Whether you are a buyer, or seller, of power, an effective hedging program will save you from a ton of headaches, and questions. Power markets are the most volatile commodity given their dependence on various other commodities, the instantaneous nature of power, and the very limited ability for power to be stored in significant volumes. The primary purpose of hedging is to create a more predictable set of cash flow in order to run your business more effectively. An effective hedging program doesn’t leave significant money on the table, nor does it make significant money. If you really think you can make money from hedging, than you are trading, not hedging. Trading can be an effective business proposition, but it requires a lot more than hedging in terms of governance, infrastructure, and analytics.
Hedging can be relatively simple given that the goal is to assure more predictable cash flows, and not to make money. In hedging, the governance requirements are about monitoring and making sure a methodology is employed which has demonstrated the ability to be an accurate predictor in the past. Any significant variations in the past analysis should be flagged and addressed in the analytics. The infrastructure for hedging can be quite simple by employing a product such as Power Market Analysis (PMA) from All Energy Consulting. PMA can be used to create the timing signals and levels at which to purchase, or sell, power.
The analytics piece is the beginning, and the end, of developing an effective hedging program. The purpose of analytics is to develop an effective system to signal purchases, or sales, and execution volumes over time. The system should not try to guess, or time, the optimum purchase time, but scale into the hedge volume based upon signals. Initially it will take several iterations of back casting to the past to produce an effective methodology to achieve intended goals while meeting an organization’s stated requirements (risk tolerance, budget, etc.).
A simple mathematical approach of developing a hedge typically doesn’t take into account weather-based fundamental market movements and the resulting commodity price changes. PMA increases the robustness of any hedge process by producing a unique set of outcomes that show the risk and reward potential of locking in prices ahead of time. A simple concept of integrating PMA is to execute a hedge when the risk and reward profiles are asymmetrical. PMA, in its non-customized form, runs a relatively high power, and a low power price, scenario for all power markets in North America. The PMA model output provides the low, and high, expectations of power prices in the future. The model does not predict commodity prices, but uses forward markets for the implied forecast of the future. Given that you use the forwards markets to execute your hedges, it is only appropriate to use the commodity prices from these same markets.
In the table below, we present actual results published May 8th 2014. The results are due to the gas and coal forwards of May 7th. The table shows that the forward curve on May 7th for NEPOOL On-Peak trading is above $60/MWh for most of the summer months. The PMA model runs indicate a much lower price outlook, with only July and September possibly being higher (in the high power price case) as compared to the forward curve. Even if July were to achieve the high case, an increase of $6.89/MWh is being risked for a potential drop of $13.08/MWh. This is an asymmetrical risk-reward profile which should signal some volume of hedging, if one was a seller of power (owner of a generation asset). If one was a consumer of power, this would indicate to limit the hedge volume. In the end, this summer has been extremely mild. Buyers of the forward curve have had an agonizing summer, losing nearly $20/MWh for the summer. Sellers are somewhat relieved. PMA does not predict weather, but the low and high cases do represent extreme weather events impact on price levels. The model does not predict that it was going to be a mild summer, but it does show the forward curve has a significant premium relative to the potential outcomes. In this simple example, the May 8th report indicated a signal to lock in some of the power for the summer if you were a plant owner. If you were a power consumer, it signals to minimize, or not purchase, summer power as the exposure to higher prices is limited.
The signal is only one part of a complete hedging program. In order to design a comprehensive hedging program, you need to incorporate your specific situation in terms of expected shape of energy requirements, volatility tolerance, and budget. With this knowledge, one can then incorporate a volume of purchase, or sales, with the signal. All Energy Consulting can help you create an effective hedging program that minimizes your earnings volatility and reduces risk by employing an unemotional, analytical rigorous process based upon PMA.
Please do consider All Energy Consulting to help you design a headache free – no regrets hedging program, whether you are a buyer, or seller of power.
Your Energy Consultant,
David K. Bellman (email@example.com) 614-356-0484
If you thought the previous discussions of Clean Power Plan (Paper #1, Paper #2, Paper #3, Paper#4) were complicated, you have seen nothing yet. The benefit discussion of the Clean Power Plan moves into the world of art versus science. This section requires one to delve into philosophy and at the same time, process math. My one semester of philosophy in college perhaps may not cut it, but I will try my best. The most complete discussion of the benefits of the Clean Power Plan is found in the Regulatory Impact Analysis for the Proposed Carbon Pollution Guidelines for Existing Power Plants and Emission Standards for Modified and Reconstructed Power Plants. The title for the report foreshadows the complexity of the subject.
