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

Why the Marcellus Shale is the Premier Natural Gas Play in the U.S. and Will Likely Remain So

Why the Marcellus Shale is the Premier Natural Gas Play in the U.S. and Will Likely Remain So


The Appalachian region makes just less than a third of total U.S. natural gas production and closer to but still below half of U.S. shale gas production. Of the shale gas plays it is by far the most gas productive per well with the second most productive, the Haynesville Shale of Northwest Louisiana, only about two thirds as productive per well. Total Haynesville production is way less than half, closer to a third of total Appalachian production. See chart below. The Haynesville is closer to export markets in the Gulf and the Henry Hub, which gives it a price advantage over Appalachian gas. However, due to its depth, high reservoir temperature, and high reservoir pressure, it is more expensive to drill a Haynesville well than an Appalachian well. The Appalachian wells involve three distinct shale reservoirs: the Utica Shale, the Marcellus Shale, and the Upper Devonian Burkett Shale. The Marcellus is by far the most drilled, and also the most productive and economic, of the three. It has the biggest fairway, encompassing the most area. The Marcellus wells are just slightly deeper than the Burkett but much shallower than the deep Ordovician age Utica Shale wells. Utica wells may have higher initial production than Marcellus wells, but the Marcellus wells decline slower and are thus more economic. Thus, it is the Marcellus that will continue to be the driver for Appalachian gas production. While the deeper Utica dry gas in Pennsylvania and parts of West Virginia holds massive gas reserves, the cost to extract is much higher so it is really a play that requires much higher gas prices. The Appalachian plays are aided by being closer to populated Midwest and Northeast markets but getting pipelines out of the basin has been slow and is likely to remain in some sort of bottleneck state for a while. The gas-pricing in the region is very susceptible to seasonal supply and demand, and warm winters can glut supply in short order. Aside from pipeline takeaway capacity and seasonal demand there is only proposed and under construction regional natural gas power plants that can help with demand a bit. 


The Permian Effect


Permian Basin shale wells are drilled predominantly for oil. Gas is now considered mostly a by-product of oil production. Quite a bit of it is pipelined to Mexico in mutually beneficial deals. A very significant but falling amount is burned off through flaring. Permian Basin flaring peaked in Dec. 2018 at 900MMCF/day, but now the whole state of Texas is down at 650MMCF/day. That is still a lot of gas and likely coming Texas regs will require high gas-to-oil ratio wells to be shut-in or choked back. Apache recently announced they were divesting the once hyped Alpine High part of the basin due to more gas relative to oil than expected. Gas-to-oil ratios in oil wells tend to increase over time so this may help keep Permian gas coming. From the Gas Production by Region graph below it can be noted that the Permian Basin as a whole makes the second highest amount of gas by formation/region but from the Well Productivity By Region graph below it can be seen that the Permian wells make about 1/10^th the gas productivity of Appalachian wells. There are just so many of them that the gas amounts add up. Someone working in the Marcellus might say “hey, you guys are drilling too much!” But as long as the Permian economics continue to work, they might just shrug. However, the recent OPEC- plus situation means that the Permian is headed for a major slow-down and depending on what prices do there might be quite a few companies that can’t remain in business. Although Trump has proposed a bailout of sorts some think that they should be allowed to fail rather than be propped up in what looks like it could be a longer-term surplus. The Permian Basin also has by far the most drilled but uncompleted wells (DUCs) – see graph below. The Appalachian and Haynesville regions, the ones that make the most productive gas wells, have less than 1/6^th of DUCs as the Permian and Eagle Ford combined, the two regions with the most DUCs. This bodes pretty good for a natural gas price recovery at some point in the future. However, with the economic slowdown due to the coronavirus, it is likely that demand for oil and gas will be suppressed for the time being. If the economic outlook improves by early summer then summer demand may ease back to normal but there is much uncertainty. BTU Analytics suggests that the recession impact to U.S natural gas demand could exceed 4.2BCF/day, enough to delay price recovery and stress some gas-heavy E & Ps.


