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Energy Guide

All posts by Susanne Buckley

New Year’s Resolutions for Energy Buyers

Below are three resolutions we can all live by because they do not include eating healthier or exercising more. These 2019 resolutions are targeted to energy buyers to help ensure your energy procurement programs are best-in-class.


Focus on Cost, not Just Price


Even though we folks in energy procurement are obsessed with energy rates, company budgets only care about overall costs. When looking at your company’s energy budget, your usage must be considered as much as your energy rate.  Energy consumption should be evaluated for quantity and quality.


It is important to understand consumption patterns given production levels, weather impacts and load flexibility. Benchmarking current consumption alongside production levels and outside temperatures is a great place to start. Trends may be evident almost immediately and anomalies may present themselves.  Identify load-consuming equipment that may have flexibility to run in advance of or behind peak hours without dramatically impacting production.  This type of load flexibility is valuable and can be monetized. Once you get your arms around how much your facility uses today you can then start figuring out how to use less tomorrow.


The quality of the power coming into your facility should also be evaluated. Specifically, voltage sags of only milliseconds can cause production interruptions costing thousands, if not millions, of dollars. These sags are usually caused by outside forces such as animals damaging utility distribution equipment, cars running into utility poles and lighting strikes.  It is nearly impossible for utilities to eliminate voltage sags for an entire network, which leaves customers to provide their own correction equipment. Quantifying the total costs of voltage sags to your operations can allow you to calculate payback periods for customer-sited solutions such as active voltage conditioners (AVCs).


Purchase Proactively, Not Reactively


Being market reactive is a very costly approach to energy buying. Many energy buyers manage their purchases around their existing contract-end date, watching the market for only a few months prior to contract expiration.  This method is not optimal and it is risky especially if the expiration is during peak price times in the winter and summer months.


By  way of example, since 2015, electricity to be delivered during the year of 2020 has traded at a minimum of $33.33/MWh and a maximum of $45.33/MWh. That is a 36% difference! If you are able to proactively take advantage of market lows by making purchasing decisions years in advance of delivery, then the likelihood of securing market lows can be achieved. Changing purchasing strategies and policies to allow this type of long term planning can be extremely valuable to your bottom line.


Expect More from Trusted Advisors


Energy suppliers and brokers are constantly seeking their next customer as sales quotas loom over their heads. This can leave many of their current customers wondering when the last time they saw “our energy sales guy” in our office. Energy buyers should demand more of their trusted energy advisors. Energy costs are one of the top expenses for many manufacturers so keeping on the leading edge of risks and opportunities is critical to your success.


Insist on periodic in-person updates on both the energy market fundamentals and impending regulated cost impacts should be provided.  Ask for energy budgets based on your production forecasts. Presentations should be provided that you can used to communicate to your management team. Finally, you should have the cell phone number of your trusted advisor and feel as if you can reach them at any time with urgent questions or concerns, but you may want to wait until after the New Year’s Eve party.






Winter Energy Costs May Make You Scream

Time to pull out and dust off your electricity and natural gas supply contracts to find out if you are exposed to a variable market rate. Why? Because if you are on a market rate this winter you will likely have a major case of sticker shock.


Natural gas and electricity prices for delivery this winter have increased dramatically moving up by more than 35% since early November. Natural gas futures for January delivery have not been this high since 2014 and are bouncing between $4.40 and $4.80 per dekatherm (dth).


The run in pricing has been driven by low inventories of stored natural gas coupled with below normal temperatures during the early part of this winter. The storage deficit started in July as inventories broke below five-year minimum levels. Since that time, the deficit has increased each month to levels which are now 12% below the five-year low and 19% below the five-year average. All it took was about three weeks of below normal temperature forecasts for the market to explode up to nearly $5.00 per dth. This volatility will continue as long as temperatures continue to be colder than expectations.


Since electricity prices are now heavily driven by the natural gas market, we have seen the electricity forwards for this winter increase by 23%. Wholesale prices for January alone have gone from $41.00 per MWh to $50.50 per MWh in just 45 days of trading.


Most customers like the stability of a fixed rate and enter into supply contracts for a defined term. Once the term of the fixed price expires nearly all suppliers roll the customer to a market variable rate. This goes unnoticed by most customers if the market rate is low but when it is screaming (like the current situation) it will make you scream when you get your bill!


