Three CEOs, three business models, one shared outlook.
Ask any three people to tell you their hopes and dreams, and chances are you’ll hear three very different narratives. For instance, pick the CEOs of three completely different kinds of utility companies—i.e., a large investor-owned utility, a wholesale generator, and an independent system operator—and you’re certain to get completely different viewpoints, right?
The executives we interviewed for Fortnightly’s 2012 CEO Forum represent companies with three radically different business models and roles in the market.
• John Russell, CEO of CMS Energy, brings the viewpoint of a regulated utility company, Consumers Energy in Michigan, and its affiliates;
• David Crane leads NRG Energy, which operates one of the country’s largest power plant fleets, and also owns the Reliant Energy competitive retailer in Texas and the new eVgo electric vehicle network; and
• John Bear runs the Midwest Independent Transmission System Operator (MISO), whose footprint soon will extend from the Canadian border to the Gulf of Mexico—assuming Entergy succeeds in joining the ISO.
Coming from such different directions, each CEO brings some rather different opinions and perspectives. But despite those differences, they share a remarkably similar outlook on the future—i.e., they’re concerned about new EPA regulations and potential over-reliance on cheap natural gas; they view renewable energy as an increasingly important part of the energy mix; and they’re paying close attention to electric vehicles as a possible game changer for the U.S. utility industry.
They also are facing future uncertainties with an optimistic view on the opportunities ahead.
John Bear: President & CEO, MISO
Fortnightly: Please tell me about recent changes in the MISO footprint, most notably the addition of Entergy. What’s driving it, and what does it mean for MISO members and customers?
John Bear, MISO: A large entity like Entergy looks at the value proposition and sees an advantage in being part of a large independent system operator like MISO. Entergy estimates they’ll gain $1 billion of value over 10 years. And Entergy is a good fit for MISO because they bring geographic diversity. Their weather is different, and their load peaks at a different time than it does in states like Michigan or Minnesota. And in terms of fuel diversity, Entergy has a different generation mix than the overall MISO market, with more gas and nuclear generation.
Expanding the MISO footprint helps us manage risks, because we can consolidate balancing authority into a regional view. That allows us to improve reliability and efficiency.
We estimate it’s worth about $524 million a year in value to MISO, because of greater scale, lower administrative costs, and other benefits that increase when Entergy joins. That value will go to consumers in both the Entergy region and our current footprint.
In the past couple of years two other large members joined MISO—MidAmerican Energy and Dairyland Power Cooperative—along with some smaller utilities. Regional transmission organizations have become an attractive option, especially with the proliferation of NERC criteria, wholesale market regulations at FERC, and an increased focus on cost. Utilities are looking to get the best value they can for their end users.
Fortnightly: At the FERC-NARUC conference in February, you raised some issues related to reliability and resource adequacy in the context of new EPA regulations. How have those issues developed since then?
Bear: We have a tremendous amount of coal-fired power capacity in our footprint, and it’s aged. Most of our plants are over 40 years old, and we have many smaller coal plants. Of 71 GW of coal-fired plants within our footprint, we expect 61 GW will be affected by the EPA air-toxic rules. We confirmed with our membership that about 13 GW will retire and the rest will require some form of retrofit. We currently have excess capacity in our footprint, but we need to manage the outages so they don’t affect reliability. And the problem isn’t just within our footprint; we have to coordinate with our neighbors.
A key question involves the gas supply outlook. If we lean more on gas-fired plants during coal-plant outages, will we have enough gas? During heating months in northern states, supply can be tight. We studied whether we’d be able to count on the gas plants to be there, and we found the answer is ‘probably not.’
There is an excess of gas supply in the United States, but deliverability is inadequate. FERC is working on this problem. Commissioner Moeller started a process and sent out a query to stakeholders. Basically we need better alignment between the generation fleet and fuel supply, and the demand for firm, intermittent, and peaking generation.
Another question is whether the engineering supply chain can perform retrofits on schedule. The outage requirements will be severe in the Midwest, and we have real concerns about meeting the EPA timeline, as well as state environmental rules that can complicate things. It looks like engineering manpower might be a constraint. Many utilities haven’t contracted for that manpower yet, so we’re not sure where the constraints will be.
