A few weeks back I discussed the importance of robust Renewable Energy Standards for the future of renewable energy development in the United States.  It seems that the the state of California agrees, as yesterday the state legislature passed legislation which will give California the most ambitious renewable energy standard in the nation.  This legislation, which was introduced by State Senator Joe Simitian, will require private and public utilities to utilize renewable energy for 33% of their total energy portfolios by the year 2020.

Previously, under legislation that was also introduced by State Sen. Simitian, state utilities were required to generate 20% of their total portfolios from renewable sources by 2010.  A study performed by the California Public Utilities Commission found that the state utilities have met this goal.  Specifically, they had achieved 18% renewable energy as of the end of 2010, and are expected to be at 20% by the end of this year.

Interestingly, the previous law included a rate cap which the new legislation would remove.  I’ve discussed the significant impact of rate cap provisions in a previous post, but suffice it to say that this move should help spur renewable production even further.

The legislation has now passed both houses, and all the remains for it to become effective is the signature of Gov. Jerry Brown.  Congratulations to State Senator Simitian for once again helping to raise the bar on renewable energy policy in the United States.

The full text of the bill is available on the California Legislature’s Bill Information Site, here, and an excellent “Fact Sheet” prepared by a member of Senator Simitian’s staff can be found here.

*Update:  Gov. Brown officially signed this legislation into law on April 12, 2011.  Angela Binewal wrote an excellent article for North American Windpower about the signing, and provides great insights into the industry’s response to the new standard.

CurtailmentA post yesterday by Susan Kraemer on the Clean Technica blog highlighted a shocking statistic from Dr. F. David Doty on GreenTechMedia:

“Approximately 25 TWh (yes, 25 terawatt-hours) of wind energy was curtailed (idled) in the U.S. last year to keep the off-peak grid energy price from frequently going negative.  That is about equal to the energy in 700 million gallons of gasoline just being thrown away. Curtailed wind energy in the U.S. appears likely to exceed 40 TWh in 2011″

Essentially, curtailment describes a situation where a renewable project is producing energy, but the transmission owner will not allow that energy to go onto the electrical grid. Thus, unless there is some way to store the energy, the energy is wasted.  The impacts of curtailment rarely get media coverage because it is complicated and usually largely controlled by dense contract language within Power Purchase Agreements (“PPAs”) and Interconnection Agreements between the renewable developer and the transmission owner.  Nonetheless, the impacts are significant for project developers.

To give a sense of the amount of energy that we are talking about here, curtailing 25 TWh of energy is roughly equivalent to throwing away a full year of energy output from a 115 MW project that is running at full capacity, or a 300 MW wind farm running at a good normal capacity factor of around 40%.

One of Susan’s main points is that this curtailment can hinder the hugely important financing of renewable projects, and ultimately can cut into the project’s bottom line.  I couldn’t agree more with her analysis.  The potential impact of curtailment can be substantial for a renewable energy project.  Whether or not the project developer gets paid for curtailed energy depends on how the PPA is drafted, and often the developer gets stuck with the bill.  If you are a project developer, 25 TWh should definitely be a statistic that you keep in your mind when negotiating and drafting PPAs with utilities and transmission companies.

In 2011, the United States Department of Agriculture (“USDA”) is planning to spend roughly $1.9 billion dollars on conservation programs designed to encourage landowners to improve their natural resource stewardship and meet environmental challenges on their land.  The roughly 275 million acres currently enrolled in these programs is expected to increase to an estimated 300 million acres over the next year.  It is important that renewable project developers determine whether the project site landowners are enrolled in these programs because developing a renewable project on land that is enrolled in one of these programs could violate the landowner’s contract with the USDA, and potentially lead to two extremely unpleasant outcomes.

1.)  First, the landowner could lose rights to future payments from the USDA, be forced to refund the payments that have already been received and be subject to additional fines.  Depending on how the renewable lease or easement is drafted, developers could be contractually obligated to compensate the landowner for these losses.

2.)  Second, some USDA programs give USDA the right to stop construction or use of the renewable facility, and can potentially force the developer to dismantle existing facilities.  Obviously, this could be devastating for a renewable developer.

There are quite a few of these USDA programs, but the two most common are the Environmental Quality Incentives Program and the Conservation Reserve Program.