High prices during times of high consumption obviously have a doubling- down effect. Most residential customers will be consuming nearly 80% of their annual natural gas usage in the next three months. The last thing you want to do is pay the highest prices seen in four years during the time when you use it the most energy.


If you are not sure if you are on a fixed rate or variable rate then call your supplier and inquire. Their phone number will be easily found on your bill. Now is the time to shore up those contracts and reduce exposure to market rates!






What’s the 2018/19 Winter Energy Pricing Outlook?

It is hard to believe that we are already talking about winter since we just turned off the air conditioning, but it can not be denied: Its  almost November! Historically, the winter months offer the highest and most volatile energy pricing, but what should you expect this coming winter?



Nationally, the summer of 2018 had the most cooling degree days on record. (A cooling degree day is the number of degrees that a days average temperature is above 65 degrees F.) That means more energy was used to cool this summer than any other year. These high temperatures were lead by the month of September which was 4 degrees higher than 30-year normal temps.


Predicting weather for this winter is obviously a risky endeavor but numerous weather models are calling for a cooler than normal winter once we get past November. The El Nino pattern is predicted for this winter which can cause heavier snowfall and colder temperatures in Texas, the Midwest and the Southeast. Based on  additional indicators such as sunspot cycles and snow cover in Eurasia, meteorologists are targeting February 2019 as the month to watch for extremely cold temperatures.


Bottom Line: If the weather models play out as predicted then this is bullish to pricing.


Natural Gas Storage

The extreme cold temperatures during the first part of this year created one of the largest ever withdrawals of natural gas from storage. This coupled with the high demand for natural gas in the electric generation sector due to the hot summer has left natural gas storage at its lowest levels since 2005.


These levels are currently 14% below the five-year average and 9% below the five-year minimum. Based on the weather forecasts, the Energy Information Association predicts natural gas inventories will end the heating season in March at 1.3 Bcf, which makes it one of the five lowest ending inventories since 2004.


Looking at the past decade, the last time storage was anywhere near this low going into the heating season was 2014. During that time NYMEX prices were near $4.00 for the prompt month. Current prices for November are $3.30.


Bottom Line: Entering heating season with inventories 14 % below the five-year average is bullish to pricing. 


Outages and Retirements

Nuclear generation outages in September set a 10-year record with over 10.9 GW of capacity going offline for maintenance and refueling. This occurred at the same time we experienced one of the hottest Septembers on record. This has lead to less efficient, higher-priced generators setting hourly rates resulting in a 5% increase in electricity prices over the past month, just as we are heading into the winter.


Long term, coal retirements continue to be at the forefront of the news as the Trump Administration tries to figure out who will pay to subsidize them. Competition from cheaper natural gas generation is squeezing out the worst performing coal units with many of them running less than 40% of the time. This is too costly for most utilities, forcing them to make hard decisions about their continued viability. Nationally, the cumulative retirements ofcoal generation since 2010 have now reached 50,000 MW’s.


Bottom Line: Nuclear outage coinciding with time hot weather resulted in higher prices going into the winter. Eliminating high-priced coal generation from the grid is neutral to long term pricing but could create short term volatility during times of high demand.


Natural Gas Production

The rate of natural gas production continues to overcome many of the bullish factors.  Production of dry gas in the lower 48 states has reached nearly 86 BCF/d which is a 13% increase over last year at this time. Shale production continues to take center stage contributing over 56 BCF/d or 65% of the total production. This is a staggering 27%  increase over last year. Although prices are holding at relatively low levels producers are extracting premium value for the liquids contained in the gas stream. This premium value is keeping the producers pumping.


Bottom Line: The increase in natural gas production is the major anchor keeping prices down and is bearish to winter pricing.


Natural Gas Fired Electric Generation

Electric generation using natural gas as a fuel continues to increase. In the PJM footprint alone, 11 GW for 18% of the region’s total was added while 14.4 GW for 19% of coal was retired. Although not making up entirely for the lost production, the new generation operates at much lower costs than did the retired coal generation assets. This is mainly due to the efficiency of the new generation technology. Those generators utilizing the newer natural gas fired technology can typically generate electricity at 35% below the cost of the older coal technology.


 Bottom Line: Making electricity cheaper is bearish to pricing.



Even though there are multiple bullish factors leading into the winter the fact that natural gas production is so high is dampening short term price impacts. However, if there is prolonged cold in the early part of the winter there is a risk of volatile short- term pricing as traders will be watching the already low inventories quickly be consumed.