We survey our members once a quarter on this issue, and we’ve found a mix of situations. Some people have already done what they need to do. Some have just started planning and are trying to evaluate whether it makes economic sense to invest in retrofits at coal plants, when gas prices are so low. And others are doing engineering, ordering equipment, and scheduling outages. Everyone is at a different point in the process, and we’re trying to maintain as much transparency as possible so we can get it done.
We’re having discussions with DOE, EPA, FERC, and the states about these issues. We’re not evaluating the rules themselves, but how to implement them reliably and efficiently. We can do it, but we think we’ll need more time.
Fortnightly: Do you see federal energy and environmental policy getting any clearer?
Bear: I don’t know. We sure would like to have an over-arching federal energy policy. It would make this job a whole lot easier. Now we’re essentially implementing state energy policies on a regional basis, alongside a collection of federal initiatives. The convergence of events has caused a dramatic portfolio evolution, and a reduction of capacity. We’re heading into a world of gas-fired generation, and we need leadership on bringing gas and electricity together. And we need an over-arching policy as opposed to a bunch of small initiatives, which aren’t necessarily leading to the same place. Some of them conflict with others. We need a policy that aims for low-cost, reliable energy, and provides incentives for economic growth.
Fortnightly: MISO approved numerous transmission projects late last year. How do they fit into your transmission expansion plans, and what priorities are you focusing on now?
Bear: Last year the MISO board approved a multi-billion dollar portfolio, with 17 elements, designed to free up congestion and lower costs in our footprint. It’s a great step forward for everyone in our region, working together to focus on the lowest delivered cost for end users. That’s an important distinction; in the past people focused on the lowest transmission cost, and built lines on the basis of reliability criteria. But by putting the regional portfolio together, we’re able to look at it economically, on a regional basis, and that makes a big difference.
Additionally the projects include smaller, local reliability projects, and others that can remove congestion within the footprint.
The next priority on our agenda is bringing Entergy in so they have the same capabilities as our portfolio in the Midwest.
Fortnightly: What’s the status of your efforts to develop a capacity market and locational pricing mechanisms?
Bear: We’re waiting on our order from FERC. We were hoping to have it in February. What we’re doing is using market mechanisms to help us understand what capacity is deliverable on a zonal basis, so we can improve reliability and get more discrete pricing. Also the capacity markets provide resources for up to 1 year, and allow load-serving entities to show that they have enough resources and reserve margin. If they don’t, there’s a penalty. We’re trying to drive bilateral markets, so people will contract for capacity and improve reliability. But we can’t implement the auction until we get FERC’s order.
The resource adequacy part of the order is especially important. Given our portfolio and the fact that the reserve margin will erode sharply, we’d like to get our resource adequacy mechanisms in place.
Fortnightly: What other policy and regulatory issues are you focused on?
Bear: FERC Order 1000 is a very important thing because it’s making regions work more closely together. We are focused on that, and specifically on seams issues within regions. We need to move energy efficiently back and forth, and we can with PJM through our joint operating agreement. But especially with the erosion of reserve margins, capacity needs to be portable across regions.
We’re working on a broader regional market initiative, with the New York ISO, PJM, and ISO-New England, to manage loop flows. And we’re focused on permitting for gas and electric facilities. It’s about the harmony of gas and electric infrastructure. Most of the pipelines in our region were built to deliver gas for heating load, and not power generation.
Finally we need to get some things ironed out between NERC and FERC. A lot of compliance requirements are coming out of NERC, and everyone is focused on that. We’d like to see more lessons coming out of the reliability and compliance initiatives, rather than just penalties. We need more transparency and sharing of best practices on how to operate more reliably.
We could learn a lot about information sharing from the Nuclear Regulatory Commission.
Fortnightly: What about FERC’s order on demand response compensation? What do you see as the potential for DR in the MISO market?
Bear: We’ve put into place all of the things we need to implement what FERC wants to do with DR, from the standpoint of technology and tariffs. Everything is there. The decision of how to implement it rests with the utilities in our marketplace.
We have a lot of DR now, but it’s mostly from older demand-side management (DSM) contracts. After EPA implementation, when we have lower capacity margins, the pressure will be on. Prices will come up a bit, and DR will be important for filling the resource gap.
