Geographic Information Systems: Some History, Some Thoughts, and What's New

Geographic Information Systems: Some History, Some Thoughts, and What’s New


ESRI, which stands for Environmental Systems Research Institute, is the premier computer mapping and spatial analysis company that provides the industry standard software platform for GIS. Their website has a nice short history of GIS. Below is a quick summary:


They begin in 1960 with the National Center for Geographic Information and Analysis which evolved with early computers. In 1963 Roger Tomlinson set out to develop the Canada Geographic Information System in order to inventory Canada’s natural resources and automate data processing and storage of that information. He also coined the term geographic information system. In 1965 the Harvard Laboratory for Computer Graphics developed software known as SYMAP. Geographers, planners, and computer scientists collaborated there to develop early GIS applications. In 1969, a member of that Harvard Lab, Jack Dangermond, and his wife Laura, founded Esri to help land use planners and resource managers. They developed software tools, formats, and work-flows, many still in use today. Esri went commercial in 1981 with ARC/INFO, making their software available to a wider public. 


It was around the mid-1980’s is when GIS began to be used more extensively in science applications. Geologists and cartographers mapping land surfaces, subsurface features, and mostly human-made above surface features, had long superimposed various “layers’ to see how they matched and how best to design various things. Archaeologists could overlay maps of settlements from different time periods to help discover how things changed spatially. Biologists could map plant and animal populations. Environmental scientists could map point-sites of pollution, how pollution disperses, and contamination plumes in groundwater and surface water. Geologists could compare subsurface features to surface features.


Because digitized layers were not available for all spatial data, some of us sometimes had to use a pre-computer technology: light tables, a surface with a light underneath, so that two paper maps of the same scale could be superimposed. One could also use ‘see-through’ tracing paper. I did this with coal seam structure maps and coal mine maps to predict depth to set gas well casing below the coal seam and to predict whether that seam was mined out and a void, possibly filled with water, would be encountered. Sometimes we had multiple coal seams and multiple mines to set multiple strings of casing through, so we had to be careful. We also had to overlay lease maps and topographic maps for spotting wells in suitable areas. With lease line distancing requirements this could be challenging. Often, I would spot wells for development plays, then the surveyor would go to the location and see if that was feasible. Sometimes he would call and suggest alternate locations based on topography and forest cover. 


With well-defined computer map layers in GIS programs like ESRI’s ArcGIS or ArcView the process is a bit easier nowadays and doesn’t require a big area to spread out maps. Spatial knowledge has come a long way in the past 35 years and helps to streamline many applications. Global positioning satellites set the stage for accurate location in three dimensional xyz space. With free GPS software on our smartphones the process of knowing where you are is simplified. When we are somewhere our coordinates can be read by others who can see where we are on a map just like we can see where we are when we’re driving. GIS has so many practical applications in so many fields and such accuracy that the methods of the pre-GIS past will simply fade away.


GIS is the basic technology for mapping spatial data. It is synonymous with mapping itself, just computerized, digitized into raster and vector data and packaged into map layers. Superimposition and what we can learn from that is often the goal. Interpreting spatial information is part of so many human endeavors. Newer technologies like drones, remote sensing, robotics, automated switching for energy production and manufacturing, and infrastructure monitoring, rely on it. Drones can be used for things like detection of oil and gas pipeline leaks by flying them along the routes with detectors embedded.

The dashboards mapping out the spread of coronavirus are an unfortunate but valuable new application for GIS. ESRI partners with the WHO, the CDC, and other public health bodies to put together geographic depictions of the data. GIS also aids the ‘contact tracing’ necessary to see where a carrier of the virus has been, although this can get into the realm of surveillance, more specifically AI surveillance by tracking our phone GPS history. 


Integrating GPS and GIS helps police and emergency medical personnel, natural disaster response, property assessment, mapping of underground utilities, wires, water pipes, gas pipes, etc. The list is pretty much endless and having accurate spatial data saves lives and makes lives easier. GIS can help farmers water and fertilize crops with great precision and less waste. ‘Call Before You Dig’ services help contractors avoid dangers by consulting detailed maps of underground features, which can be quite extensive in urban environments. GIS is often a primary feature of ‘Big Data’ which can be analyzed to find hidden trends. Political redistricting and the U.S. Census depend on GIS. Federal, state, county, and municipal governments rely on GIS. Knowledge often depends on databases and databases often include necessary spatial data so GIS is a key part of many databases. 


Some of us economic geologists like to stare at maps. It helps to get our exploration mind in perspective. Our own subsurface mapping programs have evolved in tandem with GIS and they work best with surface GIS layers superimposed.   