There are two major categories of benefits that are quantified by the EPA – Global Climate Change Benefits and the Air Pollution Health Co-Benefits. For the Global Climate Change calculation, they refer to another long titled report Technical Support Document: – Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis – Under Executive Order 12866. In this report they are running models that have the supposed capability to model carbon dioxide dispersion and global temperature responses which lead to sea elevation changes and agriculture impact. This is certainly a grand model. Once again, the validity of these models are questionable given the lack of documentation of backcasting actual historical years. However, some credit can be given to these models given that they seem well thought out. They even include human adaption profile as climate change occurs. They note adaption is likely, but limited, therefore they mitigate some of the damages being computed due to adaptation. All the calculations were focused on damages and avoided the value of life calculations. The biggest outcome of the report was the following statement: “…climate change presents a problem that the United States alone cannot solve. Even if the United States were to reduce its greenhouse gas emissions to zero, that step would be far from enough to avoid substantial climate change.” Therefore to give a value of benefit of CO2 reduction could be all for nothing unless the world is collaborating. This makes EPA’s claim of the $30 Billion dollars of climate benefit in 2030 very questionable given the lack of global participation to mitigate CO2 emissions in the world.
The Air Pollution Health Co-Benefits, unlike the Global Climate Change, is very dependent on the value of life. As noted in their footnote on many of the benefit tables – “The air pollution health co-benefits reflect reduced exposure to PM2.5 and ozone associated with emission reductions of directly emitted PM2.5, SO2 and NOX. The range reflects the use of concentration-response functions from different epidemiology studies. The reduction in premature fatalities each year accounts for over 90 percent of total monetized co-benefits from PM2.5 and ozone.” This is a very interesting footnote, as this was also noted for the Mercury Air Toxics Standards (MATS). “The reduction in premature fatalities each year accounts for over 90% of total monetized benefits….The great majority of the estimates are attributable to co-benefits from 4,200 to 11,000 fewer PM2.5-related premature mortalities”. Section 4.3.2 in the RIA details the calculation for the Clean Power Plan. EPA notes “Avoided premature deaths account for 98 percent of monetized PM-related co-benefits and over 90 percent of monetized ozone-related co-benefits.” Therefore out of the $25-59 Billion identified in net benefits 90+% comes from premature deaths. EPA noted they used the value of statistical life (VSL) at $10 million in 2030. At $10 Million dollars a life, the reduction of premature mortality amounts to 2,500 to 5,900 less than 0.1% of babies born a year in the US. I have no expertise to argue the merits of this, but I can put this into perspective. Based on the EPA logic, as a society it may be cost effective to require swimming lessons. According to the CDC, 3,533 fatal unintentional drowning occurs per year outside boating related incidents. Using EPA calculation method, this amounts to 35 Billion dollars a year of benefit if drowning could be prevented. If everyone in the US took a group swimming lesson (7 classes) for $66 this could produce a net benefit of 7 Billion assuming ¾ of the deaths could be prevented by attending swimming classes. Consider another perspective. As a society, we should probably invest a lot more in mammograms and screening tools given 10,000 women die a year because of ineffective screening tools. If this could be prevented, a benefit of $100 Billion would occur using EPA calculation. With $100 billion on the benefit side of the equation, many programs and additional screening could be done and still produce a net benefit. Here is one final perspective on the logic employed by EPA for justifying the cost having to do with prohibition. Using this analysis, one could quantify the benefits for banning alcohol based on mitigating alcohol abuse deaths. According to the CDC, 88,000 Americans die each year due to alcohol abuse. Using EPA benefit analysis, almost a trillion dollars would be placed on the benefit side of the equation for prohibition. Does the cost of prohibition add up to a trillion dollars?
If we remove the life portion of benefit, this leaves the Air Pollution Co-benefits of between $2.5 – 5.9 Billion. They did note other benefits they did not quantify, such as health reduction from direct exposure to mercury, SO2, NO2, and CO. In addition, there is value for visibility improvement not added into their benefits. They do not talk about the positive externalities that occur because of low cost power which could be eliminated with this program. This is a point missing in general academia. There are externalities that are also positive as I noted in my previous article.
In conclusion, many of the benefits are questionable, since they depend on global participation, or they are valuing benefits on a value of life calculation which needs to be measured accordingly with other worthwhile life savings initiatives. As noted in my previous article on cost, it would seem the cost is underestimated, and the benefits could be overestimated. The benefits are much more subjective and require a level of knowledge few may have obtained – including myself. Understanding and valuing life plus quantifying a range of externalities certainly require more art than science. Cost, on the other hand, is much more science than art. This subject certainly stretched my comfort zone, but this analysis shows the importance of reviewing the numbers behind the numbers and the value of taking philosophy classes.
Your Ever Willing to Learn More Energy Consultant,
David K. Bellman
Founder & Principal
All Energy Consulting LLC
“Independent analysis and opinions without a bias.”
Power Market Analysis (PMA) is now even more insightful with the addition of two more additional runs to the base case. PMA understands the future holds much uncertainty. The value of PMA is to understand that uncertainty. PMA is a tool to help those in the Gas and Power markets. Already PMA tries to formulate the maximum and minimum power price across the country. The power cases allow for one to compute the risk of a trade decision, plus using these cases can also help identify winning trades as previously discussed. Even if you are not trading, but in a role to make decisions on energy procurement, PMA can help you understand your decisions. Adding our expertise with PMA, we can help end-users develop a comprehensive hedging strategy.
