants Contractors Rate Case Expense Employee Expenses Hardware Software Other Rents Conservation Load Management Construction Reimbursement Co Contributions/Cr to Jobs Bill Interface Expense Type Capital Overheads Supervision & Admin Service Co Operating Costs Sales Tax FAS 106 FAS 112 Health Care Group Life Insurance Other Benefits Pension Thrift Plan Workers Comp Payroll Taxes Materials Outside Vendor Materials From Inventory Materials Stores Handling Total Labor Variable Pay Regular Pay Monthly System Benefit Charge Legal Accounting Vegetation US Restructuring (Savings) E&Y Analysis Transportation Energy Efficiency Program Ex Pat Proxy Injuries & Damages New Initiatives Productivity Adjustment Regulatory Assessment Fees Site Investigation & Remediation Expenses Synergy Savings Allocation Reclassification Uncollectible Accounts Inflation Miscellaneous Expense Sub Total - Departmental Non-Departmental Items: Purchased Gas TOTAL Inflation Factor $
Year 2 Rate Year Ending March 31, 2015
1,317 11,868 137 1,054 468 1,278 5,666 6,454 0 (32) 0 (20) 0 4 0 666 7,375 922 5,088 354 127 9,186 1,249 715 0 3,486 1,679 285 43,051 0 0 0 750 640 444 (2,470) 0 4,875 16,713 (170) 1,810 5,592 (931) 28,891 6,300 (161) 374 15,479 (38) (379) 180,094
i i s i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i i s s i i s i i
28 253 22 10 27 121 88 (1) (0) 0 14 (292) 20 108 8 3 (3,467) 27 15 74 36 6 1,186 16 14 9 (53) 27 4,001 (4) 39 91 (502) (20,641) (3) 8 573 (1) 379 (17,761)
1,345 12,121 137 1,076 478 1,305 5,787 6,542 0 (33) 0 (20) 0 4 0 680 7,083 941 5,196 362 130 5,719 1,276 730 0 3,560 1,715 291 44,237 0 0 0 766 654 453 (2,523) 0 4,902 20,714 (174) 1,849 5,683 (1,433) 8,250 6,300 (164) 382 16,051 (39) 0 162,333
228,094 408,188 $
11,571 (6,190) $
239,665 401,998
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Federal Income Tax For the Rate Year Ending March 31, 2016 ($000's)
Gas - As Adjusted Federal Taxable Income 108,513,286 Book Taxable Income 108,513,286 @ the Statutory Rate 37,979,650 Net FIT Before Rev Req 37,979,650
47,236,128 43,002,632 59,600
16,532,645 15,050,921 20,860
7,999,050 0 5,545,231
ADDITIONS PROVISION FOR DEPRECIATION REAL ESTATE TAXES PER BOOKS BUSINESS MEALS 50% DISALLOWANCE DEDUCTIONS GAIN ON REDEMPTION BONDS OTHER POST RETIREMENT BENEFIT LIABILITY-MEDICARE PIECE INTEREST NEW YORK STATE INCOME TAXES - CURRENT PROVISION OTHER STATE INCOME TAXES COST OF REMOVAL GAS CONTINGENCY RESERVE TAX DEPRECIATION REAL ESTATE TAXES FOR TAX DIVIDENDS PAID ON CERTAIN PREF STOCK OF PUBLIC UTILITIES TOTAL FIT EXPENSE (5,878) 0 (24,242,000) (5,751,640) 0 (9,998,813) 0 (44,284,341) (43,002,632) (74,447) 71,451,895 13,544,281 (5,878) 0 (27,558,000) (5,751,640) 0 (1,999,763) 0 (38,739,110) (43,002,632) (74,447) 81,680,177 (2,057) 0 (9,645,300) (2,013,074) 0 (699,917) 0 (13,558,689) (15,050,921) (26,056) 28,588,062 (1,857,612) 0 (1,857,612)
(2,057) 0 (9,645,300) (2,013,074) 0 (2,557,529) 0 (13,558,689) (15,050,921) (26,056) 26,730,450
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 State Income Tax For the Rate Year Ending March 31, 2016 ($000's)
