Rice Brothers Want To Run EQT

You can’t beat a proxy fight. Listening to the bombastic charges leveled by both sides against the other, rhetoric spewed at the highest level — nothing beats a company’s management team and board facing off against outsiders. Monday morning, the wraps were pulled off a potential proxy fight in the oil and gas industry. Toby Z. and Derek A. Rice told independent producer EQT Corp. they aren’t satisfied with the direction of the Pittsburgh-based E&P player. It’s early in the potential proxy fight process; the Rices are suggesting improvements they believe will make EQT more efficient, return more on investment, and generally tighten the producer’s modus operandi. But the letter makes it clear: Should EQT pooh-pooh the Rice proposals, including installing Toby Z. as head of operations, and placing more experienced O&G people with plenty of planning expertise, are placed on the board and in the executive offices, fireworks are possible. EQT, for its part, is being polite: “EQT is a refreshed company with a new management team, new operating plan and substantially reconstituted board,” according to a requested comment from the company on the Rice boy’s moves. “The company is focused on achieving profitable growth by driving operational efficiency, solid free cash flow, balance sheet strength, disciplined capital allocation and the realization of synergies. We are confident that EQT is taking the right steps to deliver superior value.” Remember, it’s early. While the $8.2 billion cash, stock and assumed debt deal EQT put together to acquire the smaller but highly successful Rice Energy made EQT the largest natural gas producer by volume in the U.S., the Rices as EQT investors aren’t satisfied with size. Yes, they want returns on the market value of their 7-plus million shares of EQT stock, but they also need the company that carried their surname to carry on – not under that name, but in success in the field, on the pad, in the individual well drilled. “EQT must add proven operational experience to the board and senior management team – in particular, individuals with experience in large-scale operational planning,” the Rices recommend. Rice Energy before its acquisition was one of the most successful independent producers of its size in the industry. And much of that success dealt with planning – Rice executives were fanatical when it came to pre-planning of every move involved in D&C – much more than most of its peers. Its executives were often conference speakers, telling the Rice story on how efficiency leads to prosperity. “EQT should improve planning through a coordinated operations schedule to reduce costs of drilling and subsequent derivative operations (e.g., completions, production, marketing, etc.),” states the PowerPoint presentation the Rices have put together in their quest to improve EQT (found online at eqtpathforward.com). Analysts contacted by Kallanish Energy on the EQT-Rice situation said they weren‘t surprised by the Toby and Derek letter and PowerPoint, and that there was little doubt the production wasn’t spur of the moment. “The timing of the release comes before EQT’s conference call this Thursday to discuss the company’s 2019 capital program and updated analyst presentation,” Sameer Panjwani, director, Equity Research with Tudor Pickering Holt, tells Kallanish Energy. “I would be very surprised if this situation is not brought up during that call.” Panjwani told Kallanish Energy the Monday release of the letter to the board and accompanying PowerPoint will be additional pressure on EQT to reveal more details on the direction the company intends to move – and how it intends to get there. “We have a proven, detailed business plan to generate an incremental $400-$600 million of pre-tax free cash flow per year above EQT’s current plans, equaling greater than $1.0 billion of free cash flow per year,” the Rice’s presentation states.“ This plan would match EQT’s current five-year production goals but generate twice the cash flow for shareholders.” The Rice letter states that over the past few weeks, in response to repeated outreach by a number of EQT investors asking for their assistance, the Rices engaged in private discussions with EQT chairman Jim Rohr and CEO Rob McNally “to express our concerns and propose solutions, which included, among other things, inserting Toby Rice into the organization with proper authority and support to oversee operations. “Unfortunately, given the lack of reciprocal engagement – and EQT pushing forward with establishing its 2019 operational plan and budget – it has become apparent that they are unwilling to make the changes needed.” The Rices quietly state that should the EQT board and company executives refuse to act upon the Rice recommendations, “we are prepared to nominate identified director candidates for election to the EQT board, if necessary.” “We have been talking to a number of EQT investors, and there appears to be a great deal of support for the Rice team: Tudor Pickering Holt’s Panjwani told Kallanish Energy. “Their proposal is not going away anytime soon.” There is one more unique twist to the potential EQT-Rice boys’ proxy fight. Of EQT’s 12 board members — certainly one not likely to lose his seat to someone with more E&P and planning experience — is Daniel J. Rice IV, former Rice Energy CEO. Joe Barone President Shale Directories, LLC

https://www.shaledirectories.com/blog/rice-brothers-want-to-run-eqt/

Winter weather could compound low gas storage problems

If your favorite natural gas forecaster is spending more time outside sniffing the air and placing a moistened index finger over his/her head, don’t be alarmed. While winter in calendar terms is still more than a month away, all the major weather forecasters have made their isobar-filled, high and low pressured, El Nino/El Nina-influenced prognostications for winter season 2018-19. But this year, which way the thermometer goes, coupled with nuclear power plant outages, and generally higher power demand throughout the U.S. economy, could lead to much higher gas prices and, worst-case scenario, possible spot product shortages. Take a look at the stored working gas numbers put out weekly by the Energy Information Administration, the statistical arm of the Department of Energy. Looking back from the week ending Nov. 9 (EIA’s most recent data), the difference between the week being compared to the five-year average for stored working gas, was negative 58 straight weeks. In other words, for 58 consecutive weeks dating back to late September 2017, the week moving forward was down compared to the five-year average. Digging a bit deeper, for the most recent 45 weeks, the percentage difference between the week being compared to the five-year-average was down by double digits, Kallanish Energy calculates. Supplies of natural gas were depleted by a cooler-than-normal 2017-18 winter and a warmer-than-normal summer of 2018, experts say. By late April, less than a month after the official March end of the heating season, stocks had fallen below 1.3 trillion cubic feet (Tcf) — the lowest in four years, according to EIA data. While stored gas is down substantially, the price for gas is up – and up substantially. Natural gas prices have in recent weeks soared over the $4 per thousand cubic feet level for the first time since prices jumped to the $7/Mcf level for a short time this past January, according to Michael Lynch, president of Strategic Energy and Economic Research, in a recent blog posting.

The natural gas price at 11:30 p.m. Monday was $4.52/Mcf.

“The tighter inventory situation can be explained primarily by the sudden surge in LNG exports,” according to Lynch. “Although they constitute only one-third of total exports (which also include pipeline exports to Canada and Mexico), they have increased sharply in the past two years as new export terminals have come online and oil prices have made them attractive.” Some experts believe the U.S. is on the edge when it comes to stored working gas – despite natural gas producers setting production records virtually weekly. Could demand overtake supply, causing shortages? “If winter weather comes in mild, then this current storage shortfall is a speed bump on the way to a looser market in 2019. If cold weather comes to fruition, though, the tenor of the 2019 outlook is fundamentally changed, and the market will spend a good portion of next year just digging out of the storage deficit,” Michael Cohen, head of energy markets research at Barclays, wrote in an October research note. While low inventories provide a bearish backdrop, it’s largely the unseasonably warm weather much of the U.S. experienced into October and unplanned nuclear power outages that are to blame for high gas prices, some experts contend. Days warm enough to require air-conditioning were 20% higher in September than the 10-year average, according to Barclays. In addition, Hurricane Florence forced power plants in North and South Carolina to shut down as much as 17,000 megawatts of nuclear power, or roughly 10,000 MW more than usual over the last four years, according to Barclays. As mentioned previously, weather prognosticators in mid-October made their winter forecasts. AccuWeather believes the return of an El Niño weather pattern will have a significant influence on the winter season. Mild air will linger in the Northeast and mid-Atlantic before cold weather takes hold in January and February. An active southern storm track will send snow and ice to parts of the southern Plains this winter, the State College, Pennsylvania-based company believes. El Niño means “The Little Boy,” or “Christ Child” in Spanish. El Niño was originally recognized by fishermen off the coast of South America in the 1600s, with the appearance of unusually warm water in the Pacific Ocean. The term El Niño refers to the large-scale ocean-atmosphere climate interaction linked to a periodic warming in sea surface temperatures across the central and east-central Equatorial Pacific. Typical El Niño effects are likely to develop over North America during the upcoming winter season. Those include warmer-than-average temperatures over western and central Canada, and over the western and northern United States. Wetter-than-average conditions are likely over portions of the U.S. Gulf Coast and Florida, while drier-than-average conditions can be expected in the Ohio Valley and the Pacific Northwest. “New York City and Philadelphia may wind up 4 to 8 degrees colder this February compared to last February,” AccuWeather forecaster Paul Pastelok said. In the Mid-Atlantic states, a few big snowstorms are likely. Most of the action will dodge the far Northeast U.S., however. In the Great Lakes, lake-effect snow will be less frequent than normal, despite above-normal water temperatures. An uptick is possible in late winter, but, for the season as a whole, residents will receive less than they are accustomed to, AccuWeather forecasts. If major metropolitan areas in the Northeast are smacked with colder-than-normal temperatires and a few big snowstorms, natural gas usage will jump. And so will gas prices. It may be time to go outside, wet that index finger and look to the west.

https://www.shaledirectories.com/blog/winter-weather-could-compound-low-gas-storage-problems/

