LuthINformed- Issue 2, Hedging and Risk

Published to LuthINformed issue 2 (April 29, 2016)

In our last issue, we discussed fundamentals of natural gas supply, pricing and markets. In this issue we look at competitive supply options. You may ask “what makes a good supply agreement?” Simply put, a good agreement is one that allows a buyer to meet budget expectations without paying too high a premium for price insurance.


Hedging and Risk

Many institutions look to reduce, or eliminate, the risk that energy cost volatility will negatively impact their operating budget. The most common way to do this is to conduct a competitive purchase RFP, and enter into a supply agreement with the lowest priced supplier. The premise of this process, of course, is that competition drives down prices. Remember that the price being offered is the Citygate price (below) – not the burnertip price.

Chart 1

The vast majority of buyers hedge volatility risk by means of a fixed price supply contract. But many fixed price contracts still contain risk because they contain usage bandwidths. A fixed price, full requirements contract eliminates this additional risk. Full requirements means the supplier will charge the agreed price, no matter how much gas your facility uses. Such a supply structure meets the needs of a client with a low risk tolerance profile.  In order for your supplier to offer you a price, they must first know how much, and when, you use gas. Typically, data from the past 12 months is used. Either your supplier or consultant may use a technique known as weather normalization to adjust your usage data to reflect “normal”, rather than actual weather conditions.

Full requirements, fixed price contracts provide budgetary certainty, however, they may also include a hefty “risk premium” because the supplier cannot know, for example, exactly how much, or how little, gas your facility will actually use. An ESCO charges this premium to protect themselves against potential penalties and to cover the cost of unknown variables such as fixing cost components which may change in the future. So generally speaking, fixed price, full requirements contracts are among the most expensive contract options.

Understanding this, it’s not surprising that a supplier will offer a lower price if the buyer accepts usage “bandwidths”. This means that any usage above, or below, a certain threshold will be “marked to market”. Under certain circumstances you may be charged current market prices for any usage outside those pre-defined limits. For example, if your facility burns too little gas to satisfy the contract, perhaps because of unusual weather or an operational issue, the excess gas will be sold into the market. And chances are, under those circumstances, the unused gas will be sold at a loss – a loss that can be passed on to you. The opposite scenario also holds true. In January 2014, the polar vortex created unprecedented demand and delivery constraints – and NYC natgas spot prices reached $120/Dth. There were numerous anecdotes regarding dramatic pass-through’s as a result. With respect to futures pricing, the rules of supply and demand always apply.

More…

Next time we will continue our discussion of supply contracts and active management strategies…


DISCLAIMER
Although care has been taken to ensure the accuracy, completeness and reliability of the information provided, Luthin Associates, Inc. (Luthin) assumes no responsibility therefore. The user of the information agrees that the information is subject to change without notice. Luthin assumes no responsibility for the consequences of use of such information, nor for any infringement of third party intellectual property rights which may result from its use. In no event shall Luthin be liable for any direct, indirect, special or incidental damage resulting from, arising out of or in connection with the use of the information.

 

Advertisements

The Magic of Microgrids

Published to LA Confidential, Summer 2016

The U.S. Department of Energy (DOE) defines a microgrid as “a group of interconnected loads and distributed energy resources within clearly defined electrical boundaries that acts as a single controllable entity with respect to the grid. A microgrid can connect and disconnect from the grid to enable it to operate in both grid-connected or island-mode.”

A microgrid may contain a variety of power and thermal energy sources: solar, wind, batteries, combined-heat-and-power (CHP) cogeneration, methane production from sewage treatment and food waste, and even energy storage. The goal is a system that can stand alone to provide power during a power outage or when the main grid is under heavy load. The potential benefits include resiliency against disasters and avoidance of transmission and distribution (T&D) costs by providing power on-site during heavy grid load.

After Superstorm Sandy caused extensive damage to electric power systems, several states sought ways to make the grid more resilient. The New York State Energy Research and Development Authority (NYSERDA), through a competitive competition known as NY Prize, awarded 83 grants to study where microgrids could be cost-effectively installed and operated. Find descriptions of the projects at http://nyserda.ny.gov/ny-prize.  The rapidly dropping prices for both solar and stored power (batteries and ice cooling) provided an impetus for projects that integrate them with other energy efficiency options, such as gas-fired CHP. Several of the studied opportunities will receive development funding to flesh out their details.

