PJM Interconnection has asked the Federal Energy Regulatory Commission for a rehearing in its reserve market proceeding because a recent FERC order departs, without adequate…
Jan 24, 2022
PJM Interconnection has asked the Federal Energy Regulatory Commission for a rehearing in its reserve market proceeding because a recent FERC order departs, without adequate explanation, from prior findings that resource procurement costs to alleviate power supply shortages should be reflected in transparent market prices.
FERC has reversed earlier decisions pertaining to an overhaul of PJM’s reserve market, forcing the grid operator to make two compliance filings before the end of February.
Following May and November 2020 decisions approving PJM’s proposed reserve market changes, FERC decided on Dec. 22, 2021, to no longer support some of those provisions after the case was voluntarily remanded from the DC Circuit Court of Appeals (EL19-58, ER19-1486).
FERC told PJM to revise its tariff and operating agreement to reflect the effective reserve penalty factors and operating reserve demand curves, or ORDCs, within 60 days. The commission directed the grid operator to also restore tariff provisions pertaining to the previous backward-looking energy and ancillary services, or E&AS, offset that became effective Nov. 12, 2020.
However, PJM after business hours on Jan. 21 filed a rehearing request with FERC that cited a dozen “issues and errors” contained in the commission’s order on remand.
The remand order reverses FERC’s prior orders, “on the same record and in disregard of much of PJM’s extensive evidence in this proceeding,” PJM said in the rehearing request.
FERC had previously approved an ORDC for PJM, finding that the costs of resources procured to alleviate shortages should be reflected in transparent market prices whenever it makes sense to do so, PJM said.
Reversing that decision in the remand order has left unsettled “the commission’s policy principles governing price formation and raises a potential barrier to future reserve pricing reforms that seek to follow the Commission’s prior price formation decisions,” the rehearing request said.
Additionally, in a dissenting opinion regarding FERC’s order on remand, Commissioner James Danly on Jan. 20 questioned how the commission could uphold FERC’s previous findings under section 206 of the Federal Power Act while reversing others when the record remains exactly the same as that upon which the earlier determinations were based.
PJM cited this argument multiple times in its rehearing request. The remand order should, at minimum, have held that there was enough presented on this record to find that PJM’s current reserve pricing may be unjust and unreasonable, thus warranting hearing, settlement, or other means of resolving material questions of fact, the grid operator said.
PJM said it remains concerned whether the existing ORDCs and reserve penalty factors are adequate to ensure the proper reserve market response.
Absent any changes to its findings, the remand order’s departure from the May 2020 order and November 2020 order “falls well short of the reasoned decision making required for administrative agency action,” PJM said.
FERC found in those prior orders, based on substantial evidence, that the pre-existing ORDCs and reserve penalty factors were unjust and unreasonable, but based on the “exact same evidentiary record and without conducting any further evidentiary procedures,” the remand order found that there is not substantial evidence that the ORDCs and reserve penalty factors are unjust and unreasonable, the rehearing request said.
“This fundamental reversal on a basic finding of fact cannot have stemmed from different facts, because no new facts were received,” PJM argued.
The remand order did not address PJM’s “extensive showing and discussion” of the forecast uncertainties that drive the need for reserves and the order also failed to address a key fact cited by the commission’s prior orders: those well-documented uncertainties can substantially exceed the maximum reserve level of the current ORDC, PJM said.
In other words, forecast errors in load, variable resource performance and interchange could under certain circumstances exceed the level of reserves that PJM is allowed to procure in the reserve market under the current ORDC, the grid operator added.
Additionally, in a separate Jan. 21 filing with FERC, PJM requested the base residual capacity market auction for the 2023-24 delivery year be held June 8 with the first and second incremental auctions canceled.
The auction was originally scheduled for late January, but FERC’s remand order required the capacity auction schedule to be delayed.
Jan 24, 2022
High gas prices have been raising costs for the production of very low sulfur fuel oil — the key marine fuel post the International Maritime Organization’s global low sulfur mandate — and curbing output of the residual fuel.
