Shale Directories Conferences
SPRING 2022 Hydrogen & Carbon Capture Conference
April 21, 2022
Stay Tuned for Registration Details in January, 2022
Hilton Garden Inn, Southpointe
Canonsburg, PA
Latest facts and a rumor from the Marcellus, Utica, and Permian, Eagle Ford Plays
Rice Brothers, “Fracking Is Good.” (Thank you, Forbes) The Rice brothers, who control EQT Corp., America’s largest natural gas producer, argue fracking can help green the world.
EQT Corp. is a venerable player in the energy business, going back 133 years to the earliest days of gas drilling in Pennsylvania, with headquarters in a granite-and-glass tower in Pittsburgh. But you’d never guess that from a visit to the office of Toby Z. Rice, its 39-year-old chief executive. Rice works out of a converted tae kwon do studio upstairs from a state-run liquor store in suburban Carnegie, Pennsylvania, 15 minutes away from the city center. The dojo features a life-sized Iron Man sporting a gorilla mask on its head, graffiti-inspired art and a “Don’t Tread on Me” Gadsden flag.
How did this unconventional Millennial end up running the country’s largest producer of natural gas? By teaming up with family, lucking into the Marcellus shale formation at the right time and making very big bets.
Toby Rice’s partners in gas exploration are his brothers Daniel, 41, and Derek, 36. The capital that launched them was $70 million in loans from a trust funded by their father. They have done well parlaying that stake; the three are now worth more than $700 million.
The Marcellus is a shale deposit stretching underground from New York to West Virginia. Fracking technology made this layer of rock valuable overnight, just at the time the brothers were getting into the gas business.
Toby, Daniel and Derek grew up in Boston, living with their mother after their parents divorced. The boys played baseball and learned about business watching their entrepreneurial family of Armenian-immigrant cousins, aunts and uncles. Mom was a caterer, while their father, Daniel Rice III, managed a natural-resources portfolio at BlackRock. He made a windfall in hedge fund performance fees and decided his sons should do something big with it. “He planted the seed in our head,” Daniel the younger says.
But first they had to prepare. Daniel learned about oil and gas at Tyco, Transocean and the investment bank Tudor, Pickering, Holt & Co. Derek became a petroleum geologist, specializing in the new field of drilling shale formations. Toby, an All-American college baseball player who didn’t get drafted, worked as a roughneck on a Texas oil rig making $9 an hour (plus $2 in safety pay if everybody kept their fingers) and quit work on a master’s in hydraulic fracturing when the trio formed Rice Energy in 2007.
This was in the early days of the fracking revolution. There had been one big shale gas field developed at that point, the Barnett, near Fort Worth, Texas. The brothers went after the Marcellus shale of Pennsylvania, as much larger operators like Chesapeake Energy were also starting to lease drillable land there. Toby lived out of his truck, tracking down landowners to make deals to lease property passed over by the big guys.
“I’ve sat at more kitchen tables with more farmers and landowners than any politician in this region,” Toby says. Adds Daniel: “You start layering scraps onto scraps, and suddenly you have room for four wells.” Their dad stopped paying attention to the numbers in 2009, after questioning a $2,300 check Toby had written to the 4-H Club of Washington County, Pennsylvania. He had won a charity auction for a rabbit, outbidding his leasing rival Range Resources. It gets you noticed. “We stormed the basin,” Derek says.
Frackers use steerable drill bits that bore down two miles to intersect a thin layer of hydrocarbon-bearing shale, then turn sideways through the shale layer. After cementing pipe into the hole, the driller uses pinpoint charges to blast holes in the pipe, then fractures the rock by injecting millions of gallons of water mixed with sand down the pipe at high pressure.
The Rice brothers believed in overdoing it—blasting a ton of sand per foot of lateral distance, triple what others used. Shale wells in the Barnett were considered big if they came online at 4,000 MCFs per day. (An MCF, or 1,000 cubic feet, has the energy content of 8.6 gallons of gasoline.) Rice Energy was cranking out Marcellus wells doing 30,000 MCF per day.
“We were just hoping for something as good as the Barnett. Instead, we were early into the biggest natural gas field in the entire country,” says Derek, who lived in a trailer on rig sites and showered at truck stops. The brothers shared a meal with every new employee and named drilling projects after comic book heroes.
The trio raised $1 billion in a 2014 public offering for Rice Energy, with Daniel serving as chief executive, and another $400 million for a sister entity, a partnership that owned pipelines. Derek says he knew they weren’t smarter than anybody else: “Clearly our peers were going to copy our designs. And then supply is going to go through the roof.” Indeed, gas production out of the Marcellus has exploded, to 35 billion cubic feet (BCF) a day, nearly a third of the U.S. total.
“Mentally we were prepared to run this company forever,” Daniel says, but in 2017 EQT made a generous offer: $6.7 billion in stock and cash, plus the assumption of $1.5 billion in debt. The Rice family got about $200 million in cash and nearly 3% of EQT shares. EQT Midstream Partners acquired the Rice-founded pipeline partnership for another $2.4 billion.
But soon after the deals closed, the Rices started getting calls from unhappy shareholders. Under CEO Robert McNally, EQT had overspent its capital budget by $300 million. It was drilling bad wells where Rice had delivered barnburners. “We gave them their drilling schedule for three years,” Derek says. “They didn’t know what they were doing after three months.” EQT’s share price fell 45%.