Bottom Bottom Line: If you have any open positions this winter consider locking in a good portion to protect your prices.






Hottest Ohio Energy Stories of the Summer

The energy markets in Ohio do not disappoint when it comes to excitement. This summer proved to be another season full of potential policy changes and market anomalies.


Trump Gives Coal CPR


Trump announced a roll back of pollution controls on coal-fired power plants to slow the pace of the transformation in the power sector toward natural gas. Market forces of cheap natural gas have strained the economics of coal-fired generation for a decade; more than 200 coal plants have closed since 2010. The EPA’s proposed relaxed standards are meant to slow the sharp pace of retiring coal plants to a rate of 20% between now and 2030. Without the new standards the rate of decline is predicted to be 29%.


The proposal eliminates the requirement of certain pollution controls if the plant invests in efficiency improvements. It is expected that efficiency improvements will only be made in regulated states where captive ratepayers must foot the bill. Opponents say that the few plants this may help will not outweigh the negative health impacts of the standards.


FES Announces More Plant Closures


FirstEnergy Solutions (FES), the bankrupt subsidiary of FirstEnergy Corp., announced it will deactivate more than 4,000 MW of coal and oil generation in Ohio and Pennsylvania in 2021 and 2022. This announcement comes on the heels of its previous notification to PJM of its plan to shutter the 908 MW Davis-Besse nuclear plant, the 1,268 MW Perry nuclear plant and the 1,872 MW Beaver Valley nuclear plant in 2021.


FES blames the closures on the market, which it says “does not adequately compensate generators for the resiliency and fuel-security attributes that these plants provide.” FES has taken this argument to the Trump administration pleading that the closure of these plants is a national security issue and calling on Section 202(c) of the Federal Power Act. The rarely used wartime section of the act does allow the Secretary of Energy to issue temporary orders if “emergency reasons of a sudden increase in demand for electric energy or shortage of electric energy” were to occur.


More closures do reduce supply; however, with a 21% capacity reserve, electricity scarcity is a hard argument to make. Nevertheless, the Trump administration has circulated a “confidential” draft plan which would require grid operators to buy electricity from the struggling plants before any other source, thereby propping up the financials of these plants.


PJM Pricing Changes on Horizon


Late last year, PJM began considering increasing payment to power generators that are less responsive to pricing signals such as coal and nuclear plants. In a highly technical proposal, PJM discussed changing its Locational Marginal Price (LMP) dispatch algorithms. Baseload units are generally not bidding in their marginal costs to PJM because, in the low-price environment, they are only profitable a few hours during the day. Under these conditions these plants accept the LMP prices that are set by more price-responsive units (i.e., natural gas units).


PJM points to the need to more accurately reflect the resources required to incentivize flexible resources and to minimize out-of-market uplift payments which are needed to keep high-priced units running for reliability. Bottom line: Market analysts are predicting LMP prices to increase, capacity prices to decrease, with a net effect of 2% to 5% increase overall.


Low Natural Gas Storage, Who Cares?


Natural gas storage is 20% lower than the five-year average and 8% lower than the five-year minimum, yet pricing is still near record lows. Prices at $2.80 per MMBTU, which is where we are today, has occurred when storage has been 500 BCF over the average, yet today we are 600 BCF below the average!


Shale production is crushing the market fundamentals as we know them. The cost of pulling natural gas out of the shale regions continues to decline and production output is at all-time highs. This production is in close proximity to consumers reducing risk of long haul pipeline constraints. Furthermore, regional pipelines are being built at a frantic pace to move the gas to higher-priced markets.


Even with the increase in demand for natural gas from power generation it is not enough to prop up prices. Record-breaking production levels at low operating costs are keeping a lid on what ordinarily would be high prices going into the fall and winter.


PLC Bonanza


This summer has been the thirteenth hottest summer on record for PJM and has caused a higher than normal number of notifications to customers who wish to control their for Peak Load Contribution (PLC). Customers can lower their capacity costs from suppliers by reducing load during the five highest-peak hours on the PJM system. Catch the right hours with a load curtailment and customers’ capacity costs will go down proportionally.


Energy professionals provide notifications to customers as to when these hours may occur based on projected PJM system demand. The target number for these notifications is no more than seven or eight in any given summer in order to capture the five hours. This year most providers have sent out at least eleven and we are still only in early September.