To summarize, the Permian Basin is the main driver for U.S. oil production but is subject to OPEC-plus price wars that can render it uneconomic. The Appalachian region, particularly the Marcellus Shale, is the main driver for U.S. natural gas production but is subject to regional and sometimes seasonal supply and demand volatility, and to a lesser extent on global LNG demand. 

References: 


Drilling Productivity Report – by US Energy Information Agency, March 16, 2020

Recession Impact to Natural Gas Demand - by Andrew Bradford, BTU Analytics, March 10, 2020

Environmental, Social, and Governance (ESG) Issues in OIl & Gas: Public Relations and Investor Relations

Environmental, Social, and Governance (ESG) Issues in Oil & Gas: Public Relations and Investor Relations


It seems ESG is the new buzzword, especially in investing. With Black Rock’s Larry Fink and others committing to investments that more clearly help the public good and that promote sustainability and decarbonization there is more intense focus on weeding out the ones that are less clearly beneficial. That includes some fossil fuel investments. Black Rock recently decided to divest from coal especially.


Compared to other industries the two with the most environmental and social risk are metals & mining and oil & gas. Upstream, midstream, and downstream oil & gas sectors as well as the oilfield service sector is exposed to ESG risks. Most oil and gas companies have environmental, health, and safety (EHS) staff involved in ESG issues. CEOs and executives should also be finely attuned to these issues. In the past decade or two it has been CSR (corporate social responsibility) and statements of environmental stewardship that have graced company websites. Some have dissed such statements as mere rhetoric. These days banks, investors, shareholders, and the public want some kind of demonstrable proof of commitment to ESG risks and developing a corporate culture of compliance. ESG risks need to be adequately evaluated and communicated throughout the company. 


Some socially responsible investors (SRIs) are even condemning some of their funds for allowing companies with ESG risks into their portfolios. Black Rock still invests in oil & gas companies like Exxon and many others, even though they have stated that ESG is now a major factor in what they will consider for investment. Some SRIs that emphasize fossil-free funds call that hypocritical. According to the WSJ article referenced below, 8 in 10 sustainable investing funds include oil and gas companies. Others would argue that they should be included, especially if they can demonstrate that the risks are being mitigated.


Among the environmental issues in oil & gas are flaring which contributes to CO2 emissions, permitting requirements, methane and VOC leak detection and repair, wastewater management, operations pollution and emissions, land disturbance, solid waste management, habitat disturbance, and local disruptions like truck traffic, light, and noise. ESH staff for oil and gas companies as well as field staff need to know the various requirements of federal regs like the Clean Water Act and the Resource Conservation and Recovery Act (RCRA) as well as state and local requirements.


The social issues involve public relations and addressing the concerns of those who are strongly against oil & gas production, even though they utilize it and benefit from it and may not understand the implications of their policy positions. Effective safety management is one key to reducing social risks. Market access via pipelines, both proposed and under construction is a major social risk as pipeline opponents work hard to deflect and slow down progress on pipelines.


Governance issues are the federal, state, and local regulations and ordinances that must be followed and things like spill and emergency response plans and interactions with regulators. The S&P paper referenced below suggests that government-owned oil & gas companies can exacerbate governance risk by the inherent lack of transparency in those state-owned companies. 


While much recent ESG focus on the industry has been on Repsol and BP’s pledges to decarbonize to some future net-zero energy state that includes investing in renewable energy technologies, that is something so far strictly confined to majors. Smaller independent companies can ill afford to invest in other industries that are marginally profitable at best and dependent on government incentives. They are better off focusing on reducing violations, developing compliance culture in the field, addressing methane and VOC emissions, addressing flaring if applicable, doing carbon accounting across operations and supply chains, and addressing ESG requirements of investors. 