We’re now evaluating the DR resource in our footprint. We believe we have a significant opportunity. Most of our current DR is on industrial loads, and the working hypothesis is there’s a big opportunity for aggregation of commercial customers and some residential customers at certain times of the day. Many of our members who are vertically integrated utilities are working to understand their opportunities and how to tap into them.
Fortnightly: What advanced technology initiatives are you working on, and where are they heading?
Bear: We’re pleased with what we’ve been able to accomplish with our synchrophasor project. It takes the wholesale model to a new level. Phase-angle indicators have real benefits for us, especially for regional coordination with Canada, PJM, and New York. We can dramatically impact loop flows, which will be helpful. Previously we were able get data on the system in three to four seconds, and now synchrophasors give us readings 30 times a second. They’re more accurate, they allow us to see what’s happening on the system, look backwards, and plan forward to make sure we’re as reliable as possible.
Also we’re working with our members on the smart grid technologies they choose. We’re involved in the Energy Systems Network in Indiana, including Project Plug-In with Duke and Indianapolis Power & Light as they integrate electric vehicles (EV). We have charging stations outside the building here, and we have quite a few employees participating in the program. We’re evaluating data to understand implications for the system.
Fortnightly: Are you considering vehicle-to-grid (V2G) technology, where EV batteries would provide distributed storage for the grid?
Bear: We’ve had a couple of instances where people brought in 1-MW batteries to provide ancillary services and balancing. It’s worked well, but our ancillary service prices are low relative to the rest of the nation. Those batteries moved east because their prices are higher. We haven’t looked at taking that idea to smaller sized batteries in cars. The project we’re working on now is providing incentives to charge at certain times of the day, effectively creating storage through demand response. As prices change that will become more viable as well.
We’re encouraged about what the future has in store for us.
David Crane: President & CEO, NRG Energy
Fortnightly: In your recent quarterly earnings call, you talked about how success for NRG is about balancing on three pillars—conventional wholesale generation, retail electricity, and clean and renewable energy. What’s the relative importance of those pillars today and in the future.
David Crane, NRG Energy: For someone investing in NRG, the value proposition involves the idea that the vast majority of our business is conventional generation, in the hub-and-spoke power system that we’ve had in this country for 100 years. But what makes NRG unique is that we’re doing wholesale and retail business in deregulated markets. So the core of the business is the combination of wholesale and retail, in Texas, the Northeast, and somewhat in California.
The situation looks quite tight in Texas. There isn’t a big supply response in the other markets either, so we’re seeing some tightness in the Northeast and in California as companies are looking to retire old plants, particularly old coal plants.
I would argue that the traditional power business in the United States is past its peak, and now is in very slow, long-term decline because of the third pillar of our balance—renewable energy. It’s almost inevitable that there will be fewer electrons generated by conventional fossil fired plants because of growth in renewables, particularly distributed renewables. That is a game changer, and we want to be part of it because it’s the highest growth part of the business today—even though for now it’s such a small business that for investors it’s more like a rounding error.
Fortnightly: Renewables have been a long time coming, and it seems like competitive solar has been 10 years away forever. How long do you think it will be before solar energy becomes a really substantial resource?
Crane: I’d say five to 10 years. We’re now trumpeting building 1,000 MW of solar projects, and that makes us the biggest solar generator in the country. That will cost about $5 billion. But people aren’t impressed because we have 26,000 MW of conventional generation. It’s all a matter of perspective.
I really think we’re on the precipice of a huge inflection point. A couple of years ago I thought it would be driven by EV adoption. That’s going a little slower than I thought it would, but the distributed solar freight train is coming down the tracks at an impressive speed. Rooftop solar now costs $3 to $4 a watt in most states, and it will be below $2/watt by 2014. That translates into 12 to 14 cents/kilowatt-hour. That will be an attractive rate in many parts of the United States. A Kinsey report said distributed solar would cost $1/watt by 2020. At that time you’ll be able to put solar on your roof and generate for 6 to 7 cents/kWh. When that happens, a significant percentage of homes will convert to solar roofs, and that will have a dramatic impact on the way electricity is delivered.
Fortnightly: NRG’s eVgo subsidiary just reached an agreement to invest $100 million in EV charging infrastructure in California. How important is the EV business as part of NRG’s strategy?
