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Distributed Energy Resources Give You Options

By Evelyn Teel

In the earliest days of electricity, generation happened close to where the electricity was used. A small hydro facility might have been used to power a single factory, or a coal-fired generator might have electrified a small town. As demand for electricity grew and we developed the capability to move it over long distances, power plants were often built in more remote areas. This allowed us to leverage distant resources such as waterfalls, build larger plants that could not be accommodated in denser areas, and keep pollution from population centers. Generation now may be coming full circle, with increased interest in Distributed Energy Resources (DER) – that is, a source or sink of power, whether located on the electrical distribution system or behind a customer meter, that operates near the facility in which it is used.

DER can provide power to one building, a campus, or even a town. In many cases, DER are connected to the grid to ensure stable, efficient power availability. If the distributed resources are not producing all the electricity the facility needs, the facility can pull power from the grid. Likewise, if the distributed resources are producing more electricity than the facility needs, the excess, in some cases, can be sold to the grid. Some systems are able to be disconnected from the grid, or “islanded,” in the event of an emergency. This means that if the rest of the grid goes down or experiences blackouts, the facility can still operate on its own, potentially at a reduced level. In some cases, the facility is permanently islanded, and therefore is disconnected from the grid entirely. This is less common, but can be an option for facilities operating in remote locations or requiring extra security.

Types of Distributed Generation

Depending on the energy requirements of the facility, the characteristics of the surrounding environment, and any organizational preferences, distributed generation can be composed of a variety of resources. The most basic type of resource might be a generator, providing emergency power in the event of a grid outage. From there, solutions can get increasingly complex, and may include one or multiple types of generation. 

Solar, a common distributed resource, must be balanced by either grid connectivity or other resources, due to its intermittent nature. Natural gas-fueled microturbines can be used, and a combined heat and power system can enable capture of waste heat from those microturbines, for space or water heating. Combined heat and power also can be leveraged in conjunction with industrial processes that have a thermal load. 

Microgrids may incorporate battery storage in order to store excess electricity for times onsite generation is not producing. The list of possible distributed generation resources goes on: wind, hydropower, geothermal district heating, geothermal heat pumps, waste biomass conversion to renewable natural gas, waste incineration, anaerobic digestion, and more. Careful consideration should be given when developing a system to ensure that the selected type(s) of generation is/are robust, reliable, and efficient.

Benefits of Distributed Energy Resources

As the costs of DER resources fall – either through reduced equipment costs or decreases in fossil fuel prices – there can be cost savings to implementing distributed generation resources. Energy costs may also become more predictable if not tied to wholesale electricity prices. 

One hidden source of cost savings with distributed generation relates to the fact that, when transmitting power over long distances, some of the electricity is lost in the form of heat. These transmission and distribution line losses are less of an issue when power is generated close to where it is used (i.e., in distributed generation). Though consumers do not directly pay for this lost electricity (approximately 5 percent of generated utility electricity), it is wrapped into the total cost of energy. When generation happens behind the meter and close to a facility, the consumer does not end up paying for lost electricity. Less wasted energy also means less unnecessary pollution. 

Microgrids, or distributed generation that can operate separate from the utility grid, can improve reliability and be integral to disaster planning. When a facility is no longer fully reliant on the grid for power, it is less susceptible to issues like grid outages and brownouts. If a facility is equipped to draw power from distributed resources, storage, and the grid, it benefits by having a fallback in case one power source fails. It is important to note, however, that some causes of grid outages, such as severe weather, natural disasters, or an electromagnetic pulse, can simultaneously damage distributed resources and grid resources. In addition, it is important to note that utilities may add “standby” charges in order to provide fallback power.

In addition to enhancing reliability, DER can also enhance security. Especially for facilities that require 24/7 uptime, distributed resources can provide a backup in the event that utility grid service is unavailable. These distributed resources may be as simple as backup generators, or may be a complex microgrid with multiple power sources, including storage. Facilities that require the utmost security may choose to be able to island, becoming reliant exclusively on distributed resources.

Case Studies

Incentives exist to implement some types of distributed generation, though they can vary over time. For example, there are incentives to support the installation of onsite photovoltaic (PV) solar arrays, but they are changing. The federal investment tax credit (ITC) for PV solar dropped to 26% of capital cost this year; it drops to 22% in 2021 and further to 10% in 2022 and thereafter. 