Shale Boom Turns 10

Ten years ago, Just Dance by Lady Gaga was the hit song, the Celtics beat the Lakers for the NBA Championship, the financial markets were getting ready to melt down and barely a drop of natural gas was being produced from the shale regions. While all things come to pass – with the exception of Lady Gaga who still is a righteous performer – the shale revolution has shifted global energy fundamentals for generations to come. Here are the biggest market shifts.


Import/Export of Shale Gas and Hydrocarbons


Let’s put this production boom into perspective. For the period 2000 – 2007, U.S. natural gas production grew less than 1%. For the period 2007 – 2017, production grew by 40% and is anticipated to grow by an additional 60% over the next 20 years. Of the 80 Bcf/d of production in the U.S. today nearly 55 Bcf/d is dry shale gas production. Ten years ago, shale gas only contributed 5 Bcf/d!


In 2007, the U.S. was expected to be one of the largest, if not the largest importer of Liquefied Natural Gas (LNG). Import terminals were constructed and ready to receive LNG from the global market just as shale production started to come on the radar. Since that time, this cheap local production killed the import idea but birthed the concept of exporting LNG. Now these terminals are feverishly being modified to export LNG to the global markets. By 2025 it is expected that the U.S. will be one of the world’s largest exporters of LNG.


Finally, pipelines to Mexico and Canada are pushing more and more natural gas out of our country. We now export nearly half of the natural gas needed in Mexico. Ten years ago our net import position was around 10 Bcf/d and now we are net exporters of almost 3 Bcf/d. This new position of net exporter of natural gas and associated hydrocarbons makes us more energy independent, certainly influencing international dynamics.




Short term, this glut of production has driven natural gas prices to all time lows altering the game for participants. Prior to the shale revolution, NYMEX natural gas prices were on average 75% higher than where they are today and with much more volatility. Storms in the Gulf of Mexico would whip up the prices on the risk that production could be shut in on the drilling platforms. It would not be unusual for prices to double based on the threat of a hurricane. Ten years later, there is virtually no volatility in the natural gas market. Traders barely care about hurricanes since most of the production is in the market areas. Furthermore, basis prices (difference between Henry Hub and the market area) are consistently negative in the Appalachian region making it the cheapest gas available.


Contributing to the low prices are improvements in drilling and extraction costs. Data consultant, IHS Markit, has estimated that over 1200 Tcf of natural gas resourses can be extracted from the ground at Henry Hub prices below $4/MMBTu. At the current rate of production that equates to 41 years of production under $4!


Power Generation Shift


Ten years ago there was a renaissance of new nuclear power projects and clean coal technologies making the headlines. Nearly a dozen new nuclear power plants were in the permitting stages and many were talking about CO2 sequestration related to new coal plants. Within a few years many of these plans were completely scrapped with the advent of the cheap, abundant natural gas. In addition to the fuel economics, natural gas-fueled power generation technology became extremely efficient. The result: Manufactured electricity that is cheap, clean and offers generation plants that are easier to build than nuclear – or coal – fired power plants.


In 2007, the generation mix in the U.S. was 49% coal, 20% nuclear and 22% natural gas. Today the mix is 30% coal, 20% nuclear and 32% natural gas, a trend that is expected to continue in favor of natural gas. IHS Markit predicts natural gas to grow to almost 50% of the power produced by 2040.




The American Chemistry Council estimates there are 310 petrochemical projects currently under construction or in planning for over $185 billion in potential capital investment. This compares with $85 billion worth of projects completed since 2010. The reason for this significant increase in investment is that chemical products produced in the U.S. can now use natural gas as their feedstock while the rest of the world uses oil. Prices for the chemical products such as ethylene, acetylene, and benzene generally track crude oil, so using cheap natural gas to make these products is a huge global competitive advantage. The U.S. petrochemical industry is providing a continuous flow of investment to capture this margin, positioning the U.S. to be the leader in satisfying global demand for chemicals.


Additionally, the Oil and Gas Journal reports that the U.S. will spend $18 billion in natural gas pipelines in 2018 which is up 144% from the previous year. This capital is earmarked for the construction of over 2,800 miles of pipeline. This is major money that is being pumped into energy infrastructure. It is unlocking the value of this new energy asset and positioning the U.S. to be an even bigger global player in the future. Talk about a game changer!






