The following Shale Directories Members are OPEN for BUSINESS during COVID-19 related shutdown.*
Support them when and how you can!
1st Choice Energy Services
Allison Crane & Rigging
American Energy Fabrication
EJ Breneman, L.L.C.
Frontier Group of Companies
Furbay Electric, Oil & Gas Division
Green Valley Seed
HYTORC Penn Ohio
Inland Tarp and Liner
MJ Painting Contractor Corp.
Mansfield Crane Service
Marshall County Co-Op – Southern States
NAI Ohio River Corridor
Oglebay Resort and Conference Center
Skycasters Converged Wireless
Zimmerman Steel and Supply Company, Inc.
*list subject to change
Shale Directories Conferences
8th Annual Upstream PA 2020
New Date October 29, 2020
State College, PA
4th Annual Appalachian Storage Hub Conference
New Date November 5, 2020
Hilton Garden Inn
Southpointe, Canonsburg, PA
8th Annual Utica Downstream
New Date November 19, 2020
New Location: Holiday Inn Belden Village
8th Annual Midstream PA 2020
New Date: December 10, 2020
State College, PA
Latest facts and a rumor from the Marcellus, Utica, and Permian, Eagle Ford Plays
ETP’s Kelcy Warren Steps Down. Kelcy Warren, the Dallas billionaire known for controversial pipelines and aggressive deal making, is stepping down as chief executive officer of Energy Transfer LP. But if the move is anything like those of fellow moguls in the pipeline industry, he isn’t going far.
The company late Thursday named Chief Operating Officer Mackie McCrea and Chief Financial Officer Tom Long as co-CEOs. Warren, 64, will stay on as executive chairman and remains the top investor. He’ll also retain a majority stake in the so-called general partner that controls Energy Transfer’s board.
Warren appears to be following a playbook employed by his billionaire rivals in the pipeline industry. Kinder Morgan Inc. founder Rich Kinder continues to serve as his company’s chairman despite relinquishing the CEO title in 2015, and Randa Duncan holds the same spot at Enterprise Products Partners LP after her father, the company’s founder, died in 2010.
“Although I am stepping away from the day-to-day management of our business, I will continue to be intimately involved in the strategic growth of Energy Transfer,” said Warren, who has a net worth of about $3 billion, according to the Bloomberg Billionaires Index.
Warren co-founded Energy Transfer in 1996 alongside Ray Davis, who now co-owns the Texas Rangers baseball team. Warren’s appetite for takeovers and his use of the tax-advantaged master limited partnership model allowed him to turn 200 miles of natural gas conduits into one of the biggest pipeline operations in the country.
Those same characteristics have frequently earned him the ire of everyone from regulators to environmental groups to investors.
Warren rose to national attention for his Dakota Access crude oil pipeline, which triggered months of on-the-ground protests after the Standing Rock Sioux Tribe objected to the path of the project in North Dakota. Even once Dakota Access faded from headlines after the project was fast-tracked by the Trump administration, Warren and Energy Transfer continued to attract scrutiny.
When building the Rover natural gas pipeline, the company bulldozed an historic house in Ohio that it had told federal regulators it would use as office space. And Energy Transfer’s Mariner East natural gas liquids pipeline has been blamed for a series of sinkholes in Pennsylvania.
Appalachian Basin NatGas Production down in October. Appalachian Basin gas production is down sharply this month as many operators dial back output in response to record price volatility, weaker shoulder-season demand and elevated storage levels.
In October, aggregate production from the Marcellus and Utica shales has averaged just 31.4 Bcf/d – about 500 MMcf/d, or 1.6%, below the prior-month average, S&P Global Platts Analytics data shows.
On Oct. 8, cash prices at the region’s key upstream hubs tumbled to historic lows, coming under pressure from a selloff at the US benchmark Henry Hub.
At Columbia Gas Appalachia, spot prices were down by nearly 55% from the Oct. 7 settlement to a record-low 60.5 cents/MMBtu. At Dominion South, cash prices were off by over 40% to around 66 cents, maintaining some distance from an Oct. 1 multiyear low settlement at 57 cents/MMBtu, preliminary data from S&P Global Platts showed.
Recurring price volatility during the autumn months has prompted at least some producers to throttle back output this season.
