april breakfast meeting 2013
TRANSCRIPT
Rate Stability and Power Cost Adjustment(PCA) = 0 for all twelve
calendar months
1
Application of Cash Criteria
1. Keep the rates stable, Metric is PCA = 0
2. Increase the transfer to the City, however, it should not be at the expense of existing Capital Expenditure Programming
3. Reduce Industrial Rates—number 1 above should take care of number 3, since no rate increase for a long time is the same as a rate decrease. In addition, Industrial Customers will benefit by having a PCA = 0 for all twelve calendar months.
2
Power Cost Adjustment 2004 - Present
3
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
January $0.02500 $0.02500 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00254 $0.00185 $0.00000
February $0.02500 $0.02250 $0.00000 $0.00410 $0.00000 $0.00000 $0.00000 $0.00076 $0.00378 $0.00000
March $0.02000 $0.02440 $0.00000 $0.00387 $0.00591 $0.00626 $0.00000 $0.00075 $0.00000
April $0.01750 $0.01950 $0.00000 $0.00160 $0.00134 $0.00000 $0.00000 $0.00295 $0.00000
May $0.02000 $0.01850 $0.00000 $0.00000 $0.00487 $0.00000 $0.00000 $0.00334 $0.00000
June $0.01500 $0.01750 $0.00000 $0.00378 $0.00029 $0.00000 $0.00000 $0.00000 $0.00000
July $0.01650 $0.03500 $0.00000 $0.00000 $0.02191 $0.00000 $0.00000 $0.00689 $0.00354
August $0.00850 $0.04500 $0.01062 $0.00000 $0.00330 $0.00000 $0.00000 $0.00000 $0.00028
September $0.00850 $0.04500 $0.00612 $0.00000 $0.00063 $0.00000 $0.00000 $0.00000 $0.00000
October $0.01000 $0.04500 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000
November $0.01300 $0.03400 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00186
December $0.02200 $0.03750 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00339 $0.00830
4
December 2012
PCA =
$.0083/KWHR PCA=$0/KWHR
Electric Large General Service Demand $948.00 $948.00
Energy Charge $5,579.09 $5,579.09
Power Cost Adjustment(PCA) $628.31 $0.00
Local Sales Tax $35.78 $35.78
State Sales Tax $491.93 $491.93
Total Electric Bill $7,683.11 $7,054.80
% Decrease in Bill -8.18%
Sample Customer Bill, and effects of the Power Cost Adjustment(PCA) For December 2012
Entire Community Benefits
5
PCA=0 all Twelve Calendar Months, Total Community
Savings, All Rate Classes
Year
2006 $517,682.47
2007 $331,060.23 2008 $1,070,826.94
2009 $131,438.19 2010 $0.00
2011 $508,840.58
2012 $449,260.04
Approximate Savings by Customer Class
6
Electric Utility Customer Class
Approximate % Allocation
of PCA Savings
Estimate of the Extension of PCA Savings by Customer Class per year
2006 2007 2008 2009 2010 2011 2012
Residential Service 24.71% $127,919 $81,805 $264,601 $32,478 $0 $125,735 $111,012
Small General Service 6.50% $33,649 $21,519 $69,604 $8,543 $0 $33,075 $29,202
Large General Service 25.46% $131,802 $84,288 $272,633 $33,464 $0 $129,551 $114,382 Large
Industrial Service 51.25% $265,312 $169,668 $548,799 $67,362 $0 $260,781 $230,246
Savings for Large Industrial Class
7
PCA=0, Large Industrial Customer Savings--
from billing information
PCA=0, Total
Community
Savings, All
Rate Classes
% Energy Sales attributed to Large
Industrial Customers
PCA=0, Large Industrial Customer
Estimated Savings
Total Large
Industrial Sales Year 2006 $12,950,208 $517,682 51.61% $267,175.93 2007 $13,328,227 $331,060 51.75% $171,323.67 2008 $13,286,228 $1,070,827 50.96% $545,693.41 2009 $10,650,886 $131,438 47.42% $62,327.99 2010 $11,471,748 $0 48.21% $0.00 2011 $11,692,880 $241,135 2012 $10,763,758 $195,936
PCA=0, Large Industrial Customer Savings
Total Large Industrial Sales
Year Less PCA Savings % Decrease on Energy Bill
2006 $12,950,208.00 $267,175.93 $12,683,032.07 -2.06%
2007 $13,328,227.00 $171,323.67 $13,156,903.33 -1.29%
2008 $13,286,228.00 $545,693.41 $12,740,534.59 -4.11%
2009 $10,650,886.00 $62,327.99 $10,588,558.01 -0.59%
2010 $11,471,748.00 $0.00 $11,471,748.00 0.00%
2011 $11,692,880.00 $241,134.82 $11,451,745.18 -2.06%
2012 $10,763,758.00 $195,936.28 $10,567,821.72 -1.82%
Average = -1.70%
Rate Study Performed in 2012
• Consulting firm SAIC performed rate study in 2012 for both electric and natural gas utilities.
