Electric Industry Seeks Balance between Distributed Generation and the Traditional Grid

Posted on March 6, 2014 by Enerdynamics

by Matthew Rose, Enerdynamics’ Instructor

The industry “topic du jour” in 2013 was that utilities are facing dramatic and potentially disastrous changes to their business. These revelations could be traced to the Edison Electric Institute (EEI) assertion that various “disruptive technologies” including distributed generation and rooftop solar poised a direct assault on the financial viability of utility companies (see EEI, Disruptive Challenges: Financial Implications and Strategic Responses to a Changing Retail Electric Business, January 2013.)money v electricity

EEI stressed concerns that business rules and regulations in place for decades may no longer be relevant to the challenges in supplying and delivering electricity.  So far in 2014, we are seeing less of the dire rhetoric about the industry’s demise and more signs that the industry is addressing its challenges.

The recent meetings of the National Association of Regulatory Utility Commissioners (NARUC) served as the venue for an announced agreement between EEI and the Natural Resources Defense Council (NRDC), one of the industry’s environmental advocacy groups.

The two organizations issued a joint set of recommendations that call for regulators to re-think the traditional utility business model.  The key tenet of the agreement is that customers deserve the opportunity to install new distributed generation technologies as a means of better controlling their energy use while keeping utilities financially whole and able to capture costs to maintain the grid.

A summary of the eight recommendations follows:

  1. The retail electricity distribution business should not be viewed or regulated as a commodity business. Instead it should focus on meeting customers’ energy service needs.
  2. Regulators should consider breaking the link between cost recovery and commodity sales while providing reasonable and predictable non-fuel revenue requirements.
  3. Customers with net metering need to provide reasonable cost-based compensation for relevant utility services used while also being compensated fairly for the services they provide back to the grid.
  4. Utilities deserve assurances that recovery of their authorized non-fuel costs will not vary with fluctuations in electricity use. Customers deserve assurances that costs will not be shifted unreasonably to them from other customers.
  5. Regulators should consider expanding utilities’ earnings opportunities to include performance-based incentives tied to benefits by cost-effective initiatives that improve energy efficiency, integrate clean energy generation, and improve grids.
  6. Effort should be directed to ensure that energy efficiency services reach underserved populations.
  7. A measurable goal should be set forth to help ensure electricity users take advantage of all cost-effective energy efficiency opportunities.
  8. State regulators should be called upon to reaffirm support of enhanced utility investment in ‘smart meters’ and a ‘smart grid.’

It should come as no surprise that the agreement was announced at the NARUC meetings since state regulators are key stakeholders. The rationale behind the agreement suggests utility acknowledgement that renewable and distributed generation technologies are a legitimate, ongoing opportunity for customers. NRDC also seems to recognize that only utilities have the ability to integrate renewables at scale, and no one benefits from a financially strapped company. Hopefully 2014 holds more opportunities to address these utility challenges.

Want to learn more about how the utility business will change as customers build more distributed generation? Attend Enerdynamics’ seminar Distributed Energy, Renewables and Microgrids in Chicago April 7-8, 2014.

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Drop in Electric Demand and Spike in Rates an Ignored Issue in the Midwest

Posted on February 27, 2014 by Enerdynamics

By Bill Malcolm, guest author

When EPA announced new emissions regulations affecting coal power plants, some in the industry predicted resulting power outages. But as coal retirements occur, the situation 467018221looks much less dire. Initial 8,500 MW power shortfall predictions for 2016 in MISO have been revised to be 2,000 MW. The EPA-induced retirements were not that big a deal after all.

Indeed, many Midwest states wondered exactly where the shortfall was since in their state they had a surplus. Here in Indiana, Purdue does its 20-year electricity supply and demand forecast, and it showed a 30% reserve margin this summer and 18% after that.

Indeed, the message from the Purdue study, a recent Department of Energy EIA report, and other sources is that power demands are flat or dropping in most areas of the nation.  As the Purdue study noted, such a trend has never been seen before.

Those few utilities that are short for 2016 need to enter into power purchase contracts to cover their needs beyond what they can generate themselves or have already contracted for in long-term supply agreements. Available sources in the Midwest apparently include several Exelon nuclear plants including the 1,000 MW Exelon Clinton nuclear power plant and the 2,000 MW Exelon Quad Cities nuclear power plant. The company’s CEO said plant closure is an option if the plants can’t be economically operated. Significant amounts of other uncontracted merchant generation also appears to be available.

Accordingly, state regulators should tell their utilities that before we put new steel (gas-fired or otherwise) in the ground, we need to use the power plants that we already have.  No more Kewaunees, please. Kewaunee was a merchant nuclear power plant in Wisconsin that was recently closed by its owner, Dominion, after the company said it could not economically operate the plant. This resulted in a loss of around 600 MW of electricity.

