Public Power Magazine

Preserving the Federal Power Program’s Core Mission


From the September 2013 issue (Vol. 71, No. 6) of Public Power

Originally published July 8, 2013

By Alice Clamp
July 8, 2013
Glen Canyon Dam is located on the Colorado River in northern Arizona near the public power town of Page. It is a unit of the Colorado River Storage Project. Submitted photo.

 

Last year, 166 U.S. lawmakers from both sides of the aisle sprang to the defense of the federal power marketing administrations. The four PMAs, which market the hydro power produced at large federally owned dams to consumer-owned utilities, are housed within the U.S. Department of Energy.

The 40 senators and 126 representatives were responding to a March 2012 memorandum from then-Energy Secretary Steven Chu outlining proposed changes to the PMAs.

“We write to express our concerns with the new direction and the initiatives contemplated for the … PMAs,” the 166 said in a June letter to Secretary Chu. “[W]e are concerned that these new initiatives have been put forward without sufficient evaluation of potential impacts to the customers of the clean, reliable electricity marketed by the PMAs.”

In his memo, Secretary Chu outlined four proposed changes to the PMAs: implementation of new transmission through third-party mechanisms; improvement of the PMAs’ rate designs; improved collaboration with grid owners and operators through steps such as entering into an energy imbalance market; and working with Congress to modernize oversight of the PMAs.

Commenting on the memo, the American Public Power Association said the changes represented DOE overreach. They would increase costs for consumers, threaten local control by creating an energy imbalance market and violate the “beneficiary pays” principle, APPA said. 

Some 600 public power utilities in 33 states buy hydro power from the PMAs. The rates paid by each utility cover all of the costs of generating and transmitting the PMA-marketed hydro power, interest on the federal investment in the project, a proportionate share of the joint costs and ongoing operation and maintenance.

The PMAs’ cost recovery is based on a system of cost pass-through, whereby federal investment is repaid, plus interest, through electricity rates, APPA said.

As modifications and updates are made to the federal dams, which are operated by the U.S. Army Corps of Engineers and the Bureau of Reclamation, the power customers that receive the benefits of these upgrades repay the government for them. This principle, long referred to as “beneficiary pays,” is a core underpinning of the agencies’ operations.

Under the energy secretary’s proposal, PMA customers could be forced to take on the costs of all system-wide transmission upgrades from which they would receive no benefit. “This would be a blatant violation of the ‘beneficiary pays’ principle…” APPA said.

Another principle put at risk by Secretary Chu’s memo is that of “preference,” which is essentially a right of first refusal to access PMA power—a right that has been granted under federal law to not-for-profit utilities, APPA said. The preference principle is set out explicitly in the statutes that govern the PMAs’ operations and marketing activities.

The Utah Associated Municipal Power Systems, a wholesale electricity provider for its 45 members, played a key role in laying the groundwork for the congressional letter. “We sat down with all six members of our congressional delegation and asked them to sign the letter,” said Ted Rampton, UAMPS’ government affairs manager. Sens. Orin Hatch, a Republican, and Jim Matheson, a Democrat, sponsored the letter.

Congressional hearings

In April 2012, the U.S. House of Representative Natural Resources Committee held a hearing on Secretary Chu’s memo. The memo raised “serious concerns about the manner and scope of how it would dramatically change the PMAs’ mission,” said committee Chairman Doc Hastings, R-Wash. 

APPA President and CEO Mark Crisson told the committee that “if implemented, this memo will increase electricity costs for public power utilities and their customers that depend on power provided by the PMAs with little, if any, associated benefits.”

In his testimony, Crisson noted that the committee’s Water and Power Subcommittee had held a PMA budget hearing a month earlier that asked who would pay for the proposed changes and whether they would force a shift from the “beneficiary pays” principle.

Crisson was back on Capitol Hill in September 2012, when he once again appeared before Hasting’s committee. In his testimony, he noted that DOE had selected the Western Area Power Administration as the first PMA “to be overhauled,” and planned a series of workshops to elicit stakeholder input. But, “given the course of the proceedings up until now, we find it hard to believe that DOE is genuinely seeking customer input,” Crisson said. He urged DOE to establish a dialog with the PMAs and said the process “should be led by the PMAs and their customers,” not by DOE. 

Draft recommendations

Based on the response to Secretary Chu’s memo, staff from Western and DOE formed a joint outreach team to obtain the views of Western’s customers and stakeholders. The result was 13 draft recommendations for implementing Secretary Chu’s proposals.

The recommendations were grouped in three categories: increasing grid efficiency, improving transmission products and integrating variable renewables.

