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Hedging Fuel Deliverability Risks in Today’s Regulatory Environment

Smart Strategies for Managing Exposure Created by Capacity Performance Rules

Smart Strategies for Managing Exposure Created by Capacity Performance Rules

BY MICHAEL DUCKER

Owners and developers of gas projects in the Northeast are faced with an increasing need to ensure reliable delivery of energy. As coal plants continue to retire and regions move to an ever-increasing reliance on natural gas, concerns on the dependence of this fuel source have surfaced. As such, new market rules in the PJM and the New England ISO are placing unprecedented value on ensuring reliability in gas turbine products and natural gas fuel delivery.

There are a wide range of fuel-delivery hedging mechanisms, including firm transport, back-up fuel, or even simply taking market risk. Each potential solution offers benefits and risks that need to be carefully weighed, and it’s important for customers to engage in a meaningful dialogue internally and with their OEM about options that exist.

Ultimately, this analysis points to first ensuring that reliable gas turbine products are selected. Thereafter, a hedging strategy for fuel delivery ought to be considered, and this analysis shows strong benefits of choosing a newly emerging business model of on-site LNG to comply with these new market rules.

Background

With an abundance of natural gas at historically low prices, environmental regulations targeting coal, and coal and nuclear plants struggling to remain profitable in competitive power markets, many regions are seeing a dramatic shift towards a greater reliance on natural gas generation. This shift is clear, particularly in the mid-atlantic region of PJM and northeast region of the New England ISO. In 2000, natural gas accounted for just 3% of generation in PJM and 24% of generation in ISO-NE. Today, natural gas comprises more than ¼ of PJM’s energy generation and more than ½ of ISO-NE’s energy generation.

Yet as regions experience a greater reliance on this clean and affordable energy resource, reliability issues have surfaced when delivery of that fuel source is unavailable. Although coal and nuclear plants may have several months to a near endless supply of fuel on-site, if a fuel supply disruption occurs to a natural gas plant, there is typically no natural gas stored on-site to continue operation. Natural gas power plants tend to be an “on demand” generator, meaning when the plant needs to operate then the fuel must be available. When that fuel is not available, and there is no back-up fuel to supply the plant, problems can arise. This was evident during the Polar Vortex in 2014 which saw record low temperatures across most of the U.S. and brought much of the Northeast to a near blackout condition. This grid “near miss” caused PJM and ISO-NE to issue tighter market rules to address reliability.

The Polar Vortex

The 2014 Polar Vortex was the kind of market event that causes a fundamental shift in regulatory oversight. This event became the center of attention for the new market rules in the Northeast due to its disruptive effects on the grid.

During the extremely cold weather of the Polar Vortex natural gas demand for residential heating competed with natural gas demand for power generation. Local distribution companies (LDCs) have a priority for natural gas for utilization within citygates, thus natural gas supplies for power plants are typically secondary and interruptible. The extremely cold weather strained these fuel supplies as natural gas was diverted almost entirely to LDCs, and many natural gas power plants simply could not operate because fuel was unavailable. At the same time the cold weather caused a multitude of other problems for power plants, including frozen stockpiles of coal, ice damage to equipment, combustion-related issues and other problems. What materialized in 2014 was more than 40,000 MW of forced outages, comprising nearly a quarter of PJM’s entire fleet. Nearly half of the outages were due to natural gas plant outages or natural gas fuel interruptions.

With such a large portion of the fleet in a forced outage and 50 percent natural gas-related, PJM moved towards implementing market rule changes to ensure such reliability issues would not occur again.

New Market Rule Overview

In 2014, PJM proposed restructuring their forward capacity market, known as the Reliability Pricing Model (RPM), to include a “Capacity Performance” (CP) component. CP requires generators to provide energy, if scheduled and dispatched by PJM, during Compliance Hours. Compliance Hours take place when PJM declares an emergency procedure event. All generators are obligated to provide their pro-rata share of energy during Compliance Hours. When a generator fails to deliver its pro-rata share of energy during a compliance event it is required to pay a Performance Payment. Performance Payments are collected as penalties from underperforming generators and delivered as bonuses to over-performing generators. Generators performing at their expected output can also earn a percentage of these bonuses, approximately 15 percent of their total capacity.

The performance payment is based on the generator’s committed output and is a function of the cost of new entry and PJM’s expected Compliance Hours.

When PJM promulgated its rule it estimated approximately 30 Compliance Hours per year, setting this baseline to calculate the performance payment. This number is currently under contention amongst PJM stakeholders because – aside from the Polar Vortex of 2014 – a historical look at trigger events yields only an annual average of 10-15 Compliance Hours. That would make the current PJM performance payment rate seemingly “too low.” For now the PJM’s projected annual 30 Compliance Hours sets the performance payment at approximately $3,400/MWh.

The performance payment means generators are exposed to a $3,400/MWh penalty or bonus during compliance events. To put it into perspective, if a combined cycle with 1,000 MW of output committed suffers a forced outage, and during the outage PJM declares a four-hour compliance event, this unit would face a penalty of $13.6 million. This is in addition to other losses the plant will incur, such as buying replacement power at real-time market prices, deviation charges assessed by PJM for not following day-ahead dispatch signals, and a higher assessed forced outage rating which will affect future capacity market payments. By any business standards, the performance payment represents a very severe penalty for a generator undergoing a four hour forced outage.

