Energy Procurement Insights for September 2017: 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, Enel X'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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On August 11, the Massachusetts Department of Environmental Protection (MassDEP) published six new regulations to reduce CO2 emissions from power plants in Massachusetts. One of these regulations, the "310 CMR 7.75 Clean Energy Standard" (CES), requires utilities and competitive suppliers of electricity to procure increasing amounts of clean energy in a similar manner to the Massachusetts Renewable Portfolio Standard (RPS). This regulation is designed to help ensure compliance with the Global Warming Solutions Act (GWSA), which requires Massachusetts to achieve a 25% reduction in greenhouse gas (GHG) emissions statewide below 1990 levels by 2020, and additional reductions of at least 80% below 1990 levels by 2050.
The CES sets a minimum percentage of electricity sales that utilities and competitive suppliers must procure from clean energy sources, beginning at 16% in 2018 and increasing 2% annually to 80% by 2050. Previously, under the Renewable Portfolio Standard (RPS), suppliers were obligated to procure 13% of their power from Class I resources in 2018, and an additional 1% annually thereafter. The regulation states that RPS Class I compliance counts towards the CES mandate. Thus, compared to the current RPS class I requirements, the CES represents an increase of 3% in 2018, 4% in 2019, 5% in 2020, etc. As shown below, by 2050, the CES represents an increase of 35% compared to the current RPS Class I standards.
Customers with existing supply contracts which were signed before August 11, 2017, will be grandfathered into the program, and will not be subject to the CES for calendar years 2018 and 2019. However, any new supply contracts signed after that date will be subject to the incremental costs associated with the CES program.
Over the next three years, based on current REC prices, Enel X estimates that the CES program will result in added costs of roughly $0.0007/kWh in 2018, $0.001/kWh in 2019, and $0.0011/kWh in 2020. With renewable costs accounting for a growing share of customers’ retail costs in Massachusetts, effective wholesale market timing and contract management is becoming increasingly vital to keeping costs low.
For updates on electricity and natural gas prices, check out our full report for this month.
A project that would deliver natural gas to the new 650 MW CPV Valley Energy Center has been denied a water quality permit by the New York State Department of Environmental Conservation (NYSDEC). This now marks the third time in recent history that the state has delayed natural gas projects by denying critical environmental permits even after the projects received approval from the Federal Energy Regulatory Commission (FERC).
The NYSDEC, in its decision, cited an incomplete environmental evaluation by FERC, but did not point to any specific environmental violations. The ruling echoes the NYSDEC’s April decision to deny permits necessary for the Northern Access Pipeline, as well as a similar decision to deny permits for the Constitution Pipeline a year prior.
The project, known as the "Valley Lateral Project," would run 7.8 miles and would deliver 130 MMcf/day of natural gas from the Millennium Pipeline to the site of the new combined-cycle gas plant.
The plant is currently expected to come online in early 2018. However, without a natural gas connection, the plant will only be able to generate power by burning fuel oil, which, due to emissions standards, drastically reduces the run times that the plant can operate. It also requires the cost of natural gas to climb drastically to for it to make financial sense for the plant to generate power while running on fuel oil.
Competitive Power Ventures (CPV), the company developing the plant, has expressed disappointment in the state’s decision, but has not changed the plant’s operational start date. CPV still believes that FERC will override the state’s decision and that the plant will ultimately have its lateral pipeline project completed.
While the CPV Valley Energy Center is not currently critical for grid reliability, it could be in coming years. In 2020 the 2,083 MW nuclear plant, Indian Point, located in the Lower Hudson Valley, is scheduled to begin its closure, and is expected to be fully offline by April 2021. While Governor Andrew Cuomo has said he would like to replace the capacity with renewable energy, most of the state’s wind and solar generation is located upstate. NYISO has estimated that in order for Indian Point to be replaced by upstate renewables, the grid would require approximately 1,000 miles of new high-voltage transmission lines to deliver the energy from its source to the densely-populated downstate region. Many believe that a much more likely scenario is that Indian point will be replaced by new natural gas-fired plants, like the CPV Valley Plant and the planned 1,070 MW Cricket Valley Plant, which is expected to come online in 2019. However, the state’s pattern of delaying natural gas projects does cause concern as the closure of Indian Point draws near without any natural gas generation online to replace it.
If FERC decides to overrule the state’s decision and grant a notice to proceed, it is estimated to take three to four months for the pipeline to be built and another month to equip the plant to run on natural gas. FERC, however, only recently restored its quorum in Mid-August, and faces a large backlog of cases to rule on. If delays to the Valley Lateral Project appear to push back the CPV Valley Plant’s start date to burn gas beyond April 2020, it will likely cause energy futures to spike for customers in the Lower Hudson Valley and New York City. It would also likely result in higher capacity pricing beginning in May 2020.
