Central Maine Power Company Distribution Revenue Increase and Average Residential Bill

Attachment 1

Central Maine Power CompanyDistribution Revenue Increaseand Average Residential Bill

Amount Percent

1 Distribution Revenue Increase ($000) 24,257$ 10.7%

Illustrative Average Residential Bill - based on 525 kWh per month % Increase % IncreaseBase Amount of Component of Bundled Bill

Total Residential Bill Components 2 Distribution A 24.46$ 27.49$ 12.4% 4.1%3 ELP B 0.45 0.46 2.2% 0.0%4 Conservation C 0.75 0.76 1.3% 0.0%5 Stranded Costs D 1.36 (0.69) -150.7% -2.8%6 Transmission E 11.65 12.43 6.7% 1.0%7 Subtotal Delivery 38.67$ 40.45$ 4.6% 2.4%8 Standard Offer F 35.84 39.69 10.7% 5.2%9 Total Bundled Bill 74.51$ 80.14$ 7.6% 7.6%

10 Distribution Increase Over Prior Period 3.03$

11 Distribution Increase as a Percentage of Total Bundled Bill 4.1%

Notes:A. Distribution rates reflect agreed-to changes in fixed monthly customer charges as per Stipulation, as well as recovery of December 2012 Ice Storm over a two year period, as proposed in ARP08 Compliance Filing Dkt. No.2014-0056.B. ELP (Electric Lifeline Program) held at the current level.C. Conservation held at the current level.

E. Transmission rates as updated per ARP08 Compliance Filing Dkt. No. 2014-0056.F. Standard Offer priced at March 2014 rates as listed on MPUC website.

(July 1, 2014 - June 30, 2015)Rate Year

D. Stranded Costs reflect proposed refund of Yankee Atomic and Connecticut Yankee DOE Settlement Funds

Attachment 2Page 1 of 15

Central Maine Power CompanyDistribution Revenue Requirement

Forecasted Rate Year Ended June 30, 2015

Schedule A Income StatementSchedule B RevenueSchedule C Operation & Maintenance ExpenseSchedule D Depreciation & AmortizationsSchedule E Operating TaxesSchedule F Income TaxesSchedule G Other Income & DeductionsSchedule H Interest ExpenseSchedule I Rate BaseSchedule J AmortizationsSchedule K Deferred Debits & CreditsSchedule L Weighted Average Cost of CapitalSchedule M AMI Levelization Benefit

Attachment 2Schedule A

Page 2 of 15Central Maine Power Company

Distribution Revenue Requirement for Rate Year Ended June 30, 2015Income Statement

($ 000 )

Rate Year Rate YearBefore Impact of After

Rate Increase Rate Increase Rate IncreaseRevenue

1 Delivery Revenue 226,065$ -$ 226,065$ 2 Impact of Rate Increase - 24,257 24,257 4 Delivery Revenues 226,065 24,257 250,322$ 5 Other Revenues 25,374 - 25,374 6 Total Revenues 251,439$ 24,257$ 275,696$

7 Total Operations & Maintenance 144,703$ 350$ 145,052$

8 Depreciation & Amortization 34,910$ -$ 34,910$ 9 Regulatory Debits & Credits 2,212 - 2,212

10 Taxes other than Income 13,802 - 13,802 11 Income Taxes 13,217 9,755 22,972 12 Other Operating Expenses 64,140$ 9,755$ 73,896$

13 Total Utility Operating Expense 208,843$ 10,105$ 218,948$

14 Net Utility Operating Income 42,596$ 14,152$ 56,748$

15 Net Other Income & Deductions (109)$ -$ (109)$

16 Net Interest Charges 19,899$ -$ 19,899$

17 Net Income - Electric 22,805$ 14,152$ 36,957$

18 Preferred Stock Dividends 10 - 10

19 Net Income Available for Common - Electric 22,795$ 14,152$ 36,947$

20 Average Rate Base 782,001 - 782,001 21 Common Equity Ratio 50.00% 0.00% 50.00%22 Rate Base Attributed to Common Equity 391,001$ -$ 391,001$

23 Return on Common Equity 5.83% 3.62% 9.45%

24 Overall Return on Ratebase (Lines 16 + 18 + 19 / Line 20) 5.46% 1.81% 7.27%

25 Overall Weighted Average Cost of Capital1 5.25% 1.81% 7.06%

Notes:1. Overall Weighted Average Cost of Capital is calculated in the same fashion as Overall Return on Ratebase, but excludes amortization of loss on reacquired debt and other interest expense, as found on Schedule H, rows 3 and 10.

Attachment 2Schedule B


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Revenue($ 000 )


Rate Increase Rate Increase Rate Increase

1 Delivery Revenue 226,065$ -$ 226,065$ 2 Impact of Rate Increase 24,257 24,257 3 Total Delivery Revenue 226,065$ 24,257$ 250,322$

4 Late Payment Revenues 3,257$ -$ 3,257$

5 AMI Opt-Out Fees 1,198$ -$ 1,198$ 6 Establishment of Service 1,788 - 1,788 7 Other 144 - 144 8 Misc. Service Revenues 3,130$ -$ 3,130$

9 Pole Attachments 12,152$ -$ 12,152$ 10 Misc CATV 514 - 514 11 IUMC Occupancy 330 - 330 12 Equipment Rent & Special Facilities 1,927 - 1,927 13 Other 2 - 2 14 Rent from Electric Property 14,924$ -$ 14,924$

15 Regulatory Amortizations (see below) (489)$ -$ (489)$ 16 Regulatory Deferrals (see below) 15 - 15 17 Billing and Collections Charges 1,895 - 1,895 18 Sundry O&M and Overhead Charges 1,894 - 1,894 19 Insuffficient Funds 110 - 110 20 Mutual Aid 150 - 150 21 Other 406 - 406 22 Other Electric Revenues 3,982$ -$ 3,982$

23 Damaged Billing Process 80$ -$ 80$

24 Subtotal Other Revenue 25,374$ -$ 25,374$

25 Total Revenue 251,439$ 24,257$ 275,696$

Detail of Regulatory Amortizations listed above:26 AMI Carrying Cost Deferral (724)$ -$ (724)$ 27 AMI Cost Savings Deferral 301 - 301 28 AMI Incremental O&M Cost Deferral (561) - (561) 29 AMI Grant Tax Impact Deferral (428) - (428) 30 AMI Depreciation Deferral (474) - (474) 31 AMI Legacy Meter Grant Offset Deferral 53 - 53 32 AMI Health effects (231) - (231) 33 AMI Levelization Benefit 574 - 574 34 Environmental Reserve Amortization 1,000 - 1,000 35 (489)$ -$ (489)$

Detail of Regulatory Deferrals listed above:36 ETS Pilot Project 15 - 15 37 15$ -$ 15$

Attachment 2Schedule C


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Operations & Maintenance Expense

($ 000 )



1 Payroll 38,435$ -$ 38,435$ 2 Pension 8,208 - 8,208 3 OPEB 2,392 - 2,392 4 Healthcare 6,394 - 6,394 5 Benefits-Other 1,578 - 1,578 6 Payroll Taxes 2,906 - 2,906 7 Employee Related 716 - 716 8 Advertising 385 - 385 9 Collections 2,045 - 2,045

10 Uncollectibles 3,261 350 3,611 11 Outside Services 10,202 - 10,202 12 Bill/Outage Alert 146 - 146 13 Vegetation Management - Cycle Trim 16,649 - 16,649 14 Vegetation Management - Non-Cycle Trim Programs 1 3,724 - 3,724 15 Legal/Rate Case Costs 1,310 - 1,310 16 IUMC Charges 14,994 - 14,994 17 Injuries & Damages 685 - 685 18 Insurances 943 - 943 19 Postage 1,707 - 1,707 20 Regulatory Assessments 2,506 - 2,506 21 Rents/Leases 4,595 - 4,595 22 Utilities 1,394 - 1,394 23 Materials 1,645 - 1,645 24 Telephone 1,100 - 1,100 25 Vehicles 7,408 - 7,408 26 Tier 1 Storm Expense 4,000 - 4,000 27 Tier 2 Storm Reserve 6,000 - 6,000 28 AMI Capability (450) - (450) 29 Other O&M 132 - 132 30 Productivity Offset (307) - (307) 31 Total Operations and Maintenance 144,703$ 350$ 145,052$

Attachment 2Schedule C


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Vegetation Management - Non-Cycle Trim Programs

($ 000 )

RateYear 1

Amounts

1 Hot Spot 1,029$ 2 Incidental Work 895 3 Enhanced Line Clearance 1,800 4 Total 3,724$

CMP commits to funding the non-cycle trim programs at the levels listed above, per paragraph 26 (b) ofthe Stipulation.

Attachment 2Schedule D


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Depreciation & Amortization Expense

($ 000 )



1 Depreciation - Distribution Plant 37,161$ -$ 37,161$ 2 SFAS 143 Cost of Removal Amortization (2,251) - (2,251) 3 Total Depreciation & Amortization 34,910$ -$ 34,910$

4 Legacy Meter Amortization 2,212$ -$ 2,212$ 5 Total Regulatory Debits/Credits 2,212$ -$ 2,212$

Attachment 2Schedule E


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Operating Taxes

($ 000 )



1 Property Taxes 13,797$ -$ 13,797$ 2 Use Taxes 5 - 5 3 Total Taxes Other Than Income Taxes 13,802$ -$ 13,802$

Attachment 2Schedule F


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Income Taxes

($ 000 )



1 Revenues 251,439$ 24,257$ 275,696$

2 O&M Expenses 144,703$ 350$ 145,052$ 3 Depreciation & Amortization 34,910 - 34,910 4 Regulatory Debits & Credits 2,212 - 2,212 5 Taxes other than Income 13,802 - 13,802 6 Other Income & Deductions (183) - (183) 7 Net Interest Charges 19,899 - 19,899 8 Total Expenses 215,342$ 350$ 215,692$

9 Income Before Taxes 36,096$ 23,907$ 60,004$

10 Federal Taxes At Statutory Rate of 35% 12,634$ 8,367$ 21,001$ 11 State Taxes At Statutory Rate of 8.93% 3,223 2,135 5,358 12 Federal Benefit of State Tax Deduction (1,128) (747) (1,875) 13 Total Federal and State Income Taxes at Statutory Rate 14,729$ 9,755$ 24,484$

Tax AdjustmentsFlow-Throughs

14 Cost of Removal (288)$ -$ (288)$ 15 Salvage Proceeds 167 - 167 16 Tax Basis Repairs/Unit of Property 1

(3,952) - (3,952) 17 FAS 143 Cost of Removal (651) - (651) 18 Subtotal (4,724)$ -$ (4,724)$

19 Plant Related 3,823$ -$ 3,823$ 20 Prepaid Insurance (12) - (12) 21 Amort Loss on Bonds 37 - 37 22 Loss on early retirments of Property (388) - (388) 23 Edison Drive Cap Lease (216) - (216) 24 Edison Drive Interest Expense 111 - 111 25 Edison Drive Building Rent per Books 42 - 42 26 Subtotal 3,396$ -$ 3,396$

Permanent27 Meals & entertainment 34$ -$ 34$ 28 Total Permanent Differences 34$ -$ 34$

29 ITC's (144)$ -$ (144)$

30 Total Effective Tax Rate Adjustments (rows 18+26+28+29) (1,438)$ -$ (1,438)$

31 Total Income Taxes 13,291$ 9,755$ 23,047$ 32 less OID Income Taxes (75) - (75) 33 Income Taxes - Operating 13,217$ 9,755$ 22,972$

1. Includes Tax Basis Repairs resolution pursuant to Stipulation Section IV A.

Attachment 2Schedule G


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Other Income and Deductions

($ 000 )



1 Interest & Dividend Income (183)$ -$ (183)$ 2 Other Miscellaneaous Income 0 - 0 3 Income Taxes on OID 75 - 75 4 Total Other Income and Deductions (109)$ -$ (109)$

Attachment 2Schedule H


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Interest Expense

($ 000 )



Interest Expense Summary1 Long Term Debt 17,897$ -$ 17,897$ 2 Short Term Debt 392 - 392 3 Amortzation of Loss on Reacquired Debt 153 - 153

Other Interest Expense:4 FIN 48 252 - 252 5 Customer Deposits 92 - 92 6 Late Payments (0) - (0) 7 Revolver Fees 367 - 367 8 Carrying Costs 369 - 369 9 Edison Drive 378 - 378

10 Subtotal Other Interest Expense 1,458$ - 1,458$

11 Total Interest Expense 19,899$ -$ 19,899$

12 Preferred Dividends 10$ -$ 10$

Calculation of Long Term Debt, Short Term Debt & Preferred Dividends

12 Rate Base 782,001$ -$ 782,001$

13 LTD % of Capitalization 45.80% 0.00% 45.80%14 LTD Component of Rate Base 358,179$ -$ 358,179$ 15 LTD Interest Rate 5.00% 0.00% 5.00%16 LTD Expense 17,897$ -$ 17,897$

17 STD % of Capitalization 4.18% 0.00% 4.18%18 STD Component of Rate Base 32,650$ -$ 32,650$ 19 STD Interest Rate 1.20% 0.00% 1.20%20 STD Expense 392$ -$ 392$

21 Preferred % of Capitalization 0.02% 0.00% 0.02%22 Preferred Component of Rate Base 172$ -$ 172$ 23 Preferred Dividend Rate 6.00% 0.00% 6.00%24 Preferred Dividends 10$ -$ 10$

Attachment 2Schedule I


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Rate Base

($ 000 )



1 Plant in Service 1,425,725$ -$ 1,425,725$ 2 Accumulated Depreciation Reserve 458,560 - 458,560 3 Net Operating Property 967,166 - 967,166 4 Accumulated Deferred Income Taxes (169,531) - (169,531) 5 Other Rate Base (30,257) - (30,257) 6 Working Capital 14,624 - 14,624 7 Total Rate Base 782,001$ -$ 782,001$

Attachment 2Schedule J


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Amortizations

($ 000 )

Rate Year Rate YearDeferred Balance Deferred BalanceBefore Settlement Settlement After Settlement Amortization Rate Year

Adjustment Adjustment Adjustment Period (years) Amortization

1 AMI Carrying Cost Deferral 13,747$ -$ 13,747$ 19 (724)$ 2 AMI Cost Savings Deferral (4,770) (957) (5,727) 19 301 3 AMI Incremental O&M Cost Deferral 10,658 - 10,658 19 (561) 4 AMI Grant Tax Impact Deferral 8,124 - 8,124 19 (428) 5 AMI Depreciation Deferral 9,013 - 9,013 19 (474) 6 AMI Legacy Meter Grant Offset Deferral (1,008) - (1,008) 19 53 7 AMI Health effects 1,154 - 1,154 5 (231) 8 AMI Levelization Benefit (see Schedule M) 574 9 Environmental Reserve Amortization (3,000) - (3,000) 3 1,000

10 Total Regulatory Amortizations (489)$

Attachment 2Schedule K


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Deferred Debits & Credits

($ 000 )