Cabot Oil & Gas on Oct. 7 said that it began strategically curtailing some 370 MMcf/d of its Appalachian production starting in mid-September. CEO Dan Dinges said that the decision came in response to lower regional gas prices. Cabot joined the region’s largest producer, EQT, which said last month that it began curtailing a net 425 MMcf/d in gas production on Sept. 1.
Regional price weakness in September and October has become a cyclical pattern in recent years, caused by lower seasonal demand, LNG terminal maintenance and high storage levels.
Since the official start of autumn, gas demand in the US Northeast has fallen to an average 14.9 Bcf/d – down nearly 1 Bcf/d compared with the final month of summer, Platts Analytics data shows.
A significant portion of that decline has been temperature-driven with mild weather keeping both gas-fired power burn and residential-commercial demand lower compared to the peak summer and winter periods.
The startup of regular seasonal maintenance at Dominion Energy’s Cove Point LNG terminal has also weighed on regional demand recently. Since September 22 – also the official start of autumn – feedgas demand at the Maryland terminal has remained at zero, down from an average 680 MMcf/d in the 30 days prior.
As Northeast gas storage levels approach capacity, waning injection demand is another factor that has weighed on Northeast market balances and prices. On Oct. 8, inventories were estimated at 1.02 Tcf – only about 40 Bcf below the region’s demonstrated maximum at 1.06 Tcf, recorded in November 2009.
Despite this season’s historic slide in cash prices, forwards markets continue to anticipate significant strengthening ahead of, and into the upcoming heating season.
At Dominion South, balance-of-the-month prices settled Oct. 7 at $1.18/MMBtu. At Columbia Gas Appalachia, the balmo contract ended trading at $1.28/MMBtu.
At both locations, forwards prices for January – typically the region’s peak month for winter demand – prices were most recently assessed at or near $3/MMBtu, S&P Global Platts M2MS data shows.
$5.00/MMBtu This Winter. Record natural gas production declines and a potential rebound in winter demand could create the tightest market of the past decade, with Henry Hub prices soaring to $5.00/MMBtu if weather is colder than normal, according to Morgan Stanley.
Researchers said that the precipitous drop in oil prices has stalled growth in the “free” associated gas coming from rampant oil production. That, combined with a roughly 50% reduction in spending by exploration and production companies from 2019, could result in a 3-4 Bcf/d year/year decline in associated gas output by the end of the year. With West Texas Intermediate crude currently below the $40/bbl threshold needed to hold U.S. volumes flat in 2021, declines could continue.
“Declines are not isolated to the oil basins,” said the Morgan Stanley team, led by equity analyst Devin McDermott.
In the gassy Haynesville Shale, for example, rig counts have fallen from around 50 to around 35 year to date. The biggest gas-producing region, the Marcellus Shale, has posted a similar drop of roughly 30%.
“Weak spot prices this summer, balance sheet stress and minimal access to external capital have left gas producers with production declines of their own, and limited ability to proactively increase capex in response to the upcoming market tightness,” analysts said.
The demand side of the equation is more positive. With Covid-19 bringing global economies to a near standstill, gas demand plummeted over the summer. The cancellation of domestic liquefied natural gas (LNG) cargoes reached a zenith of 45 in July, sending feed gas deliveries to U.S. terminals down below 3 Bcf/d, according to Morgan Stanley. U.S. capacity is around 9.5 Bcf/d.
Although the pandemic continues to cause uncertainty, weather-driven demand is expected to result in “negligible” cargo cancellations this winter as the global LNG market shifts into balance, according to Morgan Stanley. Analysts expect U.S. feed gas to stabilize around 9-10 Bcf/d during 4Q2020 from an average around 6 Bcf/d in September.
“In total, we forecast winter 2020-21 demand growth of 5-6 Bcf/d year/year, assuming normal weather,” the Morgan Stanley team said.
Other analysts and consultants, including Wood Mackenzie, have shared similar forecasts related to supply and demand this winter.
The Energy Information Administration (EIA) on Tuesday said it expects tightening balances to boost Henry Hub spot prices to a monthly average of $3.38 in January. In the Short-Term Energy Outlook, monthly average spot prices are forecast to remain higher than $3.00 throughout 2021, averaging $3.13 for the year from a forecast average of $2.07 in 2020.
