CITY OF TALLAHASSEE
CITY COMMISSION AGENDA ITEM
ACTION REQUESTED ON: May 20, 2009
SUBJECT/TITLE: Update of Energy Resource Plan and Related Issues
TARGET ISSUE: Environmental and Energy Resources

STATEMENT OF ISSUE

The electric utility industry is in a period of significant transition. This transition includes generation, transmission and distribution technology, energy efficiency, environmental policy and reliability. The City of Tallahassee owns and operates one of the largest public power utilities in the United States and is impacted by all of these industry issues. This agenda item provides an overview of recent trends in demand and energy consumption, current energy and demand forecasts, current power supply resources and related energy issues for the City of Tallahassee. Those related issues include (i) the Demand Side Management (DSM) Program, (ii) renewable power supply resources, (iii) climate change, (iv) power supply diversity options, (v) electric transmission issues and (vi) electric reliability regulation and compliance.

RECOMMENDED ACTION

No recommendations. This item is provided as information and to seek Commission guidance related to the DSM program and alternatives to further investigate power supply diversity.

FISCAL IMPACT

Not Applicable

Kevin G. Wailes, General Manager – Electric Utility

Anita Favors Thompson, City Manager

For information, please contact: Kevin G. Wailes, Electric Utility, x5532

SUPPLEMENTAL MATERIAL/ISSUE ANALYSIS
HISTORY/FACTS & ISSUES

Recent Electric Demand and Energy Consumption

The Electric Utility has experienced reduced sales of electric energy to retail customers in the most recent two fiscal years, while still increasing the number of customers served. FY2007 sales were 1.1% less than FY2006 sales and FY2008 sales were 1.2% less than FY2007. Sales for the first 6 months of FY2009 were 1.4% less than the comparable period in FY2008. Correspondingly, the City has experienced a 7.9% reduction in average monthly residential customer electric energy consumption from 1014 KWH in 2006 to 934 KWH in 2008. The DSM, economy, and energy prices have resulted in the reduction in sales.

Electric Demand and Energy Forecast
As part of the normal forecast process, staff reviews the actual demand and energy results versus the prior year forecast to determine if adjustments need to be made to the model. Based on this analysis of the 2008 results, the load and energy forecast model coefficients were updated. From these updates the 2009 base forecasts were generated. Further, sensitivity forecasts were produced to address uncertainty with respect to population and economic variables from the values assumed in the base. These high and low forecasts are intended to capture approximately 80% of possible forecast outcomes (i.e., 1.3 standard deviations).
The resulting 2009 base forecasts (not including DSM) reflect reductions in expected seasonal peak demand and annual energy requirements versus the corresponding 2008 forecasts. For the purposes of comparison, the year 2018 is used because it is the “horizon year” for the 2009 Ten Year Site Plan (TYSP). There are multiple factors contributing to these reductions but most notably changes in forecasts for Leon County population (e.g. -5.6% vs. 2008 forecast year 2018), incremental additions at FAMU (-68.2%) and per capita residential taxable sales (-20.8%). As a result of model and variable factor updates, the 2009 base forecasts for summer peak demand, winter peak demand and annual energy sales are below the corresponding 2008 forecasts in the TYSP horizon year of 2018 by 5.0%, 8.1% and 6.4%, respectively.

Demand-Side Management
The City’s electric resource plan includes a significant contribution from demand-side management (DSM) programs. This contribution was originally projected as part of the integrated resource planning (IRP) study completed in 2007. Since that time the Electric Utility has worked with its consultant to refine and update estimates of DSM program impacts, costs and market penetration. This work was not completed in time for the new information to be reviewed and approved so that it could be included in the 2009 TYSP report. Therefore, the DSM program impacts reflected in the 2009 TYSP are the same as those included in the 2008 TYSP. However, the City has received the updated potential DSM impacts and is in the process of reviewing the data, including estimated costs of deployment to attain the updated level. As a result of the updated information, the potential demand and energy impacts of the DSM program have increased in the TYSP horizon year of 2018 by 12% and 37%, respectively. The following table is a preliminary comparison of the updated DSM program impact to those previously used in the IRP process.

