May 5, 2014 - From the May, 2014 issue

MidAmerican Renewables, Since Launching Two Years Ago, Has Invested $14B In Wind & Solar

Jonathan Weisgall serves as Vice President for Legislative and Regulatory Affairs at Berkshire Hathaway Energy—at the time of our interview, before changing its name, MidAmerican Energy Holdings Company. Since 2012, the company has invested extensively in unregulated solar, wind, hydro, and geothermal projects. Weisgall spoke with TPR to update readers on Berkshire Hathaway Energy’s progress since its founding, as well as the promise of energy imbalance markets and his role in bringing an EIM to the western United States.


"How can little Iowa dispatch that much wind, which is almost as much as there is in California, virtually tied for second in the United States after Texas? The answer: We dispatch into a gigantic grid called the Midcontinent ISO." —Jonathan Weisgall

Jonathan, two years ago at VerdeXchange 2012 you announced a new MidAmerican Energy company, MidAmerican Renewables, that’s focus was to be the pursuit of unregulated renewable energy opportunities. Update our readers on MidAmerican’s investments to date. 

Jonathan Weisgall: It’s been quite significant, David. Since that announcement, we have invested just under $7 billion in California wind and solar projects, which includes the Pinyon Pines wind project in Tehachapi and three large utility-scale solar projects. One is called Topaz, east of San Luis Obispo, at about 550 megawatts. That’s about 82 percent complete. The second, at 579 megawatts, is Solar Star, which is just on the Kern-Los Angeles County border and is about 55 percent complete. The third, Agua Caliente, is 290 megawatts and is in service. We also bought the 81-megawatt Bishop Hill II wind project in Illinois, which is in commercial operation.

We have found that California markets continue to be good investment opportunities, offering stability and good regulatory certainty. The Agua Caliente project was actually finished ahead of time. Topaz is ahead of schedule and could be commissioned early. We’re talking eight to nine million solar panels and project, so these are huge. We’ve been very pleased with the process so far. 

If we were to project forward, will the trajectory of MidAmerican’s investments in solar and wind be as steep as it’s been for the last two years? 

I would say no. There are a number of factors here. As you know, demand increases in the US have slowed nationwide. We’re seeing for the first time flat to contracting demand for electricity. That flat load growth is due, probably, to three separate factors. Economic recovery from the recession is still waiting to get into higher gear. We’re also seeing some of the effects of distributed generation and some effects of energy efficiency. Regarding the large utility-scale projects like the ones I mentioned, there are fewer and fewer on the horizon. If California were to increase its renewable portfolio standard above 33 percent, though, I think we would see changes quickly in that area. 

Coinciding with there being more renewables added to the grid is the issue of grid reliability. Energy imbalance markets appear to be the response. Obviously, intermittent renewable resources have to be integrated into the grid. There are 38 balancing authorities in the West, and the Western Electricity Coordinating Council anticipates at least 60 gigawatts of wind, solar, and geothermal energy in the West by 2012. What are the next generation policy balancing mechanisms at play? 

Let me begin with our Midwest utility—MidAmerican Energy. As a regulated utility, we have invested about $8 billion in wind resources in the last decade—that’s separate from what I’ve been talking about, since this is on the regulated side—and nearly $6 billion in Iowa alone. In Iowa, by the end of 2015, we will have over 3,300 megawatts of wind, and our system will be about 39 percent wind. How can little Iowa dispatch that much wind, which is almost as much as there is in California, virtually tied for second in the United States after Texas? The answer: We dispatch into a gigantic grid called the Midcontinent ISO, which covers a very broad swath of the country, including parts of 14 states—down to Louisiana and Alabama, all the way north to Minnesota, North Dakota, and Wisconsin, along with Illinois, Indiana, Iowa, and into Montana. In the West, we’re dealing with 38 grids—38 separate balancing authorities—each of which has to balance supply and demand.

We’re moving ahead here with the Cal ISO. What we’re looking at in an energy imbalance market essentially is to balance electricity supply and demand every five minutes by choosing the least-cost resource to respond in real time. We are leveraging geographic diversity to optimize these available regional resources and take advantage of unused capacity on transmission lines. This is not joining an RTO—and participation is certainly not mandatory.  There are no exit fees. 

