A:  Austin Energy’s electric “rates” or “base rates” are set by the [Austin] City Council.  While Austin Energy (AE) is developing a plan to reexamine its rates for the 2013 fiscal year, AE’s current rates have been in place since 1994.

There are a couple of exceptions of note.  Changes to some service fees for specific services have been adopted by the Council in some years.  The Large Primary Service Special Contract Rider was adopted by the Council subsequent to the 1994 rate adoption; however, that contract lowered the rate for the commercial and industrial customers taking service under the contract rider.  Fuel charges are typically adjusted annually but not exclusively.  Those charges are calculated according to a formula previously adopted by the Council.  As base rates are set only occasionally, and because any rate proceeding is likely to be a public process, using a measure of the change in electric rates as a performance indicator of the generation plan is unlikely to be a meaningful measure.

Additionally, such a measure will only capture the impact of portions of the plan which have already been implemented and may not be a suitable measure of the impact of future plans.  Measures related to the cost of generation and fuel could be evaluated relative to changes in ERCOT market prices or other measures such as a general comparison of rates offered in Texas as a means for evaluating AE’s cost performance but estimates of future impacts will likely require a forecasting effort similar to the current resource planning effort.

A: The reliability of the wholesale electric market and the transmission network is governed by ERCOT—under the direction of the Public Utility Commission—and the ERCOT Protocols.  By law, AE is subject to the reliability rules, guidelines, and procedures established by ERCOT.  Further, reliability issues raised by to the expansion of variable resources are issues that affect and involve the entire ERCOT region.  Austin Energy cannot take independent action to resolve transmission network reliability concerns, without the full involvement of ERCOT and the ERCOT member companies.  Reliability of the distribution network—wires below 60 KV—is overseen primarily by local distribution companies.  Austin Energy is responsible for the distribution reliability within its territory.  Austin Energy would therefore have the responsibility to monitor and mitigate adverse reliability outcomes on the distribution network associated with generation resources that are connected at the distribution level.

Austin Energy already has several industry accepted performance measures in place that track the reliability of its distribution system including SAIDI (System Interruption Duration Index) and SAIFI (System Average Interruption Frequency Index) which may be used or adapted for this purpose. In addition, Austin Energy will continue to monitor the System Average Transmission Line Performance Index (SATLPI). This measure provides a means to monitor the reliability and power quality of AE’s transmission line design and maintenance programs. The data collected to calculate these performance measures include the underlying cause of a disturbance.  This information provides AE the intelligence necessary to mitigate future distribution reliability concerns.  

Memo To:  Austin Generation Resource Planning Task Force

From:        Pace Global Energy Services

Subject:    Responses to Task Force Questions

Pace evaluated the performance of the Fayette Power Plant as a merchant generator in the ERCOT market by projecting expected dispatch, cost, and revenues on an hourly basis through 2020. All market drivers and assumptions are consistent with Reference Case projections. A summary of the projections is in Exhibit 1.

In our assessment, Pace projects the capacity factor of the plant to decline modestly from the low 80 percent range to around 78 percent by 2020. Pace calculated plant gross margins by subtracting costs associated with fuel, variable operations, and emissions from expected market sales. Over the entire study period, gross margins are estimated to average around $120 million (real 2007 $).

Exhibit 1: Summary of FPP Capacity Factor and Gross Margin Expectations

Year Total Generation (GWh) Capacity Factor Gross Margin ($MM) 2009 4,351 82% 67.0 2010 4,293 83% 104.5 2011 4,302 83% 139.2 2012 4,248 82% 127.2 2013 4,173 81% 105.2 2014 4,180 81% 111.1 2015 4,185 81% 139.6 2016 4,158 80% 148.1 2017 4,116 80% 136.6 2018 4,071 78% 111.4 2019 4,038 78% 119.0 2020 4,051 78% 141.0

This case reflects a single deterministic Reference Case. Market uncertainties could shift this projection in either direction. Key risk factors include coal prices, CO2 emission compliance costs, natural gas prices, energy demand, and power market prices, which are driven by the others. These factors could impact the expected dispatch of the Fayette plant, as well as the expected margin during times of dispatch.

A: Austin Energy’s recent presentation titled, “American Reinvestment and Recovery Action Weatherization Assistance Briefing” is posted on the Public Participation Process web site, www.AustinSmartEnergy.com.

Austin Energy’s Weatherization Assistance Program using stimulus will adhere to grant funding guidelines to:

1. Assist lower-income households and homes with higher energy burden,
2. Reduce residential energy costs,
3. Increase the energy efficiency of dwellings, and
4. Improve home health and safety for the elderly, persons with disabilities, and families with young children.

Slide 14 of the Weatherization Assistance Briefing identifies potential program participants, which identifies eligible households in existing programs that target lower-income households.  A more detailed needs-based assessment has not been conducted by AE to date.

A:  The City’s contract with LCRA regarding the Fayette Power Plant does not grant LCRA a unilateral right to use AE’s share of the capacity if AE chooses not to use it.  The contract could potentially require AE to schedule sufficient power to maintain the units’ minimum operating level if LCRA does not itself schedule enough power to maintain the minimum.  LCRA has a right of first refusal with regard to any sale of the plant and any sale of power, other than spot market sales.

A:  There are two ways in which ERCOT can influence operation and or closure of any generating facility, both currently and in the Nodal market. [First,] ERCOT can start and operate any available generator up to its maximum capability if required for reliability purposes at any time irrespective of the owner’s intended operating plan.  Reliability purposes include transmission system limitations and/or generating capacity (including ancillary services) shortfalls. [Second,] for these same reasons, any intended mothballing exceeding 180 days or closure of a generating facility must be approved by ERCOT.

ERCOT may elect to maintain the operation of a generator via a one-year Reliability Must Run (RMR) agreement which may be extended annually by ERCOT Board approval.  Closure/mothball plans must be submitted to ERCOT for RMR review a minimum of 90 days in advance of a target closure date.