The team decided not to pursue any recommendations specifically targeted at energy efficiency, demand response or electric vehicles—all goals of the Energy Secretary’s memo. And some of the team’s recommendations “were developed to engage further collaboration among Western customers, tribes and stakeholders,” the group said.

The recommendations, issued in November, reflected a shift in tone and—to some extent—policy, APPA said. But the association remained concerned that DOE could use the recommendations to overhaul the PMAs for the benefit of new “stakeholders” and at the cost of PMA customers.

“The lack of specificity in the recommendations could allow DOE to take steps in implementation that could increase costs for the primary constituency of the PMAs: the preference customers,” APPA said.

UAMPS’ Rampton said most Western customers viewed the recommendations as a “fundamental change in the way the federal power marketing program was designed.” The Utah organization acts as the scheduling agent for its members that have contracts for power from the Colorado River Storage Project. UAMPS members purchase more than 595 million kWh from the project annually, said Rampton.

The team’s recommendations were “less onerous” than the Chu memo, said Leslie James, executive director of the Colorado River Energy Distributors Association. “They were remanded back to Western to implement. So the process became Western-driven instead of DOE-driven.” The distributors association represents consumer-owned electric utilities that buy hydro power from the Colorado River Storage Project.

Financial issues carved out

In his memo, Secretary Chu urged Western and the Southwestern Power Administration to implement new transmission authorities granted by Section 1222 of the Energy Policy Act of 2005 and the 2009 American Reinvestment and Recovery Act’s Transmission Infrastructure Program. Under these acts, the PMAs were authorized to partner with non-customer groups to develop transmission within their systems, but could use their discretion as to whether they would use the authorities. APPA noted that the Section 1222 authority had never been used.

Secretary Chu, however, sought to mandate these programs “by administrative fiat,” APPA said.

A month before the joint outreach team issued its draft recommendations, Western’s acting administrator removed financial issues from the text. They now reside under a separate Western program—the Access to Capital Initiative. Western said it created the program out of concern that capital funding constraints could hinder its ability to make timely investments needed to replace, refurbish and upgrade transmission facilities. The initiative would augment the two funding sources available for most of its projects—appropriations and customer advances, Western said. Through this initiative, Western would collaborate with its customers to expand customer funding sources and explore new access to funds. 

“Western told customers that the Access to Capital Initiative is a top priority,” said the Colorado River Energy Distributors Association’s James. “Its message: We need a Western-wide tool to ensure that capital needs for the transmission system are met in an era of declining appropriations.” The problem is that each of the projects within Western’s regions has a different authorizing statute, James said, and over time the customers and Western within each region have developed funding mechanisms that work well for the project/region. Moreover, customers are not convinced there is a Western-wide funding problem or that there should be a Western-wide funding tool.

There has been significant push-back to the initiative, James said. In February 2013, representatives of various customer groups met in Salt Lake City to discuss the issue. Over the years, meeting participants said they had supported various funding mechanisms to ensure that Western and the generating agencies had adequate funding to carry out their core missions.

The participants agreed on five points that they said could serve as a basis for discussing the Access to Capital Initiative.

  • Given the critical nature of this issue, customers must drive the process in partnership with Western, not be driven by Western’s process.
  • Western’s present, Western-wide “top down” approach does not fit its structure. Each region within Western has developed a funding mechanism based on such factors as size, need and project authorizing legislation.
  • Western should work with its customers to define the establishment of a more substantial Western-wide partnership policy, which would reduce the agency’s need for capital and focus available financial resources on the core mission—replacements and operation and maintenance of facilities needed to deliver federal power.
  • Customers do not want to include generating agencies in the discussion at this time. The focus should be on Western’s needs.
  • Customers do not support the pursuit of legislation that would be needed to sustain any of the Access to Capital options that have been proposed to date.

“Customers are suspicious of broad additional authority for Western,” James said. “For example, if a third party brings capital funding to Western, is there adequate assurance that there will be commensurate operations, maintenance and replacement funding from the same source. In other words, do the existing customers, who may not be beneficiaries of the capital improvement or project being financed, then become the backstop or repayment guarantor?” Western has indicated it will seek language in an appropriations bill that would give it additional authority, she said.

Ed Gerak, general manager of Buckeye Water Conservation & Drainage District, said he thinks the initiative could be an “ulterior motive—a way to get capital for integrating renewables.”

For the Utah Associated Municipal Power Systems, the expansion of the transmission system for third parties is a problem, Rampton said. “The preference customers would be on the hook for a federal upgrade. If it’s being done for, say, a wind project, the question is: how do you separate the dollars from the benefits? And if that user goes away, how do you recover the costs? We’re not going away, but a wind company might not be around long term.”