Now PMA is producing a maximum and minimum gas demand case. Using the 10 year weather analysis done previously, a constructed maximum and minimum gas demand was developed. In addition, the forward curve is adjusted downward by 50 cents for the high gas demand case and upward by 50 cents for the low gas demand case. These cases will help those trying to understand the gas markets. They can be used to help give you a good sense of when the market is at the bottom or top in terms of power demand.
In summary, PMA has added two new scenarios within their daily produced runs. All 5 scenarios are now part of the trade screener, thereby giving more certainty for the recommend trades being produced by PMA. Don’t be caught off guard by potential changes in the market, sign up now for PMA.
Please call or email to schedule an online demo of the latest most advance way to analyze the power markets - firstname.lastname@example.org – 614-356-0484.
Your Ever Improving Energy Analyst,
David K. Bellman
Founder & Principal
All Energy Consulting LLC
“Independent analysis and opinions without a bias.”
As discussed in my previous article, the Oil & Gas Industry, producers in particular, are trying to export condensates. The industry has recently gotten some exemptions, and perhaps this may lead to more. As noted in the previous article, this may not be the best policy decision for the US economy. Constraining exports will allow the entrepreneurs and innovators to find ways to use the feedstock more effectively domestically. This will then create better economic multipliers versus shipping out the feedstock. The restrictions do put an additional downward price pressure on the producers, forcing them to sell at more of a discount in order for the US refiners to take the condensate. However, the condensate will be sold at discount regardless of the export rule as explained in more detail below.
The producers believe they can sell the feedstock more effectively in the global market. This is yet to be proven. Overall Condensate is not very valuable in terms of product yield relative to most crude oil. The US has already displaced a significant volume of international condensates which was being imported to the US as seen in the figure below.
A large percentage of imports above 45 API are condensate. The dramatic drop off is due to the explosion of condensate in the US from fracking, thereby displacing the imports that were coming to the US. Wherever condensate goes, it will still have to compete on global basis plus shipping and the poor product yield. In fact, condensates yield a lot more gasoline than diesel and jet when refined. Diesel is the primary product in the rest of the world compared to the US, which is mainly gasoline.
There is lack of economic pricing discussion on condensate, including my previous piece. This time I will present the economics of condensate to prove the points that condensate exports will not likely result in economic gain for the US. The very first thing is to understand basic refining economics. I am working on a new multi-client product – Oil Market Analysis (OMA). The first part of OMA will involve an oil refining index model. This daily product will track and calculate the value of various crude oils through various refining configurations. I am using the initial results from the model for this discussion.
There are three major configurations for refining – hydroskimming, cracking, and coking. Each of them is progressively more advanced and costly. Advancements come in two forms
1. Increasing yield of products vs. residual product
2. Increasing capability to process heavier and more complex crude.
A good presentation on the various configurations can be found from Statoil. From their presentation, they expected increasing complexity requirements from refineries. The US refineries also believed this, and as a result have caused this predicament – too much condensate without an optimal home.
Running OMA refining model for the USGC Light Louisiana Sweet (LLS), Maya (Mexico Heavy Crude Oil), and Eagle Ford Condensate shows the following result in each configuration using the average USGC 2013 prices for Gasoline, iso & normal Butane, Jet, Propane, Diesel, Naphtha, Residual Fuel Oil, and Petroleum Coke. The value is essentially the revenue minus the variable cost obtain per barrel of feedstock. If LLS was processed in a cracking refinery, in the USGC they could expect $115/bbl of revenue per barrel. LLS averaged $106/bbl in 2013 – therefore a USGC refiner running LLS should have produced a margin of $9/bbl. This is not weighted nor optimized. An optimized refiner should have been able to extract more margin through better inventory management, purchasing, and offering a broader product suite.
Increasing complexity increases the variable cost of the facility – largely energy cost. The value of increasing complexity is more apparent when the crude oil is heavier. LLS is 66% lighter than Maya. “Eagle Ford” Condensate is about 277% lighter than Maya. Therefor, light crudes such as condensates cannot benefit from the increase complexity.
Refineries do not get much value from processing condensate as seen in the table above. Refiners are likely asking for significant discounts relative to LLS in order to process the condensate. The marginal refinery in the USGC is the cracking refinery. Given this market dynamic, the market should have priced the condensate around a $9/bbl discount to LLS. IF the export market marginal refinery unit is a hydroskimming, then perhaps a $5/bbl discount is possible. Given the shipping cost, the discount to condensate will still likely be greater than $7/bbl, even if exports were allowed. It is possible to create a mixture of heavy crude oil and condensate, thereby creating an optimal blend for cracking refinery to be cost competitive with a coking refinery. This could reduce some of the discount for the condensate. This would be a more sustainable path for delivering maximum value vs. trying to export the condensate. In addition, market forces would likely create a mechanism to capture the condensate discount. Many have turned to splitter projects. I don’t believe splitters would be a sustainable solution. Splitters will just flood the market with more unfinished product,s e.g. Naphtha. Naphtha prices are already under so much pressure. Naphtha eventually will have to be processed to produce finish product.
