appa: new generation - emerging technologies 1 ompa’s wind power project

APPA: New Generation - Emerging Technologies

1

OMPA’s

Wind

Power

Project


2

Who We Are

• State Governmental Agency

• Municipally governed

• Wholesale electric provider to 35 of Oklahoma’s 64 Municipal Electric Systems


3


4

Why Wind?

• Need for additional generation (plus diversity)

• City customers’ growing interest in Green Power

• Draft bills at national level, state government interest; OREC

• Other state utilities’ interest• Suppliers/marketers


5

Generation Fuel Mix for 2004

Coal63%

Hydro5%

Wind8%

Gas6%

High Efficiency

Gas18%


6

Consumer Benefits

• Helps protect the consumer against increases in fuel prices • Project scale allows a competitive low price - consumer

prices should not increase due to the addition of wind especially versus current and forecasted marginal costs

• Allows utilities to offer customers the choice of purchasing clean power

• Project provides enough energy to power almost 20,000 Oklahoma homes

• Adds another “fuel type” to OMPA’s mix of coal, Natural gas, and Hydro


7

Supply Portfolio Benefits• Long-term fixed price contract provides hedge against

volatility in fuel prices• Wind is competitively priced against other new fossil

generation• Wind is a prudent part of a diversified portfolio • Easily blended into a system with virtually no

incremental system costs• Quick to market - from conception to commercial

operation versus other generation alternatives - six months of construction time

• Reduces the need to purchase renewable energy from out-of-state if a RPS (Renewable Portfolio Standard) adopted


8

Rural Economic Benefits• Jobs

• Short-term - 80 to 120 construction positions

• Long-term - 5 to 8 permanent well-paying positions ($20k to $70k)

• Creates business opportunities in rural areas with few other significant economic development opportunities

• Increases/diversifies income for ranchers – oil/gas royalties declining

• Increases local tax revenue - typically composes a significant percentage of the historical annual operating budget

• Use of local contractors, suppliers, and services: land surveys, legal services, fuel, concrete and rock, food, and lodging

• Increases local tourism


9

Some Issues OMPA Considered in its Wind Program

• How will wind power fit OMPA’s program?

• Transmission

• Intermittency

• Major issue, FERC OATT major impediment

• Tax credits

• PTC’s Federal $0.018/kwh, State $0.0075 Kwh

• 5 year depreciation with a bonus

• Short-term forecasting

• Capacity value


10

27. Familiar with "Green Power"(SDS Survey (Residential) 2002/3)

0

20

40

60

80

100

Edmond 01 Edmond 03 All OMPA 03

Perc

ent Yes

No


11

28. Interest in Purchasing Green Powerif 5-10% Higher

(SDS Survey (Residential) 2002/3)

010203040506070

Edmond 01*(10-20%)

Edmond 03 All OMPA 03

Per

cent

Very Interested

Fairly Interested

Somew hat Interested

Not Interested


12

Green power40. How important is it to you that your utility company offers “Green Power” programs, or more environmentally friendly sources of energy, to the customer like Wind Energy?

7%

7%

5%

39%

43%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Overall 05

Very importantSomewhat importantDK/RefusedSomewhat unimportantVery unimportant


13

OMPA’s RFP

• 50 MW Must Take Purchase– OMPA shall take the output of up to 50 MW (rated

capacity) of wind generation

• Priced at a discount to OMPA’s avoided cost– Avoided cost estimated using coal energy (Nov – Feb),

7,000 Btu/kWh gas energy on peak and coal energy off peak (Mar – May, Oct) and 10,000 Btu/kWh gas energy on peak and coal eneergy off peak (Jun – Sep)


14

Responses to RFP

• FPL Energy

• Sleeping Bear, LLC (RES and Chermac)

• Zilkha (2 responses – Durham and Blue Canyon)

• Sea West

• Cuatro Vientos Power Partners, LLC (enXco)


15

FPL Energy Response

• Term – 25 years

• Pricing– $23.60 on peak, $12.00 off peak ($18.50/MWh

average) for years 1-5– Greater of $23.60 on peak or 90% of OMPA’s

avoided cost, $28.00 cap for years 6-25

• Required equity participation by OMPA


16

…FPL Energy Response

• Point of delivery – WFEC Mooreland Substation, where OG&E also has an interconnect

• Availability by 2nd quarter of 2003

• Actually came on line September 29, 2003

• First commercial wind farm in Oklahoma


17

Evaluation of Responses

• FPL Energy response most attractive– Met OMPA’s internal economic hurdle of not

increasing costs to participants– Debt financing required, credit support critical