These Energy Tycoon Brothers Insist Fracking Is Good for The Environment
Time for a proxy fight. Institutional investors backed the Rice slate of seven board members, who won 80% of the vote. In July 2019 McNally was out and Toby Rice was in. (Daniel is on the EQT board; Derek is an advisor.) The new boss shrank staff by a quarter, to 650, and invested in software and sensors. His Salesforce-enabled dashboard lets him see the conditions of 3,000 wells at 600 locations across 1.6 million acres.
In recent months EQT has acquired Chevron’s Marcellus operations for $735 million and Alta Resources’ for $2.9 billion. Those expansions vaulted the company to daily gas production of 5.5 BCF a day, ahead of No. 2 ExxonMobil.
Big bets are sometimes big mistakes. It’s common for commodities producers to use futures and options to presell production volumes and lock in prices. Toby overdid it with his hedges and was taken aback by this year’s runup in gas prices. His option trades took $3 billion out of 2021’s profits. But after adjusting its hedges, EQT is on target in 2022 to deliver $2 billion in cash flow (net income plus depreciation less maintenance-level capex) on revenue of $5 billion, analysts say. Its shares are up 40% since Toby took over, trailing some industry peers.
Many environmentalists, and a significant number of politicians, would like to put frackers out of business. Look at the numbers, the Rices retort: The shale gas revolution is the biggest reason annual U.S. carbon emissions have dropped nearly 1 billion tons since 2005, as power plants switch from coal to natural gas. Over the same period, China has increased its annual emissions by 4.7 billion tons, with coal use surging. EQT is eyeing the potential to liquefy Marcellus gas and export it out of the Philadelphia area. If that fuel gets to Asia and displaces coal, it will help mitigate climate change.
What about leaks of methane, a greenhouse gas more potent than carbon dioxide? Toby Rice pulls up a dashboard displaying details of a
$20 million program to replace 9,000 pneumatic valves at well sites with electric valves that leak almost no methane. He has enlisted Project Canary, a monitor of industrial emissions, to install the latest in laser-based sniffers. Canary cofounder Chris Romer boasts that these sensors are so good they can tell if a rig worker ate beans for lunch. It costs 2 cents per MCF to certify gas as responsibly produced. But that certification can fetch a premium of 3 to 13 cents per MCF.
“We’re not going after popular things like wind and solar. We’re going after things that make a difference.”
— DEREK RICE
Shares in EQT represent less than a quarter of the Rice brothers’ fortune. Via Rice Investment Group, the three have sponsored two special purpose acquisition companies. “We’re not going after popular things like wind and solar. We’re going after things that make a difference,” Derek says. One of those SPACs was for Archaea Energy, one of the biggest operators and developers of projects to capture fugitive methane that emerges from decomposing garbage in landfills. Catching such gas generates big tax credits, enough to yield $15 of revenue per MCF, versus $5 for regular gas. “We sell a decarbonized energy product to people who have to use fossil fuels,” says Archaea founder Nick Stork, 37. The Rice brothers own a quarter of the shares, worth $600 million.
Naturally, Toby feels he still has something to prove. That will surely require outgrowing the converted taekwondo studio. In his Dodge truck, he takes a visitor on a tour of a rundown mill complex on the banks of Chartiers Creek and Whiskey Run at the heart of Carnegie, the little town named after Pennsylvania’s most famous steel man. With so many mills shut down, its population is down by a third from its peak, but Toby foresees a revival. He wants to repurpose and rebuild a collection of warehouses and factories, creating spaces where staff will want to come to work even if they don’t have to, where they can help build what he calls a “shalennial” culture. “We will get back to doing lunch with every new hire,” he says.
2022 Integrated Energy Outlook: When will the bubble burst? (Thank you, S&P Global Platts)
In 2022, S&P Global Platts Analytics expects supply to catch up and even exceed demand growth highlighted by an increase in LNG exports, a rebound in US shale oil, gas and NGLs and the return of investment in non-OPEC production. Fears about the impact of new coronavirus variants, like omicron, on demand will add to volatility but are likely overblown. As an increasing amount of the world’s population with the highest GDP/capita become vaccinated, the potential magnitude of the impact on economic activity and demand will shrink. Aviation sector demand will likely be the most sensitive if infections become more severe but impacting a smaller number of flights as outbreaks become increasingly localized.
Prices will begin to normalize as inventories recover. Amid this process, we expect to see a greater divergence between oil and gas prices as oil starts to rebalance in the first quarter, while gas markets will remain tighter longer. Natural gas markets are vulnerable to price shocks if we experience the below-average temperatures we experienced last winter, particularly outside of North America. The divergence between oil and gas prices will see increased oil light-end products into traditional gas markets, tightening LPG supply, and by extension gasoline. At the same time, we expect strong demand growth for diesel to fuel commercial transport as supply chains debottleneck, as well as the gradual ramp up of aviation activity. While we expect stocks to recover during the year, the lack of spare capacity both in gas and oil, will leave the market vulnerable to disruption. This will be all the more difficult in light of a handful of geopolitical risks looming in key areas of supply: Iran, Libya, and Nord Stream 2. Any disruption in global supply chains will also have outsized influence on prices. While oil prices have recently corrected downward, the key test will come in the third quarter as summer demand challenges supply resilience – the absence of an Iran deal could leave the market vulnerable to breaking $100 per barrel ($/b) if combined with any other disruptive event.
