By now, it’s become cliché to suggest that the utility industry is on the brink of a massive transformation.

Analysts told us this would happen — the traditional electric utility model would be upended, and utilities would need to adjust their business models to operate in a new energy future. Now, with plummeting prices for renewables and energy storage, the finalization of the nation's first carbon regulations, and the proliferation of distributed energy resources, changes are taking hold faster than many expected. The electric sector is no longer simply anticipating a revolution — depending on where you are, it is embroiled in one today.

To help guide you through the uncertain waters of the industry, we have identified ten trendlines that are shaping the future of the power sector. The selection isn’t meant to be exhaustive, nor are we trying to rank one trend over another, but we hope the following list shows where we see the industry going.

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10. Coal power in decline

For many power companies and politicians, the single most noticeable trend in the utility industry is the steady retirement of coal-fired power plants.

About 25,000 MW of coal capacity has been retired since 2009, according to SNL Energy, and there are already formal plans to retire about the same amount of coal capacity by 2022. Of those retired plants, most were nudged into unprofitability by historically low natural gas prices and the EPA’s Mercury and Air Toxics Standards (MATS), which put strict limits on emissions of mercury, lead, and other coal plant pollutants. Environmental activism has also played a significant role, with lawyers from the Sierra Club and other green groups teaming up with business interests across the nation to push for renewables and other clean resources instead of new coal.

All that means the U.S. coal burn is now lower than it has been since the early 1980s, and the situation for fossil generators isn’t improving. The EPA’s Clean Power Plan, finalized in August, is expected to further downsize the nation’s coal power fleet in the coming decades. In an analysis of the draft plan earlier this year, the EIA predicted the federal carbon regulations would contribute to 90 GW of coal retirements by 2030, along with other factors such as renewables proliferation, gas prices, and other EPA rules. [Update: We have replaced the EIA chart originally included in this post with the below chart from the Sierra Club including all coal retirements completed or proposed by Nov. 1, 2015.]

While the outlook for coal power certainly isn’t bright, it’s not necessarily doomsday: The EPA still expects the resource to be a major fuel for electricity generation in 2030 and beyond, and the Department of Energy continues to push “clean coal” technology, despite well-documented setbacks at major U.S. plants.

9. Natural gas is growing fast

In the near-term, coal’s loss appears to be natural gas’ gain. As market conditions and regulations push older coal generators into retirement, utilities looking to add reliable capacity quickly are increasingly looking to gas plants.

Wind and solar, while growing quickly, still represent a relatively small slice of the U.S. fuel mix and only generate electricity under certain weather conditions. For utilities looking to ease integration of these resources and add baseload capacity, a combined cycle gas plant offers a relatively quick and cheap solution that meets EPA rules on carbon and other pollutants. NERC estimates that the U.S. would need to add about 150 GW of natural gas generation by 2030 to comply with the EPA’s proposed Clean Power Plan.

Those estimates — and other, similarly bullish ones from EIA — for gas capacity additions have yet to be updated based on the finalized Clean Power Plan. Although the EPA put less emphasis on gas as a bridge fuel in its final rule, analysts still expect it to grow steadily over the coming decade.

But while the future looks bright for now, the trouble for gas may come during the later years of Clean Power Plan compliance. EIA estimates show the trend for gas additions switching to retirements between 2020 and 2030 as prices for renewable energy drop further. If natural gas prices rise from their historic lows, that switch could come sooner rather than later.

8. Renewables reaching grid parity

For years, the primary argument against renewable energy was that it isn’t cost effective. Today, that line of reasoning is becoming increasingly obsolete. In many regions, wind and solar — especially at utility scale — are reaching grid parity and often pricing out more traditional generation resources.

For renewable energy observers, this trend isn’t new to 2015. Around this time last year, the financial firm Lazard released its annual study of global energy costs from a variety of fuel sources. It found that for utility-scale projects, both wind and solar are cost-competitive with traditional generation technologies without subsidies, and face fewer regulatory hurdles and market uncertainties than new nuclear or “clean coal” plants.  

Those estimates take prices from renewable energy projects around the world, but there are more localized indicators as well. In July, NV Energy signed a PPA for what many observers believe is the cheapest electricity in America — a $0.0387/kWh deal with a utility-scale solar facility built by First Solar. That record came not even a week after Austin Energy signed a PPA for 1.2 GW of solar under 4 cents/kWh, which was labeled the “cheapest solar ever” at the time.