• Other proposals– One met internal hurdle, credit support doubtful– Lowest cost purchase power proposal did not

meet OMPA’s internal hurdle


18

Wind Power Assessment CommitteeWind Power Assessment Committee

Oklahoma Wind Generators


19

Oklahoma Wind Generators• Oklahoma Utilities purchase wind energy from wind power developers under

long term contracts• OG&E

– Oklahoma Wind Energy Center near Woodward; Operated by FPLE; 34 wind turbines

– 51 MW, Commercial Operation Sept. 2003• OMPA

– Oklahoma Wind Energy Center near Woodward; Operated by FPLE; 34 wind turbines

– 51 MW, Commercial Operation Sept. 2003• WFEC

– Blue Canyon Wind Farm; near Lawton, 45 wind turbines owned and operated by Zilkha

– 74.25 MW– Commercial Operation Dec. 2003


20

OK Wind Generation Capacity (MW)

ExistingFarm (owner) Capacity Power PurchaserOK Wind Energy Center (FPLE) 51 OMPA

OK Wind Energy Center (FPLE) 51 OG&E

Blue Canyon (Zilkha) 74.25 WFEC

TOTAL EXISTING 176.25

ProposedOK Wind Energy Center (FPLE) 106.5 PSO (2004)

Sleeping Bear (Chermac) 96 NA (2005)

South Buffalo (Chermac) 25.5 NA (2005)

TOTAL PROPOSED 228


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22

Operational Issues Associated with Wind


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Summary Statistics• OG&E, OMPA, and WFEC together generated

approximately 500,000 MWH of wind energy during first year of operation

• The cost of this generation was approximately $12.5 million, or about $25/MWH

• Installed Wind Capacity:– WFEC 74.25 MW– OG&E 51 MW– OMPA 51 MW

• Total installed = 176.25 MW


24

Good Things

• Wind equipment and facilities operating well• Communities have accepted wind facilities and

have benefited– Good jobs; property tax revenue

• Capacity factor approximately 36% (near forecast)• Stable wind energy contract rates attractive

compared with gas prices at or above $5/MMBtu• Environmentally clean green power resource for

Oklahoma customers


25

Not so Good Things;Wind Timing Issues

• Over half of wind energy produced during off peak hours

• Wind generation moves in opposite direction of load more often than not

• Wind is uncertain; difficult to forecast and schedule, but this is improving


26

Wind Production Curve v. Load Curve (Annual Hourly Averages)

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30

35

40

45

1:00

2:00

3:00

4:00

5:00

6:00

7:00

8:00

9:00

10:0

011

:0012

:0013

:0014

:0015

:0016

:0017

:0018

:0019

:0020

:0021

:0022

:0023

:00

0:00

0

100

200

300

400

500

600

700

800

900

Average Production by Hour Average Hourly Load


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Operational IntegrationHourly MWh Gen Histogram

0

200

400

600

800

1000

1200

1400

1600

5 10 15 20 25 30 35 40 45 50 55 60 65 70 75

Hourly MWh Gen

No

. of

Ho

urs

Hourly Gen


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Impacts of Wind Generationon Utility Operations

• When wind production occurs off peak– Wind energy sometimes backs down gas generation,

but sometimes coal– Wind cost approximately $25 MWH– Compared to other generation - examples:

• Coal at $11 MWH ($1.25 coal)• Gas combined cycle at $42 MWH ($6 gas)• Gas-steam at $63 MWH ($6 gas)

• Larger quantities of wind production off peak will displace larger proportions of coal generation off peak


29

Impacts of Wind Generation (cont.)

• Must be backed up with spinning capacity to maintain reliability. At this point we don’t know what back-up level is required but the level does depend on the wind penetration level and the accuracy of wind power production forecasting

• Wind energy runs counter to load during many hours, which increases generation regulation duty

• Generator Imbalance Penalties on Transmission System for wind generation forecasting errors; this will improve with implementation of the SPP’s EIM in late 2005


30

SPP Tariff Scheduling Penalties• SPP OATT Ancillary Service Schedule #4

– Problem is wind forecasting

• OMPA SPP penalties for load following services would have exceeded cost of wind energy itself– OMPA cost of wind energy $2.5 million– AS #4 penalties for undersupply would have been $3.4

million if under SPP tariff (135% of energy cost)

• A TDU issue – control area operators not subject to these charges

• Major barrier for further wind development


31

Summary of First Year Operations

• Energy produced: 154,019 MWh– Undersupply 40,668 MWh (+/- 2 MW)– Oversupply 14,320 MWh (+/- 2 MW)