Gas - As Adjusted State Taxable Staff Income Adjustments 108,513,286
Book Taxable Income 108,513,286
@ the Statutory Rate 7,704,443
Net SIT Before Rev Req 7,704,443
43,002,632 59,600
3,053,187 4,232
0 (3,316,000) 0 0
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 11 of 18
0 eff Apr 2007
(5,878) 0 (24,242,000) 0 0 (43,002,632) 84,325,008 7.1%
(5,878) 0 (27,558,000) 0 0 (43,002,632) 81,009,008
(417) 0 (1,956,618) 0 0 (3,053,187) 5,751,640
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Summary of Gas Rate Base For the Rate Year Ending March 31, 2015 ($000's)
Settlement Rate Year Ending March 31, 2014 Adj. a Adjustments 47,452 950 b (9,787) (3,765) 1,291,352 7,320 (224,031) (40,545)
Rate Year Ending March 31, 2015 1,338,804 8,270 (233,818) (44,310)
Working Capital Gas Storage Materials and supplies (inc. Gas Inventory & def. Fuel) Prepayments O&M Cash Allowance (1/8 O&M exp) Supply Cash Allowance (2007 lead/lag study) Change in Supply Cash Allowance (3.64% x RY Gas exp) subtotal Working Capital
0 1,322 (418) (212) 787 1,479 36,329 0 36,329
0 63,541 (20,104) 15,063 21,654 (7,752) 72,402 1,141,348 (19,034) 1,122,314
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 12 of 18
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Capital Structure Forecast For the Rate Year Ending March 31, 2015
Total NM Annual Avg $ 2,180,508 36,233 30,121 23,137 2,095,383 Cost 4.32% 0.46% 0.00% 1.65% 3.66% 9.30%
Weighted Cost 2.16% 0.00% 0.00% 0.01% 0.02% 4.46% 6.65%
Pre-Tax Weighted Cost 2.16% 0.00% 0.00% 0.01% 0.03% 7.39%
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 13 of 18
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Statement of Gas Operating Income For the Rate Year Ending March 31, 2016 ($000's)
Settlement Rate Year Ending March 31, 2015 Adjustments $ 126 $ 607,664 $ 6,268 $ 613,932 $ Rate Year Ending March 31, 2016 Deferral Credit $ $ 607,538
Rate Year Ending March 31, 2016 with Base Revenue Requirement
Rate Year Ending March 31, 2016 and Deferral 613,932
Deductions Purchased Gas Costs 239,665 8,284 247,949 359,589 162,489 (1,580) 45,531 44,849 251,289 108,300 214 108,513 (10,461) 240,829 168 5,993 1,343 46,192 1,705 47,236 (1,580) (13,509) 148,981 168 (10,247) 349,342 6,161 355,503 149,149 (1,580) 47,236 46,192 240,997 114,506 (80) 10,373 8,204 258,322 107 107 8,311 258,429 10,453 250,118 250,118
250,118 8,311 258,429 355,503 149,149 (1,580) 47,236 46,192 240,997 114,506
Income Taxes Federal Income Taxes State Income Taxes 27,701 5,964 33,665 $ 74,635 $ 1,397 $ (1,183) 32,482 76,031 (971) (212) 26,730 5,752
1,949 426 2,375 $ 3,619 $
28,679 6,178 34,857 79,649 $
28,679 6,178 34,857 79,649
Rate Base 6.65%
1,162,770 6.54%
1,162,770 6.85%
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 14 of 18
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 15 of 18