Refineries that run on gas are facing surging prices for power and this has been forcing them to trim some operations, including production of 0.5% sulfur fuel oil.
“High natural gas prices have pushed the cost of desulfurization extremely high, which removes an incentive for refiners to produce lower sulfur molecules,” a fuel oil trader told S&P Global Platts.
European gas prices remain at historic highs on continued winter supply concerns given curtailed Russian deliveries and relatively low storage stocks.
The TTF day-ahead price hit an all-time high of Eur182.78/MWh on Dec. 21, 2021, an increase of 985% year on year, according to Platts price assessments. Though prices have cooled since, they still remain near historic highs.
The TTF day-ahead contract was assessed Jan. 18 at Eur79.20/MWh, still a year-on-year increase of 290%. According to the forward curve, prices are set to remain high in the coming months, with the TTF contract for March assessed at Eur78.25/MWh.
The higher power costs are resulting in a noticeable premium to price levels. “This has raised operating costs by roughly $3-$5/b for those refineries fully exposed to purchased spot gas [for refinery fuel and hydrogen production],” S&P Global Platts Analytics said Jan 14. “Electricity costs are also higher in many of those markets.”
The forward curve shows prices falling slightly from April, with the second-quarter contract assessed at Eur64.15/MWh on Jan. 18, but that is still three times higher than the same contract a year ago, Platts data showed.
The effect is most pronounced in Europe, where some refineries are particularly exposed to the spot gas market for their refinery fuel. In Asia, contracts are more spot oriented, Platts Analytics said.
High gas prices are also causing more demand for fuel oil as a feedstock, which means refineries are not just producing less VLSFO but also competing with the bunker market for it and for 3.5% sulfur fuel oil, or high sulfur fuel oil.
Those refiners and utility providers that have the flexibility to switch to alternative fuels are doing so.
In recent months, high natural gas prices have turned power generators to substitute away from natural gas to oil — primarily low sulfur fuel oil, low sulfur burning crude, and some HSFO — and refiners to burn more LPG and fuel oil, Platts Analytics said.
In countries where fuel oil can be used more extensively for power generation — a few European locations and Singapore — margins are now quite good, Platts Analytics said.
The result of this tight supply and increased demand is that prices for bunker fuel in Rotterdam, the Netherlands, are reaching record highs.
VLSFO prices in Rotterdam have hit their highest level since the Platts assessment was launched in July 2019. Marine Fuel 0.5%S was assessed at $651/mt on Jan. 18, Platts data showed. The previous record high for VLSFO in Rotterdam was $608/mt on Oct. 25, 2021.
“The market is continuing to go up at the moment. We have seen tightness across all grades of fuel oil in Rotterdam, which we expect to continue until the end of January at the earliest,” said one Rotterdam-based supplier.
The Asian fuel oil market, which typically sees 2 million-3 million mt/month of cargo inflows from the West, has been receiving a relatively low amount of inflows since the second half of last year, partly due to strong demand from power utilities in Europe, fuel oil traders said. Power utilities in Europe consumed more fuel oil with sulfur content of about 1%, which reduced volumes to go to Asia, the traders said.
In addition, Asian power companies raised fuel oil buying amid high LNG prices in fourth-quarter 2021, tightening Asian 0.5%S marine fuel further. The Platts JKM, the benchmark price for spot LNG in Asia, was assessed at $23.113/MMBtu on Jan. 24, compared with Singapore Marine Fuel 0.5%S at $16.07/MMBtu, Platts data showed. Asian 0.5%S marine fuel supply has remained tight, as the February-March spread was assessed still at a double-digit backwardation of $14.25/mt on Jan. 24, Platts data showed.
LNG prices had a significant turnaround in 2021 versus 2020, as JKM averaged $15.03/MMBtu during the year, with the daily physical assessment hitting an all-time high of $56.33/MMBtu on Oct. 6, 2021, as both Asia and Europe were competing for supplies ahead of the start of winter. Platts Analytics expects JKM to average more than $31/MMBtu for deliveries in Q1 due to the threat of cold temperatures and a tight global gas market, especially in Europe where storage inventories remain well below historic norms.