Rate Year

Average BalanceAMI-Related

1 AMI-Legacy Meters 1,888$ 2 AMI CC on Cap+O&M-Grant 13,385 3 AMI O&M Deferral 10,377 4 AMI Savings Deferral (5,576) 5 AMI Tax Benefit on Legacy Meters 7,910 6 AMI Depreciation Deferral 8,776 7 AMI Legacy Meter Grant Offset (981) 8 AMI Opt Out Participation Over/Under Collection - 9 AMI Health Effects 1,039

10 Total AMI-Reg Assets 36,817$

All Other11 Pension 36,793$ 12 OPEB (31,661) 13 SFAS 106 Amortization 3,507 14 SFAS 158 Pension Revaluation Amortization (0) 15 Customer Deposits (12,608) 16 SFAS 143 Removal Cost Amortization (60,965) 17 Standard Offer Retainage - 18 Accumulated Provision for Uncollectible Accounts (6,859) 19 Materials and Supplies 10,534 20 Injuries and Damages (1,681) 21 Workers Compensation (1,930) 22 Refundable CIACs (126) 23 General Office Liability (457) 24 Loss on Reacquired Debt 878 25 Environmental Reserve (2,500) 26 Total Average Balances (30,257)$

Attachment 2Schedule L


Distribution Revenue Requirement for Rate Year Ended June 30, 2015Weighted Average Cost of Capital

($ 000 )

Capitalization Weighted Tax Gross-Up WeightedPercentage Cost Cost at 40.8045% Cost

1 Common Equity 50.00% 9.45% 4.73% 3.26% 7.98%2 Preferred Stock 0.02% 6.00% 0.00% 0.00% 0.00%3 Long Term Debt 45.80% 5.00% 2.29% 2.29%4 Short Term Debt 4.18% 1.20% 0.05% 0.05%

5 Total 100.00% 7.06% 3.26% 10.32%

Attachment 2Schedule M


Distribution Revenue Requirement for Rate Year Ended June 30, 2015AMI Levelization

($ 000 )

Distribution Remove Impact Dist Rev Req Levelized Period Ending Average After Tax Calculated LevelizationRevenue of Deferred Excl Impact Revenue Deferred Deferred Average Levelization Benefit to

Requirement Debits/Credits of Def Dr/Cr Requirement Balance Balance Balance Benefit2 Customers(A) (B) (C) (D) (E) (F) (G) (H) (I)

1 TME 6/30/14 14,017$ 1 4,915$ 9,102$ 2,851$ 6,251$ 3,125$ 1,850$ 202$ 2,517$ 1

2 TME 6/30/15 12,669 4,514 8,154 2,851 11,554 8,902 5,270 574 574 3 TME 6/30/16 11,905 4,373 7,533 2,851 16,236 13,895 8,225 897 897 4 TME 6/30/17 10,802 4,231 6,571 2,851 19,956 18,096 10,712 1,168 1,168 5 TME 6/30/18 9,219 4,090 5,130 2,851 22,234 21,095 12,487 1,361 1,361 6 TME 6/30/19 8,155 3,948 4,207 2,851 23,590 22,912 13,563 1,478 1,478 7 TME 6/30/20 7,663 3,807 3,856 2,851 24,594 24,092 14,262 1,555 1,555 8 TME 6/30/21 7,107 3,665 3,441 2,851 25,185 24,890 14,733 1,606 1,606 9 TME 6/30/22 6,649 3,524 3,125 2,851 25,459 25,322 14,989 1,634 1,634

10 TME 6/30/23 6,188 3,383 2,805 2,851 25,413 25,436 15,057 1,641 1,641 11 TME 6/30/24 5,722 3,241 2,481 2,851 25,042 25,227 14,933 1,628 1,628 12 TME 6/30/25 5,251 3,100 2,151 2,851 24,342 24,692 14,617 1,593 272 13 TME 6/30/26 4,776 2,958 1,818 2,851 23,309 23,825 14,104 1,537 14 TME 6/30/27 4,296 2,817 1,479 2,851 21,936 22,622 13,391 1,460 15 TME 6/30/28 3,811 2,675 1,135 2,851 20,220 21,078 12,477 1,360 16 TME 6/30/29 3,320 2,534 786 2,851 18,156 19,188 11,358 1,238 17 TME 6/30/30 2,820 2,392 427 2,851 15,732 16,944 10,030 1,093 18 TME 6/30/31 1,459 2,251 (792) 2,851 12,089 13,910 8,234 898 19 TME 6/30/32 (603) 2,110 (2,713) 2,851 6,525 9,307 5,509 601 20 TME 6/30/33 (1,705) 1,968 (3,674) 2,851 - 3,262 1,931 210 21 123,520$ 66,497$ 57,023$ 57,023$ 23,733$ 16,330$

Notes:1) See Exhibit 1 to the Stipulation approved by the MPUC on 6/24/13 authorizing CMP to include $11.5 million in its July 1, 2013 price change. Per Exhibit 1, this $11.5M consisted of a $14.017M revenue requirement, partially offset by -$2.517 attributed to the levelization benefit.

Attachment 3 Docket No. 2013-168

{W4310818.4}

Central Maine Power Company Distribution Related Deferrals

Pursuant to the terms of this Stipulation, CMP is authorized to establish the following distribution related deferrals:

1. Storm reserve for applicable Tier 2 and 3 costs

2. Tier 3 storm costs above $15 million

3. Revenue Decoupling Mechanism

4. Power-Tax regulatory asset (including incremental costs to seek a Private Letter Ruling) In addition, CMP will continue deferral accounting for the following distribution related items in accordance with the terms of the authorizations noted along with such items:

5. Environmental Remediation (Docket No. 2007-215) – reserve accounting will remain in place.

6. O’Connor superfund site (Docket No. 91-216)

7. Electric Thermal Storage Pilot costs (Docket No. 2012-325)

8. Standard Offer Retainage (Docket No. 2010-327)

9. AMI Opt-out program (Docket Nos. 2010-345, 2010-389, 2010-398, 2010-400, and 2011-085)

10. AMI deferral costs and AMI legal / health proceeding costs (Docket Nos. 2010-51 (Phase II) and 2011-262). No additional amounts will be deferred beyond June 30, 2014 unless authorized by the Commission.

11. Conservation Program, Demand Side Management (DSM) costs (Docket No. 2002-161)

12. Low Income program, Electric Lifeline Program (ELP) costs (Docket No. 92-435)

13. Make-Ready Line Extension costs (Docket No. 2012-313). No additional amounts will be deferred after June 30, 2014 unless authorized by the Commission.

14. Electric Vehicle Pilot Program Phase II costs (Docket No. 2012-350)

15. Transmission Planning and costs allocation (Pursuant to Paragraph V(E)(4) of the MPRP Stipulation approved by Commission Order dated June 10, 2010 in Docket No. 2008-255)

16. GAAP Financial Accounting Standards including:

a. FAS 158 Pension & OPEB (ASC 718)

Attachment 3 Docket No. 2013-168

{W4310818.4}

b. FAS 109 Taxes (ASC 740)

c. FAS 143 Asset Retirement Obligations (ASC 410) Nothing in this Attachment 3 limits CMP’s authorization regarding deferral accounting for stranded cost and transmission related items and limits CMP’s rights under 35-A M.R.S. §§ 501, 502(1), 1322 and other applicable law to seek an accounting order. Note: Deferrals may be recorded in expense or revenue as appropriate in conformance with accounting requirements.

Attachment 4

NETSURVIVOR SALVAGE ACCRUAL

ACCOUNT CURVE PERCENT RATE(1) (2) (3) (4)

ELECTRIC PLANT

DISTRIBUTION PLANT

1 360.10 LAND RIGHTS 70-SQ 0 0.84 2 361.00 STRUCTURES AND IMPROVEMENTS 82-S0 (1) 1.08 3 362.00 STATION EQUIPMENT 42-O1 15 1.62 4 364.00 POLES, TOWERS AND FIXTURES 49-S0 (19) 2.34 5 365.00 OVERHEAD CONDUCTORS AND DEVICES 55-R0.5 (7) 2.27 6 366.00 UNDERGROUND CONDUIT 55-R2 (15) 1.70 7 367.00 UNDERGROUND CONDUCTORS AND DEVICES 54-R2 (21) 2.40 8 368.00 LINE TRANSFORMERS 42-R1.5 (6) 2.18 9 369.00 SERVICES 46-R0.5 (18) 2.34 10 370.00 METERS 21-L1 0 4.30 11 370.10 METERS - AMI 20-S3 0 5.07 12 372.00 LEASED EQUIPMENT ON CUSTOMERS' PREMISES 10-SQ 0 - 13 373.00 STREET LIGHTING AND SIGNAL SYSTEMS 29-L0 (9) 3.30

GENERAL PLANT

14 390.00 STRUCTURES AND IMPROVEMENTS 52-R2.5 (30) 2.07 15 391.00 OFFICE FURNITURE AND EQUIPMENT 26-SQ 0 9.01 16 391.10 HANDHELD EQUIPMENT 5-SQ 0 15.33 17 391.20 WORK MANAGEMENT SYSTEM HARDWARE 10-SQ 0 11.10 18 391.30 DISPATCH COMPUTERS 5-SQ 0 - 19 391.40 DATA PROCESSING EQUIPMENT 5-SQ 0 19.10 20 393.00 STORES EQUIPMENT 32-SQ 0 3.62 21 394.00 TOOLS AND SHOP EQUIPMENT 28-SQ 0 3.77 22 394.00 GARAGE EQUIPMENT 23-SQ 0 6.17 23 395.00 LABORATORY EQUIPMENT 27-SQ 0 6.62 24 397.00 COMMUNICATION EQUIPMENT 28-O1 (2) 1.88 25 397.10 COMMUNICATION EQUIPMENT - AMI 20-S1.5 0 5.12 26 398.00 MISCELLANEOUS EQUIPMENT 15-SQ 0 6.56

ACCOUNTS INDIVIDUALLY DEPRECIATED

27 392.00 TRANSPORTATION EQUIPMENT - PASSENGER CARS FULLY ACCRUED - **28 392.00 TRANSPORTATION EQUIPMENT - PASSENGER CARS 4 25.00 **29 392.10 TRANSPORTATION EQUIPMENT - OVERHAUL/REBUILD FULLY ACCRUED - **30 392.10 TRANSPORTATION EQUIPMENT - OVERHAUL/REBUILD 3 32.43 **31 392.20 TRANSPORTATION EQUIPMENT - TRUCKS FULLY ACCRUED - **32 392.20 TRANSPORTATION EQUIPMENT - TRUCKS 5.8 17.14 **33 392.30 TRANSPORTATION EQUIPMENT - DIGGER/FREIGHT FULLY ACCRUED - **34 392.30 TRANSPORTATION EQUIPMENT - DIGGER/FREIGHT 7.5 13.33 **35 392.40 TRANSPORTATION EQUIPMENT - TRAILERS/OFF ROAD FULLY ACCRUED - **36 392.40 TRANSPORTATION EQUIPMENT - TRAILERS/OFF ROAD 10 10.00 **

** ANNUAL ACCRUAL AMOUNT IS CALCULATED FOR EACH ASSET

Central Maine Power CompanySummary of Book Depreciation Accrual Rates

Stipulation Attachment 5Docket No. 2013-168

Page 1 of 14

Description Page

Rate Year Customer Count by Month 2

Distribution Revenue Associated with Targeted Programs and Special Rate Contracts 3

Description of Customer Growth Calculation 4

Illustrative calculation of Customer Growth Factors 5 - 6

Illustrative Rate Year Revenue Targets 7

Calculation of illustrative revenue targets for future periods 8 - 10

Calculation of illustrative RDM reconciliation for Jul 2014 - Dec 2015. 11 - 12

Calculation of illustrative RDM reconciliation for Jan 2016 - Dec 2016. 13 - 14

Central Maine Power CompanyIllustrative Example of RDM Revenue Targets and Reconciliation

Table of Contents


Page 2 of 14

Central Maine Power Company

RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast

Historical Base For Period 1 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Average Customers

RESIDENTIAL A/R 542,109 542,379 542,559 542,912 543,491 543,952 544,337 544,509 544,672 544,477 543,964 544,081 543,620 A/R-TOU / A-TOU-OPTS 6,367 6,371 6,373 6,378 6,383 6,389 6,394 6,395 6,397 6,395 6,389 6,390 6,385 A-LM 163 164 164 164 164 164 164 164 164 164 164 164 164 TOTAL RESIDENTIAL RDM GROUP 548,639 548,914 549,096 549,454 550,038 550,505 550,895 551,068 551,233 551,036 550,517 550,635 550,169

COMM/IND SGS / SGS-TOU 50,942 51,021 51,007 50,996 50,999 51,021 51,039 51,039 51,092 51,174 51,258 51,334 51,077 MGS-S / MSG-S-TOU 12,051 12,069 12,066 12,064 12,064 12,069 12,073 12,073 12,086 12,106 12,125 12,143 12,082 MGS-P / MGS-P-TOU 168 169 169 169 169 169 169 169 169 169 169 170 169 IGS-S 202 202 202 202 202 202 202 202 202 202 203 203 202 IGS-P 59 59 59 59 59 59 59 59 59 59 59 59 59 LGS-S 10 10 10 10 10 10 10 10 10 10 10 10 10 LGS-P 61 61 61 61 61 61 61 61 61 61 61 61 61 TOTAL COMM/IND RDM GROUP 63,493 63,591 63,574 63,561 63,564 63,591 63,613 63,613 63,679 63,781 63,885 63,980 63,660

RY Customer Counts by Month

Stipulation�Attachment�5�Docket�No.�2013Ͳ00168�

Page�ϯ�ŽĨ�ϭϰ

Central Maine Power CompanyDistribution Revenue Associated with Targeted Programs and Special Rate Contracts

Targeted Programs:July 2014 - June 2015 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15

A-TOU-SS 705,537$ 42,131$ 47,079$ 42,447$ 42,167$ 51,575$ 74,855$ 88,302$ 92,732$ 74,024$ 64,205$ 44,432$ 41,588$ A-TOU-SP 102,094 7,802 8,937 7,895 7,186 7,631 9,880 10,647 10,679 8,942 8,203 7,175 7,117 Easy Hours for Business 52,415 4,485 5,736 5,125 4,578 4,447 4,410 4,164 4,123 3,605 3,755 3,783 4,205 MMI 132,009 11,357 9,644 11,555 11,752 11,167 11,126 10,675 11,018 10,302 10,838 10,984 11,591 PTZ 50,616 4,218 4,218 4,218 4,218 4,218 4,218 4,218 4,218 4,218 4,218 4,218 4,218

Total Targeted Programs 1,042,670$ 69,993$ 75,613$ 71,239$ 69,901$ 79,037$ 104,489$ 118,006$ 122,769$ 101,092$ 91,219$ 70,592$ 68,719$

Special Rate Contracts:

Customer 1 129,664$ 8,775$ 8,644$ 8,614$ 8,731$ 8,908$ 15,179$ 15,091$ 14,529$ 14,661$ 8,835$ 8,900$ 8,798$ Customer 2 79 0 1 1 2 8 17 19 14 9 6 3 0 Customer 3 6,864 572 572 572 572 572 572 572 572 572 572 572 572 Customer 4 34,210 2,851 2,851 2,851 2,851 2,851 2,851 2,851 2,851 2,851 2,851 2,851 2,851 Customer 5 6,864 572 572 572 572 572 572 572 572 572 572 572 572 Customer 6 - - - - - - - - - - - - - Customer 7 9,591 799 799 799 799 799 799 799 799 799 799 799 799 Customer 8 136,958 8,471 8,503 8,502 8,735 8,526 16,899 17,157 17,103 16,810 9,220 8,399 8,633 Customer 9 9,591 799 799 799 799 799 799 799 799 799 799 799 799

Total Special Rate Contracts 333,822$ 22,839$ 22,741$ 22,711$ 23,061$ 23,035$ 37,689$ 37,860$ 37,239$ 37,073$ 23,654$ 22,896$ 23,024$

Total Special Rate Programs and Targeted Contracts 1,376,492$ 92,832$ 98,355$ 93,950$ 92,962$ 102,072$ 142,178$ 155,866$ 160,008$ 138,164$ 114,872$ 93,488$ 91,743$

Note: In the event the Commission approves any rate design modifications in the litigated portion of this proceeding as set forth in paragraph 73 of the Stipulation, any revenue impact will be reconciled within the applicable RDM classes unless the Commission orders a different recovery mechanism.