The timelines related to ERCOT notifications are the only hard-coded requirements with respect to a closure of the plant.  It would be difficult to construct a hypothetical timeline beyond those requirements without first determining a target closure date and the disposition of the entire FPP facility as it relates to LCRA's rights and obligations.

A:  Neither the contract for the Webberville [30 MW Solar] project nor the Nacogdoches [biomass] project contains an early termination option or buy-out provision that could be unilaterally exercised by the City of Austin.  From a legal standpoint, it would be unwise for the City to comment publicly on what it believes would be the consequences regarding a potential default on the part of the City.

Any attempt to speculate as to the buy-out cost of the Nacogdoches project would entail revealing confidential information as such a calculation would require the contract price and other contract terms as inputs.  It would also require knowledge of the producer’s cost, financing, and profit expectations, which AE does not have, in addition to an estimated discount rate. 

A:  The number cited for 2008 of $182.8 million is mathematically correct. However, it is difficult to tie out the other years using the graph provided. 

Plant additions are generally depreciated over a 30-year period unless the equipment has a lower useful life or the plant has a known scheduled retirement date.  In addition, plant investment funded by debt usually has a 30-year maturity schedule to match the life of assets.  The FPP scrubber project is being funded by debt and the first issue in 2008 had a 30-year maturity schedule.  Even if the plant was shut down before 2038, the debt service related to it would still need to be paid through maturity period unless something was done to pay off the debt early.

A:  The statement that natural gas prices below $3.00/MMbtu are competitive with (current) coal costs at the Fayette Power Project is accurate.  AE’s standard practice is to perform “economic dispatch” of its resources wherein demand is met with the lowest cost from available resources including market purchases.  Economic dispatch is always subject to the physical and contractual operating limitations of resources and current and near term load conditions.  Economic dispatch may also be temporarily adjusted (subject to operating limits) to perform “environmental dispatch” in consideration of Ozone Action days.

Memo To:   Austin Energy Resource Planning Task Force

CC:             John Wester, Chris Smith, Austin Energy

From:         Pat Augustine, Gary Vicinus, Pace Global Energy Services

Date:          September 15, 2009

A: In Pace’s Phase I screening analysis, we analyzed and developed portfolios around specific objectives, including lowest cost, Council Goals, and other environmental targets.  One of the constraints Austin Energy established in this phase of the analysis was around market transactions, because in Austin Energy’s resource planning process, the primary concern is meeting native load in a reliable, cost-effective manner.  As a result, as part of the screening analysis, our portfolio development aimed to minimize off-system sales and net market transactions (the difference in market purchases and off-system sales).  After consultation with Austin Energy, we determined that to focus on costs that only meet load obligations, we would display portfolio costs without any credit for off-system market sales, which may not be considered firm revenue for planning purposes.

One of the results of this analysis was that the Staff Recommendation can meet native load by using less generation from the coal-fired Fayette Power Plant (“FPP”) (around 15% less by 2020).  This result has led Austin Energy to consider an implementation strategy for the Staff Recommendation that physically reduces output from FPP in order to provide societal CO2 emission benefits.

In the Phase II risk analysis, where we have focused on a limited number of portfolios that have different levels of sales in them, we decided to consider the full range (a broader view) of all the potential cost and revenue drivers behind total portfolio costs.  Since revenues from off-system sales will be available to Austin Energy in the ERCOT market and because they are highly uncertain and dependent on market conditions driven by fuel price and load uncertainty, we considered their full effects on total portfolio costs in the risk analysis.  In this context, all cost presentations for each of the portfolios included the impact of revenues associated with sales.  (As per expected carbon accounting rules, emission liability is transferred with the sale of energy, so even if sales revenues are accounted for, emissions associated with power sales do not accrue to Austin Energy in our analysis.)  To address the implementation strategy of curtailing coal plant output in the Staff Recommendation, Pace developed sensitivity analyses to examine the cost impact of forgoing sales revenue.

A: All results presented in the risk analysis included the impact of off-system sales, unless otherwise noted.  This includes the deterministic cases displayed on the cost distributions, as well as all numerical results in the summary table.  The sensitivity display on the Staff Recommendation without off-system sales is the only location where such costs were displayed.  Supplemental results are provided below that show the impact of no off-system sales for all portfolios on a levelized cost basis.  These are shown in Exhibit 1.  The solid objects represent expected values without sales, while the outlined objects include revenues associated with such sales.  Including sales lowers costs and risk for all portfolios.

Exhibit 1: Levelized Portfolio Costs with and without Off-System Sales

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Source: Pace analysis

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A: The distributions for natural gas and coal are summarized in Exhibit 2, along with historical values and the Reference Case forecast.  For natural gas prices, the 95th percentile is displayed in solid red and the 5th percentile is displayed in solid blue.

Exhibit 2: Distributions for Fuel Price Inputs in Risk Analysis (2007$)

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Natural Gas


Coal

Source: Pace analysis

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A: As we discussed in the meeting, there is no direct conversion from $/MWh to $000s, given the treatment of load uncertainty across all iterations and given the varying amounts of DSM in the different portfolios.  To summarize this request, we have presented the expected value of portfolio costs in thousands of dollars for the year 2020 and provided a display of the summary histogram for all portfolios.  This is presented in Exhibit 3.

Exhibit 3: Projected Portfolio Costs in Thousands of Dollars in 2020 (2007$)

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Source: Pace analysis

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Question 5:  Provide mean costs over time for each portfolio by year in real and nominal dollars

The expected value of annual portfolio costs in real and nominal dollars is displayed in Exhibit 4.

Exhibit 4: Expected Value of Portfolio Costs by Year (2007$/MWh and nominal $/MWh)

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Source: Pace analysis

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A: Detailed historical production cost data is confidential under the Austin Energy Competitive Matters Resolution, Austin City Council resolution 20051201-002. The PACE Analysis and Assumptions document reflect the expectations for future costs.

A: Steve Machicek’s [Director Regulatory Affairs and Corporate Accounting] presentation to the Task Force on August 26, 2009, discussed the differences between the PACE analysis and Austin Energy’s 2020 bill impact analysis. This presentation is posted on the AustinSmartEnergy.com web site front page under "Learn More" as "PACE/AE Calculation Methods." This additional level of detail is considered confidential under the Austin Energy Competitive Matters resolution, Austin City Council Resolution 20051201-002.