The former utility owners of the plant are both building new gas-fired generation to replace their former purchases from the nuclear power plant when already available merchant generation is sitting underutilized. A better solution may be to provide utilities with incentives to contract for purchased power going forward. Further, increased incentives for demand response and energy efficiency might also be called for to deal with any shortfall.

Energy policy makers need to consider if the current regional surplus and sharply rising rate levels (coupled with flat line demands for the next 20 years) calls for a new strategy: a slow down in new energy investments (generation and transmission) while demand absorbs the current over-supply. In short, energy officials need to focus on the fact that many Midwest states have lost their low cost electricity advantage, and this may reduce the need for ongoing construction. We need strategies to cope with this new reality.

Want to learn more about how the utility business will change as customers reduce loads and build more distributed generation? Attend Enerdynamics’ seminar Distributed Energy, Renewables and Microgrids in Chicago April 7-8, 2014. The last day of the seminar will explore new utility business models that will allow utilities to still be profitable without building new power plants.

About the author: Bill Malcolm is an energy economist based in Indianapolis. He has worked for PG&E, MISO, and ANR Pipeline. He can be reached at billmalcolm@gmail.com.

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Will Facebook, Google, Apple, and Amazon Displace Your Utility?

Posted on February 20, 2014 by Enerdynamics

by Bob Shively, Enerdynamics President and Lead Instructor

One of the more outspoken and forward-thinking executives in today’s energy industry is NRG Energy’s CEO David Crane.  When recently asked who NRG’s competitors will be in the future, he responded:

“If you ask me who I worry about beating us, I give very little thought to the traditional power companies, the utilities.”[1]

He then went on to discuss technology companies such as Facebook, Google, Apple, and hand holding social iconsAmazon as well as cable companies such as Comcast. This is because Crane believes the future will belong to distributed generation including rooftop solar photovoltaic and small-scale natural gas generation such as fuel cells, Stirling engines, and cogeneration units.[2]

Crane thinks the technology companies hold the key because if you believe in the distributed resource future, you have an operational problem. Right now, loads and supply are balanced at the bulk grid level by large utility or merchant-owned power plants, some of which are continuously ramped up and down by the system operator’s Energy Management System (EMS) in response to fluctuations in loads. If we move to a distributed model, someone or something is going to have to provide a similar function at the local level. As Crane says:

“One of the changes we’re talking about when you’re talking about balancing everyone’s power systems in their house is that it basically becomes an information technology-based industry.”[3]

Japan is one country to look at when pondering the possibilities. Since the Fukushima Daiichi nuclear disaster, Japan has had to figure out how to run a modern economy with a sudden loss of 30% of the country’s generation capacity while also creating a new grid that is more resilient to possible future shocks. One answer is to move to a model of local microgrids that can operate interconnected with the larger bulk grid or can be isolated and continue operating on their own using distributed generation.

One small area of the devastated port city of Sendai maintained power after the tsunami – the microgrid at the Tohoku Fukushi University.[4] Since then Japan has become deeply interested in developing microgrids and is working world-wide to create the right mix of energy assets and information technology.[5]

As I write this, Enerdynamics’ instructor Dan Bihn is flying to Jamaica to join the Japanese government in discussing microgrid applications with the Jamaica Public Service Company. Contributing to Japan’s push in microgrids are various Japanese technology companies such as Fuji Electric, Hitachi, Panasonic, and Toshiba.

Which leads us back to the question: If a distributed energy future is coming, who will own and operate the microgrids and in-home networks that will enable this future? Utilities will struggle with significant regulatory and institutional barriers. Technology companies will struggle with figuring out how to turn cool technologies into services that work for consumers while meshing with the complex energy marketplace.

Perhaps it is the energy services companies such as NRG, Direct Energy, and Constellation  that the utilities should fear most. Or maybe it is natural gas companies copying the activities of Tokyo Gas’ Roppongi Energy Services Company that is now providing electricity and heat services to multiple customers connected to a microgrid in a  redeveloped neighborhood in central Tokyo.[6] Only time will tell.

393px-Roppongi_Hills_Mori_Tower_from_Tokyo_Tower_Night

Roppongi Hills, Tokyo
Source: This Wikipedia and Wikimedia Commons image is freely available at commons.wikimedia.org/wiki/File:Roppongi_Hills_Mori_Tower_from_Tokyo_Tower_Night.jpg under the creative commons cc-by-sa 3.0 license.

Want to learn more about distributed energy and microgrids and what they mean for the future of the utility business? Join Dan Bihn and me at Enerdynamics’ Distributed Energy, Renewables and Microgrids seminar April 7-8, 2014, in Chicago.  For more details go to our website.

