Tag Archives: Iou’s

The Hidden Cost of Solar + Energy Storage

By Jennifer Runyon, PennEnergy

Tom McCalmont, President McCalmont Engineering has been working on large solar projects for more than 15 years. The former CEO of Regrid Power, which in 2008 was purchased by Real Good Solar, his six-year old company McCalmont Engineering is fully dedicated to large solar and energy storage projects in California. “We do medium voltage interconnections, we do energy storage, we do NGOM meters, reverse-power relays, SCADA systems — so all of the things that people have problems with, we have expertise in,” he explained.

This expertise means that McCalmont understands what goes into interconnection and utility requirements for permitting and a little-known utility requirement called the NGOM, or “net-generation output meter” is making him very worried about the future of solar + energy storage projects, particularly in California.

“The issue that utilities are absolutely paranoid about is that people will use energy storage to somehow arbitrage energy rates,” explained McCalmont.

Because solar is net-metered and the owner is being paid at retail for exporting power to the grid, utilities are worried that if you add storage, you are going to sell all of your power at retail rates when they are high and buy it back when it is cheap, he explained. In other words, utilities are worried that system owners will sell more energy to the utility than their solar is actually producing because they could, in theory, draw down their energy storage system and put it on the grid.

“The technique they developed to stop this is the NGOM,” said McCalmont.

An NGOM is a second utility meter that you have to install when you have multiple sources of onsite generation, said McCalmont. “So if you have solar and storage or solar and a fuel cell or solar and a generator whatever you might have, if you have multiple sources of generation they want to make sure that that other source of generation can’t be used to get retail credit like you can with solar under net-metering.”

Read full article from PennEnergy

Inside California’s energy politics, the FERC Order 745 case, and the coming storage cost shift

By Gavin Bade, Utility Dive

[Editor’s Note: The following is part of Utility Dive’s coverage of the 2015 Energy Storage North America conference.]

For many power sector observers, California utilities are the ideal partners for forward-thinking regulators looking to adapt the utility business model to the 21st century. California’s investor-owned utilities proclaim their commitment to clean energy technologies demonstrating how they’ve surpassed mandates, accepted more rooftop solar, or integrated large amounts of storage.

Utility executives from San Diego Gas & Electric (SDG&E), Southern California Edison (SCE), and Pacific Gas & Electric (PG&E), provided apt examples in their keynotes at the Energy Storage North America conference. All these announcements could logically lead observers to conclude that California utilities have been proactive partners in helping set California’s ambitious clean energy goals. Not exactly, two veteran state legislators told Utility Dive at the conference.

Politics of renewable energy policy:

State Sen. Ben Hueso, chair of the Senate energy and utilities committee, ushered SB 350, the bill that set the state’s 50% RPS, through committee earlier this year. He said that the utilities have always fought hard against any mandates behind closed doors, whether it was SB 350 or earlier efforts. Former Assemblymember Nancy Skinner, echoed Hueso’s observations, but said that the power industry doesn’t behave much differently than others in this respect. “No industry likes mandates,” she said, noting that it took three legislative sessions to usher through the state’s previous 33% RPS, which was met with utility pressure behind closed doors.

California’s new RPS, by contrast, was authored and passed in one legislative session, a feat that Skinner said cannot be overstated. Not only does the bill increase the renewables portfolio standard to 50% by 2030, it also specifically calls on utilities to deploy energy storage and combines the renewables goal with an aggressive efficiency standard. So what changed to get such an aggressive bill passed so quickly?

…Clifford Rechtschaffen, a senior advisor to Brown, said the most important thing was that, in the end, “all of the utilities with the tiny exception of some northern California power agencies that had some qualms, they all supported SB 350.” Rechtschaffen said that while the utilities may have shown some resistance as the bill was working its way through the legislature, most of their concerns were operational in nature. “They weren’t quarreling with the notion that we needed to get to 50%,” he said. “They had concerns about how best to do it — some of which we agree with and others which we aren’t completely in line with, but we’re working on those. Storage is a big part of the solution.”

The role of storage in California’s renewable energy economy:

In a keynote panel discussion the California policymakers highlighted energy storage as the technology that can make 50% renewables and beyond possible for California. Once you get to that level of renewables, Rechtschaffen said, “storage is absolutely critical for grid integration. There’s no arguing about that.”

