Shale Directories Conferences
SAVE THE DATE!
Utica Green Upstream & Midstream Conference
March 25, 2022
Pro Football Hall of Fame
Canton, OH
SPRING 2022 Hydrogen & Carbon Capture Conference
April 21, 2022
Registration OPEN NOW! (this will sell out)
Hilton Garden Inn, Southpointe
Canonsburg, PA
Latest facts and a rumor from the Marcellus, Utica, and Permian, Eagle Ford Plays
Appalachian Drillers Still Cautious. A major artic blast came with the new year across the Eastern United States, leading to a spike in natural gas prices on top of already multi-year highs in a volatile market. For now, most producers in the Marcellus and Utica shales across the Pennsylvania, West Virginia and Ohio fairway are refraining from exponential drilling and production growth.
Following December weather that was generally more fitting for backyard cookouts than sleigh rides, a “landmark” arctic blast ushered in the new year across most of the U.S. eastern seaboard. As usual, it sparked healthy prices for Appalachia basin natural gas.
However, unlike winter heating seasons past, the February 2022 forward price spikes of more than $2/MMBtu came on top of multi-year highs in the still-volatile gas market. Also indicative of the current environment, most producers in the dry and wet gas-laden Marcellus and Utica shales across the Pennsylvania, West Virginia and Ohio fairway are, for now, refraining from exponential drilling and production growth, even as prices are expected to settle out around $4/MMBtu this year.
While acknowledging current gas prices are “well above our break-evens,” Chesapeake Energy Corp. President and CEO Domenic Dell’Osso echoed a number of his contemporaries, telling analysts on Nov. 3, “We don’t want to chase higher prices in the near term with a rapid growth ramp. We feel prices should moderate, but the backwardation (current vs. futures pricing) you see out to 2023, and even out to 2024, delivers a pretty great price for natural gas.”
Chesapeake may not be chasing higher prices, but it certainly is not shying away from deals. On Jan. 25, the company agreed to pay around $2.6 billion to acquire a reported 113,000 net Marcellus acres and up to 200 MMcfd of incremental production from tightly held Chief E&D Holdings LP. The cash and stock deal—Chesapeake’s second major acquisition since emerging from bankruptcy on Feb. 9, 2021—is expected to close in the first quarter.
In the meantime, Chesapeake plans to continue a three-rig Appalachian drilling program in 2022, with 50 to 60 wells drilled and turned-in-line and projected cumulative year-end production of 1,095 to 1,125 Bcf, up from around 790-810 Bcf in 2021. “When we laid out 2022 spend ($1.45 billion), we knew the Marcellus has takeaway constraints, so there’s a limited amount of capital that makes sense to spend there,” he noted.
Nagging takeaway constraints got some relief in December, when Williams Companies’ Leidy South expansion went in service with a designed capacity of 582.4 MMcfd. The pipeline and gas gathering project expands the company’s existing Pennsylvania infrastructure to connect with the consumer-rich Atlantic Seaboard.
Meanwhile, the U.S. Energy Information Administration (EIA) estimates the Appalachian region will produce 35,069 MMcfd of gas in February (Fig. 1), up by 559 MMcfd compared to production during the epic freeze-out of February 2021.
As for new drills, around 42 rigs were active in the combined Marcellus and underlying Utica plays in January and early February, with the former down two rigs from the same 2021 timeline, according to Baker Hughes. The wetter and costlier Utica, however, saw a sizeable year-over-year jump, going from an average four active rigs in January 2021 to 11 rigs last month.
Gulfport Energy Corp. is running one of those rigs in eastern Ohio, where it exclusively targets the Utica in a 193,000-net-acre leasehold, where full-year 2021 net production was expected to average 980 to 1,000 MMcfed. Gulfport drilled roughly 20 net wells last year with 17 net wells turned-in-line.
