april breakfast meeting 2013

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


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 + Units 3, 4 $1.62 $2.26 $1.31 $0.53 $0.62 $0.81 $0.99


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


+ Unit 8

25 MW Base Load


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 + Units 3, 4


+ Unit 8

25 MW Base Load

Savings by Market Year with Respect to Integrated Resources Plan and Other Strategies


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


Market Average

Average + Unit 6

Market Risk Mitigation 2006



33

2006 Blended

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

2006 Actual


2006 Actual Average

Avg + 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



Average + Unit 6

Market Risk Mitigation 2007



35

2007 Blended

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

2007 Actual


2007 Average

Avg + 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



Average + Unit 6




37

2008 Blended

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$80.00

2008 Actual


2008 Average

Avg + 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



Average + Unit 6


39

2009 Blended

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

2009 Actual


2009 Average

Avg + 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



Average + Unit 6

Market Risk Mitigation 2010 Average price if all extra needs purchased off market


41

2010 Blended

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

2010 Actual


2010 Average

Avg + 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



Average + Unit 6




43

2012 Blended

$-

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

2012 Actual


2012 Average

Avg + Unit 6


Note: Prices do not include transmission expense

44