Author Archives Laura Arnold

IURC Announces Technical Conference on Net Metering Implementation, SEA 309

Posted by Laura Arnold / June 16, 2017 / Posted in 2017 Indiana General Assembly, solar, Uncategorized, wind / No Comments

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IURC to Address Questions Regarding the Implementation of Net Metering Legislation, SEA 309

Requests Comments, Questions for July 20 Technical Conference

FOR IMMEDIATE RELEASE

Indianapolis (June 15, 2017) - Following questions from those involved in the installation of solar panels and other net metering equipment, the Indiana Utility Regulatory Commission (IURC) is hosting a Technical Conference as a forum to address questions and concerns regarding the implementation of the newly-enacted Indiana Code chapter 8-1-40 (Senate Enrolled Act [SEA] 309) on net metering and distributed generation, particularly the Dec. 31, 2017 deadline for the 30-year grandfather provision.

The Technical Conference agenda will be based on questions and comments submitted from the public and those involved in the installation of solar panels and other net metering equipment seeking clarification on the implementation of SEA 309. Any questions or comments must be submitted in writing either via email toURCComments@urc.in.gov or via U.S. mail to General Counsel Beth Heline, Indiana Utility Regulatory Commission, 101 W. Washington Street, Suite 1500 E., Indianapolis, IN 46204 no later than June 28, 2017. All written input will be posted on the IURC’s website.

The Technical Conference will take place on July 20, 2017 from 2:00 to 4:00 p.m. in the IURC judicial courtroom 222, on the mezzanine level of the PNC Center, 101 W. Washington Street, Indianapolis, Indiana 46204.

Please note: The discussion at the Technical Conference will be only on the short-term implementation of Indiana Code chapter 8-1-40, and not the policy decision made by the Indiana General Assembly to enact this statute.

Individuals interested in attending the Technical Conference or watching the live stream can find more information here.

About the Indiana Utility Regulatory Commission (Commission) The Indiana Utility Regulatory Commission is a fact-finding body that hears evidence in cases filed before it and makes decisions based on the evidence presented in those cases. An advocate of neither the public nor the utilities, the Commission is required by state statute to make decisions that balance the interests of all parties to ensure the utilities provide safe and reliable service at just and reasonable rates.

The Commission also serves as a resource to the legislature, executive branch, state agencies, and the public by providing information regarding Indiana’s utilities and the regulatory process. In addition, Commission members and staff are actively involved with regional, national, and federal organizations regarding utility issues affecting Indiana. For more information, please visitwww.in.gov/iurc.

Media Contact:

Stephanie Hodgin, (317) 233-4723, stehodgin@urc.in.gov

EIA: Wind, solar composed 10% of March generation

Posted by Laura Arnold / June 15, 2017 / Posted in solar, wind / No Comments

EIA: Wind, solar composed 10% of March generation

AUTHOR: Robert Walton @TeamWetDog

PUBLISHED: June 15, 2017

Dive Brief:

Renewable generation has cracked a milestone, according to the U.S. Energy Information Administration, with solar and wind providing 10% of the country's generation last month.
Those resources will probably provide 10% again for April, EIA said, while making up about 7% of the United States generation in 2016.
Wind generation contributed about 400% more than solar, as almost all states have more of the former resource. Of states with significant amounts of renewable energy, only California and Arizona had more solar generation than wind in 2016.

Dive Insight:

The milestone is seasonal, but non-hydro renewables have cracked 10% of the United States generation. While the double-digit portion will likely wane as demand ramps up in the hot summer months, the achievement is a reminder of the rapid growth of green energy.

Wind-powered generating units in Texas and Oklahoma often have their highest output in spring months, while wind-powered generators in California are more likely to have their highest output in summer months.
Monthly solar output is highest in the summer months, regardless of location, because of the greater number of daylight hours.

Source: U.S. Energy Information Administration

In 2016, Texas accounted for the largest total amount of non-hydro renewable electricity generation—but almost all of it came from wind. Texas generates more wind energy than any other state, EIA noted, but as a share of the state’s total electricity generation, wind and solar output was highest in Iowa (37% of 2016 generation).

Wind and solar resources provided at least 20% of electricity in six other states last year.

While the United States is not likely to reach 10% renewables on an annual basis yet, the country is getting close. According to EIA's most recent Short-Term Energy Outlook, non-hydropower renewables are forecast to provide 9% of electricity generation in 2017 and nearly 10% in 2018.

EIA said it expects coal's generation share to rise from 30% in 2016 to 31% in 2017 and 2018. Natural gas' share will decline from 34% in 2016, to less than 32% in 2017 and 2018, "as a result of higher expected natural gas prices."