Jan 14, 2022
Record volumes of gas certified for its environmental credentials have come to the market after nearly two dozen US gas producers committed to external assessment of their emissions and ESG criteria last year.
Over the last week, two US gas producers announced the completion of third-party certification processes, adding up to 5 Bcf/d of certified gas in Appalachia.
EQT, the largest US gas producer, announced on Jan. 14 that it had certified the majority of its natural gas production under both Equitable Origin’s EO100 Standard for Responsible Energy Development and the MiQ Standard on methane emissions. The producer received both certifications in November, with digital attribute certificates becoming available more recently, according to a Jan. 14 press release. EQT produces around 4 Bcf/d in Appalachia.
“These results not only enable us to unlock growing domestic and international markets that are valuing a differentiated commodity, they also serve as an important validation of the environmental attributes of Appalachian natural gas,” EQT CEO Toby Rice said in a Jan. 14 statement.
EQT has also partnered with Denver-based continuous monitoring firm Project Canary on a pilot program, installing Canary X sensors on two well pads in southwestern Pennsylvania.
Earlier in the week, National Fuel Gas Company announced that its production arm, Seneca Resources, had received certification from Equitable Origin for just over 1 Bcf/d of Appalachia gas production.
“As we look ahead, we expect that the certification of Seneca’s entire Appalachian natural gas base will differentiate our responsibly sourced, low methane-intensity production with end-users and commercial markets,” Seneca Resources President Justin Loweth said in a Jan. 11 statement.
Like EQT, Seneca Resources has also partnered with Project Canary for a pilot program, which will assess around 300 MMcf/d of Appalachia gas production.
The two statements come on the heels of two earlier announced certifications in December, which added 1.2 Bcf/d of certified gas in the Haynesville Shale.
On Dec. 21, Chesapeake Energy confirmed that it had completed Equitable Origin and MiQ certification for approximately 1 Bcf/d of Haynesville gas production. The producer has also partnered with the two organizations to certify its Appalachia gas production, which is expected to be completed by the end of the second quarter of 2022, as well as signed pilot project deals in both basins with Project Canary. Additionally, Haynesville producer Vine Energy, which was acquired by Chesapeake in November, sought out Project Canary certification for the entirety of its production in August.
On Dec. 8, BP’s US onshore production business, BPX Energy, announced that it had received an ‘A’ grade on the MiQ Standard for approximately 200 MMcf/d of South Haynesville gas production in Texas.
With the certified gas market in its infancy, no clear consensus has been found on how this new product will be traded or where.
Several platforms to facilitate the trading and tracking of certified gas certificates – either bundled with physical natural gas or unbundled—have emerged, including the MiQ Digital Registry and Xpansiv.
MiQ launched its global secure digital ledger, the MiQ Digital Registry, in December to hold and track certificates from issuance to retirement. With many producers choosing to seek out multiple certifications, the MiQ Digital Registry has offered joint MiQ-EO100 certificates, as well as MiQ certificates. In addition to EQT, at least two other US producers have simultaneously sought out certification from both MiQ and Equitable Origin.
Xpansiv, an exchange that specializes in environmental commodities like carbon offsets and RECs, partnered with S&P Global Platts to launch Methane Performance Certificates in early October, which can be issued and tracked with Xpansiv’s Digital Fuels Registry.
Platts MPCs represent gas produced with a methane intensity of 0.1% or lower and are unbundled from the natural gas production underpinning each certificate’s creation. As of Jan. 13, the price of an MPC was assessed at $0.049/MPC, or $7.903/mtCO2e.
Xpansiv has also partnered with Project Canary, agreeing in November to provide the exchange with methane-emissions data gathered from its continuous monitoring systems.
EQT, Chesapeake Energy, and BPX Energy all reported receiving an “A” grade on MiQ’s sliding scale of “A” to “F”. An “A” grade represents a methane intensity of 0.05% or less while an “F” is more in the ballpark of 2%.
To put an intensity of 0.05% in context, One Future, a consortium of energy companies committing to reducing methane emissions, had a gas production sector goal of 0.283% in 2020, according to its most recent methane emissions intensity report.