Environmental Quality Incentives Program (“EQIP”)

With roughly 190 million acres enrolled in 2010, EQIP is the largest of the USDA’s conservation programs. EQIP encourages landowners to implement certain conservation management practices by refunding up to 75 percent of the incurred costs and income foregone, with total payments within 6 years not to exceed $300,000. However, if the landowner permits an activity that defeats the purpose of the program or transfers an interest in the land to a party who is unwilling or unable to perform, the landowner could lose the right to all future payments, be required to refund past payments plus interest and be subject to liquidated damages. Depending on the wording of any agreements between the landowner and the developer, it is possible that the developer might be required to pay the landowner’s damages to the USDA.

Conservation Reserve Program (“CRP”)

With roughly 31 million acres enrolled, CRP is the second largest USDA conservation program. CRP helps agricultural producers safeguard land by incentivizing, through rental payments and cost sharing, the planting of long term covers to improve the quality of water, control soil erosion, and enhance wildlife habitat. If the USDA determines that the landowner has breached a CRP contract, the landowner may lose the right to all future payments, be required to refund past payments received plus interest and be subject to liquidated damages. A developer may be liable to the landowner under contractual provisions of leases or easements which may require the developer to indemnify the landowner for such costs.

Final note

The USDA conservation programs have one thing in common; it is often difficult to discover whether a parcel of land is enrolled in a program. The USDA does not disclose enrollment information for privacy reasons, and only a handful of the programs require any form of public filing. This difficulty, coupled with the significant potential risks, make it vital for developers to obtain legal representation that is knowledgeable in the unique challenges caused by the interaction between these programs and wind developments.

Todd Ganos of the Forbes’ Great Speculations blog posted an excellent piece today entitled “Three Key Technologies for Energy Independence,” which outlines a few of the technologies that will play a significant role in the future of United States renewable energy.   Specifically, he highlights the importance of “super batteries” which can be charged quickly and efficiently, and super-conductive transmission lines which can transfer energy over vast distances with minimal energy losses.  As Mr. Ganos points out, the real benefit comes from the integration of these two technologies:

“The third technology is the combination of the first two:  that is, the rapid storage and rapid transmission of electrical energy.  It has been estimated that a single bolt of lightning has enough electrical energy to power the city of Los Angeles for a day.  The problem has always been our inability to capture and store that energy, Back To The Future notwithstanding.  It was the ultimate drink from the fire hose.

The combination of these two technologies has a way of funneling that stream.  Now consider the number of lightning strikes that occur in the Midwest in an average summer.  There are probably enough to power the entire United States for a year.”

I couldn’t agree more with Mr. Ganos’ analysis, but I would take it a step further.  Renewable energy will only gain a firm foothold in the United States when it reaches true cost parity with the cheapest traditional energy alternative, natural gas.  Thus, not only do we need to develop more effective energy storage and transmission alternatives, we need to ensure that the price tag of these technologies is low enough for renewable energy projects to be competitive with natural gas.

Have you ever wondered just how many renewable energy projects across the United States have been stalled due to permitting challenges and local landowner opposition?  Well, I’ve recently stumbled upon the wonderful “Project No Project” initiative put together by the U.S. Chamber of Commerce which attempts to answer that very question.

Per the site: “Project No Project assesses the broad range of energy projects that are being stalled, stopped, or outright killed nationwide due to ‘Not In My Back Yard’ (NIMBY) activism, a broken permitting process and a system that allows limitless challenges by opponents of development.”

The database tracks both renewable and traditional coal, gas and nuclear projects, which leads to some interesting opportunities for comparisons.  For example, would you like to hear one of the most shocking statements that you’ll come across all day?  According to the Chambers database, it is just as difficult to build a renewable energy project in the U.S. as it is to build a coal-fired power plant.  Just under half of the challenged projects the database tracks are renewable energy projects.

This groundbreaking initiative raises plenty of issues that I plan to discuss over the coming days, but for now, I highly recommend checking out the Project No Project website.  It’s well worth the time.