Page 4 of 14

Description

July- December 2015:

2016

2017 and subsequent calendar years

Period 1 -- Jul 15-Dec 15 0.33%

Calendar Year 2016 0.21%



Period 1 -- Jul 15-Dec 15 0.40%




RDM Revenue Adjustments:

CMP will compare actual customer counts for Jan - December of prior year with actual customer counts Jan - December of current year.

Illustrative Residential Customer Revenue Adjustment Factor

Illustrative Comm/Ind Customer Revenue Adjustment Factor

The RDM Reconciliation examples in this Attachment do not reflect any RDM carrying costs or Storm Cost mechanism rate adjustments. Actual RDM reconciliations will include carrying costs and any Storm Cost mechanism rate adjustments.


Description of Customer Growth Calculation

CMP will compare rate year forecast customer counts from July 2014 to December 2014 to actual customer counts from July 2015 - December 2015 to determine the actual customer count growth rate.

CMP will compare rate year forecast customer counts for Jan - June 2015 with actual customer counts Jan - June 2016. CMP will compare actual customer counts for July - December 2015 with actual customer counts July - December 2016.


Page 5 of 14


RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast

Historical Base For Period 1 Jul-14 Aug-14 Sep-14 Oct-14 Nov-14 Dec-14 Average Customers

RESIDENTIAL A/R 542,109 542,379 542,559 542,912 543,491 543,952 542,900 A/R-TOU / A-TOU-OPTS 6,367 6,371 6,373 6,378 6,383 6,389 6,377 A-LM 163 164 164 164 164 164 164 TOTAL RESIDENTIAL RDM GROUP 548,639 548,914 549,096 549,454 550,038 550,505 549,441

COMM/IND SGS / SGS-TOU 50,942 51,021 51,007 50,996 50,999 51,021 50,998 MGS-S / MSG-S-TOU 12,051 12,069 12,066 12,064 12,064 12,069 12,064 MGS-P / MGS-P-TOU 168 169 169 169 169 169 169 IGS-S 202 202 202 202 202 202 202 IGS-P 59 59 59 59 59 59 59 LGS-S 10 10 10 10 10 10 10 LGS-P 61 61 61 61 61 61 61 TOTAL COMM/IND RDM GROUP 63,493 63,591 63,574 63,561 63,564 63,591 63,562

Actual Actual Actual Actual Actual Actual

Illustrative Actual Period 1Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15

RESIDENTIALApply to July

15 Rev A/R 1.01 544,820 545,091 545,272 545,627 546,208 546,672 545,615 A/R-TOU / A-TOU-OPTS 0.95 6,049 6,052 6,054 6,059 6,064 6,070 6,058 A-LM 0.98 160 161 161 161 161 161 161 TOTAL RESIDENTIAL RDM GROUP 551,028 551,304 551,487 551,846 552,433 552,902 551,833 0.44% 0.33%

COMM/IND SGS / SGS-TOU 1.01 51,400 51,480 51,466 51,455 51,458 51,480 51,457 MGS-S / MSG-S-TOU 0.99 11,930 11,948 11,945 11,943 11,943 11,948 11,943 MGS-P / MGS-P-TOU 1.01 169 170 170 170 170 170 170 IGS-S 1.01 203 203 203 203 203 203 203 IGS-P 0.95 56 56 56 56 56 56 56 LGS-S 1.01 10 10 10 10 10 10 10 LGS-P 0.98 60 60 60 60 60 60 60 TOTAL COMM/IND RDM GROUP 63,829 63,927 63,910 63,897 63,900 63,927 63,898 0.53% 0.40%

RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast RY Forecast Actual Actual Actual Actual Actual Actual

Illustrative Base Period For Year2* Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15

RESIDENTIAL A/R 544,337 544,509 544,672 544,477 543,964 544,081 544,820 545,091 545,272 545,627 546,208 546,672 544,977 A/R-TOU / A-TOU-OPTS 6,394 6,395 6,397 6,395 6,389 6,390 6,049 6,052 6,054 6,059 6,064 6,070 6,226 A-LM 164 164 164 164 164 164 160 161 161 161 161 161 162 TOTAL RESIDENTIAL RDM GROUP 550,895 551,068 551,233 551,036 550,517 550,635 551,028 551,304 551,487 551,846 552,433 552,902 551,365 COMM/IND SGS / SGS-TOU 51,039 51,039 51,092 51,174 51,258 51,334 51,400 51,480 51,466 51,455 51,458 51,480 51,306 MGS-S / MSG-S-TOU 12,073 12,073 12,086 12,106 12,125 12,143 11,930 11,948 11,945 11,943 11,943 11,948 12,022 MGS-P / MGS-P-TOU 169 169 169 169 169 170 169 170 170 170 170 170 169 IGS-S 202 202 202 202 203 203 203 203 203 203 203 203 203 IGS-P 59 59 59 59 59 59 56 56 56 56 56 56 58 LGS-S 10 10 10 10 10 10 10 10 10 10 10 10 10 LGS-P 61 61 61 61 61 61 60 60 60 60 60 60 60 TOTAL COMM/IND RDM GROUP 63,613 63,613 63,679 63,781 63,885 63,980 63,829 63,927 63,910 63,897 63,900 63,927 63,828 * January - June taken from Rate Year Customer Count forecasts.

Illustrative calculation of Customer Growth Factors

Average Customers

Year over Year Customer Growth

75% of Customer Growth

Average Customers


Page 6 of 14


Illustrative calculation of Customer Growth Factors

Actual Actual Actual Actual Actual Actual Actual Actual Actual Actual Actual Actual

Illustrative Actual Year2Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16

RESIDENTIALApply to CY

16 Rev A/R 1.00 546,514 546,687 546,851 546,655 546,140 546,257 546,999 547,271 547,453 547,809 548,393 548,858 547,157 A/R-TOU / A-TOU-OPTS 0.90 5,755 5,756 5,757 5,756 5,750 5,751 5,444 5,447 5,449 5,453 5,457 5,463 5,603 A-LM 0.80 131 131 131 131 131 131 128 129 129 129 129 129 130 TOTAL RESIDENTIAL RDM GROUP 552,400 552,574 552,739 552,542 552,021 552,140 552,570 552,847 553,030 553,391 553,979 554,450 552,890 0.28% 0.21%

COMM/IND SGS / SGS-TOU 1.01 51,345 51,345 51,399 51,481 51,566 51,642 51,709 51,789 51,775 51,764 51,767 51,789 51,614 MGS-S / MSG-S-TOU 0.98 11,832 11,832 11,844 11,864 11,883 11,900 11,692 11,709 11,706 11,704 11,704 11,709 11,782 MGS-P / MGS-P-TOU 0.99 167 167 167 167 167 168 167 168 168 168 168 168 168 IGS-S 1.00 203 203 203 203 204 204 204 204 204 204 204 204 203 IGS-P 0.95 56 56 56 56 56 56 53 53 53 53 53 53 55 LGS-S 0.99 10 10 10 10 10 10 10 10 10 10 10 10 10 LGS-P 0.95 58 58 58 58 58 58 57 57 57 57 57 57 57

TOTAL COMM/IND RDM GROUP 63,671 63,671 63,737 63,839 63,943 64,038 63,892 63,990 63,973 63,960 63,963 63,990 63,889 0.09% 0.07%


Illustrative Actual Year3

Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17Average

Customers

Year over Year

Customer Growth



17 Rev A/R 1.00 548,154 548,327 548,491 548,295 547,778 547,896 548,640 548,913 549,095 549,452 550,038 550,505 548,799 A/R-TOU / A-TOU-OPTS 0.90 5,179 5,180 5,182 5,180 5,175 5,176 4,899 4,902 4,904 4,908 4,912 4,916 5,043 A-LM 0.80 105 105 105 105 105 105 102 103 103 103 103 103 104 TOTAL RESIDENTIAL RDM GROUP 553,438 553,612 553,778 553,580 553,058 553,177 553,641 553,918 554,102 554,463 555,053 555,524 553,945 0.19% 0.14%

COMM/IND SGS / SGS-TOU 1.00 51,345 51,345 51,399 51,481 51,566 51,642 51,709 51,789 51,775 51,764 51,767 51,789 51,614 MGS-S / MSG-S-TOU 1.05 12,423 12,423 12,436 12,457 12,477 12,495 12,276 12,295 12,292 12,290 12,290 12,295 12,371 MGS-P / MGS-P-TOU 1.00 167 167 167 167 167 168 167 168 168 168 168 168 168 IGS-S 1.05 213 213 213 213 214 214 214 214 214 214 214 214 214 IGS-P 0.90 50 50 50 50 50 50 48 48 48 48 48 48 49 LGS-S 1.04 10 10 10 10 10 10 10 10 10 10 10 10 10 LGS-P 1.05 61 61 61 61 61 61 60 60 60 60 60 60 60 TOTAL COMM/IND RDM GROUP 64,270 64,270 64,337 64,440 64,545 64,641 64,484 64,584 64,567 64,553 64,557 64,584 64,486 0.93% 0.70%


Illustrative Actual Year4

Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18Average

Customers

Year over Year

Customer Growth



18 Rev A/R 1.00 549,798 549,972 550,137 549,940 549,422 549,540 550,286 550,560 550,743 551,101 551,689 552,157 550,445 A/R-TOU / A-TOU-OPTS 0.92 4,765 4,766 4,767 4,766 4,761 4,762 4,507 4,510 4,512 4,515 4,519 4,523 4,639 A-LM 0.84 88 88 88 88 88 88 86 86 86 86 86 86 87 TOTAL RESIDENTIAL RDM GROUP 554,651 554,826 554,992 554,793 554,271 554,390 554,879 555,157 555,341 555,702 556,294 556,766 555,172 0.22% 0.17%COMM/IND SGS / SGS-TOU 1.00 51,345 51,345 51,399 51,481 51,566 51,642 51,709 51,789 51,775 51,764 51,767 51,789 51,614 MGS-S / MSG-S-TOU 1.02 12,672 12,672 12,685 12,706 12,726 12,745 12,522 12,541 12,538 12,536 12,536 12,541 12,618 MGS-P / MGS-P-TOU 1.00 167 167 167 167 167 168 167 168 168 168 168 168 168 IGS-S 1.03 219 219 219 219 220 220 220 220 220 220 220 220 220 IGS-P 0.90 45 45 45 45 45 45 43 43 43 43 43 43 44 LGS-S 1.03 11 11 11 11 11 11 11 11 11 11 11 11 11 LGS-P 1.05 64 64 64 64 64 64 63 63 63 63 63 63 63 TOTAL COMM/IND RDM GROUP 64,523 64,523 64,590 64,694 64,799 64,896 64,735 64,835 64,817 64,804 64,807 64,835 64,738 0.39% 0.29%


Average Customers

Year over Year

Customer Growth


Page 7 of 14Central Maine Power CompanyIllustrative Example of RDM Revenue Targets and Reconciliation

Illustrative Rate Year Revenue Targets

The amounts below are for illustration purposes only. Rate year RDM Revenue Targest will be submitted in the Company's compliance filing on August 15, 2014 once the final rate design is determined by the Commission.

Illustrative Rate Year Targets Jul-14 * Aug-14 * Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Total

RESIDENTIAL A/R 15,457,000$ 16,544,000$ 14,483,000$ 13,036,000$ 13,412,000$ 14,665,000$ 15,026,000$ 14,656,000$ 14,082,000$ 13,610,000$ 13,142,000$ 13,599,000$ 171,712,000$ A/R-TOU / A-TOU-OPTS 323,000 347,000 309,000 278,000 313,000 393,000 444,000 436,000 396,000 340,000 303,000 294,000 4,176,000 A-LM 2,000 2,000 2,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 33,000

TOTAL RESIDENTIAL RDM GROUP 15,782,000$ 16,893,000$ 14,794,000$ 13,317,000$ 13,728,000$ 15,061,000$ 15,473,000$ 15,095,000$ 14,481,000$ 13,953,000$ 13,448,000$ 13,896,000$ 175,921,000$

COMM/IND SGS / SGS-TOU 2,417,000$ 2,471,000$ 2,130,000$ 1,883,000$ 1,868,000$ 2,055,000$ 2,074,000$ 2,099,000$ 2,007,000$ 1,918,000$ 1,860,000$ 2,003,000$ 24,785,000$ MGS-S / MSG-S-TOU 2,492,000 2,368,000 2,500,000 2,216,000 2,218,000 2,188,000 2,123,000 2,122,000 2,199,000 2,155,000 2,279,000 2,363,000 27,223,000 MGS-P / MGS-P-TOU 83,000 76,000 94,000 94,000 80,000 82,000 75,000 78,000 79,000 75,000 82,000 87,000 985,000 IGS-S 409,000 380,000 353,000 310,000 302,000 298,000 303,000 307,000 331,000 328,000 357,000 362,000 4,040,000 IGS-P 144,000 128,000 158,000 145,000 143,000 139,000 135,000 135,000 142,000 139,000 143,000 144,000 1,695,000 LGS-S 60,000 59,000 69,000 56,000 49,000 56,000 49,000 50,000 54,000 56,000 57,000 57,000 672,000 LGS-P 531,000 531,000 584,000 523,000 519,000 531,000 481,000 498,000 518,000 494,000 571,000 547,000 6,328,000 TOTAL COMM/IND RDM GROUP 6,136,000$ 6,013,000$ 5,888,000$ 5,227,000$ 5,179,000$ 5,349,000$ 5,240,000$ 5,289,000$ 5,330,000$ 5,165,000$ 5,349,000$ 5,563,000$ 65,728,000$ * For the purpose of constructing future targets, July and August revenues reflect as if the rate increase had gone into effect on 7/1/14.