Moreover, we see some tremendous benefits here in three areas. It’s the three key areas that any utility looks at these days: affordability, sustainability, and reliability. On affordability, by spreading that geographic pool and being able to use these mostly renewable resources on a five-minute basis, and to assure that these assets are used as efficiently as possible, we’re anticipating benefits to PacifiCorp and the Cal ISO customers of anywhere from $21 to $129 million annually. Right there, it’s a no-brainer, but I’ll add two other factors. We’re improving on sustainability. We’re helping to integrate renewable resources by capturing the benefits of this much greater geographic diversity of load and resources. We’re optimizing the use of renewable energy. Then there’s the third factor of reliability. We think that this energy imbalance market will increase visibility,  situational awareness, and coordination across a larger portion of the western grid.

The Cal ISO governing board approved in November 2013 detailed EIM market rules, and this past December 18 the board approved the framework for a governance structure. Elaborate on the significance of California’s regulatory actions. 

Those are essentially the details of moving ahead on a fair and open governance structure. We want to see a fully transparent process. Along with those rules have been a large number of webinars, workshops, conference calls, meetings, and written comments. Both the Cal ISO and our utility, PacifiCorp, have had a very elaborate stakeholder process and provided a lot of opportunities for both customers and stakeholders to offer feedback, forming the basis of the FERC filing that the Cal ISO made for its tariff for energy imbalance. 

There really are a number of questions to get resolved. Who is going to run this and how will it be run? How do we keep it fair? How do we get others interested? If it’s not fair, it will not be as successful as we would like. That really is what this whole governance process is designed to accomplish, and we hope all of that will be in good shape by the time we go live with PacifiCorp, which is set to October 1 of this year. There’s a transitional committee that’s being formed to recommend long-term governance structure to the Cal ISO Board of Governors. We think that’s a good process moving forward. We can say it’s good because there have been a lot of changes since the beginning of the process. 

During the Cal ISO debate, some veteran grid operators suggested that EIMs are too expensive and too difficult to implement. What do you make of such concerns?

On expenses, we’re looking at $20 million in start-up costs, which includes upgrading metering and telecommunication equipment, upgrading systems necessary to support efficient market operations, settlement of the transactions in the energy imbalance market, and implementation costs paid to the Cal ISO to participate in the EIM.  

When you look at the projected benefits that I mentioned of $21 to $129 million over time, those would certainly outweigh those costs. There are definitely start-up cost fees. Ongoing costs we think are manageable. Even just looking at the benefit of less curtailment of renewables at times of over-generation, we’re going to see a lot of benefits.

It’s very complex. We have a large team of folks working with the Cal ISO to get this right. We will conduct market simulations beginning in July and going through the end of September to make sure we get this right. 

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What is the significance of what Cal ISO does regarding energy imbalance markets for other western states? 

I think the watchword there is probably “regionalism.” California continues to import a lot of its electricity. The state is on a path to reach a 33 percent renewable target by 2020. There is talk, and I think we’ll see more late this year, from the California Air Resources Board of either a higher RPS target or new standards of greenhouse gas emissions reductions. 

I don’t think that California can do this alone. That’s what an energy imbalance market is all about—expanding the geographic diversity and promoting more regionalism in achieving these goals of affordability, sustainability, and reliability. The Cal ISO is taking a lead there. In that regard, the other utility that we recently acquired—NV Energy, which serves a very large part of Nevada—we hope will join the energy imbalance market by October 1, 2015. It has filed its tariff amendments with FERC. 

I think the impact on a company like ours or on any other developer in the West is that an energy imbalance market can contribute to greater regional development of renewables in ways that are more efficient and thus keep costs down for customers while maintaining reliability.

MidAmerican is also in the natural gas business and is probably the largest provider of natural gas to California. Give our readers a sense of the changing energy portfolio landscape of harvested natural gas as a replacement for other fuel sources. What will its place be going forward? 

Let’s begin with EPA regulations. Those will lead to about 60 gigawatts of coal plants in the United States being retired by 2017—60,000 megawatts—and that is just the beginning. We’ve only seen about 18 of the 60 gigawatts. But we’re talking about retiring 20 percent of the US coal fleet. Obviously, that’s baseload power. How much of that is going to fuel-switch to natural gas? I don’t know the answer to that, but there is no question that there’s going to have to be a lot of new replacement power. 