Oklahoma has undergone a significant legislative overhaul over the course of the last year to help advance its agenda of encouraging the development of renewable energy projects within the state.  A few of the most important legislative measures for project developers are as follows:

  • Oklahoma has established a voluntary Renewable Energy Standard (17 Okla. Stat. 801.1 et seq.), which calls for 15% of the total installed generation capacity in Oklahoma to be derived from renewable sources, including wind, by 2015.  Energy efficiency may be used to meet up to 25% of the goal.   For a primer on RES standards in the United States, see my post on the issue.
  • Oklahoma has passed SB 1787, codified as 60 Okla. Stat. 820.1 et seq., which states that access to the airspace is tied to the ownership of the land.  Thus, any wind or solar leasing arrangements associated with the airspace must be made with the landowner that owns the land below the air.
  • Oklahoma also recently passed HB 2973, codified as 17 Okla. Stat. 160.11 et seq., known as The Oklahoma Wind Energy Development Act.  This act specifies that, rather than utilizing a system of Renewable Energy Credits to track compliance with the state RES, each utility in Oklahoma must file a report with the OCC each year by March 1 which documents the total installed capacity and the energy source for each generation facilities, as well as the number of kilowatt-hours (kWh) generated by those facilities during the prior year.

The Oklahoma Wind Energy Development Act also provides rules related to decommissioning, payments, and insurance for wind projects, went into effect on January 1, 2011.  A few of the most significant provisions are as follows:

  • Equipment from wind energy facilities must be removed and the land, excluding roads, must be returned to its condition prior to the facility construction within one year of abandonment of a project.
  • Wind facility owners must file an estimate of the decommissioning costs and proof of financial security covering such costs after 15 years of operation.
  • For any wind energy facility that makes payments to the landowner dependent upon the amount of electricity produced, facility owners are required, within  to provide a statement to the landowner within 10 business days of the payment which explains the payment calculation to the landowner, allow for landowners to confirm the accuracy of payments and inspect records, and make records available to the state of Oklahoma.
  • The developer shall report to the OCC on an annual basis by March 1 of each calendar year the power generated from the facility, the nameplate capacity of the turbines, and the location of the wind turbines.
  • Wind energy facilities must have commercial general liability insurance, which must name the landowner as an insured party. Proof of such insurance must be provided to the landowner before construction begins.

Welcome to Part 2 of our outline of some of the various provisions of REC laws that legislators use to either strengthen or weaken particular aspects of the state RES, and how those slight changes can have significant impacts on your particular renewable project.  If you haven’t already done so, please take a look at Part 1, where we discussed how state legislatures use the concepts of “bundling” RECs and the underlying energy and “geographic sourcing” to tip the scale towards either incentivizing renewable projects within the state or minimizing the financial impact on utilities and ratepayers.

Today we will discuss two additional provisions which legislator’s use to define the impact of the state RES on renewable projects within the state: Rate Caps and Shelf-Life.

Rate Caps

It is often the case that energy generated from renewable projects is more expensive than energy generated from natural gas plants.  Because of this, when a utility either builds its own renewable project or purchase energy from a renewable project, its customers’ rates could increase.

With this fact in mind, many legislatures have drafted “rate caps” into their RES and REC laws.  Essentially, with a “rate cap” a utility is exempt from complying with the RES if doing so would cause its rates to increase by more than a set percentage over what it would have cost to generate that energy from a traditional source.

The impact of these rate caps is fairly obvious.  If this rate cap is set too low, it can severely undercut the effectiveness of a state’s RES, as utilities will not have to fully comply with the laws.  Ultimately, by looking at how high a particular state sets its rate cap can be a good way to tell how truly committed that state is to implementing an effective RES.

Shelf-Life

Another important aspect of REC laws that often flies under the radar is the concept of a REC’s “shelf-life.”  Most RES laws include an expiration date for RECs, or a date by which the utility must utilize a REC to comply with the RES.  After that date, the REC “shelf-life” will have lapsed and it will no longer be useable.

This concept of “shelf-life” can be extremely important, as it allows developers and utilities to “bank” their RECs in hopes that the price of the RECs will either rise or fall in the future, or if they believe the need and demand for those RECs will increase in the future.

Say, for example, that you are a developer of a large solar project in a state that has just passed a new RES.  New solar projects are being announced every day, so there does not look like there will be any shortage of RECs to meet the lowest threshold of the RES.  However, as the RES threshold increases over time, utilities will need more and more RECs to stay in compliance.

Because your solar facility can generate more energy than the market demands right now, you would want the ability to “bank” those excess RECs and have them still be useable for compliance in the later RES periods.  Otherwise, any excess RECs that you generate would go to waste.

In last week’s overview of Renewable Energy Standards, I briefly described the concept of Renewable Energy Credits (“RECs”).  Generally speaking, RECs are one of the most common mechanisms that states use to ensure that utilities are complying with the state’s RES.  A REC is essentially a certificate that gives the holder credit for developing a certain amount of energy from a renewable source.