Crane: I’m a huge fan of EVs and I believe they’ll be a big part of the future—and they should be. There’s a lot of room for development in that business. We’re just scratching the surface of what EVs can be in terms of a dual-use consumer product, acting as a distributed storage mechanism for the grid in its spare time, during the 22 hours a day when the average car isn’t being used.
We started the eVgo model in Texas a year ago, mainly to prove to ourselves that Americans would be willing to pay for their transportation fuel in a completely different way, compared to what they do now. It’s a subscription model, with one flat fee per month, as part of your home electric bill. We found it very reassuring in Texas that 90 percent of Nissan LEAF owners bought our subscription model. But the bad news is that very few customers have the product. It’s nice to have 90 percent of the market, but there are only about 100 cars in Houston and Dallas.
In California, on the other hand, there are already thousands of EVs on the streets. We saw an opportunity to settle a longstanding dispute with the state, that came out of Dynegy’s actions. We proposed to build and own this infrastructure, but unlike in Texas where it’s a private subscription model, we’ll provide public access for a certain number of years. We have $100 million committed to putting a charging network in three major cities plus the San Joaquin valley, plus wiring 10,000 more chargers across the state. We’re excited. It’s an example of far-sighted, public-private cooperation.
Fortnightly: What do you see as the outlook for EVs to grow into a major business?
Crane: Today, EVs and their support infrastructure are about where the cell phone industry was with towers around 1985. The good news is that the main workhorse for EV charging in the future will be the home electric system. And it doesn’t cost that much to put in urban chargers, to turn range anxiety into confidence.
History has shown that when you’re creating any sort of infrastructure, you create the most value by being the first mover. We aren’t the largest company in the market, but we moved early to get that advantage and set up a network. It’s no secret we also want to start doing this on the East Coast. So it’s a source of significant potential value—but everything is derivative. If the American public doesn’t embrace EVs, then it probably won’t have as much value.
The good thing is the sheer size of the automotive industry—10 million cars a year. If we get to the point where even 10 percent of the cars sold are plug-in EVs, that’s a huge potential market, and eVgo will become very valuable to shareholders.
Also, utilities should be banging the drum for electrification of transportation, especially in markets where demand growth is weak.
Fortnightly: Cheap gas is changing the U.S. power generation business. How is it affecting your investment decisions, as well as planning and development?
Crane: In the old days, when people wanted the elevator speech on NRG’s investment proposition, I’d tell them that NRG makes money by selling coal and uranium at natural gas prices. That’s the way the single-price auction system works in deregulated wholesale markets. It’s a great business when natural gas prices go up, but when gas is at $2—whether you’re running coal plants that get a price set by natural gas, or if you’re running a natural gas plant—nobody is making money on the wholesale side. You just can’t make money when the peak price of wholesale electricity in Texas is $20 to $25 a megawatt-hour. Many people seem to focus on the fact that gas plants are being dispatched more, but they don’t realize that they’re running on zero margin.
That’s one reason we like our model of marrying retail with wholesale. In markets like this, the retail side of the business does better.
On decisions of what to build, we’re building natural gas plants because the economics in this environment are compelling. But at the same time, like other executives I’m saying, ‘I’ve seen this movie before.’ We rushed out in 1998 and built gas plants, and then things changed and plants were no longer looking economic.
If I were ruler for a day, I’d say to everyone in the industry, utilities or IPPs, ‘We don’t want to sacrifice our greatest advantage, which is that we are a multi-fuel generation source.’ But I think we’re going to sacrifice it, because in this gas price environment I don’t know how anybody builds base-load capacity that isn’t gas-fired. I don’t know how you justify coal or nuclear.
Fortnightly: What about renewables? Does cheap gas kill wind?
Crane: Renewables have been insulated by the fact that a lot of states have bifurcated the market by establishing an RPS [renewable portfolio standard]. Any state where there’s an RPS, the key isn’t to be as cheap as gas, but to be the cheapest renewable source. Low gas prices are killing coal and nuclear, not renewables—yet.
When you run out of space in the RPS, gas will take its toll on utility scale renewables. But we think the future is distributed generation, because it effectively competes with the retail price of electricity, not the wholesale price. In a lot of states, the retail price is a pretty fat target. It’s gone up every year over the last six years.