In the end, exports may reduce the discount to Condensate by a few dollars. Those dollars will not likely show back up as a significant saving for the US consumer. The producers will benefit the most from the ability to export and find market arbitrages. The many that chose to do splitter projects will likely not fare as well as the feedstock discount may not keep up with unfinished product decline in prices. The condensate discount will likely continue to be greater than $7/bbl relative to LLS. There is still room to formulate a better refinery blend and even expand the US refining capability by adding a condensate refinery. (I do know a 80,000 b/d condensate refinery that can be brought back to life for $800 million in 18 month time projected IRR 30+% – email me if you are interested)
Please do consider All Energy Consulting for your refining market analysis. We have many years of practical experience and now offer a dynamic market refinery model. Please email me if you are interested in hearing more about Oil Market Analysis (OMA) – email@example.com
Your Digging Beyond Skin Deep Energy Analyst,
David K. Bellman
All Energy Consulting LLC- “Independent analysis and opinions without a bias.”
Many have given up on power trading due to various reasons from new banking regulations to limited volatility over the past few years due to gas prices. However as many leave the market, there is much opportunity being created in the market place. The power markets are vast and complex requiring a comprehensive energy background to truly understand the inner workings. With many years and significant market knowledge, Power Market Analysis (PMA) was developed to help unlock the opportunities in the power markets. The following will present post analysis of June trades and an example value of PMA.
One of the latest tools within PMA is the power trade screener. The power trade screener is capable of processing the entire N. American markets and producing a table of trades given a set of criteria on the various dispatch simulations used in the PMA. The basic PMA offering is running three runs focused on power price volatility – Base, High, and Low power price cases. The formulation of these runs are available for subscribers plus can be customized for each client depending on location interest and volatility expectations. The current criteria for the screener is to find trades that in ALL three cases produce a result that lies on one side of the current forward curve. Therefore if all three cases are below the forward curve, it is a sell. And if all three cases are above, it is a buy.
On May 20th 2014, the following represented the power trade screener view examining On-Peak Trades for the month of June. (Click on Image to Zoom)
In addition to the power trade screener, the heat rate screener also shows the same June Sell alerts for those regions. (Heat Rate trade is Power Contract / Gas Contract – if you believe heat rates are going down you sell power and buy gas)
The results of these trade recommendations can be examined now. The below table show the results of those trades. (Click on Image to Zoom)
The power trades identified by the screener produce 1 out of 3 winning trades. However, if each trade was purchased in equal volumes the trades would have netted out $13.8/MWh. The best trade was NEPOOL. This is also supported by the backcasting of NEPOOL in the model being superior relative to other markets. On a heat rates basis, 2 out 3 trades would have been winning trades.
Everyday, this analysis is done. Users can learn the patterns and make the adjustments. There is money to be made with markets that are less liquid for those who have the financial and aptitude capabilities. The screener and the simulated runs can be customized for each client.
Please contact me for a demo – firstname.lastname@example.org – 614-356-0484
Your Ever Improving Energy Analyst,
David K. Bellman
Founder & Principal
All Energy Consulting LLC
“Independent analysis and opinions without a bias.”
Summary of Senate Bill 221 and Senate Bill 310
Let me begin briefly explaining Ohio Bills Senate Bill 221 and Senate Bill 310.
SB 221 is a bill focused on increasing the state diversity of energy to cleaner and potentially game changing technology while focusing the state’s consumers on becoming more energy efficient . The bill mandates that a certain percentage of the generation come from advanced energy resources as defined by the State Commission NOT the utilities. This is important to understand. Examples of these sources can come from carbon neutral technology (e.g. modular nuclear, wind, solar, etc.) or technologies that improve how efficiently energy is consumed (e.g. combined heat and power, distributed technology, etc.). Of the advanced energy resources, the legislation calls for half of the targets to be made using traditional renewable sources (mainly wind and solar). The bill also set efficiency targets for the electric utilities to drive the consumers by implanting programs like CFL light subsidies which can be evaluated, measured, and verified by an approved vendor. The targets contained in SB 221 specific to development of advanced energy resources had price caps to prevent significant price increases for the consumer. The efficiency targets do not contain any price caps.
SB 310 is a bill focused on delaying and cutting back on SB 221 mandates. In other words, SB 310 waters down SB 221. SB 310 is designed for the utilities, because it eliminates the portions of SB 221 that threatens the utility business model (more on this later). Everyone seems to focus on SB 310’s 2 year delay of the targets outlined in SB 221 while further studies of its ramifications are conducted. SB 310 also eliminates the advanced energy resource requirement, except for the traditional renewable targets (solar, wind) which remain the same, but are affected by the two year delay. The other advanced energy portions of the bill could have enabled end-users to identify and pursue energy savings opportunities at their facilities within the state.
History of the Bill
As the dust settles on the controversial Ohio senate bill 310, critics and supporters must reassess the situation. Regardless of your position, the bills bottom line impact needs to be understood in dollars for both actual value and potential value so that informed decisions can be made on the bill and its potential changes. As noted above, the bills intent is for diversity of energy and development of new technology. This comes at additional cost that does not always show value right away.