Third-quarter production came in at around 700 MMcfed, of which 250 MMcfed came courtesy of the six-well Angelo pad in Jefferson County, Ohio, with average horizontal reaches of 17,026 ft, Fig. 2. The pad was completed with simul-frac technology and put online some 30 days ahead of schedule. The five-well Limestone pad and the four-well Extreme pad to the immediate north, with planned lateral reaches averaging 17,039 ft and 13,866 ft, respectively, figure prominently in the company’s 2022 development program.
While 90% of the activity of pure-play Antero Resources Inc. will continue to be in the lower-cost Marcellus, the company deployed one rig to the Ohio Utica in late 2021 for the first time in nearly four years. Antero, the nation’s second-largest natural gas liquids (NGL) producer, averaged net production of 3.25 Bcfed in the third quarter. The company’s long-range guidance calls for net production of 3,300 to 3,400 MMcfed between 2021 and 2025.
Antero wrapped up 2021 with 65 to 70 net wells drilled and 60 to 65 completed. The company is operating three rigs and one completion crew on a more-than-542,000-net-acre leasehold in the southwestern core of the Marcellus and Utica.
The historical price increases of late have been attributed in no small part to the advancing globalization of the domestic natural gas sector, namely the proliferation of liquefied natural gas (LNG) exports, concentrated primarily along the U.S. Gulf Coast. To tap into that market, deeply rooted Appalachian producers Chesapeake and Southwestern Energy Co. paid just over $4 billion, combined, last year to either expand their foothold or establish a position in Louisiana’s gas-rich Haynesville shale.
Appalachian pure-play operator EQT Corp., however, negotiated ample firm transportation commitments to the Gulf Coast, thereby precluding the need to snap up assets closer to LNG terminals. “We’ve got over 1.2 Bcf a day of firm transportation down to the Gulf, which is almost the largest position of any producer down there in the Haynesville. So, we’ve got a significant amount of exposure down there,” says President and CEO Toby Rice.
On the other hand, between a growing petrochemical network, increasing residential and commercial power generation, not to mention the 1.8-Bcfd export capacity of the Cove Point LNG facility in Lusby, Md., others believe in-basin demand is more than sufficient to absorb regional production. Cove Point officials have not responded to requests for current export volumes.
“We had opportunities for taking additional firm transportation out of the basin and we turned it down,” said Tom Jorden, CEO of four-month-old Coterra Energy Corp., on Jan. 6 during the Goldman Sachs Global Energy and Clean Technology Conference. “We think there are in-basin opportunities, and we see a robust set of future opportunities as we look at coal-to-gas power switching.”
Coterra sprung out of the surprising $17-billion merger of Marcellus fixture Cabot Oil & Gas Corp. and West Texas/Oklahoma producer Cimarex Energy on Oct. 1. The former Cabot’s legacy 173,000 net acres, mostly concentrated in the Marcellus core of Susquehanna County, Pa., produced, on average, 2,363 MMcfd in the third quarter. Operating two rigs and two completion crews pre-merger, the former Cabot drilled 17 wells and completed 30 in the third quarter.
While the newly branded company sees production increasing to exploit “strong Appalachian winter pricing,” Jorden believes capital constraint will not dissolve anytime soon. “I think operators will remain disciplined. Right now, as we view the Appalachia market, there is less excess of capacity. Could it erode? Definitely, but I don’t see signs of it happening in 2022,” he said. “I think there’s lots to do in Appalachia, and we also need more pipelines. I don’t think you’ll find an Appalachia operator who won’t say that.”
For Appalachian first-mover Range Resources Corp., generating free cash flow supersedes escalating 2022 production, prices notwithstanding. “As we look forward to 2022, despite the recent improvements in strip pricing for oil, natural gas, and natural gas liquids, we remain committed to maintaining production at current levels, where the focus on harvesting cash flow, reducing debt, and further strengthening our balance sheet,” says Sr. V.P. and COO Dennis Degner.
Range projects full-year 2021 production of between 2.12 and 2.13 Bcfed, with around 60 new dry and wet gas wells hooked to production. Third-quarter production of 2.14 Bcfed was up 3% from the beginning of 2021. “Our operational program for the rest of the year will result in adding production from another seven wells in the fourth quarter, which are spread across our liquids-rich footprint,” Degner said on Oct. 27.