Flaring


Flaring is an issue in oil fields where there is associated natural gas with oil production and a lack of natural gas pipelines so that gas ends up getting burned off. In the Permian Basin alone the flaring of gas peaked in late 2018 at 900MMCF/day. In terms of CO2 emissions that’s pretty big, over 1% of all natural gas produced in the U.S. Add in some other U.S. petroleum basins such as the Bakken and the total at that peak was about 1.3 BCF/day, over 1.5% of total U.S. natural gas production burned away. However, the current volume of flared gas in Texas is down at 650MMCF/day. The lack of pipelines to store and transport the gas is the major issue but cost of putting in pipelines often exceeds any profit for operators and it also takes time to build those pipelines. Direct pipelines from the Permian basin into Mexico have helped both the operators and the Mexican buyers who get it at a good price which helps the economics for Mexican manufacturing and gas power plants. Texas and North Dakota are the two states that account for most gas flaring and venting. Different states have different rules about flaring. The DOE and private industry are working on several ways to reduce flaring by utilizing the gas by putting it to work in power or conversion plants, but such ventures are also costly compared to just burning it off. Texas and North Dakota may come to require more reductions of flared gas which will result in some wells with high gas-to-oil ratios to be shut-in or choked back. If such regulations do occur, they could potentially affect up to 1.2 MMbbl/day of Permian oil production and smaller amounts of Bakken and Eagleford (TX) oil production. The associated gas also helps to keep natural gas prices low. If the gas could be recovered without shutting in and choking back wells it could be put downward price pressure on gas. Flaring in its current condition also presents a hidden climate cost of US oil production. 


In the Permian flaring by company is scored by “flaring intensity” which is simply gas flared per barrels of oil produced. Regulation by flaring intensity is a better and more fair approach than by flaring volumes alone argues Texas Railroad Commission’s Ryan Sitton. He notes that the world flaring intensity is at 0.14Mcf/barrel. The highest flaring intensities are in Iran and Iraq at 0.37Mcf/barrel. Flaring intensity in Texas is at 0.09 Mcf/barrel which is actually slightly lower than the US avg. of 0.11 Mcf/barrel. He argues that cutting flaring in Texas would increase it in other places resulting in net higher carbon emissions. So, oddly enough, requiring less flaring by volume in Texas could result in more imported oil and oil from other basins which have higher flaring intensities. Thus, any reductions via shut-in or choke-back should be targeted to high gas-to-oil ratio wells only. 


Pioneer CEO Scott Sheffield recently suggested that investors should divest from the top flarers in the Permian. He suggests that if Permian producers cannot drop their flaring rates to below 2% of gas produced by the first half of next year when new pipelines are slated to come online then they should be divested. The CEO of Parsley Energy and the leader of Shell’s Permian operations generally echoed the sentiment. Concho Resources announced recently that they have dropped their flaring rate to 1.6% compared to 3.6% in 2017. Currently the avg. flaring rate in the Permian Basin is about 5% of gas produced. 


Methane and VOC Leak Detection and Repair


Despite the Trump administration rolling back Obama’s federal methane leakage rule the industry is still committed to leak reduction and investors want to know the details. The International Energy Agency and environmental and industry groups are studying global methane leakage with new infrared satellite detectors and various projects are detailing emissions better. One is IAE’s Methane Tracker project. The new data should pinpoint where the most leakage is, so that leak repairs can be cost-estimated and fixed. The EPA was set to require accounting and reporting of company methane leakage before Trump pulled the rule. Many companies are continuing anyway to address leakage since it is kind of a low-hanging fruit due to recovering saleable gas, anticipating future requirements, and because it is good public relations and investor relations strategy. Some recent infrared analysis suggests that methane leakage has been underreported by up to 40% but there is debate about those numbers. Methane dissolved in oil and condensate bubbles out after it depressurizes from subsurface to atmospheric pressure. Oil and condensate tanks are major sources of methane and VOC emissions and need to be provided with vapor recovery systems. In prime natural gas producing areas like the Marcellus in the Appalachian Basin, methane leakage is low, similar to, or possibly lower than previous EPA estimates. Where high leakage rates have been identified they can be mitigated with current technologies. Environmental Defense Fund in partnership with academia and industry plans to launch a satellite in early 2022 to better quantify methane emissions through infrared technology around the globe from various sources. Their goal is to cut oil and gas sector methane emissions by 45% by 2025. There is some debate about the quantification of infrared data as opposed to other methods. In fact, quantification of methane emissions can only be an estimated range due to large number of potential sources and variables. How they are measured can change the numbers a bit too. Nevertheless, the range given by the EPA is probably close and remains significantly below any threshold to negate the climate benefits of gas relative to coal. The coal industry itself emits about one third of the methane emitted from oil and gas.