References:

[1] http://www.theatlantic.com/technology/archive/2013/11/who-will-compete-with-energy-companies-in-the-future-apple-comcast-and-you/281109/
[2] See for instance: http://world.honda.com/cogenerator/index.html?id=3-b, http://www.greentechmedia.com/articles/read/NRG-Energy-Deploying-Dean-Kamens-Solar-Smart-In-Home-Generator  ,  http://www.bloomenergy.com/fuel-cell/energy-server/
[3] http://www.theatlantic.com/technology/archive/2013/11/who-will-compete-with-energy-companies-in-the-future-apple-comcast-and-you/281109/
[4] See a discussion at: http://spectrum.ieee.org/energy/the-smarter-grid/a-microgrid-that-wouldnt-quit
[5] http://www.greentechmedia.com/articles/read/japan-land-of-the-pv-and-ev-connected-smart-grid
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Why the Only Super Bowl Outage Was the Broncos’ Play

Posted on February 13, 2014 by Enerdynamics

By Bob Shively, Enerdynamics President and Lead Instructor

Flash back to one year ago and many post-Super Bowl articles started like this one from CBS: “A power outage at the Super Bowl put the nation’s biggest sporting event on hold for more than a half-hour Sunday, interrupting an otherwise electric, back-and-forth 455626791game…”[1]

This year, the articles (sadly, given that Enerdynamics is headquartered in Colorado) all focused on the dominance of the Seattle Seahawks. Few gave a thought to the fact that the power stayed on throughout the game. Here’s a look at the behind-the-scenes efforts that ensured MetLife Stadium would not have a repeat headline-grabbing power outage[2].

During a normal Giants or Jets game, the stadium has a demand of about 12 MW.  But for the Super Bowl, 18 MW was expected. The New Jersey Sports and Exposition Authority that runs the stadium and Public Service Electric & Gas (PSE&G) that serves the stadium with electricity spent over a year preparing to reliably serve the electric demand.

Prior to upgrading, the stadium was served by two 12 MW feeders. Since both would need to be in use to serve 18 MW, and there would not be sufficient capability to serve 18 MW if one line failed, PSE&G brought in a third feeder. And in the event that a service transformer failed, PSE&G located a backup mobile transformer within a mile of the stadium.

Power is delivered to the stadium by PSE&G at transmission voltages, at which point power delivery is managed by the Stadium Authority. This includes a substation within the stadium to reduce voltage to levels used the by stadium equipment. So the Stadium Authority had work to do, too.

The substation was upgraded, and then, in attempt to avoid the problem that occurred last year in the Superdome when a relatively new piece of equipment failed, all equipment was checked extensively. A consulting firm was brought in to shoot infrared images of all internal wiring, and the whole stadium was run at expected Super Bowl levels of demand during a staged test in October. Minor issues identified were addressed following the test, and, as we now know, everything worked as planned.

But does that mean that PS&G and the Stadium Authority were sure the power was not going to go out during the game? Absolutely not, it simply means that they did what they believed practicable to reduce the probability of an outage. As University of Pittsburgh energy engineering expert Dr. Gregory Reed told the Associated Press:

“You can certainly put in more redundancy, but you can’t back up 100 percent (of) the entire load (or) infrastructure of every single wire, every single cable of every transformer in a network because it’s impractical from a cost point of view. You can do what you can using good engineering judgment on reducing the risk of an outage but you can’t guarantee it 100 percent. Anything can happen. When it does, then you have to be prepared to react to it.”[3]

So now we know how the probability of a power outage at MetLife Stadium was reduced through careful effort. And if you are expecting me to also explain why the Broncos had a game-long power outage, you are reading the wrong article. More than a week after the game, I still find it totally inexplicable!

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Virtual Net Metering and the Future of Community Solar

Posted on February 6, 2014 by Enerdynamics

Thanks to the folks at Clean Energy Collective for sharing this great article! 

by Emily Hois, Clean Energy Collective

Community solar is gaining momentum across the United States, making solar energy available to more people than ever before. One of the keys to facilitating shared solar is policy. “An interesting facet of policy is what it enables people to do within a given state,” Anna Brockway, SunShot Fellow at the US Department of Energy, said in a panel discussion. “If a state has some sort of virtual benefit legislation—like virtual net metering
—that enables different types of shared models that wouldn’t be possible otherwise.”

Virtual net metering allows multiple homeowners to participate in the same metering system and share the output from a single facility that is not physically connected to their property (or their meter).  This scheme goes a step beyond net metering, which allows individuals to sell excess energy produced by their on-site solar system back to the utility grid and receive credits on their electric bill.

