Maine renewable energy report released

The Maine Public Utilities Commission has issued its latest annual report on Maine's use of renewable electricity, covering the 2014 calendar year.  The report shows the impact of Maine's renewable portfolio standard, a state law requiring electricity suppliers to source specified percentages of their electricity from renewable resources.  The report found that compliance costs have fallen nearly in half since 2013.

The Maine State House.

Since Maine's electric industry restructuring in 2000, state law has required competitive electricity providers -- retail suppliers -- to procure 30% of their load served from "eligible resources." These are generally defined in statute as renewable or cogeneration facilities.  A 2007 act of the Maine legislature added a mandate that specified percentages of electricity that supply Maine’s consumers be sourced from “new” renewable resources.  Generally, these are renewable facilities that have an in-service date, resumed operation or were refurbished after September 1, 2005.  This "Class I" renewable portfolio standard began at one percent of load in 2008, and increases in one percentage point each year until reaching ten percent in 2017.  The older "eligible resource" standard became known as "Class II."

The 2007 renewables law required the Public Utilities Commission to report annually to the legislature on the program and compliance.  Each year's report is based largely on the most recently filed Competitive Electricity Provider (CEP) annual compliance reports, which are filed each July, covering the prior calendar year.  So there is some lag between the events being tracked and the publication of the report.

The Commission has just released its report covering calendar year 2014. The report notes "approximately 75 certified facilities, with a total capacity of approximately 1220 MW," although some are not operating or are eligible for other states' renewable portfolio requirements.

In 2014, most suppliers complied with the Maine renewable portfolio requirement through the use of renewable energy certificates or RECs.  According to the report, RECs from 22 facilities were used by suppliers to comply with the 2014 new renewable resource requirement.  Of these, 18 are biomass, 3 are hydro, and 1 is a wind facility. 20 of the 22 facilities are located in Maine, one is located in Connecticut and one is located in Massachusetts. Maine facilities, mostly refurbished biomass plants, supplied 99% of the approximately 811,476 RECs purchased to meet the 2014 portfolio requirement.

For calendar year 2014, 78.05% of the Class I RPS requirement was satisfied through the purchase of RECs during that year, 0.0004 % was satisfied through an alternative compliance mechanism, 21.88% was satisfied using RECs banked from 2013 and 0.1130 % will be satisfied during a 2015 cure period allowed by rule. On top of this activity, 181,595 RECs were purchased in 2014 and banked for future use and an additional 8 RECs were purchased where the supplier did not indicate whether the certificates were to be banked or would not be used.

As the Commission notes in its report, "the prices for Maine Class I RECs declined substantially over the two years leading up to 2014. This has occurred because Maine’s portfolio requirement includes, as an eligible resource, refurbished biomass facilities (which are not generally eligible in other New England states)."

One result is that the annual cost of Class I compliance fell roughly in half since the last report, with a total cost of $14,296,249 in 2014 compared to just $6,947,269 in 2013.  The report describes the cost of Class I RECs used for compliance in 2014 as ranging from approximately $1.72 per MWh to $22.33 per MWh, with an average cost of $8.56 per MWh.  Adding $198 for one supplier who satisfied a portion of the portfolio requirement through alternative compliance mechanism at the rate of $66.16 per MWh, the report describes a total Class I compliance cost to ratepayers during 2014 of $6,947,269.  The Commission translated this into "an average rate impact of about 0.06 cents per kWh (or about 30 to 35 cents monthly for a typical residential bill). In percentage terms, this translates to a residential customer bill impact of about one half of 1%."

The report also describes the cost of Class II RECs used to satisfy the eligible resource portfolio requirement as ranging from $0.00 per MWh (some RECs were provided for free as part of an energy transaction) to $1.80 per MWh, with an average cost of $0.52 per MWh and a total cost of $1,834,314. According to the Commission, this translates into less than ten cents per month on a typical residential bill.