Fortnightly: Many states’ RPS provisions have escape clauses or penalty options. Might rate shock drive states to pull back from RPS commitments?
Crane: There will be fewer RPS mandates in the future, but I don’t know if that’s because of worry about rate shock or because RPS policies were enacted during the Bush administration, by Democratic lawmakers who wanted to do something on the clean energy front. The momentum failed when the White House became Democratic.
We’re not predicating our renewable energy business going forward on new RPS requirements, nor do we believe it’s realistic for anybody in the wind or solar industry to get prices down to compete with gas at $2. The price of natural gas has been dropping for four years, but the average retail price of electricity has gone up; Connecticut ratepayers are paying 18 cents/kWh.
We think the addressable market for renewables is beyond the meter. People will be self-generating, and that will have profound implications for the system. You already see it happening in California with multi-tiered rates. People are paying 35 cents/kWh at the top tier. Anybody who’s doing that can put solar panels on their roof and pay less. The real opportunity is to target retail electricity markets in high-tariff states.
Fortnightly: FERC has been very active in recent years. What’s your perspective on the overall trend in wholesale market regulation?
Crane: FERC has been generally supportive of market competition. There seemed to be a push toward re-regulation a couple of years ago, and FERC successfully defended the deregulated markets. The re-regulation pendulum is swinging back dramatically. Almost by surprise, you’re seeing more states talking about deregulation. I think the reason is because state PUCs and people in public policy are recognizing that some of the game changers—like EV infrastructure and beyond-the-meter distributed solar—don’t naturally lend themselves to rate-base regulation particularly well. In part that’s because it can be hard for a PUC commissioner to let a utility put a bunch of EV stuff into rate base, recognizing that most EVs will be owned by people in upper income brackets.
Fortnightly: Capacity markets are emerging in some organized markets, but not Texas. What do you think of capacity markets?
Crane: Regulators in Texas changed the price cap for the summer, which is a sort of de-facto way to make it feel like a capacity market. They’re doing what they can to encourage new generation within the construct of an energy-only market. We’re watching that with great interest and we want to be supportive.
Fortnightly: What about demand response? Does that market interest you?
Crane: We’ve seen a big focus on it in the Northeast markets, and I think DR is very interesting. We’re looking at it from a business perspective. We support treating it as a resource, but the rules should be the same for DR as they are for generation. Will it be reliable, in a pinch? Sometimes questions are raised about that.
But DR is part of the future in the Northeast, and we’re looking to see if there’s an opportunity for us. We’re not sure whether it works as a stand-alone business or as a product in the tool chest. We’re looking at it.
Fortnightly: Do you view DR and conservation as a competitive threat?
Crane: Almost everything in our industry is either a threat or an opportunity, depending on whether you try to fight it or harness it. I put DR in the same category as conservation and efficiency. Given how wasteful Americans are in terms of using electricity versus almost every other country in the world, one of the great threats to the utility industry is that Americans will actually get serious about not wasting electricity. Japanese consumers are something like five times as efficient as the average American, and yet when they shut down their nuclear plants and lost 40 percent of their base-load generation, they had no blackouts. The consumers just cut back. It’s breathtaking.
Overall, this is a trend line for the industry—with DR, efficiency, and conservation. It’s our job as business people to make that trend valuable for our company. I think it’s more of a challenge in the deregulated markets. In a regulated market, if you have a cooperative commission, utilities can find a way to get compensated for people not using their product.
Reliant has something like 300,000 to 400,000 smart meters, and related products and services focused on efficiency. The way we look at it, the biggest expense in a deregulated retail market is customer churn. If we help someone use less electricity, we’re reducing our profit margin for that customer, but we’re doing it in a way that keeps that person with us for five or 10 years, rather than taking the business to someone else. That’s a winning proposition for us.
Our vision for the future is based on a triumvirate of technologies in the customer’s home—PV on the roof, an EV charging in the garage, and a smart meter that allows us to manage the whole thing on the customer’s behalf. Not only do we want to manage the system so that people are efficient, but also so that when it’s 120 degrees outside and the system is screaming for power, we can do V2G and we can draw from solar panels, to support the system and avoid having to pay $4,500/MW. This will make the energy customer more efficient, and they’ll actually become a seller into the system. That will be a very appealing proposition to the savvy homeowner.