Facts & Rumors # 313

Save these 2019 for Shale Directories Seminars

Utica Midstream March 21, 2019 Walsh University North Canton, OH

Upstream PA 2019 April 17, 2019 Penn Stater Conference Center State College, PA

Latest facts and a rumor from the Marcellus, Utica, Permian, Eagle Ford, Bakken and Niobrara Shale Plays

Are NatGas Prices for Real?  Natural gas prices have hit $4/Mcf for the first time since, well a few days in January, but they have been at or near $3/Mcf for most of the past five years, so the possibility of a “recovery” in prices is gladdening hearts in the producing industry. The fact that inventories have been below normal for the past year without moving prices has caused much gnashing of teeth and confounded the price bulls. North American natural gas may be the purest free market for commodities in the world, where supply and demand face a number of restrictions and/or regulations, but ultimately the market balance is set by economics. This is not the same as saying they are certain or that prices are predictable. As is so often the case, the causal factors are crucial. For some time, it has been argued that prices were below breakeven costs and must rise, that shale gas decline rates were so high production couldn’t be maintained, that Wall Street would force drillers to be more conservative in their investments, and/or that LNG exports would drive prices up. Only one of these appears relevant. Interestingly, the tighter inventory situation can be explained primarily by the sudden surge in LNG exports. Although they constitute only one-third of total exports they have increased sharply in the past two years as new export terminals have come on-line and oil prices have made them attractive. NatGas Almost $5. Cold weather blanketing much of the U.S. this week boosted spot natural gas prices for Nov. 15 to their highest since January in several regions, while natural gas futures slid 10% as investors took profits after a rally that had lifted them to their highest levels in nearly four years. Front-month gas futures rose as high as $4.929 per million British thermal units (mmBtu) on Nov. 14, their highest since February 2014. Traders said the cold this week would force utilities to start withdrawing gas from storage caverns that are already around 16 percent below normal for this time of year, prompting concerns of possible gas shortages in some parts of the country later this winter. NatGas Storage at 13 year low.  Working natural gas in underground storage in the Lower 48 U.S. states at Oct. 31, totaled 3.21 trillion cubic feet (Tcf), according to data from the Energy Information Administration released last week. Inventory levels for the Lower 48 and in each of the five U.S. natural gas regions ended the refill season at their lowest levels since October 2005 -- and these levels were considerably lower than their previous five-year averages, Kallanish Energy learns. While the natural gas storage injection season is traditionally defined as April 1 through Oct. 31, additional injections do occur in November. The South Central region saw the largest margin between the five-year range and working natural gas storage levels at Oct. 31, reaching 932 Bcf, 159 Bcf (15%) lower than the previous five-year range. The Pacific region saw the largest percentage difference between the end-of-season levels and the five-year range, at 264 Bcf, or 54 Bcf (17%) lower. The three other regions EIA divides the Lower 48 into to track stored working gas were 3% to 7% lower than the previous five-year range. A low starting inventory level and below-average net injections of natural gas into storage contributed to working natural gas stocks ending the refill season at this relatively low level, according to EIA. Lower-than-average temperatures in April 2018 resulted in uncharacteristic, continued withdrawals from storage during the month. Working natural gas stocks ended the withdrawal season on March 31 at 1.36 Tcf — the fourth-lowest level reported since 2005. Although net injections recovered in the following months, the net increases in working natural gas for the injection season were lower than the five-year average. From April 1 through Oct. 31, EIA estimates net injections totaled 1.85 Tcf. Injections were 269 Bcf (13%) lower than the five-year average, despite being 97 Bcf (6%) higher than injections in 2017. This level was the fourth-lowest net injected volume for the refill season in 13 years. The South Central and Pacific regions posted the largest differences from the five-year average. In the Pacific region, net injections into storage fell 33 Bcf (26%) lower than the five-year average. In the South Central region, reported net injections totaled 201 Bcf (39%) lower than the five-year average. In the East and Midwest regions, net injections were each 18 Bcf lower than the five-year average (3%). The only region that matched its five-year average net injections was the Mountain region. Despite increased natural gas production, increased demand for natural gas reduced net injections into working gas storage. Natural gas production averaged 83.6 Bcf/day during the refill season in 2018, compared with 74.7 Bcf/day in 2017 during the same period. However, greater-than-average power sector consumption of natural gas during the late spring and summer, combined with increased natural gas demand from U.S. export markets, resulted in lower-than-average weekly net injections of natural gas into storage. PTT Seeking OH Air Permits.  While it remains unclear if PTT Global Chemical America will build an ethane cracker in eastern Ohio, the company is seeking an air permit for the project from the Ohio Environmental Protection Agency, Kallanish Energy reports The state agency has scheduled a public information session on a draft air permit on Nov. 27, at Shadyside, Ohio, in Belmont County. A public hearing will immediately follow, during which the public can submit comments on the record concerning the draft permit for the $6 billion plant. The meeting was announced Tuesday by the state regulators. If approved, the permit would allow construction of an ethane cracker plant with an annual production capacity of 1.5 million tons. The plant would use six ethane cracking furnaces and manufacture ethylene, high-quality polyethylene and linear low-density polyethylene. Carbon monoxide, nitrogen oxide, volatile organic compounds, particulate matter and greenhouse gas pollutants are expected to be emitted, along with minor quantities of other pollutants, the state regulator said. Computer modeling was conducted to ensure local air quality will be protected, it said. If the permit is approved, the total maximum air emissions would be limited to protect public health and the environment, the EPA said. Encino in the Utica.  Chesapeake Energy has quietly left the gas-rich Utica Shale in eastern Ohio, but its drilling plan is still being implemented by Encino Energy, at least temporarily. The $2 billion purchase of 933,000 acres and 920 horizontal Utica wells from Chesapeake by Encino Acquisition Partners (Eap) officially closed on Oct. 29, as Chesapeake moved to reduce its corporate debt. The deal could result in more Utica production from a better-financed company that can invest in the shale region, according to observers. At the time of the deal in July, Chesapeake CEO Doug Lawler said, “We can’t grow the investment as we like and that makes it a strong candidate for divestiture.” He said the Utica was the best asset to sell and that leaves Chesapeake with five strong assets for future growth. The company last month spent $3.98 billion to acquire additional Eagle Ford and Austin Chalk assets in southeast Texas from WildHorse Resource Development Corp. “Chesapeake divesting its Utica Shale assets in Ohio is a positive move for Chesapeake and creates a new opportunity for someone else to come in and continue to develop this resources and acreage,” Matthew Hammond, executive vice president of the Ohio Oil and Gas Association told the Columbus Dispatch newspaper. The deal comes as Encino and Ascent Resources emerge as two of the biggest players in the Utica Shale as a result of recent deals, Kallanish Energy reports. Chesapeake, the third largest gas producer in the U.S., was one of the early Utica developers and its biggest producer. The Oklahoma-based energy giant had stormed into Ohio in 2010 and snapped up prime acreage in the Utica, a true first mover. Its colorful CEO, the late Aubrey McClendon, a strong Utica advocate, had quipped the Utica would be the biggest thing to hit Ohio since the plow. Now those Utica assets have been acquired by Encino and its partner, the Canadian Pension Plan Investment Board. They had teamed in 2017, with the goal of acquiring large, high-margin oil and natural gas production and development assets in the Lower 48 U.S. states. Their goal is to develop a major E&P company to further drill its Utica assets and to increase production and free cash flow. “The Utica is our most important asset,” Encino Energy president and CEO Hardy Murchison told the Canton Repository newspaper in early November. “It’s by far our largest and it’s our focus for the foreseeable future. We see decades of drilling ahead of us there, and we see it as being profitable across a wide range of oil and gas price outlooks. This is our focus,” he said. Little-known Encino Energy, a privately held company with headquarters in Houston, plans to work two rigs in the Utica Shale; Chesapeake recently had no rigs in the play. A third Utica drilling rig will be added next year and maybe a fourth rig in 2020, it said. Initially, Encino said it will drill wells that had been planned by Chesapeake. It intends to stick to the overall Utica drilling plan laid out by Chesapeake for where and how much it will drill for the next year or so. By 2020, Encino intends to implement its own drilling plan in Ohio. The company will keep its regional headquarters in Louisville, Ohio, outside of Canton, Ohio, for roughly 100 employees that transferred from Chesapeake. Encino plans to buy additional Utica acreage and to hire more workers as more rigs are added, said Murchison, who previously worked at First Reserve Corp. as well as Simmons and Co. International and Range Resources. The company has hired Ray Walker, Range’s recently retired chief operating officer, to direct its drilling efforts in the Utica. “We’ve got a lot of room to grow and what we’re really focused on is making good, steady cash flow year after year after year,” Walker told the Canton Repository. Murchison said his partnership looked at oil and natural gas basins across the country, but was drawn to the Utica. Chesapeake had assembled high-quality acreage in the Utica and the acreage that Chesapeake held included Utica dry gas and wet gas windows that produce condensate and natural gas liquids that can be lucrative, in addition to natural gas. The Utica and the Marcellus Shale also have pipelines and processing plants and an under-construction ethane cracker in Beaver County, Pennsylvania, near Pittsburgh. Chesapeake said roughly 322,000 acres it sold lie within the prime Utica commercial window for drilling. Its Ohio wells produced an average of 107,000 barrels of oil-equivalent per day (Boe/d), including 67% natural gas, 24% natural gas liquids and 9% oil. They produce about 600 million cubic feet of gas-equivalent per day (Mmcfe/d). It said the proved oil and gas reserves in the Utica Shale, as of Dec. 31, 2017, were roughly 480 million Boe (72% natural gas, 23% NGLs and 5% oil). Encino was created in 2011 and partnered with the Canadian pension fund in 2017 to create Encino Acquisition Partners. Encino put up $25 million, while the pension fund invested $1 billion. The Canada Pension Plan Investment Board is a management organization that invests funds not needed by the Canada Pension plan to pay benefits to 20 million contributors and beneficiaries. CPPIB, headquartered in Toronto, is governed and managed independently of the Canada Pension Fund and has no connection to government. As of March 31, the CPP Fund had C$356.1 billion ($268.97 billion) in assets. Its Energy & Resources portfolio consists of 10 direct investments valued at C$6.1 billion ($4.61 billion). Encino’s operations prior to the Chesapeake deal were based largely in the Anadarko Basin in Oklahoma. GE Taking Steps to Sell Baker Hughes.  