As such, the CP market rules mandate power producers focus on the reliability of gas turbine products and fuel deliverability. Failing to do so could have a crushing impact on profits.

Overview of Fuel Delivery Hedging Solutions

Mitsubishi Hitachi Power Systems (MHPS) conducted an analysis of four different hedging solutions: firm transport, fuel oil back-up, on-site LNG back-up and market risk. The analysis provides Northeast plant owners with an overview of each solution. While each solution will appeal to different plant owners for different reasons, we believe some options hold greater promise as hedging tools for most plant owners.

Firm Transportation

One of the biggest contributors to supply issues experienced during the Polar Vortex was interruptible service contracts for existing gas-fired power plants. In order to maintain competiveness in the markets, most existing gas-fired plants utilize interruptible service contracts which avoid costly reservation charges. Since peak demand for gas-fired generation typically occurs in the summer – when residential demand, local distribution companies and other firm transport holders are at their minimum usage – the need to pay a premium for firm transportation was not justified in most cases.

Moving forward, some market segments may consider firm transport and paying fixed reservation charges to guarantee the delivery of gas to the site. This is especially evident in the baseloaded, high efficiency NGCCs being developed today. By undertaking a firm transport service contract, gas-fired generators will alleviate the risks of having a fuel supply interruption during a critical grid event. This is a viable hedging strategy to avoid CP penalties.

The cost of firm transport contracts will vary greatly within regions, contracting entities, end-use customer needs, etc. While the viability and costs can differ significantly, there is public information on these reservation charges. From publically available sources, recent reservation charges have ranged from $0.30/MMBtu more than $1.00/MMBtu. We chose a lower of the average of $0.50/MMBtu for analysis purposes.

Fuel Oil

Fuel oil has been the defacto “back-up” fuel for most plants. Although not the most desirable back-up fuel, it has historically been the most cost effective. When discussing fuel oil with plant operators, there is often a litany of potential issues identified with this solution:

  • Fouling of equipment
  • O&M adders assessed by GT OEMs for utilizing the fuel source
  • Reliability issues when running or starting on fuel oil
  • A large majority of PJM issues during the Polar Vortex occurred with plants failing to start or switchover to fuel oil
  • Even if a plant is backed with fuel oil, the fuel has a proven negative reliability record
  • Emissions issues
  • Local opposition to fuel oil operation
  • Additional water usage during operation
  • Maintenance of fuel oil storage tanks
  • Turnover of tanks
  • Quarterly/periodic testing requirements
  • Fuel oil pricing spikes during cold weather events (in some cases cannot refill until end of winter)
  • Spills/environmental concerns due to clogged lines

While many plant owners are considering adding fuel oil to new or existing gas-fired plants as a CP hedge, many express less than favorable interest in using fuel oil for the aforementioned reasons.

Still, when comparing fuel oil to firm transport cost, or other site conditions that necessitate a back-up fuel, it can be a cost effective option. For purposes of this analysis, we are assuming a 550 MW plant, greenfield site, with a 3-day fuel oil storage tank solution. We have assumed no duct firing and no derate on oil operation, which would net an initial capital cost of more than $26 million to go with fuel oil as the plant back-up fuel. See Table 1 on page 20 for fuel oil cost assumptions.

On-site LNG

On-site LNG often receives less consideration as a back-up fuel option. Historically, LNG has been an expensive commodity. Building the infrastructure to utilize it as an on-site back-up fuel added additional capital costs and permitting issues, while only achieving a moderate amount of back-up time before supplies would be depleted.

However, as owners look towards hedging CP compliance – which are likely short duration events – the notion of

on-site LNG as a back-up fuel immediately gains more credibility. Moreover, new companies are emerging offering full on-site LNG packaged solutions, including options such as a fixed long-term contract with a yearly demand fee, that includes the LNG provider handling the initial capital costs, construction, permitting and long-term O&M. These agreements can include guaranteed fuel delivery periods within PJM and ISO-NE, guarantee refill on grid “disaster days,” and fixed fuel costs. This is an attractive option for developers looking to reduce upfront capital costs, while still hedging for CP uncertainties.

Other benefits of on-site LNG include:

  • Utilizing the primary fuel that gas turbines were designed for
  • Emissions are the same as the site permit on pipeline natural gas
  • Better emissions than fuel oil
  • No GT/HRSG O&M impacts
  • Less water usage
  • Minimal footprint impact, including retrofitting this solution on existing plants

Two ancillary benefits worth stressing on the use of on-site LNG include:

  1. The ability to blend LNG with pipeline gas to boost pressures in the event of a gas pipeline/gas compressor pressure anomaly, avoiding a costly gas turbine trip.
  2. Compared to fuel oil as a back-up fuel, on-site LNG enables the plant owner to fully utilize their duct-fired capacity (if installed), thus maximizing bonus capabilities while minimizing risk exposure during CP events.