But the situation for storage, especially in the eyes of utilities, wasn’t always so rosy, Rechtschaffen said. Back in 2014, the state’s IOUs were resistant to the PUC’s mandate to deploy over 1,300 MW of storage on the grid by 2020, worried that the technology wasn’t ready and that it would “put storage in a bad light.”

In reality, the opposite happened, and SCE started off the storage procurements by buying 264 MW, when it was only compelled to purchase 50 MW at the time. For the California policymakers, it was a validation of the power of mandates to drive innovation in the power sector.

Read full article from Utility Dive

Related article: Why energy storage is key to a future with ‘no more gas turbines’ (Utility Dive) – Oct. 15, 2015

PG&E Surpasses 10,000 Solar Customer Milestones in Bakersfield, Fresno and San Jose

Pacific Gas and Electric Company (PG&E) today celebrated connecting 10,000 solar customers each in three of California’s largest cities – Bakersfield, Fresno and San Jose – as part of PG&E’s milestone of connecting the 175,000th solar customer to its electric grid. These achievements, along with a new survey finding that 25 percent of Californians are considering solar panels for their home, underscore how quickly California residents are blazing a trail for solar adoption supporting a clean energy future.

“PG&E proudly supports customer choice when it comes to renewable energy. We connect thousands of new customer-owned solar installations to our grid every month with some of the fastest connection speeds in the nation. This rooftop solar power supplies clean energy to our customers and communities, and is a key part of California’s energy future,” said PG&E’s Senior Vice President and Chief Customer Officer, Laurie Giammona.

The growth is especially apparent in Bakersfield, Fresno and San Jose as each city celebrates 10,000 local solar customers connected to PG&E’s electric grid, highlighting the innovative spirit of these communities as they invest in a sustainable tomorrow. Each city has a powerful solar story to tell:

Read full press release from PG&E

Inside California’s rate restructuring plan and the battle for fixed charges looming over it

By Herman K. Trabish, Utility Dive

California regulators united behind a new rate framework before the Independence Day holiday, but lurking behind the decision is a bigger one for utilities and renewables advocates alike.

The California Public Utilities Commission (CPUC) voted unanimously on July 3 to flatten the current four-tiered electricity rate system to two tiers, push for time-of-use (TOU) rates by 2019, and make other noteworthy changes to how utilities bill customers. California’s investor owned utilities, San Diego Gas and Electric (SDG&E), Southern California Edison (SCE), and Pacific Gas and Electric (PG&E), hailed it as a step toward making rates fair. The state’s utility watchdog condemned the decision, the ratepayer advocate is concerned about it, and solar advocates are studying it warily. All recognize a decision on fixed monthly charges was deferred.

Reaction from utilities: SDG&E

SDG&E Spokesperson Amber Albrecht:

  • “We were hoping for more immediate relief but we are on the right path. This new rate structure inserts more fairness and transparency into electric utility bills,” and “brings rates more in line with the true cost of service.” The new rate design will not take away customers’ incentive to be more efficient about their electricity consumption.
  • SDG&E tier 3 and 4 customers now pay “136% more than those in the lowest tier” and those in the lowest tier “pay 15% less than the cost of the basic delivery of electricity.” With the new two tier plan, the higher users’ bills will come down while the lower users’ monthly bills will likely edge up to around $2 to $5.
  • In 2017, the SUE will go into effect; it is expected to be levied on about 2% of SDG&E customers. “Each IOU’s rates will be slightly different but the basic pattern will be the same.”
  • “This is the first step in a broader discussion about the modern electricity bill. Now we know what the framework will be. Moving forward, the CPUC will have a number of proceedings and make a number of decisions on things like net energy metering.”

