Release of Colorado STAR Report on Electrical Power Transmission Imminent

    The State of Colorado recognizes the need for additional electrical power transmission infrastructure in the state:

"Transmission is . . . a missing link that threatens to lead the state to a genuine energy crisis. Colorado's capacity to move electricity from where it is generated to where it is used is constrained. In short, we need more electric transmission capacity, and we need it soon. Failure to upgrade existing transmission lines and to deploy new transmission infrastructure in Colorado could have severe and long-lasting consequences for the state – not the least of which is an inability to put online the large amounts of new renewable resources that the public desires."

Colorado Governor's Energy Office, Renewable Energy Development Infrastructure (REDI) report, pg. 44.

The Governor's Energy Office (GEO) plans to release the third in a series of studies addressing the need for transmission in the state by the end of December. The key question addressed is how Colorado will meet the loads and needs of the future. Morey Wolfson, Transmission Program Manager, GEO, provided an introduction to the report during the October meeting of the Rocky Mountain Transmission Group.

According to the presentation, the STAR report poses the question of who pays for transmission and raises a concern that a regional transmission organization (RTO) in the west is unlikely. An RTO is a federally-regulated, independent, non-profit entity established to plan and operate the regional transmission assets under its functional control and provide non-discriminatory wholesale transmission service within its defined geographic region. With respect to the question of who pays for transmission, in the western interconnection, there is currently no mechanism that enables cost allocation and recovery for transmission lines across a multi-state region. An RTO could provide the mechanism to allocate and recover costs.

Why is an RTO unlikely? One challenge to acceptance of the RTO structure in the west is the impact to state's rights. The RTO structure; however, would enable participation in key transmission planning decisions by states and other stakeholders; and protect consumers by ensuring fair, transparent consideration of necessary transmission upgrades or other grid investments. In addition, as an independent entity, an RTO is in the position to advocate for consistency in interregional cost allocation rules, and can work with the state to coordinate transmission and generation siting decisions in-line with the state's goals for energy and economic development. This type of planning can avoid the need to build duplicative new transmission lines and by addressing the cost allocation and recovery hurdle, can enable new transmission development to help resolve interconnection queue delays to bring renewables online more quickly, thereby facilitating rural economic development.

Moreover, although the Colorado Clean Air Clean Jobs Act (for more background see posting on October 11, 2010) is a first step in preparing the state for imminent climate change legislation, infrastructure development will be needed to accommodate the shift in the electricity generation fuel mix. A study by the North American Electric Reliability Corporation (NERC) released October 2010 and available at: http://www.nerc.com/files/EPA_Scenario_Final.pdf, assessed the impacts to bulk power system planning and operations if four pending EPA rules are implemented. The study finds that "without additional power production or demand-side resources beyond those in current regional plans, the combined effects of the four EPA rules (Combined EPA Regulatory Scenario) are shown to significantly affect Planning Reserve Margins and, in most Regions/Subregions, more resources would be required to maintain NERC Reference Margin Levels." The study concludes that emerging demands are shifting the current generation mix and new infrastructure will be needed in the short term to support this shift.

The STAR report should provide additional insight into where Colorado currently stands on this issue.

Study indicates that Wyoming needs transmission and new flexible gas-fired generation to realize its wind potential

On November 9th, Black & Veatch presented a study to the Wyoming Infrastructure Authority (WIA) finding that in order to take advantage of its tremendous wind potential, Wyoming needs transmission and new flexible gas-fired baseload generation. The study also indicates that new flexible gas-fired generation could be economically located in Wyoming due to the state's Shale Gas reserves.

Wyoming is already an energy exporting state because in-state coal generation exceeds its load requirements and its export capability could be increased with wind development. The Western Renewable Energy Zone (WREZ) study indicated that 25,000 MW of wind generation could be economically built in Wyoming. Developers are proposing extra high voltage transmission projects to support this anticipated wind development. These proposed projects include the High Plains Express, the Wyoming-Colorado Intertie, TransWest Express, Gateway South, Gateway West, Zephyr and Overland and anticipate a total potential capacity of approximately 18,000 MW. The future of these projects, however, depends on the ability to deliver energy generated in-state to out-of-state markets.

While the Black & Veatch study emphasizes the need for transmission, the study did not address another key element necessary for transmission development: regional cost recovery and cost allocation mechanisms for transmission projects in the Western Interconnection. The study is posted on the WIA website.

Solar Energy Industry Association Files Whitepaper with Comments to FERC NOPR in Support of Planning, Siting and Cost Recovery for Transmission Projects in the Southwest

On June 17, 2010, the Federal Energy Regulatory Commission (FERC) initiated a Notice of Proposed Rulemaking (NOPR) to correct deficiencies in current transmission planning and cost allocation processes. On November 12, 2010, the Solar Energy Industries Association (SEIA) submitted reply comments to the FERC NOPR. In their comments, SEIA emphasized that "the current disaggregated planning process in the West creates uncertainty and stymies development of transmission" and provides an analysis of the issues in the whitepaper attached to their comments entitled, "Removing Transmission Barriers to Solar Energy Development in the Southwest." SEIA Reply Comments, Docket No. RM10-23-000, pg. 4.

The existing grid was designed around baseload generation facilities that were built close to load centers. Long distance transmission was generally designed to carry power generated from coal, nuclear and hydro power generation facilities and there was little extra capacity designed into the system. More capacity is needed to support integration of renewable generation and transmission needs to be designed to coordinate remote resources with the energy load centers that need the power. In addition, the intermittency of renewable resources can be minimized across a geographic region. Thus, transmission planning is regional.