Despite the increased rhetoric and focus on energy transition demand for all fossil fuels will increase in 2022, requiring more fossil fuel supply. Even though some companies and investors are looking to divest from fossil fuels, we see healthy levels of investment in 2022 and beyond prompting an easing of energy prices. Expect a ripple effect into other commodity sectors, including metals and agriculture, impacting the current commodity bubble. Even after the bubble pops, energy markets will only become more intertwined. Fundamentals and data will matter more than ever, requiring a steady, holistic perspective across the breadth of the energy market. Platts Analytics will continue to strive to bring clarity to the energy markets, enabling our customers to act with conviction in 2022.
TOP TEN KEY THEMES TO THE 2022 ENERGY OUTLOOK: S&P GLOBAL PLATTS ANALYTICS:
- As the first quarter goes, so goes the year. Prices across all commodity markets will by and large end 2021 at elevated levels, even if some will have slipped from peaks achieved earlier in the year. Generally, low inventories and fears of supply inadequacy over the Northern Hemisphere winter expose prices to extensive upside risk in the first quarter, particularly natural gas prices. If winter weather proves to be colder than normal in key markets (China, Japan, Europe), inventories will draw further, and prices will spike even higher. La Niña conditions make cold weather more likely in these markets. Conversely, a mild winter will ease pressure, allowing prices to normalize faster. Key geopolitical risks, such as the Iran Deal and Nord Stream 2, will have notable signposts in the first quarter, and even if they are not fully resolved in by the end of March, their status will have a large bearing on how balances and prices shape up over the rest of the year.
- After 2021 focused on energy demand recovery, 2022 will focus on whether supply can catch up. In virtually all energy commodity markets, demand rebounded more than supply in 2021, resulting in a drawdown of inventories and much higher pricing. In 2022, energy supply will grow faster, not only to catch up to 2021 demand, but also to cover additional demand growth in 2022 and to rebuild depleted inventories. While this will be a difficult lift for the supply side under normal circumstances, several key commodities and markets face considerable geopolitical risks to supply growth. While the demand side is certainly not without risk, particularly with the new COVID variant, any disruption in global supply chains will have outsized influences on prices.
- Deal or no deal: Iran is the key Iran will significantly influence oil balances in 2022, and by extension, oil prices. We assume a framework US-Iran nuclear deal will be reached in Q1, with full sanctions relief by April, facilitating 1.4 million barrels per day (b/d) of Iranian oil supply growth by the end-2022. But risks that no deal can be reached are high. Even with Iranian barrels coming back, oil markets will need more supply from the rest of OPEC by mid-year. If Iranian oil does not come back to the market, OPEC capacity will be pushed to the limit. Tensions in the Middle East will only worsen with a defiant Iran. The lack of an Iran deal, if coupled with supply interruptions elsewhere, could see oil prices test $100/b.
- New COVID variants will continue to impact oil demand but vaccinations will blunt the impact and release some pent-up demand. The rise of the omicron variant in November has raised fears that the recovery in oil demand will be derailed by renewed restrictions to mobility. While S&P Global Platts Analytics expects that new variants and localized outbreaks will occur in 2022, we do not expect the same magnitude of restrictions on mobility, particularly international air travel, that occurred in 2020 and early 2021. We project that oil demand will increase by over 4 million b/d in 2022. Even in a case where COVID proves to be more disruptive than expected, oil demand will still increase by almost 3 million b/d at a minimum, as vaccinations continue to build globally, and importantly, in countries with high GDP per capita. Oil demand growth could exceed 6 million b/d if we revert to normal more quickly. The strength in demand will push refinery runs and utilization rates (even including increased refining capacity) close to their historical ranges, improving margins.
- Global natural gas prices will hinge on the Nord Stream 2 pipeline and Russia’s gas strategy. Currently, Russia is the primary source of the world’s spare capacity and delivering that supply to markets eager to meet demand and rebuild storage will dominate balances and prices in 2022. The delayed Nord Stream 2 pipeline is essential to boosting Russian gas supply into Europe as Russia is shifting away from Ukraine transit and Electronic Sales Platform (ESP) sales. Despite the fact that Europe is desperate for gas supply, regulators appear to be in no rush to sign off on Nord Stream 2. While S&P Global Platts Analytics expects the pipeline will begin operations in June, further delays would cause European buyers to scramble for alternative gas supply, boosting not only European gas prices, but global LNG prices. Even US prices would get an uplift from this, as US LNG exports will ramp up further in 2022.
- Three to five North American LNG liquefaction projects will make final investment decisions after a two-year hiatus. Strength in global gas prices have bolstered the value proposition of incremental LNG liquefaction projects in North America, particularly in Western Canada and the US Gulf Coast, breathing new life into the prospect of an additional wave of North American LNG. Despite the prospect of slower LNG demand growth in Asia over the next few years, developers have been able to line up buyers and equity investors for potential capacity, which increases the likelihood these projects will come to fruition.