A recent GTM Research report found that 40% of the more than 16 GW of utility-scale solar currently planned for construction was chosen “primarily due to solar’s economic competitiveness with fossil-fuel alternatives.” And earlier this year, Deutsche Bank released an analysis that found solar energy will reach grid parity in at least 36 states in 2016.

Wind energy is also making waves in regional markets. Analysts credit cheap wind, along with natural gas, for pushing a host of older nuclear and coal plants to unprofitable status in deregulated markets. That dynamic has led utilities like Exelon, AEP, and, most recently, FirstEnergy, to solicit ratepayer support for their older coal and nuclear plants, arguing they are essential to reliability.

As wind turbines get taller and blades get longer, analysts expect the price for the resource to continue to drop, opening up previously undeveloped areas like the American Southeast to wind growth. Due to those declines, the Department of Energy estimates that wind could be the nation’s single greatest source of energy by 2050, comprising up to 35% of the fuel mix.

7. Utilities face growing load defection

EEI’s “Disruptive Challenges” white paper introduced the electric industry to the threat of the “utility death spiral." Nearly three years later, utilities across the nation are still struggling with how to deal with load defection as some customers bypass their local utility for their electricity needs.

Part of that is due to the rapid proliferation of rooftop solar, especially in a few select markets such as Hawaii and California. According to a recent GTM Research report, residential solar grew 70% in the second quarter of 2015 over where it was during the same period in 2014. The vast majority of residential sector growth came from California, New York, Massachusetts, New Jersey and Maryland, but Q2 2015 was also the first quarter that 10 individual states each installed more than 10 MW of residential solar. Far from troubling only utilities in places like Hawaii and California, the threat of load defection is now spreading nationwide.

While rooftop solar penetration is increasing, demand-side management and energy storage technologies are on the verge of making it easier for consumers to move their electric demand to times when electric prices are lower, at least under certain rate structures. As the Rocky Mountain Institute pointed out in a report on what it calls “demand flexibility,” the combination of these load management strategies with rooftop solar installations, especially in locations with high electricity costs, could lead a larger number of customers to purchase less power from their utility — and some even to cut the cord altogether.

If that weren’t enough, utilities are also increasingly dealing with the “other death spiral” — large customers bypassing their utility company to buy renewable energy directly from a supplier. Utility PPAs accounted for 40% of the wind capacity commissioned in 2014, down from 75% and 76% in in 2013 and 2012, respectively, while corporate solar capacity increased 28%.

The combination of the growth in residential solar with the jump in commercial renewable PPAs could be enough to trouble some utilities, but the challenge of load defection doesn’t stop there. Across the nation, power companies have been dealing with stagnant load growth since the beginning of the Great Recession in 2008. While electricity consumption used to closely follow GDP growth, increased investments in efficiency and demand side management have seen the two factors diverge in recent years.

Analysts don’t expect the threat of load defection to abate any time soon. Instead, utilities are increasingly finding new opportunities for revenue in the very sectors threatening their business models.

6. Utilities getting in on the solar game

In response to increasing load defection and consumer demand for clean energy, a number of utilities are moving into the solar industry, both in the utility-scale and rooftop markets.

One common strategy for utility companies is to form an unregulated renewables developer for the utility-scale market. In June, Utility Dive profiled Duke Energy Renewables, which has grown into a national developer in under a decade, but there are a slew of other examples as well. Southern Power, traditionally known as a fossil fuel generator, now has 20 renewables projects across the country.

But expansion in utility-owned renewables isn’t limited to large-scale facilities. Increasingly, utilities are looking to enter the rooftop market as well. In July, Georgia Power announced it would offer rooftop solar through an unregulated subsidiary, Arizona utilities APS and TEP have pilot programs for utility-owned solar, and CPS Energy recently launched a solar hosting program. As utilities look to both control the placement of DERs on their grid and capture more revenue from renewables, it’s likely the number of them offering solar options of their own will expand.

Utility involvement in the residential solar sector doesn’t sit well with many installers, who fear power companies will use their market clout and consumer relationships to shut solar companies out of the market. Solar advocates have fought for market rules that prevent utilities from owning DERs directly and instead make them the platforms for third parties to deploy various grid resources — much like the REV initiative envisions in New York.