*Values not reported in 2009 Ten Year Site Plan. Revised DSM estimates have not received final review and acceptance by staff at time of this report.

A key part of the ongoing resource planning process will be to continually monitor, verify and, where necessary, refine projections of the costs and impacts of the City’s DSM efforts on the future seasonal peak demand and annual energy requirements. Based on the updated projections of DSM program impacts and costs, and as experience is gained with DSM implementation, adjustments to the City’s resource plan may be required to maintain reliability at the lowest possible cost to our customers. In essence, given the current trends of reduced consumption over the past two and one-half years, it appears that continued deployment of the existing Energy Smart Plus program may not require the high level of financial incentives originally planned, to achieve the goals of the original DSM program. Although this will still require constant review, it will likely result in a much more cost-effective DSM program than originally designed.
The following Charts compare the 2008 and 2009 forecasts with and without DSM impacts.

Power Supply Resources
The Hopkins Unit 2 combined cycle repowering project was completed in 2008, adding 72 MW of net summer capacity to the Hopkins Plant. Because generation from the C. H. Corn hydroelectric facility is intermittent (dependent upon rainfall, reservoir and downstream conditions), effective with the 2009 TYSP these generating units are considered "energy only" and not dependable capacity resources. With these generation fleet changes and including the 11 MW purchased power agreement (PPA) with Progress Energy Florida, the City’s total current net summer power supply is 805 MW.

As a result of reductions in the load and energy forecasts, more current information regarding the development progress of the Biomass, Gas & Electric (BG&E) and Green Power Systems/Renewable Fuels Tallahassee (GPS/RFT) facilities and uncertainty regarding related regulatory requirements, updates were made to existing and future power supply resources.

After facing public opposition during their permitting process, BG&E chose to abandon its preferred site for their facility and is seeking an alternative site. Given the uncertainty associated with the facility’s siting, the City does not report any capacity or energy purchased under the BG&E PPA in the current resource plan.

Permitting activities for the GPS/RFT project have not yet begun. Based on the project’s progress to date, the Electric Utility has assumed a more conservative in-service date of June 1, 2013 for the GPS/RFT facility.

Because the BG&E and GPS/RFT facilities both employ emerging technologies, the City has considered the respective PPAs as “energy only” and not dependable capacity resources until the facilities’ reliable performance has been demonstrated for a sufficient period. So, while not a concern related to power supply, the delayed progress of BG&E and GPS/RFT increase the likelihood that the City may have to seek new resources to comply with renewable portfolio standards (RPS) under development at the State and Federal level.

Based on the 2009 base forecast adjusted for expected DSM impacts and absent any power supply resource additions, the City would face a reserve shortfall in 2016 due to the retirement of Hopkins Unit 1 (76 MW). Given the uncertainty associated with the forecasts, DSM impacts, the renewable PPAs and RPS, staff reviewed the costs of delaying the retirement of Hopkins Unit 1 by three years. Based on that review, staff determined that it would not require significant additional capital or operating expenditures to defer the retirement of Hopkins Unit 1 and has revised the retirement date.

Attachment A compares the first ten years of the 2008 and 2009 forecasts and associated resource plans.

Renewable Resources
It is likely that sometime in the next few years, electric utilities will be required to comply with climate change regulations such as a cap-and-trade program or carbon fee. Even though there is a great deal of uncertainty regarding what form and when the regulation will be effective, the threat of potential regulation has forced electric utilities to think differently about future resources. (For example, coal plants have been cancelled and biomass plants proposed.)

There are a number of initiatives at both the Federal and State level to implement some type of “Renewable Portfolio Standard” (RPS) or “Clean Portfolio Standard” (CPS). All of the various proposals would require utilities to supply a certain percentage of their energy from renewable or clean power resources by certain dates. The predominant differences in the proposals are the level of the goals, the dates for compliance, and what is included as an acceptable resource to count toward that goal. For example, some of the proposals would allow conservation, energy efficiency, and nuclear power to meet some portion of the goal. The primary issues that have impacted the legislative and regulatory consideration of these proposals are the ultimate cost to the customer and the availability of resources to meet the goals, including regional differences. Most of the proposals include goals ranging from 15% to 20% by 2020, with some higher and lower.