Esri is always improving their software and making it compatible with other software and formats so that we can zoom in to what we want to see or zoom out for a more global perspective. Although for many businesses, competition is useful, for something like GIS it is rather necessary that a single platform be standard. Esri has provided such a standard. A single platform standard will be desirable for other things too like switching dynamic energy buying and selling based on dynamic pricing. This is related to the Internet of Things and GIS is a key part of that as well. Knowing where things are on a map or within a system is geographic information and that knowledge is essential. Esri calls it the science of where.


References:


History of GIS, Esri website, (esri.com)


Dashboards Give Geographic Perspective to Coronavirus, in ArcNews Esri, Spring 2020, Vol.42 No. 2


ArcNews Esri, Spring 2020, Vol.42 No. 2

The Rise and Fall of "House Gas", Changing Royalties, and Other Well Operator vs. Landowner Issues

The Rise and Fall of “House Gas”, Changing Royalties, and Other Well Operator vs. Landowner Issues


I just read a LinkedIn post where an oilfield fabricator was hooking up wells for landowners in an abandoned Kansas coalbed methane field and it set me off on a quest for statistics and history of well-gas hookups for landowners.


Oil & Gas Royalties


The United States is one of the few countries in the word that allows landowners to collect royalties from the mineral resources extracted from their land by oil & gas companies. Details of the mineral lease are set down in the lease agreement. The ratio is quite generous. Typically, the royalty rate is at 1/8 or 12.5% of gross profit but in more recent prolific and competitive plays such as the shale gas and oil plays, 20% is more common and more than 20% is quite possible. The Canadian royalty rate is typically just a flat 10%. In other countries, the country may own all the minerals. Royalty rates vary in European countries from 0 to 20%. Some of these rates changed as it appeared that fracking could be viable in some European countries. One major reason fracking has been adopted in few other countries than the U.S. and Canada is that there are few well-established landowner royalty provisions and thus, few incentives for landowners to support it. Some states charge much higher royalties for leases on certain lands – the state of Texas charges a 25% royalty on some lands and other states have much higher than the 12.5% royalty. In 2015 the Obama administration upped federal land royalties to 18.75% on some lands. Also upped was the minimum delay rental bonus bid to hold leases for future drilling. This went up from the previous low of $2 per acre. 

It should also be noted that the landowner may not be the lease owner. This is perhaps unfortunate but this situation of a lease "severed" from the landowner became common
in the U.S. in the early-mid 20th century when shrewd politicians collected mineral leases, keeping them separated from landowners. Whether this is the case for a property is revealed when land is bought or sold. My own 35-acre property has the minerals severed which effectively means that the lease-owner could come a drill wells on my property without my permission, although I would have some rights in siting. This situation has served to create much antagonism among landowners.


The idea of landowners being mineral royalty owners in the U.S. began from the founding fathers rejecting the faraway British Crown collecting taxes from the colonists. Under President Warren G. Harding in 1920, the Mineral Leasing Act set landowner royalties at 12.5%.


In the early times of the shale gas and oil plays amidst high gas and oil prices and highest percentage of landowner cuts, landowner royalties were phenomenal, allowing landowners to strike it rich. As production grew and prices subsided those royalties also subsided. In addition, well operators looked for ways to increase their own revenue.


Changing Lease Requirements and Controversial “Post-Production Costs”


Oil and gas leases in the U.S. have tended to vary in requirements. For example, some have provisions for so-called “post-production costs,” while other don’t. Chesapeake Energy spurred the provisions for post-production costs by making leases to deduct them before paying landowner royalties which sparked some fierce debate about the practice. With high natural gas prices nobody saw a need for such provisions but as those prices dropped and profits became more constrained the well owners looked for ways to enhance dwindling profitability. The practice has sparked controversy. That is one reason among several that landowners in high-leasing unconventional gas and oil areas have banded together in landowner groups to more or less standardize their lease requirements. 


With unconventional horizontal wells the well units of a lease or multiple leases are necessarily much larger in areal extent than vertical wells so that more acreage is required for a single well and much more for a group of wells on a single well pad. If the well or pad site is on one’s property, the property owner may also receive a site fee, ranging from $2000 to $15000 per well, according to the Penn State Extension article referenced below.


Landowner Group Leasing


Since it sometimes takes quite a bit of time before a lease becomes available for drilling, the common practice is to pay landowners annual delay rental payments before well(s) are drilled on the lease in order to hold the lease for future drilling. If there is some production on the lease then future drilling is already secured by that production, a situation known as “held by production” so that rental payments are not required. What is payed to landowners for delay rental, also called a bonus, varies according to region, play, and presumed market value of the mineral resource.   


