FERC Order 1000 Complements Key Aspects of Colorado’s Electric Transmission Facility Planning Rules

Construction of electric transmission facilities is the key to economic and renewable energy development in Colorado.  Important to this development, key elements of new Federal Energy Regulatory Commission Order 1000 (the “FERC Order”) addressing regional transmission planning processes complement Colorado’s Electric Transmission Facility Planning Rules (the “Colorado Rules”) recently issued under the leadership of Commissioner Tarpey of the Colorado Public Utilities Commission (the “Commission”).  These complementary policies may help increase the likelihood of Colorado developing a robust infrastructure designed to support a vibrant economy.

Colorado has been focused on the challenges to transmission development for years. In 2006, the Colorado Transmission Task Force on Reliable Electricity Infrastructure (the “Task Force”) recognized that “Colorado’s ability to ensure continued affordable, reliable electricity and to build a vibrant economy depends on sufficient transmission capability.”  In addition, the Task Force recognized that “[t]oday the system is strained and, if current trends continue, there will not be adequate transmission to meet the needs.”  A robust grid provides consumers access to cheaper electricity and is the facilitator to development of Colorado’s vast renewable resources.  Subsequent to the Task Force report, then Governor Ritter issued a series of reports that identified policy barriers to development and these reports led to legislative and policy changes in the state.

These legislative and policy changes however, impacted transmission development in the state by requiring more complex decision making at the Public Utilities Commission (the “Commission”).  In an effort to address these changes, the Commission issued the Colorado Rules under Decision No. R11-0077 defining the Commission’s role in electric transmission facilities planning as well as new requirements for the state’s public utilities relating to planning.   In this Decision, Commissioner Tarpey acknowledges that the “Commission has an obligation to ensure that proper transmission planning is taking place in Colorado and that the transmission system is sufficient to satisfy the needs of the Colorado citizens.”

Similarly, the FERC Order acknowledges that coordinated transmission planning can protect the consumer because coordinated planning may be more efficient and cost effective.  Specifically, the FERC Order requires, “public utility transmission providers to participate in a regional transmission planning process that evaluates transmission alternatives at the regional level that may resolve the transmission planning region’s needs more efficiently and cost-effectively than alternatives identified by individual public utility transmission provider in their local transmission planning processes.” FERC Order 1000, ¶ 6. 

Colorado and the FERC emphasize coordinated planning and stakeholder input.  Under the Colorado Rules, the three jurisdictional utilities in the state are required to file biennial ten-year transmission plans reflecting their own needs and reflecting how the utility coordinated with all transmission providers in Colorado. The FERC Order goes one step further by requiring regional planning processes to produce a regional plan.  The Commission is careful, however, not to impede existing processes with the new requirements.  Indeed, the Commission clarifies that “the obligation to participate in a regional transmission planning process that produces a regional transmission plan that meets the seven transmission planning principles, is not intended to appropriate, supplant, or impede any local transmission planning processes, that public utility transmission providers undertake.” FERC Order 1000, ¶ 161.  The objective is to require planning processes to meet the planning principles outlined in FERC Order 890 while producing a regional transmission plan.  

In another example of synergies, both Colorado and the FERC provided some leeway to the jurisdictional utilities as to how to meet the requirements for coordinated transmission planning.  Specifically, the FERC Order provided flexibility for regions to enhance or define processes and procedures for planning.  The FERC explains, “[p]ublic utility transmission providers have flexibility in developing the necessary enhancements to existing regional transmission planning processes to comply with this Final Rule, based upon the needs and characteristics of their transmission planning region.” FERC Order ¶158.

Colorado and the FERC also both recognize the importance of considering public policy in transmission planning.  The FERC Order requires “each public utility provider to establish procedures for identifying those transmission needs driven by Public Policy Requirements for which potential transmission solutions will be evaluated in the local or regional transmission planning processes.”  The FERC further encourages states to actively participate in identification of transmission needs driven by Public Policy Requirements.  “Public utility transmission providers, for example, could rely on committees of state regulators or with appropriate approval from Congress, compacts between interested states to identify transmission needs driven by Public Policy Requirements for the public utility transmission providers to evaluate in the transmission planning process.” FERC Order 1000, FN 189.

While Colorado declined to address cost allocation under the new Colorado Rules, the FERC emphasized the close link between planning and cost allocation and believes that the planning is the appropriate forum to address cost allocation.  “By linking transmission planning and cost allocation through the transmission planning process, we seek to increase the likelihood that transmission facilities in regional transmission plans are actually constructed.” FERC Order 1000 ¶ 501.  Thus, the FERC Order requires each public utility transmission provider to file a method or set of methods for allocating the costs of new transmission facilities selected in the regional transmission plan.  Importantly, while the FERC Order provides principles for regional and interregional cost allocation, the Order leaves sufficient flexibility within these principles so that regions can design methods according to regional needs.