Settlement Rate Year Ending March 31, 2015 Operation & Maintenance Expenses: Departmental Items: Consultants Contractors Rate Case Expense Employee Expenses Hardware Software Other Rents Conservation Load Management Construction Reimbursement Co Contributions/Cr to Jobs Bill Interface Expense Type Capital Overheads Supervision & Admin Service Co Operating Costs Sales Tax FAS 106 FAS 112 Health Care Group Life Insurance Other Benefits Pension Thrift Plan Workers Comp Payroll Taxes Materials Outside Vendor Materials From Inventory Materials Stores Handling Total Labor Variable Pay Regular Pay Monthly System Benefit Charge Legal Accounting Vegetation US Restructuring (Savings) E&Y Analysis Transportation Energy Efficiency Program Ex Pat Proxy Injuries & Damages New Initiatives Productivity Adjustment Regulatory Assessment Fees Site Investigation & Remediation Expenses Synergy Savings Allocation Reclassification Uncollectible Accounts Inflation Miscellaneous Expense Sub Total - Departmental Non-Departmental Items: Purchased Gas TOTAL Inflation Factor $
Year 3 Rate Year Ending March 31, 2016
1,345 12,121 137 1,076 478 1,305 5,787 6,542 0 (33) 0 (20) 0 4 0 680 7,083 941 5,196 362 130 5,719 1,276 730 0 3,560 1,715 291 44,237 0 0 0 766 654 453 (2,523) 0 4,902 20,714 (174) 1,849 5,683 (1,433) 8,250 6,300 (164) 382 16,208 (39) 0 162,489
30 267 24 11 29 127 (204) (1) (0) 0 15 (1,804) 21 114 8 3 (1,951) 28 16 78 38 6 1,224 17 14 10 (55) (240) (5,623) (4) 41 (154) (520) (5,057) (4) 8 (19) (1) (13,509)
1,375 12,387 137 1,100 488 1,334 5,914 6,338 0 (33) 0 (21) 0 4 0 695 5,279 962 5,310 369 133 3,768 1,304 746 0 3,639 1,752 297 45,461 0 0 0 783 668 463 (2,578) 0 4,662 15,091 (177) 1,889 5,529 (1,953) 3,193 6,300 (168) 390 16,189 (40) 0 148,981
239,665 402,154 $
0 (13,509) $
250,118 388,646
ADDITIONS PROVISION FOR DEPRECIATION REAL ESTATE TAXES PER BOOKS BUSINESS MEALS 50% DISALLOWANCE DEDUCTIONS GAIN ON REDEMPTION BONDS OTHER POST RETIREMENT BENEFIT LIABILITY-MEDICARE PIECE INTEREST NEW YORK STATE INCOME TAXES - CURRENT PROVISION OTHER STATE INCOME TAXES COST OF REMOVAL GAS CONTINGENCY RESERVE TAX DEPRECIATION REAL ESTATE TAXES FOR TAX DIVIDENDS PAID ON CERTAIN PREF STOCK OF PUBLIC UTILITIES TOTAL FIT EXPENSE (5,878) 0 (24,242,000) (5,751,640) 0 (9,998,813) 0 (44,284,341) (43,002,632) (74,447) 71,451,895 (1,857,612) 0 13,544,281 (1,857,612) (5,878) 0 (27,558,000) (5,751,640) 0 (1,999,763) 0 (38,739,110) (43,002,632) (74,447) 81,680,177 (2,057) 0 (9,645,300) (2,013,074) 0 (699,917) 0 (13,558,689) (15,050,921) (26,056) 28,588,062
Gas - As Adjusted State Taxable Staff Adjustments Income 108,513,286
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 16 of 18
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Summary of Gas Rate Base For the Rate Year Ending March 31, 2016 ($000's)
Settlement Rate Year Ending March 31, 2015 Adj. Adjustments 53,222 983 (10,910) (4,152) 1,338,804 8,270 (233,818) (44,310)
Rate Year Ending March 31, 2016 1,392,026 9,253 (244,728) (48,462)
0 1,398 (442) (354) 711 1,313 40,456 0 40,456
0 64,939 (20,546) 14,709 21,654 (7,041) 73,715 1,181,804 (19,034) 1,162,770
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 17 of 18
NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID PSC Case No. 12-G-0202 Staff's Capital Structure Forecast For the Rate Year Ending March 31, 2016