The following quote is from the very informative Penn State Extension article referenced below:


“A word about landowner groups: You might have heard friends or neighbors talk about landowner groups in the context of gas leasing. There are different types of landowner groups. Some exist simply for sharing information about what companies are looking to lease in their particular area, current rates, and any special terms or conditions to the leases. Other groups are involved in marketing their land--they seek out and maximize acres that share a border and make bid proposals to energy companies interested in leasing. Still other landowner groups engage in collective bargaining, in which all landowners sign off on leasing terms accepted by the majority. This saves energy companies many hours of individual negotiations and gives landowners a strong negotiating position with companies looking to lease land.”



Well Hook-Ups for House Gas


The practice of offering well gas hook-ups to landowners had been dropping and was being replaced by offering them a flat fee just before the advent of unconventional shale production. These days it is rarely offered. One reason is simply liabilities and maintenance. Typically, the landowners were required to pay for hook-up to the well, but hook-ups were often done by well tenders. Well tenders that work for the well operators need to plan and do the well hook-ups and maintain any potential problems. I remember working for a company that had variable lease requirements and landowner well hook-up issues. Some had multiple buildings outfitted with gas hook-ups, including multiple commercial greenhouses. Other situations involved people illegally hooking up gas to nearby residences, splitting off from their neighbor’s hook-ups. Leaks had to be fixed and disruptions addressed. Since natural gas is potentially explosive, this could be a safety issue as well. 


Depending on the comparative cost of purchasing natural gas from the local utility, free gas for landowners can be of very significant value that may last in full for decades. People who live in rural areas where utility natural gas hook-ups are not available also benefit much from such free house gas. 


A More Recent Source of “House Gas”


Portable aerobic digesters offer home and business owners another source of house gas, but one that is magnitudes lower in volume unless one is involved in agriculture that involves much agriculture waste, food waste, or collected manure. Inexpensive digesters are common in some places in Asia as a means to get methane for cooking and thus reduce the production of toxic wood and dung smoke from cooking fires. 


References:


Millions Own Gas and Oil Under Their Land. Here’s Why Only Some Strike It Rich – by Marie Cusick and Amy Sisk, in NPR (npr.org), March 15, 2018


Federal Oil and Gas Royalty and Revenue Reform – by Nicole Gentile, in Center for American Progress (americanprogress.org), June 19, 2015


An Overview on Royalties and Similar Taxes: Oil and Gas Upstream Sector Across Europe -by Deloitte, April 2017


Natural Gas Exploration: A Landowner’s Guide to Leasing in Pennsylvania – by Penn State Extension, last updated Sept. 19, 2017

Will the Drop in U.S. Oil Demand Due Mostly to Coronavirus Inadvertently Increase Natural Gas Demand in the Short-to-Mid Term? It Seems Likely (April 23, 2020)

Will the Drop in U.S. Oil Demand Due Mostly to Coronavirus Inadvertently Increase Natural Gas Demand in the Short-to-Mid Term? It Seems Likely (April 23, 2020)


The profound drop in U.S. oil demand due to Coronavirus and to a lesser extent the OPEC-plus, Russia-Saudi oil war, has caused oil prices to crater to below zero (at least on paper). A big emerging issue in the U.S. is simply where to store the unused oil. Storage hubs are filling fast. The Trump administration plan to add 75MM Bbls to the Strategic Petroleum Reserve (SPR) will help a little but as RBN Energy CEO Rusty Braziel points out, that will take time, and storage will remain an issue in the meantime and maybe even after the SPR is filled if demand remains stagnant. Braziel suggests that the problem is 85% Coronavirus and 15% OPEC-plus, but others see OPEC-plus having a bigger influence. 


It seems likely that wells in the Permian Basin will be shut-in and the Texas Railroad Commission is still evaluating whether mandatory curtailments will occur. On average those Permian Basin oil wells make about 10% of the natural gas that wells in Appalachia do, but there are many more of those oil wells than Appalachian shale gas wells. As a result, Permian Basin gas production is over half of overall Appalachian gas production. The Permian produces somewhere around 12% or more of total U.S. gas. If a significant amount of those oil wells is shut-in, the gas they produce will be shut-in as well. How much gas will be shut-in is the question. That also means that when oil demand picks up, the gas will come back online, which could bode for a future drop in natural gas demand. But that could be far off and less impactful. The oil shut-in is likely to be widespread and across several oil basins.