New Legislation in Minnesota and Washington DC
In 2012, nine states had enacted some form of virtual net metering policy (CA, CO, CT, IL, ME, MD, MA, RI and VT). During 2013, Minnesota and the District of Columbia were added to the list, passing legislation to help both reach their individual Renewable Portfolio Standard (RPS) requirements. This fall, the Washington DC City Council unanimously passed the Community Renewables Act of 2013, legalizing net metering for solar gardens up to 5 megawatts. “Virtual net-metering is great for a city like DC where there are large populations of renters, who would typically not be potential solar customers,” reports MDV-SEIA, the Solar Energy Industries Association serving Maryland, the District of Columbia and Virginia. “This will also help DC meet its renewable portfolio, which states that they must build 250 megawatts of renewable power systems by 2021.” As of October, the District had eight megawatts installed.

In May, the Minnesota legislature passed a law requiring investor-owned utilities (including Xcel Energy, the state’s largest) to obtain 1.5 percent of their energy from solar power by 2020. This is in addition to Minnesota’s existing RPS requirement of 25 percent by 2025. To achieve the new 1.5 percent carve out, investor-owned utilities must increase their solar generation more than 30 times to reach 450 megawatts in the next seven years. With new clean energy legislation that includes a community solar program, Minnesota has already begun utilizing shared solar as a way to expand its renewable portfolio.

No One-Size-Fits-All Approach
Solar advocates and policymakers alike are realizing that there’s no one-size-fits-all approach to community solar legislation. “The space is so quickly emerging and developing that there’s a lot to understand [about] how different programs work and what makes the most sense for a given region, for a given company, for a given set of stakeholders,” Brockway says.

For example, the geographic requirements to participate in virtual net metering vary by state. Massachusetts requires community solar customers to live in the same neighborhood as the solar array. In Colorado, subscribers must only live in the same county or utility service territory.

Another varying requirement is the type of customers who may participate in virtual net metering. In Maryland, only local governments, agricultural customers and nonprofits such as churches and schools are permitted to participate in virtual (they call it ‘aggregated’) net metering.

The Future of Virtual Net Metering
Will virtual net metering be a necessity to the widespread adoption of community solar? That seems to be the million dollar question. As virtual net metering becomes more “standard,” as PV Magazine reports, community solar is “poised for expansion”— pending state legislative prerequisites that allow group net metering.

However, the Massachusetts Department of Energy Resources (DOER) released a report in March that claims community shared solar models that rely on virtual net metering services “may only be viable for a few years, or less, in some utility service territories.” While the findings were specific to Massachusetts, DOER revealed the development of larger distributed generation projects that relied on net metering were predicted to stall as state-mandated caps on net metering were reached.

Alternatives to Virtual Net Metering
Virtual net metering is not necessarily “an intrinsic part of solar community gardens,” reports Ecopolitology, an organization that investigates the politics of energy. “Independent companies or the utility could install, operate, and manage ‘subscribers,’ making solar gardens simpler and even more attractive for the average Joe.”

As an alternative to virtual net metering, DOER recommends a community solar model where participants receive a return on their investment instead of a reduction on their utility bill. Customers would then generate revenue through two sources: the sale of SRECs that the solar system produced, and the sale of clean energy to the site owner through a power purchase agreement (PPA).

Clean Energy Collective has adopted this type of model—one that supersedes the constraints of net metering laws through partnerships with utilities and billing software that doesn’t require legislation to distribute on-bill credits to customers. “Outside of a solar gardens program or virtual net metering—some kind of policy—we need the utility’s permission. So the utility is actually the gatekeeper with us,” says Paul Spencer, founder and CEO of Clean Energy Collective.

Mosaic’s community model focuses on connecting investors with solar projects that need financing, and pays investors back with interest as the project earns revenue. With this “crowdsourced” approach, Mosaic becomes a lender to solar developers—and a solar loan feels like a typical loan, explains Chief Investment Officer Greg Rosen. “It’s an early stage in community solar and [Mosaic is] trying to figure out which of these business models are going to be suitably acceptable to a broad enough group of stakeholders.”

As the solar industry continues to mature, it will be interesting to see how the different community solar models fare, says Spencer. “I don’t think there’s one good solution out there.”

 

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2014 Seminar Series Covers Energy Industry Basics and Timely Topics like Shale, LNG

Posted on January 30, 2014 by Enerdynamics

Enerdynamics’ most popular seminars on electric and natural gas industry basics are back in 2014 as part of our public seminar series. Additionally, this year’s line-up features three178592212 new seminars that explore some of the hottest topics affecting today’s energy landscape: LNG, shale gas, natural gas liquids, distributed energy, renewables, and microgrids.

