New BLM Wind and Solar Development Guidelines on Public Lands Expected Soon

With a goal to spur wind and solar development on public lands, the Bureau of Land Management (BLM) is expected to soon release a new rule that will streamline approval of new renewable energy projects.

First proposed for advance notice and comment in 2011, the rule would amend BLM regulations at 43 C.F.R. §§ 2800 and 2880 and implement, among other things, competitive leasing processes, developer incentives, revised rent and fee schedules and new megawatt (MW) capacity fees for wind and solar energy projects on BLM lands.[1]

The provisions depend on whether the project is located inside or outside “designated leasing areas” (DLAs), as determined by the BLM, which include “preferred areas” for development.[2]

Competitive Leasing

Lands within DLAs will be subject to competitive bidding procedures that provide for variable offsets to developers. Bidding developers may also pre-qualify for the offsets – limited to 20 percent of the high bid – by meeting factors set forth in a Notice of Competitive Offer.  While these factors will vary from lease to lease, they may include whether the developer has a power purchase or interconnection agreement in place for the project.[3]

Outside DLAs, the proposed rule amends existing regulations to create a competitive bidding process specifically applicable to wind and solar project development. Currently, BLM regulations only provide for competitive bidding where there are “competing applications for the same facility or system.”[4]  Under the new regulations, the BLM will be able to use a competitive bidding process to open new lands to wind and solar project development, with the winning bidder becoming a preferred applicant for the right-of-way to the project site.[5]


To incentivize bidding within DLAs, the proposed rule includes, among other incentives:

  • Reduced application fees, with a $5 per acre “nomination fee” within DLAs, as opposed to a $15 per acre application fee outside DLAs.
  • Streamlined processing and environmental review of projects within DLAs.
  • A 30-year fixed lease term within DLAs. Leases outside DLAs are available for up to 30-years, subject to adjustable terms and conditions.
  • A 10-year phase-in of the MW capacity fee, outlined below, rather than a three-year phase-in for facilities outside DLAs.
  • Standard bonding requirements of $10,000 per acre and $20,000 per acre for solar and wind energy developments, respectively. Outside DLAs, the bond requirement is based on the reclamation cost estimate minimum bond.[6]

Rent and Fees

Updated annual rent schedules are provided for in the proposed rule. These schedules are based on the approved acreage for the development, with a 10 percent encumbrance value for wind projects and a 100 percent encumbrance for solar projects.[7]

MW Capacity Fee

Additionally, the proposed rule establishes a MW capacity fee, based on the approved project MW, average wholesale energy prices, the federal rate of return per a 20-year treasury bond, and the project’s capacity factor, set at:

  • 20 percent for solar photovoltaic,
  • 25 percent for concentrated solar power,
  • 30 percent for concentrated solar power plus storage, and
  • 35 percent for wind.[8]

BLM explains that the MW capacity fee is intended to “capture the increased value of a solar or wind energy project on the public lands above the rural land value captured by the acreage rent.”[9]

BLM is implementing the wind and solar energy development rules pursuant to the President’s Climate Action Plan, announced in 2013, which uses “existing authorities to reduce carbon pollution, increase energy efficiency, expand renewable and other low-carbon energy sources and strengthen resilience to extreme weather and other climate impacts.”[10]

Since 2009, the BLM has approved an aggregate capacity of over 9,700 MW in solar, 4,700 MW in wind, and 600 MW in geothermal projects, for a total of approximately 15,000 MW of renewable energy.[11] In 2016 and 2017, BLM expects to review proposals for seven renewable energy projects, including five solar and two geothermal, with generation capacity of approximately 1,300 MW.[12]

We will continue to track this issue, and will report back with readers once the proposed rule has been finalized.

[1] 79 Fed. Reg. 59,022 (Sept. 30, 2014).

[2] Id.

[3] Id. at 59,022-023.

[4] Id. at 59,024.

[5] Id.