There is little doubt that globally there is way too much oil so demand will be slow in any case to return to normal levels. With the possibility of the coronavirus continuing to wreak havoc for months and perhaps even a year or more, there is little reason to think that oil demand will return any time soon. The Seeking Alpha article referenced below suggests that shut-ins could take 500BCF out of commission between May and November. That equates to an average of about 2.7BCF/day avg. over that time period. They noted that the shut-ins could take up to 14BCF/day off the market in the short-term but with LNG export gas also shut-in the total impact would be about 8BCF/day in a two-month period. That would certainly affect natural gas prices positively going forward. 


LNG export demand is another variable that could influence gas futures. European gas storage, like U.S. gas storage is at high levels, but in recent years more European gas is coming from the U.S. than before. BTU Analytics noted that LNG imports to Europe increased from about 6BCF/day avg in 2017 and 2018 to 13.3 BCF/day in the first quarter of 2020. During the same time period the amount of LNG exported from the U.S. to Europe has increased from 0.3 BCF/day to about 3.7BCF/day. Its attractive price has cut into pipeline imports from Russia. More contracted U.S. LNG export capacity is expected to come online in 2020 and 2021 but it is likely that it will not be utilized at high levels so some drop in overall LNG export demand from the U.S. is expected. Although European gas demand from the U.S. will surely drop in the short-term, its long-term prospects remain good with the so-called Wave 2 of U.S. LNG export expected to increase exports to Europe. WoodMac suggests that with three months of “lockdown” in Europe, 16.9 BCM (~600 BCF) of gas demand is in jeopardy. With more renewables on the European market in 2020, they are pushing fossil fuel demand down and having a bigger influence on power markets in general. Add in coronavirus and a significant drop in European LNG import demand is certain. 


According to the EIA, natural gas demand has not been affected very much by the coronavirus. People still need heat and electricity and shuttered business need some too. March 2020 natural gas consumption was significantly higher than March 2019 consumption. Low natural gas prices make it more competitive against coal, so more gas gets burned. More coal plants being shuttered and more gas plants being built and set to come online will also positively affect demand.
  

EIA (Henry Hub) predictions for Jan 2021 range from $2.70 to more than as $4.00 per mcf and a $3.00 or more avg. for 2021 bodes well for gas drillers, at least for 2021. But in the near-term getting back to $2.00 per mcf is the hope. Yesterday’s Henry Hub index was at $1.87 per MMBtu. Futures for NYMEX 12-month strip avg. from May 2020 to April 2021 was at $2.55 per MMBtu. By summer as virus-related travel limitations perhaps become clearer and perhaps a better picture of natural gas supply and demand emerges, the predictions for 2021 should be narrowed a bit, perhaps. There is still some wildcard-ness but it should be in the general range.  

Ga drillers had already tapped the brakes on growing production as prices declined in mid-2019 and production peaked in late Dec. 2019 and DUCs are quite low in the major shale gas basins but quite high in the Permian. Thus, gas drillers were pre-poised for a recovery some time in 2021. With the potential loss of significant gas production that rebound should perhaps begin sooner.


References:


Natural Gas is the Clear Winner from the Oil Blow-Up – by HFIR Energy, in Seeking Alpha, April 20, 2020


Energy Information Administration (EIA) – Short-Term Energy Outlook: Natura Gas, April 7, 2020


RBN Energy CEO Breaks Down the Meltdown in the Oil Market – interview with Rusty Braziel, in Cramer’s Mad Money, CNBC, April 20, 2020


Coronavirus: Tracking the Impact on European Gas, Power, and Chemicals – by Hadrien Collineau, in WoodMackenzie, April 22, 2020


European LNG Imports Holding Strong – by Connor McLean, in BTU Analytics, April 7, 2020


Take Me to the Other Side – Oil, Natural Gas, and NGLs in Post-COVID 2021-25 Markets – by Rusty Braziel, in RBN Energy, April 2020

U.S Home Solar Cost Comparisons, 2014 vs. 2020

U. S. Home Solar Cost Comparisons, 2014 vs. 2020

PV solar panel systems are typically valued at price per watt installed. As of January 2020, the average installed price was $2.96/watt. The true value of the energy produced is also affected by efficiency, which varies from about 15% to about 23%. Solar panels only can be found online for about $1.20/watt or lower but can vary quite a bit in quality.

I chose 2014 since I had a grid-tied system installed on my roof in Ohio that year. For comparison my own 4.3Kw system cost about $3.49/watt with polycrystalline Chinese-made Trina panels that were around 16% efficient. However, I was able to get the 30% federal tax credit which is at 26% for 2020. Another factor that has changed since then is the 30% tarrif on Chinese-made solar panels imposed by the Trump administration in 2018. In terms of overall system cost before tax credits or efficiency gains, a system is about 15% less in 2020 compared to 2014. Add in the tax credit change and the improvement drops to about 10.3%.

