Renewed Ambition

Houston — The 2021 Atlantic hurricane season will be another busy one, with an elevated probability for major hurricanes to make landfall along the continental US coastline, according to an early forecast from Colorado State University.

Tropical Weather and Climate researchers at CSU are predicting 17 named storms, eight hurricanes and four major hurricanes in the Atlantic this year. During the baseline comparison period from 1981 to 2010, the Atlantic witnessed an average of 12.1 named storms, 6.4 hurricanes and 2.7 major hurricanes.

The CSU forecast precedes the National Oceanic and Atmospheric Administration’s forecast, which is scheduled for release in late May.

On April 9, the NOAA said it was updating its own 30-year comparison period to 1991-2020, reflecting higher storm activity compared to the previous 1981-2010 period. The latest 30-year comparison period now includes 14 named storms and seven hurricanes. The number of major hurricanes remains unchanged at three.

Shut-ins, facility damage

For the US oil and gas industry, the upcoming hurricane season will again pose a significant potential threat to both offshore platforms and onshore infrastructure including refineries, gas processing and petrochemical plants, and crude, refined product and LNG export facilities.

According to CSU researchers, counties surrounding the Houston metro area and parishes surrounding the New Orleans metro are among the most vulnerable to storms making landfall in Texas, Louisiana and Mississippi, potentially posing an outsized threat to some of the region’s mostly densely concentrated oil and gas infrastructure.

During the 2020 Atlantic hurricane season, 11 named stormed entered the US Gulf of Mexico, including four hurricanes and three major hurricanes. While Hurricane Laura was the single most disruptive storm, October was the most disruptive month of the season with four named storms entering the Gulf.

During category 4 Hurricane Laura, offshore producers shut over 84% of Gulf oil production, equivalent to about 1.559 million b/d, and 60% of natural gas production, equal to over 1.6 Bcf/d. Along the Gulf Coast, LNG and product-export operations were temporarily halted and more than 2.3 million b/d in refining capacity was taken offline.

While five of the shuttered refining facilities were quickly restored to service, the Citgo and Phillips 66 refineries in Lake Charles, Louisiana, suffered more prolonged disruptions. Petrochemical operators in southwest Louisiana met a similar fate. West Lake Chemical was among those damaged, with some of its units remaining offline for upwards of six weeks.

Later in the season, October became the most disruptive month with hurricanes Delta and Zeta jointly curtailing nearly 600,000 b/d. According to S&P Global Platts Analytics analyst Sami Yahya, “The single-day peak was a little under 1.7 million b/d.”

By October 30, the 2020 Atlantic hurricane season had curtailed nearly 40 million barrels of US Gulf crude, or around 130,000 b/d. The unusually severe 2020 hurricanes were also a factor in Gulf of Mexico production declines in the year’s second half. The Gulf’s Q2 2020 production of 1.69 million b/d dropped to 1.45 million in Q3 and 1.52 million in Q4, before rising to a more-normal 1.72 million b/d in Q1 2021.

Power outages

Further inland, the impact from recent hurricanes has been borne mostly by power generators, utilities and their customers, which typically face widespread outages, demand destruction and lower power prices.

In the wake of Hurricane Laura, nearly 840,000 utility customers in Arkansas, Louisiana, Mississippi and Texas lost power. While Laura was by far the most disruptive storm of the 2020 season, the US power industry faced significant disruptions during various storms throughout the season.

During Hurricane Sally, more than 540,000 electricity customers in Alabama, Florida, Georgia and Mississippi lost power. Hurricane Delta, a major category 4 storm, cut power to an estimated 575,000 homes in the wake of its path through Louisiana and northern Mississippi. Hurricane Zeta, which struck late in the season on October 29, cut power to some 1.2 million customers of Southern Company utilities in Alabama, Georgia and Mississippi.

Houston — WhiteWater Midstream launched an open season April 12 for commitments for up to 2 Bcf of firm natural gas storage capacity at a Texas facility that serves the Permian Basin.

