On June 2nd, 2014, the Environmental Protection Agency (EPA) announced perhaps the most significant environmental reform in its history.  Entitled the Clean Power Plan (CPP), the proposed regulations are designed to reduce greenhouse gas (GHG) emissions nation-wide by 30 % below their 2005 levels by the year 2030.

Overview of the Proposed Rule

Under the CPP, states are given individual pollution goals relating to their “carbon intensity,” defined as tons of carbon per megawatt-hour of electricity, as opposed to its overall tons of carbon produced.  Specifically, for Kansas and Missouri, the CO2/MWh reduction goals set forth in the proposed rule are as follows:

Proposed Output-Weighted-Average Pounds of CO2 Per Net MWh

From All Affected Fossil Fuel-Fired EGUs


Interim Period (2020-2029)

Final (2030)

Projected Baseline


Projected Baseline











To reach these goals, states will have until June of 2016 to design either individual or multi-state implementation plans.  States submitting individual state implementation plans (SIPs) may apply for a one-year extension, with a final plan due on June 30, 2017, while states that submit multistate plans are eligible for a two-year extension, with final plan due dates of June 30, 2018.

The methods utilized to reach the goal thresholds are left largely to the discretion of the individual states, with the EPA designating four broad “building block” categories that states may choose from.  These include:

  • improvements to carbon intensity at individual plants (increase plant efficiency)
  • shifting baseload generation to lower emitting plants (switching coal for natural gas)
  • new investment in low- and no-carbon generation (renewables and nuclear)
  • demand-side efficiency (energy efficiency programs and demand response)

Because of this flexibility, it is likely that individual compliance plans will vary from state-to-state, depending upon the specific characteristics of the local energy markets and any emission reduction actions that are currently underway.

Aside from setting forth the individual components utilized to achieve the emission reduction goals, each plan must satisfy the following criteria:

  • The plan must be enforceable (quantifiable, verifiable, straightforward, and calculated over as short a term as reasonable ) and in conformance with the Clean Air Act;
  • The projected CO2 emission performance by affected EGUs must be equivalent to, or better than, the required CO2 emission performance level in the state plan;
  • The plan must specify how the effects of the plan will be quantified and verified, including CO2 emission monitoring, reporting, and recordkeeping requirements for affected EGUs; and
  • The plan must specify a process for annual reporting to the EPA of overall performance and implementation and include a process and schedule for implementing corrective measures if reporting shows the plan is not achieving the projected level of performance.

Potential Impacts

It is likely that this proposed rule will have significant impacts on energy generation and consumption in the Midwest.  Utilities that rely upon coal-fired generation plants may be required to install expensive pollution control retrofits or technology to allow the facilities to reach higher operating efficiencies, or they may have to heavily curtail or retire the facilities altogether to be replaced with less carbon intensive generation sources.  However, it should be noted that even under the CPP, coal will still be used to generate approximately 30% of the electricity in the United States in the year 2030, down from 39% in 2013.  Additionally, the first threshold must be satisfied by 2020, providing utilities several years to make the necessary plans and implement any required changes.  Nonetheless, energy intensive industries may face higher costs as the price of power rises to reflect the fleet modifications utilities will be required to undertake.

Conversely, the wind, solar and energy efficiency industries in Kansas and Missouri stand to benefit from this regulation, as it gives utilities greater incentives to invest in carbon-free generation resources and demand-response initiatives to off-set existing carbon-emitting sources. The CPP also includes proposals to increase inter-state carbon credit trading, which produces an additional opportunity for states that develop robust renewable generation.

What’s Next?

It’s important to remember that this proposed rule is currently still in draft form and won’t expected to be finalized until June of 2015 at the earliest, and potentially even later.  On the immediate horizon, the EPA will initiate a 120 day public comment period beginning on the date the regulation appears in the Federal Register.   Interested parties are invited to submit comments electronically via EPA’s electronic portal (www.regulations.gov) , by email to A-and-R-Docket@epa.gov, or by mail to EPA Docket Center, Room 3334, EPA WJC West Building, 1301 Constitution Ave., NW, Washington, DC, 20004.

There will also be a series of four public hearings scheduled between July 28 and 31, 2014, in Atlanta, Denver, Pittsburg, and Washington D.C. EPA committing to make every effort to accommodate all speakers who arrive and register.

In the meantime, the proposed rule is very likely to come under legislative and judicial attack over the coming weeks and months.  The Congressional Energy and Commerce Subcommittee on Energy and Power will hold a hearing to review EPA’s proposal the week of June 16.  Lawmakers have already promised to introduce legislation blocking the rule, although this will be extraordinarily difficult as long as Democrats control the Senate and President Obama sits in the White House.