A: Detailed historical production cost data is confidential under the Austin Energy Competitive Matters resolution, Austin City Council Resolution 20051201-002.

A: Chart provided to Task Force that shows capital project expenditures from 1998 through 2008.

A: Austin Energy will be conducting a study on the potential of Combined Heat and Power in AE’s service territory. For a discussion on thermal energy storage see question and response number 5 from the Task Force Input responses dated 8-26-09.

A: Biomass AD refers to anaerobic digestion which is a process in which microorganisms break down biodegradable material in the absence of oxygen. This is a more costly process for using biomass to generate electricity. Austin Energy is primarily looking at biomass combustion of materials such as wood waste that are more cost effective. The value provided by PACE for the levelized costs of generation for biomass combustion was 7.5 cents per kWh in both 2012 and 2020.

A: The levelized cost estimates provided by PACE for 2012 and 2020 are provided for illustrative purposes. PACE’s screening process isn’t based solely on these numbers. These are intended to be an illustrative display of two particular years, 2012 and 2020, with a set fuel, CO2 [carbon dioxide] price, and capacity factor in each one. In reality, PACE’s analysis captures a wider planning horizon, where cost variables like these change over time. PACE’s risk analysis is intended to capture the uncertainty around such variables.

The 2012 assessment assumed $10/tonne CO2 price for all years, and the 2020 assessment assumed $25/tonne. In the actual screening analysis, the impact of year-to-year variations in carbon compliance was captured (shown in PACE Assumptions Document and other presentations given to Task Force).

The $25/tonne value is by 2020 in our forecast, which results in an approximately $21.5/MWh cost to the new coal plant and a closer to $25/MWh cost for existing units like FPP.

A: PACE did not explicitly include congestion costs in its levelized cost analysis, which was used for screening purposes and does not directly correspond with how things were analyzed with PACE’s dispatch tools. In PACE’s dispatch analysis, congestion was priced into the analysis by multiplying wind output by a projected congestion value per MWh. The screening analysis did this at an annual level, assuming all congestion charges were negligible beyond 2014, while the risk analysis quantified the congestion impact every hour throughout the study period by tracking differences in projected ERCOT South and ERCOT West clearing prices.

Additionally, PACE did not include ERCOT fees and costs for any generation sources in any of the scenarios [these are fees and costs that Austin Energy does include for GreenChoice®.] These are direct fees, such as the ERCOT Administration, Nodal and TRE fees and uplift charges. To both be fair to PACE and be accurate, with one exception these items are actually assessed to the load and aren't differentiated by generation type. They are rightly included in GreenChoice® because that is a substitute for the fuel charge where these items are applied for cost recovery. So, while these charges contribute to the ultimate cost one pays they don't matter in terms of comparing generation types.

There may be other "uncertainty" costs that will be associated with wind due to it's variability but that is arguably captured by PACE in their model. For example, if you have 1,000 MW of load and 1,000 MW of wind capacity how do you ensure your cost if something less than 1000 MW is produced? The answer of course is you buy "firm" power from the market in advance to lock in cost or take whatever the real time market has to offer while selling the wind production to the market. The net result from either option may be better or worse than the price you have for your wind power. You also have the same issue in reverse if for instance you have 1,000 MW of wind but only 500 MW of load. PACE essentially does this in their model and the results are generally favorable with their market assumptions.

A: The Task Force was provided a chart on September 2, 2009 that shows a range of total costs of generation for all current generation resources. Additional level of detail is considered confidential under the Austin Energy Competitive Matters resolution, Austin City Council Resolution 20051201-002.

A: Six percent represents a target goal for achieving peak demand savings through thermal cool storage. This number represents the percentage of Austin Energy’s peak MW [megawatt] demand reduction goal that is anticipated to be met by thermal energy storage. On an annual basis Austin Energy establishes targets for the various DSM programs and technologies. Installing thermal energy storage systems requires a significant financial commitment on the part of the customer, usually resulting in a Key Account customer adopting such a system. The system usually takes about 24 months to complete. Thermal energy storage has a 6 percent target for Austin Energy based on past experience.

A: Austin Energy’s 2008 DSM Performance Measures Report (provided in the Task Force information notebooks) provides greenhouse gas emission reductions and emissions reductions for several other pollutants, annual peak demand reduction (MW), and annual energy savings (MWh [megawatt-hour]) data for all of Austin Energy’s DSM programs for the 2008 fiscal year.

A: PACE presented estimates of capital costs and operations and maintenance costs for parabolic trough and tower CSP plants of 60 MW capacities. For trough plants, capital costs per kW ranged from near-term $4,373 per kW to a long-term $4,132 per kW. Fixed O&M [operation and maintenance] costs for trough plants were estimated at $30 per kW-year. For tower plants (also known as central receiver), capital costs ranged from $5,995 to $5,688 per kW and fixed O&M was also estimated at $30 per kW-year. The "levelized cost of energy for generation technologies" document that was compiled by Austin Energy and provided to the Task Force at the July 29, 2009 meeting provides cost estimates from various sources for different types of CSP plants.

A: We are aware of this concept but it is still at the conceptual stage like large scale storage. It would need to be considered at the time of any future central solar commitment.

A: Austin Energy does not typically run out of budget for its DSM programs, just cost-effective project proposals. Austin Energy’s budget for its DSM programs tracks customer participation on an annual basis. The one potential technology that Austin Energy has not been able to see more installations of is thermal cool storage. This technology has a current rebate cap of $200,000, and the potential for greater savings is there with thermal energy storage. Austin Energy knows of the greater potential savings of thermal energy storage in larger installations and it is considering going beyond the $200,000 rebate cap on this technology to achieve greater electric demand savings. It appears that the current barrier to seeing more thermal energy storage installations is payback requirements facing Austin Energy customers. Austin Energy’s criteria could potentially allow it to justify greater rebates for thermal energy storage.