Two publicly available studies, one concentrated in an urban industrial area, Hunts Point, and the other suburban, Croton, were examined. Both were sufficiently detailed to demonstrate that the concept is heavily dependent on how much society is willing to pay for resiliency and reductions, or avoidance, of T&D costs.

The general notion is that the use of on-site renewables and demand management would, over time, produce enough revenue to cover the costs of microgrid independence. If sufficient subsidies and incentives are provided to build a microgrid, both designs would work. But if diesel or gas-fired backup generators are used instead of on-site renewables and microgrid distribution networks, both resiliency and load shedding may be attained at a fraction of the installed cost of either system. Of course, emissions requirements must be thoroughly vetted before going this route.

So – are microgrids potentially cost-effective? Microgrids were originally designed for economics, not resiliency. Adding the latter tends to balloon the bottom line cost of new systems, but resiliency brings its own benefits. The rate of return discussion changes when the cost of avoided outages are factored into the economics. Microgrids avert financial losses that occur when businesses, communities, hospitals and other facilities lose power. Thus, outages help boost microgrid economics, since the microgrid keeps power flowing to the facility when the larger grid fails.

At a May 19, 2016 conference NYSERDA reported that the top ten NY Prize applications, those with the highest Internal Rate of Return (IRR), accrued average benefits of $1.679 billion at a cost of about $759 million.  Many of the projects required no more than one outage day a year to tip into a positive IRR.

Microgrids have existed for close to a century in the form of district energy systems that centrally distribute heat (and, in some cases, chilled water, steam or power) at hundreds of sites. Please see www.districtenergy.org/map-of-district-energy-in-north-america/ for more information.   GTM Research, an electric industry research firm, estimates that there are currently about 1.4 GW of microgrids in the US.  They recently increased their 2020 estimate to 3.59 gigawatts (GW).

Although it may seem like common sense, locations where the cost of an outage in terms of business or societal impact are the highest, will make strong candidates The best chance for success may be where an “anchor tenant,” such as a large university, or a dense concentration of critical facilities, already exists or is to be erected. A central plant and distribution system may be more easily expanded to provide energy for nearby unrelated sites than would occur by starting from scratch. Making that plant and its additions resilient may be easier, depending on the dispersal of satellite participants, than creating new utility distribution that is more resilient than existing lines. A large existing central plant may already have access to high pressure gas mains and may be serving buildings with rooftop solar potential. Several such sites are likely to receive grants to further develop their opportunities. So keep an eye out for that ace up the sleeve, as more is revealed about that process.

 

Factoid: Carbon Leakage

Published to LA Confidential, Summer 2016

The lexicon surrounding energy and climate change issues never stops growing. A recent addition is “carbon leakage”, which may occur due to the difference in the strictness of climate policies between two nations. A carbon-heavy industry (e.g., cement production) may seek to cut its operating costs by moving to a country which charges less (or nothing) for greenhouse gas (GHG) emissions. The same thing may happen indirectly where electricity pricing is higher due to efforts to cut carbon from power production. An electric-intensive facility (e.g., aluminum processing) may relocate to a country where power is cheaper due to its lack of emissions controls.

Power Storage Contracts: Clearing Away the Smoke

Published to LA Confidential, Summer 2016

On-site power storage is becoming a realistic possibility. However, as with most opportunities to cut energy costs, the devil may be in the contractual details. If contract terms are not specified clearly, it could be a bunch of hocus pocus.

The cost of battery power (measured in dollars per storable kilowatt-hour, $/kWh) has been rapidly falling. The cost of solar panels has also dropped, making its renewable power competitive, after inclusion of incentives and subsidies. But solar panels only generate power when the sun shines. If some of that power could be stored, it may help trim a building’s peak load and provide off-peak power.

To make that happen, some states or utilities have been offering large financial incentives for batteries. The Demand Management Program (DMP) in New York City (which closed June 1, 2016) gave $2,100 per kW for units providing four hours of continuous power. Similar incentives were offered in California. Amortized across that duration, those rebates essentially covered the base cost of a battery, which is often the biggest ticket item in a power storage system. In both states, expanding use of on-site solar generation and changing power use patterns are creating localized problems that could be addressed by large batteries. Where such programs are available, facility managers are looking at contracts for power storage systems.

Unlike solar power purchasing agreements (PPA) that sell solar kWh over a long term commitment, a power storage agreement (PSA) is essentially an equipment lease. Essentially, you pay a flat fee for use of the device, to perform whatever tasks are desired, and the developer installs and maintains it.