Page 8 of 14Central Maine Power CompanyCalculation of illustrative revenue targets for future periods

Illustrative Rate Year Targets Jul-14 * Aug-14 * Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Total



COMM/IND SGS / SGS-TOU 2,417,000$ 2,471,000$ 2,130,000$ 1,883,000$ 1,868,000$ 2,055,000$ 2,074,000$ 2,099,000$ 2,007,000$ 1,918,000$ 1,860,000$ 2,003,000$ 24,785,000$ MGS-S / MSG-S-TOU 2,492,000 2,368,000 2,500,000 2,216,000 2,218,000 2,188,000 2,123,000 2,122,000 2,199,000 2,155,000 2,279,000 2,363,000 27,223,000 MGS-P / MGS-P-TOU 83,000 76,000 94,000 94,000 80,000 82,000 75,000 78,000 79,000 75,000 82,000 87,000 985,000 IGS-S 409,000 380,000 353,000 310,000 302,000 298,000 303,000 307,000 331,000 328,000 357,000 362,000 4,040,000 IGS-P 144,000 128,000 158,000 145,000 143,000 139,000 135,000 135,000 142,000 139,000 143,000 144,000 1,695,000 LGS-S 60,000 59,000 69,000 56,000 49,000 56,000 49,000 50,000 54,000 56,000 57,000 57,000 672,000 LGS-P 531,000 531,000 584,000 523,000 519,000 531,000 481,000 498,000 518,000 494,000 571,000 547,000 6,328,000 TOTAL COMM/IND RDM GROUP 6,136,000$ 6,013,000$ 5,888,000$ 5,227,000$ 5,179,000$ 5,349,000$ 5,240,000$ 5,289,000$ 5,330,000$ 5,165,000$ 5,349,000$ 5,563,000$ 65,728,000$ * For the purpose of constructing future targets, July and August revenues have been increased as if the rate increase had gone into effect on 7/1/14.

Residential Customer Growth Adj Jul2015 - Dec 2015 0.33%

Com / Ind Customer Growth Adj RY15 0.40%

Illustrative Targets July - Dec 2015 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15

RESIDENTIAL A/R 15,507,477$ 16,598,027$ 14,530,297$ 13,078,571$ 13,455,799$ 14,712,891$ A/R-TOU / A-TOU-OPTS 324,055 348,133 310,009 278,908 314,022 394,283 A-LM 2,007 2,007 2,007 3,010 3,010 3,010

TOTAL RESIDENTIAL RDM GROUP 15,833,539$ 16,948,167$ 14,842,312$ 13,360,489$ 13,772,831$ 15,110,184$

COMM/IND SGS / SGS-TOU 2,426,585$ 2,480,799$ 2,138,447$ 1,890,467$ 1,875,408$ 2,063,149$ MGS-S / MSG-S-TOU 2,501,882 2,377,390 2,509,914 2,224,788 2,226,795 2,196,677 MGS-P / MGS-P-TOU 83,329 76,301 94,373 94,373 80,317 82,325 IGS-S 410,622 381,507 354,400 311,229 303,198 299,182 IGS-P 144,571 128,508 158,627 145,575 143,567 139,551 LGS-S 60,238 59,234 69,274 56,222 49,194 56,222 LGS-P 533,106 533,106 586,316 525,074 521,058 533,106

TOTAL COMM/IND RDM GROUP 6,160,332$ 6,036,845$ 5,911,349$ 5,247,728$ 5,199,537$ 5,370,211$



Residential Customer Growth Adjustment CY16 0.21%

Com / Ind Customer Growth Adjustment CY16 0.07%

Illustrative Targets 2016 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Total



COMM/IND SGS / SGS-TOU 2,075,475$ 2,100,493$ 2,008,427$ 1,919,364$ 1,861,323$ 2,004,424$ 2,428,310$ 2,482,563$ 2,139,967$ 1,891,811$ 1,876,741$ 2,064,616$ 24,853,514$ MGS-S / MSG-S-TOU 2,124,510 2,123,509 2,200,564 2,156,532 2,280,621 2,364,680 2,503,661 2,379,081 2,511,698 2,226,370 2,228,379 2,198,239 27,297,843 MGS-P / MGS-P-TOU 75,053 78,055 79,056 75,053 82,058 87,062 83,388 76,356 94,440 94,440 80,374 82,384 987,720 IGS-S 303,215 307,218 331,235 328,233 357,254 362,257 410,914 381,778 354,652 311,451 303,413 299,394 4,051,016 IGS-P 135,096 135,096 142,101 139,099 143,102 144,102 144,674 128,599 158,739 145,679 143,669 139,650 1,699,606 LGS-S 49,035 50,036 54,038 56,040 57,041 57,041 60,281 59,276 69,323 56,262 49,229 56,262 673,863 LGS-P 481,342 498,354 518,368 494,351 571,406 547,389 533,485 533,485 586,733 525,447 521,429 533,485 6,345,274

TOTAL COMM/IND RDM GROUP 5,243,726$ 5,292,761$ 5,333,790$ 5,168,673$ 5,352,804$ 5,566,956$ 6,164,713$ 6,041,137$ 5,915,552$ 5,251,459$ 5,203,235$ 5,374,030$ 65,908,835$









Page 11 of 14

Target Revenues First Reconciliation Period Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Total Cap On

Reconciliation

RESIDENTIAL A/R 14,483,000$ 13,036,000$ 13,412,000$ 14,665,000$ 15,026,000$ 14,656,000$ 14,082,000$ 13,610,000$ 13,142,000$ 13,599,000$ 15,507,477$ 16,598,027$ 14,530,297$ 13,078,571$ 13,455,799$ 14,712,891$ 227,594,062$ A/R-TOU / A-TOU-OPTS 309,000 278,000 313,000 393,000 444,000 436,000 396,000 340,000 303,000 294,000 324,055 348,133 310,009 278,908 314,022 394,283 5,475,410 A-LM 2,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 3,000 2,007 2,007 2,007 3,010 3,010 3,010 44,049 TOTAL RESIDENTIAL RDM GROUP 14,794,000$ 13,317,000$ 13,728,000$ 15,061,000$ 15,473,000$ 15,095,000$ 14,481,000$ 13,953,000$ 13,448,000$ 13,896,000$ 15,833,539$ 16,948,167$ 14,842,312$ 13,360,489$ 13,772,831$ 15,110,184$ 233,113,521$ 4,662,270$

COMM/INDUSTRIAL SGS / SGS-TOU 2,130,000$ 1,883,000$ 1,868,000$ 2,055,000$ 2,074,000$ 2,099,000$ 2,007,000$ 1,918,000$ 1,860,000$ 2,003,000$ 2,426,585$ 2,480,799$ 2,138,447$ 1,890,467$ 1,875,408$ 2,063,149$ 32,771,854$ MGS-S / MSG-S-TOU 2,500,000 2,216,000 2,218,000 2,188,000 2,123,000 2,122,000 2,199,000 2,155,000 2,279,000 2,363,000 2,501,882 2,377,390 2,509,914 2,224,788 2,226,795 2,196,677 36,400,446 MGS-P / MGS-P-TOU 94,000 94,000 80,000 82,000 75,000 78,000 79,000 75,000 82,000 87,000 83,329 76,301 94,373 94,373 80,317 82,325 1,337,018 IGS-S 353,000 310,000 302,000 298,000 303,000 307,000 331,000 328,000 357,000 362,000 410,622 381,507 354,400 311,229 303,198 299,182 5,311,137 IGS-P 158,000 145,000 143,000 139,000 135,000 135,000 142,000 139,000 143,000 144,000 144,571 128,508 158,627 145,575 143,567 139,551 2,283,398 LGS-S 69,000 56,000 49,000 56,000 49,000 50,000 54,000 56,000 57,000 57,000 60,238 59,234 69,274 56,222 49,194 56,222 903,384 LGS-P 584,000 523,000 519,000 531,000 481,000 498,000 518,000 494,000 571,000 547,000 533,106 533,106 586,316 525,074 521,058 533,106 8,497,765 TOTAL COMM/INDUSTRIAL RDM GROUP 5,888,000$ 5,227,000$ 5,179,000$ 5,349,000$ 5,240,000$ 5,289,000$ 5,330,000$ 5,165,000$ 5,349,000$ 5,563,000$ 6,160,332$ 6,036,845$ 5,911,349$ 5,247,728$ 5,199,537$ 5,370,211$ 87,505,002$ 1,750,100$

* Includes adjustment for customer growth - July 15 to Dec 15.

Illustrative Actual Revenues First Reconciliation Period Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Total

RESIDENTIAL A/R 1.02 14,700,245$ 13,231,540$ 13,613,180$ 14,884,975$ 15,251,390$ 14,875,840$ 14,293,230$ 13,814,150$ 13,339,130$ 13,802,985$ 15,740,089$ 16,846,997$ 14,748,251$ 13,274,750$ 13,657,636$ 14,933,584$ 231,007,973$ A/R-TOU / A-TOU-OPTS 1.02 315,180 283,560 319,260 400,860 452,880 444,720 403,920 346,800 309,060 299,880 330,536 355,096 316,209 284,486 320,303 402,169 5,584,919 A-LM 1.03 2,050 3,075 3,075 3,075 3,075 3,075 3,075 3,075 3,075 3,075 2,057 2,057 2,057 3,085 3,085 3,085 45,150 TOTAL RESIDENTIAL RDM GROUP 15,017,475$ 13,518,175$ 13,935,515$ 15,288,910$ 15,707,345$ 15,323,635$ 14,700,225$ 14,164,025$ 13,651,265$ 14,105,940$ 16,072,682$ 17,204,150$ 15,066,517$ 13,562,321$ 13,981,024$ 15,338,838$ 236,638,042$

COMM/INDUSTRIAL SGS / SGS-TOU 0.99 2,108,700$ 1,864,170$ 1,849,320$ 2,034,450$ 2,053,260$ 2,078,010$ 1,986,930$ 1,898,820$ 1,841,400$ 1,982,970$ 2,402,319$ 2,455,991$ 2,117,062$ 1,871,562$ 1,856,653$ 2,042,518$ 32,444,135$ MGS-S / MSG-S-TOU 0.97 2,425,000 2,149,520 2,151,460 2,122,360 2,059,310 2,058,340 2,133,030 2,090,350 2,210,630 2,292,110 2,426,826 2,306,069 2,434,616 2,158,044 2,159,992 2,130,776 35,308,432 MGS-P / MGS-P-TOU 0.97 91,180 91,180 77,600 79,540 72,750 75,660 76,630 72,750 79,540 84,390 80,829 74,012 91,542 91,542 77,908 79,855 1,296,908 IGS-S 1.02 360,060 316,200 308,040 303,960 309,060 313,140 337,620 334,560 364,140 369,240 418,834 389,137 361,488 317,454 309,262 305,165 5,417,360 IGS-P 0.97 153,260 140,650 138,710 134,830 130,950 130,950 137,740 134,830 138,710 139,680 140,234 124,652 153,868 141,208 139,260 135,365 2,214,896 LGS-S 1.02 70,380 57,120 49,980 57,120 49,980 51,000 55,080 57,120 58,140 58,140 61,443 60,419 70,659 57,347 50,178 57,347 921,452 LGS-P 0.99 578,160 517,770 513,810 525,690 476,190 493,020 512,820 489,060 565,290 541,530 527,775 527,775 580,453 519,823 515,848 527,775 8,412,787 TOTAL COMM/INDUSTRIAL RDM GROUP 5,786,740$ 5,136,610$ 5,088,920$ 5,257,950$ 5,151,500$ 5,200,120$ 5,239,850$ 5,077,490$ 5,257,850$ 5,468,060$ 6,058,259$ 5,938,054$ 5,809,687$ 5,156,979$ 5,109,100$ 5,278,800$ 86,015,970$

Target - Actual Sep-14 Oct-14 Nov-14 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Total Cap On Reconciliation

Excess Above Cap

RESIDENTIAL A/R (217,245)$ (195,540)$ (201,180)$ (219,975)$ (225,390)$ (219,840)$ (211,230)$ (204,150)$ (197,130)$ (203,985)$ (232,612)$ (248,970)$ (217,954)$ (196,179)$ (201,837)$ (220,693)$ (3,413,911)$ A/R-TOU / A-TOU-OPTS (6,180) (5,560) (6,260) (7,860) (8,880) (8,720) (7,920) (6,800) (6,060) (5,880) (6,481) (6,963) (6,200) (5,578) (6,280) (7,886) (109,508) A-LM (50) (75) (75) (75) (75) (75) (75) (75) (75) (75) (50) (50) (50) (75) (75) (75) (1,101) TOTAL RESIDENTIAL RDM GROUP (223,475)$ (201,175)$ (207,515)$ (227,910)$ (234,345)$ (228,635)$ (219,225)$ (211,025)$ (203,265)$ (209,940)$ (239,143)$ (255,983)$ (224,205)$ (201,832)$ (208,193)$ (228,654)$ (3,524,520)$ 4,662,270$ -

COMM/INDUSTRIAL SGS / SGS-TOU 21,300$ 18,830$ 18,680$ 20,550$ 20,740$ 20,990$ 20,070$ 19,180$ 18,600$ 20,030$ 24,266$ 24,808$ 21,384$ 18,905$ 18,754$ 20,631$ 327,719$ MGS-S / MSG-S-TOU 75,000 66,480 66,540 65,640 63,690 63,660 65,970 64,650 68,370 70,890 75,056 71,322 75,297 66,744 66,804 65,900 1,092,013 MGS-P / MGS-P-TOU 2,820 2,820 2,400 2,460 2,250 2,340 2,370 2,250 2,460 2,610 2,500 2,289 2,831 2,831 2,410 2,470 40,111 IGS-S (7,060) (6,200) (6,040) (5,960) (6,060) (6,140) (6,620) (6,560) (7,140) (7,240) (8,212) (7,630) (7,088) (6,225) (6,064) (5,984) (106,223) IGS-P 4,740 4,350 4,290 4,170 4,050 4,050 4,260 4,170 4,290 4,320 4,337 3,855 4,759 4,367 4,307 4,187 68,502 LGS-S (1,380) (1,120) (980) (1,120) (980) (1,000) (1,080) (1,120) (1,140) (1,140) (1,205) (1,185) (1,385) (1,124) (984) (1,124) (18,068) LGS-P 5,840 5,230 5,190 5,310 4,810 4,980 5,180 4,940 5,710 5,470 5,331 5,331 5,863 5,251 5,211 5,331 84,978 TOTAL COMM/INDUSTRIAL RDM GROUP 101,260$ 90,390$ 90,080$ 91,050$ 88,500$ 88,880$ 90,150$ 87,510$ 91,150$ 94,940$ 102,073$ 98,790$ 101,662$ 90,748$ 90,437$ 91,411$ 1,489,032$ 1,750,100$ -


Residential Group Cap = 2% of Target Revenues or $4.66 MMC&I Group Cap = 2% of Target Revenues or $1.75 MM

Illustrative Results: Residential Group Excess Recovery = $3.52 MMC&I Group Shortfall = $1.49 MM

Calculation of illustrative RDM reconciliation for Jul 2014 - Dec 2015.