General Electric is speeding up a plan to divorce itself from oil-and-gas giant Baker Hughes. GE (GE), which has been racing to repair a bloated balance sheet, announced a complex agreement on Tuesday to unload up to 166 million shares in oilfield services firm Baker Hughes (BHGE). The transactions would raise about $4 billion at current prices. The timing of the deal shows how bad the debt-riddled conglomerate needs the cash. GE only completed its takeover of Baker Hughes in July 2017. Yet by June 2018, GE said it would eventually get rid of its 62.5% stake. GE had to reach an agreement to escape a lock-up period that prevented the company from exiting the Baker Hughes investment until July 2019. New GE CEO Larry Culp, who took over on October 1, is under immense pressure to bolster the company's balance sheet by rapidly selling off businesses. Panicked investors have sent GE stock plunging 50% this year, on track for its worst year since 2008. GE shares closed 8% higher on Tuesday, Culp vowed on Monday to move with a "sense of urgency" to get GE's debt problem under control. "We do have a lot of leverage," Culp told CNBC. "We have a number of options to bring that leverage down over time." In a statement on Tuesday, Culp said the Baker Hughes agreements "accelerate" the company's plan to pursue an orderly separation from Baker Hughes. GE has said the process could take several years to complete. Anderson to Lead NETL.   A West Virginia University professor, who is one of the Appalachian Basin’s top experts on, and most vocal proponents for, natural gas liquids storage and petrochemical plants, is moving to a larger, national stage. Brian Anderson, who also is director and founder of the WVU Energy Institute, has been selected the new director of NETL, the National Energy Technology Laboratory, Kallanish Energy reports. NETL has facilities in Morgantown, West Virginia, just south of Pittsburgh, and on the U.S. West Coast. “Dr. Anderson’s extensive experience and knowledge in engineering and science is extraordinary," U.S. Secretary of Energy Rick Perry said, in a statement. "As the only national laboratory that is fully owned and operated by the Department of Energy, I am confident the National Energy Technology Laboratory will continue to make strides in advancing coal, natural gas, oil, and other energy technologies under his leadership." Anderson assumed his new position Sunday. PA Using More NatGas.  More and more people are recognizing the potential Marcellus and Utica Shale natural gas could have if the gas and associated natural gas liquids were used in Pennsylvania, rather than being exported to other areas of the U.S. — and internationally. PIOGA hosted "Marcellus to Manufacturing," a day-long program in Pittsburgh which brought current and potential natural gas-related companies together to hear how firms are and can capitalize on gas, and how Pennsylvania’s state government can help make investment a reality. Mike Storms, a member of a panel discussing downstream opportunities and managing risk in the energy market, expressed the attitude of the day-long program in just seven words: “We love that the gas is here,” said the director of Operations, Engineered Products, at the Elliott Group, a 100-plus-year-old company that designs, manufactures and services turbomachinery. Elliott certainly is a beneficiary of abundant Marcellus Shale gas. Among the oil and gas-related projects it’s involved with is Shell’s now-under-construction ethane cracker in Beaver County, Pennsylvania. The Jeannette, Pennsylvania-based Company sold millions of dollars of equipment for the cracker, including monstrous compressors and steam turbines, Kallanish Energy finds. One of the primary reasons Shell selected the western Pennsylvania site for the first cracker built in the Appalachian Basin in decades was abundant, inexpensive gas. “We’re seeing facilities being built now, that if they had been built 10 years ago, would never have been built here,” according to Andy Huenefeld, price risk manager, for Kinect Energy Group. “They would have built elsewhere for low labor costs. Now, they are building here for low energy prices.” ETP Expanding Pipeline Capacity in the Bakken.  Energy Transfer Partners (ETP) said last week it's considering expanding capacity on the Dakota Access pipeline system by 45,000 barrels per day (Bpd), to as much as 570,000 Bpd, Kallanish Energy learns. CEO Thomas Long said in the company’s earnings call “recent differentials and continued basin growth highlights the need for additional takeaway capacity out of the basin.” Crude oil production in the Bakken play has reached a record and is expected to increase by nearly 13,000 Bpd in November. This would put daily production capacity at a peak of 1.35 million barrels per day (Mmbpd). The Dakota Access pipeline system can currently handle 525,000 Bpd of western Canada crude. TX October Permits.   The Railroad Commission of Texas in October issued a total of 1,149 original drilling permits, compared to 997 permits in October 2017, a 15.2% increase, Kallanish Energy reports. The October 2018 total included 1,051 permits to drill new oil or gas wells, 11 to re-enter plugged well bores and 87 for re-completions of existing well bores. The breakdown of well types for those permits is 271 oil, 64 gas, 729 oil or gas, 77 injection, two service and six "other" permits, the commission reported. In October 2018, the commission processed 987 oil, 170 gas, 49 injection and seven other completions. That compares to 257 oil, 91 gas, 39 injection and four other completions in October 2017. Total well completions processed for 2018 year-to-date are 9,254, up from 5,799 recorded in the same period of 2017, a nearly 60% increase. According to well services company Baker Hughes, the Texas rig count as of Nov. 9 was 530, representing about 50% of all rigs in the United States. The Texas state permit system is seen by many as a good indication of the way the industry is moving on a monthly basis. The Midland area was No. 1 in October for permits to drill oil/gas holes with 545 permits. It was followed by the San Antonio area, the Refugio area, the San Angelo area and North Texas. For oil completions, the Midland area again was No. 1, with 464 permits, followed by the San Antonio, Refugio, San Angelo and Lubbock areas. For gas completions, the Midland area was tops with 71 permits, followed by the San Antonio, Refugio, East Texas and, in a tie, the Panhandle and Deep South Texas areas. Oil Shortfall by 2020.  The International Energy Agency (IEA) said Tuesday there’s a mismatch between robust oil demand in the near term and a shortfall in projects, causing a “sharp tightening” of oil markets in the 2020s, Kallanish Energy reports. Launching the World Energy Outlook (WEO) 2018 report, in London, the IEA said oil consumption will continue to grow in coming decades due to rising petrochemicals, trucking and aviation demand. But meeting this growth could prove to be a challenge. Approvals of conventional oil projects need to double from their current low levels, the IEA warned. “Without such a pick-up in investment, U.S. shale production, which has already been expanding at a record pace, would have to add more than 10 million barrels a day from today to 2025 -- the equivalent of adding another Russia to global supply in seven years – which would be a historically unprecedented feat,” it said. Analyzing the diverse range of energy fuels, the Paris-based agency said the geography of energy consumption continues its historic shift to Asia, but finds mixed signals on the pace and direction of change. The WEO found oil markets are entering a period of “renewed uncertainty and volatility,” heading to a potential supply gap in the early 2020s. Meanwhile, demand for gas is on the rise, erasing talk of a glut as China emerges as a giant consumer. Solar PV is charging ahead, but other low-carbon technologies and especially efficiency policies still require a big push. IEA executive director Fatih Birol said investments of roughly $2 trillion per year will be needed to meet future energy demand. “Our analysis shows that over 70% of global energy investments will be government-driven and, as such, the message is clear: the world’s energy destiny lies with government decisions,” he added. “Crafting the right policies and proper incentives will be critical to meeting our common goals of securing energy supplies, reducing carbon emissions, improving air quality in urban centers, and expanding basic access to energy in Africa and elsewhere.” Also on Tuesday, OPEC said it has revised downwards its estimate for global oil demand growth in 2019 by 70,000 barrels per day (Bpd), compared to its previous month estimate. Crude consumption is now forecast to reach 100.08 million barrels per day (Mmbpd) next year. The producers’ cartel warned the oil markets were heading towards a new supply glut in 2019, as lower demand would meet higher non-OPEC supply. EQT Spins Off Midstream.  Equitrans Midstream Corp. has completed its previously announced spinoff from the EQT Corp., Kallanish Energy reports. Equitrans is one of the largest natural gas gatherers and transmission pipeline operators in the U.S., with a major footprint in the Marcellus and Utica Shale plays in the Appalachian Basin, the companies said. Pittsburgh-based Equitrans on Tuesday began trading on the New York Stock Exchange under the symbol "ETRN." The separation from EQT officially took pace Monday at 11:59 p.m. through a pro rata distribution of 80.1% of the outstanding common stock of ETRN. EQT shareholders retained their EQT shares and received 0.80 shares of ETRN common stock for every share of EQT common stock outstanding as of the close of business on Nov. 1. EQT retained 19.9% of the outstanding common stock of ETRN. “Today, we launch Equitrans Midstream as a powerful independent company with a very bright future,” said president and CEO Thomas Karam, in a Tuesday statement. “ETRN now emerges with strong fundamentals and, as we work to deliver solutions for our customers and create additional value for our shareholders, our goal is to achieve the scale and scope of a premier, top-tier midstream company,” he said. Equitrans’ strategy will be to focus on leveraging existing pipeline and storage infrastructure systems by developing organic growth projects that will expand its footprint across the Appalachian Basin with delivery to major demand markets, the company said. Those organic projects will primarily involve gathering and transporting natural gas to markets and providing water and other midstream services to producers across the Appalachian Basin, according to the company. “We are laser-focused on the execution of our inflight projects including the Mountain Valley Pipeline, which are expected to drive more than 50% growth in EBITDA over the next three years,” said chief operating officer Diana Charletta, in a statement. Permian Energizes Dallas-Fort Worth.  The Austin Chalk. The Barnett Shale. The Eagle Ford. These mighty Texas formations are forever cemented into local lore for the fortunes they’ve created. They’re geological playgrounds, where high-stakes games of hide-and-seek regularly occur between eager risk-takers and a precious commodity silently waiting to seep up from below. But no oil play possesses the unbridled potential of the Permian. Since it was first tapped in 1923, the shale basin has seen extraction of about 30 billion barrels. That pales in comparison to what still lies beneath. According to London-based consulting and research firm IHS Markit, between 60 billion and 70 billion barrels of recoverable oil remain underground. The value, based on current oil prices, tops $4.3 trillion. “How can we have been drilling in the Permian Basin for 100 years and then find out it has twice as much as we thought?” energy maverick T. Boone Pickens often asks. It’s a question that remains to be answered, but one thing is for certain: The effects of the Permian are being felt far beyond West Texas, where new technologies and drilling efficiencies have made it easier and cheaper to tap into the basin’s rich reserves. The boom is already having a profound impact in Dallas-Fort Worth, as energy players, logistics companies, private equity firms, investment bankers, M&A and tax attorneys, tech and service companies, oil-and-gas consultants, and others position themselves to get a piece of the action. The Latest on DUC’s.  The number of drilled, but uncompleted (DUC) wells in the Lower 48 U.S. states seven most productive basins/plays rose by 3.3% from September to October. The increase occurred despite three of the seven areas reporting a drop in DUCs, according to the November issue of the Energy Information Administration’s Drilling Productivity Report (DPR). The DPR reveals 269 DUCs were added to the September total of 8,276. The new total is 8,545, as of Oct. 31, Kallanish Energy reports. The biggest increase by far from September to October was in the Permian Basin, up 249 drilled, but uncompleted wells, 6.9%, to 3,866, from 3,617. The Anadarko was the closest basin/play to the Permian, up 41 DUCs, or 3.9%, from September to October, to 1,084, the DPR reveals. The three drilling areas which recorded a month-to-month drop in DUCs were Appalachia (the Marcellus and Utica Shale plays), Bakken and Niobrara, down 19, 20 and 14 DUCs, respectively, to 623, 797 and 401, respectively. The Eagle Ford play saw a 25-DUC increase, to 1,571, while the Haynesville Shale recorded a seven-DUC increase, to 203.