Dollar savings may come from storing either solar or off-peak grid power to use later for:

  • Peak demand and capacity charge reduction
  • Load shifting
  • Demand response programs
  • Emergency backup power

This is an exciting innovation, but as with all contracts, it pays to sweat the details. One developer agreed to install its system and charge a flat monthly fee. For a 375 kW module, the lease payment was $1,000 a month with a 10-year term. Each module stores 1,500 kWh (i.e., four hours of continuous output) per discharge cycle, yielding about $80 per storable kWh. To make that possible, all utility, state, and tax incentives go directly to the developer.

Assuming that the battery is used each weekday to cut peak demand, a total of 375,000 kWh would be stored and released each year. That averages out to $.032 to merely store and recover a kWh. The lease does not guarantee any savings, though (for extra cost) a developer may offer software and services to optimize battery operation, which also does not guarantee any savings.

To ensure savings exceed leasing costs, a facility manager needs to consider several issues:

Quality of output – All claims must be in AC kilowatts, measured at the output of the battery’s inverter, which converts battery DC output to AC. Consistency of power wave form and voltage, power factor, harmonics, etc. should reference the Institute of Electrical and Electronics Engineers (IEEE) specs for power quality. A proviso is needed to address failures to remain within them.

Costs not covered in the lease – As with a backup generator, a battery needs to be integrated with existing electric services: automatic transfer switch, power monitoring, automatic dispatch, security, fire detection and safety (the New York City Fire Department will only allow lithium-ion batteries to be located outdoors), utility interconnection, permitting, inspections, etc. Unless otherwise stated in a contract, all must be paid by the customer.

Monitoring and continuity of output – All batteries degrade over time. Tesla’s Powerwall system, for example, produces full output for only 500 charging cycles. In a commercial building, that would be only ~2 years of useful service. Through what method and at what point is the developer required to replace degraded batteries? How will payment for failed demand reduction, etc. resulting from degradation be quantified and paid to the customer?

Charge/discharge efficiency – Even before degrading, all batteries, and inverters involve losses. A large system may return ~90% of the power it absorbs, but smaller systems may give back only 80%. Where in the contract is the loss rate quantified, or is it built into the kWh output specs? How will such losses be monitored, and if exceeded, will their extra cost be repaid?

Battery disposal – If the developer goes bankrupt, who pays for removal and disposal of the system? Lithium-ion batteries must be disposed of through regulated channels. A module could weigh 10 tons (or more). A disposal bond may be needed.

Required footprint for maintenance and removal – Power storage systems need to be accessed for service and replacement. Floor plans and pathways showing all such requirements should be part of proposal and contract.

Liability – Lessor contractual liability may be quite limited. The lessee (i.e., the customer) may need additional insurance to cover battery leakage, vandalism, theft, etc. If a battery failure results in loss of customer product (e.g., food spoiled during an outage if a battery fails to provide backup power), what is the reimbursement limit?

 

Energy Supply Shenanigans

Published to LA Confidential, Summer 2016

Many new suppliers and brokers have recently entered the field of retail energy procurement. Ensuring the viability and integrity of these new companies is as important as any business agreement you enter. The importance of understanding supply contract details and language cannot be overstated. Verifying the credibility of unknown entities can prevent future troubles.

Here are some scenarios we have recently seen and ways to protect against unforeseen charges and unethical behavior:

  1. A customer signs a floating energy price that then rises due to extreme weather. When a high price is reached in one month (e.g., $.40/kWh), it becomes “stuck” at that level, even after weather has moderated. When a customer complains, a refund is given that is a fraction of the overcharge. Lacking knowledge of how to derive the correct price, the customer reluctantly takes the refund and moves on. If the customer does not complain, this overcharge may continue.

A customer taking floating pricing must know how to access the wholesale data upon which it is based (e.g., posted Day Ahead Market pricing at the grid operator’s website). That access point should be referenced in the supply contract. The supplier should be contractually required to document how a customer’s monthly price is derived.