Demand for more infrastructure to facilitate increased gas production from the prolific shale play has increased in recent years.

In particular, private equity-backed WhiteWater has been expanding its gas operations in the region. It partnered with MPLX, WTG and Stonepeak on the 450-mile Whistler pipeline to move gas from the Permian to Agua Dulce. It also partnered with MPLX on Agua Blanca, an intrastate natural gas pipeline that serves the Permian’s Delaware Basin.

WhiteWater’s Waha Gas Storage facility consists of underground salt caverns in Pecos County, adjacent to the Agua Blanca header system. There are six existing caverns and five additional permitted caverns. The facilities can provide about 10 Bcf of storage capacity once fully developed.

The open season, which runs until May 21, is seeking commitments that will be associated with about 200 MMcf/d of maximum daily injections and withdrawals. Customers will be given injection and withdrawal rights based on their total capacity commitments, WhiteWater said in a statement.

Service for the capacity contracted under the open season is expected to begin on or around July 1, 2022.

Operators in the Permian have continued to add rigs to market in the $60/b WTI price environment. While oil majors have remained disciplined with spending and rig increases, private companies and some large cap operators have been driving recent growth in US drilling activity, mainly in the Permian, according to S&P Global Platts Analytics data.

With the lure of oil comes increasing amounts of associated gas being lifted. The Energy Information Administration recently raised its US natural gas consumption forecasts for the rest of 2021. While use of the fuel in the power sector has been under pressure, demand has been strong for feedgas from Gulf Coast LNG export terminals.

US LNG feedgas deliveries remain near all-time highs, with netbacks out of the USGC remaining above $2.50/MMBtu through the end of spring, shifting upside risk to the Platts Analytics forecast for April and May.

With European storages recently drawing down hard on sparse LNG deliveries combined with concurrent cold weather, Platts Analytics expects LNG demand to be much more supported this summer compared with 2020 as storage stocks are replenished. That is expected to result in near full contracted US export utilizations with low risk of significant cargo cancellations – a bullish sign for Texas gas producers and midstream operators.

Denver — Record wind generation in the US Midcontinent is putting downward pressure on gas-fired power burns this month, posing an emerging risk to gas prices at some of the region’s key supply hubs.

Month to date, wind has generated an average 381,000 MWh in the Southwest Power Pool and over 282,000 MWh in the Midwest Independent System Operator – both record-high monthly averages for the respective ISO territories, data from S&P Global Platts Analytics shows.

Wind generation records across the central and plains states come as the National Weather Service issues red flag warnings across portions of Nebraska, eastern Colorado and Kansas. On April 8, the region was on alert for high wind speeds, low humidity and corresponding wildfire risk.

For Midwest gas and power markets, stronger wind speeds and milder temperatures this month have conspired to pressure total demand for baseload generation from fuels like gas, coal and nuclear.

As total generation also ebbs to its lowest since last spring, wind is capturing its largest average market share on record this month, accounting for some 60% of total generation in SPP and about 20% of total generation in MISO, Platts Analytics data shows.

Power Burn, prices

Since at least mid-March, rising wind generation and mild weather have put Midwest power burns under pressure.

Month to date, regional burns have averaged about 1.8 Bcf/d, making for the weakest start to April since 2017. Over the next two weeks, warming temperatures are expected to further depress Midwest power burn to an average 1.65 Bcf/d, according to current analytics forecasts.

As wintry weather across the Midwest continues to fade, reduced consumption from residential-commercial customers has also pressured the region’s market balance, lowering total gas demand to an average 11.1 Bcf/d this month – its lowest since September 2020.

While not atypical for the shoulder season, the recent and precipitous drop in demand is already starting to pressure the cash market. After approaching to $2 level earlier this week, spot gas prices at NGPL Midcontinent, Southern Star and Panhandle Tx.-Okla. were up modestly April 8 to end trading at $2.26, $2.24 and $2.21/MMBtu, respectively, preliminary settlement data from S&P Global Platts showed.

