Benton PUD Rate Information 1 August 16, 2017 Staff Preliminary - - PowerPoint PPT Presentation
Benton PUD Rate Information 1 August 16, 2017 Staff Preliminary Recommendation Plug Into Your Future: Upcoming Meetings 2 Aug 30 Utility Industry 2.0 Sep 20 Broadband Sep 27 Emerging Technologies All meetings: Benton PUD
Staff Preliminary Recommendation
2
Aug 30
Sep 20
Sep 27
All meetings: Benton PUD Auditorium 5:30-7:00pm
Staff preliminary recommendation. Commission decision expected September 12.
3
1 Bonneville Power Administration 2 Biological Opinion
4
1.9% average revenue increase effective October 1, 2017 Applied “across-the-board” to all rate classes Applied entirely to Daily System Charge/Demand Charge BPA wholesale power rate increase is the sole driver 5.4% average increase to all BPA customers 3.8% increase to Benton PUD - $2.3M annualized impact Additional BPA surcharge to occur in 2018 (not in the 3.8%) “Spill-test” ordered by US District Court – cost to be determined Benton PUD plans to absorb 2018 surcharge with cash reserves
Staff preliminary recommendation. Commission decision expected September 12.
EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA $113.40 $122.00 $0 $20 $40 $60 $80 $100 $120 $140 $160 $180 Average Monthly Bill at 1,350 kWh June 30, 2017
“Mid-C”
Average bill information has been calculated by Benton PUD staff from publicly available information from
5
Staff preliminary recommendation. Commission decision expected September 12.
EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA $181 $231 $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 Average Monthly Bill at 2,500 kWh and 30 KW June 30, 2017
“Mid-C” Average bill information has been calculated by Benton PUD staff from publicly available information from
6
Staff preliminary recommendation. Commission decision expected September 12.
EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA $1,311 $1,479 $0 $500 $1,000 $1,500 $2,000 $2,500 Average Monthly Bill at 19,000 kWh and 75 KW June 30, 2017
“Mid-C” Average bill information has been calculated by Benton PUD staff from publicly available information from
7
Staff preliminary recommendation. Commission decision expected September 12.
EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA EIA $7,096 $7,690 $0 $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 $14,000 Average Monthly Bill at 115,000 kWh and 300 KW June 30, 2017
“Mid-C” Average bill information has been calculated by Benton PUD staff from publicly available information from
8
Staff preliminary recommendation. Commission decision expected September 12.
Key factors that can influence utility average bills/rates: EIA - utilities >25,000 customers must buy 9% of load from renewables State/local taxes – different entity types pay fewer taxes Customer density – more customers per line mile = lower rates Customer growth – higher growth can lead to higher rates Debt per customer – borrowing can keep rates lower in the short term
May catch up with a utility down the road
Cash reserves – can be used to defer/mitigate rate actions
9
Staff preliminary recommendation. Commission decision expected September 12.
2 American Public Power Association
10
Residential Benton PUD 7.7 WA Publicly Owned 8.4 WA Investor Owned 10.1 WA Cooperatives 8.7 National Average 12.7 California 16.2 Commercial 6.4 7.3 9.6 7.6 10.6 15.6 Industrial 4.7 4.7 7.6 6.0 6.9 12.3 Total 6.4 6.8 9.6 7.8 10.4 15.1
1 Revenues - includes all charges to customer
Staff preliminary recommendation. Commission decision expected September 12.
11
Senior/Disabled Low Income Programs
Discount is greater of daily system charge or percentage $509K total discounts applied in 2016
Helping Hands Customer Donations (administered by CAC)
Increased minimum pledge amount from $100 to $125 Higher amounts based on family size, up to $225 Record level of donations in 2016: $54,000
Low Income Weatherization Income as a % of Federal Poverty Level (FPL) Discount Prior to 2015 Discount After 2015 150% 20% 25% 200% 15% 15% 225% N/A 10%
Staff preliminary recommendation. Commission decision expected September 12.
13
$40 $45 $50 $55 $60 $65 $70 $75 $80 $85 $90 $ Millions
(1) Net power costs (NPC) = gross power costs (including power and transmission) less secondary market sales.