SEIA provides that the following steps are necessary to enable utility-scale solar development:

1. "Transmission planning must be done on a regional level." Energy development across a multi-state region should be coordinated.

2. The disconnect between transmission planning processes and commercial-scale energy development must be addressed in order to facilitate energy development in the short term. "Planning, permitting and construction of foundational transmission lines must be achieved by 2014."

3. A multi-jurisdictional and multi-stakeholder approach should be used to address seams issues.

4. "Planning cannot be done in geographic or jurisdictional isolation. Each of these entities has a role to play (in siting, transmission study, grid management, and cost recovery) and must do their part to ensure timely development of renewable generation."

5. "A regional planning process must prioritize the planning, permitting, cost allocation and construction of key foundational lines."

SEIA concludes that the renewable energy industry is being hurt by the lack of coordinated planning, siting and cost allocation for regional transmission projects in the southwest. The SEIA whitepaper can be found under FERC Docket No. RM10-23-000.

 

HB10-1365: Colorado Clean Air Clean Jobs Act

Although taking a different approach, like New Mexico, Colorado is taking steps to prepare for impending federal mandates for the reduction of greenhouse gases (GHG). Colorado is addressing reduction of GHGs through enactment of legislation to provide incentives for electric utilities to reduce air emissions from coal-fired generation facilities. The Colorado Clean Air Clean Jobs Act (Act) was signed into law by Governor Ritter in 2010. Under the Act, the Colorado legislature found that coordinated planning for emission reductions from coal-fired plants will position Colorado to meet imminent federal legislation requiring emissions reductions. The legislature further found that promotion of the use of natural gas and other "low-emitting resources" will allow Colorado to meet its energy needs and support economic development in the state.

The Act requires public utilities in the state to file with the Colorado Public Utilities Commission (the Commission), an emission reduction plan for their coal fired generation facilities. The plan for emission reductions can include a number of elements defined in the Act, for example: retrofitting units with emission control equipment; retiring coal-fired generation facilities and replacing with natural gas fired generation or other low-emitting generation; conversion of the units to run on natural gas; long term fuel supply agreements; new natural gas pipelines and other supporting gas infrastructure; increased natural gas fired generation; and new transmission lines and transmission infrastructure.

Commission proceedings to facilitate implementation of the Act were opened two days after the Act was signed into law. The Act requires that plans be designed to meet reasonably foreseeable and current emission reduction requirements and it is generally acknowledged that the EPA will require the state of Colorado and other states to comply with increasingly stringent regulatory requirements. Xcel testified before the Commission that the "Act provides a pathway for utilities, the Commission, the Colorado Department of Public Health and Environment, and the Air Quality Control Commission to work through an expedited process to address both regional haze requirements and reasonably foreseeable future air quality regulations." Xcel's testimony further highlights the need for transmission and natural gas infrastructure to support integration of intermittent renewable energy resources and to support additional natural gas fired generation, respectively. The Commission has until December 15, 2010 to approve, deny or modify the plans with plan implementation required by December 31, 2010.

Thus comparatively, Colorado is addressing reduction of GHGs by mandating emissions reductions from coal-fired generation facilities; and New Mexico, through the current rulemaking proceedings before the Environmental Improvement Board, is working towards capping emissions of any source that emits in excess of the designated threshold.

New Mexico Cap and Trade Rulemakings

The complexity of air quality permitting regulations in New Mexico combined with the nature of oil and gas operations provides many opportunities for operators to fail to achieve regulatory compliance or, to fall out of compliance. To add to this regulatory challenge, two parallel rulemakings are currently pending before the New Mexico Environmental Improvement Board (EIB) seeking to cap greenhouse gas (GHG) emissions in New Mexico. As originally proposed, the cap and trade program would apply to sources that report emissions of 25,000 metric tons or more of CO₂ equivalent per year, thereby impacting the regulatory compliance challenge faced by large operators in the state.

The first proceeding is the result of a petition filed with the EIB by the New Energy Economy (NEE) seeking promulgation of rules to implement a New Mexico only cap in GHG emissions. The proposed rules call for a determination by the EIB of 1990 GHG levels and a limitation of 25% below these designated levels by 2020.

The second proceeding is the result of a petition filed with the EIB by the New Mexico Environment Department (NMED) seeking promulgation of rules to adopt GHG cap and trade provisions. The proposed rule calls for a cap threshold of 25,000 metric tons of emissions and a 2% decrease in the cap every year thereafter. According to the proposed rule, facilities will be required to determine their representative baseline emission and production levels using historical data and greater weight will be given to verified data and adjusted as necessary. Operators should note this provision because in some cases, verification data that uses manufacturer defined potential to emit could push operator emissions above the threshold where actual emissions are below the threshold.

The reasons proposed by the NMED for the cap and trade provisions are two-fold: (1) stimulate innovation by promoting economic opportunity for clean energy technologies; and (2) incentivize use of cleaner fuels in the state, like natural gas. It is interesting to note that while New Mexico continues to push for cap and trade regulations, California's Global Warming Solution Act of 2006 (AB32) which requires the California Air Resources Board to adopt cap and trade regulations by January 2011, is currently being challenged by Proposition 23, a ballot initiative to suspend AB32 until unemployment is below 5.5% in the state.

The evidentiary record for the NMED petition was closed September 30, 2010. Post-hearing submittals are due by October 26, 2010 and the EIB plans to deliberate at its public meeting on November 2, 2010.

The evidentiary record for the NEE petition was closed October 5, 2010. Post-hearing submittals are due by November 22, 2010 and the EIB plans to deliberate at its public meeting on December 6, 2010.