The company entered the fourth quarter operating two dual-fuel rigs and one electric-powered frac spread within a commanding 1.5 million net acres in Pennsylvania, with stacked play targets in the Marcellus, Utica and Upper Devonian shales.
CNX Resources Corp., likewise, is not inclined to ramp up activity to capitalize on futures prices that one analyst described as “the best they’ve been in a number of years.” “We like where we’re at with a one-rig, one frac crew array that’s generating a substantial amount of free cash flow. So, I think we stay within that operating plan for the foreseeable future,” said President and CEO Nicholas DeIuliis on Oct. 28. “What’s changed (in the industry) is probably where the popular focus has gone to recently, which is this concept of discipline and free cash flow generation, which we think obviously will be a good thing.”
After averaging 1,668.7 MMcfed in the third quarter, with six wells drilled and eight wells turned-in-line, CNX, which controls more than 1 million net acres, expects aggregate 2021 production of 570 to 580 Bcfe. The company wrapped up last year with a total of 35 Marcellus and two Utica wells put on production.
EQT, however, closed out 2021 with an increase in drilling and completion activity, as fourth-quarter production was expected to range between 510 Bcfe and 540 Bcfe, up from 495 Bcfe in the third quarter. The company averaged two to three rigs (Fig. 3) and three to four frac spreads last year.
In the fourth quarter, EQT planned to drill 32 wells with average lateral lengths of around 12,.000 ft—all but one targeting the Marcellus—with 33 Pennsylvania and West Virginia Marcellus wells slated for completion. This compares to 24 new drills and 23 completions in the third quarter. On the flip side, a total of 40 Pennsylvania and West Virginia Marcellus wells were turned-in-line in the third quarter, compared to 25 new producers on tap for the fourth quarter.
With the 300,000 net acres acquired in the more-than-$2.9-billion purchase of Alta Resources LLC in July 2021, EQT now controls more than 880,000 net acres in the Marcellus core.
Elsewhere, Seneca Resources Co., LLC, the exploration and production entity of National Fuel Gas Co. of New York, increased cumulative year-over-year production by 20% to 79.6 Bcfe in the fourth quarter. The company expects FY 2022 net production to jump between 335 Bcfe and 65 Bcfe from a 1.2-million-net-acre leasehold in Pennsylvania.
In FY 2022, Seneca expects to bring three pads online in Tioga County, Pa, with two targeting the Utica and the other producing from the Marcellus. An undisclosed volume of new production will be directed to the now-operational Leidy South expansion. “Our plan to ramp up production over the course of the year, to fill our new Leidy South capacity, is right on track. I expect first-quarter production to be sequentially flat, and we are timing several pads to come online during the quarter in conjunction with the new Leidy South capacity,” said Seneca President Justin Loweth. “From there, production should ramp up in the second and third quarters and then level out around 1 Bcfd net toward the end of the fiscal year.”
While integrating the newly acquired Haynesville assets, Southwestern Energy delivered an estimated 3.0 Bcfed in 2021 from the 789,218-net-acre Appalachian position. After laying down two rigs, the company expected to average two rigs and two completion crews in the fourth quarter.
Third-quarter production totaled 280 Bcfe, with 15 wells drilled and 19 wells completed and put on production at lateral reaches averaging 14,147 ft.
Meanwhile, in early January, the U.S. arm of Spain’s Repsol S.A. snapped up the estimated 42, 897 net acres held by distressed Rockdale Marcellus for a reported $222 million. The bolt-on acquisition, which was part of Rockdale’s Chapter 11 bankruptcy process, adds to the 171,000 net acres that Repsol controls in the Pennsylvania Marcellus. Repsol also owns midstream assets in Pennsylvania, with pipeline delivery capacity of 1.5 Bcfd.
Repsol intends to run three rigs in the Marcellus this year, with 2022 production estimated at 120,000 boed. At last count, the former Rockdale asset produced around 110 MMcfd.