• Consultants were made of aware of various strategies we are using and intend on implementing in the electric utility.
• Consultants only looked as far as year end 2016, result was they did not recommend raising rates.
8
Power Supply Planning Presentation
9
Operating Expenses—numbers from 2011 Audit
$18,858,445.00
$6,053,688.00
$883,761.00
2011--Operating Expenses
Power Supply Expenses
Other Expenses
PILOT
•Approximately 70% of all electric utility expenditures are power supply expenses. •Other expenses will increase due primarily large increases in Transmission Expense. •Focus on reducing power supply expenses.
10
Power Supply Planning
The following items are included in this study, some have already been implemented, while others will likely be implemented in the future.
1. Rate stabilization fund is used—this was implemented in 2006. 2. Statistical Model being used by system control to dispatch generating units—implemented in
2012. 3. Base load supply was reduced from 30 MW to 25 MW—this was implemented on January 1,
2013. This supply comes from Missouri River Energy Services. 4. Unit 8 has a scheduled run in January, June, July and August—this has been implemented, and
functions as a hedge against the market. 5. Installation of new Wartsila 9.5 MW generating unit—Unit will go on-line in February 2013. Unit
will be used as a hedge against the real-time market. 6. Change air permit for units 3 and 4. Each of these units are 4 MW dual fuel units. Late spring
2013 we will identify what needs to be done (if anything), to gain added operating hours for both units. Anticipate this will be complete in 2014. Units will be used as a hedge against the real-time market.
7. Purchase and install a 2nd Wartsila 9.5 MW generating unit—we would like to see this unit go on-line in 2015/2016 time frame. This unit will be used as a hedge against the real-time market.
11
Power Supply agreement with Missouri River Energy Services
• Missouri River Energy Services(MRES) is a Joint Action Agency. HUC has a membership agreement with MRES. HUC’s electrical bill from MRES is based on a rate. All members of MRES have the same rate structure.
• MRES rate structure is seasonal, following is a breakdown of that rate structure: – Dec-Feb.—$53.1/MWHR – March-May--$44.1/MWHR – June-Aug.—$58.3/MWHR – Sep.-Nov--$44.2/MWHR
• Approximately 70 % of Hutchinson’s electrical energy supply comes from MRES. The other 30 % comes from market purchases or is generated using HUC’s power plants.
• Much emphasis has been placed on mitigating market risk as it relates to the 30 % that HUC provides Hutchinson. Market years 2006, 2007, 2008, 2009, 2010, 2011 and 2012 have all been treated as test years to determine the proper amount of generation that need to be installed at plant 1 to mitigate market risk.
• The following slides are a representation of the level of effectiveness of HUC’s strategies for the additional 30 % using a combination of market purchases and HUC’s electrical generation.
12
Example of July 20, 2011—25 MW Base Load, Unit 3, 4, 8 New Unit 5
0
10
20
30
40
50
60
70
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Load
Base Load + Unit 8 + Other Gen.
July 20, 2011
Unit 8 scheduled start
Units 3, 4, 5 start Market > Gen Cost
Purchase off market Market < Gen Cost
Unit 8 scheduled stop
Units 3, 4, 5 stop Market < Gen Cost
Not enough generation at Plant 1 to cover load
Time—24 Hours/day
Blue Line is HUC Electric Load
Red Line is Electric Supply MRES Base Load Supply
13
MWHR’s
Example of July 20, 2011—25 MW Base Load, Unit 3, 4, 8, New Units 5 & 6
0
10
20
30
40
50
60
70
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Load
Base Load + Unit 8 + Other Gen.
July 20, 2011
MRES Base Load Supply
Unit 8 scheduled start
Units 3, 4, 5, 6 start Market price > Gen Cost
Plant 1 now has enough Generation to take care of HUC load. HUC will realize a small op. income from electric supply sold into market. The Op. Income received is subtracted from Wholesale rates charged to HUC retail customers.
