Energy Procurement Insights for September 2018: See What's Driving Prices in Your Region

Energy markets are complex, and it can be difficult to find useful information to inform the energy procurement strategy for your organization. What you need is detailed information on the factors driving prices in the region where your facilities are located.

Every month, EnerNOC's Energy Intelligence team develops in-depth reports on activity in individual energy markets. Here you can read the highlights for this month and access the full report for each region. Just click on one of the tabs above to jump directly to a specific region.

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New England
Massachusetts Clean Energy Bill Signed Into Law

On August 9, Massachusetts Gov. Charlie Baker signed H.4857, An Act to Advance Clean Energy, into law. The bill emerged as a compromise between the House and Senate on the last day of the legislative session, but in reality, it more closely resembles the House’s proposals, which were significantly more modest than the Senate’s ambitious, omnibus bill, S.2564.

While scaled back, the bill has several important features that will affect wholesale and retail electric markets. Notably, the legislation increases the state’s renewable portfolio standard, establishes the nation’s first clean peak standard (CPS), sets an energy storage target, and authorizes the state to consider doubling its offshore wind procurements.

  • Renewable portfolio standard (RPS) – Retail electric suppliers will be required to purchase an additional 2% of renewable energy annually on behalf of end-use customers beginning 2020 through 2029, up from the current annual RPS growth rate of 1%. By 2030, suppliers will be required to procure 35% of their electricity from renewable Class I resources (wind, solar, small hydro), up from the current RPS mandate of 25%.
  • Clean peak standard (CPS) – Under the CPS, retail electric suppliers serving contracts executed or extended after December 31, 2018 will be required to purchase a “minimum percentage of kilowatt-hour sales to end use customers from clean peak resources.” The mandate draws on the framework of the RPS, but qualifying resources must not only be “clean,” but also deliver energy to the grid during a defined “peak” demand period. The standard is the first of its kind, and aims to increase the use of clean energy during periods of high, carbon-intensive, and expensive demand. It is well known that the CPS is intended to incentivize the deployment of battery storage, but demand response and solar paired with battery storage would also qualify. Details regarding the implementation of the CPS are absent in the legislation. Instead, the legislature granted the Department of Energy Resources (DOER) broad authority to develop program rules, including but not limited to the establishment of a baseline minimum percentage of electricity sales that must be met with clean peak certificates beginning January 2019, the definition of seasonal peak periods, and the methodology by which clean peak certificate values are determined. The DOER is required to promulgate the rules by Dec 31, 2018.
  • Energy storage – The bill looks beyond the state’s 2020 target for energy storage of 200 MWh, and establishes a new target of 1,000 MWh by December 31, 2025. Similar to CPS, the DOER has the broad authority to pursue a variety of policies to achieve the target, such as the refinement of existing procurement methods, the inclusion in renewable portfolio standards, and the use of energy efficiency or alternative compliance credit funds.
  • Offshore wind – The bill doubles the currently authorized amount of offshore wind procurements from 1,600 MW to 3,200 MW. The bill directs the DOER to investigate “the necessity, benefits, and costs” of procuring an additional 1,600 MW on top of the existing 1,600 MW authorized under the 2016 Green Communities Act, and “may require said solicitations and procurements by Dec 31, 2035.” Earlier this summer, the state announced the award of contracts for the first 800 MW of offshore wind to Vineyard Wind, scheduled to start in late 2022.

All electric retail contracts signed or extended prior to January 1, 2019 are exempt from both the increase in incremental RPS compliance obligations and the CPS requirement. With roughly three and a half months left in 2018, an opportunity exists for retail customers to evaluate whether an early contract renewal, which would avoid future RPS incremental and CPS costs, may be in their interests. For more details, please reach out to your EnerNOC Energy Advisor or Account Manager.

For further updates on the power and natural gas markets, read our full report for this month.

New York
Demand Response Impacts Peak Day

Demand response (DR) had an impact on peak load across several days in August, flattening out the load during the afternoon peak hours. The chart below, representing August 29, highlights the potential extent of DR in New York. The projected load without DR (dotted line on the chart) represents what the real-time load would have looked like had it grown at the rate that the Day-Ahead forecast projected. Based on this estimate, it looks like DR trimmed roughly 500 MW from the peak.