Outlook

Over the balance of April, forwards gas markets are anticipating prices at the three Kansas hub locations to remain roughly flat, to modestly lower with the balance-of-month contracts priced at $2.25 for NGPL Midcontinent, $2.28 for Southern Star and just $2.13/MMBtu for Panhandle Tx.-Okla.

From April to October this year, gas demand from the power generation sector still poses the biggest downside risk for the Midwest market. According to Platts Analytics, weather-normal power burn demand could decline by as much as 400 to 500 MMcf/d this summer compared to last, thanks in part to a recent wave of gas-to-coal switching.

According to a recently published long-lead forecast from the National Weather Service, states across the Midwest currently face a 40%-50% risk for above-average temperatures from June to August – a potentially mitigating factor for this summer’s anticipated decline in power burn.

Assuming Midwest renewable generation remains at or even close to current levels, though, any incremental demand for summer cooling could be gone with the wind.

London — France was a net importer of power in Week 14 (April 5-11) as cold temperatures saw power demand rise sharply after the Easter weekend, while a combination of planned and forced outages in EDF’s nuclear fleet saw its generation at a six-month low.

Over the week, France imported, on average, 0.9 GW compared with exports of 6.8 GW in Week 13, as imports from Belgium/Germany hit the highest since Week 1 and flows to Spain reversed. Exports to Italy, Switzerland and the UK were down significantly week on week.

Power consumption averaged 54.8 GW across Week 14, up 6.2 GW week on week as unseasonably low temperatures caused a spike in demand in France, where power consumption is sensitive to cold temperatures given the extensive use of electricity for heating.

Between April 5, the end of the Easter holiday weekend, and April 6, consumption climbed over 20% to 58.6 GW and then further still through the week.

Meanwhile, nuclear output fell more than 2 GW week on week to the lowest average nuclear output since Week 40 in 2020.

According to EDF, the 1,330 MW Paluel 3 and 890 MW Dampierre 1 reactors went offline as planned during Week 14, while the 1,330 MW Paluel 1 and Paluel 4 units, as well as the 915 MW Tricastin 4 unit, were forced offline as a result of failures. Output was also reduced at the 900 MW Cruas 2 and Chinon 1 reactors due to strike action. Dampierre 4 and Cruas 4 returned to action in Week 14, however, after planned outages.

Having hit record lows in the first quarter, nuclear output climbed towards its 10-year average in March, but the fall in output from the previous three weeks saw nuclear generation in Week 14 set a record low for the week, according to RTE data going back to 2012.

According to EPEX Spot data, French day-ahead baseload prices have averaged Eur52.36/MWh ($62.3/MWh) month to date, higher than any April monthly average since at least 2012.

The near-term price outlook was trending towards the upside on an expected combination of cold temperatures and low wind input, while the low nuclear output provided further price support.

“The market seems to be very bullish still…also the latest forecasts show low wind input while French nukes are going offline in the next couple of weeks,” a European power trader said.

About 83.5 GW of natural gas-fired generation has retired since 1991 -– 57.7% of it since 2011. Coincident massive renewable generation growth likely reinforced the trend, but the flexibility of gas-fired capacity to fill in for intermittent renewables may help extend gas plants’ viability over the next few years.

About 5.6 GW of the generation retired since 2015 was relatively new – built in 1991 or thereafter, according to S&P Global Market Intelligence’s power plant database.

Based on US Energy Information Administration data, Gurcan Gulen, principal at G2 Energy Insights, a Boston-area energy consultancy, said 46 GW of gas-fired generation was retired between 2011 and 2020, of which more than 70% were older steam and combustion turbines, but 90 GW of new gas-fired capacity was built.

“Low gas prices leading to low electricity prices in competitive markets was a driver of most gas retirements but also some coal and nuclear,” Gulen said in a March 22 email. “So was the excess capacity expansion, often induced by generous capacity markets (which encouraged older plants to stay online and some new gas-fired plants) and subsidized wind and solar. Negative bidding by wind and, to a lesser extent solar, to collect [production tax credits] and/or to avoid curtailment lowered average prices in many hours further.”