I had previously spent time reviewing Senate Bill 221 while I was the Managing Director Strategic Planning at American Electric Power. SB 221 was passed in 2008 by a 132-1 margin (Republican-controlled House and Senate, combined) and signed into law by former Democratic Governor Ted Strickland. Senate Bill 221 was initially proposed with the good intentions of increasing the state diversity of energy, moving towards cleaner and potentially game changing technology, and becoming more efficient. It would be hard to vote against, hence the 132-1 margin that passed the bill. Given the current design of the utilities and public utility commission, the bill really did not have a chance to be successful.
Issues with SB 221
SB 221 bill only attempts to change the utility, not the commission. The bill adds more responsibility and oversight to the commission, but does not offer any additional budget or suggestions of any action plans to the commission. The bill offers some rewards, incentives and penalties to motivate the utilities to change . The utility typically are slow to innovate and turn change into opportunities, and therefore largely sees only the penalties. “Where there is change there is opportunity” applies to many, but not those who do not want to see change. Given their history of regulation, the utilities need to be nudged into acting more pro-actively . Therefore, bills such as SB221 were needed. However, the commission responsible for the nudging is ill-equipped.
To understand why the utility culture is not designed to capture opportunities of change, one needs to understand the history of regulation. (For more details read Regulation vs. Deregulation Utilities). The utility and Public Utility Commission capabilities are not designed for the new technological world of competitive advanced energy resources and energy efficiency. The utilities failure to innovate largely stems from their incentive structures and historical legacy. The typical consumer wanted reliable power at a reasonable price and was not really interested in the details beyond that. The end-user just wanted to turn on the switch and when the electric bill arrived, they did not want to be surprised.
Utilities have, therefore, worked hard to maintain strong relationships with the Public Utilities Commission since it regulates and approves all utility rate structures. It is no surprise that utilities remain friends with the commission since this keeps the cash flowing to their bottom line. However, when enough consumers react to poor service, the commission could be forced to insist on changes at the utility. This creates a strong incentive for utilities to maintain the status quo, rather than shake things up. Innovation requires some trial and error, which results in increased cost and potential disruptions. The cost based structure, where the Public Utility Commission approves the utility costs and fixed rate of return, does not provide additional rewards for innovation. Thus utilities have traditionally seen zero return for innovation. This mechanism focuses on reliability and reasonable costs, not innovation. This scenario has played out largely unchallenged for decades, but a shift began to occur as a growing group of society started to become more aware of the environment and vocal about repairing and improving it. That movement caught the utilities and the public utilities commissions somewhat off guard . Policy makers moved ahead of the utilities and the commission by implementing policies including SB 221.
The commission’s existing knowledge base was sufficient to oversee reliability while minimizing cost. However, the commission is ill-equipped to oversee an energy industry with new challenges and new technologies. The mandates ask for advanced energy resources and energy efficiency to be implemented with competition and un-bundling in Ohio’s shopping marketplace. Now, there is a tug-of-war between the consumer, the marketplace, and the commission with the utility stuck in the middle. At odds with the commission skill sets, SB 221 is pushing for change . The commission is now required to manage and think beyond current experience. If the commission is to acquire the needed new knowledge and experience, the budget at the commission will likely require an increase, so that they can recruit and retain the right talent to oversee Ohio’s new energy marketplace. Larger utility management teams are making nearly twice as much as commission senior staff. Yet the commission is expected to comprehend the multiple utilities plans cooked up by well-funded teams of experts whose goal is to limit disruptions of the current utility business model. Thus the commission will likely not succeed in effectively regulating policies requiring utilities to change from their current form. Any legislation is only as good as the regulation and enforcement of the bill.
Changes to SB 221 in SB 310
There are many issues with SB 221. However, these concerns could have been fixed without the drastic change in SB 310. As noted, SB 310 eliminates the advanced energy resources initiative, but leaves the renewable requirements.
The better option would have been to open up all advanced technology and renewable energies under one category. This would have allowed the marketplace to pick the winners of future advanced technology. By eliminating advanced technology, which cover the following: Distributed generation, cogeneration, clean coal technology, fuel cell, solid water conversions, and few others, SB 310 seriously erodes the good intentions of the bill. One of the reasons discussed for eliminating advance energy resource portion of the bill is the lack of progress made by utilities in this effort. However, the lack of progress is largely due to the lack of effort, limited capabilities of the commission, and the desire of the utility to not disrupt the business model.
The utilities only targeted and developed the renewable portion since SB 221 was enacted. The utilities would have you believe there was no advanced technology that was a cost effective option relative to traditional renewable energies. I don’t believe this to be the case. The better reason was because there were no transparent medium to encourage projects that would supply portions of the advanced resource category. Advanced technology is very broad, covering distributed generation to co-generation. The real issue limiting advance technology development was the lack of incentive for utilities to look for these advance technology. They understand the traditional renewable energies and those projects are less likely to hamper some of the utilities current business operation. Distributed generation projects and co-generation options are smaller in scale and directly alter a customer class, potentially causing havoc in tariff structures. The large renewable projects can be uniformly spread across classes. If it was solicited to end-users that the utility would purchase and operate a combine heat and power in their area, thereby lowering their price of power by at least 20% and reducing the environmental foot print by over 20%, I am sure there would be plenty of projects. Advance technology given its very nature will require a change from historic business operations.