Assuming the rules proceed as proposed, the most significant decisions will be made on a state-by-state basis under the supervision of the state governments.  It is likely that the individual state environmental agencies will be responsible for the ultimate preparation of the SIPs with input from the governor’s office and the state legislature, the state public utility commission, the local utilities, renewable energy developers, and large industrial users.  Thus, it is likely that the most significant opportunity to impact the changes that will be required will come from state-level lobbying and participation in the state planning process.

For additional information about these regulations or their potential impact, please contact a member of the Polsinelli Energy, Environmental or Public Policy Groups.

Since 2008, the price of solar technologies has decreased significantly and the U.S. solar market has experienced rapid growth.  The White House has just released a report chronicling this progress as well as ongoing efforts.  To recap some of the highlights:

  • In 2013 solar represented the 2nd largest source of new electricity capacity added to the nation’s grid (behind only natural gas)
  • The amount of solar power installed in the U.S. has increased from 1.2 gigawatts in 2008 to an estimated 13 gigawatts today—enough to power more than 2.2 million homes
  • Since the beginning of 2011, the average price of solar panels has dropped more than 60% and the price of solar photovoltaic (PV) systems have dropped by about 50%—PV solar modules cost about 1% of what they did 35 years ago
  • 60% of major homebuilders now offer PV as a standard available feature in new construction
  • 5 years ago, there were no commercial-scale solar energy projects on federal lands, but today the Interior Department is on pace to permit 20 GW of renewable energy projects by 2020
  • After the Dept. of Energy helped finance the first 5 domestic utility-scale PV projects larger than 100 megawatts to show the technology’s viability, 10 new similarly-sized projects have been financed by the private sector without DOE’s help
  • In 2010, the BLM approved the first utility-scale solar project on public lands and has since approved 28 solar and associated transmission projects with the potential to generate over 8,500 megawatts

The Obama Administration continues work to leverage initiatives to deploy solar through collaborations with state and local communities; as well as bolster solar production on federal lands and use by the federal government.

Working with State & Local Communities

  • While solar panels get cheaper every year, the soft costs like connection fees and labor of solar remain a price barrier.  In 2011, DOE launched its Rooftop Solar Challenge to task local and regional teams to streamline processes and make it easier to go solar. In the initial round, 22 teams worked to standardize permit processes, update planning and zoning codes, improve grid connectivity standards, and increase financing options. These efforts helped cut permitting time by 40% and reduce fees by over 10%.  Now, 8 new teams are working with industry and stakeholders to simplify the solar installation process on a more regional scale.
  • The U.S. EPA, with help from the National Renewable Energy Lab, has developed a mapping tool and suite of financing, siting and environmental assessment techniques in the Re-Powering America’s Land Initiative.  The mapping tool identifies the energy generating potential of each renewable energy source by region—advising states and communities on the most effective renewable energy source for their area.
  • DOE’s new Solar Market Pathways program will target state and local market barriers with a focus on commercial-scale solar. It will fund programs to help spur solar market growth—including establishing or expanding community solar programs and local financing mechanisms, such as commercial property assessed clean energy (PACE).

Expanding Solar Power on Public Lands & in the Public Sector

  • The Defense Department has set a goal to deploy 3 gigawatts of renewable energy on its installations by 2025, and the federal government has committed to sourcing 20% of the energy consumed in federal buildings from renewables by 2020.
  • In 2012 BLM created the Solar Energy Program to make future solar energy project permitting more efficient for utility-scale development on federal lands.  The program creates solar energy zones with access to transmission, incentives for development, and a process to guide the deployment of additional zones and projects.  BLM established an initial set of 17 Solar Energy Zones to serve as priority areas for commercial-scale development, with the potential for additional zones through regional planning processes. If fully built out, projects in the designated areas could produce as much as 23,700 megawatts of solar energy.

With Congress unable to enact meaningful energy policy and state incentives facing increased resistance, it’s worth taking a step back to recognize the progress made by the solar industry and focus on the considerable opportunities still available for continued deployment.

Although most people in and out of Washington assume (correctly) that Congress is unable to enact significant energy legislation in 2014, President Obama can still leverage executive branch power to push through substantive policies and market drivers for renewable energy.  Having essentially written off Congress himself, the President has already proclaimed this the “Year of Action,” and he intends to work toward reshaping America’s energy framework in order to adapt it to a lower carbon economy.  To do this, the President has several administrative tools still at his disposal.

Below are some of the most significant policies that President Obama can put in place during the remainder of his second term without waiting on Congress to act.  Many of these are discussed in a recent report by the Center for the New Energy Economy at Colorado State and can be found here.