My Trina panels are only at about 15.9% efficiency so there is much improvement in some of the newer more efficient panels. Some of the better panels now are at over 20% efficiency. I am going to assume here an average of 20.5% efficiency for comparison. That is a 4.6% improvement. Original economics for my system started out at about 12.5 years for payout but due to changes in state renewable energy credits just after installation dropped to about 13.5 years for breakeven. Improvements in efficiency combined with lower overall system costs mean that for a system installed today my breakeven might be 11.55 years, an improvement of just about 2 years, which is pretty significant. The bottom line here is that even with some fade-out of the federal tax credit and tariffs on Chinese panels, which are cheapest, the incremental improvements made between 2014 and 2020 are significant, making an installed 2020 PV solar system up to 15.5% cheaper than one installed in 2014.

The changes in state renewable energy credits (SRECs) indicate that the economics of home solar vary by state. State renewable energy portfolios that require a certain amount of energy to be renewable are one reason for the variation. Another way that states vary is by net metering rules, meaning how the power company pays the home energy producer for their excess generation. There are also varying fees for purchasing reversible meters and for power purchase agreements. Some states have more incentives than others.

One can also save money by buying one’s own panels and self-installing rather than purchasing from an installer. One needs to get a licensed electrician to hook the panels to the inverter. In most states grid-tied systems require that professional solar panel installers do the work so self-installing is only really an option for off-grid systems. While complete systems can be found online for about $1.50/watt, racking systems, and installation including acquiring required permits in many areas adds much more to cost.

Best Values in Solar Panels for 2020

Best value in solar panels depends on the particular attributes of a site such as roof space, roof orientation, roof pitch, region, and shading. With abundant space and ideal orientation, one might get a better value for less efficient solar panels. But for someone with limited roof space, shading, and less than ideal orientation, which is more common, the best value will be the highest rated panels.

According to Energy Sage, a reputable solar evaluation site, the best panels for 2020 are made by, LG, SunPower, and Panasonic. The main reasons given are competitive pricing, high efficiency, and the 25-year warranties. These are panels made with monocrystalline cells, more efficient in sunlight to power conversion than those made with polycrystalline cells. However, they do cost more. I am not sure that utilizing them particularly in this comparison is at average 2020 cost, but it should be reasonably close.



Energy Sage ranks solar panel value by four criteria: cost, efficiency, heat coefficient, which measures how much efficiency is lowered by high temperatures, and warranty. The 25-year materials warranty is very significant since many only offer 10-12-year warranties.

LG pitches efficiency (21.7%), a very good heat coefficient, and a 25-year warranty. They note that a superior heat coefficient is especially important for warmer areas of the country where more efficiency could be lost for longer time periods.

SunPower has the best efficiency in the business at 22.8%. Durability is built into their manufacturing process, they say. They also note that their efficiency decline rate over the years is considerably less than that of other panels, 8% over 25 years vs. 19% for competitors. That could be a significant cost advantage over time. They also have the 25-year warranty.

Panasonic emphasizes a good water drainage system, a 25-year warranty, and performance/durability testing.

References:

What are the best solar panels on the market? complete ranking table
https://news.energysage.com/best-solar-panels-complete-ranking/

https://na.panasonic.com/us/energy-

https://www.lg.com/us/solar

https://us.sunpower.com/

How Does Heat Affect Solar Panel Efficiencies? – by Stuart Fox. In Civic Solar/CED GreenTech
https://www.civicsolar.com/article/how-does-heat-affect-solar-panel-efficiencies

How Much Does a 4000 Watt (4Kw) Solar System Cost in 2020? - by Energy Sage
https://news.energysage.com/much-4000-watt-4-kw-solar-system-cost/

Grid Edge, Smart Grids, Flexible Grids: Projected Growth of U.S. Distributed Energy Resources

Grid Edge, Smart Grids, Flexible Grids: Projected Growth of U.S. Distributed Energy Resources


Wood Mackenzie just came out with a new forecast for grid edge technologies for the 2020’s. This post is basically a review of that report.