Fortnightly: That future seems a long way off.
Crane: Last year in the middle of August and the price cap in Texas was $3,000/MWh, because there was unexpected load. Reliant went into the summer hedged against expected load, serving customers who were paying us $100/MWh. I don’t need to tell you, that’s not a very attractive proposition.
Sometimes it’s not about making money, but about avoiding losing money. In certain market conditions, there’s an economically compelling market proposition for us to work with our customers to not use electricity when it’s very expensive to provide it.
And I don’t think it’s 20 years down the road before a lot of customers will be delivering power into the system from their own sources. If you think it’s 20 years away, then you’re not accounting for the pace of change in modern society. In any industry except ours, 20 years is like an epoch. It won’t happen next month, but I’d expect people will be doing this by 2020.
Fortnightly: If that’s true, then the industry could be looking at a lot of stranded costs.
Crane: Stranded cost recovery is a concept that’s unique to rate-based utilities. But yes, if I were running a rate-based utility where the pricing system is based on volume, with fixed costs spread over sales of electricity, and if I were in a high-tariff market where 50 percent of my retail customers might take a majority of their business off line and generate their own electrons—and yet depend on my system as a backup—then I would be very concerned about the Post-Officization of the business.
You see what’s happened to the Post Office. Nobody sends 1st-class mail anymore. It’s junk mail at a lower cost per piece, and the Post Office has to keep raising rates to cover fixed costs that keep rising. And that just makes them less competitive. I see that happening in this industry as people generate more of their own power. It’s inevitable that they will; people will look to harvest the solar real estate that they own. And as the people in younger generations grow up, they won’t be as comfortable buying electrons that come from a source they might not like. Why would someone in the Midwest have to take electrons produced from a mountaintop coal mine in West Virginia, if they don’t agree with that practice?
As a company, we want to be around for a long time. We want to be there for the next generation when they start to own houses, and they want clean and sustainable energy.
John Russell: President & CEO, CMS Energy and Consumers Energy
Fortnightly: Michigan’s market framework has gone through a lot of evolution. How has that evolution affected CMS Energy’s business and its opportunities in the state?
John Russell, CMS Energy: The regulatory environment is very important to the company’s success. The game changer for us was the 2008 energy law (Michigan Public Act 295) that provided a comprehensive regulatory structure for Michigan. It included renewable energy, efficiency targets, and regulatory changes, and it focused on where Michigan wanted to go in the future. It provided us with certainty in timeliness of recovery—not certainty of recovery itself, but timeliness. That has allowed us to invest in renewables, energy efficiency, distribution reliability, and gas safety. It’s helped us to make the investments that our customers need, and that are required to improve the environment.
We’re investing capital now to reduce fuel and O&M costs. By investing capital with discipline, we’re able to reduce our O&M costs by 4 percent, and we’ll continue reducing them by 1 percent per year. That keeps our base rates in the electric and gas business at or below the rate of inflation. That’s the range that our customers can afford, and we’ll continue providing a great value.
Fortnightly: How has retail competition in Michigan affected your business?
Russell: The legislation in 2008 included a retail open access level of 10 percent. That enabled customers, primarily large ones, to shop among suppliers. In the context of the full law it made sense. The retail cap was about the amount of power that we were buying on the market at the time. Although there’s some talk about increasing that cap, the 10-percent level made sense and it still does. [Editor’s note: Rep. Mike Shirkey (R-Clarkdale) in March 2012 introduced HB5503, which would allow choice immediately for any customer currently on a waiting list, and would raise the open-access cap incrementally by 6 percent each year through 2015.]
Very few customers are shopping today. It’s 10 percent of our load, but only 300 electric customers, out of 1.8 million.
On the gas side of the business, we’ve always had open access for industrial through residential customers. Surprisingly, in today’s market the majority of our gas customers are paying more through third-party suppliers than they would be if they’d bought gas from us.
The fact is, deregulated states have higher rates than states that are regulated. And most of our business customers want certainty. They want value but they also want predictability in their costs.
Fortnightly: How does cheap shale gas affect your investment decisions?