Super Summer Sale on Energy

As heat indices reach triple digits this summer, believe it or not, the energy markets are responding with short- and long-term savings opportunities for buyers. Below are the market trends that could bring value to your budget.


Buy Electricity for Future Years to Save Money


The current wholesale market for electricity delivered in 2021 and 2022 is flirting with all-time lows. The previous all-time low was established around this time last year at $27.50/MWh. The rates for these two future years are now sitting just 4% above that level at $28.50/MWh and $28.25/MWh, respectively. This is good value and well within most risk managers’ risk tolerance so purchasing power at these levels should be considered.


As for the rest of the calendar strips, power delivered in 2019 is commanding a bit of a premium, trading at $30.25/MWh. This premium is mainly due to the amount of natural gas in storage nationwide being well below the five-year average. As more natural gas fired generation is built the natural gas and electricity markets are become more connected at the hip, as one goes up so goes the other. Calendar strip 2020 is still trying to hold a small premium at $29.45/MWh. This calendar strip has room to go down especially if natural gas storage levels start making gains over this summer.


Jump on Capacity to Save


Capacity is the cost for reliable power and makes up approximately 20% of your electric supply rate. PJM, the transmission grid operator responsible for reliability in our region, holds an auction each year for the value of capacity. The auction is held three years in advance of the delivery year which starts each June. The capacity auction rates vary each year depending upon how much supply is available and how much demand is projected.


The value story with capacity starts June 2019. The capacity auction rates for this planning period cleared at a price nearly half of what you are paying today. The downward trend then continued with the next planning period starting June 2020 with an additional reduction of 18%.


These extremely discounted capacity costs have the potential to reduce your overall supply rate by 10% to 15%. If your supply contract is coming up for renewal this year you can take advantage of these low prices now by locking in capacity and moving that future savings into rates paid today.


Glut of Regional Natural Gas is a Savings Opportunity


Ohio is a major contributor of the natural gas shale play. Producers in both shale formations, Utica and Marcellus, are pumping out gas like there is no tomorrow. Production from these regions continues to break records and is now contributing over 30% of all the natural gas produced in the lower 48 states. Pipelines have been built to move the natural gas out of our region, however, not fast enough to keep up with the pace of production. The result is the potential to capture negative basis prices.


Physical constraints of a system usually mean higher prices for customers but in this case, it is the opposite. The pipeline constraints are keeping the gas trapped in our region and pushing down prices to again flirt with all-time lows. Depending upon your load shape and location in Ohio, prices for natural gas can be a discount to Henry Hub that trades on the NYMEX. Many customers are enjoying offers from suppliers at 5 to 15 cents below NYMEX settle prices. On the wholesale market, basis quotes are reaching levels of negative 50 cents in some locations. This is a great opportunity to take advantage of the (temporary in the short-term) physical constraints of the system.


On the commodity side, just as electricity, prices for natural gas delivered in 2021 and 2022 are extremely low. The NYMEX  is trading around $2.60/MMBtu for delivery in those years. Comparatively, the NYMEX has settled between $2.45/MMBtu and $4.14/MMBtu each calendar strip since 2014. Add that to the negative basis and you have incredible value for natural gas. Get it while the sale lasts!

Why are Energy Markets so Freaked about Trump’s Proposed Bailout of Failing Power Plants?

In what few would call a national security issue many are calling the end to wholesale power markets as we know them. In a leaked Dept. of Energy (DOE) memo, it seems the Trump administration is looking to breathe life in the form of bailouts to uneconomic coal and nuclear power plants for a period of two years. Where there is a will there is a way and the FirstEnergy lobbyists found it in Section 202(c) of the Federal Power Act by proposing the transition to lower cost generation a national security issue.


The concept of nuclear bailouts is certainly not new. In fact, states including Illinois and New York and have already implemented some form of bailouts with little market disruption. Why is this latest proposal so concerning to those in the energy markets?


First, is the use of the Defense of Production Act of 1950 which was enacted to aid in civil defenses at the onset of the Korean War. Section 202(c) specifically allows the secretary to issue temporary orders in wartime or other “emergency reasons of a sudden increase in demand for electric energy or a shortage of electric energy…”. This section, which undoubtedly is being interpreted broadly, has never been used to financially aid ailing, uneconomic assets. Calling the market transition to more economic generation a “national security emergency” offends most sensibilities especially given the pace and volume of new installed power generation.