The 2014 seminar series comprises 11 seminars in four major U.S. cities: Chicago, Houston, New York City, and Washington D.C. Each seminar spans two days and is designed with active participation in mind. Questions and discussion among attendees are highly encouraged. Various individual and group exercises  give attendees a real-world perspective of how the course content relates to their jobs in the industry.

The 2014 Seminar Series schedule is as follows:

Electric Industry Basics: Learn the physical system, customers, markets, and regulation to communicate more effectively and make better decisions

    • March 24-25, Chicago (Omni Chicago Hotel)
    • April 16-17, Houston (Magnolia Hotel)
    • October 15-16, Chicago (Omni Chicago Hotel)
    • November 3-4, Washington DC (Dupont Circle Hotel)

Distributed Energy, Renewables and Microgrids: How to navigate the utility industry’s biggest threats (New seminar!)

      • April 7-8, Chicago (Omni Chicago Hotel)

Wholesale Power Markets: How to use electric markets to serve customers, create profits, and manage risk

      • April 9-10, Chicago (Omni Chicago Hotel)

Gas Industry Basics: Learn the physical system, customers, markets, and regulation to communicate more effectively and make better decisions

    • April 14-15, Houston (Magnolia Hotel)
    • October 13-14, Chicago (Omni Chicago Hotel)

Liquefied Natural Gas Markets: A big risk or a timely opportunity?
(New seminar!)

    • April 29-30, New York City (The Roosevelt Hotel)

Shale Gas and Natural Gas Liquids: Has the shale revolution made natural gas a safe bet? (New seminar!)

    • May 13-14, New York City (The Roosevelt Hotel)

Seminar fees range from $1,290 to $1,590 depending upon the seminar and how early you register. (A $200 discount is given to those who register for a seminar at least three weeks prior to the seminar start date.) Registration fees include continental breakfast, lunch, and an afternoon snack. The fee also includes course materials and a networking reception the first night of each seminar.

Companies who have 8 or more participants may want to consider having Enerdynamics bring this seminar to its work site. We can also customize the content for a specific company or geographic region. Call us at 866-765-5432 to discuss your onsite options, or send us an email.

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States and Utilities Rethinking Customer-funded Energy Efficiency Programs?

Posted on January 23, 2014 by Enerdynamics

By Matthew Rose, Enerdynamics Instructor 

The level of spending and activity in customer-funded energy efficiency programs is rising. With the increase in state-level energy efficiency resource standards (EERS) and compliance targets, funding for energy efficiency programs reflects an increasing commitment.  At last count there are 26 states with various forms of directives requiring utilities or independent state administrators to spend ratepayer dollars on energy efficiency programs that meet specified savings targets[1].

Despite this forecast growth in spending, there exists a small but growing undercurrent of utilities and state regulators looking at retrenching demand-side management expenditures and accompanying program impacts. The move to reconsider efficiency targets reflects a confluence of industry issues and trends that, in some cases, counter the presumed growth in customer-funded energy efficiency.

Following are examples of states or utilities that are reexamining relevant energy efficiency spending and impacts to business operations. Examples of goal setting that have been impacted by changing market conditions are also noted. (For a more in-depth explanation on why this is happening, read the article in our latest issue of Energy Insider.)

Colorado: Xcel Energy filed for Commission approval on its 2014 Energy Efficiency Plan that includes reduced savings goals for some traditional energy efficiency programs[2]. The filing is based on a recent market potential analysis that indicated an inability to capture enough cost-effective savings to meet previously established goals. The study identified the advancement of appliance standards as a key element in the goal shortfall. The filing calls for a proposed $6.9 million in electric DSM budget cuts across 10 programs.

Iowa: The Iowa Utilities Board recently approved Alliant Energy’s Interstate Power and Light Company energy efficiency plan[3]. Under the new goals, Alliant plans to save energy reflecting 1.1% of retail sales each year over the next five years. This is less than the utility’s current goal of 1.3% and its recent performance of 1.4%. The Board also allowed the company to suspend its incentive program for renewable energy installations, which has been in place for about five years. The Iowa Utilities Board is considering a similar proposal by MidAmerican Energy, with a final order expected before the end of the year.

Ohio: A recent Senate Bill (SB 58) was filed that would overhaul Ohio’s energy efficiency and renewable energy law[4]. SB 58 would nix the requirement that half of the renewable power come from Ohio-based projects[5]. SB 58 also allows large industrial consumers to opt out of state-mandated programs. The Bill would also allow utilities to count upgrades they might have made anyway — such as equipment replacement or power plant upgrades — to count for increases in energy efficiency. The bill is currently stalled in committee.