April 25-27, 2022 | Las Vegas, NV, USA Save the date for GPM 2022 The S&P Global Platts Global Power Markets™ Conference focuses on the…
Jan 03, 2022
The S&P Global Platts Global Power Markets™ Conference focuses on the latest trends in power supply and demand dynamics, decarbonization, digitalization, emerging renewable power technology, global power markets investment, power finance, and power asset valuation / M&A.
It connects the industry not just to critical information, but to each other—it’s where deals get done.
The program is currently in production. Keep reading to learn more about the conference and who you’ll meet. Sign up to get updates about the agenda, confirmed speakers, and networking opportunities we’re rolling out. Registration opens in January 2022.
If you’re interested in being a speaker or have a topic you’d like to see on the agenda, reach out and let us know.
Tel: +1 281-229-3223
Nov 09, 2021
Jun 25, 2021
In this week’s highlights: Russia-Ukraine tensions put Dated Brent above the $90 mark, gas prices remain below December highs, EDF power workers in France get…
Jan 24, 2022
In this week’s highlights: Russia-Ukraine tensions put Dated Brent above the $90 mark, gas prices remain below December highs, EDF power workers in France get ready for a snap strike, and petrochemical contract negotiations near a conclusion amid multiple cracker outages.
-Geopolitics spur oil price rally (00:16)
-Gas deliveries sharply down (01:21)
-Upside price risk as nuclear limps through winter (02:14)
-Petrochemical contract price negotiations (02:47)
An idle Nord Stream 2 gas pipeline is “bad” for consumers of gas in Europe, the Kremlin said Jan. 19, as tensions between Russia and…
Jan 19, 2022
An idle Nord Stream 2 gas pipeline is “bad” for consumers of gas in Europe, the Kremlin said Jan. 19, as tensions between Russia and the West over Ukraine continue to simmer.
European gas prices remain at historic highs, with low Russian supplies and a protracted certification process for the now complete Nord Stream 2 pipeline significant contributors to the recent price strength.
Kremlin spokesman Dmitry Peskov said Jan. 19 that the fact that Nord Stream 2 had not been launched was impacting European gas users.
“It is bad for those involved in the project and for those who consume gas in Europe,” Peskov was quoted as saying by the Prime news agency.
The TTF day-ahead price hit an all-time high of Eur182.78/MWh on Dec. 21, an increase of 985% year on year, according to S&P Global Platts price assessments.
Prices have cooled since, though they remain at historic highs. The TTF day-ahead contract was assessed Jan. 18 at Eur79.20/MWh, still a year-on-year increase of 290%.
Russian supplies into Europe have fallen sharply since the start of 2022, with deliveries via main routes — including the first Nord Stream system — down compared with the final months of 2021.
Nord Stream is currently supplying around 146 million cu m/d of gas, down from its regular 158 million cu m/d flow rate, while deliveries via Ukraine at the Velke Kapusany interconnection point are down at just 26 million cu m/d, according to data from S&P Global Platts Analytics.
Under transit arrangements finalized in December 2019, Gazprom agreed to transit 65 Bcm of gas via Ukraine in 2020 and 40 Bcm/year in the period 2021-24, well down on a recent transit peak of 94 Bcm in 2017.
A total of 41.6 Bcm of Russian gas transited Ukraine to Europe in 2021.
Russian supplies via the TurkStream pipeline have also been lower in January compared with volumes delivered in December last year.
In a statement on Jan. 15, Gazprom said its gas exports to non-CIS countries in the first half of January totaled 5.4 Bcm — or an average of just 360 million cu m/d.
That is more than 40% lower than the average in January 2021 of 626 million cu m/d.
Peskov’s comments come as tensions with the West over Ukraine continue, with German Chancellor Olaf Scholz on Jan. 18 saying sanctions against Moscow remained an option should Russia use energy as a weapon or escalate tensions in the region.
In July, Germany — under the Merkel administration — and the US issued a joint declaration designed mainly to limit the impact on Ukraine of an operational Nord Stream 2 pipeline and to help secure the future role of Ukraine as a transit country.