A: Real dollars (in 2007 dollars.)

A: 2.5 percent discount rate was applied by PACE and this same rate was used for Austin Energy’s rate impact analysis

A: 57.4 percent

A: Austin Energy has used for its rate impact analysis natural gas cost estimates provided by PACE. The tables below were provided by PACE and show natural gas price projections through 2030 in real and nominal dollars. Natural gas projections by PACE, from 2009 through 2030 in 2007 dollars per MMBtu [thousand thousand British Thermal Units] and a discussion of those estimates are provided on pages 65-70 of the PACE Assumptions Document entitled "Assumptions and Market Drivers Document for Focused Integrated Resource Planning Analysis." The South Texas prices were used for Austin Energy’s analysis.

Year Henry Hub Houston East Texas South Texas West Texas Dallas Ft. Worth 2009 3.79 3.40 3.78 3.23 3.33 3.79 2010 5.00 4.74 4.92 4.64 4.69 5.00 2011 5.99 5.93 5.89 5.79 5.84 5.99 2012 6.31 6.39 6.17 6.26 6.31 6.31 2013 6.33 6.37 6.45 6.24 6.32 6.36 2014 6.82 6.87 6.94 6.73 6.80 6.85 2015 7.74 7.79 7.85 7.65 7.71 7.76 2016 8.31 8.36 8.38 8.22 8.25 8.29 2017 8.03 8.08 8.09 7.93 7.95 8.00 2018 7.46 7.52 7.49 7.37 7.35 7.40 2019 7.80 7.87 7.76 7.72 7.62 7.67 2020 8.77 8.84 8.70 8.69 8.57 8.62 2021 9.38 9.45 9.30 9.30 9.16 9.21 2022 9.16 9.24 9.06 9.08 8.93 8.98 2023 10.30 10.38 10.21 10.22 10.08 10.13 2024 10.65 10.73 10.56 10.57 10.42 10.47 2025 10.30 10.38 10.20 10.21 10.07 10.12 2026 10.53 10.60 10.43 10.44 10.29 10.34 2027 10.82 10.90 10.72 10.73 10.58 10.63 2028 11.01 11.09 10.92 10.93 10.78 10.83 2029 11.21 11.29 11.11 11.12 10.97 11.02 2030 11.40 11.48 11.31 11.32 11.17 11.22

Year Inflator Henry Hub Houston East Texas South Texas West Texas Dallas Ft. Worth 2009 1.051 3.98 3.57 3.97 3.39 3.50 3.98 2010 1.077 5.38 5.10 5.30 5.00 5.05 5.38 2011 1.104 6.61 6.54 6.50 6.39 6.45 6.61 2012 1.131 7.14 7.23 6.98 7.08 7.14 7.14 2013 1.160 7.34 7.39 7.48 7.24 7.33 7.37 2014 1.189 8.11 8.17 8.25 8.00 8.08 8.14 2015 1.218 9.43 9.49 9.56 9.32 9.39 9.45 2016 1.249 10.38 10.44 10.46 10.26 10.30 10.35 2017 1.280 10.28 10.34 10.35 10.15 10.18 10.24 2018 1.312 9.79 9.87 9.83 9.67 9.64 9.71 2019 1.345 10.49 10.58 10.44 10.38 10.25 10.31 2020 1.378 12.09 12.18 11.99 11.98 11.81 11.88 2021 1.413 13.25 13.35 13.14 13.14 12.94 13.01 2022 1.448 13.27 13.38 13.12 13.15 12.93 13.00 2023 1.484 15.29 15.41 15.16 15.17 14.96 15.04 2024 1.521 16.20 16.33 16.07 16.08 15.85 15.93 2025 1.560 16.06 16.19 15.91 15.92 15.70 15.78 2026 1.598 16.83 16.94 16.67 16.69 16.45 16.53 2027 1.638 17.73 17.86 17.56 17.58 17.33 17.42 2028 1.679 18.49 18.62 18.34 18.36 18.10 18.19 2029 1.721 19.30 19.43 19.12 19.14 18.88 18.97 2030 1.764 20.11 20.26 19.96 19.97 19.71 19.80

A: PACE cost projections are also used to generate the results provided in slide 20.

A: PACE cost projections are also used to generate the results provided in slide 20.

A: All cost factors are the same for both slides 13 and 20 of the Resource and Climate Protection Plan presentation. Fuel cost estimates are provided in PACE Assumptions Document. Austin Energy used its current fuel factor for 2009 in its rate impact analysis while PACE used a 2009 estimate. Construction costs are captured in capital cost estimates and levelized cost of electricity estimates provided by PACE. Based on PACE estimates for operations and maintenance costs.

A: Data previously provided by Austin Energy in various documents is referenced below. Where applicable, costs are represented in real dollars. To convert to nominal dollars an assumption of the discount rate would need to be made; 2.5 percent discount rate was applied by PACE and this same rate was used for Austin Energy’s rate impact analysis

a) For each generation plant (existing and new), for each year 2009 – 2020:

• Nameplate capacity (MW)
  A: This is provided on pages 13-14, Exhibits 8 and 9 of the PACE Assumptions Document as "capacity" for each generation facility and technology. These numbers remain constant throughout the planning period.

• Peak dispatchable capacity (MW)
  A: For conventional resources this would be the same as the nameplate capacity. For wind, Austin Energy uses an average peak capacity of 8.7 percent consistent with ERCOT [Electric Reliability Council of Texas] estimates and for solar of 50 percent. Wind and solar peak capacity will vary by day based on weather patterns and seasonal changes.

• Capacity factor (%)
  A: This level of detail is considered confidential. Capacity factors used in the LBJ [School of Public Affairs] model under the "Choose Your Generation Mix," Column O provide industry averages that are similar to Austin Energy’s current generation facilities. Projected capacity factors for Austin Energy’s renewable resource contracts are provided on page 14, Exhibit 9 of the PACE Assumptions Document as "capacity factor."

• Heat rate (mmBTU/MWh)
  A: This is provided on page 13, Exhibit 8 of the PACE Assumptions Document as "heat rate."