The key areas of overlap between the Colorado Rules and FERC Order 1000 emphasize the need for coordinated planning, the need to consider Public Policy Requirements in this planning, and the need for public utilities to incorporate stakeholder input.  These requirements are also in-line with the Clean Energy Vision (“CEV”) defined in the Western Grid 2050 report.  “A CEV trajectory requires much greater regional coordination and cooperation to build the infrastructure that access and efficiently utilize the best renewable resources in the West.”  According to the DOE, however, significant expansion of the transmission grid will be required under any future electric industry scenario and so if the FERC Order is any indication, it looks like Colorado is and has been taking the right steps towards development of a robust infrastructure.     

New Mexico Renewable Energy Transmission Authority posts Rule Making Policy

Updates from the New Mexico Renewable Energy Transmission Authority (“NMRETA”): 

At a special meeting of the NMRETA board of director’s yesterday, September 13, 2011, the board approved NMRETA’s Rule Making Policy.  The Policy can be found here: http://www.nmreta.com/images/stories/pdfs/reta_rule_making_policy.pdf

A public hearing on the “Proposed Rule Governing NMRETA Condemnation Procedure” will be held Wednesday, September 28, 2011 at 1:00 PM in Porter Hall in the Wendell Chino Building (1220 St. Francis Drive, Santa Fe, NM). 

An Overview of FERC Order 1000: Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities

The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over bulk wholesale electricity markets and interstate transmission.  FERC has been engaged in reforming transmission planning and cost allocation through several landmark orders.  FERC Order 1000 issued on July 21, 2011, is the next step in the evolution of the FERC’s approach to address regional transmission planning processes. 

Brief Background to Order 1000

FERC first addressed transmission planning in 1996 with FERC Order No. 888 requiring open access to transmission facilities to address unduly discriminatory and anticompetitive practices.  In broad terms, Order 888 required all public utilities to adopt the pro forma open access transmission tariff (OATT) and provide transmission service for its customers comparable to the transmission service they provide themselves. Order 888 did not require utilities to engage in regional planning efforts.

In 2007, determining that its open access program had certain flaws, FERC issued Order 890 requiring coordinated, open and transparent regional transmission planning processes.  Among other things, Order 890 established that each transmission provider must file a new Attachment K as part of its OATT describing how its transmission planning process satisfies the following nine planning principles:  (1) coordination; (2) openness; (3) transparency; (4) information exchange; (5) comparability; (6) dispute resolution; (7) regional participation; (8) economic planning studies; and (9) cost allocation for new projects.    

Subsequent to Order 890, the FERC held a series of technical conferences to address further planning issues and on June 17, 2010 FERC issued a Notice of Proposed Rulemaking identifying further reforms in the areas of transmission planning and cost allocation.  The FERC noted, however, that the intention was not to disrupt progress being made with respect to transmission panning and investment in transmission infrastructure, but to address deficiencies in these processes to enable better support of wholesale power markets.

On July 21, 2011 FERC issued the Final Rule (“Final Rule” or “Rule”) providing for reforms in the areas of planning, cost allocation, and nonincumbent developers.  A power point discussion of the Rule can be found here: http://www.ferc.gov/media/news-releases/2011/2011-3/07-21-11-E-6-presentation.pdf

Planning:

The Rule establishes three categories of planning reform: (1) public utility transmission providers are required to participate in a regional transmission planning process that satisfies Order No. 890 principles and produces a regional transmission plan; (2) local and regional transmission planning process must consider transmission needs driven by public policy requirements established by state or federal laws or regulations (e.g., Renewable Portfolio Standard requirements); and (3) public utility transmission providers in each pair of neighboring transmission planning regions must coordinate to determine if more efficient or cost-effective solutions are available.  However, with respect to interregional transmission, the FERC declined to mandate a requirement for neighboring transmission regions to produce an interregional transmission plan or to engage in interconnection-wide planning. 

Cost Allocation:

The Rule does not mandate specific cost allocation methods.  Rather, the Rule provides that methods for cost allocation must be based on six cost allocation principles: (1) cost allocated must be “roughly commensurate” with estimated benefits; (2) those who do not benefit from transmission do not have to pay for it; (3) benefit-to-cost thresholds must not exclude projects with significant net benefits; (4) no allocation of costs outside a region unless other region agrees; (5) cost allocation methods and identification of beneficiaries must be transparent; and (6) the methods must allow the use of different allocation methods for different types of transmission facilities.   Thus, the Rule does not require a one-size fits all method for allocating costs. 