  • Clarify that federal agencies can enter into power purchase agreements for periods of up to 25 years by directing the Office of Management & Budget (OMB) to provide agencies with permission to use renewable power purchase agreements beyond the current 10-year ceiling.  These agreements would make it easier for renewables to secure project financing.
  • Expand the use of Energy Saving Performance Contracts (ESPCs) and Utility Energy Service Contracts (UESCs) throughout the federal government and the Department of Defense in order to finance microgrids, distributed generation projects and other proven renewable energy technologies.
  • Allow states to use flexible standards that include the deployment of renewable energy within the State Implementation Plans (SIPs) for meeting greenhouse gas emissions reductions from power plants under Section 111(d) of the Clean Air Act.  This can be done by quantifying the value of renewable energy under Clean Air Act compliance and allow states to avoid costs in regulating utilities.
  • Request that the IRS issue a revenue ruling that Real Estate Investment Trusts (REITs) can invest in renewable energy.
  • Request that the Comptroller of the Currency make clear that community banks will be credited under the Community Reinvestment Act for financing renewable energy projects in low- and moderate-income neighborhoods—qualifying as public welfare investments (PWIs).
  • Work with states to reallocate $2 billion in unused Qualified Energy Conservation Bonds for investments in renewable energy projects.
  • Identify and designate new solar and wind energy zones to help meet the President’s objective of permitting 20,000 MW of renewable energy production on public lands by 2020.
  • Direct DOE’s four Power Marketing Administrations (PMAs) and the Tennessee Valley Authority to develop and demonstrate the policies and practices necessary for electric utilities to incorporate renewable energy and distributed generation into their rates and infrastructure.
  • Direct DOE and the Department of Homeland Security (DHS) to work with industry to identify resilient pathways for transmission infrastructure and develop model policies that will help utilities integrate renewable energy onto the grid.

While industries and markets wait for Congress to reform and stabilize tax policies as well as develop a true national energy policy, President Obama and his Administration can move forward immediately with these and other measures to deploy renewable energy, create jobs and grow our economy.

If you would like any information about any of the suggestions listed above or have any general questions about federal energy policy, please feel free to reach out to the Polsinelli Energy Team:

Tracy Hammond, 202.626.8322, thammond@polsinelli.com

Luke Hagedorn, 816.572.4756, lhagedorn@polsinelli.com

Earlier this month Congress finally passed, and President Obama signed, the long-awaited Agriculture Act of 2014.  The “Farm Bill” became law after an unusually contentious process that led to significant policy changes in several of the measure’s key sections such as crop insurance, dairy subsidies and food stamps.  The bill contains a robust Energy Title as well.

Because this is the most significant piece of renewable energy legislation enacted in over a year (and likely to be enacted this Congress), it’s worth noting some of the key programs and funding provisions that were included.

The bill calls for nearly $900 million in funding for important energy programs and extends those programs through the 2018 Fiscal Year. These include:

  • The Rural Energy for American Program (REAP)—$50 million/year for 5 years in mandatory funding (FY 2014-2018)
  • The Biomass Crop Assistance Program (BCAP)—$25 million/year for 5 years in mandatory funding (FY 2014-2018)
  • The Biorefinery Assistance Program—$200 million in mandatory funding from FY 2014-2016
  • The Repower Assistance Program—$12 million in mandatory funding for FY 2014
  • The Bioenergy Program for Advanced Biofuels—$15 million/year in mandatory funding for 5 years (FY 2014-2018)
  • BioPreferred Program and Federal Government Procurement Program—$3 million/year for 5 years in mandatory funding (FY2014-2018)

Although the bill also authorizes discretionary spending for many of these programs beyond the mandatory funds summarized above, Congress has routinely failed to appropriate this discretionary spending.  Since we don’t expect this behavior to change given even tighter federal budgets in the future, the mandatory funding amounts are the critical numbers to focus on and plan for.

Several key policy changes were also made to existing renewable energy programs that open up these incentives to new types of projects and biobased products.  Specifically, the bill:

  • Adopts the definition of “renewable chemicals” as a product or substance produced from renewable biomass and establishes the term in federal law for the first time, making products covered by this definition eligible for federal incentives.
  • Modifies the definition of “biobased product” to explicitly include forestry materials and forest products that meet biobased content requirements, notwithstanding the market share the product holds, the age of the product, or whether the market for the product is new or emerging.
  • Defines “forest product” to ensure that mature forest products are treated equally as other biobased products, and clarifies that all forest products are eligible for inclusion in the BioPreferred Program and the Federal Government Procurement Program if they meet biobased content requirements and innovation standards.
  • Ends grant funding for the Biorefinery Assistance Program (which was never appropriated money by Congress anyway) and extends loan guarantee eligibility for the program to renewable chemical and biobased product manufacturing facilities.
  • Blocks the use of REAP funds for the deployment of blender pumps and other mechanisms to dispense renewable fuel.

