10 predictions for the electric sector in 2014
The U.S. electric sector faces radical change in 2014. From the rise of disruptive technologies to paradigm shifts in policy and regulation, every industry player today is confronting a wholly uncertain future. With that in mind, two of our writers took time over the holiday break to reflect on state of the electric sector and gaze into the proverbial crystal ball.
But we’re not the only ones trying to divine the future. Utility Dive is asking electric utility execs to share their opinions on the state of the industry today. Please take our 2014 Benchmark Survey and forward it to your colleagues.
Without further ado, here are our 10 predictions for 2014.
1. Energy storage will break through
Davide Savenije: Energy storage has long been billed as the Holy Grail of the electric sector, but it is not yet a reality. From immediately dispatchable demand response to the storage of intermittently generated solar and wind power, the high potential of energy storage has never been in question. Arbitrage opportunities abound for stakeholders, but the technology has simply never come close to being cost-effective. Signs are that’s changing.
For one, Navigant Research projects that the global energy storage market for solar and wind will grow from $150 million today to $10.3 billion over the next 10 years, to the tune of nearly 40,000 MW in total capacity by 2023 in its base scenario.
There are opportunities for utilities, but they should also watch out: the distributed energy storage market is heating up fast. Look for early adopter regions such as California, New York, Hawaii, Colorado and New England to lead in this emerging market. More affluent ratepayers in those parts of the country have already shown the desire to bypass their electric utility with the installation of rooftop solar systems, and batteries are the just next logical step in that equation. (For example, bundled solar-and-storage systems help solar owners defeat high demand charges.)
The potential was always there, but now the market is catching up. SolarCity’s move to bundle solar systems with Tesla batteries for commercial customers was precedent-setting. Following SolarCity’s lead, SunPower recently announced it will bundle solar and storage for residential customers in the coming years. Expect the customer-sited storage market to be a big opportunity in the coming years.
Utilities are already worried about the threat of distributed storage, as shown by California utilities Edison International, Sempra Energy and Pacific Gas & Electric refusing to net meter stored solar because “the rules are in a state of flux” and “technically, a customer who now has [battery-backed solar] may not qualify for net energy metering under current rules,” according to a spokeswoman for San Diego Gas & Electric (a Sempra Energy utility).
Expect the wildly successful no-money-down, third-party-owned model popularized by rooftop solar installers to also gain traction in the storage sector. Look for battery startup Stem, which recently received $5 million from Jigar Shah’s venture capital firm and $15 million from General Electric, Iberdrola and others, to pioneer this model in the next few years.
This is not to say that grid-scale storage doesn’t have potential. Economies of scale dictate that grid-scale storage (and grid-scale wind and solar) will be more cost-effective than distributed systems may take longer for utilities to implement it on a wide scale.
In 2013, we saw the California Public Utility Commission set the first energy storage mandate for U.S. utilities, single-handedly turning grid-scale storage (and not just one or two MW, but 1,325 MW by 2020) into a reality. California has long been the example that other forward-thinking states follow and is now effectively guaranteeing a market for vendors in California (and, eventually, other early adopter states).
Puerto Rico has already followed suit in mandating energy storage for new renewable projects (of which there are 600 MW in the pipeline), stipulating that plants from now on must be able provide 45% of the plant’s maximum capacity for 60 seconds, and 30% of its rated capacity for 10 minutes.
All this goes to show that the U.S. power grid’s future will not be about added capacity, but more flexible capacity. Expect regulators and policymakers to work to incentivize the market in that direction in 2014.
2. A new normal for electric sales growth
Ethan Howland: While there will be pockets of load growth, especially in areas with expanding oil and gas production, efficiency programs and distributed generation will keep a lid on electric sales in 2014.
Overall, electric sales have dropped in the U.S. in four of the last five years and are expected to fall this year, according to a report by the Energy Information Administration.
The two key factors affecting sales that we’ll be watching are energy efficiency spending and the rise of rooftop solar panels.
Energy efficiency is taking a toll on sales. Electric energy efficiency budgets jumped from $2.6 billion in 2008 to nearly $6 billion in 2012, according to a report from the American Council for an Energy Efficient Economy. Savings increased from 18.4 million MWh, or 0.5% of retail sales, in 2010 to 22.9 million MWh, or 0.6% of retail sales, in 2011.
Efficiency spending and savings are expected to keep climbing, according to a report from the Lawrence Berkeley National Laboratory. Under a mid-case scenario, annual efficiency budgets will climb to $8.1 billion by 2025, driven by state energy efficiency standards, the report said. At the same time, savings will climb to 0.76% of annual retail sales, potentially offsetting sales growth.