Second, the 41-page leaked draft DOE memo calls for the federal government to purchase electricity from a set list of coal and nuclear plants for only two years. During this two-year period the DOE will continue to study the issue. (Two years also allows plenty of lobbying opportunity). The temporary nature of the directive alone is unsettling as it is difficult to establish new market protocols and procedures on a temporary basis. The market will be unclear about its risks which will mean higher prices for consumers.


Third, the number of facilities on the DOE’s list could be enough to skew the economic dispatch of the existing power fleet and stymy new generation. Existing economic generators may be squeezed out as rescued uneconomic plants take precedence in the dispatch order. This will certainly impact the hourly energy prices and influence the forward markets but nobody knows by how much. Not knowing how these “rescued” plants will participate in the capacity and energy markets leaves existing participants holding a gigantic bag full of risk and new money seeking more stable investments. As such, money that was once pouring into energy innovation could trickle to a slow drip.


Finally, having the federal government pick the winners and the losers is not comfortable for most stakeholders.  The Federal Energy Regulatory Commission (FERC), who has a history of rejecting prior attempts by DOE to prop up uneconomic plants, will be called upon to figure out who pays the money and who gets the money even though they don’t agree with the plan.  FERC publically rejected the idea of a “national security emergency” in a recent Senate committee hearing meeting but that may not matter. By using Section 202(c), the Secretary of Energy sidesteps FERC approval and forces their hand to implement.  This will be a complicated contentious rate making process that could take the entire two years to figure out.


There must be a better way. The CEO of Exelon, the largest nuclear generator in the U.S. and a huge beneficiary of the bailout, thinks the idea of a “national security emergency” can not be supported given the current generous capacity reserves. The capacity reserves in PJM (the transmission grid operator for Ohio, plus 12 other states and D.C.),  is over 21% for the foreseeable future which is hardly a scarcity of power resulting in a national security emergency. With all the uncertainty one thing is certain, the markets would not be the same if the DOE bailout scheme is implemented.

Should Manufacturers Make Electricity?

Customer-owned generation is not a new concept but due to changing energy markets and improved Combined Heat and Power (CHP) technologies, it’s becoming more feasible for more customers. Consumers who are considering generating their own power to bypass rising utility distribution rates, or those needing to replace a boiler, may find this technology penciling out favorably. More professionals are entering the CHP development space challenging customers with this “make or buy” decision. What factors make a CHP project work?


Need Heat


Standalone customer-sited generation is generally not efficient enough to beat the sum of market generation rates and utility distribution rates. The heat rate (the amount of Btu input needed to make 1 MW of power) is around 16,000 MMBtu per 1 MWh. Considering a delivered price of natural gas of $4/MMBtu, this puts the produced MWh around $64 without even considering operating and maintenance costs. That is not going to work as delivered electric prices for most manufacturers in Ohio are between $50 to $60 per MWh.


What makes CHP viable is the ability to capture the heat generated from burning natural gas and using that heat elsewhere in the plant. This captured heat displaces fuel that would be otherwise be required to satisfy the thermal demand in the manufacturing process. This is the classic double dip. Use the benefits of the fuel twice, once to generate electricity and once to make heat. The value of the heat benefit starts closing the gap in customer-manufactured MWhs to where it can be a winner.


No brainer opportunities come into play when an existing boiler has come to the end of its useful life. Instead of purchasing a new boiler, CHP should be considered in the design engineering. The CHP engine will reduce the size of a new boiler if not eliminate it altogether. The byproduct of burning natural gas in the engine is kWhs generated right at the plant site, eliminating the need for moving the power across inefficient transmission and distribution lines. Talk about buying local!


Need High Tariff Rates


If you can shop for generation supply (i.e., your facility is not taking power from a municipality or cooperative) then you are likely receiving very low generation rates. The energy market is near all-time lows and the capacity markets into the future have dropped to very low levels, as well. All this makes for low generation rates. The distribution rates are another matter. Rising transmission rates due to utility infrastructure improvements, as well as a basketful of non-bypassable charges have raised customer distribution rates significantly over the past five years.


For those customers located behind municipalities or cooperatives this could be an opportunity to finally take control of your energy costs. Without on-site generation, there is no other mechanism besides reducing consumption to really control electricity costs if you are unable to shop for generation service. Typically, municipalities and cooperatives have high demand charges ($/kW) associated with their tariffs. These high demand charges can drive the overall rate up considerably especially if the load factor is less than 80%.