- India to surpass China as world’s largest importer of thermal coal as China drives for self-sufficiency. 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. Despite higher domestic consumption, China’s thermal coal imports are expected to decline in 2022, as domestic production will increase by an even larger extent, as policymakers press for more self-sufficiency. At the same time, the import constraints India encountered in 2021, such as record high coal prices and freight rates, will be less severe in 2022, allowing imports to increase strongly to meet higher domestic demand and rebuild depleted stockpiles.
- New planting seasons offer new beginnings for agricultural commodities, but tight fertilizer supply and La Niña skew risks to the upside. Demand for food and renewable fuels will continue to increase, which will keep prices well supported and challenge biofuels and renewable fuels economics. Tight fertilizer supply, in the wake of turndowns of production facilities due to high natural gas prices in 2021, coupled with the rise of potentially dry conditions in Brazil from La Niña, are key supply constraints for agriculture and biofuels markets. The fate of Brazil’s second season (safrinha) corn crop will have direct and large implications on prices and demand for US exports. Renewable diesel demand for US soy oil will gain again in 2022, while Brazilian production will cover most of China’s small increase in demand.
- CO2 emissions to hit record high in 2022 despite greater focus on climate putting emissions policy on the ballot in key markets. Despite the focus on emissions reductions and a lengthening list of countries that have made net zero targets, we expect that CO2 emissions from energy combustion will increase by 2.5% in 2022 to new record levels, as some economies fully recover while others push for growth. While leaders at COP26 pledged to strengthen 2030 emissions targets by the end of 2022 rather than waiting for the formal “stock taking” process, there are significant risks to domestic environmental policy agendas from elections in 2022. Midterm elections in the US could derail the Biden Administration’s environmental agenda, while Australia’s opposition party is looking to oust the more conservative government by making stronger environmental targets a priority. These elections are reminders that “all politics are local” and the fates of global agreements are often determined by domestic elections, public sentiment, and policy shifts.
- Strong power prices boost renewables installations, but can they deliver with rising input costs and policy risks looming? Strong power prices have pushed renewable power margins to historically high levels and boosted prospects for faster installation growth in 2022. This is ironic since the underperformance of renewables was a key factor behind the surge in global power prices in the first place. Despite a ~10% increase in commissioning costs due to historically high raw materials prices and labor issues, S&P Global Platts Analytics expects solar PV additions will increase by 4% in 2022, while onshore wind installations increase by 1%. Capacity growth is predicted to decline for offshore wind, which will contract by 25% in 2022 after a strong 2021 due to the phase out of subsidies in China. The world will need to develop policies that balance the need to add zero carbon electricity supply with the cost of the dispatchability/availability of oftentimes intermittent renewable power with storage options.
Good January for the Appalachian Basin. Oil and gas production from the Utica and Marcellus shale formations is expected to increase in January, according to data from the U.S. Energy Information Administration.
The EIA’s Drilling Productivity Report shows that natural gas output stands to increase 78 million cubic feet per day by next month in the Appalachia region, which includes eastern Ohio’s Utica play and the Marcellus shale in Pennsylvania and West Virginia.
This week, Hilcorp Energy Co. filed applications with the Ohio Department of Natural Resources for permits to deepen three of its wells in Fairfield Township in Columbiana County.
So far this year, Hilcorp Energy Co. has been awarded 14 permits from ODNR to drill new wells in Columbiana County and one permit to deepen an existing well.
EAP Ohio has been awarded seven permits for new wells in the county, and five permits to deepen existing wells.
There were no new well permits issued in either Mahoning or Trumbull counties this year.
Oil in the Appalachia region is expected to tick upward by 1,000 barrels per day next month, according to EIA.
The agency reports that gas production is anticipated to increase in six of the seven shale plays across the country.
The Permian Basin in Texas stands to post the greatest increase at 115 million cubic feet per day in January, while the Anadarko play in Oklahoma is projected to see production drop by 31 million cubic feet per day.
Overall natural gas production among the country’s seven shale plays is projected to grow by 341 million cubic feet per day to 89.3 billion cubic feet daily, the EIA reports.
Oil production across these shale regions is expected to increase by 96,000 barrels to 8.4 million barrels per day. The Permian play is anticipated to experience the largest single increase, boosting output by 71,000 barrels per day, according to EIA data.
Appalachian Basin Optimism in 2022. Appalachian natural gas industry sees optimism for 2022. At a major shale conference this week in Pittsburgh, the Appalachian natural gas industry worked to make sense of what has been an unexpected 2021 and mostly expected a positive year ahead, with some caveats. Much of Hart Energy’s DUG East Conference, the first time it was held since December 2019 in a very different shale landscape, discussed not only what was happening in the Appalachian gas industry but also how it could position itself amid challenges from the market, competition with renewables and the challenges from more government regulation and attention on emissions.
NatGas Demand to Grow by 25% by 2030. TC Energy Corp. expects North American natural gas demand to grow 25% by 2030, a top pipeline executive told investors earlier this month.
NatGas demand forecast
Demand would mainly be driven by coal-to-gas switching in the power sector and global demand for liquefied natural gas (LNG), TC’s Tracy Robinson, president of the Canada natural gas pipelines unit, said at the annual investor day.