• Fuel cost ($/mmBTU)
  A: Fuel cost estimates for natural gas are provided above in detail in both real and nominal dollars. A discussion of fuel costs for natural gas, coal and nuclear is provided on pages 65-75 of the PACE Assumptions Document.

• Construction cost for year completed ($/kW)
  A: Total capital cost projections are provided by the PACE analysis. In the PACE presentations dated May 27, 2009 and June 29, 2009, capital costs are represented as new unit and existing unit fixed costs in slides that present the cost components of different scenarios. For existing units these costs are considered sunk costs and are therefore not relevant to the discussion of future potential capital costs.

• Total operating cost including cost of fuel, O&M, depreciation, debt service, incentives, carbon tax, etc. ($/kWh)
  A: Slide 50 of the PACE presentation dated May 27, 2009, shows levelized cost projections for 2012 and 2020 broken up by capital and fixed O&M costs (include debt service), variable O&M costs, fuel costs, and emission costs (carbon).

b) Provide each generation plant (existing and new):

• Estimated total life (yrs)
  A: PACE has been requested to estimate the estimated useful life for each type of generation technology. Most conventional generation units can last indefinitely if properly maintained, but may become non-competitive due to efficiency or other operating characteristics.

• Estimated remaining life (yrs)
  A: Existing facilities can continue to operate with capital investments to maintain and upgrade when necessary and appropriate. Retirement determinations are made when a better alternative is available relative to life extension. Various costs to consider include capital for a new unit, efficiency/heat rate, fuel cost, O&M, and environmental compliance.

• Levelized cost over total life including cost of fuel, O&M, depreciation, debt service, incentives, carbon tax, etc. ($/kWh)
  A: Slide 50 of the PACE presentation dated May 27, 2009 shows levelized cost projections for 2012 and 2020 broken up by capital and fixed O&M costs (include debt service), variable O&M costs, fuel costs, and emission costs (carbon).

c) For Austin Energy system for each year 2009 – 2020:

• Peak load (MW)
  A: This information is provided on page 8, Exhibit 3 of the PACE Assumptions Document with DSM. These projections were made prior to the Austin Energy staff recommendation of achieving an additional 100 MW of DSM savings.

• Peak load without DSM (MW)
  A: This information is included in the LBJ model under the tab entitled "Before You Begin."

• Nameplate capacity (MW)
  A: This is provided on pages 13-14, Exhibits 8 and 9 of the PACE Assumptions Document as "capacity" for each generation facility and technology. Total nameplate capacity and capacity additions are represented on various slides for different scenarios in the PACE presentations dated May 27, 2009 and June 29, 2009. Annual capacity additions by resource type through 2020 are provided as a separate document.

• Peak dispatchable capacity (MW)
  A: For conventional resources this would be the same as the nameplate capacity. For wind, AE uses an average peak capacity of 8.7% and for solar of 50 percent. Wind and solar peak capacity will vary by day based on weather patterns and seasonal changes.

• Weighted average capacity factor (%)
  A: This is not considered a useful industry metric due to the significant differences between unit types.

• Austin Energy generation (kWh)
  A: For generation to meet AE customer load, this information is provided on page 8, Exhibit 3 of the Pace Assumptions Document with DSM.

• Austin Energy customer consumption (kWh)
  A: See above answer. Annual generation for native load by generation type is presented for different scenarios in the PACE presentations dated May 27, 2009 and June 29, 2009.

• Austin Energy revenue ($)
  A: Revenue requirements are presented for different scenarios in the Pace presentations dated May 27, 2009 and June 29, 2009.

• Average cost of new power plant additions completed during the year ($/kW)
  A: Total capital cost projections are provided by the PACE analysis. In the PACE presentations dated May 27, 2009 and June 29, 2009, capital costs are represented as new unit and existing unit fixed costs in slides that present the cost components of different scenarios. A discussion of capital cost assumptions used by PACE are provided on pages 14-19 of the Pace Assumptions Document. Cost components of the staff recommendation are provided as a separate document.

• Planned budget for new DSM projects completed during the year ($/kW)
  A: Austin Energy has submitted its budget for rebates and the conservation program in general for the 2010 fiscal year. Austin Energy has not budgeted for future years and any projections would be estimates. In Karl Rábago’s [Vice President, Distributed Energy Services] presentation to the Task Force on the "Demand-side Resource" goals for kW and kWh demand and energy savings were provided. In order to reach these goals a $ per kW ceiling target of the cost of our next unit of avoided capacity is set. In the past, this has been set at the price of our next unit of CCGT [combined-cycle gas turbine] capacity – about $740 kW. That number will change over time – likely upward and at least at the rate of inflation. It is also possible that other technologies will become the next avoided unit of capacity – changing the "ceiling value."

• Inflation rate (%)
  A: PACE applied a 2.5 percent discount rate to its cost projections. Austin Energy assumes this same discount rate.

A: Steve Machicek [Director, Regulatory Affairs and Corporate Accounting, Austin Energy Finance] presented this information at the August 26, 2009 Task Force meeting in a presentation.

A: Austin Energy is working with PACE to determine a date to present its risk analysis findings to the Task Force. This will also provide an opportunity for Task Force members to ask questions to PACE about any other topics.

A: Utilities typically have a reserve margin above projected peaks. This is needed to address required operating reserves, e.g. spinning reserve, unplanned outages and load uncertainty.

A: Steve Machicek presented this information at the August 26, 2009 Task Force meeting.

A: This request is beyond the scope of the resource planning process as this would require a full rate analysis. The resource planning process is focused on the generation component of rates.

A: If full life cycle costs refer to impacts outside of the power sector, PACE has not accounted for that in their analysis, which is specific to costs of generation for Austin.  However, PACE did run their analysis through 2030 and has amortized all fixed costs over the expected lives of new projects.

A: Comparing the forecasts on the rate impacts of the biomass and solar projects with the PACE results is an apples and oranges comparison.  The Austin Energy forecasts were for the fuel charge only and represented a snapshot for that timeframe.  If recalculated today they would be different based on updated fuel cost projections – particularly for natural gas which has declined significantly over the past year. Additionally, the referenced impacts were stated (as noted in the presentations) for the year in which the given project first impacts the fuel charge, not through 2020. Since the projects begin in different years the estimates cannot be directly added for a total value.