The agency said generation share of hydropower is forecast to be nearly 8% in 2017 and 7% in 2018. The nuclear share of generation remains just under 20% in both 2017 and 2018.

Fossil fuel interests seek to kneecap NC’s growing solar industry

Posted by Laura Arnold / June 13, 2017 / Posted in Uncategorized / No Comments

Fossil fuel interests seek to kneecap North Carolina’s growing solar industry

Solar companies created thousands of jobs on the back of a decades-old law. Now, the state’s utility wants to rewrite it.

By Molly Taft, Laura A. Shepard, and Monika Sharma

Alongside Highway 401 in northern North Carolina is a 21st-century twist on a classic rural scene. A few miles outside of Roxboro, sheep graze among 5,000 panels at the Person County Solar Park, keeping the grass tidy on the rural installation.

Fields like these aren’t just scenic settings for roadtripping tourists to snap photos. Solar has “been some of the only economic development to happen in rural North Carolina in the last 30 years,” explained Richard Harkrader, CEO of a local solar company.

For companies like Harkrader’s Carolina Solar Energy, the Tar Heel State is a great place to do business. Abundant sunshine, ample support for clean energy, and smart public policy have spurred the rapid growth of solar. Today, North Carolina boasts more solar capacity than every state except California. In the first quarter of 2017, North Carolina added more solar than any other state, and its solar industry employs more people than Wake Forest University.

North Carolina solar jobs by county. CREDIT: Solar Foundation

But, despite — or perhaps because of — its success, solar is facing a battle in the state.

North Carolina solar companies owe much of their success to an obscure federal law passed in the wake of the 1973 OPEC oil crisis, when shortages produced lines around the block at gas stations and tipped the U.S. economy into recession. At that time, Americans got about one-sixth of their electrical power from burning petroleum, much of it imported from the Middle East. In a bid for greater energy independence, lawmakers approved The Public Utility Regulatory Policy of 1978, known as PURPA.

Among other things, PURPA required utilities to buy renewable power from independent producers if it cost no more than electricity from the conventional power plants owned by the utility. The aim was to source more power from small renewable facilities, like the Person County Solar Park, easing demand for electricity from coal, gas, and — in particular — petroleum-fired power plants.

In the 1970s, PURPA didn’t do much for renewables. In the era of bellbottoms and disco, cheap solar power was a distant dream, and the fledgling solar industry was peddling clunky technology at sky-high prices. But solar has taken off over the past decade, and PURPA has become far more important — especially in North Carolina. Some 92 percent of the state’s solar projects have been supported by the decades-old law.

While PURPA is a federal law, state regulators have a lot of wiggle room when it comes to implementation. North Carolina regulators have historically required longer contracts from utilities, making solar an especially attractive option. That’s because while solar poses high upfront costs, it pays for itself over the long term through savings on fuel. With conventional power plants, by contrast, operators continue to pay for coal or gas over the life of the plant.

But just when PURPA is beginning to do what its drafters intended, utilities in North Carolina want to hobble the policy.

Utilities make money in part by owning and operating power plants. But when utilities are required to source power from independently owned solar arrays, their own coal- and gas-fired power plants generate less electricity — and less revenue. Moreover, the need for additional capacity is shrinking. North Carolina’s electricity demand has flattened in recent years.

Duke Energy, the largest utility in North Carolina, is now leading the charge against PURPA. Duke currently is required to buy power from any cost-competitive small-scale solar installation. The utility wants to change the policy so that it would solicit bids to build new solar arrays only when it needs additional generating capacity.

Duke Energy’s solar farm in Conetoe, North Carolina. CREDIT: Duke Energy

Duke also wants to shorten power purchase agreements so that the company isn’t locked into long-term solar power agreements if the price of coal or gas falls, or if a new solar installation proves cheaper.

“Their argument is that renewables will be cheaper than they are today, so [Duke] shouldn’t have to pay” for power from existing solar installations under PURPA, said Chris Carmody, executive director of North Carolina Clean Energy Business Alliance. “But they’ll turn around and establish a 10-year contract to buy natural gas, which is volatile and has heavy fluctuation. Utility-scale solar has no fluctuation — once the project is built, that’s it.”

Duke also claims that solar farms are flooding the grid with power on sunny days. This forces the utility to ramp down and then ramp up coal- and gas-fired power plants, which is less efficient than letting generators run at a constant rate. Complicating matters, developers are mostly building solar farms in the rural, eastern part of the state, far from hydroelectric storage systems that could bank surplus solar power.