Gas supply from the Western Canadian Sedimentary Basin (WCSB) and the Appalachian Basin, two of the main sources of gas flowing on TC pipes, is set to grow by a combined 13 Bcf/d by the end of the decade, Robinson said. She cited the competitiveness of the basins’ gas supply, with high natural gas liquids content in the WCSB and high well productivity in the Appalachia.
The executive also highlighted that North American LNG has some of the lowest emissions intensity in the world.
TC is aiming to ensure the WCSB “has the right amount of competitively priced capacity” to supply gas to the rest of the continent.
Compared with 2020, natural gas flows to date on TC’s Canadian Mainline are up 24% this year, with Nova Gas Transmission Line up 13%, Robinson said.
For 2021, TC expects to bring more than $1.3 billion worth of pipeline projects into service in Canada, part of a larger expansion underway since 2017. By the time the expansions are completed in 2024, “we’ll have positioned our assets effectively” in the WCSB’s Montney Shale, “and added 3.5 Bcf/d of delivery capacity to multiple markets,” Robinson said.
In addition, the 2.1 Bcf/d Coastal Gaslink (CGL) pipeline, which would supply gas to the LNG Canada export project in British Columbia, is more than 50% complete, Robinson said.
TC management said in its 3Q2021 report to shareholders it expects CGL “project costs to increase significantly along with a delay to project completion compared to the original project cost and schedule.”
This is because of the “scope changes, previous permit delays…and the impacts from Covid-19, including a British Columbia provincial health order,” the company said.
What’s Driving U.S. Natural Gas Demand Growth?
In the United States, meanwhile, natural gas demand is set to grow by 22% between 2020 and 2030, said TC’s Stanley Chapman III, president of U.S. and Mexico natural gas pipelines. LNG exports are expected to drive the growth, augmented by pipeline flows to Mexico.
TC’s pipelines deliver about 27% of natural gas consumed in the United States, Chapman said, noting that throughput across the U.S. pipelines is up 5% year-to-date.
“Similarly, Lower 48 production will grow commensurately,” Chapman said, with the Permian and Appalachian basins, as well as the Haynesville Shale leading the way.
TC placed $900 million worth of U.S. projects in service during 2021, with another $7 billion of growth, modernization and maintenance projects equating to 10-15 Bcf/d slated to enter service between 2022 and 2025. Another $500 million of projects are awaiting final investment decision.
Chapman said “contrary to what you may hear about our business, both the near and longer-term fundamentals are relatively healthy. In the short-term, as the pandemic winds down, worldwide economic growth has created strong demand for goods, services and energy at a pace that has exceeded that of supply.”
Chapman said “given the breadth of our extensive pipeline network, in any given year I believe we should be originating about $1 billion of new growth projects.”
In the United States, TC has growth projects “in some form of origination on virtually all of our 13 pipes, all of which are primarily in-corridor, permittable, constructable, compression-related expansions,” he said.
TC is expected to win large projects related to coal-fired power plant retirements, which “may include opportunities for us to continue to electrify our compression fleet.” Chapman said. “For example, there are 16 coal plants within 15 miles of our Columbia and ANR pipelines that currently generate about 16 GW of capacity and have announced retirements by 2025.”
While a large portion of new capacity would be replaced by renewables, “there still will be a residual need for 1-2 Bcf/d of incremental pipeline capacity for reliability purposes…directly adjacent to our footprint.” Chapman said.
On the energy transition front, TC would need to electrify one to two U.S. compression stations per year for the rest of the decade, requiring potential capital investments of $1-2 billion over that timeframe, he said.
Renewable natural gas (RNG), meanwhile, “remains a focus point” as TC looks to grow its footprint from 11 RNG interconnects and 4 Bcf of gas/year today, to 40 RNG interconnects and more than 30 Bcf of gas annually by 2025. This could require deployment of more than $200 million.
Longer-term, TC expects to see more opportunities around carbon capture, utilization and storage, as well as hydrogen, Chapman said.
“In 2022, I’d like to see us lay the foundation for, if not implement, a pilot program around hydrogen blending.” TC “will invest in these technologies when they can be deployed safely and generate a return that successfully competes for the capital against the other growth opportunities that we have.”
Permian Output Expects to Reach Record in December. U.S. expects Permian oil output to reach record in December. Crude production in the Permian Basin is expected to surpass a pre-pandemic high this month as a rebound in the U.S. shale industry fuels activity in its most prolific patch. Supplies from the Basin, which straddles West Texas and New Mexico, is projected to reach 4.96 million barrels a day in December, the Energy Information Administration said Monday in a report. The current record of 4.91 million barrels a day was set in March 2020. The agency also sees supplies exceeding 5 million barrels a day next month for the first time in data going back to 2007. Note: Petroleum Economist also reports.
32 NatGas Powered Plants in the Pipeline. Recent reports from groups analyzing U.S. power generation note how states near the nation’s largest shale plays are expected to bring significant new natural gas-fired generation online over the next few years, despite concerns about recent market volatility that sent gas prices to their highest levels in more than a decade.