The PACE results are an estimate of gross revenue requirement impact associated with each scenario, and as such cannot be directly compared to the fuel charge estimates of individual projects. The scenario revenue requirement estimate includes a fuel value for all resources in the scenario mix, but does not include rate differences among customer classes or other important costs of operations (e.g., transmission, distribution, G&A [general and administrative]) that could change in the future. This method of estimating gross revenue impact allows for a meaningful way to compare all the scenarios on the basis of common assumptions, but is not sufficient for estimating the ultimate impact on individual customer rates.

One should also keep in mind that many things have changed over the time that it has taken to conduct this process. Some of the factors that make direct comparisons difficult include that the earlier Austin Energy forecasts used older/higher load forecasts and the outlook for natural gas prices was higher in the older forecasts.

A: PACE’s results assume CO2 legislation will be imposed. A discussion of these impacts and projected carbon costs are provided on pages 53-57 of the PACE Assumptions Document entitled "Assumptions and Market Drivers Document for Focused Integrated Resource Planning Analysis." Therefore, the results for the Staff Recommendation would reflect these compliance cost estimates. FPP is able to reduce its capacity factor to 60 percent (of AE’s control) in 2020 due to increased wind in its generation mix. However, running FPP at a higher capacity factor and selling the remaining energy to the market could generate revenue for Austin Energy. If this were to occur, this would create a policy issue as Austin Energy would be generating revenue based on the selling of a resource that generates CO2. These issues are discussed in slides 32-35 of Austin Energy’s presentation entitled "Resource and Climate Protection Plan."

A: The original Waxman-Markey projections provided in the April presentation showed a requirement to lower CO2 emissions by 14 percent below 2005 levels, a reduction for Austin Energy to about 4,779,000 metric tons. At that time, there was some confusion as the goals of Waxman-Markey were changing as the legislation moved through committee to the House of Representatives. By May, the goal changed from a 20 percent reduction by 2020 below 2005 levels to a 17 percent reduction by May as legislation moved through Congress. The latest presentation from Austin Energy entitled "Resource and Climate Protection Plan" represents the requirements of the House approved version of Waxman-Markey (now in the Senate) which requires a 17 percent reduction in CO2 emissions below 2005 levels by 2020.

A: One would have to isolate the addition of a particular resource and the amount of that resource to determine the cost of reaching a 35 percent renewables goal by 2020 rather than 30 percent. Comparison of the costs of the Staff Recommendation to the Straw Man or other scenarios that only reach the 30 percent renewables goal provide an indication of the cost difference.

A: If and when carbon legislation is passed Austin Energy will re-evaluate its resource and climate protection plan with regards to such regulation. The plan envisions the need for reduced carbon emissions based on the likelihood of such regulation as well as Council’s direction to establish a carbon plan.

A: Austin Energy considered all scenarios analyzed by PACE consulting. There were three primary differences between the staff recommendation and the lowest bill impact meeting Council goals scenarios: 1) the inclusion of 200 MW addition of a combined cycle natural gas unit at Sand Hill, 2) the addition of geothermal and landfill gas in the lowest bill impact scenario and 3) the timing of solar resources.

Austin Energy decided to recommend the inclusion of the addition of a 200 MW combined cycle natural gas unit expansion at Sand Hill for several reasons that are expressed on slide 26 of Austin Energy’s "Resource and Climate Protection Plan" presentation. Austin Energy feels that the combined cycle unit will reduce natural gas fuel price risks as this unit will be more efficient than other natural gas units and it will reduce reliance on power market purchases.

The Lowest bill impact scenario included 50 MW of relatively cheap geothermal and 15 MW of relatively cheap landfill gas. Austin Energy is not confident that these resources will be available by that amount by 2020 at the costs estimated by PACE. If these resources are available at such cost by 2020 Austin Energy would consider those resources at the time they are available.

All solar deployment beyond the Webberville solar facility (70 MW) under the lowest bill impact scenario would be built out in 2020 under the Lowest bill impact scenario. Under AE’s staff recommendation solar is added incrementally in the final five years of the planning period (2016-2020).

A: This type of analysis is beyond the scope of Austin Energy’s resource planning process. This type of analysis would require many assumptions on societal costs.

A: Need to clarify billing demand and monthly kWh usage.

A: An annual rate change was input for each year.  In reality, the base portion of the rate change would not change annually. However, fuel does. The only factors causing increases or decreases in the base rate are PACE’s numbers for O&M, debt service, etc.  All scenarios assume Austin Energy owns future generation plants beyond the current agreements in place (Webberville and the biomass).

A: Austin Energy does not have any knowledge of the costs associated with this contract beyond what has been made publicly available.

A: Using current transmission rates a 100 MW reduction in 4CP (Austin Energy’s average load during the ERCOT one-hour peak of each summer month, i.e. "four month coincident peak") will reduce Austin Energy’s transmission charges by a little over $2 million. There is an offsetting reduction in base revenues, the magnitude of which is strictly speculative. The offsetting loss in energy sales will depend on a variety of factors including the type of DSM that resulted in that energy reduction (i.e. load shifting, peak clipping, etc.)

A: It is unclear at this point what, if any, effect the EPA finding would have on biomass plants. At this point, all it would do would be to bring carbon and certain other greenhouse gas (GHG) emissions under EPA jurisdiction under the Clean Air Act. Austin Energy does not know, and has no reason to believe, that the EPA would find that the proposed Nacogdoches biomass plant is not carbon neutral. Nor can Austin Energy speculate what restrictions the EPA would choose to place on biomass plants if it were to find them to be non-carbon neutral.

A: AE primarily reviewed the permit application to see if all Best Available Control Technology (BACT) and Prevention of Significant Deterioration (PSD) provisions were covered. From the CO₂ perspective, there was no language in any of the permits in regards to CO₂ so AE had nothing to review on that perspective.