Scholz said Jan. 18 he stood by all aspects of the declaration with Washington.
In the meantime, the operator of Nord Stream 2 has completed the process of filling the 55 Bcm/year link with gas, but commercial operations are yet to begin as the operator waits for regulatory clearance.
The head of the German energy regulator, the Bundesnetzagentur, said Dec. 16 there would be no final decision on the certification of the operator of the pipeline in the first half of 2022.
The German regulator had four months from Sept. 8 to issue a draft decision on certification, but the process was suspended Nov. 16 after a little more than two months had passed.
The four-month process will resume once the regulator is satisfied that the actions around transferring assets to a new German subsidiary are completed.
The European Commission also has up to four months to issue a decision, after which time it is returned to the Bundesnetzagentur, which has a further two months to publish its final opinion.
While the roller coaster ride that US power markets have endured since the novel coronavirus pandemic took hold in March 2020 is not over, power…
Dec 30, 2021
While the roller coaster ride that US power markets have endured since the novel coronavirus pandemic took hold in March 2020 is not over, power forward traders may foresee a shortening of the hills and valleys by late 2022.
However, supply chain issues for materials such as steel and coal may tighten power markets more than forward traders realize.
The 2022 on-peak forward curves for four US hubs as of Dec. 22 show price rangers substantially smaller compared to year-to-date monthly average day-ahead on-peak locational marginal prices in 2021. The exception is California where drought, wildfires, extreme weather and high renewable penetration present higher risk.
Also, in every case except California, forward highs are front-loaded to January and February, reflecting lingering concerns about the “black swan” event of February 2021’s winter storm.
However, accelerating novel coronavirus infections may dampen economic activity in the first quarter. According to Worldometers.info, which collects data from public health agencies, the seven-day moving average of new COVID-19 cases in the US rose to 171,573 as of Dec. 22, above the recent peak of 167,589 on Sept. 2. The last time the seven-day moving average topped Dec. 22’s number was Jan. 26 at 172,377.
The Institute for Health Metrics and Evaluation in Seattle projects the daily infection rate in the US could top 2.7 million in late January, including those who never get tested, if protective mask use remains much below 80%. For comparison, IHME’s previous highest daily infection rate was 504,275 on Dec. 28, 2020.
Another factor that may weaken power demand is weather. The National Weather Service’s Dec. 16 forecast for January, February and March indicates the likelihood of near normal or above-normal temperatures for all except the Northern Rockies and the Pacific Northwest, where the probability for below-normal temperatures ranges from 33%-50%.
The US Energy Information Administration projects that heating-degree days in January, February and March will be down about 1.5% from 2021 levels. For the year, S&P Global Platts Analytics projects average load levels across the Lower 48 states in 2022 will be about 0.5% below 2021 levels.
However, in a 2022 special report, Platts Analytics said, “After 2021 focused on energy demand recovery, 2022 will focus on whether supply can catch up.”
An ability to “catch up” depends on supply and pricing constraints. Building power infrastructure requires steel, and prices for US flat-rolled steel products rose sharply in the first three quarters of 2021, with domestic hot-rolled coil, a steel pricing benchmark, surging 94% from the start of the year to a record high of $1,960/st in late September, according to Platts pricing data.
“If you are someone looking to expand the power grid, you’re not going to get the transformers that you need,” said John Anton, IHS Markit director of pricing and purchasing. “There will be a shortage of electrical steel next year and probably for many years to come and therefore there is going to be extreme pressure on the people who make electrical machinery from electrical steel.”
“Lead times for transformers [I’m now] hearing from the largest companies in North America are out 12 months,” Anton said.
Another potential constraint is coal supplies, according to Platts Analytics.
“Global coal demand is expected to increase again in 2022 as developing markets, China and India in particular, will need additional energy supply from coal to meet incremental energy demand growth,” Platts Analytics said.
In the US, the EIA projects that the power sector’s coal inventories fell by about 51 million short tons, about 38%, in 2021 and will further decline by 10 million st, or 13%, in 2022, despite a 9% increase in domestic coal production in 2021 and another 6% increase projected for 2022.