Texas small hydro project loses exemption

What happens to a proposed hydroelectric project takes longer than anticipated to be built, due to difficulties with project financing and severe flooding?  As the developer of a proposed project in Texas recently found out, federal regulators can be lenient up to a point -- but under some circumstances the developer can lose its federal authorization to develop and operate the project.

The A.H. Smith Dam on the San Marcos River in Martindale, Texas was originally constructed in about 1894 to provide mechanical power a cotton gin; later, electric generation was installed, but power production ceased in the 1940s when low wholesale energy prices made operation uneconomic.  Modern hydropower facilities rated at 150 kilowatts were installed in 1984, but were ultimately abandoned.

In 2005, developer Hydraco Power, Inc. applied to the Federal Energy Regulatory Commission for an exemption from the licensing requirements of Part I of the Federal Power Act for its proposed A.H. Smith Dam Project.  Hydraco's project included refurbishing and restoring the operation of the existing turbine located at the dam's powerhouse, installing a new buried transmission line and a water surface elevation gate in the headpond.

On June 2, 2006, the Commission granted Hydraco an exemption for the project.  As a standard condition of exemptions, the Commission retained the right to revoke the exemption if any term or condition was violated.  Among the terms was a requirement that Hydraco file within 120 days a
plan and schedule to install the new transmission line and restore the powerhouse, turbine, and trash racks to operating condition, as well as notice that the Commission could terminate the exemption if actual construction of any proposed or required facility had not begun within two years or had not been completed within four years of the date of issuance of the exemption.

Over the next 8 years, Hydraco filed a series of construction plans and schedules, but never completed the project despite obtaining repeated extensions of key deadlines.  After multiple prompts by Commission staff to file a revised plan and schedule for restoring project operation or an application to surrender the exemption, the Commission noted that Hydraco either failed to respond or responded by stating that it could not estimate a schedule for restoring project operation because project construction, including major component repairs, was on hold due to lack of funds.

After the Commission issued a public notice in August 2014 stating its intent to terminate the project exemption "due to Hydraco’s longstanding violation of exemption Article 10 and its failure to provide a timeframe for restoring project generation", on November 20, 2014, the Commission issued an Order Terminating Exemption. That order found that "Hydraco has only performed minimal work at the project since obtaining its exemption in 2006 and that it lacks the funding to proceed with the necessary component repairs, including construction of the powerhouse interior and generating unit."

Hydraco filed a request for rehearing of the Order Terminating Exemption.  On rehearing, Hydraco asserted that it had reached a financing agreement with a new investor and, consequently, it is ready to perform the work needed to comply with its exemption. Hydraco also objected to the findings that project construction was at a standstill and that Hydraco intended to abandon the project, noting that the Commission should excuse construction delays caused by severe flooding.

Last week, the Commission issued an Order Denying Rehearing in the case.  It first noted that Hydraco had not demonstrated that it now has the money needed to bring the project on line.  Not only did Hydraco not show evidence of a final financing agreement, but the documents showed a source of only half of the funding needed for project restoration.  Second, the Commission noted that Hydraco's recent activities -- regularly inspecting the dam and removing debris from its spillway, trashracks, and grates, securing the site against vandalism and installing lighting, and repairing damage caused by a flood -- are "either maintenance or repair, not project development."  Finally, the Commission articulated its "doctrine of implied surrender", which it applies where the entity responsible for the project has, by action or inaction, clearly indicated its intent to abandon the project, but has not filed a surrender application.

With the exemption terminated and Hydraco's request for rehearing denied, the A.H. Smith Dam project faces an uncertain future.  On the one hand, the site presumably still offers many of the same values that Hydraco hoped to capture -- use an existing dam, with existing generation facilities, to generate renewable electricity.  However, the loss of the FERC exemption means that Hydraco (or any other developer) will have to start the federal hydropower process over if it hopes to redevelop the dam as a hydroelectric generating site.

The case of the A.H. Smith Dam project illustrates a number of themes: interest in restoring existing hydropower infrastructure to generate renewable energy with relatively less environmental impact than newly-built dams, the challenge of securing financing for small hydropower projects -- and perhaps most importantly the value of compliance with FERC hydropower rules.