RDM Reconciliation For First Period September 2014 - December 2015


Page 12 of 14


Residential Group Cap = 2% of Target Revenues or $4.66 MMC&I Group Cap = 2% of Target Revenues or $1.75 MM

Illustrative Results: Residential Group Excess Recovery = $3.52 MMC&I Group Shortfall = $1.49 MM

Calculation of illustrative RDM reconciliation for Jul 2014 - Dec 2015.

RDM Reconciliation For First Period September 2014 - December 2015

Target Revenues RYJUL16* Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Total

RESIDENTIAL A/R 15,539,644$ 16,632,455$ 14,560,436$ 13,105,699$ 13,483,710$ 14,743,409$ 15,078,720$ 14,707,422$ 14,131,408$ 13,657,752$ 13,188,110$ 13,646,713$ 172,475,478$ A/R-TOU / A-TOU-OPTS 324,727 348,855 310,652 279,486 314,674 395,101 445,558 437,530 397,389 341,193 304,063 295,032 4,194,260 A-LM 2,011 2,011 2,011 3,016 3,016 3,016 3,011 3,011 3,011 3,011 3,011 3,011 33,143 TOTAL RESIDENTIAL RDM GROUP 15,866,381$ 16,983,321$ 14,873,099$ 13,388,202$ 13,801,399$ 15,141,526$ 15,527,289$ 15,147,962$ 14,531,808$ 14,001,955$ 13,495,184$ 13,944,755$ 176,702,882$

COMM/INDUSTRIAL SGS / SGS-TOU 2,428,310$ 2,482,563$ 2,139,967$ 1,891,811$ 1,876,741$ 2,064,616$ 2,090,022$ 2,115,215$ 2,022,504$ 1,932,817$ 1,874,368$ 2,018,473$ 24,937,407$ MGS-S / MSG-S-TOU 2,503,661 2,379,081 2,511,698 2,226,370 2,228,379 2,198,239 2,139,400 2,138,392 2,215,987 2,171,647 2,296,605 2,381,254 27,390,714 MGS-P / MGS-P-TOU 83,388 76,356 94,440 94,440 80,374 82,384 75,579 78,603 79,610 75,579 82,633 87,672 991,059 IGS-S 410,914 381,778 354,652 311,451 303,413 299,394 305,341 309,372 333,557 330,534 359,758 364,796 4,064,959 IGS-P 144,674 128,599 158,739 145,679 143,669 139,650 136,043 136,043 143,097 140,074 144,105 145,112 1,705,484 LGS-S 60,281 59,276 69,323 56,262 49,229 56,262 49,379 50,386 54,417 56,433 57,440 57,440 676,128 LGS-P 533,485 533,485 586,733 525,447 521,429 533,485 484,716 501,847 522,002 497,816 575,411 551,226 6,367,080

TOTAL COMM/INDUSTRIAL RDM GROUP 6,164,713$ 6,041,137$ 5,915,552$ 5,251,459$ 5,203,235$ 5,374,030$ 5,280,479$ 5,329,857$ 5,371,174$ 5,204,900$ 5,390,321$ 5,605,974$ 66,132,832$

* Includes adjustment for customer growth.

RDM Reconciliation % of Target Revenues

RDM Reconciliation

(Capped)

RDM Reconciliation

(Capped)RDM to Defer

Prior RDM Deferral to

Recover (net of accrual)

Deviation from Prior Period

RDM Reconciliation

Total RDM Reconciliation

(Capped)

Total Target Revenues Including

Reconciliation

TOTAL RESIDENTIAL RDM GROUP -1.51% -1.51% (3,524,520)$ -$ -$ -$ (3,524,520)$ 173,178,361$ TOTAL COMM/IND RDM GROUP 1.70% 1.70% 1,489,032$ -$ -$ -$ 1,489,032$ 67,621,863$

Target Revenues RYJUL16* + Total RDM Reconciliation** Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Total

RESIDENTIAL A/R 15,229,689$ 16,300,704$ 14,270,013$ 12,844,293$ 13,214,763$ 14,449,337$ 14,777,960$ 14,414,067$ 13,849,543$ 13,385,334$ 12,925,060$ 13,374,516$ 169,035,278$ A/R-TOU / A-TOU-OPTS 318,250 341,897 304,456 273,912 308,397 387,221 436,671 428,803 389,463 334,387 297,998 289,147 4,110,601 A-LM 1,971 1,971 1,971 2,956 2,956 2,956 2,950 2,950 2,950 2,950 2,950 2,950 32,482 TOTAL RESIDENTIAL RDM GROUP 15,549,910$ 16,644,572$ 14,576,440$ 13,121,160$ 13,526,116$ 14,839,513$ 15,217,581$ 14,845,821$ 14,241,956$ 13,722,672$ 13,226,008$ 13,666,613$ 173,178,361$

COMM/INDUSTRIAL SGS / SGS-TOU 2,482,985$ 2,538,460$ 2,188,150$ 1,934,407$ 1,918,997$ 2,111,103$ 2,137,080$ 2,162,840$ 2,068,042$ 1,976,335$ 1,916,571$ 2,063,921$ 25,498,892$ MGS-S / MSG-S-TOU 2,560,033 2,432,648 2,568,251 2,276,498 2,278,553 2,247,734 2,187,570 2,186,540 2,265,882 2,220,544 2,348,315 2,434,870 28,007,437 MGS-P / MGS-P-TOU 85,266 78,075 96,566 96,566 82,184 84,239 77,281 80,372 81,403 77,281 84,494 89,646 1,013,373 IGS-S 420,166 390,374 362,637 318,463 310,245 306,136 312,216 316,337 341,067 337,976 367,858 373,010 4,156,485 IGS-P 147,931 131,494 162,313 148,959 146,904 142,795 139,106 139,106 146,319 143,228 147,349 148,380 1,743,884 LGS-S 61,638 60,611 70,884 57,529 50,338 57,529 50,490 51,521 55,642 57,703 58,734 58,734 691,352 LGS-P 545,497 545,497 599,944 537,278 533,169 545,497 495,629 513,147 533,755 509,025 588,367 563,637 6,510,440

TOTAL COMM/INDUSTRIAL RDM GROUP 6,303,516$ 6,177,158$ 6,048,746$ 5,369,700$ 5,320,389$ 5,495,031$ 5,399,373$ 5,449,863$ 5,492,110$ 5,322,092$ 5,511,688$ 5,732,197$ 67,621,863$

* Includes adjustment for customer growth.** RDM Reconciliation allocated to classes in proportion to their share of target revenues. This illustration of RDM Reconciliation does not include any accrual of carrying costs. See Attachment 6 for illustration of carrying costs accrual.** This illustration of RDM Reconciliation does not include any Storm Costs mechanism rate adjustments. Actual RDM reconciliation will include such rate adjustments, if applicable.


Page 13 of 14

Target Revenues Second Reconciliation Period Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Total Cap On

Reconciliation


TOTAL RESIDENTIAL RDM GROUP 15,505,095$ 15,126,311$ 14,511,037$ 13,981,942$ 13,475,894$ 13,924,824$ 15,866,381$ 16,983,321$ 14,873,099$ 13,388,202$ 13,801,399$ 15,141,526$ 176,579,031$ 3,531,581$


TOTAL COMM/IND RDM GROUP 5,243,726$ 5,292,761$ 5,333,790$ 5,168,673$ 5,352,804$ 5,566,956$ 6,164,713$ 6,041,137$ 5,915,552$ 5,251,459$ 5,203,235$ 5,374,030$ 65,908,835$ 1,318,177$


Illustrative Actual Revenues Second Reconciliation Period Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Total

RESIDENTIAL A/R 0.98 14,680,738$ 14,319,240$ 13,758,429$ 13,297,275$ 12,840,028$ 13,286,527$ 15,151,152$ 16,216,644$ 14,196,425$ 12,778,057$ 13,146,617$ 14,374,824$ 168,045,957$ A/R-TOU / A-TOU-OPTS 1.02 453,819 445,642 404,758 347,519 309,701 300,502 331,222 355,832 316,865 285,076 320,967 403,003 4,274,908 A-LM 0.99 2,976 2,976 2,976 2,976 2,976 2,976 1,991 1,991 1,991 2,986 2,986 2,986 32,786


COMM/IND SGS / SGS-TOU 1.02 2,112,833$ 2,138,301$ 2,044,579$ 1,953,912$ 1,894,826$ 2,040,504$ 2,472,020$ 2,527,249$ 2,178,487$ 1,925,864$ 1,910,522$ 2,101,779$ 25,300,877$ MGS-S / MSG-S-TOU 1.02 2,162,751 2,161,732 2,240,174 2,195,350 2,321,672 2,407,245 2,548,727 2,421,904 2,556,909 2,266,444 2,268,490 2,237,807 27,789,204 MGS-P / MGS-P-TOU 1.03 77,305 80,397 81,428 77,305 84,520 89,674 85,890 78,646 97,273 97,273 82,786 84,855 1,017,352 IGS-S 1.02 309,280 313,363 337,860 334,798 364,399 369,503 419,132 389,414 361,745 317,680 309,481 305,382 4,132,036 IGS-P 0.97 131,043 131,043 137,838 134,926 138,809 139,779 140,334 124,741 153,977 141,308 139,359 135,461 1,648,618 LGS-S 1.02 50,016 51,036 55,119 57,161 58,181 58,181 61,486 60,462 70,709 57,387 50,214 57,387 687,340 LGS-P 0.99 476,529 493,371 513,185 489,408 565,692 541,915 528,150 528,150 580,865 520,193 516,214 528,150 6,281,821 TOTAL COMM/IND RDM GROUP 5,319,756$ 5,369,243$ 5,410,182$ 5,242,859$ 5,428,099$ 5,646,800$ 6,255,739$ 6,130,566$ 5,999,965$ 5,326,149$ 5,277,066$ 5,450,822$ 66,857,248$

Target - Actual Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 Total Cap On Reconciliation

Excess Above Cap

RESIDENTIAL A/R 376,429$ 367,160$ 352,780$ 340,956$ 329,231$ 340,680$ 388,491$ 415,811$ 364,011$ 327,642$ 337,093$ 368,585$ 4,308,871$ A/R-TOU / A-TOU-OPTS (8,898) (8,738) (7,936) (6,814) (6,073) (5,892) (6,495) (6,977) (6,213) (5,590) (6,293) (7,902) (83,822) A-LM 30 30 30 30 30 30 20 20 20 30 30 30 331

TOTAL RESIDENTIAL RDM GROUP 367,561$ 358,452$ 344,874$ 334,172$ 323,189$ 334,818$ 382,017$ 408,854$ 357,818$ 322,083$ 330,829$ 360,713$ 4,225,380$ 3,531,581$ 693,800$

COMM/IND SGS / SGS-TOU (37,359)$ (37,809)$ (36,152)$ (34,549)$ (33,504)$ (36,080)$ (43,710)$ (44,686)$ (38,519)$ (34,053)$ (33,781)$ (37,163)$ (447,363)$ MGS-S / MSG-S-TOU (38,241) (38,223) (39,610) (38,818) (41,051) (42,564) (45,066) (42,823) (45,211) (40,075) (40,111) (39,568) (491,361) MGS-P / MGS-P-TOU (2,252) (2,342) (2,372) (2,252) (2,462) (2,612) (2,502) (2,291) (2,833) (2,833) (2,411) (2,472) (29,632) IGS-S (6,064) (6,144) (6,625) (6,565) (7,145) (7,245) (8,218) (7,636) (7,093) (6,229) (6,068) (5,988) (81,020) IGS-P 4,053 4,053 4,263 4,173 4,293 4,323 4,340 3,858 4,762 4,370 4,310 4,190 50,988 LGS-S (981) (1,001) (1,081) (1,121) (1,141) (1,141) (1,206) (1,186) (1,386) (1,125) (985) (1,125) (13,477) LGS-P 4,813 4,984 5,184 4,944 5,714 5,474 5,335 5,335 5,867 5,254 5,214 5,335 63,453 TOTAL COMM/IND RDM GROUP (76,030)$ (76,482)$ (76,392)$ (74,187)$ (75,296)$ (79,845)$ (91,026)$ (89,429)$ (84,413)$ (74,690)$ (73,832)$ (76,792)$ (948,413)$ 1,318,177$ -$

Calculation of illustrative RDM reconciliation for Jan 2016 - Dec 2016.Central Maine Power Company

Illustration of RDM Reconciliation For Calendar Year 2016Residential Group Cap = 2% of Target Revenues or $3.53 MM

C&I Group Cap = 2% of Target Revenues or $1.32 MMIllustrative Results: Residential Group Shortfall = $4.22 MM Exceeds Cap by $0.69 MM

C&I Excess Recovery = $0.95 MM


Page 14 of 14

Calculation of illustrative RDM reconciliation for Jan 2016 - Dec 2016.Central Maine Power Company

Illustration of RDM Reconciliation For Calendar Year 2016Residential Group Cap = 2% of Target Revenues or $3.53 MM

C&I Group Cap = 2% of Target Revenues or $1.32 MMIllustrative Results: Residential Group Shortfall = $4.22 MM Exceeds Cap by $0.69 MM

C&I Excess Recovery = $0.95 MM

Target Revenues RYJUL17* Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Total






RDM Reconciliation % of Target Revenues

RDM Reconciliation

(Capped)

RDM Reconciliation

(Capped)RDM to Defer

Prior RDM Deferral to

Recover (net of accrual)

Deviation from Prior Period

RDM Reconciliation

Total RDM Reconciliation

(Capped)

Total Target Revenues Including

Reconciliation

TOTAL RESIDENTIAL RDM GROUP 2.39% 2.00% 3,531,581$ 693,800$ -$ 17,623$ 3,549,203$ 180,524,858$

TOTAL COMM/IND RDM GROUP -1.44% -1.44% (948,413)$ -$ -$ (7,445)$ (955,858)$ 65,509,336$

Target Revenues RYJUL17* + Total RDM Reconciliation** Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17 Jan-18 Feb-18 Mar-18 Apr-18 May-18 Jun-18 Total






** RDM Reconciliation allocated to classes in proportion to their share of target revenues. This illustration of RDM Reconciliation does not include any accrual of carrying costs. See Attachment 6 for illustration of carrying costs accrual.** This illustration of RDM Reconciliation does not include any Storm Costs mechanism rate adjustments. Actual RDM reconciliation will include such rate adjustments, if

Attachment 6Page 1 of 8Example 1

Central Maine Power CompanyRDM Carrying Cost Example

Example 1: Undercollected Deferral Balance Below Annual Cap -- C&I Group 9/14 to 12/15

Actual Projected Cumulative Average Short-TermDistribution Distribution Monthly Monthly Borrowing Number Carrying Cumulative CumulativeRevenues Revenues Difference Def Balance Def Balance Rate of Days Costs Carrying Costs Total