Energy Aspects analysts, meanwhile, said when not undergoing maintenance or under storm-related shutdowns, U.S. gas export facilities have routinely run at high utilization rates. Tropical Storm Beta created a backlog of boats outside Freeport, TX, according to the firm, resulting in a feed gas delivery record of 1.9 Bcf/d on Sept. 29. The intake at the Sabine Pass export project in Louisiana also neared its maximum capacity of 4.0 Bcf/d in the days after Beta.
“High run rates reflect LNG offtakers’ response to widening global arbitrage, helped by the recent drop in Henry Hub pricing,” Energy Aspects said. Demand for U.S. LNG is forecast to be “durable” through the winter and into next summer, with exports reaching 10.3 Bcf/d, or 95% utilization, from December to February.
Energy Aspects’ supply/demand balances estimated that 95% utilization rates would continue into the 2021 injection season, including volumes from third production unit at Cheniere Energy Inc.’s Corpus Christi facility, which is projected to begin operations in March.
U.S gas storage inventories, which entered the injection season at lofty surpluses to historical levels, have struggled to return stocks to more seasonal proportions. September inventories finished the month sitting at record highs, with more weeks remaining in the injection season.
Morgan Stanley is projecting stocks to exit the traditional injection season at the end of October at around 3.9 Tcf, which is roughly in line with the five-year average. The analyst team is forecasting the combination of constrained supply and increasing demand possibly leading to one of the largest winter draws over the past decade.
“Assuming normal 10-year weather, we expect tight end-March inventories of around 1.2 Tcf, which is roughly 35% below the five-year normal of about 1.8 Tcf, with a mounting deficit thereafter,” said the analysts. Colder-than-normal weather could result in the lowest U.S. gas inventory levels on record, “and a material price rally to $5/MMBtu, or higher, and average in the mid-$4 range for full year 2021.”
LNG Shortage in This Decade. There will be a worldwide supply-demand gap for liquefied natural gas by the end of the decade totaling more than 100 million metric tonnes per annum — 50% of current U.S. LNG capacity, analytics/consulting firm Wood Mackenzie reports.
This supply gap is the “big prize” for the next phase of LNG export facilities in the U.S. – but competition worldwide to fill the gap will be intense, led by Qatar.
During a late September webinar entitled “North American LNG Winter Outlook 2020,” five of Wood Mac’s natural gas and LNG analyst-experts gave their take on U.S. operations, the global update and outlook, the U.S. winter outlook, and taking a look at the next wave of LNG projects.
“We see the global LNG demand growing at 4% per year this decade,” according to Alex Munton, Principal Analyst, North American LNG at Wood Mackenzie. “There will be a supply-demand gap by mid-decade, which grows to 100 MMTPA by the end of the decade.”
While the future looks bright, U.S. gas supply for LNG currently is in decline, said Ben Chu, Wood Mac’s head of Trading Analytics and Proprietary Data, Natural Gas. “Operators would rather raise free cash flow than raise production.”
Feed gas flowing to U.S. LNG export facilities fell to just 2 Bcf/d from 5 Bcf/d with the advent of Hurricane Laura in August, Ryan Bartley, LNG Analysts, Natural Gas. The good news is by mid-September, so-called nominations of gas to export facilities rebounded to 7 Bcf/d.
And by November, “U.S. LNG exports are expected to be fully recovered,” Chu added.
This winter, American LNG export facilities are projected to ship 8.5 Bcf/d of LNG,” said Amir Rejvani, LNG and Proprietary Analyst, Natural Gas.
The next upswing for LNG facility development in the U.S. will begin in 2023, with production from said complexes to begin in 2028-29, according to Munton.
Asked about U.S. production for the coming winter and summer of 2021, Chu said Wood Mackenzie is forecasting 89 Bcf/d during the coming winter, dropping slightly to 88 Bcf/d next summer. Dry gas production in the States peaked last November at 95 Bcf/d, according to Chu.
Chevron Buys Noble. Chevron Corporation (NYSE: CVX) announced today that it has entered into a definitive agreement with Noble Energy, Inc. (NASDAQ: NBL) to acquire all of the outstanding shares of Noble Energy in an all-stock transaction valued at $5 billion, or $10.38 per share. Based on Chevron’s closing price on July 17, 2020 and under the terms of the agreement, Noble Energy shareholders will receive 0.1191 shares of Chevron for each Noble Energy share. The total enterprise value, including debt, of the transaction is $13 billion.