But renewable-energy advocates say this isn’t a problem with solar. It’s a problem with the aging power grid — some places haven’t seen an update in more than 50 years. North Carolina, they contend, needs better transmission lines and more energy storage.

Solar companies are hopeful they can reach an agreement with utilities. Steve Levitas, a lawyer for Cypress Creek, said that the solar industry “has been trying to work toward consensus” with Duke, and is open to new policies that allow solar to continue its impressive growth.

Last week, the state House passed a sweeping, bipartisan, Duke-backed energy bill that would curtail PURPA while creating new incentives for solar. The bill would shorten contracts for solar installations, cap the volume of renewable energy that utilities are required to buy from third parties, and create a competitive bidding process for new solar projects. At the same time, the bill allows ratepayers to buy power directly from community solar arrays, and it would establish a rebate program for rooftop solar, among other changes. On balance, the bill appears to favor the utility. Solar firms have largely kept quiet on the measure.

Solar companies say they are accustomed to the sweeping changes in public policy. Harkrader said that, for small firms, “new challenges and new markets” are a normal part of the equation. “We call it the solar coaster.”

Nexus Media is a syndicated newswire covering climate, energy, policy, art and culture.

SEIA: Principles for the Evolution of Net Energy Metering and Rate Design

Posted by Laura Arnold / June 13, 2017 / Posted in Uncategorized / No Comments

Principles for the Evolution of Net Energy Metering and Rate Design

Download a PDF of this document

This document provides a consensus view of solar advocates for regulators and stakeholders considering rate design and compensation for distributed solar generation, including potential alternatives to net energy metering. Traditional net energy metering (NEM) is fundamentally a bill credit that represents the full retail value of distributed electricity delivered to the distribution system, and has been a critical policy for valuing and enabling distributed generation. As penetration of solar and other distributed energy resources increases, states and utilities have begun to examine, and in some cases implement, alternative rate and compensation mechanisms.

The principles below are intended to be consistent with the imperative of public utility commissions and energy service providers to maintain reliable, cost-effective service to all customers while protecting the rights of customers to generate their own energy in a manner that provides both system and public benefits, including environmental protection and economic development.

They provide high level criteria for the conditions under which states may wish to consider alternatives to NEM, and high level principles for what distributed solar compensation mechanisms should look like where alternatives to NEM are appropriately considered.

Specifically the paper is organized into four sections:

Basic principles, foundational to considerations for considering rate design and compensation for distributed solar generation.
Criteria and Conditions for the Consideration of Alternatives to Net Energy Metering
Guiding Principles for Solar Rate Design, and
Guiding principles for Alternative Compensation

Basic Principles^[1]

Customers have a right to reduce their consumption of grid-supplied electricity with energy efficiency, demand response, storage, or clean distributed generation. Thus, a customer should always receive the full retail price value for behind the meter choices that reduce grid-supplied energy consumption, whether installing energy efficiency measures, or consuming on-site generation.
Solar rate design and compensation mechanisms should support customer economics to invest in solar that are sustainable, consistent with the full stream of values provided by the system, and fair to all stakeholders.
Net energy metering is a proven mechanism for driving solar deployment, liked and understood by customers, and is preferred in most circumstances.
Most studies have shown that the benefits of distributed solar generation equal or exceed costs to the utility or other customers where penetration is low. Assertions that current or future solar customers have shifted or will shift costs to others, and/or create new costs, must be demonstrated with valid, transparent data that reflects the values, avoided utility costs, and results of deploying solar at the distribution level, as well as the utility cost of providing service.
- A cost of service study that fails to consider the benefits of distributed solar generation (DSG) cannot establish a cost-shift.
- Regulators should require an independent cost-benefit analysis before considering substantial rate design or compensation changes based on cost-shift assertions.
- The benefits of existing distributed solar should be recognized when considering any asserted cost shift.
- The time frame for review of costs and benefits must be on par with the life of the particular type of Distributed Energy Resources (DER) assets, e.g. 20-30 years, and be forward looking, not a snapshot of one year of sunk costs as is typical in a general rate case (GRC).
- Regulators should seek to ensure in GRC, Integrated Resource Plans (IRP) and other relevant proceedings that future avoided costs found in cost/benefit studies related to DSG and other DER are actually avoided (e.g. the canceled PG&E transmission projects saving $200 million and the Brooklyn-Queens Demand Management project avoiding costly upgrades).
- Since some level of quantifiable cross-subsidization is inherent in all rate design, particularly for large diverse classes, an independent finding of a material cost shift should be required before regulators authorize substantial changes to rates or rate design.
Net metering can be accomplished through simple energy netting, or in combination with monetary compensation depending on the rate design:
- For non-time differentiated residential and small commercial rates, i.e. rates based on energy consumed at any time, energy netting on a kWh basis over the billing period is good policy particularly at low to moderate penetration levels, and pending demonstration of a material impact.
- For time-differentiated rates, monetary compensation is an accepted feature of some current NEM structures and may be necessary to preserve the full value of excess energy.
Opportunities for retail customers and third party DSG and other DER developers to provide additional services (e.g. voltage & frequency regulation, VAR support) should be encouraged, especially in States moving towards a service oriented utility/regulatory model, though access to markets, and appropriate compensation mechanisms.
Consideration of creating separate rate classes for customers that choose to utilize DER technologies must be based upon a factual demonstration of significantly different load and cost characteristics using publicly available actual data, and should generally be discouraged as potentially discriminatory.