The transmission network has been sized and operated to accommodate the Colorado River project, Rampton said. Another generating resource, one that isn’t compatible with hydro, could force a change in hydro generation or transmission that might require additional capital, he said.

The Balancing Authority of Northern California is trying to keep an open mind on the issue, said Jim Feider, BANC’s general manager. The balancing authority, which includes the Sacramento Municipal Utility District, Modesto Irrigation District and the cities of Roseville and Redding, matches generation to load and coordinates system operations. Western operates as a sub-balancing authority within BANC’s footprint, Feider said. “It’s a collaborative partnership. BANC is the wraparound balancing authority and Western provides some services.”

“We’re not convinced that Western’s need for legislative [funding] authority is real,” he said. “It seems to have jumped to the conclusion that it needs that authority before adequately collaborating with its customers.”

Other issues

Energy imbalance market. Among the draft recommendations was a proposal to study costs and benefits of an energy imbalance market. The joint outreach team said an EIM—which would feature a bid-based market rather than cost-of-service rates—would be one possible way to achieve some of the benefits of sub-hourly scheduling and improved coordination among balancing authorities. Business objectives for participation in an energy imbalance market would address a number of customer, tribe and stakeholder concerns, the team said.

Buckeye’s Gerak said an EIM could represent a red flag for most customers. “We interact with a lot of sister organizations and saw an EIM as the camel’s nose under the tent. We were worried that it would mean an added layer of governance and costs. We believed the projected savings were overstated. An energy imbalance market would be a net cost adder, not a savings.”

Preference. The Western transmission system was designed with the preference customers in mind, Rampton said. “When the benefits are extended to a host of other stakeholders, the benefits to preference customers are diluted.”

Historically, preference customers have been defined as nonprofit organizations that own and operate a distribution system, Rampton said. “But that definition changed in the early 1990s, allowing organizations without a distribution system to buy federal hydro power.” To date, he said, qualifying organizations have been small. But that could change in the future.

“The [joint outreach team] draft recommendations contained a nuance of that,” said Rampton.

Final recommendations

The Balancing Authority of Northern California was among those representing Western customers that provided feedback on the team’s draft recommendations, Feider said. “Western and DOE took customer comments into account,” he said. “And

Final Recommendations

The joint outreach team, composed of the Western Area Power Administration and the U.S. Department of Energy representatives, issued its final recommendations on March 1.

The recommendations call for Western to:

  • develop a consistent methodology for determining the regulation reserve capacity needed by each Western balancing authority
  • consolidate its four open access same-time information system (OASIS) sites within the Western Interconnection into a single OASIS site
  • revise its large generator  interconnection procedures (LGIP) to conform to changes recommended by WestConnect’s LGIP Work Group
  • evaluate the potential to standardize transmission and ancillary service rate methodologies
  • initiate processes in Western’s Desert Southwest, Rocky Mountain, and Colorado River Storage Project (CRSP) service areas to identify opportunities for increased integration of transmission systems within each region
  • continue to work with regional reliability organizations to implement intra-hour scheduling, including 15-minute scheduling;
  • participate in regional and sub-regional efforts to find ways to integrate variable resources cost-effectively
  • evaluate the transmission and ancillary services rates charged by each Western-owned transmission project and determine the feasibility of developing new transmission products
  • evaluate its integrated resource planning program; and
  • engage customers and stakeholders to evaluate efforts within the WECC footprint to move from a contract-path to a flow-based approach. “As part of Western’s analysis, it should ensure that outcomes are cost-effective, benefits are clearly identifiable, and costs are neutral, or that any cost-shift is minimized,” the team said.

 

political pressure—the letter from members of Congress and the House hearings—was also a big factor.”

At the beginning of March, the team issued its final recommendations. While the draft recommendations were categorized by subject, the team’s final recommendations are grouped by actions to be taken: immediate implementation or continuation, further evaluation and consideration or not recommended for implementation.

The team dropped three of the original 13 recommendations, including the implementation of an energy imbalance market in the West. It also dropped the recommendation to perform a Western-wide infrastructure investment study. And a recommendation to look at transferring the Electric Power Training Center to the National Renewable Energy Laboratory has been superseded by a re-evaluation of an earlier decision to close the training center, according to a report in APPA’s Public Power Daily

In response to stakeholder input, the team developed a set of principles used to guide it in developing the final recommendations. Those principles were: 

  • Consider the unique attributes of Western’s regions,
  • Coordinate with federal generating agencies,
  • Ensure that the beneficiary or user of the system pays,
  • Build on the existing efforts already underway within Western, and
  • Ensure that Western stays within the limits of its authority.