The acquisition of Noble Energy provides Chevron with low-cost, proved reserves and attractive undeveloped resources that will enhance an already advantaged upstream portfolio. Noble Energy brings low-capital, cash-generating offshore assets in Israel, strengthening Chevron’s position in the Eastern Mediterranean. Noble Energy also enhances Chevron’s leading U.S. unconventional position with de-risked acreage in the DJ Basin and 92,000 largely contiguous and adjacent acres in the Permian Basin.
“Our strong balance sheet and financial discipline gives us the flexibility to be a buyer of quality assets during these challenging times,” said Chevron Chairman and CEO Michael Wirth. “This is a cost-effective opportunity for Chevron to acquire additional proved reserves and resources. Noble Energy’s multi-asset, high-quality portfolio will enhance geographic diversity, increase capital flexibility, and improve our ability to generate strong cash flow. These assets play to Chevron’s operational strengths, and the transaction underscores our commitment to capital discipline. We look forward to welcoming the Noble Energy team and shareholders to bring together the best of our organizations.”
“This combination is expected to unlock value for shareholders, generating anticipated annual run-rate cost synergies of approximately $300 million before tax, and it is expected to be accretive to free cash flow, earnings, and book returns one year after close,” Wirth concluded.
“The combination with Chevron is a compelling opportunity to join an admired global, diversified energy leader with a top-tier balance sheet and strong shareholder returns,” said David Stover, Noble Energy’s Chairman and CEO. “Over the last few years, we have made significant progress executing our strategic objectives, including driving capital efficiency gains onshore, advancing our offshore conventional gas developments and significantly reducing our cost structure. As we looked to build on this positive momentum, the Noble Energy Board of Directors and management team conducted a thorough process and concluded that this transaction is the best way to maximize value for all Noble Energy shareholders. We look forward to bringing together our highly complementary cultures and teams to realize the long-term value and benefits that this combination will deliver.”
CAT Buys Weir. Caterpillar to acquire Weir Oil & Gas in $405 million cash deal. Caterpillar Inc. has signed an agreement to acquire the Oil & Gas Division of the Weir Group PLC, a Scotland-based global engineering business. Headquartered near Fort Worth, Texas, Weir Oil & Gas produces a full line of pumps, flow iron, consumable parts, wellhead and pressure control products that are serviced via an extensive global network of service centers located near customer operations.
MVP Getting More Stream-Crossing Challenges Stream-crossing permits bring new court challenges as MVP awaits construction restart. NGI. In keeping with an extensive history of persistent legal opposition to Mountain Valley Pipeline LLC (MVP), environmental groups have asked a federal appeals court to stay recently updated waterbody-crossing permits for the 303-mile, 2 million Dth/d natural gas conduit. In petitions filed Monday with the U.S. Court of Appeals for the Fourth Circuit, a coalition of plaintiffs including the Sierra Club has asked the court to put a hold on MVP’s Nationwide Permit 12 (NWP 12) approvals, issued by the Huntington, WV, and Norfolk, VA, districts of the U.S. Army Corps of Engineers.
Water Recycling Facility in the Permian. Houston company constructs Permian water recycling facility. Houston-based Breakwater Energy Partners LLC says it has finished constructing the largest water recycling facility in the Permian Basin following laws passed last year that sparked a rush on expanding the water recycling industry in West Texas. Last year, a Texas House Bill and a New Mexico House Bill were passed and determined that oil and gas operators own wastewater from hydraulic fracturing.
Pipeline Support Need from Regulators. Regulators can support the Texas economy by knocking down hurdles to build pipelines. This year has already presented a whirlwind of challenges as a result of COVID-19, including widespread shutdowns and travel restrictions that have led to a significant drop in demand for natural gas and petroleum products. With potential shifts in national leadership on the horizon, the future of energy and environmental policy remains uncertain. Policymakers should understand the stability, economic investment and promise that energy development and infrastructure projects can bring to our nation in a time of unprecedented uncertainty.