With a long-term outlook favoring natural gas as U.S. coal stockpiles continue to dwindle, utilities are moving forward with plans to add gas-fired generation capacity through 2025, according to Colorado-based BTU Analytics, a FactSet Company. Andrew Bradford, Vice President Power for FactSet, told POWER on Dec. 14 his group “is tracking 32.3 GW of natural gas-fired power plants with in-service dates through 2025 that are in advanced stages of development.” Bradford said “14.2 GW have a status of under construction, 3.4 GW are at pre-construction, and 14.7 GW have a status of advanced permitting.”
Bradford said the PJM and MISO regions, along with the U.S. Southeast, are the most-active new-build regions with 15.8 GW, 3.8 GW, and 6.2 GW, respectively, planned to come online over the next few years.
“It is important to think about all of these different generation types as backstops for each other,” said Sarp Ozkan, Senior Director of Power & Renewables Analytics at Enverus. “So, as the price of natural gas as the fuel increases, the backstops like coal and fuel oil become more competitive and are called upon to serve the load. As the price of natural gas as the fuel decreases, coal and fuel oil get moved further away from being in the money.”
Ozkan on Tuesday told POWER that “natural gas provides two distinct advantages. One advantage is that it is dispatchable, making it necessary for peak demand periods. Additionally, it is the cleaner in terms of emissions profile than coal and fuel oil.”
EIA Expects 6% Rise in Gas-Fired Capacity
Though not as bullish as the BTU Analytics’ numbers, the U.S. Energy Information Administration (EIA) in its Monthly Electric Generator Inventory published in November said it expects 27.3 GW of new natural gas-fired generation capacity to enter operation from 2022 to 2025, a 6% increase above the current 489.1 GW of U.S. capacity as of August 2021. The agency said its data shows that most of the planned new gas-fired capacity will be built in the Appalachia region, which includes the Marcellus and Utica shale plays across West Virginia, Pennsylvania (Figure 1), and Ohio. Those plays accounted for more than one-third of all U.S. dry natural gas production in the first six months of this year.
The Salt River Project in Arizona recently approved an expansion of the Coolidge Generating Station, with a plan to add 16 gas-fired turbines to the site. Go here to read more about that project.
“Proximity to supply is always important. It avoids high transport costs and allows for a more competitive fuel price,” said Ozkan. “In cases where the natural gas demand from a power plant is behind a constraint in the natural gas infrastructure and in close proximity to the best resources [for example: the core of the Marcellus, Utica, or Haynesville], natural gas prices will be the most competitive and keep the plant in the money against the backstops.”
Illinois, which has pipeline access to Utica and Marcellus gas, accounts for 3.8 GW of new gas-fired capacity scheduled to come online over the next four years, according to EIA. The group said other states utilizing gas from those plays include Michigan, with 3.2 GW of new capacity planned; Ohio (2.9 GW); and Pennsylvania (1.9 GW).
- The Hickory Run Energy Center in Pennsylvania was a POWER Top Plant award winner in 2021. The facility features two Siemens SGT6-8000H gas turbines, two John Cockerill Energy heat recovery steam generators, and one Siemens SST6-5000 steam turbine. The 1,000-MW plant came online in 2020, one of several gas-fired power plants in a region with abundant natural gas resources. Courtesy: Kiewit
Florida also has 3.2 GW of new gas-fired generation capacity scheduled. Regional pipeline networks for natural gas have continued to expand in that state. EIA said five new gas-fired plants are expected to enter commercial operation over the next four years in Florida, where utilities also are rapidly expanding their solar power generation capacity.
New Ohio Plant Comes Online
One of the most recent new plants to enter commercial operation is the 1,182-MW South Field combined cycle gas turbine plant (Figure 2) in Ohio. Bechtel completed engineering, procurement, and construction work at the new $1.3 billion facility in October.
Not every project sited in recent years is moving forward, though, and some gas-fired power plant projects have been canceled. Robinson Power, a Pennsylvania company with plans to build a 1-GW facility known as Beech Hollow, recently withdrew its request for a permit from the state’s Dept. of Environmental Protection (DEP). The company had altered plans for the project several times, though each of those designs had been approved by the DEP despite opposition from environmental groups.
- The South Field Energy power plant in Columbiana County, Ohio, entered commercial operation in October 2021. The 1,182-MW facility is located on fewer than 20 acres of land that is part of a 150-acre parcel about three miles from Wellsville. The facility uses two General Electric gas turbines, each with a heat recovery steam generator and steam turbine generator. Advanced Power and an investor group including Japanese banks and power companies own the facility. Courtesy: South Field Energy
The 1.1-GW Charles City Combined-Cycle Gas Turbine Plant in Virginia, known as C4GT, was canceled in July. The nearby 1.6-GW Chickahominy Power Station, though, located about one mile from the C4GT project, remains under development, despite opposition to both the plant and an accompanying 83-mile gas pipeline.
‘Natural Gas Generation’s Reliability is Key’
Bradford told POWER that gas-fired generation, particularly in areas with ready access to a steady supply of natural gas, will remain important even as more utilities and governments support growth of renewable energy.
“As much as some environmentalists would like to accelerate to a net-zero emission future without natural gas, it is hard to see how that happens,” Bradford said. “What Winter Storm Uri in ERCOT in February 2021 highlighted yet again is in the energy industry redundancy and reliability at scale are paramount. Until a low-cost, large-scale, long-duration battery comes to market, natural gas power generation’s reliability at scale is key.”