Maryland: The State of Maryland (and its statewide Empower Maryland Program) has not met expected interim savings targets and is in jeopardy of falling short of its “15 x 15” energy efficiency targets (15% reduction by 2015)[6]. The state is trying to accelerate savings, and the Maryland Energy Administration anticipates a near doubling in impacts in 2013-2015 (as compared to 2010-2012), but overall the savings have a strong possibility of falling short.

Arizona: Arizona Corporation Commissioner (ACC) Gary Pierce recently filed a letter requesting the Commission reevaluate the state’s EERS rules. Arizona Public Service has informally noted that, given changes in the marketplace and the economy, it may be difficult to meet the current 22% reduction by 2020. No imminent changes are expected in the short term as the ACC is focused on addressing issues of restructuring and net metering[7].

In addition to the above states, there is anecdotal evidence suggesting other utilities are closely monitoring the impact of energy efficiency on their operations and trying to determine the ability and costs for complying with savings targets.  Whether these are isolated exceptions or the origins of a larger movement is not yet clear. It is clear, however, that utilities are carefully measuring the impacts of delivering energy efficiency and looking for ways to reduce risks and limit exposure.

References:

[1] American Council for an Energy Efficient Economy, York, Kushler, Hayes, Sienkowski, Bell and Kihm, Making the Business Case for Energy Efficiency: Case Studies of Supportive Utility Regulations, December 2013

[2] Xcel Energy filing, Colorado-Docket Number 13A-0686EG

[3] Iowa Environmental Council, Iowa Utilities Board Approves Cuts to Alliant Energy’s Efficiency Efforts, December 2, 2013

[4] As Pending in the Senate Public Utilities Committee-130th General Assembly 2013-2014 Regular Session- Sub S.B. No. 58

[5] Ohio considers: Is energy efficiency worth the money? by Chrissie Thompson, Cinncinnatti.com, December 4, 2013

[6] Maryland ninth on energy efficiency, may fall short of goal; Two reports on efficiency say utility programs must ramp up, by Jamie Smith Hopkins, The Baltimore Sun, November 06, 2013

[7] Source: American Council for an Energy Efficient Economy, webinar presentation. Energy Efficiency in the States: 2013 Outlook, March 2013

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Fundamentals Rule Natural Gas Pricing, Part II

Posted on January 16, 2014 by Enerdynamics

by Belinda Petty, Enerdynamics Instructor

Last week’s blog post discussed how and why fundamentals rule natural gas pricing. Following up on that discussion, here are a few examples of events or scenarios that in recent years have been game-changing on both the natural gas supply and demand sides.gas pipeline

Rockies oversupply
During the early 2000s, a new era of gas supply growth developed in the Rockies. Producers began drilling coalbed methane. This new dry gas source was quick to drill and easy to standardize without the need for lots of new processing plants. While area and regional demand absorbed some of the new production, supply quickly outstripped demand by 2005. Rockies prices, which had been rising in concert with national natural gas prices, began to fall.

By 2007 Rockies prices had dropped by more than 30% to less than $5/MMBtu, and some spot prices fell dramatically to as low as $0.05/MMBtu. Rockies producers had to do something to change the market fundamentals or they were all going to be broke!

By the late 1990s some producers, knowing a fundamental supply and demand mismatch was coming, began to discuss a new pipeline to move Rockies gas east. In 2004, the Rockies Express Pipeline (REX) construction began. By the time the first phase of REX received gas in 2007, Rockies supply far outweighed the demand. Rockies prices still traded at a significant discount to the rest of the market.

When Phase II came on line in 2008, Rockies prices flew up in response to the additional markets now accessed by the new pipeline capacity. The additional markets shifted supply from the Rockies to the Midwest, pushing out more expensive Gulf Coast supply and eroding the overall national price level. When Phase III opened new markets to Rockies supply all the way to the Ohio/Pennsylvania border, Rockies prices began to move in unison with the rest of the gas market.

The graph below compares the growth in production with the impact on Rockies regional prices during REX commissioning. The market saw the imbalance coming, but the lead time to react took longer than the growth of supply. Building pipelines, storage, or distribution systems take long periods of time due to regulatory requirements and capital commitments. So there is often a timing mismatch between a major market change and getting the assets in place to absorb the change.


Increase in natural gas electric generation
Overall gas supply in the U.S. has grown dramatically for the last five years. The growth has come as success in drilling shale formations has boomed. Initially, the new shale volumes were concentrated in the southeastern parts of the U.S., specifically in Texas and Louisiana. New supplies caused downward overall pricing pressure but were absorbed into a robust network of pipelines and markets accessible to Gulf Coast supplies.

However, as the Marcellus shale in Pennsylvania began its prolific rise in production, the supply and demand imbalance resulted in a fundamental shrinking basis between northeast prices and Henry Hub as well as Henry Hub gas prices falling from $4 to $2/MMBtu over the course of 2011.