[6] See BLM, Competitive Solar and Wind Energy Leasing Regulations, available at

[7] 79 Fed. Reg. at 59,023.

[8]  Id.

[9] Id.

[10] BLM Press Release, Secretary Jewell Announces Competitive Leasing Policy to Encourage Solar and Wind Energy Development on Public Lands, Create Greater Certainty for Developers, Sept. 25 2014, available at

[11] See BLM, Renewable Energy Projects Approved Since the Beginning of Calendar Year 2009, available at

[12] See BLM, 2016-2017 Renewable Energy Projects, available at

California Continues Ambitious Regulation of Greenhouse Gas Emissions

Yesterday, Governor Jerry Brown signed Senate Bill (SB) 32 into law, extending and expanding California’s 10-year old greenhouse gas (GHG) emissions reductions mandate under Assembly Bill (AB) 32.  SB 32 provides for a 40% reduction in GHG emissions from 1990 levels by 2030.  This builds on AB 32’s existing mandate to reduce statewide emissions to 1990 levels by 2020.  In negotiations to pass SB 32 in the final weeks of the state legislative session, the bill was trimmed to add only one sentence to existing statute, to insert the 2030 target.  Left unaddressed was one question of the moment, can the cap and trade program authorized by AB 32 legally continue past 2020?  The California Air Resources Board (ARB) has its own answer to the question, the subject of this earlier post.  The courts will no doubt end up as the final arbiter.  Whether post-2020 GHG emissions reductions are met through a cap and trade program or other screws and hammers in ARB’s toolbox, the 2030 target is now written into law, rather than just Executive Order B-30-15.

The vital component of the compromise to pass SB 32 was companion bill AB 197.  AB 197 establishes legislative oversight of ARB’s actions to implement AB 32 and SB 32, by creating a Joint Legislative Committee on Climate Change Policies and adding two ex officio nonvoting members to the Board.  AB 197 also puts a new twist on ARB’s broad authority to adopt rules and regulations to achieve emissions reductions.  AB 32 requires ARB to achieve maximum technologically feasible and cost-effective emissions reductions from sources or categories of sources.  AB 197 further requires ARB to prioritize direct emissions reductions, including from large stationary sources and mobile sources, when adopting rules and regulations to achieve reductions.

In addition to headliner SB 32, the Legislature passed one additional bill with direct emissions reduction mandates, SB 1383.

Continue Reading

SDG&E Seeks Projects for Community Renewables Program

Via my colleague Xiaowan Mao:

On August 31, 2016, SDG&E will issue one ECR Request for Offers (“RFO”), seeking contracts with facilities that produce Renewable Portfolio Standard (RPS)-eligible energy for the purpose of implementing its ECR program. In this solicitation, SDG&E is seeking PPAs for the ECR program only. This solicitation is not requesting bids for feed-in-tariff projects (e.g. Re-MAT, Bio-MAT), GT projects, BioRAM or other RPS procurement activities that currently exist or are being contemplated.

Approved on September 28, 2013, Senate Bill (SB) 43[1] created the Green Tariff Shared Renewables (“GTSR”) program, which consists of a Green Tariff (“GT”) option and an Enhanced Community Renewables (“ECR”) component.[2]  San Diego Gas & Electric Company (“SDG&E”) plays an active role in implementing the GTSR program to: (1) make clean, renewable energy available to bundled utility customers, whether or not they own a home and/or can afford a significant capital investment; (2) increase the overall volume of renewable energy in the area of San Diego and (3) increase options for institutional, commercial and residential customers to meet their renewable energy goals. [3] Continue Reading

NARUC Accepting Comments on Draft Distributed Energy Resources Manual that Seeks to Guide Regulators Through Tricky Territory

The National Association of Regulatory Utility Commissioners (NARUC) recently issued a draft manual on distributed energy resources (DER) compensation to assist jurisdictions in navigating the challenges and policy considerations associated with this hot button issue. The release of the manual marks the first time NARUC has specifically weighed in on DER compensation issues.