If there’s one thing the two sides can agree on, however, it is community shared solar, which allows customers without suitable rooftops for solar to buy a few modules on a larger array. For utilities, it gets away from the controversies surrounding net metering and rate design (see below), and allows installer to access a previously untapped part of the market. GTM Research estimates that community solar installations will grow sevenfold from 2014 to 2016.

5. Debates over rate design reforms and value of DERs are heating up

In addition to getting into the solar industry themselves, a number of utilities are responding to the rise of distributed generation by altering their rate designs to properly value distributed resources.

The trend was brought on largely by the practice of retail net metering, which pays utility customers with solar the retail rate for the electricity they send back to the grid. Many utilities think this rate of remuneration is too high, and have proposed to compensate solar owners at what they see as a more equitable rate.

More than 20 states today have debates raging about increases in fixed charges on utility bills. Power companies pushing them say they’re essential to cover grid infrastructure costs, while solar advocates say they unfairly diminish the value of rooftop arrays.

Beyond fixed charges, a number of states have regulatory proceedings open to determine the value of distributed resources to the grid, including California, Hawaii, Minnesota, and Maine. While each differs in its approach, all the state initiatives and academic papers on the subject have the same goal: to devise a strategy for valuing DERs in various locations and times on the grid. As you can imagine, that’s a really difficult thing to do, but given that utility executives see DERs as their greatest business opportunity, expect more states and companies to jump into the DER valuation debate in the near future.

4. Utilities are modernizing the grid

With all the new utility-scale and distributed renewable capacity coming on the grid, there’s a growing need for utilities to upgrade and modernize their transmission and distribution grids. NERC estimated this spring that the nation will need to add about 7,000 miles of transmission lines to comply with the Clean Power Plan, and that number is likely to climb higher due to the increased emphasis on renewable resources the EPA wrote into the finalized plan. Utilities that supply growing load centers, like oil and gas drilling operations, have already felt the need to build out their transmission lines.

But modernizing the grid means more than installing new lines — the modernized grid must handle two-way power flows, whereas in the past all the power in the system flowed one-way only from the bulk power level down to customer.

Last year, the International Energy Agency estimated that the U.S. would need to spend $2.1 trillion by 2035 on grid technologies and infrastructure to prepare for higher penetrations of renewables, and utilities are largely responding. EIA numbers show that the nation’s power companies have been steadily increasing their investments in smart grid technologies in recent years, despite stagnating load growth in many locations.

Many of the regulatory initiatives underway to help determine the value of DERs also order their state’s utilities to prepare their distribution grids for increased penetrations of distributed resources. The grid of the future may look very different than the one today, with utilities across the nation completing their smart meter rollouts, installing two-way grid communication devices, and experimenting with new grid resources like energy storage.

3. Utilities buying into storage    

As utilities look to optimize their distribution grids and integrate more renewables, few technologies hold as much promise as energy storage.

For years, analysts have theorized a future where giant, grid-scale batteries provide a bevy of services for the grid. Teamed up with wind and solar, they could help smooth peaks and troughs in variable generation and store it for use at a later time. When aggregated and bid into electricity markets, a fleet of batteries could act as a reliable demand response resource, all the while providing backup power during outages and performing other grid functions like frequency regulation and voltage control. That promise of energy storage is why over 400 utility executives named it their top emerging technology in a Utility Dive survey early this year.

Some of those hopes for grid-scale storage are being realized today. Early this month, Stem and PG&E successfully aggregated customer-sited storage systems and bid them into the real-time energy market in the California ISO, marking the first time such an action has been taken in that market. Shortly thereafter, Hawaii’s Kauai Island Utility Cooperative announced a deal with SolarCity to purchase dispatchable power from a solar-plus-storage facility that will use solar to charge a 52 MWh battery and discharge it during the evening peak demand period.

Those advances mark the beginning of a new chapter for utility-scale storage. But for behind-the-meter batteries, a new era was ushered in earlier this year when Tesla announced its home battery product. At first marketed only for backup power, the company plans to allow the battery to link up with home solar systems, letting customers generate power during the day and discharge it at night.

Most energy analysts say the price point for Tesla’s batteries is still too high. But even so, initial interest in the batteries has been intense, with the company selling out of batteries through mid-2016 in the first week they were on the market. Already, a slate of challengers have emerged to challenge Tesla in that segment, including Orison and SimpliPhi.