Utica Shale Well Activity as of Nov. 10. 2019

DRILLED: 252 (254 as of last week) DRILLING: 121 (120) PERMITTED: 469 (467) PRODUCING: 2,075 (2,072) TOTAL: 2,917 (2,913)

TOP 10 COUNTIES BY NUMBER OF PERMITS

1. BELMONT: 585 (585 as of last week)
2. CARROLL: 525 (525)
3. HARRISON: 430 (427)
4. MONROE: 414 (414)
5. GUERNSEY: 242 (242)
6. NOBLE: 223 (223)
7. JEFFERSON: 203 (202)
8. COLUMBIANA: 159 (159)
9. MAHONING: 30 (30)
10. WASHINGTON: 22 (22)

TOP 10 COMPANIES BY NUMBER OF PERMITS

1. CHESAPEAKE: 888 (888 as of last week)
2. ASCENT RESOURCES UTICA: 485 (481)
3. GULFPORT: 406 (406)
4. ANTERO: 260 (260)
5. ECLIPSE: 193 (193)
6. RICE: 128 (128)
7. XTO: 75 (75)
8. HILCORP: 59 (59)
9. CNX GAS: 52 (52)
10. PENNENERGY RESOURCES: 40 (40)

SOURCE: OHIO DEPARTMENT OF NATURAL RESOURCES     Joe Barone jbarone@shaledirectories.com 610.764.1232 Vera Anderson vera@shaledirectories.com 570.337.7149

https://www.shaledirectories.com/blog/facts-rumors-313/

PETROCHEMICAL VALUE CHAIN

EDUCATIONAL WORKSHOP

''The Shell Chemical Ethane Cracker operation is due to make 1.6 million tons a year of ethylene which is used in products ranging from food packaging to automotive parts." - _{StateImpact-NPR} Nov. 15, 2018 8:30 am - 3:30 pm EagleSticks Golf Club 2655 Maysville Pike Zanesville, OH A one-day educational workshop is being presented this November to explain the benefits of entering the downstream petrochemical value chain and help companies create a plan to connect with industry players. This Ohio workshop will take place on November 15, 2018 at EagleSticks Golf Club in Zanesville, Ohio. Below are some of the key points for the workshop agenda.

• Presentation about the downstream petrochemical industry and the latest news on key influencers for the industry as the result of all the natural gas in the Marcellus and Utica
• Case studies about manufacturing companies who have successfully sold products and services in this value chain
• Strategy sessions to help each participant develop a customized plan to move forward in the downstream petrochemical economy taking advantage of the inexpensive natural gas from the Marcellus and the Utica

To learn more about or register for this educational workshop, visit https://petro.polymerohio.org

https://www.shaledirectories.com/blog/petrochemical-value-chain/

New Horizons Appalachian Basin

The Kallanish New Horizons - Appalachian Basin event is fast approaching, and you have a limited amount of time to book your place at this important event. Come to hear from our esteemed speaker panel which includes: Shell, Williams, Penn State and the Father of the Marcellus talk about pipelines, crackers, storage, big data, and workforce challenges in the Appalachian Basin. The event is taking place in Southpointe/Pittsburgh on Thursday Nov. 29th at the Hilton Garden Inn. Important - Book your place today and pay $300 per ticket. >>Register Today https://www.kallanishenergy.com/nh-appalachian-basin/register-online/ Conference Speakers -------------------------------- Terry Engelder, Professor Emeritus of Geosciences Department of Geosciences, The Pennsylvania State University Michael Marr, Business Integration Lead, Shell Chemical Co. Tomas B Murphy, Director, Penn State Marcellus Center for Outreach and Research Jim McGlone, Chief Marketing Officer, Kenexis Consulting Michael Atchie, Manager of Public Outreach, Williams Cos. J.P. Dutton, President, Belmont County, Ohio, County Commissioners George S. Pullen, Senior Economist for Division of Market Oversight, U.S. Commodity Futures Trading Commission Joe Barone, President, Shale Directories Philip Lamb, Managing Partner, PRL International Tom Gellrich, Founder, Top Line Analytics Tom Foster, Data Scientist/Business Development Manager, Mach Parallel LLC Scott Potter, Managing Director, Business Development, RBN Energy >>View the program https://www.kallanishenergy.com/nh-appalachian-basin/#program Key Event Details: -------------------------------- Venue: Hilton Garden Inn Location: Southpointe/Pittsburgh Date: November 29th Format: ¾ day conference - including Breakfast, Lunch, Coffee Breaks Early Bird Price: $200 per ticket (expires Oct 31st) If you have any questions please do not hesitate to get in touch and I will be happy to help.  We look forward to seeing you in Pittsburgh next month. Contact us your local Kallanish Team Member: ------------------------------- Cayleigh Reid Tel: (412) 626-7487 Email: cayleigh.reid@kallanish.com Veronica Ravella Tel: (412) 675 2925 Email: veronica.ravella@kallanish.com

https://www.shaledirectories.com/blog/new-horizons-appalachian-basin/

Facts & Rumors # 311

Expo/Industry events for the next few months

 

Marcellus Utica Houston November 7-8 JW Marriott Houston Galleria 5150 Westheimer Road Houston, TX 77056

http://www.marcellusuticahouston.com/

 

Downstream Petrochemical Value Chain November 15, 2018 Eagle Sticks Golf Club 2655 Maysville Pike Zanesville, OH

https://bit.ly/2CWeXjs

 

For other events visit http://www.shaledirectories.com/site/oil-and-gas-expo-information.html

Latest facts and a rumor from the Marcellus, Utica, Permian, Eagle Ford, Bakken and Niobrara Shale Plays