  1. A broker approaches a client for whom he had previously arranged a power contract with supplier X. The broker’s commission was 1 mil/kWh ($0.001). Later, the broker secures a brokering arrangement with supplier Y that pays him a 3 mil/kWh commission. Due to a drop at the wholesale power market, Y’s contract offers a lower price – even with the higher commission. The broker persuades the customer to switch to Y and terminate his contract with X. He tells the customer there will be a small termination penalty which will be far less than the savings derived from the new, lower price. The broker’s commission then triples. However, once the termination occurs, the customer receives a bill for a hefty penalty. The broker says there must be a mistake, but in the end, leaves the customer to fight it out with supplier X.

When working with a broker, a savvy customer will have a service contract that spells out the actions the broker may take on the customer’s behalf. Such an agreement should include a proviso under which the broker must make the customer financially whole for any action or recommendation that results in a fee or penalty incurred by the customer, unless previously disclosed and quantified in writing by the broker. To be fully covered, the customer should (prior to implementing a broker’s recommendation) secure from the supplier a written statement quantifying any fee or penalty that may result.

  1. A clever broker secures utility account numbers held by customers with whom he has never spoken. The broker takes those numbers to suppliers with whom he has a brokering agreement and claims exclusivity over them. Doing so blocks other brokers (or consultants) from performing procurement services for those accounts because the suppliers decline to provide them with price bids.

To prevent this trick, a customer should provide a Letter of Exclusivity (LOE) to his desired broker or consultant who will include it in any RFP seeking energy pricing.

  1. How do brokers get utility account numbers without a customers’ knowledge? A growing number of cities (e.g., Austin, Chicago, Minneapolis, Philadelphia, New York City, Seattle, San Francisco, and Washington, D.C.) now require annual benchmarking of building energy use. A clever practitioner offers to perform that service at little or no cost if the landlord provides account numbers for the required usage data. He then uses the account numbers or sells them to another broker in order to:
  • Transfer their supply to his desired supplier, thereby securing commissions. This is known as “slamming”
  • Claim exclusivity (item #3 above) with his suppliers in order to block others from providing procurement services for them
  • Use the account numbers to access customer contact information to pitch his services

Customers may safeguard themselves against slamming by having their accounts blocked by their utility. This means that the supply service cannot be transferred without the customer’s written permission (call your utility rep for further instructions). If their landlord must comply with benchmarking requirements, keep accounts confidential by simply providing monthly usage data in a spreadsheet – identified by location – not account number.

  1. A broker claims that there is no fee for procurement services, and that instead, they are paid by the supplier. Of course, the broker’s fee is embedded in the supply price, which is paid by the customer. For full transparency, a customer should insist on disclosure of broker fees within their supply contract.

Conversely, if a broker collects a fee from a customer for procurement services, it is important that the supply contract state that no broker fees are payable. This will prevent unscrupulous brokers from ‘double dipping’.

  1. Some brokers may have a “special” arrangement with a supplier and the broker always steers its client to this same company regardless of the price.

To avoid this, ask the broker for a list of the last three deals they did and identify the supplier and a customer contact. If all three suppliers are the same, suspect the worst and move on.

LuthINformed- Issue 1

Published April 15, 2016

Here at Luthin Associates, we are constantly striving to improve our client services. We all know that there is an incredible range of information available on energy markets – various reports probably hit your inbox on a daily basis.

But making use of all of this information can be challenging – even frustrating – without a solid understanding and a comfort level with it all. We want to help. Every 2 weeks, we’ll be sending you a short discussion on a broad range of energy related topics. In this first issue, we discuss some natural gas fundamentals. Plain English, nuts and bolts kind of of stuff – with links to more info if you’re interested. Future issues will delve deeper, with the goal of illuminating and informing. We’ll do the research and save you time by pointing you in the right direction. Not too often. Not too much. I hope you like it. And of course, your feedback is always welcome…

-Catherine Luthin


Has this ever happened to you? You’re watching CNBC, or surfing the web, and a headline catches your attention: The price of natural gas is, let’s say, $1.97. This seems like a very attractive number. So you call your consultant or supplier for an indicative price. Invariably, the quote you get back is higher – perhaps dramatically higher. What’s going on? Are you being ripped off? Let’s look into what’s really going on…

Natural gas is priced at various locations throughout the country. These locations, or market hubs, are located at the intersection of major pipeline systems. There are over 30 major market hubs, the largest of which is known as the Henry Hub, located in Louisiana. NYMEX futures contracts are Henry Hub contracts, meaning they reflect the price of natural gas for physical delivery at this hub.