One of the benefits of demand response is its impact on real-time prices. By trimming the load, the ISO can avoid using more costly generating units. During the afternoon peak on August 29, from 3PM to 5PM, the Day-Ahead market cleared at an average of $114/MWh, while the Real-Time market cleared near $149/MWh. It is possible that the Real Time prices could have cleared even higher without DR. On August 28, the Real-Time Prices averaged $313/MWh while topping out above $500/MWh versus Day Ahead of $94/MWh, as the ISO did not appear to trim as much load across the peak.

Customers who can curtail load or shift to backup generation or energy storage during these events can directly influence their energy costs for the next capacity year, especially if they are on capacity pass-through product. For customers located in Zones G-J (Lower Hudson Valley, New York City), the impact of managing peak demand can result in significant savings. For those customers in Zone A-F (rest of New York), the impact is much less, as the cost of capacity is roughly 25% of the downstate markets. Those in New York City, meanwhile, could save approximately 6,500 for the upcoming capacity year (next May through April) by reducing their capacity tag by 100 kW.

For further updates on the power and natural gas markets, read our full report for this month.

Mid-Atlantic
FERC Allows Delay to Upcoming PJM Capacity Base Residual Auction

On August 30, FERC granted PJM’s request to push back the upcoming Base Residual Auction (BRA) for Capacity year 2022-23. The auction was originally slated to open May 13, 2019, but no resolution surrounding Capacity Market Reform has been reached between PJM and FERC.

Capacity Market Reform was initially proposed due to state subsidies providing extra revenue to in-state nuclear and renewable generation. These incentives create an unfair advantage for certain types of generation and act against true economic capacity market pricing, where all generation assets are treated and paid the same. Proponents to this issue claim that because nuclear and renewable generation assets receive other revenue streams outside of the capacity market, they can potentially offer lower bids into the BRA, lowering the overall capacity clearing price. 

FERC has denied two of PJM’s proposals for Capacity Market Reform, one which would hold a two-part capacity auction including and excluding state-subsidized capacity resources, and the other which would create a price floor for capacity resources. PJM is currently working on a solution and moved the 2022-23 Base Residual Auction to August 14 to August 28, 2019.

For further updates on the power and natural gas markets, read our full report for this month.

Midwest
FirstEnergy Plans Retirement of Additional 4GW of Generation in OH and PA

In March of this year, FirstEnergy announced the planned retirement of three nuclear facilities in Ohio and Pennsylvania totaling 4,048 MW of capacity.

In the last week of August, FirstEnergy announced additional planned retirements, this time three coal and oil generators totaling 4,004 MW of capacity. The newest announcements bring the total planned retirements to 8,052 MW, of which 6,180 MW is located in PJM’s ATSI zone in northern Ohio. In the current environment, FirstEnergy’s planned retirements of these nuclear and coal facilities will likely drive up capacity prices in the 2022/2023 capacity year.

The story of nuclear and coal subsidies continues to unfold in Ohio. Over the last year, at-risk nuclear and coal generators have lobbied state and federal lawmakers in an effort to enact subsidies to keep the uneconomic plants open. The arguments have centered on what generators claim is a market failure to price in the added “resilience” of on-site fuel storage they provide to the grid. While some states have enacted subsidies to support these at-risk generators, passing the cost directly onto customers, the Ohio legislature declined to pass a similar bill last year. The estimated cost to end users in Ohio was approximately a 5% increase to their electricity bill. As a result, FirstEnergy has announced retirements of the six generation facilities below.

The majority of the retirements are slated to occur in the 2022/2023 capacity year and are located in PJM’s ATSI zone in northern Ohio. FirstEnergy has requested that PJM exempt these generators from the 2022/2023 capacity auction. In its public statement, FirstEnergy left open the possibility of keeping the facilities online, stating that “Depending on the timing of any federal policy action, deactivation decisions could be reversed or postponed.” The outcome will likely depend on decisions made by FERC on the structure of the 2022/2023 capacity auction, which is covered in our commentary for the Mid-Atlantic market for this month.