Big Boys Will Be Driving U.S. Shale.  Independent producers will forever be pioneers of the U.S. shale sector, but as the play matures, expect major oil companies to play a growing and critical role in its future development. Majors, with their financial strength and integrated solutions, are well-equipped to handle the structural challenges that the U.S. shale sector now faces, from insufficient pipeline and export infrastructure in the Permian and Gulf Coast, to excessive gas flaring in Bakken. The time also looks right for majors get more involved and “scale up” in shale. Big Oil remains very light in U.S. shale oil relative to other upstream assets in their portfolio. Majors have traditionally focused on “megaprojects,” schemes such as those in deep water or oil sands, where capital investments are massive and payback periods are long. Giants like Royal Dutch Shell plc and Total S.A. have already exited from Canada’s oil sands, where they believe breakeven costs are too high. The onset of the low-carbon energy transition also must be considered, and the fact is that oil sands emit more carbon dioxide than any other oil projects and must produce for many years—at relatively high oil prices—to deliver sufficient financial returns. U.S. shale oil, on the other hand, has proven its mettle at low prices, having stood up to OPEC in a price war. Breakeven prices for shale have been driven below $40 a barrel and are even lower for companies fracking the best rock. Shale is a “short-cycle” upstream asset, meaning new production can be brought on within months after investment decisions are made. Chesapeake Buys WildHorse.  Chesapeake Energy Corp is buying oil producer WildHorse Resource Development Corp in a nearly $4 billion deal, it said on Tuesday, as it looks to increase oil production capacity during a period of rising crude prices. The Oklahoma-based oil and natural gas producer said each WildHorse shareholder will get either 5.989 shares of Chesapeake common stock or a combination of 5.336 shares of Chesapeake stock and $3 in cash, for each share they hold. WildHorse’s shares surged 13.5 percent to $20.50 in premarket trading, while Chesapeake shares slumped 8 percent to $3.42. The acquisition is expected to give Chesapeake about 420,000 high-margin net acres in the Eagle Ford shale and Austin Chalk formations in Southeast Texas, and help it save between $200 million and $280 million in annual costs. Chesapeake has been directing its capital toward oil production and shifting away from natural gas amid a rise in crude prices and a slump in natural gas prices. “We plan to focus the vast majority of our projected 2019 activity on our high-margin, higher-return oil opportunities in the PRB and Eagle Ford Shale, while decreasing capital and activity directed toward our natural gas portfolio,” Chesapeake Chief Executive Officer Doug Lawler said in a statement. Dominion Sells Blue Racer Interest.  Private equity firm First Reserve on Thursday said it’s buying Dominion Energy's 50% interest in Blue Racer Midstream for an undisclosed price. Blue Racer is a joint venture formed in December 2012 by Dominion and Caiman Energy II to own, operate, develop and acquire midstream assets in the Utica Shale and certain adjacent areas in the Marcellus Shale. Midstreamer Blue Racer provides natural gas gathering, compression, dehydrating, treating, processing, fractionation, and transportation services, Kallanish Energy understands. "… We have a long history of investing in the Utica shale, most notably through our ownership of Ascent Resources, which is currently the largest natural gas producer in the basin,” said Gary Reaves, managing director of First Reserve. “This historical and current portfolio experience leads us to believe the Utica shale is one of the premier rich natural gas development areas in the U.S., and, in our view, Blue Racer is particularly well-positioned to capture this opportunity.” Blue Racer features more than 700 miles of gathering pipeline and 800 million cubic feet per day (Mmcf/d) of cryogenic processing capacity. The midstreamer has a number of customer contractual commitments comprised of multi-year pacts that include acreage and well pad dedications, first flow commitments, minimum volume commitments, and demand payments. "When we formed Blue Racer in 2012, Dominion contributed the initial gathering, processing and fractionation assets that allowed Blue Racer to establish a foothold in the region, that we expanded into a growing business serving the leading producers in the Utica and Marcellus shale plays,” said Stephen L. Arata, Blue Racer CEO. The purchase is being funded in part by equity from First Reserve Fund XIII and investment funds affiliated with First Reserve. The transaction is expected to close prior to year-end 2018. Cabot 3^rd Qtr. Update.  Cabot Oil & Gas Friday reported its third-quarter, all-natural gas production volume jumped more than 15% year-over-year, free cash flow skyrocketed sevenfold, and the net result of brokered natural gas jumped nearly $12 million. The strong positives led to a nearly 600% increase in net profit, while revenue rose a strong 41.4%, Kallanish Energy calculates. For the quarter ended Sept. 30, natural gas production jumped to 186.5 billion cubic feet (Bcf), up from 161.2 Bcf one year ago. Daily equivalent production rose to 2.03 Bcfe/d, compared to 2.03 Bcfe/d. Cabot's operations are primarily centered in Susquehanna County, in northeast Pennsylvania. Average gas prices during the quarter rose to $2.36 per thousand cubic feet, up from 2.03/Mcf. Cabot’s top executive was extremely pleased with free cash flow for the quarter jumping to $28.57 million, from just $4 million one year ago. "We returned to free cash flow generation during the third-quarter while delivering significant year-over-year growth in all financial metrics," stated Dan O. Dinges, Cabot chairman, president and CEO. The Houston-based independent producer reported zero oil and condensate production during the most recent quarter, which financially was a drop of $56.91 million reported for the third quarter of 2017. The net result of brokered natural gas $12.44 million, from just $730,000. Bottom line, net profit for the quarter totaled $122.34 million, up from $17.59 million. Revenue rose to $545.17 million, from $385.42 million. Penn Virginia Sold. The Houston oil and gas driller Penn Virginia Corp. was bought Sunday in a stock and cash deal worth $1.7 billion, including debt. Denbury Resources of Plano will acquire Penn Virginia and its 84,000 acres in the Eagle Ford Shale in a deal expected to close in the first quarter of 2019, pending shareholder approval. Denbury operates in multiple states across the Gulf Coast and Rocky Mountain regions. The company specializes in enhanced oil recovery techniques, which pump carbon dioxide into wells to boost their production. Penn Virginia's CEO John Brooks said in July that the company was seeking "a range of strategic alternatives," including a possible sale. Penn Virginia filed for bankruptcy in May 2016, about three months after crude price hit their low of about $26 a barrel during the recent oil bust. During its bankruptcy, Penn Virginia moved its headquarters from Virginia to Houston. The company employed about 80 people at the beginning of this year. The company emerged from bankruptcy in September 2016, though it said in its second-quarter 2018 filing with the Securities and Exchange Commission that as of Aug. 3, there were still claims against the company related to the bankruptcy. Rice Brothers 2.0 The brothers behind Rice Energy recently closed on their first investment in a fracking software company they believe will revolutionize the industry. The Rice brothers—Daniel, Toby and Derek—emerged earlier this year with the launch of Rice Investment Group (RIG), a $200 million multi-strategy fund focused on all facets of the oil and gas sector. Through RIG, the Rice brothers plan to target investments of $1 million to $40 million across the upstream, midstream, oilfield service and energy technology sectors, focusing on companies that are “electrifying the oil field.” “Said another way, we are looking for companies that can capture data from disconnected operations in the field to empower data-driven decisions on things that matter,” Toby Rice told Hart Energy. Rice, who sources and evaluates investment opportunities for RIG, said he believes the group’s latest investment—Cold Bore Technology Inc.—is one of those companies and will play a leading role in transforming the industry. Cold Bore is a Calgary, Alberta-based developer of fracturing optimization software cofounded by Brett Chell, the company’s president who Rice dubbed a “shalennial”—an oil and gas entrepreneur from the millennial generation. Antero 3^rd Qtr. Update.  Antero Resources on Thursday reported a net loss of $154 million in 2018's third quarter, despite turning a record 73 Appalachian Basin wells to production, Kallanish Energy reports. That compares to a Q3 2017 net loss of $135 million. The Denver-based company posted revenue of $1.1 billion, compared to $648 million a year ago. The turned wells included 58 horizontal Marcellus Shale wells and 15 Utica Shale wells. “We completed more wells in the third quarter than any other quarter in Antero’s history, with 73 wells turned to sales, a testament to the company’s outstanding operational team,” said chairman and CEO Paul Rady, in a statement. He noted capital spending will decline in the fourth quarter as the company is operating only five drilling rigs and three completion crews. Drilling efficiencies have allowed the company to idle three completion crews. “Having recently surpassed the 3 billion cubic feet-equivalent per day (Bcfe/d) of production milestone for the month of October, the fourth quarter is expected to be an important inflection point for the company as we expect to deliver attractive cash flow from operations growth combined with a reduction in spending,” Rady said. The company has also benefitted from higher liquids prices, company officials said. Antero said its 58 Marcellus wells had an average lateral length of 9,100 feet and an average 30-day rate per well of 18.3 million cubic feet-equivalent per day (MMcfe/d) on choke. The company said it expects to begin production on 27 additional Marcellus wells in Q4. It is running five rigs in the Marcellus area. The Utica Shale wells in eastern Ohio had average lateral length of 10,400 feet and an average 30-day rate per well of 17.7 MMcfe/d. Antero said it does not intend to operate any rigs or completion crews in Ohio in the fourth quarter as it focuses on liquids-rich locations in the Marcellus instead. Total Antero net daily gas equivalent production in Q3 totaled a record 2.72 Bcfe/d (29% liquids), a 17% increase over Q3 2017, the company said. Liquids production averaged 129,352 Bpd with 25% ethane recovery. That included oil production of 10,632 Bpd, a 15% increase over the prior year. Liquids production is 43% of total product revenue before hedges. Antero said it plans to spend $600 million on a stock repurchase program over the next 12 to 18 months. The company noted it suffered oil production curtailments in the latter part of Q2 and into Q3 due to trucking constraints. The curtailments negatively impacted production by an average 86 MMcfe/d during Q3. As previously announced in Q3, Antero Midstream and Antero Midstream GP announced plans to simplify the midstream corporate structure by merging and converting to a C-corp. Chesapeake 3^rd Qtr. Update.  