Greenhouse Gas Emissions Accounting and Disclosure


Not only are oil and gas operators calculating their carbon footprint, but the oilfield service sector is as well. Emissions need to be measured and disclosed in today’s regulatory environment and opportunities to reduce emissions across all aspects of operations need to be considered.  In some North Sea oil operations electrical power is being supplied from shore rather than gas turbines which are more carbon intensive than the electric power. They are also reducing the number of people working offshore. Reducing the number of people working onsite in the oil and gas fields is another factor. With effective online data hubs transmitting well data in real time there is opportunity to work very effectively off-site, which eliminates transportation emissions and makes safety easier. Rigs may use friction reducers to cut the power requirements to lift the drill string off bottom. These and other energy conservation measures are likely to be further explored in order to reduce emissions. Other emissions reduction opportunities are explored later in this article.


Permitting


One issue with permitting is requirements for environmental assessments and surveys. This is more likely to be an issue in environmentally sensitive areas or with government-owned lands. Industry and its supporters have argued for streamlining permitting so that projects can be developed in a more timely manner. Eliminating duplicity in biological surveys by doing blanket regional surveys is one way operators have been doing this. Even so, some states like Colorado with stronger regs, will likely continue to see longer permitting times. In Colorado, approved permits have been cut in half due to new environmental regs. There are things there more characteristic of western states like effects on wildlife and local water usage. Colorado oil and gas companies are beginning to realize that slower permitting is the new norm there. It is unclear (and I would say unlikely at this point at least in the near term) that other states will follow. The ability to get permits approved quickly can affect companies’ bottom lines and needs to be considered, especially in the typically volatile price environments associated with oil and gas. The slow-down in permitting is already beginning to affect the industry in Colorado and will likely lead to a slow-down in oil & gas production in the state, despite favorable geology.


Anti-Fossil Fuel Sentiment


In a recent survey (Ernst & Young 2017) of people of different ages about their perceptions of the energy industry the total net positive perceptions were just 21%. Broken down it ranged from 31% net positive among Millennials to a mere 9% net positive among Gen Xers. Generally younger people expressed a more negative perception of the industry. Overall 59% of respondence had a positive view of natural gas but only 35% of respondents had a positive perception of oil. Both the general public and investors are scrutinizing oil & gas companies and making demands that sustainability and emissions issues be addressed. Thus, oil & gas companies are increasingly encouraged to develop “carbon strategies.”  They need to consider the possible impacts of things like carbon pricing, stranded assets (particularly for projects that take a lot of time to develop), operational decarbonization, greenhouse gas reporting, and leak detection and repair. All of the above come with significant new costs to the industry. Some of the majors are beginning to develop plans and timelines for “net zero” carbon emissions. This assumes they will add more renewables to their portfolios as well as reduce operations emissions.


More than one current viable Dem presidential candidate has vowed to target the oil & gas industry. Bernie Sanders is willing to go to extremes to vilify the industry by banning fracking altogether. Although, he would not likely succeed even if elected, it shows there is considerable popularity of curbing fracking, which is how most of the oil & gas is produced. Oil & gas as a whole provides more than 70% of primary power production in the U.S. and nearly 70% of that comes directly from fracking (and that % will continue to grow). Banning fracking is not at all viable. Renewable sources would take years, perhaps decades, and incredible cost just to pick up some of the slack.