• Cost of undersupply (if under tariff)– $3,403,000 compared to wind– $1,370,000 compared to gas @ 10,000 HR– Studies say $3.11/MWh; however, SPP is in the

$13.2 – 22.1/MWh range


32

SPP Capacity Credits for Wind

• Dependable capacity in SPP– SPP proposes to allow only 4% of nameplate

– Other RTOs allow up to 30%

– Cost ~ $28,900/kW installed capacity

– Nearly 10x nuclear capacity cost

– Most restrictive of all NERC regions

• SPP methodology is a barrier to future wind production and a penalty to investment in Oklahoma


33

Operational Integration60-Min MW Gen. Change Histogram

0

2000

4000

6000

8000

10000

12000

14000

16000

-40 -35 -30 -25 -20 -15 -10 -5 0 5 10 15 20 25 30 35

60-Min MW Gen Change

No

. of

Oc

cu

rre

nc

es

60-Min MWChange


34

Interconnection Issues

• Transmission Expansion Costs are significant; – Wind resource is frequently remote from load– Radial lines to wind sites required

• Southwest Power Pool Transmission Tariff penalizes wind scheduling errors – Hourly wind forecasting not that accurate (data from

OK production thus far shows 85% to 90% of the hourly errors are between –5 MW and +15 MW)

– SPP imbalance penalties for load following services exceeded cost of wind energy itself for OMPA during 2004; SPP EIM may improve or eliminate this situation


35

Issues for Future Wind Development in Oklahoma

• Larger quantities of wind energy could displace larger proportions of low cost coal energy due to generally off peak nature of wind production

• Transmission costs– Non-discriminatory transmission construction and cost

allocation of transmission costs– Transmission System expansion needs are expensive

and may only be useful to connect additional wind generation

– SPP Transmission penalties for forecasting errors are high


36

Issues for Future (Cont.)

• High Installation Costs– SPP recognizes only a small percentage of a wind

facility’s nameplate capacity as dependable

– This results in very high effective installation costs for wind facilities (from $8,000/kW (@ 15% capacity factor) to $30,000/kW (@ 4% capacity factor)

• Wind forecasting needs to improve– Scheduling errors lead to imbalance penalties, which

are high


37

Issues for Future (Cont.)

• Technologies to improve wind production load shape and capacity factor– Compressed air storage– Combination with other renewable generation, e.g.,

hydro, biomass– Combination with low cost fossil generation, e.g.,

waste gas, re-cycled oil– Multiple wind farms operating together taking

advantage of the diversity in the timing and level of production across the farms

• Customer can purchase– 100% wind energy, or– 100 kWh blocks

• Additional cost is 1.8 c/kWh, but

• Fuel cost adjustment is waived• Note – OG&E customers pay 2c/kWh,

and fuel cost adjustment is also waived

Edmond’s Program

•Marketing materials available to OMPA cities

•Edmond and OMPA will modify appropriately

•Participating city pays printing and distribution costs

OMPA Cities participating (so far):

•Edmond

•Altus

•Tonkawa

•Frederick

•Okeene

•several others in process

Oklahoma Municipal Power Authority

Oklahoma Wind Energy Center

Woodward, Oklahoma


42

Economic Impacts of Forecasting Constraints on Wind Park Operations

Oklahoma Municipal Power Authority

Presented by Jonathan Horn


43

Introduction

• Forecasting techniques

• FPLE forecaster employed by OMPA

• Economic impacts of forecast error on OMPA

• Conclusions


44

Forecasting Horizons

• Short-term: Time horizons of zero to six hours.

• Serve a market function

• Long-term: Time horizons of six hours to one week.

• Serve a scheduling function


45

Short-Term Forecasting Techniques

• Physical approach

• Statistical approach

• Combination of physical and statistical


46


47

Long-Term Forecasting Techniques

• Take relevant NWP data

• Downscale data to hub height

• Convert wind speed to power output using the power curve

• These models are generally outperformed by statistical models in the short-term


48

FPLE Model Employed by OMPA

• Produces a forecast for “today” and each of the next five days

• Out to 21 hours the model uses Aviation Model Output Statistics (AVN MOS) or Forecast System Laboratory Rapid Update Cycle (FSL RUC) wind speed maps

• The data is graded and the best available data is used to determine surface wind speed

• Corrections are applied based on wind gust up logic, thunderstorm logic, and direction change logic


49

FPLE Model Employed by OMPA

• Medium term model from 21 hours to 2 days uses AVN MOS when available, otherwise uses NGM MOS