Total NM Annual Avg $ 2,253,284 99,920 29,606 22,667 2,220,440 Cost 4.82% 0.46% 0.00% 1.65% 3.66% 9.30%
Weighted Cost 2.35% 0.01% 0.00% 0.01% 0.02% 4.46% 6.85%
Pre-Tax Weighted Cost 2.35% 0.01% 0.00% 0.01% 0.03% 7.39%
Cases 12-E-0201 and 12-G-0202 Appendix A Schedule 2 Page 18 of 18
Case 12-E-0201 & 12-G-0202 Appendix B Page 1 of 1 NIAGARA MOHAWK POWER CORPORATION Gas Transmission and Distribution Depreciation Rates Effective 4/1/2013 Average Service Life (ASL) 100 55 85 40 45 25
Account Account Name Gas Transmission Plant 365.00 Land Rights 366.00 Structures and improvements 367.00 Mains 369.15 Measuring and regulating station equipment 369.25 Measuring and regulating station equipment - manholes 369.55 Measuring and regulating station equipment - RTU Gas Distribution Plant 374.00 Land Rights 375.00 Structures and improvements 376.11 Mains - Steel 376.12 Mains - Plastic 376.13 Mains - Cast Iron 376.14 Mains - Valves 378.10 Measuring and regulating station equipment 378.20 Measuring and regulating station equipment - manholes 378.55 Measuring and regulating station equipment - RTU 380.10 Services - Metallic 380.20 Services - Plastic 381.00 Meters 382.00 Meter installations 383.00 House regulators 384.00 House regulator installations 385.00 Industrial measuring and regulating equipment
Curve SQ R2 R3 R0.5 LO H4
Depreciation Rate 1.00% 2.00% 1.29% 2.75% 2.89% 4.20%
-10.00% -10.00% -10.00% -30.00% -5.00%
100 45 95 65 80 90 36 45 25 60 60 33 50 40 40 40
SQ L0 H4 H4 S0.5 S2 L0.5 L0 H4 R1.5 R4 R2.5 R1 R1 H5 R5
-40.00% -40.00% -30.00% -200.00% -20.00% -30.00% -35.00% -5.00% -10.00% -10.00% -5.00% -50.00% 0.00% 0.00% 0.00%
1.00% 3.11% 1.47% 2.00% 3.75% 1.33% 3.61% 3.00% 4.20% 1.83% 1.83% 3.18% 3.00% 2.50% 2.50% 2.50%
Case 12-E-0201 & 12-G-0202 Appendix C Page 1 of 1
Appendix C--Deferral Allocators - Electric Description SC-1 SC-1C SC-2 SC-2D SC-3 Sec SC-3 Pri SC-3 Sub/Tran SC-3A Sec/Pri SC-3A Sub SC-3A Tran Lighting Deferral Allocator 59.26% 1.02% 4.65% 12.92% 8.87% 3.01% 0.43% 1.87% 1.07% 3.05% 3.85% 100.00%
Case 12-E-0201 and 12-G-0202 Appendix D Page 1 of 1 Gas Rate Design Customer Charges for Rate Year 1 RATE YEAR 1 Service Class SC-1 Residential SC-2 Small General SC-3 Large Supply SC-5 Transportation SC-6 Interruptible Transportation SC-7 Small Transportation SC-8 Transportation with Standby Sales SC-12 Non-Residential DG < 250,000 SC-12 Non-Residential DG 250,000 - 1,000,000 SC-12 Non-Residential DG 1,000,000-2,500,000 SC-12 Non-Residential DG > 2,500,000 SC-13 Residential DG NYSEG Base Customer Charge $ 19.18 $ 23.00 $ 780.00 $ 500.00 $ 580.00 $ 360.00 $ 880.00 $ 147.00 $ 465.27 $ 1,400.00 $ 1,400.00 $ 26.29 $ 808.80 Low Income Total Minimum Delivery Surcharge Service Charge $ 1.17 $20.35 $ 1.17 $24.17 $ 1.17 $781.17 $ 1.17 $501.17 $ 1.17 $581.17 $ 1.17 $361.17 $ 1.17 $881.17 $ 1.17 $148.17 $ 1.17 $466.44 $ 1.17 $1,401.17 $ 1.17 $1,401.17 $ 1.17 $27.46 $ 1.17 $809.97
Customer charges for Rate Years 2 and 3 are described in the Term Sheet.