But several factors could lead to higher-than-expected sales. The economy could take off. Low natural gas prices could cut into the cost savings potential for efficiency, and the harvesting of low-hanging fruit like the now-ubiquitous compact fluorescent bulbs could make it hard to keep up the pace of savings.
But that’s unlikely. On top of rising efficiency spending, rooftop solar is growing quickly. Slowly but surely, distributed generation is taking a bite out of sales. For one, Arizona Public Service estimates that rooftop solar is eating into its sales by about 0.5% a year. What will happen if solar prices drop even more? Certainly in areas with relatively high electric rates, solar will become more appealing.
Any potential opportunities for electric sales growth appear outmatched right now by the rise of energy efficiency and distributed energy resources. The EIA expects electricity demand growth to grow very slowly through 2040 compared to the past. The lack of significant electric sales growth is a fundamental threat to the traditional utility business model, predicated as it is on the sale of electricity. It’s a new normal to which utilities will seek to adapt.
3. Coming soon to a Public Utility Commission near you: Net metering battles!
Davide Savenije: A significant precedent was set for net metering in 2013, when the Arizona Corporation Commission (ACC) imposed the first rooftop solar fee in the U.S. — albeit at a relatively modest $0.70/kW. Utilities will continue to fight net metering policies in the regulatory arena, though some regulators (such as the ACC) have indicated the issues raised by rooftop solar are best answered through the electric rate-setting process.
Solar proponents will doubtless fight back. In most regions, solar has the majority of public support, and this could tip the scales in solar’s favor, particularly in places like California and New York, where there is a rapidly expanding market for residential solar. That being said, the way in which current utility regulatory models are set up inherently penalizes non-solar owning ratepayers for solar-friendly net metering policies Therefore, utilities will seek other, creative ways to counter solar-friendly net metering policies, such as fixed grid connect fees.
Based on the precedent set by the ACC, expect state regulators to start setting distributed generation fees to balance out net metering. Expect the net metering issue to come up next in Colorado, where Xcel’s net metering proposal has come before regulators as part of its renewable energy standard compliance plan, and Georgia, where Georgia Power dropped its proposed solar fee but promised to take up the issue again soon. It will also be interesting to see what happens in California in 2014. California has long been the standard bearer on forward-looking energy policies, and lawmakers recently gave regulators the power to set distributed generation fees up to $10/month. If California acts, look for similarly progressive states to follow its lead, at least eventually.
As of right now, however, there is no widely accepted approach to the issue. Both solar advocates and utilities nationwide have too much at stake to compromise, so expect state battles to heat up and make lots of headlines next year. A resolution to the net metering question could of course be reached (it is, after all is said and done, a mathematical equation we’re talking about), but don’t expect that happen anytime soon. The battles in 2014 will ultimately serve as indicators of where state net metering policies are eventually headed.
4. Renewable subsidies will fade
Ethan Howland: Renewable developers have benefited from a range of federal and state subsidies and supports over the years. But that may start changing as renewable technologies have come closer to grid parity and as governments take a sharp look at their budgets.
The federal production tax credit (PTC) for wind expired at the end of 2013. Typically, when a PTC expires there is an intense lobbying effort to have it reinstated. But this year seems different. This is partly because the most recent PTC was changed so that projects that started construction by December 31 were eligible for the credit. In the past, wind farms needed to be operating by the deadline to be eligible. So this year, the pressure was off. Wind developers have scores of projects that they will build over the next year or two. Many of those wind projects were the least-cost option for new generation, when including for the PTC.
Meanwhile, the 30% federal investment tax credit for solar runs through 2016.
But there area also signs the federal incentive system could change soon. Last month, Senate Finance Committee Chairman Max Baucus, a Democrat, proposed revamping how federal renewable-related incentives would work. Under a draft bill, federal incentives would be roughly cut in half and based on greenhouse gas emissions.
The American Wind Energy Association praised Baucus for his leadership on the issue, but the Solar Energy Industries Association raised concerns about the draft bill. Expect a tough debate on the federal incentives (assuming Congress moves on the issue).
At the state level, regulatory commissions have been reducing incentives for rooftop solar as the price of photovoltaics has dropped. The Long Island Power Authority in August reduced its solar rebates and the Arizona Corporation Commission has cut rebates for solar. Expect to see more cuts to state rebate programs in 2014.
5. Utilities face life-or-death decision on distributed generation
Davide Savenije: Distributed generation presents a clear and present danger to the traditional utility business model.