DERs are generally smaller-scale electric generation facilities that are located close to customers and can be used to provide a portion or all of their immediate electricity needs, and can also be used by the distribution grid to reduce demand or increase supply. Examples of DERs include solar, wind, thermal, and storage technologies, among others.  Given their contrast to the traditional utility scale bulk electric generation model, state regulators across the country are struggling to determine how to appropriately compensate DERs.  The manual discusses the myriad questions associated with DER compensation, including the cost of integrating DERs with the grid, monetizing the benefits DER resources provide, and determining ownership of the resources.

Seeking to provide flexible advice to jurisdictions implementing DER compensation methodologies, the manual focuses on factors jurisdictions should consider in developing DER rates. It presents key questions for regulators to consider, including “What costs should be paid by DER and what should be recovered from base rates?” and “Does DER avoid utility infrastructure costs?” The manual also discusses the “divisive” issues of cost-shifting between users and non-users of DERs.

Compensation methodologies addressed by the manual include net energy metering (NEM); valuation methodologies, which include value of resource, value of service, and transactive energy; demand charges, fixed charges and minimum bills, standby and backup charges, and interconnection fees and metering charges. NARUC emphasizes that technological advances, such as advanced metering infrastructure, smart transformers, Advanced Distribution Metering Systems, and others can support the grid and integration of DERs, as well as accompanying DER compensation methodologies.

Stakeholders can submit comments on the draft manual by emailing, and comments will be accepted through September 2. The final version of the manual is expected in late November. A copy of the draft manual is available here (pdf).

Minnesota Power Requests Proposals for Wind; Solar, Demand Response & Customer Self-Generation to Follow

Minnesota Power released a Request for Proposals (RFP) yesterday for up to 300 MW of wind generation, with proposals due by September 7, 2016. A copy of the RFP and additional details are available at Minnesota Power also filed its press release with the Minnesota Public Utilities Commission (MPUC).

Minnesota Power will also release several more RFPs over the next few weeks for up to 300 MW of utility-scale solar generation and an unspecified amount of demand response and customer self-generation.

This series of RFPs comes on the heels of the MPUC’s Order issued last week approving and modifying Minnesota Power’s Integrated Resource Plan. The Order requires Minnesota Power to “initiate a competitive-bidding process to procure 100–300 MW of installed wind capacity” by the end of 2017. The Order also requires Minnesota Power to “acquire solar units of 11 MW by 2016, 12 MW by 2020, and 10 MW by 2025” and finds that “up to 100 MW of solar by 2022 is likely an economic resource for Minnesota Power’s system.” Minnesota Power must also “propose a demand-response competitive-bidding process within six months,” and “include a full analysis of all alternatives to natural gas, including renewables, energy efficiency, distributed generation, and demand response, for providing the energy and capacity sufficient to meet the Company’s needs” in its next resource plan. A copy of the Order is available here (pdf).

Minnesota Public Utilities Commission Approves Some Changes to Community Solar Program, Declines Other Changes

The Minnesota Public Utilities Commission (MPUC) approved several major changes to Xcel Energy’s Community Solar Garden (CSG) program yesterday, while also voting to maintain other aspects of the CSG program. Mike Hughlett of the Star Tribune has this report. The MPUC’s decisions are summarized below:

Bill Credit Rate

  • Declined to modify the Applicable Retail Rate at this time or take any action on further bill credit adders.
  • Decided to shift to the Value of Solar for CSGs submitted after next year, with some tweaks to lock in the inflation adjustment, weather normalization and include location specific avoided costs. The Department of Commerce is also tasked with determining whether there should be adders to the rate based on certain locational characteristics of the CSG or type of subscribers.

CSG Development

  • Retained the ban on co-location over 1-megawatt.
  • Eliminated the material upgrade limitation on interconnection.
  • Required Xcel to develop a CSG specifically for low-income customers by March 2017. Other proposals for increasing access for low-income customers are encouraged to file at that time as well.