Reaction from utilities: Southern California Edison

SCE Director of Pricing Design Russ Garwacki:

  • “Our estimates find the high usage customers are paying $600 million in subsidies per year to low usage customers. Even when fully implemented in 2019, there will still be significant subsidies left in the rate structure but this does provide relief.” The new plan corrects an overpayment by higher usage customers without asking lower usage customers to subsidize them.
  • Incentives for conservation and solar: The new rate design will not take away customers’ incentive to be more efficient about their electricity consumption. Lower rates for tier 2 customers will reduce their incentive to be more efficient, but higher rates for tier 1 customers provide them with an incentive to conserve. “There is a point-counterpoint. And that extends to the incentive to go solar. Because the tiers are flattened and the rates are more closely tied to cost, more middle usage customers will consider solar. A recent CPUC energy division report found solar adoption is higher under flatter tiers.”
  • Minimum bill/fixed charges: The decision “was a compromise and balancing of a large number of issues,”—the minimum bill is an example. It is not, as characterized, a replacement for a fixed charge. The commission decided to deal with the fixed charge in 2019, but the implication of the minimum bill is that even the lowest usage customers should pay “some fair share” for the distribution system. “They viewed the minimum bill as a first step toward fixed charges. That is not what we asked for but it is a step in the right direction.”
  • TOU rates: Rates follow cost with a TOU structure and it is important to provide that cost signal for residential customers. SCE just completed transitioning all its non-residential customers to TOU rates. Studies are beginning to demonstrate that, over time, usage shifts and the load profile flattens in response to them. SCE wanted an opt-in to TOU rates, but the commission disagreed.

Reaction: Solar Industry

  • Solar Energy Industries Association: “Most importantly, we’re glad to see that the commission has not adopted fixed charges – and recognized that there’s no evidence to justify them. These rates are workable, although we believe a greater tier differential would more appropriately reflect the costs of high energy users.” The flattened tiers “should significantly mitigate any concerns the utilities have about cost shifts among ratepayers.”
  • Solar Electric Power Association: “This decision is an important part of the process to incorporate more distributed resources into the system.” But rate design “needs to be articulated as part of a broader conversation on the utility business models.”
  • SolarCity: “The proposed decision achieves the utilities’ goal of flattening the tiers while also making the entire rate system more equitable for ratepayers. If net metering remains in place, this decision will continue to allow Californians to go solar.”

Read full article from Utility Dive

California’s Distributed Energy Grid Plans: The Next Steps

By Jeff St. John, Greentech Media

Last week, after a year of behind-the-scenes work and much public debate, California’s big three investor-owned utilities turned in their long-awaited distribution resource plans (DRPs). These DRPs are essentially blueprints for how Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric are going to merge rooftop solar, behind-the-meter energy storage, plug-in electric vehicles and other distributed energy resources (DERs) into their day-to-day grid operations and long-range distribution grid planning and investment regimes.

Each California utility has created mapping tools that show how much capacity is available on each distribution circuit for new DER interconnection, for instance — something that could be very useful for distributed energy developers. All three utilities have also agreed on a common set of measures for how DERs could help shore up grid capacity, increase reliability, serve system-wide needs, and otherwise stand in for costly utility upgrades. And each has laid out how it plans to fold these DRP methodologies into their general rate cases (GRCs), the once-every-three-years process that determines how much each can charge its customers for its capital and operating costs for the coming years.

Many questions remain about how to determine which combination of DERs will meet the least-cost models that utilities use to rank their distribution grid upgrades, and what kinds of new capabilities grid-supporting DERs will need to have to serve as replacements for utility investments. There’s also much uncertainty about how DERs serving as stand-ins for grid infrastructure should be paid for, and how their costs and benefits should be shared. These issues are of major interest for solar-storage combinations from SolarCity and Tesla, SunEdison and Green Charge Networks, Sungevity and Sonnenbatterie, and SunPower and partners Stem and Sunverge, which see an opportunity for earning grid services revenues as stand-ins for distribution grid investments. They’re also important for the commercial building and residential energy management platform providers looking for ways to tap California’s emerging opportunities for distributed demand response.

These costs and values wouldn’t just flow from utilities and their customers to DER providers—each utility’s DRP asks the California Public Utilities Commission (CPUC) for permission to spend lots of money on beefing up their own systems to enable their visions. Southern California Edison alone is estimating its DRP-related capital expenditures could add up to $347 million to $560 million over the next three years, for example, and PG&E and SDG&E will also be seeking new funding, though they haven’t yet specified how much.

All three DRPs add up to nearly 1,000 pages, which makes it hard to summarize all the next steps they contain, but here are a few highlights of the challenges to come.

Read full article from Greentech Media

Related articles: How California’s biggest utilities plan to integrate distributed resources (Utility Dive)