When talking about tariffs I cannot go without mentioning the dreaded deal-killing standby rates. Standby rates are charged by the utility to the customer when the CHP is not operating. If the CHP goes offline, the full load of the facility would move to grid power. In doing so, a new demand for the full load would be established. Depending upon the utility, the customer may be required to pay a majority portion of the new demand charge for the next year, even during those months when the CHP is fully operable. Working these standby demand charges into the deal can pull the plug on any economic benefits.


Need the Right Structure with the Right Partner


A continuum of deal structures exists for implementing CHP from the customer owning the asset, leasing the asset or just purchasing the energy and heat from the asset. Each of these structures comes with its own set of risks and benefits. From a pure financial play, the customer owning the asset will bring the greatest value but the greatest operational risk and requires mega capital. Partnering with developers that will design, construct and own the project with a lease agreement back to the customer helps alleviate the need for capital investment but the customer will be required to share the benefit with the owner. The final structure which looks like a power purchase agreement also alleviates the need for capital and is a very easy structure of price per unit of heat and energy, but this structure also shares the project benefits with the developer.


Just like most things, finding the right partner to implement CHP for your company is critical to the success of the project. Borrowing rates, performance guarantees, price escalators, and off-balance sheet accounting are all the details that can make or break the implementation of CHP. Many developers and even traditional commodity suppliers are now offering CHP development, but there are relatively few completed projects. There can be benefits to using the “new player in town” but more than likely they will be learning on your project which is not a very comfortable position as the customer.


However, under the right conditions, CHP can offer a huge benefit that converts uncontrollable electric tariffs to more manageable natural gas costs. Through risk management strategies, it is possible for CHP to produce the benefits of lower cost and more price control.

What Does FirstEnergy Solutions Bankruptcy Really Mean to You

No one would have predicted a few years ago that the very same company fighting our policy makers for the opportunity to live or die by the market through electric deregulation would be the same company succumbing to Chapter 11 bankruptcy restructuring, mainly due to the effects of an open market. The company which once had the largest market share of electric-shopping customers in Ohio has been lobbying everyone, even President Trump, for a life preserver to keep its high-cost power plants operating. When one hears about a perceived utility going bankrupt most immediately think “Get out the candles, honey, the power is going out” but what are the real impacts of this bankruptcy on Ohio’s people, policy and the price we pay for power?




Let’s first understand who the heck is going bankrupt. FirstEnergy Solutions (FES) is a subsidiary to FirstEnergy Corp. Other subsidiaries include the regulated utilities such as Toledo Edison, Ohio Edison and Cleveland Electric Illuminating, which are not included in the bankruptcy action.  FES is NOT the utility. It does, however, own the fleet of power plants formerly owned by First Energy Corp. and it does market this power to customers through its deregulated retail operations.


FES has indicated that possibly within the next three years it will close three power plants, two of which are the infamous Perry and Davis-Besse nuclear plants on the shores of Lake Erie; the third a nuclear plant in Pennsylvania.  If this actually occurs, the closing will undoubtedly impact the employees of those plants which have been reported by FES at 2,300 and will reduce the power available by 4,000 MW. The bankruptcy filing requests that the plants continue to operate while FES goes through the bankruptcy process which some experts are saying it could take five years at a minimum. All the while, the company will be looking for a buyer of the assets. In the short term, FES indicated that it is business as usual for employees.


The economic challenges of these power plants date back decades with enormous construction cost overruns but the final nail in the coffin was the extreme market pressure from natural gas plants which can produce power at significantly less cost than nuclear power. Here is the evidence: 11,000 MW’s of new natural gas plants in various stages of planning and construction in Ohio.




The news of these plants closing has been expected. The company missed the optimum window to sell them, placing all its bets on the ability to lobby for market rule changes and subsidies.   Over the past three years, lobbyists for the company have hit up policy makers like a swarm of locusts. They have been active en masse at the Ohio General Assembly, the Public Utility Commission of Ohio and now the Trump Administration. The efforts have not produced any measurable policy changes as there is little data supporting the need for changes other than the viability of FES.  Additionally, customer groups, environmental groups and independent power producers have stepped up in to be actively engage in the discussion.


