ISO-NE details 2011 expenses, projects

ISO New England on May 18 said it has issued its financial report for the year 2011, which includes a summary of ISO’s 2011 operations, its financial position and financial statements.

In 2011, ISO’s total expenses were $139.6m, compared to $128.1m in 2010. This represents an $11.5m, or 9.0%, increase over 2010. Expenses net of depreciation, amortization, and interest increased $9.3m, or 8.9%, in 2011 over 2010.

ISO-NE also said that the FERC‐approved capital expenditure budget for 2011 was $26.5m, while actual spending was under budget by about $1.82m, primarily as a result of delays in the design and approval for the Forward Capacity Market reform and price‐responsive demand projects. These projects are expected to span into 2012 and beyond. A number of other smaller dollar changes have occurred in 2011 capital spending, ISO-NE said in its report.

According to ISO-NE, major projects in 2011, some of which are ongoing and multiyear, include:

Standard Market Design Upgrade Phase III: Phase III will upgrade the framework of the eMarket and eFTR user interface. The market operator interface also will be enhanced to allow control room operators to send manual dispatch instructions directly to generators, via remote terminal units, when the market system is unavailable.

Business Continuity Plan Infrastructure Enhancements Phase II: The project was the second of three stages of an initiative that began in 2008 to update the ISO’s infrastructure to enhance business continuity. Phase II included synchronization of the master control center and backup control center networks and the creation of a locationally independent web presence, such that external web applications may be available at the BCC independent of other ISO functions.

The total project costs were about $2.44m and the project was completed in November 2011.

Synchrophasor Infrastructure and Data Utilization: The ISO and the New England transmission owners received a grant, in conjunction with their application under a U.S. Department of Energy Funding Opportunity Announcement for Smart Grid Investment Grant, to focus on bulk power system operations associated with the installation of phasor measurement units.

The company is eligible to receive reimbursement of about $7.9m, or up to 50% of the total project costs, which were initially estimated at about $18.1m. The project cost may total less than the about $18.1m based on a revision to the budget; however, the scope of the project will remain the same. The ISO and the transmission owners will incur the 50% of the costs that DOE does not reimburse.

The ISO’s 2012 capital budget for this project is $1.6m. The ISO expects to receive 50% reimbursement from the DOE, resulting in a net spend for the ISO of $4.8m, of which $4.1m is expected to be for capital expenditures. The remaining project costs will be borne by the participating transmission owners and are not included in the ISO’s capital costs. The project is expected to be complete in the second quarter of 2013.

Energy Management System (EMS) Upgrade and Enhancements: The project will upgrade the hardware and software for the existing EMS 2.3 and Habitat 5.6 platforms, communication front-end of the EMS, and testing and training simulator environment system to the EMP 2.6 and Habitat 5.8 platforms to stay current with supported versions.

The project allows the ISO to take full advantage of the latest product features and will simplify and reduce the cost of future upgrades. The project will ultimately enhance the reliability of system operation. The estimated total cost for this project is about $4.1m. The targeted completion date for the project is October 2012.

Web Enhancements Phase I: The project will address the recommendations resulting from the 2010 Information Delivery Operational Excellence initiative. The project encompasses several improvements to the ISO’s external website that will add a significant increase in external user functionality, ease maintenance of the website, and improve the reliability of the website.

The focus of this project is on the real-time operational data used on a daily basis to make business decisions. The primary scope of the project consists of the design and development of XML operational data feeds, and the implementation of a new portal solution that is flexible and easily maintainable. The estimated total cost for this project is $1,974,000. The targeted completion date for this project is May 2012.

Market Mitigation Automation: The project will convert a very manual, time‐intensive process and integrate mitigation into the real-time dispatch process. Currently, the Internal Market Monitor has the ability to mitigate the marginal unit (i.e., the unit setting the price) one unit at a time only as they sequentially set the price.

The implementation of the automated process also will provide full compliance with the tariff in calculating the price impacts as outlined in Market Rule 1, Section III, Appendix A III.A.5.5.3. The automated process will provide the necessary precision in determining market impact and will result in identifying not just the marginal unit, as in the current manual process, but all resources within—for example, a constrained area that is affecting market outcomes result of its supply‐offer conduct.

Additionally, the rule‐based logic of automated mitigation will remove any perception of discretion from the market‐impact testing and mitigation process. The total estimated project cost is $2,220,000, and the targeted completion date is May 2012.