Significant Uncertainty
Better
Actual Actual Actual Forecast: July 2017 Forecast: July 2017 Forecast: July 2017
Primary cost drivers since 2007
Primary cost drivers - future
Staff preliminary recommendation. Commission decision expected September 12.
Significant efforts underway to bend cost curve down
14
Net Power Supply 64% O&M 17% Net Capital 11% Debt Service 5% Taxes less Other Revenue 3% 2017 Revenue Requirement Total Net Expenditures $124.8 million*
* Amount needed to collect through electric rates
Staff preliminary recommendation. Commission decision expected September 12.
15
BPA Power 74% BPA Transmission 11% Non-BPA Resource Costs 14% Other* 1% 2017 Revenue Requirement Total Net Power Costs $79.8 million
Staff preliminary recommendation. Commission decision expected September 12.
Net Power Supply 64% * Net conservation costs, ancillary services, and net secondary market sales and purchases
16
17
Staff preliminary recommendation. Commission decision expected September 12.
18
Staff preliminary recommendation. Commission decision expected September 12.
19
BPA rates increased 33% since
Internal Operations (dams) Continued investment in fish and
Reduced secondary market sales
Biological opinion (more later) Staff preliminary recommendation. Commission decision expected September 12.
Secondary Market Sales
Fish and Wildlife (F&W) Program
20
BPA F&W costs in 2016 – $622 million $127 million for foregone revenue & power purchases $495 million for program costs Historically ≈25% of BPA costs $16.5 billion spent (1978‐2016)
Staff preliminary recommendation. Commission decision expected September 12.
21
Influenced by:
Retail loads:
Water volume & timing: More water through turbines is better Market prices:
Staff preliminary recommendation. Commission decision expected September 12.
Power Purchase Contract thru 2028
3.0₵+ kWh
Power Markets Northwest & California
Rate changes biannually; Trend is higher Price changes hourly; Trend is much lower
Excess Power Sold on Market Used to Buy Down Retail Rates
2.6₵ kWh
Many NW utilities have secondary market sales – particularly BPA
Customers 3.0₵ kWh + Other Costs (2016 Avg: 6.7₵) 3.0₵ kWh + Other Costs (2016 Avg: 6.7₵)
Staff preliminary recommendation. Commission decision expected September 12.
Same Issue Impacting BPA
22
23 5.56₵ 6.50₵ 5.82₵ 4.34₵ 2.77₵ 2.04₵ 3.14₵ 3.25₵ 2.67₵ 2.57₵ 2.13₵
2.00 3.00 4.00 5.00 6.00 7.00
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Budget
Cents per kilowatt-hour Power market prices are expected to remain low.
Staff preliminary recommendation. Commission decision expected September 12.
BPA impacted by same price trends
24 115.4 96.6 100.2 93.4 85.3 142.6 129.4 97.7 108.1 83.7 97.4 139.0 80.0 90.0 100.0 110.0 120.0 130.0 140.0 150.0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Million Acre Feet (MAF)
More Water = More surplus power Average water 100.4 MAF Staff preliminary recommendation. Commission decision expected September 12. Lowest (2015) and 2nd highest (2017) water year in last decade
25
$84 $100 $95 $90 $86 $83 $80 $80 $83 $90 $95 $95 $95 $99 $104 $106 $45.0 $50.0 $55.0 $60.0 $65.0 $70.0 $75.0 $80.0 $85.0 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120
2002 2003 Apr 2004 Nov 2005 Sep 2006 Jan 2007 Jan 2008 Jan 2009 Jan 2010 Jan 2011 Jan 2012 Jan 2013 Jan 2014 Sep 2015 Sep 2016 Oct 2017*
Net Power Cost $ Millions) Bill Amount ($’s) Bill Amount Net Power Cost
*September 2017 based on an estimated 1.9% rate increase for residential customer class
From 2002 to 2017
1.55% Benton PUD average annual growth rate 2.12% Consumer Price Index escalation
Figures are NOT inflation-adjusted – expressed in nominal dollars
Staff preliminary recommendation. Commission decision expected September 12.