While Congress may still debate energy efficiency legislation and tax writers could cobble together another tax “extenders” bill prolonging certain incentives for renewable energy, it’s important to realize that the Farm Bill may be the last significant piece of energy legislation signed by President Obama before the midterm electio

As the country faces polar vortexes of various magnitudes, a storm is brewing on the horizon for the wind energy industry.  A shifting political climate is drawing increased attention to the number of avian deaths, particularly eagle deaths, that may result from wind farms.  This mounting pressure felt by the wind industry is fueled by allegations that the U.S. Fish and Wildlife Service (USFWS) has given the wind industry a free pass when it comes to avian impacts as well as the recent prosecution of Duke Energy Renewables, Inc. under the Migratory Bird Treaty Act (MBTA) for avian deaths at two of its Wyoming wind farms.  At the same time, the USFWS’ regulatory changes to the Bald and Golden Eagle Protection Act (BGEPA) permitting rules are fundamentally altering the business case for obtaining an eagle take permit under the BGEPA.

Regulatory Background

Under the MBTA it is unlawful to pursue, hunt, take, capture, kill, or attempt to take, capture or kill any migratory bird.  No permit is available to authorize the incidental killing or injuring of migratory birds as a result of wind energy generation.  Rather, the USFWS has promulgated voluntary Land-Based Wind Energy Guidelines (Wind Energy Guidelines) which outline a structured, scientific process for addressing avian conservation concerns at all stages of wind energy development.  Companies that develop projects in accordance with the Wind Energy Guidelines and in consultation with USFWS are not immunized from liability under the MBTA.  Instead, the USFWS has indicated that adherence to the Wind Energy Guidelines will be taken into consideration when the USFWS considers whether to prosecute a developer or operator under the MBTA.

The BGEPA prohibits the “take” of bald and golden eagles by otherwise lawful activities except by permit.  A “take” of an eagle includes actions such as pursuing, shooting, shooting at,  poisoning, wounding, killing, capturing, trapping, collecting, destroying, molesting, or disturbing.  The eagle take permit allows the take of bald and golden eagles when the taking is associated with, but not the purpose of, otherwise lawful activity.  The USFWS has developed voluntary Eagle Conservation Plan (ECP) Guidance as a supplement to the Wind Energy Guidelines.   The ECP Guidance is intended be implemented in conjunction with the Wind Energy Guidelines and focuses on gathering information specific to eagles to support an eagle take permit decision.  Although the ECP Guidance does not address enforcement discretion, the Wind Energy Guidelines provide that the USFWS will consider adherence to the Wind Energy Guidelines when determining whether to pursue BGEPA violations, so long as the project is not likely to result in an eagle take.

An eagle take permit does not authorize the construction or operation of a wind energy facility, and an eagle permit is not required to construct or operate such facilities.  The eagle take permit authorizes the eagle take that may result from the construction or operation of the facility.  Wind energy project developers and operators thus face a business decision that weighs the risk that project will take an eagle, the risk of enforcement under the BGEPA, and the burden of obtaining an eagle take permit.  Most notably, for projects that do not otherwise have a federal nexus, the application for an eagle take permit will trigger the burdensome National Environmental Policy Act (NEPA) procedural requirements.

Lessons From Duke

There is a simple lesson to be learned from the Duke enforcement case:  when the USFWS expresses concerns regarding a project’s impacts to avian wildlife and the adequacy of the project’s avian impact studies, make sure those concerns are addressed during project development.  If the wind project has already been developed, obviously the past cannot be changed.  There is no time like the present, however, to consider strategies for minimizing potential future liability, including assessing the robustness of the project’s avian protection plan or bird and bat conservation strategies and the necessity of additional mitigation measures.

Changing Regulatory Policy

Much has been said about the USFWS rules promulgated in December 2013 which extended the maximum duration an eagle take permit to 30 years and the degree to which the longer term permit provides certainty for wind energy industry.  Of equal importance, but flying under the radar, are the amendments to the BGEPA permitting fees which created a reduced fee category for “low-risk” projects.  This rule change has fundamentally altered the risk calculus regarding whether wind projects should obtain an eagle take permit –not because of the price,  but because of the underlying policy shift.

Under the ECP Guidance promulgated last April, a project poses a minimal risk to eagles if it:

  1. has no important eagle use areas or migration concentration sites within the project area;
  2. has an annual eagle fatality rate estimate of less than 0.03 eagles per year (1 eagle death per 30 years); and
  3. causes cumulative annual take of the local-area population of less than 5% of the estimated local-area population size.

The ECP Guidance explains that projects meeting the above criteria may not require or warrant eagle take permits but also advises that the decision should be made in coordination with the USFWS.

Under the new rules, which went into effect on January 8, 2014, the USFWS has created a reduced fee category for “low-risk” projects.  Low-risk projects are those where the applicant can demonstrate that the eagle take is expected to be less than 0.03 eagles/per year using approved models and predictive tools.  Qualifying projects will be charged a permit application of $8,000 rather than $36,000 and pay $500 every 5 years in administrative fees rather than $2,600.