Many deals in the power industry are made behind closed doors yet at times they offer competitive advantages. However, given a case where there is a regulated enforcement for certain projects, it would be reasonable to create a transparent pricing platform. The commission could do an initial pre-screen to qualify the projects as advance technology (this still can include traditional renewables) – SB 221 gave them this power. The state would be acting prudently and wisely by allowing commission to approve each new “advance technology” source. Due diligence would still be required from the utility just like every other project. Creating such a platform would prevent the excuse that there are no cost effective advance technology projects available compared to traditional renewable projects. At the same time, it would give commercial and industrial clients, plus developers, an ability to propose innovative projects that could transform a portion of the energy use in the state towards the intentions of the original goals of SB 221.
The abuse of the system would be limited by price caps and volume requirement in the bill. End-users should realize prices would not climb any more than the explicit price caps – “An electric distribution utility or an electric services company need not comply with a benchmark under division (B)(1) or (2) of this section to the extent that its reasonably expected cost of that compliance exceeds its reasonably expected cost of otherwise producing or acquiring the requisite electricity by three per cent or more.” Utilities should realize their business is not required to transform quickly and drastically given the initial volumes are slowly being ramped up plus the cost limits should mitigate some of the rise. Inside the platform, vendors and developers would submit their project information. They would also submit a minimum subsidy value needed to have the project go forward. The various utilities would then bid on the various projects. A sample screen of the platform I have in mind is shown below:
The platform would enable the commission to have a market price to observe the cost of advance technology relative to traditional renewable. This would also enable the utilities to find projects quicker and develop a portfolio for achieving the requirements while staying under the restrictions of the bill. The end-users and developers would have ways to participate in the future of Ohio energy mix.
The other big propaganda for SB 310 was that SB 221 is too costly. Too costly is questionable given the advanced energy resource requirements had price caps as noted above. If the targets are too costly the utilities did not have to achieve those targets. The overarching cost rise was limited to 3%.
There were also cost limits, specifically, on renewables:
“The compliance payment pertaining to the renewable energy resource benchmarks under division (B)(2) of this section shall equal the number of additional renewable energy credits that the electric distribution utility or electric services company would have needed to comply with the applicable benchmark in the period under review times an amount that shall begin at forty-five dollars and shall be adjusted annually by the commission to reflect any change in the consumer price index as defined in section 101.27 of the Revised Code, but shall not be less than forty-five dollars.”
In addition, there were limits on the solar piece:
“The compliance payment pertaining to the solar energy resource benchmarks under division (B)(2) of this section shall be an amount per megawatt hour of under-compliance or non-compliance in the period under review, starting at four hundred fifty dollars for 2009, four hundred dollars for 2010 and 2011, and similarly reduced every two years thereafter through 2024 by fifty dollars, to a minimum of fifty dollars”
However, there was a disclaimer that made the use these price caps quite troublesome – “The compliance payment shall not be passed through by the electric distribution utility or electric services company to consumers. The compliance payment shall be remitted to the commission, for deposit to the credit of the advanced energy fund created under section 4928.61 of the Revised Code. The compliance payment shall be subject to such collection and enforcement procedures as apply to the collection of forfeiture penalties under sections 4905.55 to 4905.60 and 4905.64 of the Revised Code.” This basically directs the utility to implement more expensive programs to avoid the compliance penalty since this was not a legitimate bridge.
Those supporting SB310 for cost reasons could have sought adjustment of the above cost numbers versus throwing the entire advanced energy requirement out of the equation. A simple rewrite of the compliance payment could have also assured the utility never spent any more than allowed. The one area which was left open to unlimited cost was the Energy Efficiency and Demand Side Management (EE/DSM) programs. As with the alternative energy requirement, a price cap should have been established in terms of rate increases from EE/DSM programs. SB310 still does nothing to address future cost of EE/DSM programs.
Energy Efficiency (EE)/ Demand Side Management (DSM)
The EE/DSM arena is a scary place given its spectacular growth. As noted in my Clean Power Plan review paper #3 , the industry has grown significantly from $1.6 billion in 2006 to $5.9 billion in 2011 and projected at over $8 billion (figures from the American Council for an Energy-Efficient Economy). With that much money in the system in such short time and the fact that the industry depends on estimates, there is bound to be “corruption” unless there are good checks and balances. EPA notes this in their discussion of EE/DSM – “Regardless of how the energy savings of an energy efficiency measure are determined, all energy savings values are estimates of savings and not directly measured”.