EQT Developing ‘Next Generation’ of Unconventional Wells in Appalachia. EQT Corp. now expects the Mountain Valley Pipeline (MVP) to come online in 2023, which could help narrow its natural gas price differentials and ease Appalachian takeaway constraints, but management acknowledged last week that the “specter of timing” continues to loom over the project.
EQT has capacity booked on the system and a stake in MVP’s lead sponsor Equitrans Midstream Corp, which expects the project to start up this summer. Equitrans is reviewing that timeline after a federal appeals court last week vacated MVP’s Endangered Species Act authorizations and set back construction further.
The 303-mile, 2 Bcf/d system would move more Appalachian natural gas from West Virginia to the Southeast. EQT’s fourth quarter investor presentation assumes a mid-2023 start-up for MVP.
The pipeline has been dogged by regulatory delays. EQT CFO David Khani said during a call last Thursday to discuss year-end results that the company sold some of its shares in Equitrans during the fourth quarter and would consider selling more as the stock has declined.
“We’ll be thoughtful in when we want to sell them again,” he said. “I think the specter of timing is unknown on MVP. So, we’ll probably be a little patient here given that the stock is now under $8. We’ll wait until we get the view on MVP and the timing because I think that’s creating a cloud obviously over Equitrans’ stock.”
Fetching Higher Gas Prices
EQT, the nation’s largest natural gas producer, reported higher average realized prices for 2021 of $2.50/Mcfe, up from $2.37 in the prior year. Those gains were offset by wider differentials, however, as pipeline constraints in the Northeast have dented the realizations of Appalachian producers.
CEO Toby Rice said high energy prices in New England are the direct result of takeaway issues in Appalachia. He also cautioned that a rapid energy transition and resistance to natural gas projects in places like Europe have led to higher energy costs as well.
“Why is what’s happening in New England relevant?” Rice asked analysts during the call. “It’s relevant to the people in the southeast United State. You need to understand there is a pipeline that is going to allow you to benefit from low cost, reliable, clean energy, and this is something that people need to be aware of, because what’s happening in Europe, what’s happening in New England, starts with the things right now happening to MVP.”
‘Next Generation’ Wells
Rice said his team has been working to get a stronger grip on what they can control. EQT reported steep losses on hedges last year as prices crept upward. However, Rice said the company has started implementing an updated hedging strategy that “provides downside protection, while leaving large-to-upside exposure to higher natural gas prices.”
CFO David Khani noted that the company has paid off more debt, allowing it to “switch from a defensive hedging strategy with nearly all swaps to a more balanced approach” for 2023. The company has about 65% of its production volumes hedged for 2022 and another 42% hedged next year. EQT has layered on an overall floor of $3/Dth and a ceiling of $5/Dth in 2023.
Management also guided for 2022 capital expenditures (capex) of $1.3-1.45 billion to produce between 1.95-2.05 Tcfe. Guidance was higher than last year’s capex of $1.1 billion and above Wall Street consensus.
Inflationary pressures and incremental spending for a new well design are likely to push spending higher this year.
Management said the company would phase in a “next generation” well design in 2022 that’s been under development for the past year. Preliminary results from those wells are expected by the end of the year.
“We have confidence in beginning to phase in a next generation well design in 2022 that is geared toward further improvement in well productivity and drilling economics, leading to long-term free cash flow and value creation as we apply these learnings across our long runway of core inventory,” Rice said.
EQT produced 527 Bcfe in the fourth quarter across its Marcellus and Utica shale assets in Ohio, Pennsylvania and West Virginia. That’s up from 401 Bcfe in 4Q2020. Full year production was 1.9 Tcfe, up from 1.5 Tcfe in 2020. Rising volumes were the result of EQT’s acquisition of Alta Resources Development LLC and Appalachian assets it purchased from Chevron Corp.
Certifying Natural Gas
The company also continued to make headway on a concerted push to clean up its production and strengthen environmental, social and governance initiatives. Rice said third parties have now certified that most of its natural gas is produced in an environmentally-responsible way.