This creation of a low-risk permit signals a likely shift in policy by the USFWS whereby the USFWS may urge developers to obtain an eagle take permit even when there is only a very remote chance of an eagle being in the project area over the life of the project.   In justifying the low-risk permit, the USFWS explained that “there are potential benefits to eagles from issuing permits in situations in which take is unlikely, because such ‘low-risk’ permits will require monitoring and reporting” (although less than is required for higher risk projects) thereby allowing the USFWS to collect additional data on eagle use of the project areas and potential impacts of the permitted activities.  Moreover, it is not clear what projects will be deemed “not likely to result in a take” and qualify for enforcement discretion under the Wind Energy Guidelines in light of the low-risk permit category.  By definition, a permit is not required where a take is not likely.  Nevertheless, the USFWS now has created a permit for situations in which take is not likely.

What You Can Do Now

In light of the changing political and regulatory fronts impacting the wind energy industry, existing and planned wind energy projects should re-evaluate their compliance and risk management strategies concerning the BGEPA and the MBTA.  Projects seeking financing can expect more opinions from counsel regarding the advisability, and perhaps necessity, of obtaining an eagle take permit.  In addition, to smooth the way for project financing, it  will be even more critical than in the past to obtain documented and clear concurrence by the USFWS that the project is not likely to result in an eagle take and that an eagle permit is not required.

For More Information

If you have questions about the impacts of the new BGEPA regulations that went into effect in January, please contact:

Maribeth M. Klein    602.650.2309  mklein@polsinelli.com

Margaret B. LaBianca    602 650 2304  mlabianca@polsinelli.com

Although the new year is less than a month old and Congress has only been in session a handful of days, there’s a lot to talk about regarding renewable energy policy.

In mid-January, the President signed the FY 2014 Omnibus Appropriations bill.  This included funding for the entire federal government through September 30th of this year.   Despite immense fiscal pressure, several renewable projects of note received at least some funding including the following:

  • With an estimated $7.8 million in grant funding and $40 million in loan guarantees likely to be forthcoming for a Notice of Funding Available in 2014, the Omnibus allocated an additional $3.5 million for loan guarantees to further support the Rural Energy for America Program (REAP). Eligible REAP projects in the past have included biofuel production equipment, flex-fuel pumps, and anaerobic digesters for electricity production.
  • The bill provides for the transfer of up to $45 million from the Department of Energy to confirm its commitment to the Navy’s biofuel program.
  • The Biorefinery Assistance Program, has a current Notice of Funding Availability (NOFA) out for its remaining $76 million in carryover funding to support up to $181 million in loan guarantees for eligible commercial biorefinery developments or retrofits. However, of the six conditional commitments still in the program pipeline, some are expected to either not close or be reduced.

In addition to enacting the Omnibus Appropriations package, The President and his Administration have several rulemakings on the docket for the year that can help deploy and promote renewable energy on public and private lands.

U.S. EPA has a full plate with more than 140 items on its radar, including regulations tightening carbon dioxide emissions from both new and existing power plants.  These could ultimately prove to be the biggest federal drivers for renewable energy production in the coming decades.  The rule for future power plants—proposed in September, 2013—should be finalized by year’s end.  This proposal would essentially prohibit new coal fired power plants from being built, unless plans included a mechanism to capture and sequester much of the plants carbon emissions underground.  A similar proposal for existing power plants is set for release in June 2014, to be finalized in June the following year.

The U.S. EPA will also have to determine what levels to set for the year’s Renewable Fuels Standard (RFS).  Late last year the agency proposed scaling back targets for the first time since the program was established in 2005, requiring that refiners blend just 15.21 billion gallons of renewable fuels into the nation’s fuel supply.

The Interior Department plans to establish a competitive bidding process for solar and wind energy projects for the first time.  The regulations planned for May for commercial solar and wind energy development on federal lands would establish competitive bidding procedures for sites within designated leasing areas, would define qualifications for potential bidders, and would structure the financial arrangements necessary for the process.  In the past, BLM has only processed applications on a first-come, first-served basis, which has led to numerous delays.

Over the last few months, the future of the popular Missouri solar rebate program has been the subject of ongoing negotiations between the public utilities, the solar industry, state regulators, and large industrial interests.  The end result of these negotiations is, for the first time, a clear indication of the amount of solar rebate funds that remain to be distributed by each utility.  For solar developers in Missouri, this information provides much needed regulatory certainty and has a tremendous impact on when and whenre to focus efforts to capitalize on this lucrative incentive.