Russell: We were in the process of developing an 830-MW clean-coal generation plant that we canceled in part because of shale gas. Other factors were the weak economy and excess capacity. That was going to be a multi-billion dollar investment.
Due to environmental rules and gas prices—but primarily because of environmental rules—we’re mothballing seven coal-fired plants between now and 2015. That buys us some time to determine what the EPA rules will mean for these plants.
Uncertainty about the rules makes large investments difficult in this industry. Even when the agency issues new rules, they’re challenged in court, and that can send you back to square one. We’re the largest investor-owned utility in Michigan, and we’ll be investing capital. But we need certainty about the rules. The investments we make are 30- to 40-year investments. Conflict happens when regulations change, or aren’t codified, or they’re challenged and decided by the courts.
Low gas prices open up opportunities in gas fueled generation. We purchased a 900-MW plant a few years ago that was running at 13- to 14-percent capacity factor. Last month it ran at over 80 percent. So we’re seeing a shift in the balance of our portfolio from coal toward natural gas. That has reduced costs to customers by over $100 million. I expect those changes to continue.
The default fuel for new generation will be natural gas. Since legislators haven’t taken a position on it, regulators are filling that void, and that means natural gas will be the fuel of choice. One thing I believe is that it’s important to have a balanced portfolio. If everyone switches to natural gas, it will drive up demand and prices. We need a balance between gas, coal, nuclear, renewables, and efficiency.
For us, renewable energy is a little easier. We believe renewables should be part of a balanced portfolio, and that’s supported by the 2008 energy law, which says 10 percent of our power needs to come from renewables by 2015. Already 5 percent is being supplied by renewables. We’ve begun construction and this year we’ll complete our first large wind park, the Lake Winds project, which will bring our renewable percentage to 8 percent. We have another energy park on the horizon, and we’re entering supplier contracts. We’re moving ahead with renewable energy. Our total investment to achieve the 2015 target will be about $500 million. I think that’s about the right level until the costs come down, with the experience curve.
Fortnightly: Unlike most utilities, CMS has access to major storage capacity. How does that fit into your portfolio?
Russell: We operate one of the largest pumped-storage facilities in the world, the Ludington plant on Lake Michigan. We’re investing along with our partner DTE Energy to increase the capacity to about 2,200 MW. It’s a true engineering marvel. It not only allows us to serve peak load, but in the future it will help with balancing the intermittent nature of renewable energy being built in the state.
The Ludington plant was built on the premise that off-peak generation costs are low, because nuclear plants were running at night and load wasn’t there. So we could use off-peak power to pump up the reservoir with 27 billion gallons of fuel. But today in Michigan, wind generation is good at night, and we can use that energy at night to pump the reservoir. That’s where storage becomes an advantage—using energy with zero incremental cost, and putting it back into the system when demand and prices are high.
It would be very hard to duplicate a plant like Ludington, but we are expanding and upgrading it with more efficient runners and other equipment. The country would be well served by more pumped storage plants, but the siting is a challenge.
Fortnightly: How do EVs factor into CMS’s plans?
Russell: We believe in EVs. They are a component of the future, and we like the idea of the utility providing transportation fuel. Plus in Michigan the auto industry is part of our culture, and we support EVs as the evolution of that industry. We have EVs in our fleet, both Fords and Chevys, and we’re testing electric bucket trucks. It’s important for utilities to step up and facilitate EVs, and we are a part of that.
We offer incentive rates for Chevy Volt owners, with discounts on the electricity they use. We offered home chargers to the first 2,500 Volt drivers. Volts are made here in Michigan, and so are 80 percent of the batteries, and we’d like to see production continue. We’re offering incentives to help ensure this happens in Michigan, and the market reaches a critical mass. We install chargers for customers and we set up charging stations at many service centers and community areas.
The thing that’s held back EVs is the price. Also the batteries diminish in the winter. But we now have people who have driven them 30,000 to 40,000 miles, and they love them. They’re good cars, reliable, and enjoyable to drive. We’re adding more to the fleet.
Also with projections of natural gas prices, we see an opportunity for vehicles fueled with compressed natural gas. The market and applications are different for CNG; it’s good for delivery vehicles and commercial vans. It might have merit in the next several years, with the forecasted price of gas.