Chesapeake Energy (CHK) reported third-quarter 2018 net income of $60 million, compared to a net loss of $41 million in Q3 2017, Kallanish Energy reports. Adjusting for items typically excluded, the company’s adjusted net income was $174 million, and adjusted EBITDA was $594 million. The company said that its quarterly cash flow from operating activities was $504 million, up 52% from Q3 2017 levels. Third-quarter reported its EBITDA for Q3 2018 was $504 million. Chesapeake reported it spent $619 million on capital spending in Q3, down from $692 million in the year-ago quarter. "Chesapeake continues to make significant progress on our strategic priorities, as demonstrated by our improved cash flow from operations, which was more than 50% higher than the 2017 third quarter due to higher average realized commodity prices and 13% growth in our adjusted oil production,” said president and CEO Doug Lawler, in a statement. The company, he said, plans to focus its 2019 activity in its high-margin, higher-return oil opportunities in the Powder River Basin in Wyoming and the Eagle Ford Shale in South Texas. Chesapeake’s Q3 2018 oil production was 89,000 barrels per day, driven largely by increased Wyoming production. The company reported its average rig count in Q3 2018 was 19 and 84 gross wells were spud, 81 gross wells were completed and 75 gross wells were connected. A year ago, the company had 17 rigs at work, spud 86 wells, completed 120 wells and connected 122 wells. In Q3 2018, the company’s average daily production was about 537,000 Boe, compared to roughly 542,000 Boe one year ago. Chesapeake’s top plays for oil were the Eagle Ford Shale in South Texas, the Powder River Basin in Wyoming and Montana and the Utica Shale in Ohio, assets which the company has sold. Its top plays for natural gas are the Marcellus in Pennsylvania and West Virginia, the Haynesville in Louisiana and the Utica Shale in Ohio. “Momentum is building” in the Powder River Basin, Chesapeake said. Five rigs were moved there last July to drill in the Turner formation and it is experimenting with tighter well spacing’s. It expects to place 15 Turner wells into production in Q4 2018, and an additional 65 to 70 Turner wells in 2019, the company said. Its best Turner well produced a peak 24-hour average rate of 3,133 Boe/d (47% oil) from a 10,246-foot lateral. In the Eagle Ford, Chesapeake placed 29 wells into production in Q3 and expects to add 53 wells to production in Q4. Production numbers dipped in September and October due to localized flooding. It plans to add a fifth Eagle Ford rig in 2019. Higher gas prices in the Appalachian Basin boosted the company’s finances, it said. It placed seven Marcellus Shale wells to production in Q3 and expects to place 25 Marcellus Shale wells to production in the fourth quarter. It placed 11 Utica Shale wells into production in Q3. The Utica asset sale closed earlier this month. Williams 3^rd Qtr. Update.  Williams on Thursday reported third-quarter net income of $129 million, a $96 million increase from one year ago, Kallanish Energy reports. Cash flow from operations was $746 million, about $41 million more than Q3 2017. The midstream giant said its Q3 2018 adjusted EBITDA was $1.20 billion, up $83 million, or 7.5%, from Q3 2017. “This quarter’s strong execution and results highlight why we are so bullish on the future,” said president and CEO Alan Armstrong, in a statement. The company has positioned itself to be the leading natural gas infrastructure company and it sees full-year 2018 financial results “trending toward the upper end of our financial guidance for 2018,” he said. Williams has “a backlog of attractive investment opportunities,” he added. Armstrong credited some of the revenue growth to higher natural gas volumes in the Northeast along with the expansion of the Transco system in the Atlantic-Gulf segment. Those projects “helped significantly increase service revenue this quarter,” he said. There was a $227 million improvement in operating income associated with Transco Pipeline expansion projects going online. He said revenue will likely grow on the Transco system in the Q4 2018 and 2019 with added shipments on the $3 billion Atlantic Sunrise pipeline from the Marcellus Shale in Pennsylvania and the company’s Gulf Connector project. “Importantly, Atlantic Sunrise has opened up new markets for Marcellus producers, and that is driving accelerated growth in our Northeast G&P business segment. This growth will continue for many years,” he said. The Atlantic Sunrise can move natural gas as far south as Alabama. The company has also announced plans to expand natural gas pipelines out of Northeast Pennsylvania with Transco’s Leidy South Expansion, he said. Williams with corporate offices in Tulsa, Oklahoma, intends to rapidly expand its gathering systems and plants in the Marcellus, Utica, Haynesville, Powder River. DJ and Wamsutter plays, according to Armstrong. Higher prices for natural gas liquids also benefitted the company’s bottom line in Q3 2018. In the third quarter, Williams also closed on the acquisition of Williams Partners, sold its Four Corners assets for $1.125 billion and began operating assets in Colorado’s DJ Basin that had previously been part of a joint venture. CNX 3^rd Qtr. Update CNX Resources reported third-quarter net income of $125 million, a strong turnaround from a loss of $26 million in the year-earlier quarter, Kallanish Energy reports. After adjusting for certain items, the Pittsburgh-based company had adjusted net income of $35 million. That compares to an adjusted net loss of $41 million in Q3 2017. The quarter was strong financially and for operational execution, the company said. Capital spending was $297 million in the quarter, compared to $150 million spent in Q3 2017, driven largely by increased drilling and completion activities in the Appalachian Basin. In the latest quarter, the company sold 119.0 billion cubic feet-equivalent (Bcfe) of natural gas, an increase of 18% from the 101.0 Bcfe sold one year ago. That was driven by a substantial increase in dry Utica Shale volumes from Ohio’s Monroe County, the company said. “During the third quarter, our team delivered targeted turn-in-lines with continued strong well performance,” said Nicholas J. DeIuliis, company president and CEO, in a statement. That operational execution led to expected production and lower cash costs, he said. The company’s Q3 2018 production included 70.6 Bcfe in the Marcellus Shale and 33.6 Bcfe in the Utica Shale. The Marcellus production was 17% higher than Q3 2017 production and the Utica Shale production was 67% higher than the year-ago production, the company said. In the quarter, CNX operated four rigs and drilled 23 wells including 15 Marcellus Shale wells in Greene County, Pennsylvania. It also drilled three dry Utica wells in Westmoreland County, Pennsylvania, three dry Utica wells in Monroe County, Ohio and two Marcellus wells in Tyler County, West Virginia. In the quarter, the company utilized three frack crews to complete 27 wells, including 15 Marcellus wells in Greene County, The company also turned-in-line 35 wells in the quarter. That included 15 Marcellus wells in Greene County, six Marcellus wells in Washington County, Pennsylvania, five Marcellus wells in Tyler County, West Virginia, four dry Utica wells in Ohio’s Monroe County and five wet Utica wells in West Virginia’s Harrison County. CNX said it expects 2018 production to peak in the fourth quarter with about 16 new wells expected to be turned-in-line. Total quarterly production costs dropped from $2.26 to $1.97 per Mcfe through reduction in lease operating expense, transportation, gathering and compression costs and depreciation, depletion and amortization, it said. Transportation, gathering and compression costs improved to a drier production mix and higher sales volumes, the company said. CNX also reported it has repurchased about 27.6 million shares for $425 million. The company has about $25 million left in its stock repurchase program that is set to expire on Dec. 31. It has an additional $300 million to repurchase with no expiration date. A total of roughly 8.3 million shares were purchased in Q3 2018. Eclipse Resources 3^rd Qtr. Update.  Independent producer Eclipse Resources, currently in the process of acquiring fellow independent Blue Ridge Mountain Resources, reported Wednesday recording-setting third-quarter revenue. Revenue for the quarter ended Sept. 30; hit $130.12 million, up from $91.55 million one year ago, Kallanish Energy reports. “For the third quarter of 2018, the company was able to achieve record revenue of $130.1 million, a 42% increase over the third quarter of 2017, while also posting a 46% increase in adjusted EBITDAX over the third quarter of 2017, which came in at a new company record of $66.8 million,” said Benjamin W. Hulburt, chairman, president and CEO. Eclipse’s crude oil and natural gas liquids jumped year-over-year, with crude production up more than 100%, to 574,800 barrels, while NGL production rose 34.2%, to 906,400 barrels during the three-month period. Natural gas production fell 14% year-over-year, to 22.98 billion cubic feet (Bcf), down from 26.72 Bcf. Higher commodity prices naturally helped the Pennsylvania-based independent, with oil reaching $52.67/Bbl, up from $42.42/Bbl, NGLs jumping to $27.66/Bbl, from $19.52/Bbl, while natural gas rose to $2.22 per million Btus (Mmbtu), from $2.20/Mmbtu. During the third quarter of 2018, Eclipse began drilling five gross (2.2 net) operated wells, commenced completions of eight gross (3.5 net) operated wells and turned to sales 13 gross (6.8 net) operated Utica Shale wells. Third-quarter operating income jumped into positive territory, to $21.19 million, from a $2.79 million loss one year ago. Profit for the quarter totaled $4 million, compared to a $16.69 million loss in the year-ago quarter. Commenting on the acquisition of Blue Ridge, estimated at an equity value of $908 million, Eclipse said progress on the merger closing is continuing as planned, with the deal expected to be consummated during the fourth quarter of this year. Pending completion of the merger, Eclipse said it’s received nonbinding commitments supporting an increase in the company’s revolving credit facility borrowing base of $150 million to $375 million, while extending the maturity of the credit facility to five years from the deal closing. Blue Ridge, headquartered in Irving, Texas, changed its name in 2017. It was formerly Magnum Hunter Resources, which declared bankruptcy in 2016 and ousted founder Gary Evans. Blue Ridge CEO John Reinhart will lead the combined company. He formerly was chief operating officer at Ascent Resources, initially created by Aubrey McClendon following his ouster from the company he co-founded, Chesapeake Energy. Reinhart had worked at Chesapeake for roughly nine years. Continental 3^rd Qtr. Update.  