Particularly taking into account incentives, the financial benefits of distributed generation can be quite compelling. Here is an example of a planned 2,000 kW onsite solar PV generation system. Electricity produced via solar PV creates solar renewable energy credits (SRECs), which can be (I) retired, (II) sold to electricity load serving entities (LSEs) that must comply with state renewable portfolio standards (RPS), or (III) sold to end users who wish to further green their supply. The sale of SRECs in this case generates income each year. In the first year, these SRECs are worth approximately $113,704. The initial investment cost is just over $3.6 million. However, after accounting for the federal investment tax credit (ITC); bonus depreciation; the SREC income; and the energy savings realized by generating power onsite, the actual first year cost of the project is just over $1.7 million – less than half the total price tag. The breakeven point – the time at which the project is expected to have paid for itself – is six years. Given that the lifespan of solar panels is approximately 25 years, this leaves plenty of time for significant cost savings. 

The value of onsite generation might be measured by more than just its financials, however. We also calculated that, over the estimated 25 year lifespan of the solar panels, the facility would save on carbon emissions equivalent to: more than 45 million pound of coal not burned; nearly 14,000 tons of waste recycled rather than landfilled; more than 4.6 million gallons of gasoline not consumed; or 679,763 tree seedlings grown for 10 years. This analysis indicates not only the financial upside of the project, but also the long-term carbon savings it enables.

Below are summary financial analyses related to three under development distributed generation (onsite solar PV) projects, including the project outlined above (Project A).

Project AProject BProject C
Onsite Solar2,000 kW1,700 kW2,000 kW
Year 1 Summary$$$
Initial Investment(3,644,028)(2,872,343)(3,717,150)
26% Federal ITC947,447746,809966,459
Depreciation Cash Value650,459512,713663,511
Energy Savings (year 1)205,732220,028263,612
SREC Income (year 1)113,704130,554367,507
Year 1 Cash Flow(1,726,686)(1,262,239)(1,456,061)
Financial Statistics
Breakeven6.04.82.9
After-Tax IRR13.6%18.9%32.8%
After-Tax NPV$2,210,468$2,995,331$3,898,417
Environmental Offset*
Pounds of coal not burned45,297,59038,502,95241,900,271
Tons of waste recycled, not landfilled13,98311,88612,934
Gallons of gasoline not consumed4,625,8503,931,9734,278,911
Tree seedlings grown for 10 years679,763577,799628,781
*Over 25 years, carbon savings equivalent to one of the above

When deciding whether to pursue distributed generation – whether through solar, combined heat and power, geothermal, biofuel, or others – it is crucial to work with an independent partner not only to understand the options that best fit your needs but also to identify the equipment or service providers that will most effectively implement your desired approach. Just as with competitive supply contracts for electricity and natural gas, the lowest priced option is not always the best, and it is important to understand all the fine print before making a decision. When implementing distributed generation, it is also important to ensure that you have appropriate contracts in place for supplemental electricity service or to enable the sale of excess electricity back to the grid.

We anticipate continued interest in distributed generation, not only for its potential fiscal benefits but also its potential reliability and security benefits and clean energy credentials. Please contact us if you are interested in learning more.

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484-8096, or email us at info@avalonenergy.us. 

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Copyright 2020 by Avalon Energy® Services LLC

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NCAC – 22nd Annual Washington Energy Policy Conference

ONE WEEK FROM TODAY

Secure your spot here: https://www.ncac-usaee.org/event-2845352

Energy Technologies and Innovations: A Disturbance in the [Market] Force

Thursday, April 12, 2018, 8:30 AM to 6:00 PM

The George Washington University

Keynote speakers:

Mark P. Mills, Senior Fellow, Manhattan Institute

Gil Quiniones, President and CEO, New York Power Authority

In addition to these keynote speakers, the following panels will be held:

PANEL 1: The Grid Awakens: Electricity Generation and Demand
Phil Jones, Executive Director, Alliance for Transportation Electrification
Bryce Smith, Founder and CEO, LevelTen Energy
John Zahurancik, COO, Fluence
Barney Rush, Board Member ISO New England, Rush Energy Consulting (moderator)

PANEL 2: Hydrocarbons Strike Back: Innovations to Maintain the Status Quo

John Eichberger, Executive Director, Fuels Institute
Sid Green, President, Enhanced Production Inc.
Mike Trammel, Vice President for Government, Environmental, and Regulatory Affairs, Excelerate
Rita Beale, CEO and President, Energy Unlimited (moderator)