• Applies correction based on wind direction change logic

• Long term forecast for 2-5 days uses NWS MRF data


50

Forecasting Impacts on OMPA

• Cannot follow load dynamically with few exceptions

• Must adjust next hour tags by 20 minutes till the top of the hour

• Conduct market trades three hours out


51

Impacts Under OATT

• OATT has a bandwidth of +/- 2 MW

• Penalty for undersupply under the OATT is $100/MWh

• Price paid for oversupply is 90% of avoided cost (usually coal at around $10 MWh)


52

Oversupply and Undersupply Bandwith Equals +/- 2Actual Wind Wind AverageWind Caused Caused Wind GIB Cost Total Cost of Total GIB Cost

Month Production Undersupply Oversupply Unit Cost Less Unit Cost Actual Wind Due to UndersupplyOctober 2003 9,214 2,917 1,595 18.31$ 81.69$ 168,708.34$ 238,289.73$

November 2003 13,242 3,091 456 15.21$ 84.79$ 201,410.82$ 262,085.89$ December 2003 15,030 4,790 618 14.86$ 85.14$ 223,345.80$ 407,820.60$

January 2004 10,238 3,949 1,178 15.76$ 84.24$ 161,350.88$ 332,663.76$ February 2004 11,808 3,073 691 16.31$ 83.69$ 192,588.48$ 257,179.37$

March 2004 14,786 3,494 1,298 16.83$ 83.17$ 248,848.38$ 290,595.98$ April 2004 12,551 4,222 828 16.90$ 83.10$ 212,111.90$ 350,848.20$ May 2004 21,077 4,242 1,741 17.05$ 82.95$ 359,362.85$ 351,873.90$

June 2004 9,760 3,167 1,248 16.13$ 83.87$ 157,428.80$ 265,616.29$ July 2004 10,447 3,155 1,424 16.31$ 83.69$ 170,390.57$ 264,041.95$

August 2004 10,794 2,503 2,106 16.13$ 83.87$ 174,107.22$ 209,926.61$ Total 138,947 38,603 13,183 2,269,654.04$ 3,230,942.28$

FPLE 2 Hour Forecast


53

Oversupply and Undersupply Bandwith Equals +/- 2Actual Wind Wind AverageWind Caused Caused Wind GIB Cost Total Cost of Total GIB Cost

Month Production Undersupply Oversupply Unit Cost Less Unit Cost Actual Wind Due to UndersupplyOctober 2003 9,214 1,140 1,127 18.31$ 81.69$ 168,708.34$ 93,126.60$

November 2003 13,242 1,411 1,383 15.21$ 84.79$ 201,410.82$ 119,638.69$ December 2003 15,030 1,460 1,589 14.86$ 85.14$ 223,345.80$ 124,304.40$

January 2004 10,238 1,434 1,384 15.76$ 84.24$ 161,350.88$ 120,800.16$ February 2004 11,808 1,152 1,166 16.31$ 83.69$ 192,588.48$ 96,410.88$

March 2004 14,786 1,478 1,536 16.83$ 83.17$ 248,848.38$ 122,925.26$ April 2004 12,551 1,297 1,284 16.90$ 83.10$ 212,111.90$ 107,780.70$ May 2004 21,077 1,763 1,699 17.05$ 82.95$ 359,362.85$ 146,240.85$

June 2004 9,760 3,167 1,476 16.13$ 83.87$ 157,428.80$ 265,616.29$ July 2004 10,447 1,381 1,465 16.31$ 83.69$ 170,390.57$ 115,575.89$

August 2004 10,794 1,561 1,454 16.13$ 83.87$ 174,107.22$ 130,921.07$ Total 138,947 17,244 15,563 2,269,654.04$ 1,443,340.79$

Persistence 2 Hour Forecast


54

Forecast Comparison for 8/26 - 8/27

1 4 7

10

13

16

19

22

25

28

31

34

37

40

43

46

TIME IN HOURS

OU

TP

UT

IN

M

W

ACTUALOUTPUT

FPLE 2-HOURFORECAST

2-HOURPERSISTENCE


55

Locational Marginal Pricing

• Prices would be set based on the cost to supply the next MW of power

• Short-term forecasts may become less important

• Accurate long term forecasts would be required for utilities to take full advantage of opportunities created by LMP


56

Conclusions

• Short term forecasting is probably more important than day ahead forecasting in the near term for organizations like OMPA;

• In a well functioning LMP market, short term forecasting will be much less important, at least from the viewpoint of producer economics;

• As the SPP gains more wind MW’s, regulation for wind production could become burdensome;

• Or because of geographic diversity it may not be an issue at all.

appa: new generation - emerging technologies 1 ompa’s wind power project

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