Investor Demands for Accountability and Sustainability


Investors in for the long-term are considering things like oversupply keeping profits low and decarbonization pushes lowering future demand. Oil majors like BP and Exxon have long invested in renewable energy projects and R&D. Exxon scientists were pivotal in developing lithium batteries. While the percentage of renewables in their portfolios have varied over the years mostly due to profitability, it is clear they want to leave the door open for transitioning into cleaner energy companies in the future.


Compliance with ESG will become a more routine part of loan agreements, stressed Jim Finley, CEO of Finley Resources, Inc. at the recent NAPE Global Business Conference. He says banking groups will have checklists which companies must address. This suggests that things like carbon accounting, best practices, and best technologies will become requirements rather than choices.


Carbon accounting and disclosure will be a necessary feature going forward. Investors will demand it. Another issue for investors is the possibility of stranded assets where expensive long-term projects will not be able to realize their full returns due to changes in regulatory requirements. Developing strategies for low carbon business models is the wave of the future, like it or not.


ESG Compliance Opportunities for Oil & Gas Companies


There are ways to comply with ESG demands that may help a company’s public image. One is simply making a demonstrable effort to reduce operation emissions of pollutants and CO2. The pumping requirements of the many-staged, high-rate, high-volume frac jobs of today are considerable. Diesel is the most common fuel to run large trucks, frac pumps, and other equipment. Some companies use natural gas from their nearby fields to power these ops. Electrified frac fleets are being piloted as well. Costs are of course an issue here and with oil & gas prices and profits very low at present there is additional challenge. Industry partnerships, consortiums, and DOE projects could be of help. Various projects are trying to better understand methane emissions and regional water management issues. Better water management practices can reduce truck traffic and occurrences of spills. Reusing higher percentages of frac water can preserve regional water resources. Compliance with acknowledged industry best practices and best technologies for reducing emissions is another way to address ESG concerns. Being ahead of possible regulatory changes is also a good strategy so some companies prefer to go beyond mere compliance.


"New Energies" and Some Thoughts on the Details of Decarbonization


As mentioned above some of the majors are devoting more capital towards “New Energies.” These involve renewables like solar and wind but also things like algae-derived biofuels and energy efficiency improvement. A recent forum: Perspectives on the Future of Oil and Gas, at the Payne Institute for Public Policy at the Colorado School of Mines, involved executives from BP, Shell, and Equinor. According to Equinor, things that need to occur to keep reasonably close to Paris Accord scenarios include big changes in carbon pricing and fuel efficiency standards, more than half of vehicles being electric by 2030, an 80% reduction in coal demand, solid growth in biofuels, 80% more nuclear energy by 2050, massive subsidized investments in renewable electricity, and a huge increase in CO2 capture and sequestration. These are tall orders, none of which is of much concern to the current US administration. Even if such changes are made by 2050 the world will still need significant amounts of oil and gas. Shell’s “Sky” scenario from 2018 would halve CO2 emissions by 2050 and reach net zero by 2070. Requirements for that scenario are also challenging: North Americans halving their energy consumption per capita by 2050, accelerated growth in electrical consumption (electrification), replacing natural gas with biofuels, more carbon capture and sequestration, a massive reforestation effort, and a global market of electric cars solely by 2030 (sorry, but this does not even seem possible), 95% of buildings converting to electric power. 40-50% of industry converting to electric power, and 25% of heavy transport converting to electric power. BP stressed the need for more natural gas and continued investment in new oil and gas fields during the transition, which will not happen overnight.