Strong production growth, particularly from its Bakken holdings, along with much-improved crude oil and natural gas sales powered Continental Resources to a more-than $300 million third-quarter profit increase. Also helping the Oklahoma-based independent producer were higher sales prices for both crude and natural gas: $65.78 a barrel vs. $43.27/Bbl in the third quarter of 2017 for crude; and $3.12 per thousand cubic feet vs. $2.74/Mcf one year ago for natural gas. Crude production jumped 17.1% year-over-year, to 164,605 barrels per day, up from 140,611 Bpd, Kallanish Energy reports. Gas production rose a strong 29.5%, to 793.79 million cubic feet per day (Mmcf/d), up from 613.06 Mmcf/d. The Company's Bakken production hit an all-time quarterly record, averaging 167,643 Boe/d in the quarter, up 23% from the year-ago quarter. During the quarter, the company completed 42 gross (26 net) operated wells flowing at an average initial 24-hour rate of 2,013 Boe/d. Continental currently has eight rigs drilling in the Bakken, up two rigs from last quarter to facilitate continued oil growth in 2019. In fourth quarter, production is expected to ramp significantly with up to 70 wells forecast to be completed by year-end 2018. "The performance and returns from the Bakken have been exceptional," said Jack Stark, president. "Our entire 2017 Bakken program, which included 133 operated wells, paid out by the end of third quarter 2018. Now that's capital efficiency." Continental third-quarter profit reached $314.17 million, up from just $10.62 million one year ago. Crude and gas sales jumped to $1.27 billion, from $704.82 million one year ago. Revenue for the latest quarter totaled $1.28 billion, up from $704.82 million one year ago. $5 NatGas.  The natural gas market is looking rather tight, even as U.S. production continues to set new records. Inventories fell sharply last winter, leaving the country a little light on stocks heading into injection season. That did not concern the market much, with record-setting production expected to replenish depleted inventories. However, the past six months has not led to surging stockpiles, and inventories replenished at a much slower rate than expected. We are about to enter the winter heating season with inventories at their lowest level in 15 years. For the week ending on October 19, the U.S. held 3,095 billion cubic feet (bcf) of natural gas in storage, or 606 bcf lower than at this point last year, and 624 bcf below the five-year average. The reason for this is multifaceted, with seasonal weather playing a role, but also structural increases in demand. “Hot summer weather, LNG liquefaction demand, exports to Mexico, and the industrial sector have all mitigated the impact from an 8.7 bcf/d YoY production growth surge this summer,” Bank of America Merrill Lynch said in a recent note. Low inventories and potential deliverability risks led the investment bank to hike its price forecast for the first quarter of 2019 to $4 per MMBtu, up from a prior estimate of just $3.40/MMBtu. Coal shutdowns have led to a lot of fuel switching. Moreover, new gas-fired power plants have opened up and continue to do so. The U.S. also became a sizable LNG exporter in 2016, and exports will continue to climb in the years ahead with more terminals coming online. New pipeline interconnections with Mexico should also lead to more shipments from Texas to the U.S.’ southern neighbor. Peak winter demand in the early 2000s stood at around 75 to 85 billion cubic feet per day (bcf/d), according to BofAML. That figure spiked to 100 bcf/d last winter, helping to explain the rapid decline in inventories. There was a cold snap in early January, but the winter on the whole was “near normal,” BofAML argues, making the steep fall in stocks all the more remarkable. In other words, demand is structurally much higher than it used to be; the sudden tightness is not just because of a seasonal anomaly. But, as always, natural gas markets can be highly volatile, and very sensitive to extreme weather. A cold snap this upcoming winter could lead to a price spike, especially with the inventory buffer so low. “The Polar Vortex winter of 2013-2014 realized a record low salt inventory level of 54 bcf,” BofAML said. Salt inventories are those that can be called upon quickly. “Another Vortex, which on average has occurred once every 7 years in the 1950-2018 period, would be catastrophic,” Bank of America Merrill Lynch warned. Unlike 2014, the last time we saw a polar vortex and a natural gas price spike, this time around there is a lot less coal to fall back on in the event that inventories plunge to low levels amid soaring demand. As a result, natural gas prices might be forced even higher. “A cold winter paired with higher coal prices and reduced gas-to-coal switching could propel NYMEX natural gas to a brief spike over $5.00/MMbtu,” BofAML said. This does not negate the long-term bearish forecast for natural gas prices. The U.S. shale bonanza continues, both in the Marcellus and Utica shales in the northeast and the Permian basin in West Texas. “Past this winter, we expect production to overwhelm demand growth and lead to above-normal inventories by 2H19 and a risk of storage congestion in 2020. Our average price forecast for 2020 remains $2.55/MMbtu, reflecting bearish longer-term fundamentals,” BofAML concluded. Still, in the short run, structurally higher demand and the prospect of another polar vortex, or merely below average temperatures this winter, could overwhelm what has been record natural gas production. More Challenges for Rover.  Rover Pipeline has been cited for three violations by the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration, Kallanish Energy reports. The violations are for improper testing of pipeline welds, failing to comply with specifications or standards on repairing dents to the steel pipe, and failure to build the pipeline to avoid stresses on the pipeline. The agency said the company committed “probable violations.” The violations could have triggered multi-million-dollar fines, but the federal agency said no fines would be imposed. The company said it is not contesting the violations and has been working with the federal agency to correct the problems. It said it is “in general agreement” with the agency’s proposed compliance order. The company has spent in excess of $11.5 million in correcting the problems, it reported. Those violations have prevented Rover Pipeline from beginning commercial service on its Sherwood and CGT laterals to move natural gas from the Appalachian Basin, the company acknowledged. The violations were discovered in Phmsa inspections on Jan. 25, March 19-22, May 8-11 and June 18. The violations were issued by the Phmsa on Sept. 11 and came to light in a recent company filing with the Federal Energy Regulatory Commission that oversees interstate pipelines. Rover Pipeline, an Energy Transfer Partners’ subsidiary, on Oct. 25 filed a request with FERC seeking to begin full operations on the Sherwood and CGT laterals prior to Nov. 1. It said the problems with the Phmsa had been corrected. It said its shippers “have urgently requested Rover to place these facilities in service to allow their stranded natural gas supplies to be transported to Midwest markets.” A similar request was filed last August. Those two laterals are mechanically complete and the final grading and seeding have been completed, Rover Pipeline wrote. The company said it has also filed plans for additional ground-movement areas outside the construction right-of-way along the Sherwood and CGT laterals. The Sherwood Lateral runs about 54 miles from eastern Ohio into West Virginia. The CGT line runs roughly six miles from the Sherwood line to an interconnection with a Columbia Gas Transmission line. They are among the last Rover laterals to be approved for commercial service. The $4.2 billion twin pipelines had encountered trouble with leaks and spills from horizontal directional drilling in Ohio where drilling had been halted for a time because of concern by state agencies. Construction was also halted for a time in West Virginia because of erosion and sediment control problems along pipeline laterals. The 713-mile pipeline will move up to 3.25 billion cubic feet per day of Utica and Marcellus natural gas to the Gulf Coast, the Midwest and Ontario. Initial service on the pipeline began Aug. 31, 2017. HHEX Hires Former Range Exec.  Huntley & Huntley Energy Exploration LLC (HHEX) said Oct. 30 it hired John Applegath, a former executive with Range Resources Corp. (NYSE: RRC), to serve as its senior vice president and COO. Applegath joins HHEX after recently retiring from Range Resources, where he served as senior vice president of operations from 2014 to 2018, leading both the Marcellus Shale division and, more recently, the North Louisiana division. “I am excited to join HHEX at this pivotal time in the company’s history,” Applegath said in a statement. “I look forward to returning to a basin I know extremely well and working with our industry partners, as well as the entire HHEX team.” HHEX is a privately-held energy company based in Canonsburg, Pa., that focuses on the upstream and midstream development of natural gas resources in the Appalachian Basin. The company has assembled a position in southwestern Pennsylvania of more than 100,000 largely contiguous and operated acres within the core Marcellus, Utica, and Upper Devonian fairways, according to the HHEX press release. At HHEX, Applegath will be responsible for the company’s operational and technical activities. His appointment is effective immediately. Huntley & Huntley Using Electric Fracture Stimulation.  Huntley & Huntley, with some 100,000 acres leased in southwestern Pennsylvania, has kicked its shale drilling program into high gear this year. Yesterday we told you that a former Range Resources veteran in charge of Range’s Marcellus drilling program has joined up with H&H. We have more H&H news: The company has contracted with oilfield services company U.S. Well Services to use “electric fracking”–natural gas powered electric fracture stimulation. It’s more environmentally friendly than diesel-powered fracking, reducing noise by 99% and fuel consumption by 90%. Williams Wins Eminent Domain Case.   Williams’ Transco Pipeline has just won a major eminent domain court case for its Atlantic Sunrise Pipeline project that will have implications for all pipelines. Yes, Atlantic Sunrise is now in the ground and flowing natural gas. However, a small group of landowners in Lancaster County opposed to Atlantic Sunrise resisted and would not allow Transco to build. So Transco sued and won a court order, based on the right of delegated eminent domain granted by the Federal Energy Regulatory Commission (FERC), to immediately take possession of those properties and build the pipeline. The landowners continued to fight the order and the case eventually ended up in federal court. EQT Midstream Plans New Pipeline.  EQT Midstream, which is about to be renamed to Equitrans Midstream Corp. in a few weeks, recently issued its third quarter 2018 update. As you know, the two are about to split and become two independent companies. As part of the EQT Midstream update, the new midstream company leaders spoke about Mountain Valley Pipeline (MVP), a 303-mile pipeline from West Virginia into southern Virginia. MVP has experienced a lot of setbacks, most of them from a campaign of lawsuits filed by Big Green organizations. A new pipeline project related to MVP was mentioned prominently in this week’s quarterly update. The pipeline is called Hammerhead. NatGas Production Up in the Appalachian Basin.  Over the past few weeks two new pipelines have come online: Williams’ Atlantic Sunrise and DTE Energy’s NEXUS. More capacity along Energy Transfer’s recently completed Rover also recently came online. The effect of the three combined has been dramatic. Production volumes have shot up another 1 Bcf (billion cubic feet) in the past month, to over 30 Bcf/d. And get this: While the Appalachian spot price for gas was $1/Mcf (thousand cubic feet) on Oct. 8 ($2 *below* the Henry Hub price), on Oct. 24 the Appalachian price was averaging $3/Mcf! Just 12 cents below Henry. A movement of $2/Mcf! Behold the power of pipelines and why we write about them so much. Joe Barone jbarone@shaledirectories.com 610.764.1232 Vera Anderson vera@shaledirectories.com 570.337.7149