Background on the Solar Rebate Program

Since its creation in 2008, the $2/watt Missouri solar rebate program has been an interesting case study on the potential impact of state-level solar incentive programs.  From the perspective of satisfying its intended goal of promoting the wide-scale adoption of small-scale solar panels in the state, the program has been an undeniable success.  Based upon the information disclosed to the MPSC, as of September, 2013 the program has paid out approximately $62.5 million to Missouri residents and businesses to help defray the costs of installing solar panels.  As the chart below (based on public MPSC filings) illustrates, the solar rebate program gained significant momentum in 2012, and continued to grow steadily throughout 2013:

Solar Rebate Applications

















Solar Rebates Paid
















Aug./Sep., 2013





*See MPSC Docket No. ET-2014-0059, On-The-Record Presentation Transcript – Volume 1, October, 23, 2013
** See MPSC Docket No. ET-2014-0084, Direct Testimony of Richard Wright, October, 11, 2013

Of course, all of this success comes with a price tag.  In an effort to ensure that these costs are properly managed, the statute implementing the solar rebate program provides that the cost of implementing the state Renewable Portfolio Standard, which includes the solar rebate program, cannot exceed by more than 1% of the cost that would otherwise be paid by ratepayers if the RPS did not exist.  At the time the legislation was passed, no one expected that the solar rebates would cause this 1% “Retail Rate Impact” cap to be triggered, but the program has become far more popular than was originally anticipated.

Recent MPSC Dockets

Earlier this year, Kansas City-based utility KCP&L recognized that the 1% Retail Rate Cap would be triggered in its General Missouri (“GMO”) territory, which includes most of the KCP&L’s customers outside of the Kansas City metro area.  Accordingly, on September 4, 2013, KCP&L filed an application with the Missouri Public Service Commission to suspend the rebate payments for the GMO territory.  In that docket, KCP&L worked with the solar industry and the Commission Staff to negotiate a settlement addressing the payment of the solar rebates through the remaining life of the program.  That settlement agreement, which became the basis for similar agreements with KCP&L’s other territory and with Ameren, contained the following material terms:

  • The utilities will not suspend payment of the rebates in any given year, unless and until the total amount of all rebates paid over the life of the program exceeds a threshold amount ($50 million for GMO, $46.5 million for KCP&L, and $91.9 million for Ameren)
  • When the agreed-upon caps have been met, the utilities will file an application with the Missouri Public Service Commission to end the solar rebate program, and that application will be supported by the Commission Staff, the Office of the Public Counsel, the Missouri Industrial Energy Consumers, and the Missouri Solar Energy Industry Association.
  • To keep the public updates on the progress of the program, the utilities will create a regularly-updated website indicating the number of rebate applications that have been submitted, the number of rebate applications that have been approved, and the amount of solar rebates that have been paid.
  • Solar rebate amounts paid by the utilities will be included in a regulatory asset account to be considered for recovery in rates through either a general rate case or through a rate adjustment mechanism to be proposed by the utilities.

The Future of Missouri Solar Rebates

For solar developers and customers interested in installing solar panels on their homes or businesses, the real question is how long the solar rebate funds can be expected to last.  Fortunately, digging into the various public filings in the MPSC dockets and information released by the utilities, it is possible to put together some rough estimates of the level of solar rebate funds that are still available for each of the utilities:

Estimated Solar Rebate Funds Remaining Per Utility






Solar Rebate Cap





Rebates Paid





Applications Pending





Rebates Paid + Applications Received





Funds Remaining





*Updated as of 12/6/13.  See http://www.kcpl.com/save-energy-and-money/for-business/business-rebates/mo/solar-power-rebate/current-program-spend.

Based on the above estimates, it seems clear that the solar rebates are likely complete for the GMO territories.  In fact, assuming that all applications that have been submitted are approved, approximately $7 million worth of rebates that have already been submitted will be denied for lack of funds.  It is important that customers and solar developers working in this territory take the likely unavailability of the solar rebate into account for any potential installations in the future.

For Ameren’s and KCP&L’s non-GMO territories, however, the solar rebates continue to be available.  It should be noted that, based upon their testimony before the MPSC, Ameren has seen a significant increase in the number of solar rebate applications in the last few months.  Thus, it is likely that they will exhaust their supply of solar rebates more quickly than KCP&L, which has also seen a steady, but slower, increase in applications.

All told, the recent MPSC dockets have shown that approximately 60% of the Missouri solar rebate program funds have been exhausted, including all or close to all of the funds in the GMO service territory.  With that said, however, there is still tremendous opportunity for continued growth in Missouri solar, as approximately $71 million remain to help defray the cost of new systems in the KCP&L and Ameren service territories.  For customers of those utilities, sunny skies remain ahead, at least for a little while longer.

With renewable energy growing in acceptance every day, distributed generation (DG), locally produced energy, is expected to increasingly replace the large, centralized power grid that we’ve all grown accustomed to.