Rigs Returning to the Eagle Ford. South Texas Drilling Permit Roundup: Gas wells return to the Eagle Ford. Five weeks after the Eagle Ford Shale lost its last gas rig, someone is once again searching for the fossil fuel in the South Texas shale play. Two weeks ago, the shale gained a trio of rigs, pushing its count from nine to 12, according to data from Baker Hughes Inc. Last week, that number held steady, with two of the new rigs dedicated to oil drilling and a third in place to drill natural gas wells.
Pipeline Discount in TX. Pipeline operators lure Texas shale producers with discounts. Large pipeline operators in the U.S. shale patch are reducing fees to keep their upstream customers shipping crude from the Texas oilfields to the U.S. Gulf Coast amid a decline in demand in the pandemic. Kinder Morgan, for example, is offering a discount of around 50 percent on its pipeline in the Eagle Ford shale play for some of its current customers, people with knowledge of the issue told Bloomberg.
Waiting for the Permian Comeback. Will the Permian stage a miraculous comeback? It is the crown jewel of the U.S. shale industry, but it’s in crisis. Thousands of layoffs, numerous bankruptcies, canceled land auctions, plummeting rig counts, and fewer fracking crews have plagued the Permian for the better part of this year—but is the worst behind the landmass that is America’s best (and perhaps only) chance at oil independence?
NatGas July Production Up in PA & TX. Natural gas production during July rose in Texas and Pennsylvania, the U.S.’s largest and second-largest gas producers, data from the states reveals.
Preliminary reported gas volume in Texas jumped 9.8% from July 2019, to July 2020, to 798.32 Bcf, from 726.81 Bcf, Shale Directories reports.
Keep in mind, the Texas data is preliminary, and no doubt will be updated as late and corrected production reports are received at the Railroad Commission of Texas. For example, in July 2019, the difference between preliminary and updated gas production jumped 164.31 Bcf.
Pennsylvania’s gas production during July rose 3.9% from a year ago, climbing to 598.70 Bcf, from 576.45 Bcf.
Reeves County in West Texas was the state’s leading gas producer county, at 85.87 Bcf, up sharply from June 2019’s 63.38 Bcf of production. Second place in both July 2020 and 2019, was Webb County in South Texas, falling slightly from 58.40 Bcf, to 54.50 Bcf.
The third most productive Texas County in the two most recent Julys was Midland in West Texas, jumping from 32.40 Bcf in July 2019, to 45.97 Bcf in July 2020. Tarrant County, the home of Fort Worth, was the fourth-highest gas producer in July 2019, at 32.32 Bcf. It was replaced by Panola County in East Texas in 2020, with production totaling 35.15 Bcf.
Culberson County was the fifth-largest producer this past July, at 31.90 Bcf, while in July 2019, the fifth most productive county was Panola, at 30.16 Bcf.
Susquehanna County, in Northeast Pennsylvania, retained the top spot in the state in terms of gas production from July to July. The dry gas king saw its production increase slightly, from 141.55 Bcf, to 141.89 Bcf, state DEP data shows.
Washington County in Southwest Pennsylvania, remained in second place, with gas production jumping from 97.43 Bcf, to 103.12 Bcf. Greene County, in the very southwest corner of the state, fell to fourth place from third, as production year-to-year dropped to 81.15 Bcf, from 87.49 Bcf.
Bradford County, in North-central Pennsylvania, rose to third place from fourth, as production jumped to 82.61 Bcf, from 786.70 Bcf.
Lycoming County in North-Central Pennsylvania, took fifth place in July 2020, with production reaching 40.43 Bcf, up from sixth place and production totaling 30.35 Bcf in July 2019. Fifth place in 2019 (and sixth place in July 2020) went to another north-central county, Tioga, falling from 31.49 Bcf, to 29.58
PA Permits October 1, to October 8, 2020
County Township E&P Companies
- Bradford Tuscarora Chesapeake
- Bradford Tuscarora Chesapeake
- Wyoming Braintrim Chesapeake
- Wyoming Braintrim Chesapeake
- Wyoming Braintrim Chesapeake
- Wyoming North Branch Chesapeake
- Wyoming North Branch Chesapeake
- Wyoming North Branch Chesapeake
OH Permits October 1, to October 8, 2020
County Township E&P Companies
- No New Permits
WV Permits September 21, to September 25 2020
- Brooke SWN