A couple of obvious points: First, the fracking issue is always out there on natural gas. The industry has to get that right and make sure it does not face its own Three Mile Island, because a major aquifer contamination may stop fracking in its tracks. Two, with this huge switch to greater natural gas development—as you know, natural gas use has gone from 20 percent to something like 29 percent nationwide in one decade—we’ve got to build out the infrastructure in this country. We need more pipelines and more storage. That was the huge problem during the past winter’s polar vortex in New England. There was just not enough natural gas to go around, even though lots more is being produced in the fields, and there were big price spikes in New England. A fourth and related issue is exporting, because the more you export, the more you limit supply. We’ve got to understand what the long-term implications are of this enormous shift in the demand curve for natural gas. 

As we move from coal to natural gas, there are other issues, as well. For example, look at a coal plant with a 30-day onsite supply of fuel. You’re running the coal plant, you look out the window, and you see your fuel supply. When you’re running a gas plant, you’re facing just-in-time delivery from a pipeline on a daily basis, and you’re competing with hospitals, households, and commercial operations, especially on cold days. That’s a huge issue. Then there is price volatility. Throughout the 1990’s natural gas prices were settled in at the $2 to $2.50mm BTU range, and then spiked as high as $14 in 2001, 2003, and 2005-06. With large new supplies of shale gas from fracking, projections are that we’re not going to see that price volatility continue, but the history of natural gas pricing would lead you to question that assertion. 

Those are a number of the challenges we’re facing, not to mention the recently publicized methane issues that go with natural gas development, as well as increasing environmental opposition. When the Sierra Club says, “We’re going to be preventing new gas plants from being built wherever we can”—and that’s a direct quotation from their president, Michael Brune—that shows that switching to natural gas is not a no-brainer.

I would add, there’s also an eggs-in-one-basket problem. One of the energy strengths of our country, I think, is our fuel diversity. We’ve got a lot of nuclear, we have a lot of coal, and we’re pushing for clean coal. If that doesn’t work, clearly there will be a push for more natural gas, renewables, and nuclear. But going overboard certainly can cause problems—no question. Our company’s Kern River Pipeline delivers about one third of the natural gas into California and that continues to be a very, very healthy market, but if we look at more and more use of natural gas for power plants, there are a lot of infrastructure challenges coming down the pike.

Let’s close with the question repeatedly asked at the VerdeXchange Conferences you’ve been a part of: “Where Now for Solar and Wind?” What, specifically, will be the consequences of declining subsidies for solar and wind in the marketplace?

Big changes. In this country, we don’t really have an energy policy, per se. We have tax policies and we have environmental policies. We’ve discussed the environmental policies with EPA rules driving the shutdown of coal plants simply on economics. That, of course, is an indirect driver of renewable energy development. A second driver of renewable energy development is state policy—primarily, renewable portfolio standards. A third driver is tax policy. With solar, the investment tax credit goes through the end of 2016. It’s premature to predict what will happen there. That investment tax credit, if it reverts to the 10 percent, will certainly have an impact on utility-scale solar development, not to mention distributed generation, although net metering will continue to help.

The other major tax driver, of course, has been the production tax credit (PTC), which was extended through the end of 2013 with new language changing the requirement from being online by the end of the year, to a requirement of start of construction by the end of the year. As a result, most projects that started in 2013 and are scheduled for completion, let’s say, by the end of 2015 meet that standard, so the industry is not facing a real cliff right now. Indeed, we’ll see maybe as much as 6,000 to 10,000 megawatts of wind power capacity added this year.

But the PTC extension expired at the end of 2013, and we will see if it gets extended for 2014. The Senate Finance Committee several weeks ago did pass a bill that would extend that PTC through 2015, with the same start of construction language. If that were to be law, that would promote wind and other renewable energy development that could use the PTC easily through 2017 and possibly into 2018.

But that is just committee action. The bill has not gone to the Senate floor. It probably will pass the Senate, but there is pretty strong resistance to PTC extension in the House, and this issue may not get resolved until late this year, possibly in a lame-duck session of Congress. These on-again-off-again tax policies remove a lot of the certainty that developers are looking for. I can say unequivocally that without a production tax credit, companies like ours would not be building the large amount of the wind that we’ve built, because it would simply not be economic to do so as a regulated utility. Without the investment tax credit, solar certainly looks less attractive, as well.

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© 2014 The Planning Report | David Abel, Publisher, ABL, Inc.