  • Earlier this year, the utility trade group Edison Electric Institute warned of distributed energy’s potential to disrupt the traditional utility’s century-old business model of charging all customers for shared infrastructure.
  • In a recent utility industry survey by PricewaterhouseCooper (PwC), 94% of international industry representatives predict that the power utility business model will be either completely transformed or significantly changed between today and 2030. Distributed generation, according to the survey, is one of the primary causes of this change. Worldwide, 64% expected that distributed generation would make up more than 20% of the global electricity mix by 2030, and 90% of North American businesses predicted that distributed generation would force utilities to significantly change their business models.
  • In a report covering lessons learned from Superstorm Sandy, a group of companies that design, build, and operate the grid called the GridWise Alliance issued a report with a broad swath or recommendations. The stakeholders recognized new policies, rules and operating procedures are needed to safely leverage customer-owned distributed generation during major outage events like Sandy.

A host of changing dynamics including deregulation, changing state and federal policies and incentives for renewable energy, and an explosion of distributed generation is leading to a reduction in the fossil-fuel electricity utilities sell.  As the grid shifts toward this new distributed generation, microgrids—small, self-sustaining grid systems—will become more and more commonplace as technology enablers.

Microgrids have the potential to radically change the U.S. electricity paradigm. Although barely heard of ten years ago, microgrids are expected to explode into a $40 billion-a-year global business by 2020, according to Navigant Research, a clean-technology data company. In the U.S., about 6 gigawatts of electricity will flow through microgrids by 2020, Navigant said.  And while only about 30 commercial-scale systems exist now, some estimate that up to 24,000 U.S. sites could be available for large-scale microgrid conversions.

Once just used to avoid power blackouts, microgrids are now used by power consumers to offset rising retail power prices, which have climbed 34% since 2003 according to the Energy Information Administration. Operators can remain connected to the grid and switch between the electricity they generate and the outside, and can also sell surplus electricity back to the utilities through net metering.

The Department of Defense (DOD) is beginning to embrace DG and microgrids as well.  In May, Lockheed Martin completed the first domestic microgrid at Fort Bliss in Texas for the U.S. Army. The military has already been using them at sites in other countries to reduce fuel consumption.

DOD’s Smart Power Infrastructure Demonstration for Energy Reliability and Security (SPIDERS microgrid program) prime integrator Burns & McDonnell put together a white paper highlighting two huge benefits for our military:  increased power reliability and generation efficiency.

Microgrids do come with their own challenges, such as enabling all of the various components to communicate with one another—and increased standardization is certainly needed if microgrid systems are to continue to proliferate.  But, much like the smart grid and other networks, this challenge can be met with guidance by cooperative stakeholders and perhaps some guidance from government policy.  Any policy will have to straddle the technology-neutral line of effectively enabling development, while still encouraging future innovation.

As our grid increasingly turns to renewable energy, look for distributed generation and, in particular, microgrids to change the hundred-year-old energy game.










As part of our continuing effort to provide current, topical information relating to renewable energy projects, RenewableEnergyLawInsider provides a series of posts from individuals with a wide range of experience and expertise. Today, Tracy Hammond from the Polsinelli Public Policy Group in Washington D.C. provides an update about the impact that the federal government shutdown will have on renewables in the United States.

The federal government shutdown is now in its fourth day, and there is no quick resolution of the   partisan standoff in sight.  Both Republicans and Democrats appear to be digging in instead of reaching out, and it is likely that this shutdown could last two to three weeks, with a breakthrough coming only as the U.S. approaches its borrowing limit (or debt ceiling) October 17th.

Although there’s enough speculation, prognosticating and second-guessing to fill volumes; I’ll focus here on how this shutdown will impact renewable energy.

In thee near term, the government shutdown could delay the release of federal renewable fuel requirements for 2014.  Renewable fuels stakeholders expected the U.S. EPA to release its proposed targets—levels of conventional and advanced biofuels that must be blended into gasoline and diesel—in mid-October.  The release will almost certainly be delayed and the longer the shutdown, the longer the delay.  A long delay in the release of the requirements will increase  uncertainty in the fuels market, giving critics of the RFS additional opportunities to call for repeal or modifications to the program.  A delay will also affect efforts in Congress, where a group of lawmakers from the House Energy and Commerce Committee are crafting legislation to reform the standard. However, their efforts will hinge  on what EPA decides to do with its 2014 numbers.

Other rules that could drive renewable energy development, like EPA’s efforts to draft emissions caps for greenhouse gases will also be delayed, making it even more difficult to meet the timeline laid out by President Obama earlier this year.

During the shutdown, many Congressional offices are working with significantly reduced staffs.  And with much, if not all, of the attention focused on funding the government and raising the debt ceiling, work is not being done on a host of other legislative priorities.  Just one example is the renewable energy Production Tax Credit (PTC), now set to expire in less than three months.  In addition to wind, the PTC provides a 2.3 cent-per-kilowatt-hour credit for geothermal energy and closed-loop biomass, and a 1.1 cent-per-kilowatt-hour credit for qualified hydropower facilities, marine and hydrokinetic power, landfill gas, trash combustion, small irrigation power facilities and open-loop biomass. The Congressional Joint Committee on Taxation found that a one-year extension of the tax credit would cost about $6.1 billion over 10 years. A five-year extension would cost roughly $18.5 billion.  Given the current budget pressures, these are not insignificant amounts.  Without some sort of as-yet-unknown “grand bargain”, it seems very unlikely that the PTC will be extended before the end of 2013.