In the current environment, customers located in northern Ohio, PJM’s ATSI zone, should expect increases in the 2022/2023 capacity auction clearing prices. Uncertainly around the outcome of these generators and the impact on retail electricity prices is likely to persist for some time as state and federal lawmakers debate the issue of nuclear and coal subsidies. If events unfold in their current form and capacity prices do increase, it would be prudent for customers who can manage their capacity tags to do so in the summers ahead of any upcoming contracts extending beyond May 2021.

For further updates on the power and natural gas markets, read our full report for this month.

Texas
August Demand Failed to Meet Expectations

August in ERCOT has traditionally been the litmus test for the grid as the dog days of summer push the grid to its limits. Initially, this year appeared no different. ERCOT set expectations for high demand due to a weaker-than-average hurricane season and growing demand in the state. The pre-summer outlook boasted a forecasted August peak of 72,974 MW, which stood out by itself, but appeared timid after July’s peak of 73,259 MW. The vaunted demand never materialized.

August in ERCOT left without breaking the 70,000 MW level, maxing out at 69,846 MW on the 23rd. Aside from some incidental hours of high LMPs, August pricing was more or less in line with historical averages. North Hub Day-Ahead ATC LMPs averaged $31.60/MWh, $4.77/MWh above August 2017, and $1.77/MWh above August 2016. Forward power pricing remained flat largely due to unknowns surrounding supply of future natural gas in the region rather than questions about the resilience of the grid. Basis pricing at Houston Ship Channel moved up considerably over the course of the month (see graph on page 3).

Concerns about the grid will fade as we enter the shoulder season. The Fall 2018 Seasonal Assessment of Resource Adequacy (SARA) released by ERCOT on August 6 forecasts a wide moat of available capacity over the upcoming months. ERCOT is expecting the planned mothball of a 470 MW coal unit in October and delays in 300 MW worth of wind generation, but still expects roughly 5,000 MW of excess capacity due to the lower demand expectations. Natural gas production at Permian has ramped up year-on-year, but the vast majority of this has gone to increased demand for export to Mexico or via LNG. Basis across the state has moved little or upward, which has kept forward implied heat rates at elevated levels. Due to the supply/demand dynamics of the region, we expect this elevated regional pricing pattern to hold over the next several weeks barring a demand shock.

For further updates on the power and natural gas markets, read our full report for this month.

California
CAISO Disputes Independent Generators Complaint to FERC

CXA La Paloma, a 1,124 MW natural gas power plant in McKittrick, CA, has filed an official complaint to the Federal Energy Regulatory Commission (FERC) against the California Independent System Operator (CAISO).

La Paloma and other generators are claiming the state’s ambitious green energy policy is running traditional resources out of business. They stated that the temporary mechanisms to sustain Resource Adequacy remains unjust and unreasonable, as existing resources are not being justly paid for providing capacity or have the ability to recoup operating costs. Due a patchwork approach for Resource Adequacy, newer, more efficient generators have been forced to retire. These generators claim that as California increase its reliance on renewable energy sources, current resources will not be able to cover costs and will therefore be required to enter Reliability-Must-Run contracts, costing end users more in the long run. 

La Polama has requested that FERC order CAISO to construct a centralized resource adequacy procurement process that includes a downward sloping demand curve along with uniform locational pricing. They are also requesting a payment system from CAISO to compensate them fairly for the capacity they provide. Included in their complaint is a proposal for CAISO to be required to implement a forward, multi-year capacity market similar to PJM and ISONE. This would allow for transparent pricing that can take into account ongoing resource changes. As currently constructed, PJM and ISONE employ a forward-looking three-year capacity market. 

CAISO issued a response urging the federal regulators to reject the proposal of implementing a forward-looking capacity market. They warned that a formalized central capacity market would hinder the progress of renewable energy adoption and conflict with the state’s environmental laws and policies. CAISO states that it has successfully maintained grid reliability under the state’s Resource Adequacy program through bilateral transactions with generators. CAISO also claims that adopting a capacity market similar to PJM or ISONE would subject California customers to the same challenges that have emerged in those two regions. In March 2018, FERC approved a two-part capacity auction in ISONE to assist with handling renewable and nuclear resources. FERC ordered changes to PJM’s capacity market stating that state policies were depressing auction prices.