Florida Senate Bill No. SB1154 was proposed this year to establish a “Clean Portfolio Standard” for investor-owned utilities (IOUs) in Florida. Although the bill did not pass, it is instructive to look at the impacts it would have had on the IOUs, and also how the City might comply with other proposals that are under discussion. Attachment B provides additional details and analysis.

Climate Change

· Status of legislation: There are a number of initiatives at both the Federal and State level to implement some type of climate change regulation or legislation. Pursuant to Governor Crist's Executive Order 07-127 and the 2008 Florida Energy Bill (HB 7135), a cap-and-trade program for greenhouse gases (GHG) is being formulated at the state level with a proposed rule expected by January 2010. The proposed cap-and-trade program is still in its earliest stages of development with ongoing discussions about joining a regional program or developing a Florida-only program. However, there remains a strong preference by the State and regulated entities to participate in a national cap-and-trade program. On May 19, 2009, the Florida Department of Environmental Protection (FDEP) will hold another rulemaking workshop to discuss possible aspects of a regulatory program. In particular, FDEP will take comments on allocation methods for carbon dioxide (CO2) allowances (e.g., auction, free allocation, or combination of both). No proposed regulatory language will be presented at this FDEP workshop.

At the federal level, cap-and-trade programs are also on the forefront of climate change legislation, as the expected economic returns on such programs provide attractive options for correcting expected budget shortfalls. The Waxman-Markey draft, "The American Clean Energy and Security Act of 2009" is being promoted as comprehensive energy legislation that will create millions of new clean energy jobs, enhance America's energy independence and cut global warming pollution. This draft legislation would require reduction of GHG emissions in phases, starting in 2012 and achieving an 83% reduction below 2005 levels by 2050. The legislation would also provide that CO2 and other GHG's not be regulated under the Clean Air Act, but instead would be regulated and reduced through a cap-and-trade program. The legislation also promotes energy efficiency programs and new technologies such as carbon capture and sequestration.

· Tallahassee Electric Utility CO2 Data: The City has implemented a number of generating fleet improvements over the last 10 years that have significantly improved the efficiency and environmental profile of the fleet. In 2008, the City emitted 10% less CO2 to serve retail customers than in 1990 (in total tons), even though load has increased by 49%. 1990 emissions have historically been used as a benchmark for CO2 reductions, but, as noted above, some recent proposals refer to 2005. The City’s 2008 CO2 emissions to serve retail load were also 20% lower than 2005. While this is a notable accomplishment, the City’s compliance with these goals is dependent on the rules that are established for inventory and benchmarking the CO2 emissions. In addition, the City has made the majority of the improvements possible to its generating fleet to reduce the CO2 emissions, so further improvements will predominantly be through conservation or renewable resources. While it is impossible to determine the ultimate cost of Climate Change regulation, the costs per ton that have been discussed in recent reports range from $10 per ton to $80 per ton. The City’s emissions to serve retail load in 2008 were approximately 1.4 million tons. Based on a range of $10 to $80 per ton, it would increase annual production costs by $14 million to $112 million. That amount equates to a fuel cost increase of approximately 7% to 56% based on forecasted fuel expenditures in 2010.

· Carbon Offsets: A cap-and-trade program for carbon dioxide (CO2) emissions from electric utilities appears likely. However, whether Florida will adopt its own program or participate in a regional or national program still remains to be seen. Greenhouse gas (GHG) offsets are GHG emissions reduction or sequestration that occur outside of the capped sector (e.g., outside of the electric utility sector). To qualify as an offset, the GHG emissions reduction/sequestration generally must be real (represent actual reductions), additional (cannot count reductions required by a regulatory program or that would have occurred anyway in the absence of a program), verifiable, enforceable, and permanent. In addition, most cap-and-trade proposals place constraints on the types of acceptable GHG emission reduction/sequestration projects and the total quantity of GHG offsets that may be used to satisfy a source's compliance obligations. For example the ten state Regional Greenhouse Gas Initiative (RGGI) program only allows a small portion (initially 3.3 percent) of a source's total compliance obligation to be satisfied by CO2 offsets. Some potential offset projects for the City of Tallahassee may include such things as tree planting, land preservation, methane capture at the wastewater treatment facilities, growing new crops at the Southeast Farm Spray Field, and converting fleet vehicles and buses to compressed natural gas. However, the ability to use any of the above described projects towards carbon offsets will ultimately depend on the specific requirements of the cap-and-trade program to be developed.