I am a supporter of energy efficiency and conservation programs having seen some fantastic data and work while assisting the Northwest Power & Conservation Council. However, I have also seen the darker side while assisting a utility in Indiana and reviewing some of the AEP plans. The companies who are in charge of evaluating, measuring, and verification are typically working in all three spaces. I have seen an evaluator in one state who acted as a measurer in another state. This cannot be allowed. Given that many utilities get shared savings, they are somewhat indifferent in this discussion. Shared savings is an incentive mechanism created to align the utilities with reducing energy usage. In the traditional regulated format, the utility only gets a return on capital investment, which incentivizes the utility to grow energy usage. If demand is falling, there is less likely any need for capital investment. Shared savings allows a utility to share in the savings of an efficiency program by collecting a certain percentage from the reduction of energy usage. Therefore, when an evaluator approves a plan the utility proposed, and the measurer and verifier support it, the utility would not oppose the assumed large savings in kWh, even though it may not be real, because the cost difference and savings are shared with the utility. The bigger the saving, the more the utility gets back. The only consequence is the load forecast will typically be too low and the rate payer is stuck paying more for plans that really add no savings. Most of the time, the commission is not equipped to understand the nuances in the EE/DSM program, so the utilities can bring in their expensive lawyers and impressive EMV. Before you know it, the programs is approved. The last leg of defense in an overwhelmed commission is the consumer protection council, which was cut in half by Kasich in 2011, even though they received their pay from the utilities, not the state budget. This was in the year they saved the rate payers significant amounts of money and was a true thorn in the utility. “The Supreme Court of Ohio ruled 7-0 in its April 19 decision that the PUCO improperly allowed AEP to charge customers unlawful and unreasonable rates. The Court ruled in favor of the OCC in agreeing that AEP’s 2009-2011 rate plan was unlawful by including $63 million in retroactive rates, $456 million in costs to potentially provide default service for customers who shop for an alternative supplier and $330 million in carrying charges for environmental investments.”
The energy efficiency cost you are currently paying can be easily computed from your bill if you belong to AEP. They post the calculation of your rate. Download the excel file and enter your information and review the corresponding sheet that represents your profile. In my case, I am paying $5/month or a total of $60/a year to pay for the energy efficiency program. The residential energy efficiency program is essentially reducing subsidies with a little portion for O-Power. O-Power is a report, telling me how much more I consume relative to my supposed comparable house. Is it truly worth $60/a year to subsidize light bulbs and a report to tell me my consumption relative to other houses? What alternative light bulb would I buy if it wasn’t for the subsidy? Does it achieve the value that the measurer and verification company is stating? In this case, my rate is being impacted nearly 4% by this program.
Better oversight is needed in the EMV space for EE/DSM. Some worthwhile programs can be found in the data, which are likely around 50-70% of the total programs. Many other programs are predominantly number tricks, enabling the EE/DSM industry to support itself and grow. SB 310 should have addressed price caps and better oversight EE/DSM.
SB 310 still carved out a solar requirement in one of the cloudiest states in the country. I think, in large part, the belief was if you had a solar mandate, solar manufacturers would come here. There is enough solar demand in the US market that if the state of Ohio could create a supply chain and manufacturing advantage, they would come here to manufacture and even to export to other states. China is a leading manufacturer of solar not because they placed a solar mandate.
SB 310 also ended a requirement that utilities purchase half of their renewable energy from within the state. This, in effect, produces a subsidy to other states. The purpose of the renewable program for many was to stimulate economic development. As I noted in the solar argument, mandates do not stimulate manufacturing, but if you are going to have a mandate, you might as well force some of the development in the state – or don’t have the mandate at all. One cannot criticize too much on cost given the price caps for cost in renewable compliance.
SB 310 does create a committee – “There is hereby created the Energy Mandates Study Committee to study Ohio’s renewable energy, energy efficiency, and peak demand reduction mandates.” The study will cover 8 objectives which I will give my precursory estimate of the results:
(1) A cost-benefit analysis of the renewable energy, energy efficiency, and peak demand reduction mandates, including the projected costs on electric customers if the mandates were to remain at the percentage levels required under sections 4928.64 and 4928.66 of the Revised Code, as amended by this act;
DKB: Cost for the renewable piece will not rise any greater than the 3% required by the bill. EE/DSM mandates are questionable in cost and delivery of actual kWh savings. The current system over accounts 10-40% energy savings, therefore better checks and balances will be need in the EE/DSM arena. Recommend putting a cost rise limit with EE/DSM as with the renewable goals.
(2) A recommendation of the best, evidence-based standard for reviewing the mandates in the future, including an examination of readily available technology to attain such a standard;
DKB: Having qualified commission staff and consultants with significant experience in the region along with some power modeling experience to analyze future mandates.
(3) The potential benefits of an opt-in system for the mandates, in contrast to an opt-out system for the mandates, and a recommendation as to whether an opt-in system should apply to all electric customers, whether an opt-out system should apply to only certain customers, or whether a hybrid of these two systems is recommended;
DKB: If the commission wants to guarantee savings from current structure an opt-in is applicable. However education is the key for consumer actions.
(4) A recommendation on whether costs incurred by an electric distribution utility or an electric services company pursuant to any contract, which may be entered into by the utility or company on or after the effective date of S.B. 310 of the 130th General Assembly for the purpose of procuring renewable energy resources or renewable energy credits and complying with the requirements of section 4928.64 of the Revised Code, may be passed through to any consumer, if such costs could have been avoided with the inclusion of a change of law provision in the contract;
DKB: This is a very slippery slope. Adding contracts with change of law would result in significant risk premiums. Creating sustainable laws is a better answer.