Customers with immediate needs to sign a power or gas contract should look to sign short-term agreements. Market prices are being heavily influenced by the near-term weather events and we expect prices to rebound lower over the next several weeks as moderating seasonal weather patterns return.

For further updates on the power and natural gas markets, read our full report for this month.

Mexico
Without a Forward Market, Suppliers Careful to Take On Risk

In January 2016, after the Mexican electricity market officially deregulated, the independent system operator, CENACE, began publishing Day Ahead prices. About 14 months later, CENACE began releasing Real Time pricing. What has still yet to develop in the country are forward markets for both electricity and natural gas. Suppliers, therefore, are not able to go out to a market to purchase a future block of power to hedge against a contract that they offer to a customer. They are bearing the market risk and will have to purchase power for their customers at the market rate, with little forward insight into what those prices may be. Also, with the market in its infancy, many supplier books are still relatively small. They are therefore spreading risk out across fewer customers and smaller total load. An unexpected spike in consumption at just a couple of locations in their portfolio can expose suppliers to significant market risk.

Customers familiar with energy procurement in the United States are accustomed to “fully-fixed” energy price contracts in which they are guaranteed a known price provided their consumption stays within a fairly generous band compared to their prior year’s consumption pattern. This “bandwidth” is calculated against monthly totals and is typically offered between 25% and 100%. Given these parameters, customers rarely have to worry about their consumption patterns and can be confident that the price on their contract will be the price that they pay. In Mexico, bandwidth provisions look very different.

Because of the unique risks suppliers face in the current market, bandwidth parameters are far narrower, making it much more likely for customers in Mexico to exceed them. Suppliers may offer bandwidth as low as 3%, with few offering more than 5% unless at a very high premium. Further, the band is typically calculated on an hourly basis compared against a customer-supplied consumption profile, as opposed to monthly totals. For example, if a customer expects to consume 500 kW at 1 pm on a given day, a 5% bandwidth would allow for just a 25 kW deviation before additional settlements must be considered. Customers, therefore, are taking on more of the risk than in other markets. Let’s say that the customer in this example uses 600 kW at 1 pm. The customer would pay their contracted rate for 525 kW, but now has an exposure of 75 kW. The customer will have to buy that power at the real-time market price, which can be higher or lower than the contract price, but is generally higher on average. In certain cases, suppliers may charge an additional fee for procuring that additional usage on the customer’s behalf.

Customers should consider bandwidth carefully when comparing third-party supply contracts. The key details to look for include the percentage of the band (e.g. 5%), the granularity of the measurement (e.g. hourly v. monthly), the settlement process, and any potential fees or charges associated with over- or under-consumption. Customers should also consider how accurately they will be able to forecast their consumption profiles. A customer with a fairly predictable and stable load profile may be willing to take a lower bandwidth contract in exchange for a lower price, whereas a customer with a highly unpredictable load or the inability to provide suppliers with an accurate load forecast may need to pay more for higher bandwidth. Until the market matures and suppliers are able to more confidently hedge their customer positions, customers will continue to bear significant market risk.

For further updates on the power and natural gas markets, read our full report for this month.

Henry Hub
Pace of Demand Growth likely to Dictate Market Balance for the next 12 Months

2018 has been pivotal for both sides of the fundamental economic equation of supply and demand for natural gas. The balance between supply and demand is the primary driver impacting short and long-term natural gas pricing. In recent editions of this commentary, we reported on the supply growth over the past decade (August 2018 Nat Gas Commentary). The supply boom from the Marcellus shale led to the gas pipeline infrastructure explosion in 2018, with around 11 Bcf/day of new transportation capacity expected to be operational by December 31, 2018.  However, prices have remained stable instead of sharp decreases in NYMEX pricing. The main driver for the relative stability is the growth in demand meeting the growth in supply. The article below aims to analyze the growth of each component of natural gas demand.