Case 12-E-0201 and 12-G-0202 Appendix E Page 1 of 1 Gas Rate Design Deferral Credit Allocators for Rate Years 1, 2 and 3
Service Classification SC-1 Residential SC-2 Small General SC-3 Large Supply SC-5 Transportation SC-7 Small Transportation SC-8 Transportatiaon with Standby Sales SC-12 Non-Residential DG SC-13 Residential DG NYSEG Total
Deferral Allocator 74.06% 17.02% 0.22% 1.76% 2.91% 3.91% 0.02% 0.00% 0.09% 100.00%
Case 12-E-0201 and 12-G-0202 Appendix F Page 1 of 2
NIAGARA MOHAWK POWER CORPORATION Electric Net Utility Plant and Depreciation Expense Reconciliation Electric Revenue Requirement Target For the Rate Years Ending March 31, 2014, March 31, 2015, and March 31, 2016
Rate Year Ending March 31, 2014 Total Electric Revenue Requirement Target Total Electric Plant in Service (a) $ 8,016,500,020 $ Non-Interest Bearing CWIP (b) 44,198,692 Reserve for Depreciation (c) $ (2,654,923,964) $ Electric Net Utility Plant in Service (d) 5,405,774,748 9.44% $ 690,510,971 $ 510,305,136 $ 180,205,835 $ Electric Depreciation Expense (e) 180,205,835
Forecast included in Revenue Requirement Settlement Pre-Tax WACC Total Revenue Requirement Target
Rate Year Ending March 31, 2015 Total Electric Revenue Requirement Target Total Electric Plant in Service (a) $ 8,368,544,574 $ Non-Interest Bearing CWIP (b) 49,569,525 Reserve for Depreciation (c) $ (2,725,362,244) $ Electric Net Utility Plant in Service (d) 5,692,751,855 9.59% $ 733,450,274 $ 545,934,903 $ 187,515,371 $ Electric Depreciation Expense (e) 187,515,371
Rate Year Ending March 31, 2016 Total Electric Revenue Requirement Target Total Electric Plant in Service (a) $ 8,756,174,570 $ Non-Interest Bearing CWIP (b) 50,014,328 Reserve for Depreciation (c) $ (2,802,599,037) $ Electric Net Utility Plant in Service (d) 6,003,589,862 9.79% $ 783,501,463 $ 587,751,448 $ 195,750,016 $ Electric Depreciation Expense (e) 195,750,016
Case 12-E-0201 and 12-G-0202 Appendix F Page 2 of 2
NIAGARA MOHAWK POWER CORPORATION Gas Net Utility Plant and Depreciation Expense Reconciliation Gas Revenue Requirement Target For the Rate Years Ending March 31, 2014, March 31, 2015, and March 31, 2016
Rate Year Ending March 31, 2014 Total Gas Revenue Requirement Target Total Gas Plant in Service (a) $ 2,042,629,184 $ Non-Interest Bearing CWIP (b) 6,677,438 $ Reserve for Depreciation (c) (757,954,294) $ Gas Net Utility Plant in Service (d) 1,291,352,328 9.44% $ 165,882,645 $ 121,903,660 $ 43,978,985 $ Gas Depreciation Expense (e) 43,978,985
Rate Year Ending March 31, 2015 Total Gas Revenue Requirement Target Total Gas Plant in Service (a) $ 2,114,531,440 $ Non-Interest Bearing CWIP (b) 7,131,524 $ Reserve for Depreciation (c) (782,858,155) $ Gas Net Utility Plant in Service (d) 1,338,804,809 9.59% $ 173,922,729 $ 128,391,381 $ 45,531,348 $ Gas Depreciation Expense (e) 45,531,348
Rate Year Ending March 31, 2016 Total Gas Revenue Requirement Target Total Gas Plant in Service (a) $ 2,192,727,293 $ Non-Interest Bearing CWIP (b) 7,295,039 $ Reserve for Depreciation (c) (807,995,232) $ Gas Net Utility Plant in Service (d) 1,392,027,100 9.79% $ 183,515,581 $ 136,279,453 $ 47,236,128 $ Gas Depreciation Expense (e) 47,236,128
Appendix G Page 1 of 4