Natural gas prices in October hit their highest levels since 2008, leading some generators to burn more coal, but a warmer-than-normal start to the winter season across much of the country has sent gas prices into retreat as inventories of the fuel have risen. Government data released Tuesday indicates U.S. utilities will leave enough gas in storage to allow stockpiles to reach above-normal levels by year-end for the first time since April of this year.
Bradford said his group “expects following winter 2021-2022 for HH [Henry Hub] to price just above $3.00 per MMBtu on average through 2025 as capital-disciplined E&Ps [exploration and production companies] deploy capital ratably to respond to stronger pricing. While BTU’s Henry Hub forecast is slightly higher than the last several years of Henry Hub cash pricing, we do expect the strong coal burns in 2021 to decline as natural gas should price more competitively relative to coal in 2022.”
Market for Gas Favorable vs. Coal
Bradford said a favorable market for natural gas vs. coal means “gas-fired generation in 2022 should be up slightly at 31.0 Bcf/d vs. 2021 at 30.8 Bcf/d. BTU Analytics expects gas-fired power generation to climb to 31.7 Bcf/d by 2025 as increases in new gas capacity and further coal retirements are offset by competition from renewables and continued retirements of older-dated gas units.”
The EIA earlier this year said more than 60 GW of natural gas-fired generation capacity has been added across the U.S. since 2014. Some utilities, including Duke Energy, have warned of new gas plants becoming stranded assets even as Duke itself earlier this year said it could build as much as 9.6 GW of gas-fired capacity in the Carolinas, to help meet demand for electricity as coal plants retire. The utility also is investing heavily in solar and wind power.
Duke Energy on Tuesday said it has completed a retrofit at its Marshall Steam Station in North Carolina, enabling all four units of the 2-GW facility to burn natural gas along with coal. The Marshall project was the last piece of a $283 million endeavor begun in 2016 to convert eight coal-burning units at Duke Energy plants to burn at least some natural gas.
“The multi-decade investment thesis for new natural gas-fired combined cycle baseload power plants continues to be under pressure from renewables and now the energy transition and a race to a net-zero future,” said Bradford. “There are investment teams that have pitches of how gas-fired power plants can play in a net-zero future for existing and new-build assets. Solutions include hydrogen blending, carbon capture and sequestration, and other emerging combustion technologies … however, many of these projects are early stage, expensive and at smaller scales. Gas-fired power assets that can ramp quickly to backfill a duck curve and have a net-zero solution will likely see more attention by investors going forward.”
Ozkan reiterated natural gas’ importance as “a dispatchable resource with a cleaner emission profile than its backstops. As electrification continues and the mix of renewables in the generation mix grows, to keep the grid reliable we will need dispatchable generation or utility-scale storage. Natural gas-fired generation is very attractive as it is both dispatchable, and has a cleaner emissions profile than its backstops like coal and fuel oil.”
Bradford again pressed on the importance of location for new gas-fired power plant construction. “The Marcellus Shale has always had the advantage of proximity to the large U.S. East Coast population,” he said. “Gas plants located in the Marcellus will continue to have the advantage of access to decades of low-cost drillable gas inventory. The Permian [in Texas] is in a similar spot in terms of low-cost inventory and has the advantage of power load growth tied to oil production. Again, E&Ps are focused on ESG [environmental, social, and governance] goals, so any power needs to drive oil production will need to help E&Ps meet their ESG goals.”
MVP Gets VA Permit. Virginia board OKs stream-crossing permit for gas pipeline. A Virginia board has granted a waterbody crossing permit for the Mountain Valley Pipeline. The State Water Control Board voted 3-2 on Tuesday to grant a permit for the natural gas pipeline to cross about 150 streams and wetlands in southwest Virginia, The Roanoke Times reported. The pipeline still needs a similar permit from West Virginia and federal approval.
Exxon Starts PetChem Expansion. Exxon Mobil starts construction on $2B Baytown chemical expansion. Construction has started on a roughly $2 billion expansion at Exxon Mobil Corp.’s petrochemical manufacturing complex in Baytown — the largest in the United States — one of the project’s contractors said. The Irving, Texas-based company is adding an alpha olefins unit and a performance polymers unit to the complex, the company said. The additional units have been in the works since at least 2018, according to documents filed with the Texas comptroller’s office. The company made a final investment decision, or FID, on the project in May 2019.
Permian Merger Mania Coming. Permian merger mania heats up with the birth of a $4 billion shale oil giant. Investment firm EnCap has merged two of its portfolio companies to create a shale oil producer in the Permian worth $4 billion, Reuters has reported, citing unnamed sources familiar with the matter. Advance Energy Partners and Ameredev II both operate in the Delaware Basin and, according to the report, will see total Permian oil production reach 5 million bpd for the first time as soon as next month.
Jet Fuel Inventories at 7-Year Low. U.S. inventories of jet fuel reached a seven-year low last month as mounting demand intersected with lower production, federal researchers said in a report Monday.
EIA Jet Fuel
Jet fuel supplies had increased over the summer months as refineries ramped up output to meet rebounding demand for gasoline and distillate fuels. Refiners processed more crude to meet that demand, and jet fuel is a byproduct of oil refining.