He added that the company has signed 10 deals to sell 1.2 Tcfe of certified production for $60 million in premiums to benchmark prices. EQT has previously said at least one deal was completed with an international buyer.
EQT is also continuing to attract interest from several liquefied natural gas parties across the value chain, Rice said. Any of those supply deals could give it exposure to international prices and growing demand for natural gas overseas amid a shortage of the fuel in some markets. He indicated that demand is only likely to grow as the energy transition will create a need for more natural gas.
“The macro events we are seeing are forcing a conversation grounded in reality, and we believe that conversation will end with a significant call on U.S. natural gas,” Rice said.
EQT reported fourth quarter net income of $1.8 billion ($4.69/share), compared with net income of $64 million (23 cents) in the year-ago period.
The company reported a full-year net loss of $1.2 billion (minus $3.58), compared with a net loss of $967 million ($3.71) in the prior year. The 2021 results were mainly attributed to a loss on derivatives.
FERC Has Made Pipeline Construction Even More Difficult. FERC issues ‘historic’ overhaul of pipeline approvals. The Federal Energy Regulatory Commission issued sweeping new guidance yesterday for natural gas projects, including a first-ever climate change threshold, upending decades of precedent for how major energy infrastructure is approved. FERC updated a 23-year-old policy for assessing proposed natural gas pipelines, adding new considerations for landowners, environmental justice communities and other factors. In a separate but related decision, the commission also laid out a framework for evaluating projects’ greenhouse gas emissions.
Marathon to Increase CAPEX 20%. Shale giant Marathon chooses cash returns over oil ramp-up. Marathon Oil Corp. said oil and natural gas production won’t increase this year as it concentrates on pouring cash into dividends and share buybacks. The shale giant announced plans to spend $1.2 billion on capital projects this year, in line with analysts’ expectations for a 20% increase from the 2021 level, according to a statement on Wednesday. The company forecasts generating more than $3 billion of free cash flow, exceeding estimates by half a billion dollars.
Pioneer CEO Says Shale Cannot Grow. Pioneer CEO Sheffield warns U.S. shale is unable to grow much more. U.S. shale lacks the capacity to come to the rescue of consumers battling sky-high energy prices with much more crude production, says the boss of the Permian Basin’s biggest oil explorer. Only OPEC countries like Saudi Arabia and the United Arab Emirates have the ability to meaningfully increase production fast in the wake of supply shortages, Pioneer Chief Executive Officer Scott Sheffield said on Bloomberg TV. U.S. shale, the world’s oil growth engine for the past decade, is constrained by labor shortages and demands by shareholders to return cash, he said.
Shale Giants Say, “No” to More Drilling. Not even $200 a barrel: Shale giants swear they won’t drill more. The Texas wildcatters that ushered in America’s shale revolution are resisting the temptation to pump more oil as the market rallies, signaling higher gasoline prices for consumers already battered by the worst inflation in a generation. Crude prices hurtling toward $100 a barrel typically would spark a frenzy of new drilling by independent explorers in shale fields from the desert Southwest to the Upper Great Plains — but not this year. Influential players like Pioneer Natural Resources Co., Devon Energy Corp. and Harold Hamm’s Continental Resources Inc. just pledged to limit 2022 production increases to no more than 5%, a fraction of the 20% or higher annual growth rates meted out in the pre-pandemic era.
Biden Working to Increase Oil Prices with This Policy. Biden looks to pressure investors away from fossil fuels via climate disclosures. The pressure is increasing on companies to follow environmental, social, and governance standards from both the private sector and the government. The Biden administration is prioritizing proposed rulemaking that would require companies to produce climate-related disclosures, most notably through the Securities and Exchange Commission, a form of indirect pressure on fossil fuel companies. The SEC is debating the extent to which it can compel companies to disclose details about how much energy they buy and how they handle climate risks.
Appalachian Basin Drillers Sending Money to Shareholders. Appalachia shale-gas drillers move to buy billions in own shares. Appalachian shale drillers are pledging to return billions of dollars to investors through share buybacks while keeping a lid on production growth as cash flow swells. Antero Resources Corp., which explores natural gas fields primarily in West Virginia and Ohio, said Wednesday it may repurchase up to $1 billion in stock starting next week as part of plan to return as much as 50% of free cash flow over the next few years. That follows similar announcements by CNX Resources Corp. and EQT Corp.