Many reports have been released related to electricity generation from biomass and life-cycle emissions from such plants. A few of these reports are referenced below. The following is a link to a report by NREL [National Renewable Energy Laboratory] on life-cycle emissions for biomass: http://www.nrel.gov/docs/gen/fy99/25695.pdf

The following is a link to a report by the Energy Information Administration on biomass for electricity generation: http://www.eia.doe.gov/oiaf/analysispaper/biomass/pdf/biomass.pdf

The following is a link to a report on life-cycle emissions for different electric generation technologies, including biomass: http://www.parliament.uk/documents/upload/postpn268.pdf

In the Q&A document released by Austin Energy on this plant there is a reference to a NREL study that determined wood waste materials used at a biomass plant would result in a net 148 percent reduction in global warming gases (including the processing, collection and transportation of the waste material.)

The chapter in Volume II of the LBJ School of Public Affairs’ report on biomass also discusses in more detail the issue of direct emissions at a biomass plant vs. avoided emissions from natural waste decay used for the carbon accounting of biomass as a fuel source for generating power.

For information on the global warming potential for different greenhouse gases please see the information provided starting on page 210 of this report from the IPCC [Intergovernmental Panel on Climate Change]: http://ipcc-wg1.ucar.edu/wg1/Report/AR4WG1_Print_Ch02.pdf

A: Burning biomass is generally preferable to burning coal, especially if the biomass were to be left to decompose. The feedstocks for a biomass plant are likely to be wood waste and other materials that will decompose and ultimately return to the atmosphere. If the decomposition goes anaerobic, the result would be methane, at least 21 times more powerful a greenhouse gas as CO₂. There are production related emissions such as hauling, chipping, etc. There are also sustainability benefits to providing renewable energy wages and economic stimulus in the area.

The attached [located at http://www.austinsmartenergy.com] presentation to Council by Nacogdoches Power, LLC addresses this issue as well. Specifically, see slides 7-9. The environmental characteristics and emissions associated with this type of a biomass plant are also discussed in the document that was attached to this information request entitled "Nacogdoches Power GRU Proposal" on pages 17-19. The actual emission rates from the plant are redacted, indicating this is considered confidential information to the Gainesville Regional Utility.

A: The following webpage contains materials on the Nacogdoches biomass plant that AE has contracted to receive power from:

http://www.austinenergy.com/About%20Us/Company%20Profile/nacogdochesBiomassProposal.htm

AE’s information policy may differ from what the Gainesville Regional Utility’s information policy is. Florida law may also differ from Texas law in its requirements for information to be provided by electric utilities. The competitive climate Gainesville finds itself in may differ from that faced by AE. Austin’s policy is set forth by Austin City Council resolution, and the rationale for the prohibition on disclosure is contained therein.

A: Two models are used: 1) Electric Reliability Council of Texas (ERCOT) hourly dispatch model of Zonal market and 2) screening tool which is also an hourly dispatch model based on Austin Energy (AE) data that interacts with ERCOT model (provides more detail). This is a dynamic build-type model; not using an optimization mechanism. Model is representative of all plants in ERCOT system and expected new-builds. Able to do long-term runs and test out expansion plans and evaluate hourly clearing prices.

A: Uses broader model (screening tool) and uses a stochastic analysis by running a simulation with multiple iterations to look at different uncertainties. Power prices are outputs in the model. This is like a Monte Carlo simulation, but also looking at a few factors independently and evaluating the relationships between these factors (fuel costs, capital costs, and energy demand for AE and ERCOT). Assuming new resources are built in ERCOT and look at economics of new generic builds, there is a reference case for what is expected happen (changes by iteration for risk analysis).

A: Replace FPP is similar in costs to Straw Man because the avoided costs of operating FPP ($5/MWh), paying for its fuel ($20/MWh), and the cost of carbon ($25/MWh) is similar to an average cost of the renewables and purchased power used to replace FPP (combination used is described: 17 percent increase in purchased power, 18 percent increase in wind generation, 2 percent increase in solar and 3 percent increase in solar .replacement costs is about $70/MWh). While this is about a $5 difference from Straw Man, FPP is only 30 percent of generation replaced so final impact is about $1.50 increase per MWh (about 2% of generation costs).

Costs included in the comparison are markets costs of generation on the margin (typically natural gas), O&M, capital, fuel, operating equipment for emission reduction, and carbon. Does not include SO2 costs, but are minor for this comparative analysis. No value placed on costs of pollutants other than CO2 (but is included in risk analysis) or value of selling or leasing Fayette Power Project.

The model only projects the actual cost of generation by looking at costs of generation. This is not looking at all the actual total costs to customer. So this analysis is only a part of the overall rates to customer. Transmission, distribution and overhead costs are not included in this analysis.

The model does include carrying costs for debt and reserves, and does look at total costs for technologies. Looks at depreciation and capital left for current units.

PACE was not provided with Roger’s analysis on switching to natural gas above to evaluate.

A: Does not include same projected future potential transmission congestion costs (has transmission costs through 2012 and then assumes new transmission lines will eliminate these costs) as AE had for that pricing plan (but will look at risks of wind costs in risk analysis). The contract cost is actually about $57 which is similar to what PACE gets.

A: Did look at availability of geothermal in region and this number (50 MW) is about 10 percent of available geothermal for Texas, which is about the percent of wind that is attributed to AE. DSM projections are based on supply curve for DSM provided by AE.

A: The "levelized NPV" costs are an average (levelized, flat rate) year-to-year change in real dollars per MWh from 2009 to 2020 and the "increased costs" is the total rate of change in real dollars from 2009-2020.

Costs being increased are for AE, not customers, for just the cost of generation. Embedded capital and debt service is considered in cost of generation. Amortize costs for new builds. Use a levelized repayment costs. If there was a value for FPP the impacts on cost of generation could be easily calculated by this model.

A: As far as I know the only environmental impact that PACE has looked at to date is CO2 emissions.  They may be looking at other environmental impacts such as water use in the risk analysis.