For updates on electricity and natural gas prices, check out our full report for this month.
Day Ahead pricing at Western Hub has remained low and stable through the first eight months of the year, avoiding the winter and summer spikes that have historically impacted the region. This is the second straight year the region has avoided such spikes, indicating that the PJM region is better capable of handling demand shocks through low natural gas prices and a more diverse generational mix.
Historic lows for each month have been set within the past 24 months. With new, more efficient generation resources and additional renewable resources expected to replace retiring coal plants, this trend should be expected to continue for the foreseeable future.
One illustration of this change is the recent coupling of the Western Hub Heat Rate with power prices. The natural gas heat rate is the measure of generator efficiency of converting natural gas into electricity. Traditionally, the heat rate has not had a direct relationship with power prices in the PJM Western Hub, meaning power prices could increase even as gas prices fell. With the growth of natural gas generation and an increased dependence on the fuel as a marginal resource, the heat rate has lowered in tandem with regional LMPs. This effect is buoyed by renewable generation growth, which accounts for roughly 6% of the on-peak fuel mix in PJM. These additional "price taker" resources allow more efficient natural gas resources to act as the marginal units. We expect this relationship to continue as robust natural gas production and continued renewable generation creation will place downward pressure on the heat rate, keeping LMPs low and stable.
For further updates on electricity and natural gas prices, read our full report for this month.
Public Act 341 (PA 341), which went into effect in April, requires Load Serving Entities (LSEs)—including utilities and suppliers—to demonstrate four years of forward capacity. While the ruling is not certain, as there are more details to be worked out, there are several issues customers need to be aware of before going to market.
PA 341 was intended to address concerns regarding the state’s anticipated generation shortfall, after legislators and utilities argued that local generation may not be able to maintain grid stability in a few years, and that utilities were at a disadvantage to Alternative Energy Suppliers who could offer less expensive capacity procured via MISO auction. Early versions of Act 341 included a stipulation, known as the Locational Clearing Requirement (LCR), requiring LSEs to purchase from generation located in the Lower Peninsula. The Michigan Public Service Commission (MPSC) is expected to finalize the path going forward by September 28.
The heart of the issue for competitive supply rests in the LCR and timing. The current expectation is that suppliers will need to demonstrate that they have four years of contracted capacity to comply with the ruling, and that there will be a requirement around local resources for the capacity, aka the LCR. Suppliers unable to procure enough capacity will need to purchase the capacity through the State Reliability Mechanism (SRM), which is likely to reflect prices set by the utilities, considering the utilities control most of the lower peninsula generation. The SRM will replace the MISO auction process for setting prices in Michigan beginning on the next capacity cycle, June 1, 2018.
The general consensus is that the SRM prices will reflect prices close to the service provided by utilities (default service), and thus will diminish the value of the Retail Open Access, or “Choice” program, reducing competition in the state and increasing costs for energy consumers. Choice customers that do not procure capacity independently would default to the SRM rate and could be forced to pay as much as $510/MW-day; the current capacity rate set by auction in MISO is $1.50/MW-day. The initial SRM will be in place for the first four-year planning term, from June 1, 2018 to May 31, 2022. Customers will then need to continually plan five years ahead; they will need to secure capacity for the June, 2022 – May, 2023 period by late 2018 or early 2019.
For Choice customers, the LCR decision is important because out-of-state capacity is less expensive than capacity in Michigan. Therefore, a lower LCR would be better for Choice customers. Even if there is no in-state requirement, however, customers should still expect a large cost increase relative to the current capacity year. Figure 1 below illustrates some of the price differences between historical MISO auction settlements and some of the proposed and projected rates coming out of the SRM.
Overall, there is a lot of uncertainty that still needs to be cleared up by the commission. Our first recommendation is to wait until after the ruling on September 28 before pursuing fixing capacity costs beyond June 1, 2018. After that, we see two potential paths. First, customers can hedge capacity costs through their supplier and leave it up to the supplier to maintain the capacity obligations set forth. This is likely the easiest option going forward, but it may be an issue if suppliers need to purchase additional capacity through the SRM. Also, if a customer chooses to pass through capacity costs, the customer will be charged the SRM price, which is likely to be much higher than the suppliers’ offered cost of capacity.
The second option is to procure capacity obligations through bilateral agreements with generators and sleeve the capacity through the existing supplier. The capacity procured would be subject to the existing LCR rules (if included in final language), and the supplier would have to agree to purchase on the customer’s behalf. The benefit of this option would be to purchase capacity below the expected SRM rate and below what suppliers could procure on their own. This option does have challenges, as a supplier may be able to purchase the capacity obligations more competitively and avoid the SRM rates on their own. In addition, suppliers are not obligated to accept the capacity hedge set up through a bilateral agreement between customer and generator, and the switching rules are not clear if a customer switches suppliers over the duration of the bilateral capacity agreement. Moreover, payment for the capacity obligations is uncertain. Some suppliers may require an upfront payment, and there is uncertainty regarding how a customer’s peak load contribution (PLC) will be determined, or if the method will change.