HIGH RISK SECTIONS PART 255 ACTIVITY TITLE Material - General Transportation of Pipe Pipe Design - General Design of Components - General Requirements Design of Components - Flexibility Design of Components - Supports and anchors Compressor Stations: Emergency shutdown Compressor Stations: Pressure limiting devices Compressor Stations: Ventilation Valves on pipelines to operate at 125 psig or more Distribution line valves Vaults: Structural Design requirements Vaults: Drainage and waterproofing Protection against accidental overpressuring Control of the pressure of gas delivered from high pressure distribution systems Requirements for design of pressure relief and limiting devices Required capacity of pressure relieving and limiting stations Qualification of welding procedures Qualification of Welders Protection from weather Miter Joints Preparation for welding Inspection and test of welds Nondestructive testing-Pipeline to operate at 125 PSIG or more Welding inspector Repair or removal of defects Joining Of Materials Other Than By Welding - General Joining Of Materials Other Than By Welding - Copper Pipe Joining Of Materials Other Than By Welding - Plastic Pipe Plastic pipe: Qualifying persons to make joints Notification requirements Compliance with construction standards Inspection: General Inspection of materials Repair of steel pipe Repair of plastic pipe Bends and elbows Wrinkle bends in steel pipe Installation of plastic pipe Underground clearance Customer meters and service regulators: Installation Service lines: Installation Service lines: Location of valves External corrosion control: Buried or submerged pipelines installed after July 31, 1971 External corrosion control: Buried or submerged pipelines installed before August 1, 1971 External corrosion control: Protective coating External corrosion control: Cathodic protection External corrosion control: Monitoring Internal corrosion control: Design and construction of transmission line Remedial measures: General Remedial measures: transmission lines Strength test requirements for steel pipelines to operate at 125 PSIG or more General requirements (UPGRADES) Upgrading to a pressure of 125 PSIG or more in steel pipelines Upgrading to a pressure less than 125 PSIG Conversion to service subject to this Part General provisions Operator Qualification Essentials of operating and maintenance plan Change in class location: Required study Damage prevention program Emergency Plans Customer education and information program Maximum allowable operating pressure: Steel or plastic pipelines Maximum allowable operating pressure: High pressure distribution systems Maximum and minimum allowable operating pressure: Low pressure distribution systems Odorization of gas Tapping pipelines under pressure Purging of pipelines Control Room Management Transmission lines: Patrolling CODE SECTION 255.53(a),(b),(c) 255.65 255.103 255.143 255.159 255.161 255.167 255.169 255.173 255.179 255.181 255.183 255.189 255.195 255.197 255.199 255.201 255.225 255.227 255.231 255.233 255.235 255.241(a),(b) 255.243(a)-(e) 255.244(a),(b),(c) 255.245 255.273 255.279 255.281 255.285(a),(b),(d) 255.302 255.303 255.305 255.307 255.309 255.311 255.313(a),(b),(c) 255.315 255.321 255.325 255.357(d) 255.361(e),(f),(g),(h),(i) 255.365(b) 255.455(d),(e) 255.457 255.461(c) 255.463 255.465(a),(e) 255.476(a),(c) 255.483 255.485(a),(b) 255.505(a),(b),(c),(d) 255.553 (a),(b),(c),(f) 255.555 255.557 255.559(a) 255.603 255.604 255.605 255.609 255.614 255.615 255.616 255.619 255.621 255.623 255.625(a),(b) 255.627 255.629 255.631(a) 255.705 RISK FACTOR HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH
Appendix G Page 2 of 4