Time—24 Hours/Day
Blue Line is HUC Electric Load
14
Red Line is Electric Supply
MWHR’s
Example July 2011 July 2011
$/MWHR MWHR Total Cost
Base Load $ 58.02 18,600 $ 1,079,172.00
Market Purchases $ 29.11 7,824 $ 227,755.95
Cost of Unit 8 Scheduled Gen. $ 36.60 2,400 $ 87,840.00
Hedged Gen.--units 3, 4, 5, 6 $ 47.49 3,109 $ 147,649.33
Additional Market Purch. After gen. $ 140.21 17 $ 2,383.62
Total HUC Load and Cost w/o bundling $ 34.88 13,350 $ 465,628.90
Bundled Gen.Revenue $ 67.54 1,751 $ 118,260.86
Bundled Gen Expense $ 47.24 1,751 $ 82,725.00
Bundled Gen Op Income $ 35,535.86
Total HUC Cost less bundling op. income $ 32.22 13,350 $ 430,093.04
Blended Cost for July $ 47.24 31,950 $ 1,509,265.04
MWHR's % Provided
Provided from MRES Base Load Supply 18600 58.22% $ 58.02
Combination of Market & Generation Supply 13350 41.78% $ 32.22
Total HUC retail supply 31950
15
Monthly Supply from MRES and Market/Generation for 2011
Monthly 2011
% MRES Supply
Agreement % from Market/Generation
January 72% 28%
February 72% 28%
March 74% 26%
April 77% 23%
May 74% 26%
June 67% 33%
July 58% 42%
August 62% 38%
September 74% 26%
October 80% 20%
November 83% 17%
December 81% 19%
2011 Annual Supply % Supplied
% MRES Supply Agreement 72%
% from Market/Generation 28%
Note: This reflects the 25 MW base load power supply agreement with MRES. Please note that anywhere from 60% to 80% of HUC average monthly energy purchases are provided via MRES base load supply agreement. 16
HUC 2011—Market $/MWHR
$-
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$40.00
$45.00
$50.00
Market
Statistical Model+Unit 6
Average Market Price
Average + Unit 6
Market Mitigation 2011
Average price using a combination of market purchases and HUC generation at plant 1
Average price if all extra needs purchased off market
17
2011 Blended
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
2011 Actual
Statistical Model+Unit 6
2011 Average
Avg + Unit 6
2011 Base Load Contract reduction, Unit 8 scheduled run, Statistical Model being used, Installation of New Unit 5 Unit 3 and 4 added Op. hours Installation of New Unit 6
Note: Does not include transmission expense.
18
Annual % Supply From MRES and Market/Generation
% Annual Supply
Year
% MRES
Supply
Agreement
% from Market
and/or
Generation
Total HUC
Load
(MWHR's)
2006 69% 31% 319069
2007 67% 33% 328647
2008 69% 31% 318496
2009 76% 24% 288620
2010 72% 28% 305777
2011 72% 28% 302775
2012 75% 25% 291957
Note: The MRES base load power supply agreement accounts for approximately 70% of HUC annual energy needs. 19
$/MWHR savings by project and Benchmarking Study
2006 2007 2008 2009 2010 2011 2012
Actual Average $54.06 $53.77 $57.47 $54.10 $52.78 $53.51 $52.35
25 MW Base Load and Market Purch. $50.68 $53.22 $52.47 $45.38 $45.59 $45.87 $46.01
+ Unit 8 $49.71 $52.54 $51.52 $45.64 $45.33 $45.66 $45.94
Statistical Model + Unit 5 $47.78 $49.85 $49.96 $45.01 $44.59 $44.71 $44.76
Statistical Model + Units 3, 4 $46.16 $47.59 $48.64 $44.49 $43.97 $43.90 $43.77
Statistical Model+Unit 6 $44.23 $44.91 $47.08 $43.86 $43.23 $42.94 $42.59
APPA Benchmark--10% to 50 % Generation(median) $46.00 $58.00 $47.00
APPA Benchmark--North Central/Plains(median) $49.00 $59.00 $60.00
APPA Benchmark--50% to 100% Generation(median) $34.00 $46.00 $43.00
20
Per Unit and Extended Savings
Per Unit($/MWHR) Savings by project 2006 2007 2008 2009 2010 2011 2012
25 MW Base Load and Market $3.38 $0.55 $5.00 $8.72 $7.19 $7.64 $6.35
+ Unit 8 $0.97 $0.68 $0.95 ($0.26) $0.26 $0.21 $0.07
Statistical Model + Unit 5 $1.93 $2.68 $1.56 $0.63 $0.74 $0.96 $1.18
Statistical Model + Units 3, 4 $1.62 $2.26 $1.31 $0.53 $0.62 $0.81 $0.99
Statistical Model + Unit 6 $1.93 $2.68 $1.56 $0.63 $0.74 $0.96 $1.18