26
6.0% 0.0% 0.0% 0.0% 3.9% 4.9% 1.9% 0.0% 2.6% 2.6% 2.6% 0.0% 0.0% 0.0% 1.0% 2.0% 3.0% 4.0% 5.0% 6.0% 7.0% 8.0% 9.0% 10.0% Jan 2012 Jan 2013 Jan 2014 Jan 2015 Sep 2015 Sep 2016 Oct 2017 2018 May 2019 May 2020 May 2021 2022 2023 Projected Revenue Increase %
Significant Uncertainty Primary Driver: Rising Power Costs
Proposed
27
28
29
What is the FCRPS BiOp?
Federally developed river management plan Guides the operation of 14 dams relative to endangered fish NOAA Fisheries lead agency
13 threatened or endangered stocks of salmon/steelhead 2008 BiOp and 2014 Supplemental BiOp backed by: Four federal agencies, three northwest states, majority of Tribes Subsequently challenged by:
National Wildlife Federation, Oregon, Nez Perce Tribe, others
Staff preliminary recommendation. Commission decision expected September 12.
30
In May 2016, U.S. District Court ruled that BiOp is insufficient Remanded the BiOp back to the federal agencies for rewrite
Ruled that BiOp violated the Endangered Species Act and
“Recommended” that NEPA process consider the “reasonable”
More recently, Court ordered additional “spill-test” Spill-test for 2018 – April thru Mid-June Concern by federal agencies of “unintended consequences”
Total dissolved gas levels may increase
Staff preliminary recommendation. Commission decision expected September 12.
31
BPA plans to implement a surcharge for the cost of this test Not included in the BPA 5.4% wholesale increase on Oct 1 Uncertainty as to financial impact – as much as $40M to BPA May impact Benton PUD $0.6K to $1.2M in 2018 Staff recommendation Based on what we know today, use reserves to absorb the one-
Staff preliminary recommendation. Commission decision expected September 12.
32
Staff preliminary recommendation. Commission decision expected September 12.
33
34
35
36
37
38
Hydro Wind Solar Natural Gas Low Cost of Energy Carbon Free Peak Capacity Flexibility Transmission Support
39
No grid-scale storage (except for hydro)
Northwest
Staff preliminary recommendation. Commission decision expected September 12.
40
Staff preliminary recommendation. Commission decision expected September 12.
41
42
16 12 15 22
Kennewick Lows
Load Hydro
Thermal Wind
Staff preliminary recommendation. Commission decision expected September 12.
43
100 97 98 102 99 101 102
Kennewick Highs
Load Hydro
Fossil Wind Nuclear Staff preliminary recommendation. Commission decision expected September 12.
44
Legal - protective appeal filed
1 on US Court ruling
Legislative – proposed House Resolution 3144 Operate dams in accordance with 2014 BiOp until amended Limitations on restricting electrical generation/navigation No pending further judicial review Columbia-Snake River Irrigators Association
“God squad”- existing provision of Endangered Species Act Request to Inspector Generals (US Corps of Engineers/Department of Commerce)
2015 juvenile fish transportation program
Education of stakeholders on all sides
Staff preliminary recommendation. Commission decision expected September 12.
1Appeal filed by NOAA Fisheries, US Army Corps of Engineers and Bureau of Reclamation, Montana,
Idaho, Northwest RiverPartners, and Inland Ports and Navigation Groups.
45
46
47
O&M budget escalation at 1.7% annually since 2015 Includes major scope additions
Cybersecurity, disaster recovery and public safety
Escalation excluding scope additions is 0.6% annually since 2015 Positive trends on key benchmarks O&M cost per customer comparison Distribution O&M cost per circuit line-mile comparison Customer per employee ratio
Staff preliminary recommendation. Commission decision expected September 12.