Transportation is a factor in electric generation coal costs, and the US EIA projects power plant coal costs to average almost $36/st in 2022, up 3.2% from $34.75/st in 2021, which was up 2.8% from 2020’s $33.85/st.
However, natural gas will likely mitigate coal’s influence on power pricing. As of Dec. 22, the Henry Hub forward strip for the 12 months of 2022 had a discount of almost 2% from Henry Hub average monthly spot prices in 2021, Platts price data shows.
Forward gas markets in the Appalachian Basin have remained largely indifferent to this month’s steep drop in gas production there, even as tighter supply boosts…
Jan 24, 2022
Forward gas markets in the Appalachian Basin have remained largely indifferent to this month’s steep drop in gas production there, even as tighter supply boosts cash and balance-of-month contract prices.
At the region’s benchmark upstream hub, Eastern Gas South, calendar-month basis prices for Q1 are actually lower this month compared to last, despite continued production weakness in Appalachia and rising seasonal demand across the US Northeast.
Month to date, Eastern Gas South’s February 2022 forward contract has dipped about 4 cents from its prior-month average to 61 cents discount to the Henry Hub. The March contract is down about 2.5 cents this month to average 56 cents behind the benchmark, S&P Global Platts’ M2MS forwards data shows.
Lower forward basis at Eastern Gas has persisted this month even as the hub’s cash and balance-of-month prices rise. In January, cash basis is up nearly 30 cents to 51 cents discount to Henry Hub. After rolling to January, the balmo contract at Eastern Gas has also strengthened, settling most recently at just 35 cents discount to the benchmark – up from a more-than-75 cents discount late last month.
The more bullish near-term price trend reflects tighter supply-demand fundamentals this month in both Appalachia and the Northeast gas markets more broadly.
In January, combined production from the Marcellus and Utica has fallen to an average 33.3 Bcf/d – down about 1.2 Bcf/d, or almost 3.5%, compared with the December average. In late January, the steady decline in gas production has continued with output recently dipping to its lowest since July at an estimated 32.2 Bcf/d on Jan. 22, S&P Global Platts Analytics data shows.
While declines in gas production in the new year are not uncommon in Appalachia or other North American shale basins, the 2022 downturn comes just regional gas demand hits seasonal highs. On Jan. 21, total Northeast demand topped 37.5 Bcf/d to reach its highest since January 2019. Over the next seven days, demand forecast to remain elevated at an estimated 33.2 Bcf/d.
In its eight- to 14-day outlook, the National Weather Service has forecast milder temperatures for the Northeast which are also expected to persist through February.
While warmer weather could help to ease the Northeast market balance, basis prices at Eastern Gas South and other nearby hubs are likely to remain elevated into next month and potentially into March, absent a rebound in gas production.
A quick rebound in gas production across Appalachia isn’t entirely out of the question. Its its latest survey published Jan. 19, Enverus reported an estimated 40 drilling rigs in operation across the Marcellus shale – the most since February 2020. Recent data from the US Energy Information Administration also show upstream activity in Appalachia at or near pandemic-era highs as new-well drilling and well completions accelerate.
With increased digitalization making oil and gas assets more susceptible to cyberattacks, the public and private sectors must work together in 2022 to build out…
Dec 31, 2021
With increased digitalization making oil and gas assets more susceptible to cyberattacks, the public and private sectors must work together in 2022 to build out more proactive security capabilities to mitigate the risk to critical energy assets, industry stakeholders and security experts said.
“The cycle that we’re in is that when a major attack happens, there’s focus from the legislative branch and the executive branch to do something,” Leo Simonovich, head of Siemens Energy’s industrial cyber security business, said. The actions that follow tend to be prescriptive, rapid and address the fallout of the specific attack, “but we need to get more proactive.”
He contended that cyber regulations are likely to become more abundant because attacks are happening and many of the critical infrastructure sectors are not regulated. “But what we need to see even more of is the platforms that enable public and private to come together,” including funding models that are transparent, use risk-based approaches, and enable flexibility for operators to account for differences in their cyber maturity curves, Simonovich said.