Leakage Surveys - Transmission Transmission lines: General requirements for repair procedures Transmission lines: Permanent field repair of imperfections and damages Transmission lines: Permanent field repair of welds Transmission lines: Permanent field repair of leaks Transmission lines: Testing of repairs Distribution systems: Leak surveys and procedures Compressor stations: procedures Compressor stations: Inspection and testing relief devices Compressor stations: Additional inspections Compressor stations: Gas detection Pressure limiting and regulating stations: Inspection and testing Regulator Station Overpressure Protection Transmission Line Valves Prevention of accidental ignition Protecting cast iron pipelines Replacement of exposed or undermined cast iron piping Replacement of cast iron mains paralleling excavations Leaks: Records Leaks: Instrument sensitivity verification Leaks: Type 1 Leaks: Type 2A Leaks: Type 2 Leak Follow-up High Consequence Areas Required Elements (IMP) Knowledge and Training (IMP) Identification of Potential Threats to Pipeline Integrity and Use of the Threat Identification in an Integrity Program (IMP) Baseline Assessment Plan( IMP) Conducting a Baseline Assessment (IMP) Direct Assessment (IMP) External Corrosion Direct Assessment (ECDA) (IMP) Internal Corrosion Direct Assessment (ICDA) (IMP) Confirmatory Direct Assessment (CDA) (IMP) Addressing Integrity Issues (IMP) Preventive and Mitigative Measures to Protect the High Consequence Areas (IMP) Continual Process of Evaluation and Assessment (IMP) Reassessment Intervals (IMP) General requirements of a GDPIM plan Implementation requirements of a GDPIM plan. Required elements of a GDPIM plan. Required report when compression couplings fail. Requirements a small liquefied petroleum gas (LPG) operator must satisfy to implement a GDPIM plan
255.706 255.711 255.713 255.715 255.717 255.719 255.723 255.729 255.731 255.732 255.736 255.739(a),(b) 255.743(a),(b) 255.745 255.751 255.755 255.756 255.757 255.807(d) 255.809 255.811(b),(c),(d),(e) 255.813(b),(c),(d) 255.815 255.819(a) 255.905 255.911 255.915 255.917 255.919 255.921 255.923 255.925 255.927 255.931 255.933 255.935 255.937 255.939 255.1003 255.1005 255.1007 255.1009 255.1015
HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH
HIGH RISK SECTIONS PART 261 Operation and maintenance plan Leakage Survey Carbon monoxide prevention Warning tag procedures HEFPA Liaison Warning Tag Inspection Warning tag: Class A condition Warning tag: Class B condition 261.15 261.17(a),(c) 261.21 261.51 261.53 261.55 261.57 261.59 HIGH HIGH HIGH HIGH HIGH HIGH HIGH HIGH
Appendix G Page 3 of 4
OTHER RISK SECTIONS PART 255 ACTIVITY TITLE Preservation of records Compressor station: Design and construction Compressor station: Liquid removal Compressor stations: Additional safety equipment Vaults: Accessibility Vaults: Sealing, venting, and ventilation Calorimeter or calorimeter structures Design pressure of plastic fittings Valve installtion in plastic pipe Instrument, control, and sampling piping and components Limitations On Welders Quality assurance program Preheating Stress relieving Inspection and test of welds Nondestructive testing-Pipeline to operate at 125 PSIG or more Plastic pipe: Qualifying joining procedures Plastic pipe: Qualifying persons to make joints Plastic pipe: Inspection of joints Bends and elbows Protection from hazards Installation of pipe in a ditch Casing Cover Customer meters and regulators: Location Customer meters and regulators: Protection from damage Customer meters and service regulators: Installation Customer meter installations: Operating pressure Service lines: Installation Service lines: valve requirements Service lines: Location of valves Service lines: General requirements for connections to main piping Service lines: Connections to cast iron or ductile iron mains Service lines: Steel Service lines: Cast iron and ductile iron Service lines: Plastic Service lines: Copper New service lines not in use Service lines: excess flow valve performance