First looking back to the 2010’s they note that low-cost fuels and stagnant electric load growth defined the decade. This set the stage for some distributed energy technologies to be poised for growth in the current decade. Although distributed energy resources (DERs) and technologies like electric vehicles have only just begun in the last couple years to appear, both combined at about 0.2% of projected load growth in 2020, it is clear that both are growing. With the rollout of 5G there will be a rollout of self-driving vehicles, electric vehicles, that are expected to reduce traffic accidents to the eventual point of lowering auto insurance rates. EV fleets and distributed resources like grid-tied rooftop solar and storage beyond the distribution substation, at the grid edge, will become more dispatchable, says the report. In order for this to happen at a large scale, continued grid modernization and regulatory support are necessary. Commercial and industrial customers who want green energy will be able to buy it easier or build their own like many of the tech companies have.  


DERs are a double-edged sword for utilities. They can help prevent some expensive upgrades by helping with local demand response issues, but they can also potentially destabilize the grid and utilities need to make some investments to prevent that from happening. They also require a smarter grid so those investments are a prerequisite, but one that has had significant success so far. With DERs some consumers of energy also produce energy. These are called prosumers. Grid flow becomes bidirectional with DERs sometimes feeding the grid. Wood Mac says there will be a shift this decade from mitigating DERs to monetizing them. Right now, many market-design demonstration projects are ongoing. 


They say the grid is evolving in three stages: 1) the utility-centric phase of build-out of smart grid technologies including smart meters and bidirectional metering and communications. 2) the ecosystem-centric phase of DER integration including customer access to wholesale markets (currently a debate among system operators, DER providers, and the FERC), improving sensors and switching on the networks, changing regulatory models, and offering some infrastructure deferments. In this phase the utilities are still responsible for grid balancing 3) the market-centric phase which offers more systemwide benefits and decentralized grid balancing responsibilities. 


Intermittent renewable energy sources like wind and solar, which continue to increase on the grid, create grid balancing challenges for utilities and power markets. Currently in the U.S., there are 50 gigawatts of behind-the-meter flexible DERs enrolled in demand response programs. A large rollout of EVs would increase this quite a bit. Those sources already enrolled in demand response are considered the easiest to integrate and monetize. Regulatory reform in terms of improved market access will help DERs integrate and monetize. From the report:


“In the U.S., the Energy Regulatory Commission is pushing regional market operators to formalize market designs that are inclusive of DERs. FERC has mandated operators under its jurisdiction to survey interconnection practices within their footprints and assess the economic benefits of incorporating individual resources and aggregations onto an equal footing with traditional system-balancing resources. The FERC order will shape DER participation in markets in the 2020s and will join Orders 745 and 841 as the most significant DER regulations of the last decade.”


The use of DERs for demand response is really about optimizing grid flexibility in a grid with inevitable growth of intermittent resources. This will require new or altered business models. Demand response providers are increasingly being incorporated into larger utilities and service providers trying to enhance their energy management capabilities. The need is to integrate DERs into participating in power markets and to assess the value of that participation. Increased electrification, particularly of heating and transport, are expected to grow quite a bit in the 2020’s. Decarbonization is one of the main reasons this is happening. That will increase electricity demand and make utilities consider the costs of new infrastructure upgrades. Dispatchable DERs and microgrids will help to provide grid resiliency. If DER pricing becomes well-defined in power markets and the IOT abilities of appliances and thermostats are incorporated, then these can also help to stabilize grids. Orchestrating these changes will be a juggling act and will not be cheap to implement but optimization will help stabilize the grid and eventually help profitability. They note that North American available EV storage capacity will be at 97.5 gigawatt-hours in 2020 and possibly to 647.3 gigawatt-hours by 2030. This storage capacity can and likely will be incorporated into wholesale and local power markets in the so-called EV2G revolution predicted long ago.


One problem noted in the report is the lack of standardization and alignment of policies and requirements among utilities, commissions, and government. Such standardization will help the scaling of optimal DERs. The currently fragmented system is not optimal and better alignment will help de-risk grid edge investment. 


One of the authors of the report, Elta Kolo, summarizes in the GreenTech Media article that in order for DERs to be optimized for grid balancing four key areas need to be addressed: regulatory reform, the evolution of market models, the scale of grid edge investment around electrification, and de-risking grid edge investment. Along with electrification of heat and transport there will be residential solar-plus-storage. Another requirement will be the ability to dynamically determine the value at any given time of energy, capacity, and ancillary services. 