Criteria and Conditions for the Consideration of Alternatives to Net Energy Metering

Penetration level should be the leading threshold criteria for consideration of alternatives to NEM.
Customers who installed solar under net metering should be grandfathered for a reasonable period of time. Customers have a reasonable expectation that rate structures (as opposed to rates themselves) will not change dramatically. Gradualism is an important rate design principle, and a gradual phase-in to any new compensation methodology should be provided at the end of the grandfathering period.
Process: Early, i.e. pre-litigation, data collection and analysis under the guidance of the State Commission can provide opportunities for collaboration toward the development of a factual basis for future changes to rate designs, compensation, and other mechanisms.
Simplicity, Gradualism, and Predictability: The simplicity of the NEM compensation mechanism facilitates customer adoption of distributed solar. Any future design should consider customer needs for simplicity and any changes should be applied gradually and predictably.
Shadow billing and voluntary pilot programs to analyze opportunities to increase the benefits that net metered systems provide to the grid, and to assess the actual impacts of proposed changes (for example, time-of-use (TOU) pilot programs) should be considered before making substantial mandatory changes to compensation or rate design.
Hold harmless policies should be in place for low-to-moderate income (LMI) customers.
NEM imports & exports are generally netted monthly in most states, and trued up annually. More granular netting generally reduces solar customer economics, but may be worthy of consideration when penetration levels increase, or in conjunction with deployment of other DERs such as storage.

Guiding Principles for Solar Rate Design

Rate design should seek to send clear price signals to customers that encourage sustainable, cost-effective investments in solar and complementary technologies.
Rate designs should not create barriers to the deployment of distributed solar generation or DER technologies other than solar.
Rate designs that provide greater incentives for DER technology deployment (e.g. more steeply inverted block rates) can be considered to encourage early adoption of efficiency, distributed generation and storage technologies.
Rate designs that emphasize temporal cost-causation (time-varying, critical peak pricing and critical peak rebates) are generally consistent with solar deployment, and may be quite beneficial to customer and system alike when solar is integrated with DERs like storage or demand response.
Rate designs that emphasize higher fixed (e.g. customer, service and facility or basic service) charges than necessary for recovery of strictly customer-related costs like service drop, billing, and metering, or quasi-fixed (e.g. mandatory residential demand) charges do not reflect cost causation, disproportionately impact low and moderate income customers, and should be discouraged.
Regulatory review of rate design alternatives should consider impacts on low-income customers; e.g. utility fixed or quasi-fixed charge proposals usually put solar and efficiency technologies further out of reach of LMI customers.
Any consideration of standby, backup or other supplemental charges for solar customers must (1) be consistent with PURPA requirements, (2) be based upon a customer’s ability to control self-generation similar to a conventional fossil resource (e.g. diesel or natural gas), and (3) reflect the probability of customer generation unavailability in the development of any rates.

Guiding principles for Alternative Compensation

A fair value of solar (or “stacked benefit”) compensation rate can be considered for distributed solar generation exports, at higher penetration levels. Such value should be determined taking into account both short term and long term (life of system) benefits of distributed solar generation.

Buy all/Sell all (BA/SA or “VOST”) compensation approaches should be at the option of the retail customer, i.e. VOST should not be the only customer option. Critical considerations impacting system economics and the ability to finance include the frequency and effect of future changes to the value proposition. In addition, consideration must be given to the effect on customers of the lack of energy hedging (customer-generated solar energy does not offset the customer’s utility-supplied energy).

Alternative Compensation methods should take into account the efficacy of integrating solar with other forms of DER (e.g. storage) in the grid of the future, assuring that barriers to new technologies are not created.