In futures markets, there is a separate price for each individual calendar month. Graph each month and the resulting shape is known as “the curve”.  A higher trending futures curve is known as Backwardation – the opposite trend is called Contango. Remember that $1.97 price? Well, it’s almost certainly the cost of the “prompt month”. They may not say so, but that’s how the media reports commodities prices. The prompt month refers to the futures contract that is closest to expiration. (e.g., if the current month is April, the prompt-month contract is May). Three business days prior to the first day of the following month, the current months futures contract expires and a final monthly settlement price is established (chart below). After this settlement date, the next month begins trading.

table 1

To determine your cost per Dth, a supplier multiplies your historical monthly gas usage by the corresponding NYMEX monthly futures price to create a weighted average cost of gas, or WACOG. So unless you’re buying just the prompt month, your NYMEX cost will be different than the number you typically see in the media. This same methodology can be applied to determine your historical cost. The natgas price point will then be the NYMEX settle as opposed to the futures price.

Graph  1.png

As the chart above shows, the largest component of a non-residential natgas price is usually the NYMEX. But there are other costs as well. The NYMEX cost – plus – Basis, Line Loss, Supplier Margin, and any applicable Taxes create an all-in price. Line Loss refers to the cost associated with the amount of gas that leaks from pipelines. And of course, the Energy Supply Company (ESCO) charges a profit Margin. The all-in price is also known as the Citygate price.

Table 3.png

In simplest terms, the cost to transport gas via interstate pipeline from the Henry Hub to your local Utility is known as “Basis”. The cost for basis, just like the NYMEX, is expressed in $ per Dth (or mmBtu). Pipeline volumes fluctuate greatly. Constraints and excess occur to such an extent that basis can be either a positive or negative number. Like the NYMEX, basis will often be weather-driven and is highly correlated to supply and demand dynamics. However, basis is not necessarily correlated to NYMEX prices.

An ESCO is only responsible for gas up to the Citygate – the point at which a utility receives it into its distribution system. It is easy to imagine this point as a “gate” on the outskirts of a city. It is the Utility’s job to then deliver the gas from the Citygate to its final destination at a residence or business. By adding the Citygate unit cost to the Utility unit cost you get the burner tip price.

Of course, many factors affect prices – natural gas is one of the most volatile commodities on the market. Industrial output and accompanying economic swings affects the amount of natural gas needed by all users. During the economic downturn of 2008, industrial natural gas consumption fell by over 7 percent. Despite this, natural gas prices were dramatically higher than current levels – the highest monthly settlement price that year was $13.105 – reached in JULY! Typically, during the summer, domestic production and imported gas can more than meet customer demand, and excess supplies are placed into storage facilities. In the winter, demand for gas generally exceeds production and import capabilities, so withdrawals from storage are used to provide the extra gas needed to meet customer requirements.

Table 4

Every week, the EIA releases an inventory report that gauges natgas supply and demand versus the previous week. This report, released every Thursday at 10:30 a.m., often has an immediate impact on markets. The latest inventory report (above) shows a decline of 3 Bcf vs. the previous week. Stocks were 956 Bcf higher than last year at this time and 849 Bcf above the five-year average. Immediately following the release of the report, the curve moved lower. Traders considered the report bearish for short term prices and the prompt month again dropped below $2.

Table 5

Weather, of course, has a big impact on supply and demand. Gas prices are typically higher in the winter than summer. The chart above shows the correlation between power and natural gas prices and the effects of seasonality (e.g. higher winter and lower summer price trend). Seasonality is a predictable occurrence but, of course, many other variables contribute to natural gas volatility. Economic conditions, speculation and availability of supply are also major contributors to volatility.

Table 6Table 7Table 8.pngTable 9

Both natural gas and power prices are still near historical lows. There are many emails and websites that offer daily market trend analysis and commentary. But for an in-depth discussion on energy markets, purchasing strategies and other topics, call us here at Luthin Associates. Our certified energy managers are always available to discuss any questions you may have.

Luthin Associates : 732-774-0005


DISCLAIMER

Although care has been taken to ensure the accuracy, completeness and reliability of the information provided, Luthin Associates, Inc. (Luthin) assumes no responsibility therefore. The user of the information agrees that the information is subject to change without notice. Luthin assumes no responsibility for the consequences of use of such information, nor for any infringement of third party intellectual property rights which may result from its use. In no event shall Luthin be liable for any direct, indirect, special or incidental damage resulting from, arising out of or in connection with the use of the information.