To facilitate understanding of how the order impacts non-RTO markets, the FERC has scheduled two webinars. More information on these webinars can be found here:  http://www.ferc.gov/EventCalendar/EventDetails.aspx?ID=5952&CalType=%20&CalendarID=116&Date=09/13/2011&View=Listview

Nonincumbent Developers – Removal of Federal Right of First Refusal (“ROFR”)

The Rule further acknowledges that Order 890 did not specifically address the potential for, or effect of, undue preference to incumbent utilities over nonincumbent transmission developers through practices applied within transmission planning processes.  As a result, there is the potential for a nonincumbent developer to lose the opportunity to construct its proposed transmission project to the incumbent transmission owner if that owner has a Federal Right of First Refusal (“ROFR”) to construct any transmission facility in its service territory.  The new Rule addresses nonincumbent developers by requiring removal of any ROFR from Commission-approved tariffs and agreements with respect to new transmission facilities selected in a regional transmission plan for purposes of cost allocation.  The removal of the ROFR is subject to four limitations:

1.       Removal does not apply to a transmission facility that is not selected in a regional transmission plan for purposes of cost allocation;

2.       Removal does not apply to upgrades to transmission facilities;

3.       Removal allows, but does not require, use of competitive bidding to solicit transmission projects or project developers; and

4.       Removal does not impact state or local laws or regulations regarding the construction of transmission facilities.

The impacts of the Rule on transmission planning will likely become clearer after the compliance period.  Under the rule each transmission provider is required to make a compliance filing within twelve months of the effective date of the Final Rule.  Compliance filings for interregional transmission coordination and interregional cost allocation must be filed within eighteen months of the effective date.

FERC’s transmission and cost allocation page can be found here:  http://www.ferc.gov/industries/electric/indus-act/trans-plan.asp

New Mexico Environment Department REVISING New Haul Road Policy

On September 2, 2011, we posted information regarding the New Mexico Environment Department’s (“Department”) new haul road policy requiring all haul road emission calculations to be based on unpaved road emission factors.  As mentioned in the previous posting, the Department’s new policy was apparently based on an Order issued by the Environmental Improvement Board on December 29, 2010, upholding the Department’s denial of Helena Chemical Company’s Notice of Intent (“NOI”) application. Since that posting, however, the Department has removed the new policy from their website and according to the Department, is currently revising its policy to comport with EPA’s January 2011 changes to AP 42 Section 13.2.1 governing paved haul roads - changes made subsequent to the Helena decision.  Based on the EPA changes, the revised policy will most likely reflect allowance of the use of AP 42 paved emission factors for paved haul road calculations under certain defined criteria.

AP 42 Section 13.2.1 with the 2011 changes can be found here: http://www.epa.gov/ttn/chief/ap42/ch13/final/c13s0201.pdf

The Department intends to post its new policy under its Frequently Asked Questions page as soon as it is approved. 

New Mexico Environment Department New Haul Road Policy

Companies seeking to permit emission sources in New Mexico should be aware of the New Mexico Environment Department’s (“Department”) new haul road policy posted on the Department’s website on July 12, 2011.  This new policy requires all haul road emission calculations to be based on unpaved haul road emission factors.  The Department presents this policy under its Frequently Asked Questions page http://www.nmenv.state.nm.us/aqb/FAQ.html#PP (see Permit and NOI processing).  Specifically:

                The Department considers the reduction of emissions through the proposed use of paved roads to be a control measure because both the installation and the maintenance of the paved road is not enforceable by the Department pursuant to the Air Quality Control Act or the Federal Act.  Since NPR or NOI emissions must be based on the Potential Emission Rate (PER) as defined in § 20.2.72.7.Y. NMAC, the paved road control measure cannot be applied to PER calculations.  Thus, road emission calculations must be based on unpaved road emission factors.

The policy is apparently based on an Order issued by the Environmental Improvement Board on December 29, 2010, upholding the Department’s denial of Helena Chemical Company’s Notice of Intent (“NOI”) application.   One issue in the Helena case was emissions from the haul roads.  The Helena facility has two haul roads.  These roads were paved in mid-2005.  According to the Order, “the haul roads accumulate dust, debris and fertilizer, and must be swept frequently, including at the end of each shift.”  The Department provided five reasons for denial of the NOI including the Department’s inability to impose conditions on the haul road if the NOI was issued.  This is explained by the Department as follows,

Helena’s reliance on AP-42 Section 13.2.1 Paved Roads did not have sufficient justification in light of the potential for debris to collect on the roads and the fact that there would be no condition to sweep or otherwise maintain the roads if an NOI were issued.

Under this new policy, unless the haul road is very short, it is unlikely that any facility with an emission source will fall below the threshold to trigger the requirement for a permit in New Mexico.