While the price for battery storage is still too high to make projects like the Kauai facility economic on the mainland, costs are coming down quickly. Tesla is boosting production at its giant gigafactory for batteries under construction in Nevada, and its executives say the resulting economies of scale will help it bring down the price for storage across the market. By the end of the decade, the Tesla team would be “disappointed” if battery costs weren't in the $100/kWh range, Tesla CTO JB Straubel recently said.

2. Utilities becoming more customer-centric

The rapid growth in both grid and home energy technologies has forced utilities to rethink the customer relationship. Whereas power companies used to think of their consumers simply as ratepayers, or even just “load,” new home energy technologies and shifting customer expectations have pushed them to focus on individual consumers.

Increasingly, utilities are beginning to market themselves to customers as something more than a utility company — a “trusted energy advisor” of sorts. The idea is for the utility to set itself apart from other energy companies by helping customers better manage their energy use. Many utilities have begun to offer technologies like mobile apps that allow customers to track and control their energy usage, pay bills, report outages, receive high-bill reports and more.

Some utilities are teaming up with third party vendors to offer “connected home” packages. The idea is to link up the energy technologies and major appliances in a consumer’s home to allow them more control over their usage. A rooftop solar array, for instance, could be linked with a smart thermostat and battery storage, and then all controlled through an app that allows the user to decide when to use the stored power and when to send it back onto the grid. Combine that with the ability to track power consumption from major appliances on a utility mobile app, and you’ve got the recipe for “demand flexibility” that the Rocky Mountain Institute and others believe could transform how we consume energy.

Utilities aren’t quite to that point of smart home technology yet — the vendors themselves aren’t either — but there are many promising partnerships that could lead to the dream of a fully-connected home energy system. Comcast currently offers a Grand Slam service bundle which, through a partnership with NRG Energy, allows the user to add electricity services to existing telecom and entertainment offerings. The company also has a demand response partnership with Nest and Chicago utility ComEd.

Tech companies are also seeing ample opportunity in the space. Last year, Google purchased the smart home technology firm Nest, best known for its thermostats, in a bid to break into the home energy market. For utilities, the opportunity to partner with third parties to market new services, open new revenue streams, and keep their customers happy, is very real. Navigant Research expects revenue from the home energy sector to more than double by 2023, reaching $2.4 billion.

1. Utility business models are changing

If each of these trends has something in common, it’s that they all are changing the way electric utilities have traditionally done business.

For most of the 20th century, the role of the utility was quite clear: Build out the grid and power system as a regulated monopoly entity to achieve economies of scale, and then maintain it so the lights don’t go out. Utilities appealed to regulators when they needed new infrastructure, and then built it while earning a modest return.

Fast forward to today, and much has changed. In large swaths of the nation, that vertically-integrated utility model has been broken up, with separate companies taking responsibility for the grid, power plants, and, sometimes, marketing energy to consumers.

For many companies, the only place monopoly ownership persists is on the grid, and even that is being challenged. Regulated utilities nationwide are having to rethink their business models based on the growth of distributed resources.

A few state regulatory agencies have taken a proactive approach to the changes, opening proceedings to push their power companies toward “Utility 2.0.” California and New York, with its REV initiative, have captured most of the headlines for their groundbreaking regulatory work in redefining the utility’s role on the distribution grid. Other states like Massachusetts and Minnesota have similar dockets open, and business model transformation has become perhaps the greatest singular focus of the utility industry.

“Every consulting shop has a stitch on it. There are probably ten universities with projects on it, NGOs and so on,” Bentham Paulos, principal at PaulosAnalysis and a consultant for GTM Research, told Utility Dive in March.

Exactly how utility business models will transform will depend on location and regulation, Paulos said. States with high electricity prices and large amounts of distributed generation on their grids — like Hawaii and California — are leading the charge toward reform, but increasingly, more traditional utilities are beginning to alter their models as well. Southern Co., for instance, has been steadily increasing its investments in utility-scale renewable generation through its independent generation developer, and in July announced it would enter the rooftop solar industry in Georgia through an unregulated subsidiary.

How other utilities will make money in the 21st century remains to be seen, but one thing’s for sure — they don’t expect to preserve their old business models for long.