There is some opportunity for the use of renewables in carbon capture and sequestration, particularly with the use of so-called “blue hydrogen” (natural gas or naptha sourced hydrogen) or “green hydrogen” (clean electricity-sourced hydrogen) to help reduce emissions in refining, CCS, and heavy transport. Exxon and Repsol are working to incorporate these cleaner energy changes into their operations. Offshore wind may be helpful in several ways from providing energy to offshore platforms to using decommissioned offshore platforms for offshore wind development. Chevron recently bought Natron Energy to take advantage of their data, battery, and EV-charging capabilities.


Director of the Bureau of Economic Geology at the University of Texas at Austin, Scott Tinker brings some interesting perspectives to the decarbonization debate. He suggests that there is a need to rely on both regulatory policy and technology with compromises being made on both sides of what has become a divisive issue wrought with biases and partisanism. He suggests dropping the narrative of carbon vs. non-carbon sources of energy as it is well known that both will be needed far into the future. 80% of global energy comes from fossil fuels so ramping down is going to take lots of time no matter how one looks at it. He concludes that “Both the economy and the environment must be solved for simultaneously.”


References:


Oil Industry Faces Rising ESG Pressures This Election Year – by Joseph Marman, in Hart Energy, Feb. 10, 2020


Does ESG Present a Risk to 1.2 MMb/d of Permian Production? – by Corey Boettiger, in BTU Analytics, Feb. 4, 2020


ESG for Energy: Three Things Companies Should Be Doing (Part 2) – by Tony Jones, Opportune LLP, in Hart Energy, Feb. 12, 2020


Natural Gas Venting and Flaring Increased in North Dakota and Texas in 2018 – by Energy Information Administration, Dec. 6, 2019


Natural Gas Flaring and Venting: State and Federal Regulatory Overview, Trends, and Impacts – by US Dept. of Energy, June 2019


Owning the Narrative: Managing Public Perceptions of the Oil Industry – by Heather Saucier, in AAPG Explorer, Feb. 2020


Analyst: Uncertainty is the Oil Industry’s Greatest Challenge – by David Brown, in AAPG Explorer, Feb. 2020


Oil Majors Plan for Low-Carbon Future – by Heather Saucier, in AAPG Explorer, Feb. 2020


The Myopia of a Carbon-Only Lens – by Barry Friedman, in AAPG Explorer, Feb. 2020


Defining the Oilfield Service Sector’s Role in Meeting CO2 Goals – by Cameron Wallace, in World Oil, Feb. 3, 2020


BP, Shell, Total Seek Norwegian Green Power for Oil Platforms – by Nerijus Adomaitis, Reuters, in Hart Energy, Feb. 13, 2020


BP’s Net-Zero Goals Sees the Major Dwindle Oil Activity – by Mary Holcomb., in Hart Energy, Feb. 12, 2020


MSCI’s Five ESG Trends to Watch in 2020 – by Linda-Eling Lee, Meggin Thwing, and Ric Marshall, in Green Money (greenmoney.com), Feb. 2020


Oil & Gas Experts on Regs: Resist the Rocky Mountain Sigh – in Hart Energy, Feb. 19, 2020

Texas Names Best and Worst Companies for Gas Flaring – by Carl Surran, in Seeking Alpha, Feb. 19, 2020


Defining the Oilfield Service Sector’s Role in Meeting CO2 Goals – by Cameron Wallace, in World Oil, Feb. 3, 2020


Texas Regulator Says Stricter Flaring Rules Would Increase Global CO2 Levels – by Cameron Wallace, in World Oil, Feb. 19, 2020


ESG for Energy: Three Things Companies Should Be Doing (Part 1)– by Tony Jones, in Hart Energy, Feb. 11, 2020


Partnership Advances Satellite Mission to Cut Oil Industry Emissions – by Velda Addison, in Hart Energy, Jan. 30, 2020


Pioneer CEO Scott Sheffield Urges Investors to Divest in Top Flarers – by Jennifer Hiller, Reuters, in Hart Energy, Feb. 20, 2020