A landmark Edison Electric Institute report on the disruptive challenges put it best (if you haven’t read this, put it at the top of your recommended reading list): “Due to the variable nature of renewable [distributed energy resources], there is a perception that customers will always need to remain on the grid,” it reads. “While we would expect customers to remain on the grid until a fully viable and economic distributed non-variable resource is available, one can imagine a day when battery storage technology or micro turbines could allow customers to be electric grid independent. To put this into perspective, who would have believed 10 years ago that traditional wire line telephone customers could economically ‘cut the cord?'”
Utilities will need to make a choice in 2014: resist the threat or seize the opportunity. (Or do nothing.) Realistically, expect a combination of the first two in order for utilities to help facilitate a business model transition that’s partly on utilities’ own terms.
But, you might be asking, how can utilities “seize the opportunity?” There are a few potential models they can explore:
- Create deregulated subsidiaries to install rooftop solar systems outside of their territory.
- Create solar leasing programs to install utility-owned rooftop solar systems for ratepayers.
- Invest capital in rooftop solar installers
- Partner with rooftop solar installers to sell systems to ratepayers
After a record year for residential solar installations, expect smart utilities to adopt elements of the most successful distributed solar models. I expect distributed generation to continue its rapid ascension in the marketplace, but I don’t see it replacing utilities (or at least completely). Economies of scale dictate that utility-scale renewables will be more economical. That said, rooftop solar panels coupled with cost-effective storage could snare anywhere between 20-50% of the market in the long-term.
Some utilities are already acting on the opportunity, including: Sempra Energy, Duke Energy, Pacific Gas & Electric, Sacramento Municipal Utility District, Integrys, NextEra, Edison Internation and PSE&G. But many others aren’t.
If they don’t invest, expect distributed generation providers “to pick off all their highest value customers,” says Dan Yates, CEO of Opower, one of the major players in the energy efficiency space. As this happens (in fact, it has already started to), the utility’s grid costs pro rata will rise and “they will have less and less capacity to afford more expensive distribution, transmission and generation because they’ll become less and less cost effective,” says Yates. “Then, the distributed generation guys will just go creeping down the stack and we’ll end up in a distributed generation world with no centralized utility.”
Utilities are inherently slow-to-act organizations, making decisions on 10-year timelines. But the rise of DG is making that difficult and utilities should embrace flexibility if they want to survive. The grid is changing and it only follows that utilities will need to adapt their business models. The faster that a utility acts on distributed generation, the more chance they will have to thrive off the changes.
“We don’t know which companies will helm the future of the electricity industry,” says David Crane, CEO of NRG Energy, the largest independent power producer and retail electricity provider in the U.S. “The only thing I am sure of is that our sector can no longer defend the status quo. Put simply, we can’t act like utility companies anymore.”
In 2014, utilities must and will make decisions that will define not only their fate, but that of the industry as a whole.
6. A major Western power line will be built
Ethan Howland: After years of development, at least one major interstate transmission project will start construction this year in the West.
There are roughly 20 major interstate transmission projects under development in the West, along with dozens of smaller instate proposals, according to the Western Electricity Coordinating Council.
The two most likely projects to see construction get underway are the 500-kV SunZia project that would run from eastern New Mexico to Arizona and the 600-kV TransWest Express project from Wyoming to southern Nevada. Both projects aim to deliver renewable generation to California. Both projects have been under development for about five years. But, while close to the finish line, neither project is out of the regulatory woods just yet.
Getting a major power line underway in the West could make it easier for other projects to move ahead as well. Although California has adopted policies favoring in-state renewables, power line developers contend that wind can be delivered from states as far away as Wyoming at competitive prices. They argue that out-of-state renewables will provide greater geographic diversity, smoothing out energy production. New Mexico and Wyoming also have natural gas reserves that could be used by power plants to firm up the delivery of renewables to California.
7. Paradigm shift in energy policy will accelerate fossil fuel phase-out
Davide Savenije: The Environmental Protection Agency (EPA) announced carbon pollution standards for new power plants in 2013, effectively ending any plans to add new coal capacity to the grid. But the real blow to coal power will come in 2014, when the EPA announces carbon pollution standards for existing power plants in June. Expect those standards to greatly accelerate the retirement of coal plants across the U.S. The costs of compliance will make it nearly impossible to keep coal in the long-term mix.
While the standards for new plants essentially require carbon capture and storage technology (which is far from a cost-effective reality, at the moment), expect the coming standards for existing plants to be completely different. Ron Binz, President Obama’s defeated choice to lead the Federal Energy Regulatory Commission, believes EPA regulations for existing power plants are the “great underestimated change that is about to engulf U.S. regulation.”