 


But, as fundamentals change, markets adjust. Declining gas prices pushed natural gas into parity with coal as a fuel source for electric generation. Typically when gas prices drop below $5/MMBtu some inefficient coal units can no longer compete with gas generation, and as prices drop below $4/MMBtu fuel switching to gas becomes dramatic. As gas prices fell, electric generators accelerated the switch from coal to gas as the fuel of choice for generation. The new demand absorbed a huge supply overhang allowing prices to stabilize to today’s level.


Regional Marcellus supply basis shifts
Regardless of the overall supply balance position, regional factors can impact locational pricing in dramatic ways. This has been the case in the Marcellus shale basin at various points since 2011. The Leidy supply hub is the most recent example. New production has been building upstream of Leidy since 2009. In 2012, new production had grown to the point where no unused transmission capacity was available to move incremental gas to market. Producers began competing with each other to ensure their gas would flow.

Gas prices eroded to a one-day low of $.05/MMBtu. Market participants scrambled for ways to alleviate the bottleneck. From the first of 2013, new gathering, processing, and pipeline capacity has been built to allow the majority of production to move. With the last of a new 1Bcf/d tranche of transmission capacity commissioned on Nov. 1, 2013, Leidy pricing has shifted from a -$1.45 basis to Henry Hub to a -$.40 price basis to Henry Hub. The supply/demand balance has been restored with assets in place to move the majority of gas to market. Again, the time to get regulated assets in place took longer than the time needed to develop the production, gathering, and processing.

What does this say about the future?
Given the price instability we’ve discussed, is natural gas a reliably economical fuel source over the long term? Or is it too risky and are prices likely to rise soon? No one knows for sure. Variables include:

  • new asset and capital commitment
  • whether shale producers will continue to find and produce cheap supply
  • whether environmental concerns will curtail shale production
  • how quickly natural gas demand will grow
  • and whether natural gas exports will become significant.

A recent modelling effort by Stanford University[1] suggests that under most scenarios it is likely that prices will stay below $6/MMBtu over the next decade. But keep your eye on the changing fundamentals — as history has shown a change in fundamentals can result in dramatic shifts in natural gas prices.

References:
[1] See Changing the Game? Emissions and Market Implications of New Natural Gas Supplies, EMF Report 26, Volume 1, September 2013, p. 23 (available at http://emf.stanford.edu/files/pubs/22532/Summary26.pdf)

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Fundamentals Rule Natural Gas Pricing, Part I

Posted on January 9, 2014 by Enerdynamics

by Belinda Petty, Enerdynamics Instructor

Natural gas prices in North America rise and fall. In the last decade, the Henry Hub monthly price has been as high as $14/MMBtu and as low as $2/MMBtu. How can the same commodity at the exact same location be sold for seven times more one year than the next? Can we expect such instability to continue into the future, and should we be wary about becoming more dependent on natural gas as a key fuel?

Why price levels change
In North America, natural gas is a commodity whose price is driven by fundamentals. The value of natural gas, or price level, is determined by the perception of the supply and demand picture. Long supply, meaning suppliers are producing more supply than required by market demand, pushes prices down since buyers are able to negotiate price among multiple suppliers who need to sell for cashflow. Short supply means that production is equal to or less than demand. This results in buyers bidding up the price so they can get supply before another buyer does.

Currently in North America, the market perceives the balance to be supply long, and prices are at a traditionally low level below $4/MMBtu. Price volatility, or short-term price spikes and dips, is the result of a perceived supply and demand imbalance caused by supposed changes in underlying fundamentals. Once the fundamental factors causing the spike and dip resolve, prices should fall back in line with the overall perceived value of the commodity.

A century of natural gas use has led to the development of a robust set of assets to produce gas and move it to consumers, thus fulfilling the overall level of gas demand. These assets include a variety of supply basins with producing wells, gathering systems, processing plants, transmission pipelines, storage facilities, distribution networks, and a variety of customers. As long as there is excess capacity along the network of assets, there is flexibility to meet minor changes in the supply/demand balances. However, any major change in the balance disrupts the market, and the pricing, until the change can be absorbed.

This process may include getting new assets in place to alleviate the imbalance or customers changing their usage patterns. But in some cases, like the recent development of techniques to economically produce shale gas, major changes are structural and result in a long-term transformation of market fundamentals.

Market changes can come from anywhere along the value chain. Sometimes they impact the entire market. Other times they impact a region or location only. Next week’s post will look at some examples of game-changers in recent years on both the supply and demand side.

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The Energy Industry: A Review of 2013 Highlights and What May Come in 2014, Part II

Posted on January 2, 2014 by Enerdynamics

By Bill Malcolm, guest author

Happy New Year!