ESG Industry Report Card: Oil & Gas, in S&P Global (spglobal.com), June 3, 2019


The Role of Oil and Gas Companies in the Energy Transition – by Robert (“RJ”) Johnston, Reed Blakemore, and Randolph Bell, in Atlantic Council (atlanticcouncil.org), Jan. 9, 2020


ESG for the Oil and Gas Industry – What You Need to Know for 2020 – by Dan Genovese, in Oil & Gas 360 by Enercom, Jan. 3, 2020


ESG Funds Enjoy Record Inflows, Still Back Big Oil and Gas – by Akane Otani, in Wall Street Journal, Nov. 11. 2019


Colorado Oil and Gas Well Permitting Cut in Half by Drilling Reforms – by Zachary Frazier, RPL, in Oklahoma Mineral (oklahomaminerals.com), Nov. 13, 2019

Value Potential of Recycling, Refurbishing, and Repurposing EV Batteries for Home, Business, and Industrial Storage

Current Issues in Energy Storage: 2) Value Potential of Recycling, Refurbishing, and Repurposing EV Batteries for Home, Business, and Industrial Storage


EV batteries no longer viable for the specific charging requirements of the vehicle can work well for the less specific tasks of feeding the grid as well as for off-grid powering. This has long been known. Thus, spent EV batteries have a high resale value. Most EV batteries are warranted for 8 years and 8-10 years is the usual ballpark figure given for useful battery life. Typically, at appoint somewhere just beyond 8 years the capacity drop accelerates to a point where the batteries are no longer useful. Battery life is dependent on several factors including high temperature exposure, frequency of charging, whether fully charging and discharging or not, type of charging, and how the battery management system (BMS) handles some of those factors. My Toyota Prius hybrid battery lasted just over 11 years and over 350,000 miles before being replaced. The “core charge” on the old battery is significant, about $1300 a few years ago. This is usually incorporated into battery replacement. One can also purchase refurbished batteries although I’m not sure what the quality and life is of those. Automakers and battery manufacturers can repurpose batteries, refurbish them, or recycle them for their valuable parts and materials. 


The battery management system (BMS) is the key to optimizing value of EV “afterlife” batteries along with a way to invert power into AC. One company in Melbourne, Australia: Relectrify, states that their BMSs are superior to conventional battery management systems since they can monitor and control flow to and from each individual cell in the battery pack. Their internal inverter technology allows them to produce grid-compliant AC waveforms making an external inverter unnecessary. Those two factors combine to significantly lower the costs of using post-EV batteries for energy storage.


It is also true that lithium batteries lose capacity after many charges. Typically, the conventional BMS will not drain the battery down too far or charge it fully even though the data for the user will say 0% or 100%. Keeping the reserve in both charge and discharge is necessary to increase the life of the battery. Fast charging can also reduce battery life. Level 2 charging will not significantly affect battery life, but level 3 charging can. I believe the main reason is that level 3 chargers heat up the battery and the heat reduces battery life. Battery life is typically even significantly shorter in bigger vehicles such as buses and vans – a mere 3-4 years according to the Institute for Energy Research. As EVs and PHEVs take more market share there will be a growing abundance of spent EV batteries. Recycling, refurbishing, and repurposing are necessary not just due to their value but also due to the liabilities of toxic materials so that they can be kept from landfills.


Recycling of lithium ion batteries involves sophisticated chemical procedures. One method is smelting to recover minerals like lithium, cobalt, and nickel. However, smelting is generally an uneconomic process. For example, recycling lithium for use is about five times more costly than using mined lithium. For this reason and others repurposing is a more attractive alternative. For EVs, after the batteries are no longer viable for the vehicle, they still typically have about 70% of their capacity remaining. In Japan, Nissan repurposes batteries to run street lights. In France, Renault repurposes batteries to run elevators. In Michigan, GM backs up its data center with repurposed Chevy Volt batteries. Repurposed batteries are also used for home energy storage, electric bikes, and other tools. A few years ago, I read about spent EV batteries being used with solar to power remote state park facilities. In some cases the spent batteries are even being used for EV charging! It is estimated that about ¾ of EV batteries will likely be reused eventually.