The team also said it recognized the need to acknowledge the potential impacts associated with implementing any of the proposed recommendations, such as the potential for cost shifts and the need for Western’s customers, tribes and other stakeholders to be part of the evaluation process. 

“There are two issues that continue to scare us,” said Buckeye’s Gerak. They are rate-setting methodologies and intra-hour scheduling. Both are recommended for immediate implementation or continuation. The recommendation on rate-setting methodologies calls for an evaluation of the potential to standardize transmission and ancillary service rate methodologies.

“This recommendation and the one on intra-hourly scheduling go hand–in-hand,” said Gerak.

A recommendation proposed for further evaluation—new transmission products—also concerns Buckeye. “There could be some benefits, but it requires customer review, peer review,” said Gerak. “We’d like more input on what this would mean, because it’s our money.” Asked if such input was possible, he replied: “There are ways for that to happen, especially through legislation.”

The final recommendations are moving in the right direction, said BANC’s Feider. “[The joint outreach team] backed off the energy imbalance market. I’m pleased the team recognized that a lot of operational tools are being explored by utilities in the West.” He thinks the team sees the recommendations as a work in progress.

But he is concerned about a couple of issues. “One recommendation proposes determining how much regulation reserve capacity is needed to satisfy commitments and make any surplus available for integrating renewables,” said Feider. “In the view of BANC and its members, this raises a preference question.”

The balancing authority supports the notion of periodically reassessing the level of reserve capacity needed for regulation, Feider said. “But we are concerned that forcing a ‘consistent methodology’ Western-wide may not fully accommodate the needs of individual regions.” He added that the reliability-based control is still in a trial mode and it would be premature to use it to determine regulation reserve levels. Finally, any surplus capacity that is identified must first be marketed to preference customers before it can be used for other purposes, he said.

“The basis for Western’s marketing of federal hydro power, as well as the rate structures, is developed through a public process,” Feider said. “When customers sign contracts, they expect the federal agency to honor them. Customers build their resource mix around that. We rely on rulemaking processes to do our planning and resource mix.”

“It’s ok for Western to study this issue,” Feider added, “but we will keep a careful eye on it.”

A second issue concerns the transition from a contract path model to a flow-based approach to transmission. “The good news is that the [joint outreach team] recognizes this can’t be done in isolation, but requires the collaboration of all transmission users in the West,” Feider said. “You can’t flip the model on its head.”

If the energy imbalance market does go forward, it would use a flow-based approach, he said. “But that could trample on the existing rights of direct ownership or long-term contracts.”

The team, which recommended further evaluation of this proposal, has estimated a two- to four-year timeline, Feider said. “Western will have to deal with the entire Western Interconnection.”

Whither Congress, DOE?

Congress has often been the voice of the PMA customer, said Buckeye’s Gerak. “And as constituents, that’s a channel we will continue to use.”

UAMPS’ Rampton points to the congressional letter as an example of the role that Congress can play. “A number of signatories don’t even have a PMA in their state,” he said.

The most recent congressional action came in the form of an amendment to the House of Representatives’ energy and water appropriations bill. The amendment, sponsored by Paul Gosar (R-Ariz.), would prohibit DOE from implementing Secretary Chu’s memorandum. That memo “has created a great deal of concern among our constituents, who rely on power marketing administrations for affordable and reliable energy,” said Rep. Gosar in a speech on the House floor. He noted that the issue “has undergone significant scrutiny here in Congress over the past year.” He said that few issues had garnered such congressional consensus as this one.  Gosar was among the 166 signatories of the 2011 letter to then Secretary Chu expressing concern about his memorandum.
 
On July 10, 2013, the House approved the appropriations bill, with the amendment, by a vote of 227-198.

Congress continues to provide oversight—through committee and budget hearings, said BANC’s Feider. “As long as Western stays within its legislative authority and doesn’t engage in mission creep, it’s ok.”

The final recommendations are an improvement, said Will Coffman, APPA senior government relations representative. “But we’re not there yet.”

APPA is watching to see how Western and DOE will proceed, he said.

On top of it all, there is a new secretary of energy. “It’s too early to tell whether Ernest Moniz will carry the flag forward,” said Buckeye’s Gerak. “There’s a chance he might have different thoughts—or that Congress might have to get involved.”

There’s also a new administrator at Western. “Mark Gabriel has announced that the Access to Capital Initiative will be delayed,” said Coffman. “However, customers are still waiting for details on how long, exactly, this delay will be.”

On the surface, things appear relatively calm, said BANC’s Feider. “But you never know what might pop up.”

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