Based on our initial assessment, the easiest and best path forward is likely to contract for capacity through your supplier. The contractual complexity, unclear switching rules, and payment terms of purchasing capacity through a generator are the main reasons for the recommendation. Furthermore, considering forward strips beyond June 1, 2018 are at some of their lowest points over the past three years, we recommend moving quickly after the rules are finalized on September 28. We will keep an eye on the regulations and provide future guidance as it becomes clear.
For updates on electricity and natural gas prices, read our full report for this month.
The low demand for power in the western Gulf Coast—as a result of Hurricane Harvey and its aftermath—is likely to persist, thereby suppressing power prices. This phenomenon could have implications for independent power producers already hurting from low prices.
Suggested comparisons include Hurricane Ike, which hit the Texas coast in mid-September 2008 and caused billions of dollars in damages that included significant, widespread and prolonged outages in the Houston area.
Gurcan Gulen, Senior Energy Economist at the University of Texas Bureau of Economic Geology’s Center for Energy Economics, said in a statement to S&P Global that "we should see a repeat" of the power price pattern from Hurricane Ike. "Demand will remain suppressed for days if not weeks, not only because of lost load but also due to lower temperatures," Gulen added.
Power prices will likely reflect the lower system demands as storm damage has forced out large segments of industrial production, as well as causing massive residential and commercial load destruction.
Across the ERCOT footprint, the biggest impact was seen in the Gulf region, as load was reduced more than 40%, while the less affected areas in the Central and Southwest saw declines just below 30% compared to their normal ranges.
As demand erosion far outweighed supply side reductions, spot prices remained depressed throughout the storm and the days following. For pricing to recover, it will heavily depend on how quickly power lines can be repaired in order to restore service for end users.
For updates on electricity and natural gas prices, read our full report for this month.
The Mexican utility, the Comisión Federal de Electricidad (CFE), announced that the default electricity prices for commercial and industrial users will decrease in September relative to August. Residential customers will also see their rates fall month-over-month.
Industrial customers will see a tariff rate decrease between 1.3% and 1.7%, and commercial customers will see a decrease of between 0.9% and 1.3% relative to the tariff rates in August. The decrease is the result of small movement in natural gas prices, which are one of the main determinants of power prices. September marks the sixth consecutive month in which tariff rate have decreased for CFE’s large customers. Also, residential customers will continue their streak of 33 consecutive months without a price increase.
CFE’s monthly updates to the tariffs can be problematic for power customers that require more budget transparency and certainty—particularly when prices are increasing. Increasingly prevalent third-party suppliers are offering more competitive rates that can provide greater budget certainty. Enel X is actively working to vet new entrants to the supplier market, and can assist customers in finding and choosing the best independent contract to manage their costs and risk at the most competitive price.
For updates on electricity and natural gas prices, as well as new developments in renewable energy in Mexico, read our full report for this month.
Last month, the banner story was unquestionably Hurricane Harvey. Harvey had a neutral/bearish impact on NYMEX and Gulf Coast basis pricing, and the fact remains that both NYMEX and Gulf basis points are at an attractive price point compared to the past five years. Even as hurricanes continue to dominate the headlines, Hurricane Irma is expected to have a minimal impact on Florida basis pricing.
The last hurricane season to significantly impact natural gas pricing was in 2005, when Hurricane Katrina, Rita, and Wilma all made landfall. During that time, NYMEX pricing at the Henry Hub trading point soared from an August settlement of $7.647/MMBtu to a $10.847/MMBtu settlement for the September and a whopping $13.907/MMBtu October settlement price. The natural gas narrative from 2005 is easily juxtaposed with today’s supply/demand situation. A quick look at the gas price reaction from Harvey underscores the extremely strong fundamentals of a supply rich market that can shrug off natural disasters, such as hurricanes in the Gulf region.
While past storms like Katrina and Rita forced meaningful rallies in gas pricing, Harvey’s impact was minimal to Henry Hub gas pricing because the storm’s shutdown of all end-user demand in the affected region outweighed the loss of production throughout the Gulf Coast. The bearish price reaction in NYMEX and regional basis pricing reflects the increased reliance of onshore gas production relative to history. In 2001, the Gulf Coast accounted for approximately 26% of total US gas production. Fifteen years later, the reliance on Gulf gas production shrunk to around 4%, according to Platts. The cause of this change is undoubtedly the shale revolution, as inland production has diversified along the southeast and Northeast and Great Plains regions. During Harvey, the offshore production was reduced by 81%; however, this reduction did not impact pricing due to minimal Gulf production levels.
For more insight into natural gas pricing trends, read our full report for this month.