PANEL 3: Innovation: A New Hope in Energy

Bill Farris, Associate Laboratory Director for Innovation, Partnering, and Outreach, National Renewable Energy Laboratory
Elisabeth Olson, Economist, Office of Energy Policy & Innovation, FERC
Christopher Peoples, Managing Partner, Peoples Partners and Associates
Devin Hartman, Electricity Policy Manager, R Street Institute (moderator)

PANEL 4: Return of Energy Policy

Adele Morris, Policy Director for Climate and Energy Economics, Brookings
Jason Stanek, Senior Counsel, House Energy & Commerce Committee, Subcommittee on Energy
Pat Wood, Chairman, Dynegy
Kevin Book, Managing Partner, ClearView Energy Partners (moderator)

Note: Chatham House Rules apply.

Full Agenda and to register –> http://www.ncac-usaee.org/events.php#event151

RSVP: Required

Conference Information:

Organizer: Michael Ratner, NCAC-USAEE Vice President (mratner@crs.loc.gov) / 202-707-9529
Venue: The George Washington University, The Marvin Center, 3rd floor, Continental Ballroom, 800 21st Street, NW, Washington, DC 20052

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Time to Draw Down the Strategic Petroleum Reserve? – Part 2

It has been argued that there is too much crude oil in the Strategic Petroleum Reserve and that it should be drawn down.  Arguments have been made that one should “tie the amount of insurance you carry to the size of the need.”  By that argument, because domestic production is up and “hit record levels in 2011,” and imports “have dropped by more than 20% since 2006,” the reserve is “just too big and full” (see note 1).  It has also been claimed that over the first 30 years of the SPR’s existence, “its volume averaged fewer than 550 million barrels – 75% of capacity” (see note 2).

Background

The creation and stocking of the US Strategic Petroleum Reserve was enabled by the Energy Policy and Conservation Act of 1975 (EPCA).  The EPCA stated that the purpose of the Act was “…to provide for the creation of a Strategic Petroleum Reserve capable of reducing the impact of severe energy supply interruptions.”    See previous discussion concerning the SPR here.  The SPR can hold a total of 727 million barrels of crude oil and is currently at 96% capacity.

Over time, how much crude has been held in the SPR?   

The graph below shows the stock of crude oil in the SPR since its creation.

Over its life, the SPR has held an average of 519 million barrels of oil, which is 72% of its capacity.  As you can see on the graph, it took many years to construct and fill the SPR.  In fact, it was as recently as December 27, 2009 that the SPR actually reached its full capacity of 727 million barrels.  However, the many years it has taken to fill the SPR isn’t relevant concerning the working level for which it was designed.  The SPR was intentionally filled slowly so as to not appreciably affect the market price of petroleum products.   This has been accomplished in part by using royalty-in-kind crude oil from US Outer Continental Shelf leases.  In 2005, EPCA was amended to increase the size of the SPR to one billion barrels, in part as recognition that US crude oil consumption has increased since 1975.  Efforts to expand the SPR to one billion barrels were suspended in 2011.

How exposed are we to foreign imports?

Today, crude oil imports represent 42% of US consumption.  The graph below shows the ratio of net imports to US consumption plotted over time.

In 1975, when the Energy Policy and Conservation Act was enacted, crude imports represented 36% of total US consumption.  After that, imports rose to 47% during December 1977, declined to 27% in October 1985, and then generally rose again to a peak of 66% during October 2005.  Since October 2005, imports have fallen to 42%.

Conclusion

While it is accurate to say that imports have fallen from a high of 66% to 42% today, imports are still above 36%, the level of imports that existed at the time EPCA was enacted in 1975.  While US dependence on crude oil imports has dropped over the last seven years, today it is greater than it was in 1975.  Relying on the original intent when the SPR was established, there is no need to draw down the SPR.

Note 1 – Opinion piece by Austan D. Goolsbee in the The Wall Street Journal, April 10, 2012.

Note 2 – IBID.

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484- 8096, or email us at jmcdonnell@avalonenergy.us.