Antero Is Happy. Antero: ‘We like where we are’ and don’t plan to look outside of Appalachia. Antero Resources, a major Appalachian natural gas producer and one of the largest natural gas drillers in the country, said it’s not planning to join in the out-of-basin acquisition frenzy that’s been going on lately. The past year has seen moves by some Appalachian-only drillers like Cabot Oil & Gas Corp. and Southwestern Energy to acquire or merge with out-of-area producers to increase operations in the Haynesville or Permian basins. Even EQT Corp. (NYSE: EQT), the country’s biggest natural gas producer, bulked up with the 2020 acquisition of Chevron Appalachia and the 2021 acquisition of Alta Resources’ Marcellus assets in northeastern Pennsylvania—but not Antero (NYSE: AR).
Don’t Mess with TX. Don’t mess with Texas: BlackRock confirms its support for oil and gas. BlackRock will continue to invest in oil and gas firms and is not boycotting the energy industry, the world’s biggest asset manager has said in a letter sent to Texas officials and trade groups after the top U.S. oil-producing state started considering dropping investors that it thinks are boycotting its energy industry. “We will continue to invest in and support fossil fuel companies, including Texas fossil fuel companies,” executives at BlackRock wrote in a letter, which a spokesperson for the asset manager confirmed to Reuters was sent to Texas stakeholders earlier this year. Note: CBS News also reports.
ET Pushing to Build Permian NatGas Pipeline. Energy Transfer joins in rush to build Permian gas pipeline. Energy Transfer LP has joined a growing list of energy companies looking to build the next pipeline to transport growing amounts of natural gas production from the Permian Basin, the largest U.S. shale field, in West Texas and eastern New Mexico to export hubs on the Gulf Coast. “Given the proposed route and our ability to utilize existing assets, we believe we could complete construction of (the Permian) project in two years or less once we have reached FID (final investment decision),” Energy Transfer Co-Chief Executive Thomas Long told analysts on earnings call late Wednesday.
Pipeline Constraints Will Keep NatGas Prices High. Pipeline constraints to keep US natural gas prices high even if oil hits $100/b. If crude oil prices top $100 per barrel in 2022, U.S. natural gas markets will not be swamped with gas associated with more oil basin drilling, as has happened in the past, market observers said. Independent U.S. oil and gas exploration and production companies, or E&Ps, are expected to mostly held to their pledges to keep spending and production flat and send any extra cash they receive from higher commodity prices to lenders and shareholders.
Average O&G Wage $115,116. (Thanks, MDN) Founded in 1946, the Texas Independent Producers & Royalty Owners Association (TIPRO) represents nearly 3,000 individuals and companies from the Texas oil and gas industry. TIPRO is one of the country’s largest oil and gas trade associations and a strong advocacy group representing both independents and royalty owners in Texas. TIPRO generates some great research reports, including their latest annual “State of Energy Report” for 2022. The report, which looks at oil and gas across the country (not just Texas) finds that the O&G industry supported a total of 832,869 direct jobs in the U.S. last year. The U.S. O&G sector paid a national annual wage averaging $115,166 during 2021, 76% higher than average private sector wages!
Comprehensive Analysis of LNG Exports. Even as winter starts to wind down, global natural gas prices remain elevated as rising tensions between Russia and the Western world have destabilized European energy markets and pushed LNG, and U.S. LNG in particular, to center stage. From a markets perspective, the story of the past year has been high global gas prices — a strong incentive for LNG producers to push production facilities to operate at peak capacity and produce additional cargoes. The tight market has also spurred demand for new long-term sales and purchase agreements, creating momentum for a potential new wave of LNG development. But while gas prices in Europe and Asia have been elevated all year, they have not been elevated evenly. The Asia-Europe price spread has swung dramatically from favoring Asia last spring and summer to favoring Europe this winter, and U.S. export destinations have swung with it. Last summer, almost no destination-flexible LNG produced in the U.S. was landing in Europe and now Europe is consuming U.S. LNG at record levels. In today’s RBN blog, “Upside Down — How Global Prices Help Steer U.S. LNG to Different Destinations,” Lindsay Schneider takes a look at how the global price spreads impact U.S. LNG export destinations and what the strength in European demand means for the future of LNG development.