However, because we are dealing with legislation and regulations, you can safely assume that the clean and easy description doesn’t tell the whole story.  With that in mind, over the next few days I’ll outline some of the various nuances of REC laws that legislators use to either strengthen or weaken particular aspects of the state RES, and how those slight changes can have significant impacts on your particular renewable project.

Because this is a large topic, I thought it would be best to break it into the following pieces:

  • Part 1  gives an overview of why states modify their REC laws and describes the concepts of “bundling” and “geographic sourcing.”
  • Part 2 will discuss the concepts of “rate caps” and the “shelf-life” of RECs.

Overview of REC modifications:  It’s politics, folks

Before we get into the nuts and bolts that make up the REC laws, it might be useful to step back and consider for a moment why a state would want to strengthen or weaken its REC requirements.

As we all know, there are a number of significant advantages to renewable energy: (1) reduced dependence on foreign oil; (2) greatly reduced environmental impacts; (3) sustainable energy source for the future; (4) economic development and job growth, etc.   However, because public utilities often have to make significant capital investments to generate renewable energy, it is possible that the average electricity rates in the state will increase as a result.

Every state addresses this balance between incentivizing renewable projects and avoiding increased electricity bills differently.  In essence, in the war over  the impact of the RES on renewable energy development in the state, the concepts that we will be discussing over the next few days make up the battleground.

Bundled Energy vs. RECs

One of the most basic principles that a legislature has to address when drafting a RES is whether it will allow RECs to be separated from the underlying energy.  This can be a difficult concept to wrap your head around, so let’s spend a moment fleshing it out.

Imagine a wind farm develops 1MW of energy.  That MW of energy is valuable two reasons.  First, the actual energy itself can be sold to a utility.  Second, because the energy was generated from a renewable resource, it counts towards compliance with the state’s RES.

This dual-value can be addressed by legislators in one of two ways when drafting the RES and REC laws.  They can either “bundle” the electricity and the REC together, or they can allow the REC to be sold separately from the underlying energy (or “unbundle” the REC from the energy).

If they “bundle” the energy and the RECs, a utility can only comply with the RES if it has purchased the actual energy from the renewable developer, like so:

If the energy and RECs are “unbundled”, the developer can sell the energy to one utility (for our purposes “Utility A”) and the REC to another (“Utility B”), like so:

Now, you may be asking yourself why unbundling doesn’t effectively double a developer’s profits, as they can sell the energy to count towards Utility A’s RES requirement, and sell the REC to count towards Utility B’s RES requirement.  States typically address this “double counting” by prohibiting the REC and the underlying energy from both being counted towards compliance with the state RES.

The actual impact of the bundling vs. unbundling decision on developers depends upon a number of factors.  If the RECs and energy are bundled, utilities are largely limited to purchasing energy from the renewable projects that are geographically close to their service area.  Therefore, if you are a developer that only has projects within a single state, you might be in favor of bundling because it limits the number of competing projects that can sell power to the utilities.

However, if you are a developer with projects scattered across the United States, you might prefer that the energy and RECs be unbundled.  That would allow you to sell your energy to utilities that are close to your projects, and sell the RECs to utilities in other states.

Geographic Sourcing

An issue that is often linked to bundling is “geographic sourcing.”  When drafting the RES, legislators have to decide whether and to what extent they should limit the geographic area for renewable projects that can comply with their RES.

For example, a RES statute can require that, in order to count towards the RES threshold, utilities must purchase renewable energy or RECs from projects located within the state.  Legislators might include this type of provision if they are particularly interested in encouraging renewable development within the state.

Let’s use Kansas as an example, because I really enjoy coloring it blue…

If the geographic sourcing provision requires that the energy be generated in Kansas, then obviously only Kansas projects will be allowed to count towards a utility’s RES threshold.

However, the RES statute could also require that the energy or RECs be purchased from projects located within the state, or that deliver their energy to utilities within the state.  This effectively expands the footprint to include renewable projects from the surrounding states.

Similarly, the RES statute could allow the energy or RECs to be purchased from any project located within a particular RTO…

Legislators could settle on either one of these provisions as a compromise position between those that are primarily interested in encouraging renewable energy development in the state and those that are worried about the cost impacts on the utilities and the ratepayers.