standards External corrosion control: Buried or submerged pipelines installed after July 31, 1971 External corrosion control: Examination of buried pipeline when exposed External corrosion control: Protective coating Rectifier Inspection External corrosion control: Electrical isolation External corrosion control: Test stations External corrosion control: Test lead External corrosion control: Interference currents Internal corrosion control: General Atmospheric corrosion control: General Atmospheric corrosion control: Monitoring Remedial measures: transmission lines Remedial measures: Pipelines lines other than cast iron or ductile iron lines Remedial measures: Cast iron and ductile iron pipelines Direct Assessment Corrosion control records General requirements (TESTING) CODE SECTION 255.17 255.163 255.165 255.171 255.185 255.187 255.190 255.191 255.193 255.203 255.229 255.230 255.237 255.239 255.241(c) 255.243(f) 255.283 255.285(c),(e) 255.287 255.313(d) 255.317 255.319 255.323 255.327 255.353 255.355 255.357(a),(b),(c) 255.359 255.361(a),(b),(c),(d) 255.363 255.365(a),(c) 255.367 255.369 255.371 255.373 255.375 255.377 255.379 255.381 255.455(a) 255.459 255.461(a),(b),(d),(e),(f),(g) 255.465 (b),(c),(f) 255.467 255.469 255.471 255.473 255.475(a),(b) 255.479 255.481 255.485(c) 255.487 255.489 255.490 255.491 255.503 RISK FACTOR OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH
Appendix G Page 4 of 4 Strength test requirements for steel pipelines to operate at 125 PSIG or more Test requirements for pipelines to operate at less than 125 PSIG Test requirements for service lines Environmental protection and safety requirements Records (TESTING) Notification requirements (UPGRADES) General requirements (UPGRADES) Conversion to service subject to this Part Change in class location: Confirmation or revision of maximum allowable operating pressure Continuing surveillance Odorization Pipeline Markers Transmission lines: Record keeping Distribution systems: Patrolling Test requirements for reinstating service lines Inactive Services Abandonment or inactivation of facilities Compressor stations: storage of combustible materials Pressure limiting and regulating stations: Inspection and testing Pressure limiting and regulating stations: Telemetering or recording gauges Regulator Station MAOP Service Regulator - Min.& Oper. Load Distribution Line Valves Valve maintenance: Service line valves Regulator Station Vaults Caulked bell and spigot joints Reports of accidents Emergency lists of operator personnel Leaks General Leaks: Records Type 2 Type 3 Interruptions of service Logging and analysis of gas emergency reports Annual Report Reporting safety-related conditions General (IMP) Changes to an Integrity Management Program (IMP) Low Stress Reassessment (IMP) Measuring Program Effectiveness (IMP) Records (IMP) Records an operator must keep 255.505(e),(h),(i) 255.507 255.511 255.515 255.517 255.552 255.553(d),(e) 255.559(b) 255.611(a),(d) 255.613 255.625(e),(f) 255.707(a),(c),(d),(e) 255.709 255.721(b) 255.725 255.726 255.727(b)-(g) 255.735 255.739(c),(d) 255.741 255.743 (c) 255.744 (d),(e) 255.747 255.748 255.749 255.753 255.801 255.803 255.805(a),(b),(e),(g),(h) 255.807(a),(b),(c) 255.815(b),(c),(d) 255.817 255.823(a),(b) 255.825 255.829 255.831 255.907 255.909 255.941 255.945 255.947 255.1011 OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH OTH
OTHER RISK SECTIONS PART 261 High Pressure Piping - Annual Notice Warning tag: Class C condition Warning tag: Action and follow-up Warning Tag Records 261.19 261.61 261.63(a)-(h) 261.65 OTH OTH OTH OTH
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