Copyright 2012 by Avalon Energy® Services LLC

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Natural Gas Prices Continue to March Down

March is the last month of the five month winter heating season.  As of March 30, the level of US working gas in storage was 2,479 BCF.  This is an increase during a time of the year when natural gas is historically withdrawn from storage, not injected.  The March 30 level is 927 BCF, or 59.7% greater than the average March working gas level of 1,552 BCF recorded over the previous five years.  The graph below shows the minimum, average and maximum levels of working gas in storage over the years 2007 through 2011 as well as the levels recorded so far during this year, 2012.

The graphs below show the January, February and March working gas storage levels compared to the average level over the period 2007 through 2011.

As seen in the table below, the volume of natural gas in storage continues to increase compared to the historical average.

Yesterday, the May natural gas futures contract settled at $2.09 per Dekatherm.

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484- 8096, or email us at jmcdonnell@avalonenergy.us.

Copyright 2012 by Avalon Energy® Services LLC

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OFO (No Room at the Inn)

Huh? What does OFO mean? First, a step back.

The US natural gas pipeline and distribution system can be thought of as a large container with producers injecting natural gas (supply) and customers withdrawing natural gas (demand).  Last year, during 2011, the US consumed 24.4 trillion cubic feet (TCF ) of natural gas, or, on average, about 67 billion cubic feet (BCF) per day.

Interconnected with the US pipeline system is about 4 TCF of working gas storage capacity that is used to help balance supply and demand. Generally, natural gas is injected into storage during the summer and fall and withdrawn during periods of peak winter demand. Formation pressure from natural gas wells along with pressure added to the systems by mechanical compressors (driven by reciprocating engines and gas turbines) move natural gas through the pipeline and distribution systems. There are times when customers take more natural gas out of the pipeline and distribution network than is being injected by production wells or from storage. This can occur during prolonged cold spells and when surface equipment associated with production wells freezes over, for example. In these cases, the result will be a decline in system pressure. As system pressure drops, the ability to deliver natural gas to all customers diminishes. Systems operators have several tools available to manage pipeline pressure, including using “line pack” or also interrupting service to some customers. However, during extreme conditions, these tools may not be enough to maintain system pressure and operators may resort to an Operational Flow Order (OFO).

An OFO is an order to transportation customers and their suppliers that they together must keep the amount of natural gas they inject into the system within a tight limit compared to the amount of natural gas a customer burns. If injections for a customer fall below the threshold compared to actual burns, penalties are applied which, in the worst case, can be substantial.

So far, the 2011/2012 winter has not been very cold. Why, then, would a discussion of OFOs be of interest today?

On Friday, March 16, Delmarva Power (which operates a natural gas distribution system) issued an Operational Flow Order “until further notice.” This OFO was issued “due to warmer than normal weather conditions…and the inability to inject gas into storage.” So, here we are still in the winter heating season, when distribution companies are normally withdrawing natural gas from storage, and Delmarva has run out of storage capacity into which to inject natural gas. Rather than being concerned that system pressure will drop to an unacceptably low level, the concern is that system pressure will RISE to an unacceptably HIGH level.

Rather than being concerned that customers will withdraw more natural gas from their system than is delivered into their system, in their OFO, Delmarva indicates that “customers may deliver no more than one hundred and five percent (105%) of the volumes of gas tendered for burn by the customer on a daily basis, net of losses and unaccounted-for gas.”

Because deliveries are scheduled in advance (“nominated”) and because actual usage can vary significantly due to changes in weather and other factors, this is a tight threshold on a short cycle (daily) basis.

And what if a customer over delivers? Delmarva’s OFO states, “For all such … over-delivery volumes, a charge of THIRTY FIVE DOLLARS ($35.00) per MCF will be applied…” (emphasis added).

Currently, Delmarva’s commodity cost rate is $5.28 per MCF. This means the penalty is 563% of the cost of delivered natural gas. If you file your taxes late, you may be subject to a 10% penalty. If you deliver natural gas over the threshold into the Delmarva system, the penalty is more than SIX-FOLD the commodity cost of natural gas.

OFOs, when they are issued, occur during the winter. OFOs issued to ensure adequate delivery of natural gas during times of exceptionally cold weather do occur but are infrequent. OFOs, such as this one, issued during winter time to ensure that excess deliveries are not made are highly unusual. An employee of another East Coast natural gas utility indicated that over the company’s life, there has never been an OFO related to reducing system pressure during the winter time. The size of the penalties in the case being discussed here is a measure of how significant the current oversupply situation is.