In last week’s Part I of this post, we looked at a few energy industry trends that emerged in 2013: low electric load growth, the closing of nuclear plants for economical reasons, and debates on retail choice. But there’s still much to discuss as we look back on 2013 and ahead to 2014…

Will solar power change the utility to just a distribution system operator?
A new trend in 2013 was a concern over the impacts of distributed generation (DG), net metering, and solar. Several states decided to pay the full retail rate for distributed generation when buying back power — far higher than its wholesale value.

With solar, some charged that it was being subsidized by non-participants and receiving grid services at no charge. An EEI Foundation Study, “Value of the Grid to Distributed Generation Customers,” found that solar was not paying its fair share of costs given it uses the grid 24 hours a day[1].

Another concern is cost shifting of solar subsidy and solar back-up/grid costs to non-participating customers. In November, the Arizona Corporation Commission allowed Arizona Public Service (APS) to impose a $5 per month charge on solar.

Solar advocates claim that the underlying rates are the real issue (i.e. the PG&E and SCE residential rates are steeply inverted thereby inflating the solar savings). Advocates also point to DG and a “dynamic microgrid” as the utility business model of the future, which can help manage extreme weather events like Superstorm Sandy (see November Public Utilities Fortnightly[2]).

RTOs continue to expand
It’s never a dull moment in the Regional Transmission Organization (RTO) footprint world. Always remember that RTO membership is voluntary.

On Dec. 19, Entergy and several neighboring utilities such as Cleco joined Midcontinent Independent System Operator (MISO). This adds 25,000 MW or so of generation to the grid and a distinctly Southern flavor to the grid operator once known as the Midwest ISO.

Meanwhile, Western Area Power Administration or WAPA (Great Plains Unit/Basin/Heartland) has announced it may join Southwest Power Pool (SPP). This could also force Montana Dakota Utilities (MDU) to switch to SPP from MISO given much of MDU’s service territory is surrounded by the WAPA control area.

WAPA — a federal power marketing agency — and its decision to join an RTO is quite a catch for SPP. Power Marketing Administrations (PMAs) are not subject to FERC jurisdiction and have historically been suspect about the push into a RTO.

In any event, we now will have two mega north-south RTOs (MISO and SPP) as well as the granddaddy of big RTOs, PJM. Only the Southeast, the desert Southwest, and the Northwest remain as RTO hold outs.

Challenges of wind integration increase with growth in wind, other renewables
MISO and ERCOT both now have more than 10,000 MW of wind, and the amount of wind coming on line is growing. ERCOT reports the Competitive Renewable Energy Zone (CREZ) transmission lines are about to come on line at a cost of $7 billion to transport Panhandle wind to the load centers. MISO’s multi-value projects (around $6 billion) also continue to be planned or built to, among other things, allow more wind to get to load centers.

In 2013, legislative attempts to repeal state wind mandates have gone nowhere. So look for more wind to come on line, which means integrating the variable resource will be more important than ever. States like Illinois and Minnesota have a 25% mandate.

Cost recovery trackers and regulatory streamlining
Why wait for the PSC to process your case in a multi-year proceeding? Several legislatures have enacted measures to shorten or streamline the regulatory process. These include bills to fast track rate increase requests for mandated programs, transmission infrastructure, and the like.

Other states are limiting the time PSCs have to process cases:

  • In Illinois, a formula rates bill was passed that fast tracks smart meter program roll out.
  • Indiana’s SB 560 gives the Commission just a year to process cases and created a new transmission and distribution cost system improvement charge.
  • Michigan allows utilities to put filed rates in effect subject to refunds.

 Look for similar bills to pop up in other states in 2014.

Gas, gas, and more gas
Low cost natural gas — buoyed by the dramatic increase in supply thanks to fracking — continues to be the fuel of choice for all new power plants. Natural gas for vehicles and fleets also is on the rise. My favorite is the new Laclede Siemens partnership to promote NGV fleets and fueling stations.

Conclusion
That’s all we have space for in this recap, but when it comes to the energy industry, there’s always more to discuss. I will save Order 1000, mergers, demand response, and the benefits of RTO capacity markets (or not), for a future article.

In short, 2013 has been an interesting year with many of the trends likely to continue into the New Year.

About the author: Bill Malcolm is an energy economist based in Indianapolis. He has worked for PG&E, MISO, and ANR Pipeline. He can be reached at billmalcolm@gmail.com.

References:
[1] Value of the Grid to Distributed Generation Customers, Edison Electric Foundation Study, updated October 13 at www.eei.org

[2] November 2013 issue of Public Utilities Fortnightly (articles on microgrid, game changers, and more).

 

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