(5) A review of the risk of increased grid congestion due to the anticipated retirement of coal-fired generation capacity and other factors; the ability of distributed generation, including combined heat and power and waste energy recovery, to reduce electric grid congestion; and the potential benefit to all energy consumers resulting from reduced grid congestion;
DKB: The conclusion will reflect how much the utilities influence the committee. Based on my experience, CHP and distributed generation can play a significant part. Not only do they offer energy savings by being close to the demand source and using the heat, which is not used at all at centralized plants, they offer resiliency to the grid and can be used to support the grid in times of need.
(6) An analysis of whether there are alternatives for the development of advanced energy resources as that term is defined in section 4928.01 of the Revised Code;
DKB: There is always room for alternatives and innovation – this is the USA. Governments can play a role in nudging development without overly committing by using price caps such as in SB 310 and SB 221. The fear of transformation only comes from the incumbent who does not want change. A marketplace platform could offer market transparency and a place for end-users and developers to participate in the evolution of the energy industry.
(7) An assessment of the environmental impact of the renewable energy, energy efficiency, and peak demand reduction mandates on reductions of greenhouse gas and fossil fuel emissions;
DKB: Estimation should use a dispatch model to produce these figures since the commitment of the units will likely change particularly if the load curves flatten. A flat load curve is actually to the benefit of the coal units. Ohio is a net exporter of electricity, so bordering states programs will be of significant influence.
(8) A review of payments made by electric distribution utilities to third-party administrators to promote energy efficiency and peak demand reduction programs under the terms of the utilities’ portfolio plans. The review shall include, but shall not be limited to, a complete analysis of all fixed and variable payments made to those administrators since the effective date of S.B. 221 of the 127th General Assembly, jobs created, retained, and impacted, whether those payments outweigh the benefits to ratepayers, and whether those payments should no longer be recovered from ratepayers. The review also shall include a recommendation regarding whether the administrators should submit periodic reports to the Commission documenting the payments received from utilities.
DKB: If they really audited this, I think they will uncover quite a bit of dirt. Once again this is not due to the efficacy of the mission, but to the fact the industry has grown so rapidly and there is just so much money now.
Politics SB 310
Lastly, I want to address the politics of SB 310. Many insiders deem SB 310 as the First Energy Corporation bill. Rumors express a concern that some of these programs were causing a drop in capacity prices in this region. Given that First Energy coal fleet is deregulated, this was a big concern for them. Mathematically, this would occur, but the volumes from SB 221 at this time are too small to have a significant impact. The real drop in capacity prices was a function of the aggregators in other parts in the PJM markets, the MISO imports, and stagnating demand which drove the capacity price down. Dropping of advance technology resource requirements would have only threatened the utilities. No one else would have been detrimentally impacted by having the advance energy resource option given the price caps – unless you think 3 percent is too much to pay for diversification – perhaps 2 percent? I believe Distributed Generation and Cogeneration incentive mechanism provided a threat to the utility that they did not want to risk taking on. SB 310 is a bill to leave no utility behind, but at the cost of potentially stagnating advancement. The keyword is potential – it is possible that nothing would change, but a cost of 3% may have been worth the risk. A positive, I see from SB 310 relative to SB 221 is the dropped responsibility of the commission. They don’t have to understand the potential advance technology. They lose a key oversight piece “For the purpose of this section and as it considers appropriate, the public utilities commission may classify any new technology as such an advanced energy resource or a qualifying renewable energy resource”
In conclusion, the major weaknesses of SB 221 were not improved and the intent of the bill weakened in SB 310. I regret I did not have time nor was asked to review SB 310 before the bill was signed. The impacts of SB 310 will benefit a few. The few are mainly the utilities. It is possible End-users may save some money with SB 310 relative to SB 221, but the savings likely will not amount to much given the potential gains of transforming the energy mix for Ohio to be more resilient and environmentally friendly. The next adaptation to the Ohio energy bill needs to re-introduce the advance technology portion found in SB 221 and create a mechanism for success by increasing the commission’s budget and the development of a clearinghouse platform for advanced technology. Other adaptions include adding a price cap on EE/DSM similar to the alternative energy source option, greater oversight of EE/DSM programs, and fine-tuning the compliance costs to give more flexibility for the commission to modify and utilities to be able to recover some of the alternative compliance payments.
End-users are still left with many other uncertainties including the recent EPA Clean Power Plan to mitigate CO2 emissions. If you are an end-user trying to understand the future of power, I can and will be able to help you navigate through the storm of uncertainty. I have many years of experience in forecasting and developing risk mitigation strategies in the energy industry. I am always up to date in current markets and offer a daily forecast of all North American power hubs. This product is being used by hedge funds and utilities.
Your Enthused and Optimistic Energy Consultant,
Founder & Principal
All Energy Consulting LLC
“Independent analysis and opinions without a bias.”