References:


Foresight 20/20: The Making of a Flexible Grid – by Elta Kolo and Ben Kellison, in Wood Mackenzie – Power and Renewables, March 2020


A New Era is Beginning For the Grid Edge. Is the Utility Industry Ready? – by Elta Kolo, in GreenTech Media, March 19, 2020

Appalachian Natural Gas Power Plant Build-Out Update (April 2020)

Appalachian Natural Gas Power Plant Build-Out Update (April 2020)


As coal plants continue to close due to unprofitability, pollution and carbon emissions, and due to age, more gas plants are under construction and in planning in the Appalachian region. This region is the most profitable for gas plants due to proximity of the gas resource and the need for power due to high population. Nuclear plants are also closing due to unprofitability and age. Even with some state government bailouts the trend is likely to continue. Clean energy advocates might agree with bailouts for nuclear plants but not for coal plants.


The switch from coal to gas in power production is the main reason the U.S. is leading the world in greenhouse gas emissions reduction and another more local benefit is the continuous decline in all major air pollution emissions since the advent of high-volume hydraulic fracturing of horizontal shale gas wells in the region. (see graph for pollutant emissions in Ohio below). Sometimes newer and more efficient combined cycle gas plants replace older less efficient gas plants too. Natural gas in the region is plentiful and cheap. 


Detractors say that building gas plants now in the “energy transition” to lower carbon sources is a bad idea as they can become stranded assets if and when decarbonization is accelerated. However, newer combined cycle gas plants continue to get more efficient and emit less. In the future if carbon capture, utilization, and sequestration become more viable, then these newer built gas plants could perhaps be adapted for that. 


In this post I am focusing on four states: Ohio, Pennsylvania, West Virginia, and Kentucky. All four of these states are strong coal-producing states where coal-fired plants remain dominant in West Virginia and Kentucky but have been overtaken by gas plants in Ohio and Pennsylvania. West Virginia and Kentucky have been slower to switch from coal to gas.


Ohio


Ohio has gas five gas plants slated to come online in the next few years with a combined capacity of 6.135 gigawatts. Previous to that, since 2017, 4.02 gigawatts of gas power capacity have come online. Ohio went from 94% coal generation in 2007 to 58% coal generation in 2017. Below is a graph from the Energy In Depth article referenced below that shows how nearly all significant pollutants have dropped consistently as gas replaced coal on the grid.

Pennsylvania


In Pennsylvania the last unit at Three-Mile Island nuclear plant closed recently. Pennsylvania has 21 gas plants under construction with a generation capacity of about 6.4 gigiwatts. Planned retirements of 15 nuclear, coal, diesel, and landfill gas plants since 2018 total 4.391 gigawatts. Pennsylvania in late 2019 was 34% natural gas but by year-end 2022 is expected to be at nearly 45% gas, 24% coal, and 17% nuclear. Gas was at just 23% in 2009. Gas production in Pennsylvania increased nearly 30-fold since 2007 while U.S. gas production has nearly doubled since then.


West Virginia


In West Virginia there are just two gas-fired plants in the works, one in Harrison County and one in Monongalia County. Between 2007 and 2017 coal generation in WV dropped from 97% to 94% and gas went from less than 1% to about 2% in 2017. Apparently, several planned gas-fired projects in West Virginia have faced legal challenges funded by the coal industry, said Anne Blankenship, director of the West Virginia Oil and Natural Gas Association. Natural gas is cheap and available in much of Northern and Western West Virginia and offers cleaner air, less carbon emissions, and much greater efficiency. The state produces nearly 2TCF of natural gas annually. The Longview Power project in Monongalia County is also set to include the largest solar farm in West Virginia. There is currently a unit there burning coal. Its total capacity is set to be 2 gigawatts but the planned natural gas portion is at 1.2 gigawatts. The huge solar field has a generating capacity of just 50-70 megawatts (0.05-0.07 gigawatts). With the considerable natural gas resources in West Virginia it is quite odd and simply unacceptable that gas currently makes less electricity in the state than hydro and also less than wind! The Harrison County project is at 625 gigawatts. The Brooke County plant that may be starting construction soon adds 830 megawatts for a total of 2.625 gigawatts of gas capacity ahead for the state. Even with these additions, gas power will be far lower than it should be in the state. Clearly, West Virginia has more potential for natural gas plant buildout and due to the momentum of decarbonization and the life of gas plants it would be better to build them sooner rather than later. The monopolic power of coal and the coal lobby in the state is unfair to competition and should be challenged. Energy Solutions Consortium LLC has been trying without luck to push plans for building three gas-fired plants in the state. According to Jamison Conklin in article referenced below: “… the company cleared a major hurdle when the West Virginia Supreme Court upheld its siting permit for an 830 megawatt {0.830 gigawatt} facility in Brooke County, allowing construction to start this year. The coal-backed Ohio Valley Jobs Alliance had challenged it in court.” Below is the astounding grid energy mix in West Virginia that favors coal and disfavors gas.