For purposes of this analysis, we are assuming a 550 MW plant, greenfield site, with a 32 hour storage tank solution (~100,000 decatherms). No duct firing is considered. This option results in a $2.1 million yearly cost for CP back-up. See Table 2 on page 21 for on-site LNG assumptions.

Fuel Delivery Risk

Owners certainly have the option of simply taking the market risk that fuel will be available when needed. PJM historical compliance events – with the exception of 2014 – all occurred in the summer months. Thus, some owners can certainly justify a limited risk of fuel interruption during summer months when competing needs for gas are minimal.

Of course if there is never a fuel interruption during a compliance event, this will be the cheapest option. But it also comes with the greatest potential risk. A single interruption during a compliance event could eradicate any savings from another solution.

Other Products

There is a growing interest in the insurance community to offer products to protect against CP events. However, as with any insurance product, there are vast amounts of coverages that can be pursued as well as a wide range of premiums for the same products at different end-users. For that reason, and due to the limited information on these emerging products, these options were not included as part of our analysis.

Solution Analysis

For this analysis, MHPS based its review on an owner building a greenfield JAC combined cycle power plant. The

MHPS JAC turbine was recently launched and is the world’s most efficient gas turbine at over 63 percent efficiency. For competitive power markets like PJM and ISO-NE, the need to be efficient – even in a low cost gas environment – is critical in order to dispatch ahead of other units and increase operating hours. The MHPS JAC is a good proxy for the types of units that will be built in the future in these markets reflecting the move towards advanced class, high efficiency gas turbines. The key performance specifications of the JAC combined cycle utilized in this analysis are listed in Table 3 on page 21.

In compiling key market assumptions for the fuel-hedging analysis, four scenarios were specifically chosen for several reasons. (1) historically, total compliance events have averaged ~10 hours per year with the exception of 2014; (2) compliance events have typically been in the summer when fuel is available and interruptions are less likely; (3) the maximum single duration event occurred during the Polar Vortex in 2014 and we believe this would be representative of a “worst case” single loss of fuel contingency event. The key assumptions for this analysis is outlined in Table 4 on page 22.

The results in Figure 3 on page 22 illustrate the total cost in net present value for the four solutions. A NPV analysis is necessary since some solutions require upfront capital costs while others require ongoing yearly fees. To provide a true comparison, a simple yearly review of costs would not be accurate.

In reviewing the results, with the exception of once case, the on-site LNG solution results in the lowest cost option of all four solutions. It represents nearly half the cost of the fuel oil option and one sixth the cost of firm transport. Although the storage limits back-up fuel available to 32 hours, it would seem for CP applications that this amount of storage is very reasonable and would even hedge against a “worst case” Polar Vortex-type of event. Moreover, it comes with ancillary benefits without additional environmental, maintenance, or reliability concerns.

Sensitivity

As a final review of the options, it is prudent to consider under what conditions firm transport or fuel oil will be the most economical solution. Figure 4 on page 24 shows a sensitivity study of the total cost of the firm transport solution under varying reservation fees and the sensitivity of the total cost of fuel oil under varying initial capital costs. Holding the other assumptions constant, firm transport becomes an economically viable solution when reservation fees are in the range of $0.10-0.15/MMBtu. Meanwhile, fuel oil becomes economically viable – assuming a scenario of a 4 hour/year event – when initial capital costs are <$15M.

As for the viability of these scenarios occurring, for firm transport it will be contingent on owners leveraging conditions that enable firm transport costs at such levels. For fuel oil, the scenario of <$15M initial capital cost could certainly materialize if an existing site already has fuel oil storage.

Some brownfield sites have tanks or a new site may be in close enough proximity to other projects that have fuel oil storage on-site. Under these conditions, initial capital costs would be minimal and likely would be <$15M thus making fuel oil an economically viable solution.

Conclusions

As a first line of defense against potential CP issues, owners and developers of gas projects in the Northeast must select reliable gas turbine products. Using the most reliable gas turbine products will help power producers reap the benefits of bonuses during contingency events and mitigate major losses due to forced outages. The reliable delivery of fuel to the site is a critical factor and, if fuel cannot be delivered, owners and developers must consider a wide range of hedging mechanisms.

This analysis seems to make it clear that on-site LNG is an economically viable solution in the context of new market rules in PJM and ISO-NE. Given the short-term nature of these events, but critical need to be hedged, on-site LNG appears to have strong merit. Further, the minimal impacts this solution has on emissions, O&M costs and plant integration, along with the ancillary benefits LNG provides in the event of pipeline/gas compressor pressure fluctuations, make it a very attractive solution.

The emphasis on Capacity Performance is likely to increase and there is a potential for the rules to expand into other regions as natural gas becomes a primary feedstock for power generation throughout the United States. Energy producers need strategies to be fully hedged through a combination of reliable gas turbine equipment and selecting a back-up fuel solution that best meets their needs.

Author: Michael Ducker is the director of Market Analysis at Mitsubishi Hitachi Power Systems Americas based in Orlando, FL.

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