Electric Sales (MWHR's) 319,069 328,647 318,496 288,620 305,777 302,775 291,957
Extended Savings 2006 2007 2008 2009 2010 2011 2012
25 MW Base Load and Market $1,078,771 $180,675 $1,592,879 $2,516,080 $2,198,758 $2,312,946 $1,852,610
+ Unit 8 $309,172 $224,629 $304,073 ($74,937) $80,785 $62,353 $20,350
Statistical Model + Unit 5 $615,954 $882,118 $496,845 $180,551 $225,721 $289,806 $344,275
Statistical Model + Units 3, 4 $518,163 $742,836 $418,396 $152,043 $190,081 $244,047 $289,916
Statistical Model + Unit 6 $615,319 $882,118 $496,845 $180,551 $225,721 $289,806 $344,275
Total Savings $3,137,378 $2,912,375 $3,309,037 $2,954,288 $2,921,065 $3,198,957 $2,851,426
Note: Red = Market Hedge and Bundling
21
Bundling and Market Prices
2007 2008 2009 2010 2011
Annual LMP(Market)
Prices $51.26 $48.08 $24.61 $29.01 $27.76
$-
$500,000.00
$1,000,000.00
$1,500,000.00
$2,000,000.00
$2,500,000.00
$3,000,000.00
$3,500,000.00
2006 2007 2008 2009 2010 2011 2012
Bundled Revenue
Bundled Income
Bundled Expense
Effects on bundling as it relates to LMP or Market Prices--HUC generates more MWHR’s during higher market year prices. In addition, Operating Revenue and Operating Income both increase substantially. The graph only reflects plant 1 generation.
22
Bundling and Market Prices
2007 2008 2009 2010 2011
Annual LMP (Market) Prices $51.26 $48.08 $24.61 $29.01 $27.76
0
5000
10000
15000
20000
25000
30000
2006 2007 2008 2009 2010 2011 2012
Bundled Generation
Bundled Generation
MWHRS
HUC generates more MWHR’s during higher market year prices. The graph only reflects plant 1 generation.
23
Market Purchases, Hedged Generation and LMP (Market) Prices
2007 2008 2009 2010 2011
Annual LMP (Market) Prices $51.26 $48.08 $24.61 $29.01 $27.76
0
20000
40000
60000
80000
100000
120000
2006 2007 2008 2009 2010 2011 2012
Hedge
Market Purchases
Market Purchases and Hedged Generation--HUC generates more MWHR’s during higher market year prices. The graph only reflects plant 1 generation.
MWHR
24
Savings due to changing Base Load and Market Purchases—January 2013
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
2006 2007 2008 2009 2010 2011 2012
25 MW Base Load
25
Savings due to Unit 8 Scheduled Hedge and Bundling—January 2013
($500,000)
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
2006 2007 2008 2009 2010 2011 2012
+ Unit 8
25 MW Base Load
Note: Red = Market Hedge and Bundling 26
Savings due to adding Unit 5 Hedge and Bundling—February 2013
($500,000)
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
2006 2007 2008 2009 2010 2011 2012
Statistical Model + Unit 5
+ Unit 8
25 MW Base Load
Note: Red = Market Hedge and Bundling. Years 2006, 2007 and 2008 are higher market years, please note effectiveness of HUC generation during those years.
27
Savings due to Additional Operating Hours Units 3 and 4 Hedge and
Bundling--2014
($500,000)
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
$3,500,000
2006 2007 2008 2009 2010 2011 2012
Statistical Model + Units 3, 4
Statistical Model + Unit 5
+ Unit 8
25 MW Base Load
Note: Red = Market Hedge and Bundling. Years 2006, 2007 and 2008 are higher market years, please note effectiveness of HUC generation during those years.
28
Savings due to adding Unit 6 Hedge and Bundling —2015/16
($500,000)
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
$3,500,000
2006 2007 2008 2009 2010 2011 2012
Statistical Model+Unit 6
Statistical Model + Units 3, 4
Statistical Model + Unit 5
+ Unit 8
25 MW Base Load
Savings by Market Year with Respect to Integrated Resources Plan and Other Strategies
Note: Red = Market Hedge and Bundling. Years 2006, 2007 and 2008 are higher market years, please note effectiveness of HUC generation during those years.