Battery disposal became an issue in China, the world’s leader in amount of lithium batteries deployed and in EVs, beginning in 2017. In 2016 China had about 1/3 of all EVs. EVs and accompanying infrastructure such as charging stations really took off in China in 2016 aided by generous government subsidies and incentives. EVs are a smart choice for China due to an urban population that is dense so that short-range vehicles can be optimized. However, China did not have an adequate plan for spent battery disposal. China typically uses lithium phosphate batteries which have a shorter lifespan, about 5 years. I’m referencing an article from Oct. 2017 so perhaps more is being done in China now to address battery disposal, recycling, and repurposing. At that time only about 5% of batteries were being recycled in the EU. The obvious reason is that it is a financial loss. Battery disposal could become a serious environmental issue in China if the problem is not adequately addressed. In fact, one could consider battery disposal costs a hidden cost of all lithium battery power. 


The Forbes author, Bill Roberson, does note that since spent EV batteries do have potentially valuable components, looking for cheaper ways to recycle them might pay out at some point. Some think that an efficient “closed loop” recycling system for them would be most beneficial. Roberson also mentions Tesla’s recent patent announcement of a new lithium-based battery system that they say could get a million miles and possibly a per-charge driving range over 1000 miles. Such a system would revolutionize the industry and make battery disposal less of necessity to be dealt with quickly. Of course, its probably still in the R & D phase and could be years or decades till viability, if at all.


One question I would have for a company like Relectrify is: how long do the repurposed batteries last? Another would be:  how easy would it be to replace them? Presumably each battery cell could be replaced when sufficiently weakened. According to Bloomberg the new method by Relectrify is expected to cut grid storage costs by $150 per KWh. New battery storage cost is about $289 per KWh so, basically using spent EV batteries as a part of Relectrify’s system could halve costs. This would be a boon to some grid and home storage projects. Relecttrify is working with Nissan (Leaf batteries) and American Electric Power AEP) on a pilot grid storage project in Ohio. AEP notes that Relectrify’s internal inverter really makes the economics work as an external inverter is often a major cost component of a storage system. Relectrify’s system/process can also extend the spent battery life due to its better BMS. Relectrify also sees potential for their process improving newer versions of EV batteries. Other companies are also continuing to work with new battery chemistry and models and to develop new BMSs. These include new and more precise ways to estimate battery health and remaining battery potential. Another thing being studied is assymetrical temperature modulation which has the potential to reduce over-heating and subsequent loss of battery life due to super-fast charging. 


References:


Old Electric Car Batteries Are Now Powering the Grid – by Courtney Linder, in Popular Mechanics, Jan. 27, 2020


Better Batteries with Relectrify’s BMS+Inverter – by Michael Bloch- Solar Quotes Blog, Jan. 27, 2020


The Afterlife of Electric Vehicles: Battery Recycling and Repurposing – Institute for Energy Research – April 2019


China’s New Environmental Problem: Battery Disposal – Institute for Energy Research, Oct. 13, 2017


The Clock Is Ticking on Electric Car Batteries – And How Long They Will Last – by Bill Robertson, in Forbes, Sept. 30, 2019


What Can 6000 Electric Vehicles Tell US About Battery Health – by Charlotte Argue, in GeoTab.com, Dec. 13, 2019


The Secret Life of an EV Battery – by Andy Miles, in Google Clean Technica, Aug. 26, 2018


Old Electric Car Batteries May Help Cut Costs of Storing Power – by David Stringer, in Bloomberg Business News, Jan 23, 2020


Future Batteries , Coming Soon: Charge in Seconds, Lat Months, and Power of the Air – by Max Langridge and Luke Edwards, in Google (pocket-lint.com), Jan. 3, 2020