1 Sep-14 5,787,887$ 5,889,169$ (101,282)$ (101,282)$ (50,641)$ 0.35% 30 (15)$ (15)$ (101,297)$ 2 Oct-14 5,135,254 5,225,636 (90,382) (191,664) (146,473) 0.31% 31 (39) (54) (191,717) 3 Nov-14 5,089,599 5,179,679 (90,080) (281,743) (236,704) 0.18% 30 (35) (89) (281,832) 4 Dec-14 5,258,001 5,349,052 (91,050) (372,794) (327,269) 0.35% 31 (99) (188) (372,981) 5 Jan-15 5,152,640 5,241,141 (88,501) (461,295) (417,044) 0.35% 31 (126) (313) (461,608) 6 Feb-15 5,199,504 5,288,361 (88,857) (550,152) (505,723) 0.31% 29 (126) (439) (550,591) 7 Mar-15 5,239,281 5,329,434 (90,153) (640,305) (595,228) 0.18% 31 (92) (531) (640,836) 8 Apr-15 5,077,278 5,164,779 (87,501) (727,806) (684,056) 0.35% 30 (200) (730) (728,536) 9 May-15 5,259,284 5,350,468 (91,184) (818,990) (773,398) 0.28% 31 (186) (917) (819,907)

10 Jun-15 5,467,999 5,562,928 (94,929) (913,919) (866,455) 0.29% 30 (209) (1,126) (915,045) 11 Jul-15 6,058,448 6,160,539 (102,091) (1,016,010) (964,964) 0.26% 31 (216) (1,342) (1,017,352) 12 Aug-15 5,937,641 6,036,425 (98,784) (1,114,794) (1,065,402) 0.25% 31 (229) (1,571) (1,116,365) 13 Sep-15 5,810,774 5,912,456 (101,682) (1,216,476) (1,165,635) 0.29% 30 (282) (1,853) (1,218,329) 14 Oct-15 5,155,560 5,246,299 (90,739) (1,307,215) (1,261,846) 0.26% 31 (277) (2,130) (1,309,345) 15 Nov-15 5,109,725 5,200,161 (90,436) (1,397,651) (1,352,433) 0.23% 30 (259) (2,390) (1,400,041) 16 Dec-15 5,278,793 5,370,203 (91,410) (1,489,061) (1,443,356) 0.23% 31 (277) (2,666) (1,491,728) 17 Jan-16 (1,489,061) (1,489,061) 0.23% 31 (285) (2,952) (1,492,013) 18 Feb-16 (1,489,061) (1,489,061) 0.23% 28 (258) (3,209) (1,492,271) 19 Mar-16 (1,489,061) (1,489,061) 0.23% 31 (285) (3,495) (1,492,556) 20 Apr-16 (1,489,061) (1,489,061) 0.23% 30 (276) (3,771) (1,492,832) 21 May-16 (1,489,061) (1,489,061) 0.23% 31 (285) (4,056) (1,493,117) 22 Jun-16 (1,489,061) (1,489,061) 0.23% 30 (276) (4,332) (1,493,394) 23 86,017,668$ 87,506,729$ (1,489,061)$ (4,332)$

24 Proposed Annual Cap: 1,750,135$

25 Amount Above Annual Cap: -$

Note: Actual and projected distribution revenues exclude revenue from Lighting, LGS-ST and LGS-T rate classes


Month End Average Pre-TaxDeferral Monthly Amortization WACC @Balance Def Balance Expense 10.32% Balance ROI Total

1 Jun-16 (1,493,394)$ -$ -$ -$ 2 Jul-16 (1,368,944) (1,431,169) (124,449) (12,308) 3 Aug-16 (1,244,495) (1,306,719) (124,449) (11,238) 4 Sep-16 (1,120,045) (1,182,270) (124,449) (10,168) 5 Oct-16 (995,596) (1,057,820) (124,449) (9,097) 6 Nov-16 (871,146) (933,371) (124,449) (8,027) 7 Dec-16 (746,697) (808,921) (124,449) (6,957) 8 Jan-17 (622,247) (684,472) (124,449) (5,886) 9 Feb-17 (497,798) (560,023) (124,449) (4,816)

10 Mar-17 (373,348) (435,573) (124,449) (3,746) 11 Apr-17 (248,899) (311,124) (124,449) (2,676) 12 May-17 (124,449) (186,674) (124,449) (1,605) 13 Jun-17 - (62,225) (124,449) (535) (1,493,394) (77,059) (1,570,453)

Central Maine Power CompanyIllustrative Example of RDM Monthly Amortization and Return on Investment

Example 1: Undercollected Deferral Balance Below Annual Cap -- C&I Group 9/14 to 12/15

Annual Totals



Example 2: Undercollected Deferral Balance Above Annual Cap -- Residential Group 1/16 to 12/16Treatment of Amount Equal to Annual Cap


1 Jan-16 15,127,276$ 15,494,580$ (367,304)$ (367,304)$ (183,652)$ 0.35% 31 (55)$ (55)$ (367,360)$ 2 Feb-16 14,757,356 15,115,570 (358,214) (725,518) (546,411) 0.31% 29 (136) (191) (725,710) 3 Mar-16 14,156,908 14,501,552 (344,644) (1,070,163) (897,840) 0.18% 31 (138) (330) (1,070,492) 4 Apr-16 13,639,066 13,973,007 (333,941) (1,404,103) (1,237,133) 0.35% 30 (361) (691) (1,404,794) 5 May-16 13,143,442 13,466,408 (322,966) (1,727,069) (1,565,586) 0.35% 31 (472) (1,162) (1,728,231) 6 Jun-16 13,580,503 13,915,104 (334,602) (2,061,670) (1,894,370) 0.31% 30 (488) (1,651) (2,063,321) 7 Jul-16 15,474,714 15,856,484 (381,770) (2,443,440) (2,252,555) 0.18% 31 (347) (1,997) (2,445,438) 8 Aug-16 16,563,478 16,972,052 (408,574) (2,852,014) (2,647,727) 0.35% 31 (798) (2,795) (2,854,809) 9 Sep-16 14,506,179 14,863,748 (357,569) (3,209,584) (3,030,799) 0.29% 30 (732) (3,528) (3,213,111) 10 Oct-16 13,057,129 13,378,983 (321,854) (3,531,438) (3,370,511) 0.26% 31 (741) (4,268) (3,535,706) 11 Nov-16 13,462,121 13,792,725 (330,604) (3,862,041) (3,696,739) 0.23% 30 (709) (4,977) (3,867,018) 12 Dec-16 14,770,856 15,131,340 (360,484) (3,529,231) (3,695,636) 0.23% 31 (708) (5,685) (3,534,916) 13 Jan-17 (3,529,231) (3,529,231) 0.23% 31 (676) (6,361) (3,535,592) 14 Feb-17 (3,529,231) (3,529,231) 0.23% 28 (611) (6,972) (3,536,203) 15 Mar-17 (3,529,231) (3,529,231) 0.23% 31 (676) (7,648) (3,536,879) 16 Apr-17 (3,529,231) (3,529,231) 0.23% 30 (654) (8,303) (3,537,534) 17 May-17 (3,529,231) (3,529,231) 0.23% 31 (676) (8,979) (3,538,210) 18 Jun-17 (3,529,231) (3,529,231) 0.23% 30 (654) (9,633) (3,538,864) 19 172,239,027$ 176,461,552$ (4,222,525)$ (9,633)$


21 Amount Above Annual Cap: (693,294)$




1 Jun-17 (3,538,864)$ -$ -$ -$ 2 Jul-17 (3,243,959) (3,391,412) (294,905) (29,166) 3 Aug-17 (2,949,054) (3,096,506) (294,905) (26,630) 4 Sep-17 (2,654,148) (2,801,601) (294,905) (24,094) 5 Oct-17 (2,359,243) (2,506,696) (294,905) (21,558) 6 Nov-17 (2,064,338) (2,211,790) (294,905) (19,021) 7 Dec-17 (1,769,432) (1,916,885) (294,905) (16,485) 8 Jan-18 (1,474,527) (1,621,980) (294,905) (13,949) 9 Feb-18 (1,179,621) (1,327,074) (294,905) (11,413) 10 Mar-18 (884,716) (1,032,169) (294,905) (8,877) 11 Apr-18 (589,811) (737,263) (294,905) (6,340) 12 May-18 (294,905) (442,358) (294,905) (3,804) 13 Jun-18 - (147,453) (294,905) (1,268) (3,538,864) (182,605) (3,721,470)


Example 2: Undercollected Deferral Balance Above Annual Cap -- Residential Group 1/16 to 12/16Treatment of Amount Equal to Annual Cap

Annual Totals


RDM Carrying Cost ExampleExample 2: Undercollected Deferral Balance Above Annual Cap -- Residential Group 1/16 to 12/16

Treatment of Amount Exceeding Annual Cap

MonthlyDeferred Cumulative Net Average Net Pre-Tax Cumulative Cumulative

Monthly Cumulative Income Taxes Deferred Cumulative Cumulative WACC @ Carrying Balance plusMonth Activity Balance @ 40.8045% Income Taxes Balance Balance 10.32% Costs Carrying Costs

1 Dec-16 (693,294) (693,294) 282,895 282,895 (410,399) (205,200) (1,765) (1,765) (695,059) 2 Jan-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (5,294) (698,588) 3 Feb-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (8,823) (702,117) 4 Mar-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (12,352) (705,646) 5 Apr-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (15,881) (709,175) 6 May-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (19,410) (712,704) 7 Jun-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (22,939) (716,233) 8 Jul-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (26,468) (719,762) 9 Aug-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (29,997) (723,291) 10 Sep-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (33,526) (726,820) 11 Oct-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (37,055) (730,349) 12 Nov-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (40,584) (733,878) 13 Dec-17 - (693,294) - 282,895 (410,399) (410,399) (3,529) (44,113) (737,407) 14 Jan-18 - (693,294) - 282,895 (410,399) (410,399) (3,529) (47,642) (740,936) 15 Feb-18 - (693,294) - 282,895 (410,399) (410,399) (3,529) (51,171) (744,465) 16 Mar-18 - (693,294) - 282,895 (410,399) (410,399) (3,529) (54,700) (747,994) 17 Apr-18 - (693,294) - 282,895 (410,399) (410,399) (3,529) (58,229) (751,523) 18 May-18 - (693,294) - 282,895 (410,399) (410,399) (3,529) (61,758) (755,052) 19 Jun-18 - (693,294) - 282,895 (410,399) (410,399) (3,529) (65,287) (758,581) 20 Jul-18 - (693,294) - 282,895 (410,399) (410,399) (3,529) (68,816) (762,110)

Central Maine Power Co.


Beginning Amortization Pre-Tax After-Tax AverageBalance Expense Balance Balance Balance Current Cumulative

1 Jul-18 (762,110)$ (63,509)$ (698,601)$ (413,540)$ (206,770)$ (1,778)$ (1,778)$ 2 Aug-18 (698,601) (63,509) (635,092) (375,946) (394,743) (3,395) (5,173) 3 Sep-18 (635,092) (63,509) (571,583) (338,351) (357,148) (3,071) (8,244) 4 Oct-18 (571,583) (63,509) (508,073) (300,757) (319,554) (2,748) (10,993) 5 Nov-18 (508,073) (63,509) (444,564) (263,162) (281,959) (2,425) (13,418) 6 Dec-18 (444,564) (63,509) (381,055) (225,567) (244,365) (2,102) (15,519) 7 Jan-19 (381,055) (63,509) (317,546) (187,973) (206,770) (1,778) (17,297) 8 Feb-19 (317,546) (63,509) (254,037) (150,378) (169,176) (1,455) (18,752) 9 Mar-19 (254,037) (63,509) (190,528) (112,784) (131,581) (1,132) (19,884) 10 Apr-19 (190,528) (63,509) (127,018) (75,189) (93,986) (808) (20,692) 11 May-19 (127,018) (63,509) (63,509) (37,595) (56,392) (485) (21,177) 12 Jun-19 (63,509) (63,509) (0) (0) (18,797) (162) (21,339)

In Rates:13 July 2018-June 2019 (762,110) (21,339)

14 Return on Investment 10.32%15 Monthly Compound Rate 0.8600%16 Statutory Tax Rate 40.8045%

Central Maine Power CompanyMonthly Amortization and Return on Investment

Carrying Costs

Example 2: Undercollected Deferral Balance Above Annual Cap -- Residential Group 1/16 to 12/16Treatment of Amount Exceeding Annual Cap



Example 3: Overcollected Deferral Balance -- C&I Group 1/16 to 12/16


1 Jan-16 5,324,575$ 5,248,484$ 76,090$ 76,090$ 38,045$ 0.35% 31 11$ 11$ 76,102$ 2 Feb-16 5,372,327 5,295,770 76,557 152,647 114,369 0.31% 28 28 39 152,686 3 Mar-16 5,413,350 5,336,901 76,449 229,096 190,872 0.18% 31 29 68 229,164 4 Apr-16 5,246,249 5,172,015 74,234 303,330 266,213 0.35% 30 78 146 303,476 5 May-16 5,433,331 5,357,965 75,366 378,696 341,013 0.28% 31 82 228 378,924 6 Jun-16 5,650,638 5,570,722 79,915 458,612 418,654 0.29% 30 101 329 458,941 7 Jul-16 6,260,264 6,169,170 91,094 549,706 504,159 0.26% 31 113 442 550,148 8 Aug-16 6,134,402 6,044,882 89,520 639,226 594,466 0.25% 31 128 570 639,796 9 Sep-16 6,005,224 5,920,740 84,485 723,711 681,469 0.29% 30 165 735 724,446 10 Oct-16 5,328,370 5,253,650 74,720 798,431 761,071 0.26% 31 167 902 799,333 11 Nov-16 5,281,317 5,207,447 73,870 872,301 835,366 0.23% 30 160 1,062 873,363 12 Dec-16 5,454,571 5,377,727 76,844 949,146 910,723 0.23% 31 175 1,237 950,382 13 Jan-17 949,146 949,146 0.23% 31 182 1,419 950,564 14 Feb-17 949,146 949,146 0.23% 29 170 1,589 950,734 15 Mar-17 949,146 949,146 0.23% 31 182 1,771 950,916 16 Apr-17 949,146 949,146 0.23% 30 176 1,947 951,092 17 May-17 949,146 949,146 0.23% 31 182 2,128 951,274 18 Jun-17 949,146 949,146 0.23% 30 176 2,304 951,450 19 66,904,617$ 65,955,472$ 949,146$ 2,304$


21 Amount Above Annual Cap: -$ Cap does not apply for overcollected balances




1 Jun-17 951,450$ -$ -$ -$ 2 Jul-17 872,163 911,806 79,288 7,842 3 Aug-17 792,875 832,519 79,288 7,160 4 Sep-17 713,588 753,231 79,288 6,478 5 Oct-17 634,300 673,944 79,288 5,796 6 Nov-17 555,013 594,656 79,288 5,114 7 Dec-17 475,725 515,369 79,288 4,432 8 Jan-18 396,438 436,081 79,288 3,750 9 Feb-18 317,150 356,794 79,288 3,068 10 Mar-18 237,863 277,506 79,288 2,387 11 Apr-18 158,575 198,219 79,288 1,705 12 May-18 79,288 118,931 79,288 1,023 13 Jun-18 (0) 39,644 79,288 341 951,450 49,095 1,000,545


Example 3: Overcollected Deferral Balance

Annual Totals

{W4364231.3}

Central Maine Power Company Settlement Attachment 7Distribution Rate Case Docket No. 2013-168Storm Reserve Provision Page 1 of 4in thousands of dollars Example Definitions

Example 1: The reserve balance at the end of the year absent storms is negative $4.0 million. During that year the Company experiences two Tier 2 storms at a total of $9.0 million. In addition, the Company experienced a Tier 3 storm of $30.0 million. Sharing would be invoked and there would be $2.0 million sharing from the Tier 3 storm. In addition, since the reserve is still above the $10.0 million threshold after the Tier 3 storm is accounted for, there would be additional Tier 2 sharing. This would be based on 50% of the post-Tier 3 accounts differential, or $3.0 million which produces a pre-cap sharing amount of $1.5 million, but which would be reduced to $1.0 million as a result of the overall cap.