The six components of gas demand are power burn, industrial, residential/commercial, pipe loss, net exports to Mexico, and LNG feed-gas. 2018 was a breakout year for demand, with all consumption components posting year-over-year growth versus the previous two years. All signs point to demand growth continuing at a record pace.

Production has deservedly dominated the headlines for several years, and demand needs to continue to grow in-kind to keep the market balanced and spur enduring production growth into the next decade. If demand growth falls behind production growth, customers will likely see 12-month rolling strip NYMEX pricing drop to around $2.60/MMBtu. Demand growth above expectations for the rest of 2018 may push the natural gas 12-month rolling strip price above $3.00/MMBtu for the first time since late January 2018. The final third of 2018 is underway, and demand is continuing to respond with growth above previous expectations. The higher-than-expected consumption is the cause for elevated near-term NYMEX pricing compared to 2020-2022 pricing, also known as backwardation. Customers continue to favor longer-term gas supply contracts as a result of the backwardation. The lower-priced long-term deals will likely remain the lowest price option for gas supply.

Natural Gas Demand Components:

1. Power generation

Power generation has led the way for the growth in demand throughout 2018, and the trend is likely to continue for the next few years. Since 2014, there have been 2.7 GW of new gas-fired generation put into place in the Midwest alone. During that same period, an estimated 10.3 GW of coal capacity was taken offline in the region, according to S&P Global. Based on these statistics, natural gas consumption for power generation will continue to grow leaps and bounds over the next several years.

Customers with facilities near the Chicago, MichCon, and Ventura market areas have seen basis prices rally significantly since the start of summer 2018. Storage in the Midwest started the season well behind the five-year average and was unable to make up any ground, which put upward pressure on Midwest basis prices. A 10-year low in regional storage is likely to start winter 2018/19. Despite the increase in gas deliveries, the factors listed above are providing a tight market balance between supply and demand in the region. Customers are utilizing the low-price NYMEX futures to fix pricing at a relatively low unit cost.

2. Industrial

Industrial growth since the start of 2016 has been steady, with nearly 6% growth in 2018 versus 2016. A primary driving factor for the resurgence of industrial demand is the low cost of energy, particularly natural gas. The sustained low gas prices and a backwardated natural gas forward market offer cost stability for several years. Industrial demand is likely to continue at a moderate growth pace. 

3. Residential/Commercial

As natural gas has become more abundant, many utilities have increased their usage through system expansion or conversion from other fuels. Residential/commercial consumption growth since the start of 2016 is just over 7% in 2018 versus 2016. The consumption of the residential/commercial sector is closely tied to the weather and, therefore, is difficult to predict from year-to-year. 

4. Pipeline Loss

Pipeline loss is the loss of pressure that occurs in pipeline flow due to the effect of the fluid's viscosity near the surface of the pipe. Based on the growth in the amount of natural gas transported via pipelines, it is certain that gross losses will grow in proportion with both supply and demand levels. 2018 pipeline loss is 4.6% above 2016 levels. 

5. Net Exports to Mexico

Exports to Mexico rely heavily upon the maturation of the Mexican energy market. As a nation, from January 1, 2016, to August 31, 2018, Mexico has increased its reliance on natural gas from around 3.6 Bcf/day to just around 4.6 Bcf/day, a growth rate of around 28%. The maturation of the Mexican market will play a crucial role in demand growth in the next 3-5 years, as rapid export growth is expected to continue. 

6. LNG Feed-Gas

LNG feed-gas averaged just below 3.3 Bcf/day in August 2018 and 3.5 Bcf/day from January 1, 2018, to August 31, 2018. The year-to-date level represents a jump of 2.7 Bcf/day or 558% for the same period in 2016. Exports of LNG are expected to nearly triple in the next 12-months based on estimates from Blue Quadrant Capital Management. According to the firm, exports would make up around 10% of total demand by 2020. Currently, exports make up around 1.5% of total demand according to EIA data. Despite the continuance of demand growth, exports will gain a meaningful share of total demand in the next two years.

For further updates on the natural gas market, read our full report for this month.

Authored By The EnerNOC Energy Intelligence Team

The Energy Intelligence team provides talent and knowledge to our customers by making the complexity of energy management simple.

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