Timeline for Completion

  • Extended the deadline for developers to complete CSGs by requiring that CSGs achieve Mechanical Completion within 24 months of Xcel finding the application Expedited Ready.
  • Broadened day-for-day extensions to include projects involved in Independent Engineering disputes with Xcel as well as other affected projects lower in the queue.
  • Required Xcel to provide, upon applicant’s request, written confirmation of the then-current Mechanical Completion deadline for an application, accounting for applicable day-to-day extensions.
  • Modified the definition of Force Majeure in the CSG tariff to extend the 24-month deadline by 6 months where there is a local government moratorium that prevents a CSG from obtaining a local permit, but excludes from the extension failure to seek a permit or other permitting delays.
  • Required projects that have been deemed complete but not expedited ready to become expedited ready in 60 days.

The MPUC declined to take action on consumer protection issues, such as how disclosures must be conveyed to subscribers, and will consider those issues at a later date.



What You Need to Know about the Proposed Revisions to California’s Cap and Trade Program

Late Tuesday, the California Air Resources Board (ARB) released draft amendments to California’s cap and trade regulation, including revisions to the current program in place through 2020, an extension of the program through 2030, and setting the stage for continued emissions reductions under the program through 2050. ARB’s proposed amendments come in the middle of a recent milieu of uncertainty:  pending litigation challenging the legality of the existing program, an opinion from the state Office of Legislative Counsel that ARB lacks authority under AB 32 to continue cap and trade past 2020, unprecedented weak demand at the most recent allowance auction, and legislation proposed in the California Senate to establish a statutory emissions reductions mandate for 2030 still in process this session.  With all of these balls in the air, ARB has doubled down and drafted regulations dropping the program’s emissions cap from 334.2 million metric tons (MMT) of CO2e in 2020 to 200.5 MMT in 2030, with major elements of the cap and trade regulation continuing in effect past 2020 to achieve the emissions reductions. Continue Reading

Eighth Circuit Panel Rules Minnesota Climate Change Law Unconstitutional

Today, the Eighth Circuit determined that the Next Generation Energy Act (“NGEA”), a Minnesota law that established power sector standards for carbon dioxide emissions, was unconstitutional (decision available here). In so doing, the Court affirmed the decision of District Court Judge Susan Nelson, whose 2014 decision we covered in “Court Declares Minnesota Coal Law Unconstitutional: Electrons Favor the Laws of Physics to Those of Governments.”

However, the Eighth Circuit panel arrived at Judge Nelson’s conclusion by a different route. Only one member of the panel – U.S. Circuit Judge James Loken – explicitly agreed with Nelson that the NGEA violated the dormant Commerce Clause. Judge Loken found that the NGEA’s “broad prohibitions plainly encompass non-Minnesota entities and transactions” and “regulate activity and transaction taking place wholly outside of Minnesota” because “when a non-Minnesota generating utility injects electricity into the MISO grid to meet its commitments to non-Minnesota customers, it cannot ensure that those electrons will not flow into and be consumed in Minnesota.  Likewise, non-Minnesota utilities that enter into power purchase agreements to serve non-Minnesota members cannot guarantee that the electricity eventually bid into the MISO markets pursuant to those agreements will not be imported into and consumed in Minnesota.”

By contrast, Judge Murphy disagreed with Judge Loken’s extraterritoriality analysis while Judge Colloton never even reached the dormant Commerce Clause question. Judge Murphy reasoned that because the NGEA’s importation prohibition “bans contracts for power from new large power plants, it thus bans wholesale sales of electric energy in interstate commerce” in direct contravention of the Federal Power Act’s grant of exclusive jurisdiction over “the transmission of electric energy in interstate commerce” to the Federal Energy Regulatory Commission.  Meanwhile, Judge Colloton reasoned that, “[b]y demanding offsets or allowance purchases from a North Dakota energy facility as a condition for contracting to provide power to Minnesota customers, Minnesota’s statute conflicts with the regulatory scheme that Congress designed in the Clean Air Act,” which allows each state to regulate emissions from sources within its borders through State Implementation Plans.