Generation Control Application (GCA) Phase I: The project, which was launched in 2010, and placed in  service in January 2012, developed a look‐ahead commitment and scheduling capability in a study mode within the existing real‐time unit‐dispatch system, thereby forming the basis for a real‐time  dispatch mode with look‐ahead functionality.

The capability is improving accuracy and optimality of the fast‐start commitment/decommitment logic, the analysis of intra‐day power system trends, the management of system uncertainty and commitment and dispatch instruction, external transaction scheduling, and the analysis tool for supporting operation decisions. The project addresses increased real‐time dispatch and scheduling challenges, especially in the emerging area of the smart grid. The total cost for this project was $1.6m.

Software Development Costs: In addition to the major projects described above, the ISO incurred $1.8m in software development costs. These costs supported a multitude of enhancements to existing software systems.

Further, ISO-NE said that its aggregate customer base has decreased year-to-year, with 460 customers in 2011, down from 479 customers in 2010. The ISO’s customers include generators, suppliers, publicly owned entities, transmission owners, demand‐response resources, alternative resources, and end users.

The cash cleared in 2011 was $5.8bn, compared with $6.8bn in 2010, which is a decrease of about 15%. Energy market transactions that cleared through the ISO decreased about 8% from 2010 to 2011. In addition, the all‐in energy market cost decreased 6%, and average natural gas prices decreased by about 5%. All these measures are key indicators of the cash that clears through the ISO, according to the ISO’s report.

2012 Outlook

According to ISO, projects and initiatives for 2012 will encompass three major strategic areas: planning and operations, wholesale markets, and, capital project plans. The strategic planning process has identified the following near‐term challenges: the retirement of uneconomic capacity, the dependence of power system operations on natural gas system infrastructure, and the performance and flexibility of current power system resources.

Major projects and initiatives the ISO will undertake in 2012 that incorporate all the strategic areas of focus are described in the ISO’s 2012 Wholesale Markets Project Plan and Roadmap for New England: A Proposal for Meeting the Challenges Identified in the Strategic Planning Initiative.

Federal lawmakers continue to consider energy policies that will have an impact on the ISO, including those that address incentives for renewable and alternative energy sources, the domestic production of oil and gas resources and strengthened cyber security laws, ISO noted.

The U.S. Environmental Protection Agency has issued a final rule limiting mercury and other toxic air emissions from power plants that could result in moderate retirements of older, fossil‐fired power plants in the next three or four years. A cooling water rule, which is expected to be finalized in 2012, also could affect the operation of generating facilities beginning in 2018.

Moreover, ISO-NE said it continues to participate in the Eastern Interconnection Planning Collaborative (EIPC) in support of the DOE’s interconnection‐wide transmission analysis project. Phase 1 of the project focused on the formation of a diverse stakeholder group, the modeling of 80 public policy “futures” through the use of macroeconomic models and the selection of three of these “futures” for in‐depth transmission analysis.

The EIPC is now focusing on Phase 2 of the project—the development of transmission build‐out options for the three selected scenarios. Like Phase 1, Phase 2 will culminate with a report, currently scheduled for completion by mid‐2013.

The ISO and transmission owners are implementing the Smart Grid Investment Grant from DOE. The goal of the project is the installation of about 40 phasor measurement units (PMUs) as well as communications infrastructure across the transmission system. To date, 12 PMUs have been installed and are streaming test data to the ISO. The full implementation of the project is expected by June 2013.

In 2011, FERC issued orders that require significant implementation and compliance efforts of the ISO. Modifications to the energy market to allow for the participation of price‐responsive demand is set to be implemented in two phases, beginning with a transition in 2012 followed by full integration in future years, ISO-NE said in its report.

Modest reforms to the forward capacity market will be needed in 2012 for the seventh forward capacity auction (FCA). The ISO also will submit to FERC in 2012 compliance filings for the implementation of changes for the eighth FCA.

The ISO and stakeholders are aiming for the development of longer‐term structural improvements. Conceptual development and market design will begin in 2012 and continue through 2013. However, the full implementation of the needed changes in New England is expected to take several years, ISO-NE said.

FERC‐ordered enhancements to the transmission planning process include the addition of capability and processes to plan for transmission infrastructure driven by public policies. Compliance through the regional stakeholder process will take place throughout 2012 and into the first quarter of 2013, according to the ISO’s report.