Binz believes the standards will force utilities to “reduce the intensity of greenhouse gas emissions per kilowatt-hours” through the institution of carbon pricing. “The cost is on the manufacturer and the benefits go to society” because the standard is addressing something “which is not priced in electricity,” Binz says.
This is part of a greater paradigm shift in energy policy and regulation. As the U.S. heads towards a clean and sustainable energy future, policymakers are starting to adopt new mechanisms to turn this future into a reality. It’s no longer about cheap and reliable electricity; it’s about public health and an earth that our children’s children can inherit. Look for this transcendental shift to become only more pronounced in 2014 and beyond.
8. Utilities will sign up for Western energy imbalance market
Ethan Howland: The energy imbalance market being created by the California Independent System Operator (ISO) and PacifiCorp will attract more participants by the time it is launched in September.
Under the planned model, the ISO will automatically dispatch generation every five minutes in its footprint and the balancing authorities controlled by PacifiCorp. In much of the West, balancing authorities use manual dispatch on an hourly basis. The market will increase efficiency and help integrate variable renewable generation like wind and solar.
NV Energy has said it plans to join the market and utilities like Xcel Energy are interested in joining. The more balancing authorities that join, the more efficient the market will be.
But not all utilities want to join. In particular, public power utilities are leery of Federal Energy Regulatory Commission oversight. Instead, utilities and transmission owners in the Northwest are considering efforts that will make grid operations more efficient, but fall short of a full blown energy imbalance market.
Expect both efforts to move ahead in 2014.
9. Utilities will grow green pricing programs
Davide Savenije: Utilities in 2014 are facing the choice of meeting demand for clean energy or losing their customers.
The issue is pretty simple. A growing number of utility customers large and small want to use clean energy for reasons financial and not. If their utility can provide it to them—whether in the form of distributed resources or renewable energy credits—then great. If not, these customers will look to bypass the utility. It’s a trend we saw a lot of in 2013.
On the residential side, customers seeking clean energy are driven largely by non-financial reasons such as energy independence. While individual customers may defect from the utility and install solar panels, an even greater danger for utilities is when an entire community decides to bypass the utility. We’re seeing this primarily on the more progressive West Coast (and this shows why green pricing programs are thriving there):
- Sonoma Clean Power is set to become California’s second community choice aggregator with about 20,000 customers lined up ahead of its launch next year. It expects to reach 140,000 by 2017.
- San Francisco is exploring options to bypass Pacific Gas & Electric to meet demand for renewable energy. This includes joining Marin Clean Energy, which is California’s only and largest community aggregator with about 90,000 customers.
Meanwhile, large commercial and industrial (C&I) customers are going green for largely financial and political reasons. For utilities, this threat is even greater, as C&I customers wield more political influence than a group of individual customers and make up a much larger percentage of their revenue requirement:
- Google put pressure on Public Service Co. of Oklahoma to design a new renewable energy offering for commercial and industrial customers.
- Duke Energy is developing a green pricing program for large energy users in North Carolina, also after pressure from Google.
Expect utilities to grow their green pricing programs and rooftop solar leasing options to mitigate these risks in 2014.
10. Capital spending peaks and puts pressure on rates
Ethan Howland: Utilities are at the peak of a construction cycle and will look for ways to ease the pain of rate hikes by spreading the increases over several years. In states that have already seen a series of rate increases, regulators will also be looking for ways to minimize rate hikes, perhaps by taking a tougher look at dubious investments.
At the same time that capital expenditures are peaking, electric sales growth has slowed (see our prediction on sales growth). In the past, rapid sales growth helped spread out the effect of revenue hikes. Slow growth accentuates the revenue increases.
Regulators have already been approving lower return on equity (ROE) levels for utilities, which can sharply reduce utility revenue. The average approved ROE in the third quarter was 10.05%, according to a recent report on rate cases by Edison Electric Institute, which represents investor-owned utilities. “Falling interest rates account for much of this trend,” the report said. “Attempts by state commissions to moderate rate increases during times of financial hardship for many customers have also contributed in recent years.”
Moody’s Investors Service expects capital expenditures for 34 utility holding companies to dip slightly to $69 billion this year from $70 billion in 2013, according to a recent report. The ratings agency expects capex to fall to $65 billion in 2015. Moody’s notes that new environmental standards like potential rules for carbon emissions could cause capital spending to start rising again, but not until after 2016.
Cutting costs does not appear to be a fruitful opportunity for utilities. Starting with the recession in 2008, utilities focused hard on cutting their operations and maintenance costs. Employees were let go, positions were left unfilled and non-core businesses were sold. It is unclear how much more belt-tightening is possible.