What is driving this situation? Simply put, the combination of unusually warm weather this winter and diminished industrial demand for natural gas has created a large natural gas surplus. Normally, imbalances can be managed with storage. But, this year, there is no room at the Inn. Storage levels are far too high. There is nowhere for the natural gas to go.

Below are updates to two graphs presented in a previous blog post (https://avalonenergy.us/2012/02/how-low-can-they-go/).


Natural gas storage levels remain excessively high. And, as noted previously, the gas cannot stay in storage until next winter because the reservoirs need to be cycled down. As we predicted, this “overhang” continues to keep downward pressure on natural gas prices. On Friday, the April 2012 natural gas futures contract closed at $2.33 per dekatherm (Dth) and the twelve month strip at $2.92/Dth.

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484- 8096, or email us at jmcdonnell@avalonenergy.us.

Copyright 2012 by Avalon Energy® Services LLC

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How Low Can They Go?

How low can natural gas prices go? We may find out soon. First some background.

US natural gas demand varies considerably over the course of a year, driven primarily by natural gas usage related to heating. During peak winter months, natural gas demand exceeds the production capacity of North American natural gas wells. Natural gas can be stored underground in significant quantities in depleted reservoir, salt cavern, and aquifer storage facilities and called upon to meet demand during these peak winter usage periods.

The US underground natural gas storage infrastructure is extensive, as shown on the above map.

Natural gas is injected into underground storage facilities during periods of low demand and then withdrawn during times of peak demand. As natural gas is injected and withdrawn from these storage facilities, some natural gas must remain in the reservoir in order to maintain adequate pressure. This is referred to as “base” or “cushion” gas and is permanent inventory. Additional natural gas in an underground storage facility is “working” gas and is available to be delivered during higher demand periods.

The graph above shows monthly US natural gas base, working, and total storage volumes going back to September 1975. The injection and withdrawal of working gas is highly seasonal (red line) while base gas levels are much more stable (green line).

The above graphs show monthly US natural gas injections and withdrawals (gross and net), over the same 436 month time period. Both graphs are asymmetric along the horizontal zero axis. Over time, injections equal withdrawals. However, working gas is injected more evenly during non-winter time periods while withdraws occur much more quickly during the winter.

As shown on the above graph, natural gas is generally injected during the months of April through October and withdrawn heavily during December, January, and February.

Looking back over the past ten years, as shown in the table above, the US natural gas base gas level has remained fairly steady at about 4,300 billion cubic feet (BCF) while monthly working gas has varied considerably from a low of 730 BCF to a high of 3,851 BCF.

More recently, the US ended the year 2011 with 3,472 BCF of working gas in storage, 12.5% above the 3,087 BCF year-end average of the past five years.

At month end, January 2012, the US natural gas storage level stood at 2,966 BCF, 729 BCF (or more than 30%) higher than the five year January average of 2,237 BCF. This is significant.

Much lower than normal volumes of natural gas have been withdrawn from storage as a result of the mild winter so far, and the large amount of natural gas in storage represents a significant overhang of supply as the winter heating season winds down. What does this mean for natural gas prices in the near term? Unless February and March are exceptionally cold, short term natural gas prices are headed down.

Spot natural gas prices could be headed to sub $2 per million Btu (mmBtu) or even sub $1 per mmBtu levels. Liam Denning, writing in the The Wall Street Journal, recently suggested that spot natural gas prices could turn NEGATIVE. How can this be?

For operational reasons, natural gas storage reservoirs must be cycled. Working gas can be injected under pressure and stored for several months, but the natural gas must be periodically removed in order to reduce reservoir pressure and maintain the integrity of the storage reservoir. Storage operators levy stiff penalties if storage customers do not adhere to withdrawal schedules. Normally, this is not an issue for storage customers as their natural gas is withdrawn during the winter heating season. But at this point, it does not look like there is enough winter left for end users to need the large volume of natural gas in storage. And, the gas cannot stay in storage until next winter because the reservoirs need to be cycled down. So, in order to avoid penalties, storage customers may have to liquidate their positions during the spring when demand for natural gas is generally at its lowest, or during the summer time. This would drive spot market prices down. It is conceivable that prices could get down to zero, at which point storage customers may be motivated to pay someone to take their gas in order to avoid penalties.

The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484-8096, or email us at jmcdonnell@avalonenergy.us.

Copyright 2012 by Avalon Energy® Services LLC