Despite many policy roadblocks, FES is throwing the Hail Mary in the policy fight arguing for an 83-year law that would declare a state of emergency to keep the plants open. Pointing to grid reliability, FES has requested that the federal government give the plants preferential economic treatment to maintain operation. PJM, the grid operator in charge of reliability, refutes the claims that closing those plants will result in reliability issues. Additionally, PJM has  mechanisms already in place to provide increased revenue to these plants if they are needed for reliability.




The bankruptcy declaration is not a shock to those close to the energy markets, but it does not ease the pain to the 14,000 FES creditors. The FirstEnergy Corp. stock price did very little on the news and the forward energy markets moved up only a few percentage point. From a short-term perspective, the price to watch is the upcoming PJM capacity auction. This auction determines the price paid to generators by load for committing to meet the system’s peak demand. If FES does not include the 4,000 MW contributed by its nuclear plants in the next auction one would think these auction prices will increase.  The auction will be held next month for delivery in June 2021 to May 2022. (Customers may remember a similar plant closure announcement which occurred  right before the 2015 – 2016 PJM capacity auction. The auction cleared three times the historic average auction price resulting in customer bills increasing by over 25% for that year.)


That being said, the new gas-fired power plants under development will more than make up this lost capacity but it is all about the timing. If all the projects are built by the time of these nuclear plants fully retire, there will be enough power to supply two times the demand of every resident in the state of Ohio.  This fundamental is very bearish to long term prices. Replacing these nuclear plants with nearly double the capacity and at a production price significantly less leads us to speculate that prices will remain low for the long term.











Customer Driven Energy Innovation

The maturing of energy deregulation is now allowing customers to drive market solutions. In Ohio, this story started in 2009 as customers found savings by leaving utility generation and going to third party generation providers. Now, in order to keep their customers, these providers are beginning to meet market demands for more innovation.  Here are three recent trends.


Holistic Energy Planning

With a competitive market comes choices. These choices can be overwhelming especially in a space that can include everything from usage data collecting gadgets to on-site distributed generation.  The energy space is highly fragmented with experts focused on their individual solutions and services. From a customer’s perspective it can be extremely time consuming and frustrating to weed through all the solutions, pitches and expertise flying at them to find the perfect fit for their company.


As a result, we are seeing more customers stepping back from the chaos and developing overall energy plans. In this approach, key stakeholders develop an energy vision and mission for their organization that will then guide actions and initiatives. Such a framework establishes budgetary and sustainability goals, evaluation guidelines for new opportunities, methods to prioritize projects and a plan to communicate these guidelines throughout the organization.


While it may sound like more effort and resources to put such a plan together, customers are finding – in the long run  – it is more efficient. The plan keeps resources focused and on track even when team members move in and out of the organization.


Divesting Customer Energy Assets 

What was once a far-out idea is now coming more and more into the conversation.  Some companies are contemplating selling their energy systems (e.g. company – owned substations, HVAC equipment, energy distribution systems) to energy companies and those energy companies, in turn, providing supply arrangements.


Such a deal was recently executed on a very large scale by Engie and The Ohio State University. In its very simplest terms Engie purchased the steam, chilled water, electricity, gas systems from the university for a little over $1 billion. Engie will then optimize those systems and charge the university for energy and other services on a monthly basis over the course of the next 50 years.


Obviously, this is the King Kong of deals but this transaction can be scaled to meet the needs of manufacturers with aging energy infrastructure. This construct is getting the ear and interest of those in the finance departments who manage capital budgets. As with everything, the devil is in the details of these complex transactions to make them work for both parties.


Engagement Around Consumption

It is nearly impossible to measure program results without clean, consistent and accurate data.  Sleek and frictionless energy platforms are challenging the status quo of data delivered on our energy invoices. Many customers are seeking alternatives to pdf versions of invoices, key punching data and tracking data through spreadsheets.  This is even more critical when companies have ENERGY STAR® and sustainability goals that require benchmarking metrics.


Customers are now demanding platform solutions that will store, track and audit these data while seamlessly connecting with ENERGY STAR Portfolio Manager®.  This type of solution allows the customers to finally have the reporting options they need to drive behavioral change, capital spending and project prioritization.


Additionally, some consumers are analyzing not just what happened in the past via their invoice but how can they impact consumption on a real-time basis. Customers who want to control not just energy peaks but find anomalies in consumption are moving to more real-time monitoring.  Insights can be used to not only track the health of equipment but also of unexpected human behaviors impacting energy consumption.


We are past the tipping point with customer driven solutions and this market will continue to innovate to meet consumer demands.




Leading the Way