Solar specific surcharges such as installed capacity fees are discriminatory, generally unsupported by facts, and impede distributed solar generation system economics.

[1] The Criteria and Principles herein do not distinguish between regulated and restructured states. However, rate designs, cost allocation methods, avoided costs and cost/benefit analyses must recognize whether the utility is distribution-only or vertically integrated.

Solar reform bill sailing to N.C. House floor vote Wednesday

Posted by Laura Arnold / June 08, 2017 / Posted in solar / No Comments

Solar reform bill sailing to N.C. House floor vote Wednesday

Jun 6, 2017, 2:45pm EDT; Updated Jun 6, 2017, 3:47pm EDT

The bill reforming state solar and renewable energy regulations is slated to hit the… more

NANCY PIERCE

Two N.C. House committees approved a bill mandating a competitive-bidding process for utility-scale solar construction and encouraging development of rooftop and community solar projects, sending it on to a first vote on the House floor Wednesday morning.

The House Energy and Public Utilities Committee, where the bill originated, passed it unanimously Tuesday morning and sent it on to the House Finance Committee for a vote at noon.

While there were a few questions raised and some skepticism expressed, the tone at the energy committee was almost unfailingly positive. Donald Bryson, state director for conservative group Americans for Prosperity, gave a short statement during the public comments on the bill. Though AFP had announced reservations about the bill on Monday, Bryson told the committee it “does far more good than harm” and said his group supports it.

Saving $850 million

On the much more liberal side was Rep. Pricey Harrison, D-Guilford, a committee member and longtime champion of solar and renewables in the state. She wondered aloud whether limits the bill imposes on new programs that would allow leasing arrangements for residential solar and development of community solar programs (neither currently permitted by state law) will prove too strict.

But she ended saying, “this bill does a lot of good for renewable energy in the state,” and supported it.

During the committee hearing, Kendal Bowman, Duke's vice president for regulatory affairs and policy, said that Duke estimates it would save about $850 million in solar power purchases over the next decade if the bill is adopted.

To arrive at that figure, Duke estimated how much solar power it would purchase from new projects over the next 10 years. It projected how much it would pay if the state's current regulations remained in place as well as its cost if the competitive bidding and other more market-based procedures in the bill were implemented. Those savings would be passed on to customers.

Direct hand

The brief and generally friendly sessions in the Legislative Office Building contrasted with the arduous — and sometimes contentious — nine months of negotiations that went into producing the bill.

The state’s dominant utility, Charlotte-based Duke Energy (NYSE:DUK), and the solar industry and its advocates were long at loggerheads over a consensus bill. Eventually, energy committee chairs Reps. John Szoka and Dean Arp took a direct hand in forging the consensus bill. The agreement they worked out with the various sides was used as a substitute for the text of an innocuous bill in their committee that the pair had introduced in early April.

It settled at least parts of the battle between Duke and the solar industry by giving utilities more control over where and when new solar projects are built. It shortens the terms for solar contracts and significantly reduces the size of projects that qualify.

But it also establishes a bidding system for new solar construction. That is administered by an independent third party, assuring solar developers that they will not be completely at the mercy of Duke.

Encouraging rooftop solar

Duke’s two North Carolina utilities must agree to purchase about 2,660 megawatts of solar through the system through roughly the end of 2020.

And those projects that go through the bid process will be able to have the longer contract terms that utility-scale solar developers say they need to make their projects financeable.

It also has several provisions that could boost what a close-to-moribund rooftop solar industry in the state. It requires Duke’s utilities to develop a rebate program for a residential and commercial rooftop solar program. And it would allow solar installers to lease projects to customers, to reduce upfront costs for roof top solar.

Leasing programs would be limited to 1% of peak demand for each utility.

Community solar

And the bill sets up rules for community solar programs. Each utility’s program would be limited to 20 megawatts total, and it must offer the power to customers in its service area. No solar farm in the program could be larger than 5 megawatts.

The limits on those programs were one of the concerns raised by Harrison. But the leasing limit, at 1% of peak demand at Duke’s two utilities, would be 250 megawatts, says Duke spokesman Randy Wheeless. Across of all of North Carolina, Duke currently has only 50 megawatts of rooftop solar on its system. So Wheeless says there is plenty of room for growth.

North Carolina has long lagged in residential and commercial solar despite its strong utility-scale solar development. Low utility rates and some policy issues surrounding net metering have made solar less attractive here than in many top solar states such as California — the only state with more solar on the grid than North Carolina — Arizona and New Jersey.