The cyberattack on Colonial Pipeline “served as a pretty serious wake-up call, though we’ve seen wake-up calls in the past that the federal government has kind of hit snooze on,” Rob Morgus, senior director of the US Cyberspace Solarium Commission, said in an interview. “Time will tell how serious the response is to the pipeline incident.”
Morgus was referring to the heightened attention placed on the midstream segment of the oil and gas industry in 2021 after a ransomware incident forced Colonial to shut operations for nearly a week, triggering gasoline and diesel price spikes, panic buying and supply shortages across the Southeast and East Coast.
Congress has since increased its attention paid to the security of the pipeline network and has floated legislation that could see passage in 2022.
Bills already introduced have called for updated pipeline security guidelines, identifying and protecting systemically important critical infrastructure and mandatory cyber incident reporting. The notion of liability protection for nonfederal entities who satisfy mandated security protocols but still suffer a cyber breach is also being debated, with support coming from the GOP.
“We’re beginning to see an emergence of camps here, and it’s going to take some interesting and likely difficult negotiation to get over it,” Morgus said. “Frankly, we could have another attack that hits people in their pocketbooks and makes people actually feel the pain of cyber risk, and that might unlock additional political capital to move something like this forward.”
Following a year that put the security of the US pipeline network under intense scrutiny, “everybody wants to know what the next threat is going to be,” said the American Petroleum Institute’s Suzanne Lemieux.
The latest cyber incident to hit the oil and gas sector caused North American propane distributor Superior Plus to “temporarily disable certain computer systems and applications” after falling victim to ransomware Dec. 12, the company said.
Parker Fawcett, an analyst at S&P Global Platts Analytics, said, “moving forward, increased digitalization across major upstream projects globally could put companies at higher risk of cybersecurity threats, but US shale would likely be less of a high-profile target due to the fragmented nature of the production and localized networks they operate on.” But he contended that small US shale operators with fewer resources to invest in cybersecurity “could be an easier target, albeit being a much smaller target” in terms of payout potential for a cybercriminal.
Lemieux said API is “just continuing to build expertise and build relationships across the industry to make sure that we are as prepared as possible.”
The group is also focused on overcoming challenges to implementing new cybersecurity protocols and ensuring its voice is heard as new regulations are likely to be put on the table in 2022.
Following the attack on Colonial, the Transportation Security Administration issued two security directives, making the pipeline sector subject to mandatory cybersecurity requirements for the first time. Those directives sunset in May and July of 2022 but are expected to be renewed while TSA crafts rules for a permanent cybersecurity program for pipeline systems.
“TSA itself will admit that they rushed to impose the security directives,” providing limited opportunities for stakeholder input and ultimately diminishing the effectiveness of the directives, the Association of Oil Pipe Lines’ John Stoody said.
Among the implementation challenges are mandates that apply to both IT and OT systems, which are operated differently and cannot handle new requirements in the same manner, according to API. Patching, for instance, can be completed relatively quickly on an IT system but must be conducted in a test environment and in consultation with equipment vendors for an OT system to ensure that any changes do not create system reliability concerns.
Companies and trade groups are working with TSA to educate it on different system configurations and come up with alternative measures or action plans to meet the new cybersecurity protocols.
But “TSA was not resourced to do the directives and they didn’t get any additional personnel or funds to implement this,” Lemieux said. “They’re running with limited resources and they’re under arbitrary timelines that just forced us into a challenging environment for both the operator and for the TSA. We don’t see that necessarily changing in 2022.”
Pipeline trade groups have jointly asked TSA to conduct an advanced notice of proposed rulemaking to ensure adequate industry input on what constitutes “reasonable, applicable, auditable, and sustainable regulations.”
“What we didn’t want is a regulatory proposal to pop out of the hat like a rabbit and repeat the same mistakes of the security directives, which were developed in isolation without knowledge or awareness of some of the technical issues that any type of proposal like that would face,” Stoody said.
TSA had said an ANPRM is under consideration, and is a tool the agency has successfully exercised in the past.