Because nearly all other legislation has taken a back seat to the funding and debt discussions, the Farm Bill remains in limbo.  With no new Farm Bill agreement, programs like the Renewable Energy for America Program (REAP), the Biomass Crop Assistance Program (BCAP) and the Advanced Biorefinery Assistance Program are attempting to operate with only leftover money from previous years.  Soon, these programs will expend all of their resources and be forced to shut down until Congress passes a Farm Bill authorizing new funding.

Speaking of REAP, BCAP and other similar programs, with no one at USDA, DOE and other agencies to review and approve applications, no new funds will likely be released to worthy recipients.  Projects will be put on hold and construction will stop on efforts to increase energy efficiency and deploy new renewable energy across the country.  Although this may only be a short term hiccup lasting a few weeks, delays take a toll on project financing, increase expenses and push off potential completion.  As the budget battles continue, federal departments and agencies will almost certainly continue to try to do more with fewer resources—both human and monetary.  This trend will inhibit deployment and make it more difficult for deserving projects to move forward.

The first rule of medicine is do no harm.  As Congress continues to fail at its most basic task—funding the federal government—renewable energy and those that earn a living in the sector won’t be mistaking their congressional leaders for doctors anytime soon.

As part of our continuing effort to provide current, topical information relating to renewable energy projects, RenewableEnergyLawInsider provides a series of posts from individuals with a wide range of experience and expertise. Today, Tracy Hammond from the Polsinelli Public Policy Group in Washington D.C. provides an update about the ongoing attention being paid to the Renewable Fuel Standard by the U.S. House of Representatives.

The House Energy and Commerce Committee this week completed 2 days of hearings on the renewable fuel standard (RFS), the federal mandate to blend 36 billion gallons of biofuels into the nation’s gasoline supply by 2022.  Multiple industries and interests weighed in on the economic, environmental and technical impacts of the law. The hearing capped off an effort that began with a series of white papers the panel released this summer to gather information and feedback on the program.

The RFS is one of the largest and most controversial renewable energy program ever mandated by the federal government.  Since its creation in the 2005 and expansion in 2007, interest groups have launched major lobbying campaigns both supporting and opposing the standard. It has suffered additional criticism since last summer’s record drought badly damaged the nation’s corn crop, raising questions about the viability of corn-based ethanol, the most common biofuel in the U.S.

For the first time since 2007, Congress is taking a very serious look at revising the standard.  Although some, like the oil and refining sectors and their congressional allies, are calling for a full repeal of the law, there is not sufficient support for such a dramatic policy reversal.  This sentiment was summed up best by senior Democrat Rep. Gene Green (D-TX), “I would probably vote for repeal of the RFS, but I don’t just see where we’re going to get there.”

There does, however, seem to be support—at least in the committee—for making changes to the standard to address rising ethanol credit prices and the 10% “blend wall,” or the technically feasible limit to the amount of ethanol that can be blended into the nation’s fuel supply.  This is echoed by Rep. John Shimkus (R-IL), “You don’t have enough for a repeal, but you do have enough for a reform.”

Other Members complained that U.S. EPA, which administers the RFS program, sets excessively high targets for cellulosic biofuels.  These fuels made from purpose-grown plants, ag waste, algae, energy grasses and other feedstocks that don’t conflict with food crops are 2nd generation biofuels and were hoped to eventually displace corn ethanol and soybean biodiesel.  Unfortunately, the development of these fuels has been agonizingly slow.  For example, the mandate calls for 1 billion gallons of cellulosic biofuels made this year. Instead, EPA has proposed revising that number down to just 14 million—and that target will not likely be met by the advanced biofuels industry.

Senate Democrats from the Mid-Atlantic states are also wading into the debate.  Sen. Ben Cardin (D-MD) is working on legislation to reform the RFS, while senators from neighboring states, including Delaware and Pennsylvania, are urging the EPA to temporarily waive some blending requirements for obligated parties (refiners) in their states.  Like their House counterparts, oil-patch Republicans in the upper chamber have also called for a full repeal.

As with many things involving Congress, this process will take a long time to play out.  After 6 years of “fuel vs. food” fights, questions about the sustainability of corn ethanol, and the near non-existence of a cellulosic biofuels industry; however, we may be reaching a tipping point that will force lawmakers to make changes to the most contentious parts of the RFS both in order to appease critics and perhaps even prevent the standard’s total collapse.