48 $343 $349 $360 $348 $343 $378 $381 $395 $400 $371 $408 $408 $445 $445 $438 $480 $479 $469 $542 $561 $459 $454 $455 $427 $409 $437 $428 $431 $424 $382 $408
$300 $350 $400 $450 $500 $550 $600 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Budget
O&M(1) Cost per Customer – APPA(2) Benchmark
Stated Year Benton PUD Dollars Benchmark - APPA Benton PUD 2017 Constant Dollars
(1) O&M = non-power operations & maintenance cost (distribution, transmission, customer accounts, and administrative and general). Excludes Broadband. (2) American Public Power Association - 2015 median for West utilities. (3) Inflation rate utilized comes from a producer price index for electric utilities, which on average has been slightly under 3%
Benton PUD continues to be below APPA benchmark O&M Cost per Customer has declined after factoring in the effects of inflation(3) Staff preliminary recommendation. Commission decision expected September 12.
49 $4,257 $4,449 $4,483 $4,506 $4,699 $5,132 $4,977 $5,217 $5,446 $5,388 $5,679 $6,479 $7,090 $7,064 $6,576 $6,088 $6,232 $7,171 $7,121 $8,372 $5,699 $5,785 $5,661 $5,527 $5,598 $5,938 $5,593 $5,694 $5,773 $5,547 $5,679
$3,000 $4,000 $5,000 $6,000 $7,000 $8,000 $9,000 $10,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Budget
Distribution O&M(1) Cost per Circuit Line Mile – APPA(2) Benchmark
Stated Year Benton PUD Dollars Benchmark - APPA Benton PUD 2017 Constant Dollars
(1) Distribution O&M only. Excludes Broadband. (2) American Public Power Association - 2015 median for West utilities. (3) Inflation rate utilized comes from a producer price index for electric utilities, which on average has been slightly under 3%
Benton PUD continues to be below APPA benchmark Distribution O&M Cost per Circuit Line Mile has remained flat after factoring in the effects of inflation(3) Staff preliminary recommendation. Commission decision expected September 12.
50
Better Red Line
45,570 46,600 47,074 47,616 48,197 48,710 49,521 50,053 50,762 51,642 52,259 156 156 159 155 152 152 151 148 153 154 155 292 299 296 307 317 320 328 338 332 334 337
100 200 300 400 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 55,000
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 Actual Budget Actual annual average for years 2007-2016
Electric Customers (13.3% increase) Customers per Employee (14.5% increase) Customers per Employee (14.5% increase) FTE Employees (1.0% decrease)
Definition of Customer per American Public Power Association Customers per Employee Average Customers
Attrition not included in budget
Staff preliminary recommendation. Commission decision expected September 12.
51
155 184 50 100 150 200 250 300 350
WPUDA1 Survey – December 2016 (Distribution Systems Only)
52
Source: WPUDA Source Book (July 2017)
Median for survey respondents (158) Benton PUD Projected 2017 (147) Staff preliminary recommendation. Commission decision expected September 12.
1Washington PUD Association
Measures the number of days utility can cover its operating expenses using unrestricted reserves and assuming no additional revenue
Historical and Forecasted
53
Staff preliminary recommendation. Commission decision expected September 12. 143 136 127 155 147 132 118 99 97 100 110
$47.6M $48.5M $44.7M $53.5M $53.3M $47.7M $44.2M $38.7M $38.9M $39.6M $42.2M
20 40 60 80 100 120 140 160 180 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Actual Forecast
Source - Moody’s Investors Service Public Power Electric Utility Medians and Methodology, June 2014
Planned drawdown of reserves over time 2016 Bond Issue Moody’s Median average for Aa/A rated utilities (122) Benton PUD staff recommended range (108-132)
1,151 1,955 $0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000
WPUDA1 Survey – December 2016 (Distribution Systems Only)
54
District below the median and average of Washington PUDs
Source: WPUDA Source Book (July 2017)
Median for survey respondents ($1,558) Benton PUD Projected 2017 ($1,079) Staff preliminary recommendation. Commission decision expected September 12.
1Washington PUD Association
55
Equity and Fairness Better align fixed revenues with fixed costs Gradualism Work to mitigate significant changes to rates Gradually change rates to align with costs
56
Staff preliminary recommendation. Commission decision expected September 12.