However, the U.S. Energy Information Administration (EIA) said refiners tapered output during the fall, in part because of hurricane-induced outages. Driven by mounting air travel trends, demand for jet fuel quickly surpassed production.
“This increased demand, along with reduced production, has caused inventories to decline,” EIA researchers said.
Stockpiles of the transportation fuel fell to the lowest level since 2014 during the week ended Nov. 26, according to EIA’s Weekly Petroleum Status Report (WSPR). Supplies stood at 36.1 million bbl that week, down about 1% from year-earlier levels.
However, in its latest WPSR, covering the week ended Dec. 3, EIA said that the jet fuel trajectory suddenly flipped.
The new Omicron variant of the coronavirus forced at least a temporary pullback in air travel that week. Overall demand for petroleum products in the Dec. 3 period dropped 2% week/week, led lower by a pullback in jet fuel consumption. Jet fuel demand of just 1.2 million b/d for the latest covered week was the lowest since the week ended June 4. It had topped 1.7 million b/d during the Nov. 26 week.
Jet fuel inventories for the Dec. 3 period increased 2% week/week.
Rystad Energy analyst Louise Dickson said the new variant reminded that the virus remains a wildcard that could cause sharp retreats in demand, particularly if cases surge and travel restrictions are imposed. She noted this is a global challenge.
Rystad’s data for the Dec. 3 week “registered the biggest weekly demand drop in countries facing large Covid-19 caseloads,” including Russia and India, Dickson said.
U.S. demand for petroleum products nevertheless is holding strong relative to 2020, when consumption was curbed by the pandemic’s fallout and vaccines were not yet available.
Over the past four-week period, demand averaged 20.9 million b/d, EIA said, up 10% from the same period last year. Over the past four weeks, motor gasoline consumption averaged 9.1 million b/d, up by 14%, and distillate fuel demand averaged 4.1 million b/d, up 6%. Jet fuel product supplied was up 27% to 1.5 million b/d.
Total U.S. oil inventories, excluding those in the Strategic Petroleum Reserve, decreased by 200,000 bbl from the previous week. At 432.9 million bbl, inventories for the Dec. 3 week were 7% below the five-year average.
The Rice brothers, who control EQT Corp., America’s largest natural gas producer, argue fracking can help green the world.
Onshore Flaring Way Down. U.S. onshore gas flaring lowest since 2012 in Q3- Rystad Energy. U.S. onshore gas flaring dropped to its lowest since 2012 in the third quarter of 2021, led by declines in the Bakken and Permian basins, as more companies attempt to minimize the burning off of excess gas, consultancy Rystad Energy said on Wednesday. Rystad said flaring activity in September fell about 24% from the prior month to 380 million to 390 million cubic feet per day (Mcfd). The reduction in the Bakken was in line with expectations while the change in the Permian Basin, the nation’s largest oil field, was surprising, Rystad said.
O&G Going High Tech. Oil and gas industry to spend $15 billion on a tech transformation. The oil and gas industry is set to spend $15.6 billion on digital transformation by the end of this decade to enhance cybersecurity, maintain safe operations, and create sustainable performance, technology intelligence firm ABI Research said in a new report on Wednesday. Currently, the oil and gas sector face operational, commercial, and existential threats due to increased pressure to reduce emissions, protect against cyberattacks, and maintain the reliability and safety of operations, ABI Research said.
Climate Change Could Kill 600 Billion Barrels. Climate change imperils world’s oil and gas reserves: research. Reuters. Much of the world’s reserves of oil and gas is under threat from rising tides, storms, floods and extreme temperatures caused by climate change, risk consultancy Verisk Maplecroft said on Thursday. Access to the equivalent of 600 billion barrels or 40% of the world’s recoverable oil and gas reserves could be affected by the wild weather, with major producers Saudi Arabia, Iraq and Nigeria among the most vulnerable, the UK-based firm wrote in a research note.
Pipelines Are Empty. About half of U.S. oil pipeline space is empty after boom time building spree. Reuters. About half of U.S. oil pipeline space is sitting unused, heating up competition for barrels in higher-output areas like the Permian Basin in Texas. Overall U.S. pipeline capacity utilization is at around 50%, compared with a range of 60% to 70% headed into early 2020 before the coronavirus pandemic hit, according to consultancy Wood Mackenzie.
PA Permit December 9, to December 16, 2021
County Township E&P Companies
- Bradford Asylum Chesapeake
- Bradford Asylum Chesapeake
- Bradford Asylum Chesapeake
- Bradford Asylum Chesapeake
- Green Jackson EQT
- Green Jackson EQT
- Green Jackson EQT
- Green Jackson EQT
- Westmoreland Hempfield Apex Energy
- Westmoreland Hempfield Apex Energy
OH Permits December 6, to December 10, 2021
County Township E&P Companies
- Belmont Rose EOG Resource
- Monroe Benton Diversified Res.
- Monroe Benton Diversified Res.
WV Permits November 29, to December 3, 2021
- Marshall Tug Hill
- Pleasants Jay-Bee O&G
- Tyler Antero
- Wetzel Tribune Resources
- Wetzel Tribune Resources
- Wetzel Tribune Resources
- Wetzel Tribune Resources
- Wetzel Tribune Resources
- Wetzel Tribune Resources