Finally, the legislators could draft the geographic sourcing provision very broadly, so the energy or RECs could be purchased from anywhere in the United States…

This is the position that is likely to lead to the least amount of renewable development within the state. The utilities will almost certainly be able to find RECs from resource-rich states like North or South Dakota which would be cheaper than those sold by in-state projects, and as a result the guaranteed revenue stream for in-state projects would dry up.  As a result, renewable energy companies that want to encourage development of project’s within a particular state tend to oppose particularly broad geographic sourcing provisions.

This concludes Part 1 of our overview of REC provisions, but be sure to stay tuned because tomorrow we will discuss the concepts of “rate caps” and “shelf-life.”

As this is a new blog, I thought it would be a good idea to have the first few posts give a broad overview of some of the big concepts in renewable energy law before diving into the more nuanced issues that are dominating the current conversation.  With that in mind, it seemed appropriate to start with one of the biggest forces driving the current renewable energy boom in the United States, Renewable Energy Standards.

While it may seem that governmental renewable energy incentives have gained an increasing amount of momentum in our national discourse in recent years, it may surprise you to know that some states have been on the cutting-edge of renewable energy promotion for just shy of three decades.  In fact, in 1983 Iowa became the first state to implement a program known as Renewable Energy Standards (“RESs”) to encourage the development of alternative energy projects within its borders.

Though today RES programs come in many varieties, they are essentially state legislative initiatives that require a certain threshold percentage of a utility’s total energy portfolio be generated from renewable sources (such as wind, solar, biomass, geothermal or other sources) by a certain date in the future.  For example, the state of Kansas requires all public utilities within the state to derive 10 percent of their total energy from renewable sources by the year 2011, 15 percent by the year 2016 and 20 percent by the year 2020.

Though this is a reasonably simple concept on paper, under most state RES programs, each utility does not necessarily have to construct renewable projects to meet these threshold amounts.  To account for utilities that do not currently have sufficient access to a renewable resource, or that have not yet developed renewable energy projects to take advantage of the resources that are available, most RES programs allow an alternative path to compliance through Renewable Energy Credits (“RECs”).  It is perhaps easiest to think of a REC as a piece of paper which states that the holder has generated 1 MW of renewable energy that can be counted toward satisfying the state RES.  If Utility A cannot generate enough renewable energy to meet the RES, they may purchase RECs from Utility B who has generated more than enough renewable energy to meet its RES threshold.

If the laws and regulations are drafted carefully, creating a market for these RECs allows states to exert additional pressure on utilities to build their own renewable projects, as this will inevitably be cheaper than purchasing RECs on the open market.  There are numerous issues that can strengthen or weaken the total impact of a RES standard as it is being drafted (such as rate caps, geographic sourcing, etc.), and I am planning on getting into these issues in more detail in an upcoming post.

With that background, you may be wondering how common these Renewable Energy Standards have become in the United States.  Currently, 36 states plus the District of Columbia and Puerto Rico have enacted some form of RES.  Because these RESs were implemented independently of one another, they vary significantly from state-to-state, with goals ranging from Hawaii’s 40% by 2030 to Arizona’s 15% by 2025.  Similarly, the penalties for not meeting the standards range significantly, from mandatory fines (the most common result) to no fines at all (as in North Dakota).

The wide-spread adoption of RES by the states has not gone unnoticed by the lawmakers in Washington.  However, though there have been several bills introduced by this and the previous Congress which would enact a federal RPS that must be followed by each state, as of this writing, it does not appear that any action will be taken any time soon.

Welcome to TheRenewableEnergyLawBlog.com!  My name is Luke Hagedorn, and I am an attorney based in Kansas City, MO that is primarily focused on renewable and traditional energy issues.

Over the course of my career, I have been struck by the fact that there is no one consistent body of law that renewable energy developers have to draw from in order to successfully launch a project.   Regardless of what type of technology your project utilizes (solar, wind, biomass, geothermal or whatever else is coming down the innovative technology pipeline), successfully turning the development plan into actual generated energy requires an understanding of a very wide swath of local, state, and federal laws and regulations.

While it may seem (and probably is) impossible to  truly understand all of these varied and complex legal issues, the goal of this blog is to present helpful descriptions of some of the most common legal obstacles that renewable projects are likely to face, provide updates about new or changing laws and regulations that might impact renewable projects, and occassionaly provide interviews with people in the industry that can speak to some of these issues.

With all that said, welcome!  I hope that this blog can provide some useful resources for anyone who is interested in continued innovation and success in this hugely important sector of the U.S. economy.