57
Generation MOSTLY VARIABLE Transmission FIXED COST Distribution FIXED COST Customer-Owned Generation Utilizes Same Assets
FIXED COSTS DO NOT VARY BY POWER CONSUMED Staff preliminary recommendation. Commission decision expected September 12.
Based on 2017 Cost of Service Analysis Data
58
$- $10 $20 $30 $40 $50 $60 $70 Revenue Requirement (Cost) Projected Revenue Revenue Requirement (Cost) Projected Revenue Revenue Requirement (Cost) Projected Revenue Residential General Service Irrigation $ Millions
Fixed Variable
56% 44% 40% 60% 43% 57% 15% 85% 20% 80% 19% 81% Fixed Costs: Costs that do not change throughout the year with variability in energy consumption Fixed Revenue: Revenue collected through daily system charge and demand charge rate components Staff preliminary recommendation. Commission decision expected September 12. Revenues from fixed rate components need to be better aligned with fixed costs Revenues from fixed rate components need to be better aligned with fixed costs Revenues from fixed rate components need to be better aligned with fixed costs
Industry-wide, fixed revenues have been less than fixed costs
Rate structure has been in place for a century Industry saw no compelling need to change until now
Customer-owned solar now highlighting historical rate structure:
Solar customers use less energy from utility Able to avoid fixed costs buried in the kWh charge rate Non-solar customers can be disadvantaged
59
Staff preliminary recommendation. Commission decision expected September 12.
$0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $200 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 Customer Bill / Cost to Serve Customer kWh Consumption
Revenue vs. Cost to Serve
Simplified Example
60
Staff preliminary recommendation. Commission decision expected September 12.
Cost Revenue
Fixed Cost to Serve
Flat fee per day Intended to cover customer-related costs including: Customer service and billing Allocation of administrative & general (A&G) Minimum level of distribution infrastructure needed to serve a customer All major customer classes have a customer-related fixed charge
61
Staff preliminary recommendation. Commission decision expected September 12.
$18.75 $16.50 $- $5 $10 $15 $20 $25 $30 $35 $40 Monthly Base Charge
62
*Snohomish PUD has a monthly minimum bill in lieu of a monthly base charge. The monthly minimum bill is currently $15.90.
Benton PUD currently below the median
As of June 30, 2017
Median has increased by $2.75 over the past 2 years
Base Charge information has been calculated by Benton PUD staff from publicly available information from other utilities’ websites. Calculation is Benton PUD’s best effort to provide comparable information.
Staff preliminary recommendation. Commission decision expected September 12.
63
BPA power cost increase is the sole driver for Oct 2017 increase Since the majority of cost is variable, suggests an increase in kWh rate On the other hand…………… Benton PUD fixed revenues are not aligned with fixed costs Common issue for nearly all electric utilities across the nation Rate structure misalignment can lead to greater customer inequities Utilities across the country raising daily/monthly fixed charges
Staff preliminary recommendation. Commission decision expected September 12.
64
October 2017 increase entirely to fixed charges Gradual fix to historical misalignment Residential: daily system charge increase from $0.55 to $0.62 per day
Increase from $16.50 to $18.60 based on a 30-day month Consistent with increases peer utilities are making to base charges
Other classes: increases to daily system charges and demand charges Gradually increase base charge – over time
Remain near the median of benchmark utilities (currently $18.75)
Cost of Service Analysis shows residential base charge should be $27.90
Staff preliminary recommendation. Commission decision expected September 12.
65
Customer Class Current Rates DSC 1 Demand Residential $16.50 N/A Small General Service $20.40 N/A Medium General Service $41.40 $8.77 Large General Service $41.40 $7.45 Large Industrial $226.20 $7.92 Small Irrigation $4.50 $3.10 Large Irrigation w/o MLC $31.50 $3.25 Large Irrigation w/MLC MLC 2 $3.78 Large Irrigation Pumping Station $30.00 $3.25
1) Daily system charge: $ per month based on a 30-day month Small General Service and Medium General Service rates based on Multi-Phase service 2) Large irrigation w/MLC class has a Miles of Line Charge in lieu of a daily system charge
Proposed Rates DSC 1 Demand $18.60 N/A $24.00 N/A $48.30 $9.55 $58.80 $7.93 $226.20 $8.53 $5.40 $3.34 $36.00 $3.57 MLC 2 $4.21 $36.00 $3.64
Staff preliminary recommendation. Commission decision expected September 12.