29
Summary of Savings 2006 2007 2008 2009 2010 2011 2012
25 MW Base Load and Market Purchases $1,078,771 $180,675 $1,592,879 $2,516,080 $2,198,758 $2,312,946 $1,852,610
Savings due to gen. hedge & bundling $2,058,608 $2,731,700 $1,716,158 $438,208 $722,307 $886,011 $998,815
$3,137,378 $2,912,375 $3,309,037 $2,954,288 $2,921,065 $3,198,957 $2,851,426
$0
$500,000
$1,000,000
$1,500,000
$2,000,000
$2,500,000
$3,000,000
$3,500,000
2006 2007 2008 2009 2010 2011 2012
Savings due to gen. hedge & bundling
25 MW Base Load and Market Purchases
Summary--note effectiveness of plant 1 generation hedge and bundling during higher electric market years (years 2006, 2007, and 2008).
30
Question on Power Supply Planning?
31
Supporting Documents
32
HUC 2006—Market
$/MWHR
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
$90.00
Market
Statistical Model+Unit 6
Market Average
Average + Unit 6
Market Risk Mitigation 2006
Average price using a combination of market purchases and HUC generation at plant 1
Average price if all extra needs purchased off market
33
2006 Blended
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
2006 Actual
Statistical Model+Unit 6
2006 Actual Average
Avg + Unit 6
2006 Base Load Contract reduction, Unit 8 scheduled run, Statistical Model being used, Installation of New Unit 5 Unit 3 and 4 added Op. hours Installation of New Unit 6
Note: Prices do not include Transmission expense.
34
HUC 2007—Market
$/MWHR
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
$90.00
Market
Statistical Model+Unit 6
Average Market Price
Average + Unit 6
Market Risk Mitigation 2007
Average price if all extra needs purchased off market
Average price using a combination of market purchases and HUC generation at plant 1
35
2007 Blended
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
2007 Actual
Statistical Model+Unit 6
2007 Average
Avg + Unit 6
2007 Base Load Contract reduction, Unit 8 scheduled run, Statistical Model being used, Installation of New Unit 5 Unit 3 and 4 added Op. hours Installation of New Unit 6
Note: Prices do not include transmission expense
36
HUC 2008—Market
$/MWHR
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
$90.00
Market
Statistical Model+Unit 6
Average Market Price
Average + Unit 6
Market Mitigation 2008
Average price if all extra needs purchased off market
Average price using a combination of market purchases and HUC generation at plant 1
37
2008 Blended
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
2008 Actual
Statistical Model+Unit 6
2008 Average
Avg + Unit 6
2008 Base Load Contract reduction, Unit 8 scheduled run, Statistical Model being used, Installation of New Unit 5 Unit 3 and 4 added Op. hours Installation of New Unit 6
Note: Prices do not include
38
HUC 2009—Market
$-
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$40.00
$45.00
$50.00
Market
Statistical Model+Unit 6
Average Market Price
Average + Unit 6
Market Mitigation 2009
39
2009 Blended
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
2009 Actual
Statistical Model+Unit 6
2009 Average
Avg + Unit 6
2009 Base Load Contract reduction, Unit 8 scheduled run, Statistical Model being used, Installation of New Unit 5 Unit 3 and 4 added Op. hours Installation of New Unit 6
Note: Prices do not include transmission expense.
40
HUC 2010—Market $/MWHR
$-
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$40.00
$45.00
Market
Statistical Model+Unit 6
Average Market Price
Average + Unit 6
Market Risk Mitigation 2010 Average price if all extra needs purchased off market
Average price using a combination of market purchases and HUC generation at plant 1
41
2010 Blended
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
2010 Actual
Statistical Model+Unit 6
2010 Average
Avg + Unit 6
2010 Base Load Contract reduction, Unit 8 scheduled run, Statistical Model being used, Installation of New Unit 5 Unit 3 and 4 added Op. hours Installation of New Unit 6
Note: Prices do not Include transmission
42
HUC 2012—Market
$/MWHR
$-
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$40.00
$45.00
$50.00
Market
Statistical Model+Unit 6
Average Market Price
Average + Unit 6
Market Mitigation 2012
Average price if all extra needs purchased off market
Average price using a combination of market purchases and HUC generation at plant 1
43
2012 Blended
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
2012 Actual
Statistical Model+Unit 6
2012 Average
Avg + Unit 6
2012 Base Load Contract reduction, Unit 8 scheduled run, Statistical Model being used, Installation of New Unit 5 Unit 3 and 4 added Op. hours Installation of New Unit 6
Note: Prices do not include transmission expense
44