Fortnightly: How important will smart charging be for integrating EVs?
Russell: We give customers special off-peak rates, or they can have flat charging rates. From a system standpoint, having the vehicle on our system hasn’t caused any problems, nor do I expect it to. If you plug in your Volt to a normal garage outlet, it’s like plugging in a hair dryer. If you have a higher-voltage charger, it’s like running an electric dryer. Those things don’t seem to cause any problems on our system. I think there’s been more attention paid this issue than is really needed.
Smart charging has potential for the long term. However, we’ve been very deliberate in our rollout of smart grid technology, and the first thing you need in order to use the capacity of vehicle batteries is a grid that can handle two-way communications with the user. There may be potential in the future, but we need to get the smart grid set up first, and that won’t be fully rolled out until 2019. We’re moving forward with it, but in a prudent and measured approach. We performed a couple of pilots, rolling out 60,000 meters this year. The business case is positive for our customers on the electric side of the business, but we haven’t found a positive business case on the gas side.
Fortnightly: What’s driving the business case for electric smart meters?
Russell: The value for customers is that they’ll save money. We’ll roll out efficiency opt-in programs that will allow customers to save energy. And customers will have ready access to the information they need to control their energy usage, if they choose.
Fortnightly: Will you need DR to help manage peak load? Or do you have a lot of excess capacity in Michigan, as a result of the recession?
Russell: It seems to surprise people that we in Michigan have seen a pretty good recovery from the lowest levels of the recession. We were leading the nation in unemployment, with 14.1-percent back in 2009. We’re now at 8.1 percent, and the average in the nation is 8.2 percent. We saw our sales go up in 2010 by 1.7 percent, and in 2013 by 1.3 percent. A conservative estimate is that this year sales will increase by around 2 percent. We’re seeing a significant increase based on historic levels in our industrial load. Michigan is recovering. And last summer we broke a 125-year record for peak load.
With renewable energy coming online, we’re keeping up with demand. But we need to look toward the future, when we’ll have plants closing as a result of new environmental rules, and also new reserve margin requirements by MISO. By 2015 or 2016, there will be a shortage of capacity in some areas, and we’re focusing on that now.
Fortnightly: What’s your perspective on evolving FERC regulations and changes at MISO?
Russell: Since MISO formed, they’ve done a great job on reliability. I think a capacity market is needed in the future. PJM has one and MISO would benefit by having one too. Also I’m supportive of Entergy joining MISO. As one of the largest members, I can say it’s good to have more.
Regarding FERC rules, the key is that whoever gets the benefit of an investment ought to pay for it. In Michigan we have several renewable energy projects that required upgraded transmission, and we were willing to pay for that. But FERC has ruled that those kinds of costs should be spread around to other states, and I don’t think that’s fair. I’m concerned that as transmission projects are built in other states to capture renewable energy, we’ll be paying for those costs. I don’t think our customers will see value for that expense. We need to look at who receives the benefits, and that includes jobs for construction and O&M. Those things go where the plant is sited, not the transmission line.
Fortnightly: What other priorities are you focused on today?
Russell: The top priority for our company is safety. Despite all the uncertainty around things like EPA rules and economic volatility, we can’t take our eye off the fact we operate in a dangerous business.
Beyond that, as a company we need to focus on adding value for our customers, using new technologies and communications methods, like social media, that benefit our customers. Our average electric customer spends $3 a day with us. That’s less than the cost of a gallon of gasoline, and the value they get for that is tremendous.
One other thing I’m worried about is our aging workforce. It’s important that we transition the skills and culture we have today into a newer workforce. On the professional side, the main concerns involve engineers, IT professionals, accountants, and project managers. On the skilled workforce side, it’s line workers, construction talent, and plant workers.
We announced a voluntary separation program. With this program, we choose who goes and the timing of their transition, and that’s different from other voluntary separation programs where seniority determines who goes. We’ll look at each case to see if we can do our job without that person, and if we can we’ll offer a relatively modest separation package. It’s a unique approach but it’s serves us well. It allows us to manage the transition, and in some cases to bring in new talent to support the transition of retiring workers.
It’s the transition that’s critical. If we’re managing the transition, then it won’t freeze up the organization. We can hit the ground running, and that’s important as we continue to grow.