Example 2: Same storm activity as Example 1. In this instance, however, the end of year reserve balance, without storms, is negative $2.0 million. Tier 3 is accounted for the same way so there is a $2.0 million share as a result of Tier 3. In addition, since the reserve balance is in excess of $10 million after the Tier 3 accounting, there would be additional sharing. In this case the excess is $1.0 million resulting in $500,000 additional sharing. The $3.0 million cap in this case would not be reached.

Example 3: Same storm activity as Example 1. In this case, the end of year storm balance before consideration of storms is 0. There would be a $2.0 million sharing as a result of the Tier 3 storm. No additional sharing would occur since the reserve balance excluding the Tier 3 event would be below $10 million.

{W4364231.3}

Central Maine Power Company Settlement Attachment 7Distribution Rate Case Docket No. 2013-168Storm Reserve Provision Page 2 of 4in thousands of dollars( ) = Negative / Debit Row

Reference Example 1 Example 2 Example 3

1 Reserve Balance at the End of the Year Before Tier 2 and 3 Storms (4,000)$ (2,000)$ -$

Tier 2 and Tier 3 Storm ActivityTier 3 Storm Activity

2 + Tier 3 Storm (30,000)$ (30,000)$ (30,000)$ 3 - Tier 3 Storm Activity in Excess of ($15M) Recovered in Distribution Rates / Accounting Order 15,000 15,000 15,000 4 - Company Sharing capped at $2M 17 2,000 2,000 2,000 5 Subtotal: Tier 3 Storm Activity (13,000)$ (13,000)$ (13,000)$

Tier2 Storm Activity6 + Tier 2 Storms (9,000) (9,000) (9,000) 7 - Company Sharing capped at overall sharing level of $3M 25 1,000 500 - 8 Subtotal: Tier 2 Storm Activity (8,000)$ (8,500)$ (9,000)$

9 Reserve Balance at End of Year After Tier 2 and 3 Storms - Before Distribution Rate Adjustment (25,000)$ (23,500)$ (22,000)$

10 Customer Sharing - Distribution Rate Adjustment (amount over $10M) 18+26 15,000 13,500 12,000

11 Reserve Balance at End of Year After Tier 2 and 3 Storms - After Distribution Rate Adjustment (10,000)$ (10,000)$ (10,000)$

Calculation of Company and Customer Sharing of Reserve Balances Above the ThresholdTier 3 Sharing

12 Calculated Reserve Balance After Tier 2 and 3 Storms 1+2+3+6 (28,000)$ (26,000)$ (24,000)$ 13 less: $10M Reserve Threshold 10,000 10,000 10,000 14 Subtotal: Portion of Reserve Balance Above the Threshold (18,000)$ (16,000)$ (14,000)$ 15 less: Portion not Attributed to Tier 3 Storms1 3,000 1,000 - 16 Portion of Reserve Balance Above the Threshold Attribted to Tier 3 Storms (15,000)$ (15,000)$ (14,000)$

17 Company Sharing of Tier 3 Reserve Adjustment - 50% up to $2M per Event 2,000$ 2,000$ 2,000$ 18 Customer Sharing of Tier 3 Reserve Adjustment - Distribution Rate Adjustment 13,000 13,000 12,000 19 Total Tier 3 Sharing 15,000$ 15,000$ 14,000$

Tier 2 Sharing20 Calculated Reserve Balance After Tier 2 and 3 Storms 1+2+3+6 (28,000)$ (26,000)$ (24,000)$ 21 less: $10M Reserve Threshold 10,000 10,000 10,000 22 Subtotal: Portion of Reserve Balance Above the Threshold (18,000)$ (16,000)$ (14,000)$ 23 less: Portion Attributed to Tier 3 Storms 16 15,000 15,000 14,000 24 Portion of Reserve Balance Above the Threshold Attributed to Tier 2 Storms (3,000)$ (1,000)$ -$

25 Company Sharing of Tier 2 Reserve Adjustment - 50% up to $3M Annual Tier 2 and 3 Cap 1,000$ 500$ -$ 26 Customer Sharing of Tier 3 Reserve Adjustment - Distribution Rate Adjustment 2,000 500 - 27 Total Tier 2 Sharing 3,000$ 1,000$ -$

Company and Customer Sharing of Reserve Balance in Excess of the ThresholdCompany Sharing

28 Sharing Attributed to Tier 3 Storms 17 2,000$ 2,000$ 2,000$ 29 Sharing Attributed to Tier 2 Storms 25 1,000 500 - 30 Total Company Sharing 3,000$ 2,500$ 2,000$

Customer Sharing - Distribution Rate Adjustment31 Sharing Attributed to Tier 3 Storms 28 13,000$ 13,000$ 12,000$ 32 Sharing Attributed to Tier 2 Storms 26 2,000 500 - 33 Total Customer Sharing 15,000$ 13,500$ 12,000$

Notes:1) The calculation of the portion of the reserve adjustment not attributed to Tier 3 Storms on numbered row 15 is performed by taking the total reserve adjustment (numbered row 14 above) and first allocating it to Tier 3 Storm related debits (net of numbered rows 2 and 3 above), with the remaining balance being the reserve adjustment not attributed to Tier 3 Storms.In the first example, the total reserve adjustment of ($18M) is first attributed to the ($15M) of Tier 3 debits, which leaves ($3M) as being attributed to Tier 2 Storms (and not attributed to Tier 3 Storms). The calculation is similar in the second example, with the only difference being that the total reserve adjustment is ($16M), which leaves ($1M) as being attributed toTier 2 Storms. The third example shows a total reserve adjsutment of ($14M) being entirely attributed to the ($15M) of Tier 3 debits, with ($1M) impacting the reserve prior to itreaching the ($10M) reserve threshold.

{W4364231.3}

Central Maine Power Company Settlement Attachment 7Distribution Rate Case Docket No. 2013-168Carrying Costs Illustration - True Up and Tier 3 Deferral Page 3 of 4in thousands of dollars( ) = Negative / Debit

Schedule A: Accrual of Carrying Costs on the Reserve Balance Prior to True Up for Company SharingBased on Values From Example 1 as Shown on Pages 1 and 2

Assumptions1) Tier 2 Storms (Page 2, Line 6) assumed to occur in February and July, Tier 3 Storm (Page 2, Line 2) assumed to occur in November

Ending Reserve Cumulative Starting Reserve Ending Reserve Average ReserveStarting Credits Balance Before Storm Cost Storm Cost Balance After Balance After Balance After After Tax CumulativeReserve to the Tier 2 and 3 Debits to Debits to Tier 2 and 3 Tier 2 and 3 Tier 2 and 3 Average Number Carrying CarryingBalance Reserve Storms the Reserve the Reserve Storms Storms Storms Balance WACC of Days Costs Costs

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M)1 Jan-15 (10,000)$ 500$ (9,500)$ -$ -$ (10,000)$ (9,500)$ (9,750)$ (5,772)$ 10.32% 31 (51)$ (51)$ 2 Feb-15 (9,500) 500 (9,000) (4,500) (4,500) (9,500) (13,500) (11,500) (6,807) 10.32% 28 (54) (104) 3 Mar-15 (9,000) 500 (8,500) - (4,500) (13,500) (13,000) (13,250) (7,843) 10.32% 31 (69) (173) 4 Apr-15 (8,500) 500 (8,000) - (4,500) (13,000) (12,500) (12,750) (7,547) 10.32% 30 (64) (237) 5 May-15 (8,000) 500 (7,500) - (4,500) (12,500) (12,000) (12,250) (7,251) 10.32% 31 (64) (301) 6 Jun-15 (7,500) 500 (7,000) - (4,500) (12,000) (11,500) (11,750) (6,955) 10.32% 30 (59) (360) 7 Jul-15 (7,000) 500 (6,500) (4,500) (9,000) (11,500) (15,500) (13,500) (7,991) 10.32% 31 (70) (430) 8 Aug-15 (6,500) 500 (6,000) - (9,000) (15,500) (15,000) (15,250) (9,027) 10.32% 31 (79) (509) 9 Sep-15 (6,000) 500 (5,500) - (9,000) (15,000) (14,500) (14,750) (8,731) 10.32% 30 (74) (583)

10 Oct-15 (5,500) 500 (5,000) - (9,000) (14,500) (14,000) (14,250) (8,435) 10.32% 31 (74) (657) 11 Nov-15 (5,000) 500 (4,500) (15,000) (24,000) (14,000) (28,500) (21,250) (12,579) 10.32% 30 (107) (764) 12 Dec-15 (4,500) 500 (4,000) - (24,000) (28,500) (28,000) (28,250) (16,723) 10.32% 31 (147) (910) 13 Total 6,000$ (24,000)$ (910)$

Schedule B: End of Year Carrying Cost True Up for Company SharingBased on Values From Example 1 as Shown on Pages 1 and 2

Assumptions1) Tier 2 Storms (Page 2, Line 6) assumed to occur in February and July, Tier 3 Storm (Page 2, Line 2) assumed to occur in November2) Company Sharing of Tier 3 Storm Expense in column A, numbered row 24 per end of year criteria shown on page 2, numbered row 17.3) Company Sharing of Tier 2 Storm Expense in column A, numbered row 15 per end of year criteria shown on page 2, numbered row 25, applied Carring Costschronologically to the first Tier 2 storm that pushes the reserve balance over $10M. Based on the assumptions used to develop this example, the True Upfirst Tier 2 storm that pushes the reserve balance over $10M occurs in February. Reconciliation

Average Pre- True Up Storm Reserve CC (910)$ Cumulative Cumulative After Tax CC True Up - Company Sharing 69

Company Company Company Average Number Carrying Total Storm Reserve CC (841)$ Sharing Sharing Sharing Balance WACC of Days Costs

(A) (B) (C) (D) (E) (F) (G) Tier 3 Excess CC (115) 14 Jan-15 -$ -$ -$ -$ 10.32% 31 -$ 15 Feb-15 1,000 1,000 500 296 10.32% 28 2 Grand Total (957)$ 16 Mar-15 - 1,000 1,000 592 10.32% 31 5 17 Apr-15 - 1,000 1,000 592 10.32% 30 5 18 May-15 - 1,000 1,000 592 10.32% 31 5 19 Jun-15 - 1,000 1,000 592 10.32% 30 5 20 Jul-15 - 1,000 1,000 592 10.32% 31 5 21 Aug-15 - 1,000 1,000 592 10.32% 31 5 22 Sep-15 - 1,000 1,000 592 10.32% 30 5 23 Oct-15 - 1,000 1,000 592 10.32% 31 5 24 Nov-15 2,000 3,000 2,000 1,184 10.32% 30 10 25 Dec-15 - 3,000 3,000 1,776 10.32% 31 16 26 Total 3,000$ 69$ Total True Up

Schedule C: Accrual of Carrying Costs on Deferred Tier 3 Storm Costs in Excess of $15M - Recorded in a Separate AccountBased on Values From Example 1 as Shown on Pages 1 and 2

Assumptions1) Tier 3 Storm (Page 2, Line 2) assumed to occur in November

DeferredStarting Tier 3 Storm Ending Average After Tax CumulativeDeferral Costs in Excess Deferral Deferral Average Number Carrying CarryingBalance of $15M Balance Balance Balance WACC of Days Costs Costs

(A) (B) (C) (D) (E) (F) (G) (H) (I)27 Jan-15 -$ -$ -$ -$ -$ 10.32% 31 -$ -$ 28 Feb-15 - - - - - 10.32% 28 - - 29 Mar-15 - - - - - 10.32% 31 - - 30 Apr-15 - - - - - 10.32% 30 - - 31 May-15 - - - - - 10.32% 31 - - 32 Jun-15 - - - - - 10.32% 30 - - 33 Jul-15 - - - - - 10.32% 31 - - 34 Aug-15 - - - - - 10.32% 31 - - 35 Sep-15 - - - - - 10.32% 30 - - 36 Oct-15 - - - - - 10.32% 31 - - 37 Nov-15 - (15,000) (15,000) (7,500) (4,440) 10.32% 30 (38) (38) 38 Dec-15 (15,000) - (15,000) (15,000) (8,879) 10.32% 31 (78) (115) 39 Total (15,000)$ (115)$

{W4364231.3}

Central Maine Power Company Settlement Attachment 7Distribution Rate Case Docket No. 2013-168Carrying Cost Illustration - Post End of Year Page 4 of 4in thousands of dollars( ) = Negative / Debit

Schedule D: Accrual of Carrying Costs Prior to the Commencement of RecoveryBased on Values From Example 1 as Shown on Pages 1 and 2

Assumptions1) Customer Portion of the Reserve Adjustment in column A per end of year criteria shown on page 2, numbered row 33.2) Deferred Tier 3 Storms in Excess of $15M in column B recovered through an Accounting Order as shown on page 2, numbered row 3.

DeferredCustomer Tier 3 Storm Total Costs CumulativePortion of Costs in Excess to be After Tax Number Carrying Carrying

Reserve Adj of $15M Recovered Balance WACC of Days Costs Costs(A) (B) (C) (D) (E) (F) (G) (H)

1 Jan-16 (15,000)$ (15,000)$ (30,000)$ (17,759)$ 10.32% 31 (156)$ (156)$ 2 Feb-16 (15,000) (15,000) (30,000) (17,759) 10.32% 28 (141) (296) 3 Mar-16 (15,000) (15,000) (30,000) (17,759) 10.32% 31 (156) (452) 4 Apr-16 (15,000) (15,000) (30,000) (17,759) 10.32% 30 (151) (603) 5 May-16 (15,000) (15,000) (30,000) (17,759) 10.32% 31 (156) (758) 6 Jun-16 (15,000) (15,000) (30,000) (17,759) 10.32% 30 (151) (909) 7 (909)$

Schedule E: Recovery of Customer Portion of Reserve Adjustment and Deferred Tier 3 Storm Cost in Excess of $15M - Including Carrying CostsBased on Values From Example 1 as Shown on Pages 1 and 2

Assumptions1) Balance to be Recovered in column A, line 8 equals the Total Costs to be Recovered (Page 4, Schedule D, column C) plus Accrued Carrying Costs on the ReserveBalance (Page 3, Schedule A) less the End of Year True Up for Company Sharing (Page 3, Schedule B) plus Accrued Carrying Costs on Deferred Tier 3 Storms in Exessof $15M Recovered Through an Accounting Order (Page 3, Schedule C) plus Accrued Carrying Costs Prior to the Commencement of Recovery (Page 4, Schedule D, (column G).