Costs for emissions equipment are included (scrubber costs). Carbon dioxide is, but NOx and SOx are not (but are looked at in risk analysis) [while] other pollutants are not looked at directly. Water use is not included.

A: Not in current scenarios but will look at for NOx and SOx in risk analysis.

A: The 700 MW of demand savings are included in AE’s load forecast. For additional DSM (which is included in some of the scenarios that have been run) this is an efficiency supply curve assumption (so the amount of additional DSM that is provided is peak demand savings i.e. for 14 MW of DSM this means at peak 14 MW of demand savings are achieved, but the "capacity factor" of DSM is much lower. [DSM] is based on supply curve assumption provided by AE, which is included in documents provided by PACE for assumptions of model.

A: Practical limit is driven by economics. Model has determined that beyond 800 MW is not economically viable relative to other models. Not doing a risk analysis on this directly, but can be inferred from risk analysis on load uncertainty.

A: PACE does have experts in this field, but defer to AE’s perspective rather than PACE’s expert opinions or knowledge.

A: Not difficult to run, but would have to make assumptions on costs of shutting down as well as value for selling at a particular time. PACE is [sic] only provided impacts on cost of generation, not costs on rates to customers.

A: AE Staff: I will defer to PACE to clarify this but it appears that the baseline for the percentage change is contract cancellations assuming that AE could cancel its recently signed renewable contracts, i.e. biomass plant and solar plant at Webberville. Reference point is assumption that renewable contracts (wind, solar and biomass) were not in place. The increased costs shown are for power market prices, transmission congestion costs (modeled independently, but consulted with AE) and carbon dioxide costs.

A: AE Staff: It is my impression that these numbers only represent the cost of generation, not overhead costs for the utility; are you asking for the specific numbers that are represented in this chart? I do not think that PACE has the information to show annual total utility costs (costs to customers) but we can bring this up PACE: The issue of total costs will be handled by AE. Energy production would be load served which is provided in the PACE assumptions document (for peak demand).

A: AE Staff: I believe it is assumed that AE owns all future units, but current PPAs reflect the terms of the contracts, PACE should confirm this. PACE: PPAs are represented for current [generation] fleet as necessary but future added generation is assumed to be AE owned other than the scenario with the nuclear PPA. AE would not be eligible for tax credits as [a] municipal utility, but if AE’s ownership were not assumed tax credits would be available.

A: AE Staff: The only difference from the Straw Man is 300 MW of rooftop solar (beyond the 100 MW of remote solar, i.e. centralized solar (Photovoltaic) PV owned by the utility.) For the 300 MW of solar it is assumed that 75 is owned by [the] utility and 25 percent owned by customers.

PACE: The above answer is accurate.

A: This would be something that could be analyzed as a spreadsheet exercise.

A: It would take about two to three weeks to get the full risk analysis results for a new scenario. Reason is the number of iterations that must be run. It would take less time to simply run the screening analysis.

A: Six portfolios will initially be run for risk analysis: 1) original Straw Man proposal, 2) no additional generation, 3) lowest cost impact meeting Council goals, 4) replace FPP with renewables, 5) replace FPP with nuclear, and 6) staff recommendation when it is released.

Develop uncertainty distributions for fuel costs, capital costs, and energy demand for AE and ERCOT as a whole. The core of that analysis has been completed and they are working on summarizing and organizing results. Have yet to determine the timing of releasing these results to the public. Explanation is provided on how risk analysis will be presented. Reliability is not a risk they are looking at until AE indicates there will be a significant difference among scenarios.

Fuel Source Energy Generated (MWh) % of Energy Generated Natural Gas:   3,426,251 25.9% Coal:   4,414,838 33.4% Nuclear:   3,605,772 27.3% Purchase Power:   1,763,369 13.3% Total:   13,210,230 100.0%

Retail Energy Sales FY2008 Service Area Sales 12,184,239,834

A: Off-system energy sales are confidential

A: AE retail load.

A: Purchased Power is "conventional" non-renewable power purchases.

A: EUC report is fiscal year whereas the fuel charge is calculated on a calendar year basis. EUC report excludes hedging and ERCOT charges whereas the Fuel Charge includes those items.

A: In process of compiling information for calendar year 2008.

A: In process of compiling information for calendar year 2008.

A: In process of compiling information for calendar year 2008.

A: No.

A: The impact from hedging natural gas is not included in the Fuel Expenditures table; however, the impact is included in the fuel factor calculation. The impact generally includes gains or losses from hedging as well as any related premiums.

A: Figure 25 was intended to illustrate relative use and availability rather than a strict technical definition of capacity factors. The difference between the two is greatest for intermittent resources and natural gas units, particularly simple cycle peaking units. For example, on an industry wide basis simple cycle gas turbines typically have capacity factors in the 10-20 percent range with availability of 90+percent. Actual capacity factors for this type of unit will vary significantly by utility depending on their resource mix. AE’s individual capacity factors are confidential, however, as we have noted in resource plan presentations AE’s average capacity factor for all simple cycle units is about 10 percent while the newer Sand Hill units in that group average about 15 percent.

A:This information can be obtained by referring to other presentation documents on this web site, i.e. the PACE Analysis and others.

A: AE uses a statistically adjusted end-use (SAE) model that is updated yearly to account for any changes in local trends as well as trends within the energy market. SAE modeling is an econometric modeling approach that allows for a multitude of factors to be taken into account to determine future energy demand. This type of modeling technique focuses on the end-uses of electricity and the reasons for consuming electricity over a given period of time. Historic billing data, weather patterns, and future projections of demographic changes within the AE customer base area are some of the many factors utilized to make future projections of energy demand. Regression modeling is used within the model to break future demand into residential, commercial, and industrial customer classes. Future reductions in demand through demand-side management (DSM) are also incorporated into the model. Projections of the impact of DSM programs assume that customers will continue to enroll in AE’s current and future DSM programs, more efficient technologies will continue to emerge, and building code standards will continue to be enhanced and adopted by Austin’s City Council.

Additional information on AE’s load forecasting is included in Chapter 5 of Volume II of the LBJ School of Public Affairs report. Further details are confidential.