· Community Forums: The City Commission expressed the desire to establish an ongoing community dialogue and solicit feedback and input regarding customers’ interest in further reducing the City’s carbon footprint, including its potential impact on utility rates. The Environmental Policy and Energy Resources and Communications departments will coordinate and provide a draft schedule, including a proposed panel with the first meeting to be held in September 2009.

· Chicago Climate Exchange (CCX): Staff is investigating the merits of becoming a member of the CCX. The Chicago Climate Exchange® (CCX), launched in 2003, identifies itself as North America’s only active nation-wide, voluntary, legally binding integrated trading system to reduce emissions of all six major greenhouse gases (GHGs), with offset projects worldwide. CCX Members are leaders in GHG management and represent all sectors of the global economy, as well as public sector innovators. Reductions achieved through CCX are the only reductions made in North America through a legally binding compliance regime, providing independent, third party verification by the Financial Industry Regulatory Authority (FINRA, formerly NASD). CCX is a cap-and-trade system whose members make a legally binding emission reduction commitment. Members are allocated annual emission allowances in accordance with their emissions Baseline and the CCX Emission Reduction Schedule. Members who reduce beyond their targets have surplus allowances to sell or bank; those who do not meet the targets must comply by purchasing CCX Carbon Financial Instrument® (CFI™) contracts. Benefits to the City may include recognition/credit for early action and potential net revenue from sale of CO2 allowances.

Electric Transmission Issues:
As discussed in the past, in general the transmission grid in northwest Florida is electrically weak compared with other areas of the state (or south Georgia). The City’s 230kV transmission line to Bainbridge, Georgia and its interconnection with Progress Energy near Crawfordville represent the strongest links in the area, and therefore provide a key pathway for power flow to loads in the region as well as facilitating the transfer of power through the region to loads in central and south Florida.

The combination of thermal line ratings and transfer limits based on contingency analysis effectively constrain the amount of power that can flow into, across, and out of northwest Florida. The reality of this limitation affects the City’s ability to access the power markets and to maintain system reliability; it also shapes the type of alternatives the City can reasonably consider to address future needs. Due to the configuration of the regional grid, any transmission expansion projects to significantly address the City’s power transfer capabilities would need to reach strong connection points well outside the NW Florida region, further complicating the scope of these projects.

In an attempt to determine the value of expanding transmission infrastructure in the context of the last Integrated Resource Planning (IRP) Study, the City engaged R.W. Beck, Inc. (Beck) to assess the economics of representative transmission projects to determine if the investment in transmission facilities could be recovered through improved access to the power market. Based on an analysis concluded by Beck in 2006, the cost of investment in transmission required to improve the City’s market access would not offset savings from purchased power transactions.

The Electric Utility continues to investigate alternatives to maintain or expand the City’s import/export capability consistent with North American Electric Reliability Corporation (NERC)/ Florida Reliability Coordinating Council (FRCC) requirements and applicable agreements among the owners of transmission facilities at the Florida-Georgia border. One of the alternatives under review is adding local generation to release a portion of the Available Transmission Capacity (ATC) reserved for reliability purposes, effectively increasing the amount of import capability that could be used for access to the power market. In addition to grid studies, staff is also conducting internal transmission system studies intended to identify improvements necessary to ensure system reliability.

More detail is included as Attachment C - Update on Electric Utility Transmission Planning Issues & Strategies.