Since the panel was divided on the application of the dormant Commerce Clause to the NGEA, the permissible scope of state regulation of the energy sector remains uncertain. The concurrences in today’s decision in the Eighth Circuit add additional complexity and uncertainty by asserting that Minnesota’s law may be in conflict with the Clean Air Act or preempted by the Federal Power Act. In addition, and with respect to the question of whether state energy policy may run afoul of the extraterritorial doctrine of the dormant commerce clause, the Tenth Circuit recently came to a different conclusion in the face of a similar challenge to Colorado’s renewable portfolio standard (the Tenth Circuit decision can be found here). While the ultimate outcome is uncertain, the Eighth Circuit decision is sure to spark continued discussion and debate. Watch this space for updates as these issues move forward.




MN Court of Appeals Upholds PUC’s Community Solar Order

The Minnesota Court of Appeals filed its decision today affirming the Public Utilities Commission’s August 6, 2015 Order in the community solar garden proceeding, which adopted the partial settlement agreement between certain solar developers and Xcel Energy and decided several crucial aspects of Xcel’s community solar program, including the 5 MW cap on co-located gardens.  Sunrise Energy Ventures, LLC, a major developer in the community solar program, argued on appeal that the Commission engaged in improper and unlawful rulemaking, violated due process, and acted contrary to the Public Utility Regulatory Policies Act of 1978 (PURPA).

The Court of Appeals rejected each of Sunrise’s arguments. The Court found that the Commission had not engaged in rulemaking in its Order, but rather had made reasonable determinations consistent with the statute to modify the program in light of the “overwhelming response” of developers. The Court also found that the reservation letter between the developer and Xcel is not an enforceable contract and cannot serve as the basis for a substantive due process claim, and that the Commission did not violate Minnesota’s open-meeting law by taking a break to “talk to staff” and then immediately voting to adopt the co-location cap. Finally, the Court concluded that the Commission did not violate PURPA by allowing Xcel to refuse interconnection for a community solar garden that would require upgrades over $1 million, because Xcel’s Section 10 tariff already offers developers the ability to interconnect pursuant to PURPA.

Sunrise has 30 days to seek review of the decision from the Minnesota Supreme Court.

U.S. Fish and Wildlife Service Issues Proposed Changes to Eagle Permit Regulations, Opens 60-Day Comment Period

Today the U.S. Fish and Wildlife Service (Service) published notice in the Federal Register of proposed changes to its eagle permitting regulations (Proposed Rule).  Concurrent with the Proposed Rule, the Service issued a Draft Programmatic Environmental Impact Statement (DPEIS) analyzing the proposed changes under the National Environmental Policy Act (NEPA), and a Status Report that estimates size, productivity, and survival rates for bald and golden eagles, and provides recommendations on authorized take limits.  The Service is accepting comments on the Proposed Rule and the DPEIS until July 5, 2016.

Although we are still in the process of evaluating the entire package, the proposed changes represent a significant step forward for applicants seeking regulatory certainty through the eagle permitting process. Here’s a quick snapshot of the proposal:

(Re)extends maximum permit term to 30 years.  As we discussed in a previous post, in August 2015, the U.S. District Court for the Northern District of California set aside the 30-year tenure provision of the 2013 revisions to the eagle permit regulations on NEPA grounds, concluding that the Service had failed to demonstrate an adequate basis in the record for deciding not to prepare an Environmental Impact Statement or Environmental Assessment.  The Proposed Rule, now backed by NEPA analysis that evaluates the 30-year maximum term, once again extends the maximum term for eagle take permits from five to 30 years, subject to recurring five-year check-ins.  In the Federal Register notice, the Service acknowledges that the “5-year maximum permit term is unnecessarily burdensome for businesses engaged in long-term actions that have the potential to incidentally take bald or golden eagles over the lifetime of the activity.” Continue Reading