Drillers Cannot Find Sand. Drillers in the United States struggle to obtain sand for fracking as oil prices rise. Hart Energy. With crude prices at their highest in years, U.S. oil drillers are scrambling to increase output quickly, but they’re being hampered by a scarcity of sand for fracking operations. Parts of Texas and New Mexico, the epicenter of US shale production, are likely to set new records for crude output. Sand supplies are so scarce that some oil drillers are slowing down their work and increasing sand costs are eating into their profits. Once over-built and oversupplied, the sand markets have been turned upside down. Consultancy Rystad estimates that spot prices are between $50 and $70 a ton — a giant leap from prices in early teens at the start of the pandemic and sharply above last year’s levels of $20 to $25 per ton.
Permian Oil Production to Set a Record in March. Permian oil output forecast to hit record high in March. Oil output in the Permian in Texas and New Mexico, the biggest U.S. shale oil basin, will rise 71,000 barrels per day (bpd) to a record 5.205 million bpd in March, the U.S. Energy Information Administration (EIA) said in its productivity report on Monday. Gas output in both the Permian and the Haynesville in Texas, Louisiana and Arkansas will rise to record highs of 20.4 bcfd and 14.5 bcfd in March, respectively.
New England Polluters. During the six weeks ended Feb. 7, the region’s fleet of power stations burned 1.7 million barrels of fuel oil, accounting for more than 10% of the grid’s electric capacity, according to ISO New England. Fuel oil typically accounts for less than 1% of the region’s power production.
Burning that fuel oil produced about 3.55 billion pounds of the greenhouse gas carbon dioxide in January alone, up 4,800% from emissions from fuel oil in January 2021, according to emission rate estimates used by ISO-NE emission analysts. The grid’s total carbon dioxide emissions totaled about 8.8 billion pounds in January, up 44% from the year-ago period. ISO-NE said the estimates are high-side averages based on individual fuel types.
Less than 5% of the New England electricity comes form renewables. Will they ever see the “NatGas Light?”
PA Permit February 3, to February 17, 2022
County Township E&P Companies
- Allegheny Findlay Range
- Allegheny Findlay Range
- Allegheny Findlay Range
- Armstrong East Franklin Snyder Bros
- Bradford Herrick SWN
- Bradford Herrick SWN
- Lycoming Gamble Seneca
- Lycoming Gamble Seneca
- Lycoming Gamble Seneca
- Lycoming Gamble Seneca
- Lycoming Gamble Seneca
- Lycoming Gamble Seneca
- Lycoming Gamble Seneca
- Lycoming Gamble Seneca
- Susquehanna Bridgewater Coterra
- Susquehanna Bridgewater Coterra
- Susquehanna Bridgewater Coterra
- Susquehanna Bridgewater Coterra
- Susquehanna Bridgewater Coterra
- Tioga Hamilton Repsol
- Tioga Hamilton Repsol
- Tioga Hamilton Repsol
- Tioga Hamilton Repsol
- Washington East Findlay CNX
- Westmoreland Hempfield Apex
- Westmoreland Hempfield Apex
OH Permits February 8, to February 11, 2022
County Township E&P Companies
- Carroll Rose EOG
- Columbiana Hanover EAP OHIO
- Columbiana Hanover EAP OHIO
- Columbiana Elk Run Hilcorp
- Columbiana Elk Run Hilcorp
- Guernsey Wills Ascent
- Guernsey Wills Ascent
- Guernsey Wills Ascent
- Guernsey Wills Ascent
WV Permits February 7, to February 11, 2022
- Brooke SWN
- Wetzel Tug Hill