Power Supply Diversity Alternatives:
The Tallahassee City Council voted to establish an electric utility in 1899, which would directly compete with the Capital City Light and Fuel Company, providers of gas lighting to Tallahassee. The Council declared it, “…expedient for the City of Tallahassee to exercise the authority to establish and maintain an Electric Plant for municipal use and for the use of its inhabitants.” After a lengthy legal battle that was ultimately decided by the U.S. Supreme Court, the City was able to construct its first 100-kilowatt power plant, which supplied lighting along the length of Monroe Street and provided for connection to businesses lining the street.

For most of its 107 years, the City has operated a vertically integrated electric utility providing distribution, transmission and generation service. However, four times in history, the ownership and operation of generation facilities has been reevaluated, and for a period of 23 years, ending in 1952, the City leased its generation facilities to another utility and purchased 100 percent of its power generation needs. Today, the City is one of nine vertically integrated utilities with system generation in the State of Florida.

Volatile natural gas prices have prompted the City to explore alternatives again, with a goal of managing the impact of fuel price volatility and its effect on electric retail rates. In October 2008, the Financial Viability Committee comprised of Commissioners Mustian and Katz directed staff to explore the feasibility of selling the City’s electric generation assets. While a sale of generation assets does not appear to be a viable alternative at this time, staff has identified several other potential options to consider that may address power supply resource diversity. A brief history and summary of options is included in Attachment D to this Item.

Staff is seeking Commission direction to explore options to address fuel price volatility.

NERC Reliability Standards
NERC, the North American Electric Reliability Corporation, is an international, independent, self-regulatory, not-for-profit organization, whose mission is to ensure the reliability of the bulk power system in North America. NERC’s enforcement authority is established through its role as the Electric Reliability Organization (ERO) as selected by the Federal Energy Regulatory Commission (FERC) pursuant to the 2005 Energy Policy Act. One of NERC’s statutory roles is to conduct periodic, independent assessments of the reliability and adequacy of the bulk power system based on requirements set out in mandatory Reliability Standards. Reliability Standards are the planning and operating rules that electric utilities must follow to ensure the most reliable system possible. NERC has the legal authority to enforce compliance with NERC Reliability Standards, which it achieves through monitoring, audits and investigations, and the imposition of financial penalties and other enforcement actions for non-compliance. NERC has the ability to impose fines up to $1,000,000 per day for violations deemed to have high risk to the reliability of the grid.

In June 2007, 83 Reliability Standards consisting of over 1,000 individual requirements became mandatory and enforceable within the NERC regions with associated financial penalties. More standards (an additional 355 requirements) are pending approval at the FERC. Like most other utilities in the country, at the time the standards were implemented the City self-reported violations of parts of some standards (all were minor and most involved incomplete documentation of compliance), and staff has developed mitigation plans to bring the operating and planning practices of the electric utility in line with these new mandatory standards.

Compliance monitoring has now become the single largest effort by many utilities to ensure reliability. FERC and NERC emphasis on comprehensive review of mandatory standards requires utilities to focus substantial effort on tracking, documenting, training and evaluating performance against these standards. In most cases, this effort is in addition to the staff’s current responsibilities, which in turn will lead to the need to either augment staff or outsource tasks related to compliance.

Recently, the FERC issued a statement in the context of determining appropriate penalties for non-compliance regarding what it considered the key factors that should be part of an effective compliance program. These factors are: (1) the role of senior management in fostering compliance; (2) effective preventive measures to ensure compliance; (3) prompt detection, cessation, and reporting of violations; and (4) remediation efforts. The City has been working to develop a comprehensive compliance strategy that addresses these factors as part of preparations for a NERC compliance audit scheduled for November 2009.

CHARITABLE CONTRIBUTIONS

Not applicable

OPTIONS

Not applicable

FISCAL IMPACT

Not applicable

ATTACHMENTS/REFERENCES

Attachment A - Summary of Changes - 2008 vs. 2009 Forecasts, DSM and Resource Plans
Attachment B - Summary of Legislative Proposal – Bill No. SB 1154
Attachment C - Update on Electric Utility Transmission Planning Issues & Strategies
Attachment D - City of Tallahassee Electric Generation