Month End After Tax CumulativeBalance to be Monthly Average Average Number Carrying Carrying

Recovered Recovery Balance Balance WACC of Days Costs Costs(A) (B) (C) (D) (E) (F) (G) (H)

8 Jun-16 (31,866)$ 9 Jul-16 (29,210) (2,655) (30,538) (18,077) 10.32% 31 (158) (158) 10 Aug-16 (26,555) (2,655) (27,882) (16,505) 10.32% 31 (145) (303) 11 Sep-16 (23,899) (2,655) (25,227) (14,933) 10.32% 30 (127) (430) 12 Oct-16 (21,244) (2,655) (22,571) (13,361) 10.32% 31 (117) (547) 13 Nov-16 (18,588) (2,655) (19,916) (11,789) 10.32% 30 (100) (647) 14 Dec-16 (15,933) (2,655) (17,261) (10,217) 10.32% 31 (90) (736) 15 Jan-17 (13,277) (2,655) (14,605) (8,646) 10.32% 31 (76) (812) 16 Feb-17 (10,622) (2,655) (11,950) (7,074) 10.32% 28 (56) (868) 17 Mar-17 (7,966) (2,655) (9,294) (5,502) 10.32% 31 (48) (916) 18 Apr-17 (5,311) (2,655) (6,639) (3,930) 10.32% 30 (33) (950) 19 May-17 (2,655) (2,655) (3,983) (2,358) 10.32% 31 (21) (970) 20 Jun-17 0 (2,655) (1,328) (786) 10.32% 30 (7) (977) 21 Total (31,866)$ (977)$

Note: The illustration in Schedule E shows that the recovery of the balances and carrying costs on the "Customer Portion of the Reserve" and the "Tier 3 Storm Costs in Excess of $15M" are combined. For purposes of recovery the "Customer Portion of the Reserve" and the "Tier 3 Storm Costs in Excess of $15M" and the respective carrying costs thereon will be recovered through separate rate adjustment mechanisms and may be recovered over different periods of time.

Stipulation Attachment 8 Page 1 of 5

Docket No. 2013-00168

Central Maine Power Company Pricing Flexibility Criteria Beginning September 1, 2014

I. Introduction

This document establishes the pricing flexibility criteria to be used for service beginning September 1, 2014 for the following service categories: 1) changes to existing optional targeted service rate schedules; 2) establishing optional targeted service rate schedules; and 3) targeted rate contracts. Pricing changes that satisfy specific criteria and requirements, as provided below and by Commission decisions on related matters, will be effective 30 days from the fling date. The Commission may suspend a rate schedule or the effective date of a contract if it does not comply with the applicable specified criteria and requirements. In the event the Commission does suspend a rate schedule or contract, it will make a final determination within four months of the initial filing. This document does not preclude pricing changes that do not satisfy the criteria, but such changes generally require Commission review and approval.

II. Optional Targeted Service Rate Schedules

A. General

The Company may change existing targeted service rate schedules and/or establish new optional targeted service rate schedules with customer qualification criteria based on marketing characteristics identified by the Company.

1. The price cap for the targeted service will be the price that the customer in the targeted service class would face (or the most reasonable reflection of the price) if the customer’s service were taken under the applicable existing core delivery rate class.

2. Rate schedules will be designed so that on an annual basis, the

revenue collected will be equal to or greater than the combined revenue from (a) 100% of the transmission, conservation/solar assessment, and electricity lifeline components of the Company’s applicable core delivery rate schedule(s) in effect at the time the targeted rate schedules were designed; and (b) the distribution marginal costs for the applicable rate classes1. The applicable

1 The Company will be able to reduce to zero the revenue from the stranded cost component fo the Company’s applicable core delvery rate schedules in effect at the time the targeted contract or rate schedules were designed. The stranded cost component includes costs associated with long-term contracts entered into pursuant to 35-A M.R.S.A. § 3210-C and §§ 3601-3609. As noted in the Commission’s Order dated October 26, 2011 in Docket No. 2011-222, it is clear that costs under these contracts are not


Docket No. 2013-00168

transmission rates for customers taking service at the transmission and sub-transmission voltage levels are not included in the Company’s applicable core delivery rate and will be determined as set forth in the ISO-New England Inc. Transmission, Markets and Services Tariff (formerly known as FERC Electric Tariff No. 3), or any successor tariff applicable to transmission and associated ancillary services, as revised or amended from time to time. The minimum revenue calculation shall be adjusted to account for either the imposition or adjustment of any fee, levy, tax, premium, license, surcharge or other charge imposed by or pursuant to the act of any arm, agency or institution of government, whether directly or indirectly, that the Company is required to collect from the Customer, including, but not limited to any energy conservation or solar fund assessment under 35-A M.R.S.A. § 3211-A or any successor provision.

3. Unless specified in the targeted service rate schedule or a

contract pursuant to the rate schedule, rates will not change more than two times per year.

4. The Company will specify a sunset date for each optional

targeted service rate schedule. The sunset date will be no later than December 31, 2019. The rate schedule will automatically terminate on the sunset date unless CMP proposes renewal pursuant to then-current criteria, requirements, and processes.

B. Filing and Notice Requirements; Review Process

1. The Company will file proposed changes to an existing, optional,

targeted service rate schedule or a proposed rate schedule for new or redefined optional targeted service with an effective date 30 days from filing. The proposed rate schedule, along with pre-determined filing requirements, will be served on a pre-determined service list. Parties will have 14 days to file written comments or objections. The Commission may suspend the effective date of a proposed rate schedule only if it does not conform to the applicable specified criteria and requirements. In the event the Commission does suspend the effective date of a rate schedule, it will make a final determination within four

“stranded costs” as defined by statute. In that Order, the Commission determined that for cost recovery purposes, there is no reason to treat such costs differently than stranded costs associated with existing purchased power contracts and accordingly ordered that utility costs associated with long-term contracts shall be treated the same as other purchased power contract-related stranded costs and addressed in utility stranded costs proceedings.


Docket No. 2013-00168

months of the initial filing. Should no decision be issued after four months, the optional targeted rate schedule will become effective.

2. The Company must include the following material with its filing:

a. A demonstration that the proposed rate schedule complies

with the applicable floor criteria set forth in A.2 above and all other applicable requirements and criteria;

b. Expected revenue from the program, the incremental

revenue from this program compared to what would have happened without this program and the difference between revenue under the program and revenue at core rates in effect at the time the program becomes effective, assuming the same level of delivery services. CMP will also provide the cumulative totals for all programs and contracts, given the addition of the program for which the Company is filing for permission to implement.

III. Targeted Rate Contracts with Individual Customers

A. General The Company may enter into new or may renew existing targeted rate contracts with individual customers that govern the provision of service to that customer. 1. A targeted rate contract is defined as a contract in which a targeted rate

is provided to a customer for a period ending prior to December 31, 2019.

2. Rates charged pursuant to the contract will be designed so that over the

term of the contract, the revenue collected will be equal to or greater than (a) 100% of the transmission, conservation/solar assessment, and electricity lifeline components of the Company’s applicable core delivery rate schedule(s) in effect at the time the targeted rate schedules were designed; and (b) the distribution marginal costs for the Customer’s applicable rate class(es)2. The applicable transmission rates for customers taking service at the transmission and sub-transmission voltage levels are not included in the Company’s applicable core delivery rate and will be determined as set forth in the ISO-New England Inc. Transmission, Markets and Services Tariff (formerly known as FERC Electric Tariff No. 3), or any successor tariff applicable to transmission and associated ancillary services, as

2 See Footnote 1.


Docket No. 2013-00168

revised or amended from time to time. The minimum revenue calculation shall be adjusted to account for either the imposition or adjustment of any fee, levy, tax, premium, license, surcharge or other charge imposed by or pursuant to the act of any arm, agency or institution of government, whether directly or indirectly, that the Company is required to collect from the Customer, including, but not limited to any energy conservation or solar fund assessment under 35-A M.R.S.A § 3211-A or any successor provision.

3. The Company will file targeted rate contracts to be effective 30 days

from filing. Written comments or objections to the proposed targeted contract must be submitted with 14 days of filing. The contract will take effect unless the Commission finds, within 30 days of the filing date, that it does not conform to the applicable specified criteria and requirements, or is anti-competitive or unduly discriminatory.

4. Targeted rate contracts that do not conform to the applicable specified

criteria and requirements generally require Commission review and approval. The Commission’s hearing examiner will establish the procedure, including hearing dates, for review and decision of such contracts. The final decision will be issued no later than four months after the time of the contract’s filing. Should no decision be issued after four months, the contract will become effective.

5. No party is precluded from arguing for the applicability of any criteria

for approval in the four month proceeding.

B. Filing Requirements; Review Process

1. he Company must include the following material with its filing:

a. A demonstration that the proposed contract complies with the applicable floor criteria and all other applicable requirements and criteria;

b. If the targeted rate contract is deferring a self-generation

option, the Company will include its analysis of the customer’s self-generation alternative; and

c. The expected revenue from the contract, the incremental

revenue from the contract compared to what would have happened without this contract and the difference between revenue under the contract and revenue at core rates in effect at the time the contract becomes effective, assuming the same level of delivery services. CMP will also provide


Docket No. 2013-00168

the cumulative totals for all programs and contracts, given the addition of the program for which the Company is filing for permission to implement.

Stipulation Attachment 9 Docket No. 2013-168

ELECTRIC DELIVERY RATE SCHEDULE Page 115.00 CENTRAL MAINE POWER COMPANY Twenty-Seventh Eighth

Revision

RATE O TEMPORARY POWER DELIVERY RATE

AVAILABILITY This rate is available only to customers taking service under special contract for Temporary Power

as of December 19, 1995. Delivery of energyservice under this rate will be furnished only to the extent capacity on the

Company’s transmission and distribution system is available from time to time, during such periods as the Company may designate, to customers in order of priority of application. No applications under this rate will entitle a customer to obtain a priority preference until confirmed by the Company.

Delivery of energyservice subject to Rate O is all kilowatt-hours, exclusive of kilowatt-hours

delivered under other non-firm tariffs, delivered in excess of the demand levels for firm service established in the customer's special contract for Temporary Power.

Temporary Power delivery service, if available, may be used for scheduled maintenance and

emergency maintenance of generating equipment. All equipment associated with the production of electrical energy is considered part of the generating equipment as specified in the customer's special contract for Temporary Power delivery service. The customer will provide the Company with at least 60 days notice of the estimated beginning and ending dates of the customer's scheduled maintenance.

TRANSMISSION SERVICE In addition to the requirements and charges under this rate schedule, customers connected at the

transmission or subtransmission voltage level will take transmission service in accordance with the terms of the ISO-New England Inc. Transmission Markets and Services Tariff. For customers served at the primary or secondary distribution voltage levels, transmission service charges will be included in the Temporary Power Delivery Rate as described below.

CURTAILMENT OF TEMPORARY POWER DELIVERY SERVICE The Company shall have the right to deny service under this rate or to discontinue furnishing

service under this rate, in whole or in part, immediately upon notice to the customer that the Company's transmission or distribution system is approaching a capacity constraint, in the Company's judgment.

______________ Effective Date: September 1, 2014 Eric N. Stinneford Docket No. 2013-00168 Vice President–Controller, Treasurer &

ClerkEffective Date: July 1, 2005 R. Scott Mahoney


Docket No. 2005-82 Vice President – Controller, Treasurer & Clerk


ELECTRIC DELIVERY RATE SCHEDULE Page 115.10 CENTRAL MAINE POWER COMPANY Twenty-First Second

Revision


FAILURE TO CURTAIL If the customer fails to curtail as requested by the Company above, all delivery of energyservice

during the temporary power curtailment period, exclusive of kilowatt-hours delivered under other non-firm tariffs, will be subject to the customer's applicable General Service Standby/Station Service rate schedule.

RATES Transmission-Level Customers: CMP will provide Temporary Power delivery service at the Temporary Power Delivery Charge.

The Temporary Power Delivery Charge per calendar month will be the per kWh chargesrates set forth in the then-current Rate LGS-ST-TOU or Rate LGS-T-TOU and the Company's Terms and Conditions on file with the Commission, as revised from time to time plusthe greater of: 1) $0.045 per kWh less the customer’s energy supply price for this Temporary Power service multiplied by the total kWh delivered under this tariff; or 2) the applicable monthly transmission charges for usage under this tariff as determined under ISO-New England, NEPOOL and Company’s OATTs for transmission and subtransmission customers. CMP will charge a $500 administrative fee for each month the customer takes service under Rate O. Distribution-Level Customers:

CMP will provide Temporary Power delivery service at the Temporary Power Delivery Charge. The Temporary Power Delivery Charge per billing period will be the ratesper kWh charges set forth in the then-current Electric Delivery Rate Schedule and the Company's Terms and Conditions on file with the Commission, as revised from time to time plusthe greater of: 1) $0.045 per kWh less the customer’s energy supply price for this Temporary Power service multiplied by the total kWh delivered under this tariff; or 2) the applicable monthly transmission charges for usage under this tariff from the appropriate general service rate, as provided in Terms & Conditions 44 for customers served at the distribution level. CMP will charge a $500 administrative fee for each month the customer takes service under Rate O.

METERS The Company will furnish one set of meters for measuring both the energy delivered under the firm

service rate schedule and the energy delivered under this rate schedule. If service under Rate O requires metering facilities in addition to, or in substitution of, the standard

facilities that the Company would normally install to provide firm service, the Company will provide the additional or substitute metering, and the customer will be subject to an additional monthly charge in accordance with Section 13 of the Terms and Conditions.


______________ Effective Date: March 1, 2000September 1, 2014

Raymond W. HepperEric N. Stinneford Docket No. 97-5802013-00168 Vice President–

Controller, Treasurer & ClerkGeneral Counsel


ELECTRIC DELIVERY RATE SCHEDULE Page 115.20 CENTRAL MAINE POWER COMPANY Eighth Revision


SPECIAL CONDITIONS

1. Priority of Application

In case there are applications for delivery of more energy than the Company has available transmission or distribution capacity, final determination of allocation of capacity shall remain with the Company, giving due regard to the order in which applications have been made and the blocks of energy required by the respective customers for efficient operation and the necessity for advance planning of their respective work schedules.

2. Non-replacement of Firm Service

None of the service furnished under this rate shall be in replacement of any other service being taken by the customer under other rates at the time notice of availability of service under this rate is given to the customer or in substitution for firm electric service under filed rates, but shall be in addition thereto.

3. Excess Transformer Capacity

If any transformers are required in excess of those used on the primary power service, they

shall be owned and maintained by the customer. ______________ Effective Date: March 1, 2000 Raymond W. Hepper Docket No. 97-580 General Counsel


ELECTRIC DELIVERY RATE SCHEDULE Page 115.30 CENTRAL MAINE POWER COMPANY First Revision


Cancelled. ______________ Effective Date: March 1, 2000 Raymond W. Hepper Docket No. 97-580 General Counsel

Central Maine Power Company Distribution Revenue Increase and Average Residential Bill

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Transcript of Central Maine Power Company Distribution Revenue Increase and Average Residential Bill