Kentucky


While Kentucky has been slow to move away from coal, it is now accelerating that move a bit. Two of the largest coal-fired plants in the state are scheduled to shutter in 2020. Both are older inefficient plants. From 2008 to 2018, Kentucky coal went from 94% to 75% generation while natural gas went from just 1% to 18% generation. However, the existing 12 coal plants in Kentucky are fairly modern and some could be running for up to 30 years from now. As of a couple years ago there were only 4 power plants in Kentucky burning natural gas with a capacity of just less than 3 gigawatts. Clearly, there is much more potential to switch from coal to gas in the state. Sierra Club and Michael Bloomberg have targeted the state to retire coal plants but also to replace them with renewables rather than gas plants, which would require a truly massive amount of land under solar panels. Wind is not a great resource in the state. While there is some hydro potential of the “run-of-the-river” type, mainly on the Ohio River, due to long permitting times and low capacity factors it is mostly not viable as a replacement for coal power. 


Environmentalist Arguments Against Coal to Gas Switching


There has been some push back among environmentalists of the switching from coal to natural gas. This is unfortunate and perhaps has some to do with the wrongly perceived threats to groundwater and surface water via fracking and the over-predicted magnitudes of methane leakage, much of which is mitigatable even if true. As mentioned above the Sierra Club and Michael Bloomberg have been pushing their Beyond Coal campaign in such a way as to also push for no new gas plants. Quite obviously, switching from coal to gas in power generation is the quickest and cheapest means we currently have of making meaningful reductions of carbon emissions and pollution. Mark Szybist of the Natural Resources Defense Council has argued that the PJM Interconnection that runs power capacity markets in the region has unfairly advantaged natural gas over renewables. One reason is due to no carbon pricing. Another is that the capacity market is designed in such a way that allows gas to seasonally outbid renewables such as wind and solar. He also argues that it prices out some nuclear. He does not advocate subsidizing nuclear but acknowledges and shrugs at the already significant subsidization of wind and solar. He also acknowledges that due to fracking Pennsylvania’s carbon emissions have dropped by a whopping 30% in the past decade. Then he goes on to bash any nuclear subsidy plans as flawed (I think there is a plausible case for some nuclear subsidies). While it may be argued that the PJM capacity market should be more favorable to renewables (essentially subsidizing them twice) the clear economic situation in Pennsylvania is the continued potential of plentiful cheap local gas to replace coal generation, clean the air, reduce carbon, and keep electricity affordable. It would take years of renewables development to replace one mid-sized gas plant as current rates of deployment. He then goes on to state the debatable methane emissions arguments. It should also be noted that methane emission rates among the recent shale gas wells in Appalachia are among the lowest in the nation.


Conclusions


Ohio and Pennsylvania have taken the lead among the four Appalachian states covered here in switching from coal to gas in power generation. Kentucky is also coming around a little even though they have considerably less gas resources than the other 3 states. West Virginia has been the slowest state to make the switch and is the biggest tragedy here but also the biggest potential. Coal to gas switching means cheaper, more efficient, much cleaner, and less climate impacting energy. Projects in these 4 states will likely lead to 15 gigawatts of new natural gas capacity in the next few years but quite a bit more is possible and should be implemented sooner rather than later.


References:


More Than $15 Billion Being Invested on Natural Gas Power Plants in Ohio – by Nicole Jacobs, in Energy in Depth, March 12. 2020


Report: Gas-Fired Generation Will Rise in Pennsylvania as Coal, Nuclear Decline – by Darrell Proctor, in Power (powermag.com), Sept. 4, 2019


Electric Power Outlook for Pennsylvania 2018-2023 – by Pennsylvania Public Utility Commission, August 2019


Pennsylvania’s Gas Power Problem, Part I: The Build-Out – by Mark Szybist, in Natural Resources Defense Council, May 10, 2019


Pennsylvania’s Gas Power Problem Part II: Cost and Risk – by Mark Szybist, in Natural Resources Defense Council, May 10, 2019


Gas-Fired Power Projects on the Rise in West Virginia – by Charles Young, in WV News, Oct. 7. 2019


Another Gas-Fired Power Plant Moving Ahead in West Virginia – by Jamison Conklin, in Natural Gas Intelligence (NGI), Sept. 13, 2019


Kentucky Leads the Country in 2020 Coal Retirements, in wfpl.org


New Electric Generating Capacity in 2020 Will Come Primarily from Wind and Solar – by Energy Information Administration, Jan. 14, 2020


Kentucky – State Energy Profile Analysis – by Energy Information Administration, May 16, 2019


Longview Power Plant – entry in Wikipedia