Efforts to support generation via minimum offer price rules in capacity markets and scarcity pricing schemes in the Electric Reliability Council of Texas market were insufficient to keep retired plants running, Gulen said.

Frequent cycling

Wade Schauer, a research director for Americas power and Renewables at the Wood Mackenzie consultancy, said many of the larger natural gas combined-cycle units “were designed to run 24/7, but renewables are forcing them to cycle daily, which leads to increased maintenance costs.”

“Low energy costs and oversupplied capacity markets mean they can’t cover their fixed operating costs,” Schauer said in a March 22 email. “If coal plants retire in large numbers as expected, that would help some of the older NGCCs survive for another ten years or so because then they would cycle off and on less frequently.”

Demand issues

One factor in the relatively early retirement of gas-fired generation over the recent past has been slow load growth since the Great Recession of 2008-09.

Over the past three decades, noncoincident peakload in the Lower 48 States has grown by about 245.7 GW to about 769.8 GW in 2020, according to North American Electric Reliability Corporation data. However, much of that growth was front-loaded, with a growth rate of about 12 GW/year for the first 15 years and a growth rate of less than 4.4 GW/year for the most recent 15 years.

“The abrupt cessation of peak demand growth [circa] 2008 left the industry with too much capacity,” said Morris Greenberg, senior manager for North American power at S&P Global Platts Analytics, in a March 22 email. “The least efficient peaking units were not needed. Once fully depreciated (in the case of regulated units) there was no longer any reason to keep them online. Renewables probably played a role by reducing net load. However, renewables provide diminishing capacity value as their share increases, so I would not necessarily expect a negative impact going forward. Battery penetration would be a greater concern for peaking units.”

ERCOT blackouts

The winter storm that struck Texas in February, resulting in massive generation outages, blackouts for more than 4 million electricity customers and the deaths of 57 people is having repercussions which may also enhance gas-fired generation’s longer term viability.

“With respect to wind/solar in ERCOT, neither is expected to provide much dependable capacity in the winter so I would not expect development plans to change,” Greenberg said. “With respect to gas-fired capacity, the [Public Utility Commission of Texas] may want to consider requiring power plant weatherization to ensure operability at low temperatures. They could also require firm gas supply or dual-fuel capability (that will be usable at low temperatures and for a sufficient number of days). The firm gas requirement could encourage addition of gas storage which could be weatherized at lower cost than individual wells.”

G2 Energy Insights’ Gulen said, “[Clearly] the loss of gas generation was the catalyst of blackouts,” but added that this “was primarily caused by the lack of preparing generation facilities and gas supply chain for such extreme winter weather.”

“I’m sure assumptions will be revisited in terms of probability of such extreme weather and risk models will be adjusted but fundamentally the problem was not a capacity (or resource adequacy) problem,” Gulen said. “Still, capacity markets, interconnection to neighboring grids, more demand-side participation, [distributed energy resources], etc. are all on the table.”

Campbell Faulkner, senior vice president and chief data analyst at OTC Global Holdings, an interdealer commodity broker, said he is “deeply concerned about thermal units being bid out of the dispatch stack.”

“While reserve margins in the various control areas are being ‘maintained,’ across the US, the lack of dispatchable and controllable units leads me to believe we are trading reliability for overall lower power prices,” Faulkner said in a March 22 email. “That trade-off could lead to more frequent events similar to the Texas blackouts due to the mis-match between what’s available to dispatch and the constant growing need for greater electrical generation. I still maintain high confidence in the continued renewable build-out, but worry that the [grid reliability] aspect along with the ability to deal with adverse grid conditions has become a lesser consideration to the overall generation mix. More frequent rotating outages … on high load days could spur more localized backup generation (solar/battery and generators).”

More distributed generation will likely boost the need for large conventional generators to maintain frequency, but these are facing challenging economics, Faulkner said.