66
67
Test Year Revenue Requirement
Total costs and allocations to customers to be recovered through the COSA process and rate making.
Cost of Service Analysis
Unbundling, classification and allocation of Revenue Requirement to be recovered from customer classes
Rate Design
Use the cost of service results and Rate Strategy to guide rate design. Rates should fully recover all costs not funded by reserves and/or debt.
Financial Forecast
Multi-year financial forecast to project total utility costs and initial revenue requirement for average rate impacts. Staff preliminary recommendation. Commission decision expected September 12.
68
COSA is a quantitative tool to guide setting rates for each class COSA results for each class can vary from year-to-year Policy goals/decisions can influence how rates are set Benchmarking rates is another tool to guide rate setting
69
Staff preliminary recommendation. Commission decision expected September 12.
70
Staff preliminary recommendation. Commission decision expected September 12.
1Planned drawdown of reserves used to mitigate revenue increase
71
(Amounts in $000's)
Customer Class Revenue Requirement(1) Estimated Revenues w/ Current Rates(2) Difference ($) COSA Results Increase Needed (%) Residential $61,178 $58,662 $2,516 4.3% General Service 33,936 34,988 ‐1,052 ‐3.0% Large Industrial 3,416 3,303 113 3.4% Small Agricultural Irrigation 1,123 1,058 65 6.1% Large Irrigation w/o MLC(3) 1,215 1,095 120 11.0% Large Irrigation w/MLC (3)(4) 22,689 21,208 1,481 7.0% Other (5) 1,236 691 545 78.9%
Total $124,793 $121,005 $3,788 3.1%
Note: (1) Revenue requirement does not reflect application of reserves (2) Reflects low income allocation (3) Large Irrigation class results include the respective wheelturning rate classes (4) Revenue requirement has been reduced for AFC unwind revenue of $0.4 million (5) Other includes Street Lighting, Security Lighting, and Unmetered services
Staff preliminary recommendation. Commission decision expected September 12. Proposing a 1.9% increase in rates
72
(Amounts in $000's)
Customer Class Revenue Requirement(1) Estimated Revenues w/ Projected Rates(2) Difference ($) COSA Results Increase Needed (%) Residential $63,855 $60,311 $3,544 5.9% General Service 35,317 35,710 ‐393 ‐1.1% Large Industrial 3,558 3,366 192 5.7% Small Agricultural Irrigation 1,163 1,077 86 8.0% Large Irrigation w/o MLC (3) 1,278 1,118 160 14.3% Large Irrigation w/MLC (3)(4) 23,744 21,788 1,956 9.0% Other (5) 1,264 707 557 78.8%
Total $130,179 $124,077 $6,102 4.9%
Note: (1) Revenue requirement does not reflect application of reserves (2) Estimated revenue includes recommended 1.9% revenue increase Reflects low income allocation (3) Large Irrigation class results include the respective wheelturning rate classes (4) Revenue requirement has been reduced for AFC unwind revenue of $0.5 million (5) Other includes Street Lighting, Security Lighting, and Unmetered services
Use of reserves to forego revenue increase in 2018 Staff preliminary recommendation. Commission decision expected September 12.
73
Utilizing gradualism for changes in rates Some customers had 2015/7% increase & 2016/4.9% increase Dampens the year-over-year impact for customers Power costs continue to rise: affects all classes BPA increase in October 2017 Major uncertainty with carbon legislation/regulation
Staff preliminary recommendation. Commission decision expected September 12.
74
Staff proposal: 1.9% average revenue increase
Increase directly attributable to BPA power increase October 1, 2017 Applied across the board to all rate classes Applied entirely to Daily System Charges and Demand Charges
Draft rates presented to Commission at August 22 meeting Consider adoption of new rates at September 12 meeting
New rates would be effective October 1, 2017
Staff preliminary recommendation. Commission decision expected September 12.
75