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Natural gas proponents prepare to battle subsidized nukes

While the price is not at the optimum level, continued pipeline additions are helping to maintain, even raise the price of U.S. natural gas, even in the Appalachian Basin. One only needs to look at the number of natural gas-fired power plants that recently came online, are under construction or going through the permitting process to see the cleanest of fossil fuels is remaking how America’s power is produced.

Gas-fired plants in the pipeline

In the trio of states including Pennsylvania, Ohio and West Virginia alone, 30 natural gas-fired plants are somewhere in the development pipeline, totaling more than 26,500 megawatts of power, and investment pegged at more than $3 billion. But there is a potentially very large pothole in the way of the continuing march to natural gas dominance, Kallanish Energy reports. And having backers in extremely high governmental places could only make the pothole larger.

Some states offering subsidies

The concept of subsidies to owners of nuclear power plants, while shut down – at least temporarily – at the federal level, lives and is growing at the state level. Already, New York state, Illinois, Connecticut and New Jersey have passed legislation that offers subsidies under a variety of names (“handouts” to opponents) to nuclear power plant owner-operators. Nuclear plant owners say the subsidies are warranted because without them, their emissions-free facilities cannot compete with dirt-cheap natural gas or even with some subsidized wind and solar plants.

Subsidies, or handouts

Already, one of the U.S. major nuclear plant operators, FirstEnergy, has announced its nuclear power unit has filed for Chapter 11 bankruptcy protection. Billions of dollars of said subsidies – all customer-paid – will be given, officially to maintain zero-emission power, along with power plant jobs and tax base.

Nothing but politics

During last week’s annual Shale Insight 2018 conference in Pittsburgh, the topic of handouts to the nuclear industry was the focus of an early-conference panel discussion. And the presentations were somewhat foreboding. “What has happened in states like New York, Illinois, Connecticut and New Jersey is coming to these three states (Pennsylvania, Ohio, West Virginia),” said John Shelk, president and CEO of the Electric Power Supply Association. EPSA represents independent power producers and marketers.

“This is all about politics,” according to Shelk.

Shelk’s fellow panelist, Dean Ellis, former executive vice president Regulatory Affairs and Communications, at Dynegy, told the Shale Insight audience the concept of “grid resiliency” is a hot topic in the power industry. Subsidy proponents argue having nuclear power available increases resilience.

Reliability vs. resiliency

What is grid resiliency and how does it differ from grid reliability? One comparison states reliability is aimed at reducing the probability of power interruptions, while resilience is aimed at reducing the damage from outages and shortening outage durations. A recent study, “A Customer-focused Framework for Electric System Resilience,” by Alison Silverstein Consulting and Grid Strategies LLC, states “power system resilience should be measured from the end user’s perspective – how many outages happen (frequency), the number of customers affected by an outage (scale), and the length of time before interrupted service can be restored (duration).”

A ‘chilling effect’

Silverstein and Grid Strategies reported fellow consulting firm Rhodium Group determined less than 0.1% of customer outage-hours were caused by generation shortfalls or fuel supply over the 2012-2016 period. The panel agreed state subsidies will have a “chilling” effect on the power market – and will certainly impact the usage of natural gas. Not that the natural gas industry is going to back down from pushing its side in the great fuel debate. “We didn’t ask for a fuel fight,” Shelk said.  

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Facts & Rumors # 310

Expo/Industry events for the next few months

Marcellus Utica Houston November 7-8 JW Marriott Houston Galleria 5150 Westheimer Road Houston, TX 77056

http://www.marcellusuticahouston.com/

 

Downstream Petrochemical Value Chain November 15, 2018 Eagle Sticks Golf Club 2655 Maysville Pike Zanesville, OH

https://bit.ly/2CWeXjs

For other events visit

http://www.shaledirectories.com/site/oil-and-gas-expo-information.html

Latest facts and a rumor from the Marcellus, Utica, Permian, Eagle Ford, Bakken and Niobrara Shale Plays

Gulfport Energy 3^rd Qtr. Financial Update.  Gulfport Energy reported its net production in third-quarter 2018 grew 19% from the Q3 2017, Kallanish Energy reports. Net production in Q3 2018 averaged 1.43 billion cubic feet-equivalent pe4r day (Bcfe/d), said the company, a major player in the Appalachian Basin. Production was 1.20 Bcfe/d in the third quarter of 2017. The latest Q3 production was 89% natural gas, 8% natural gas liquids and 3% oil, the company reported last week. The company said its realized natural gas price for Q3 2018 averaged $2.32 per thousand cubic feet, its oil price averaged $68.73 per barrel and its NGL price averaged 74 cents a gallon, or $31.18/Bbl. Those prices are before the impacts of derivatives and include transportation costs. Gulfport reported it turned to sales 11 gross and net operated wells in the Utica Shale in the Appalachian Basin and 7 gross (5.4 net) operated wells in the SCOOP play in Oklahoma during the third quarter. “The third quarter marked another outstanding operational quarter for Gulfport, delivering a 7% increase in total production per day and realizing strong price realizations across all of our products,” said CEO and President Michael G. Moore, in a statement. “Gulfport’s third-quarter production increase was driven by continued outperformance of our base production wedge, an active turn-in-line schedule and an increase in ethane recovery during the quarter, maximizing the value received for the natural gas liquids stream,” he said. In Q3, the company produced 104.98 Bcfe from the Utica Shale in Ohio, 25.26 Bcfe from the SCOOP play, and 1.01 Bcfe in southern Louisiana. Utica production jumped from 90.82 Bcfe in Q3 2017, a 15.6% increase. Gulfport will release its 3Q 2018 financial data in the next few weeks. VA DEP Approves Atlantic Coast Pipeline.  Although the 600-mile Atlantic Coast Pipeline (ACP) was federally approved a year ago, in October 2017, the $6 billion pipeline from Dominion Energy running from West Virginia through Virginia into North Carolina had not yet secured all state-required permits. The remaining holdout has been Virginia. Late Friday afternoon the Virginia Department of Environmental Quality (DEQ) finally issued a “401” permit for crossing streams and rivers, which clears the way for ACP construction to begin in the Old Dominion. Satellite Imagery Reveals Permian Frack Trends.  New research gathered through daily satellite imagery reveals the impact infrastructure bottlenecks and differentials are having on frack crew count numbers and well completions in the Permian basin. Westwood Global Energy Group’s SatScout Service is responsible for the new data. “The Delaware and Midland Basins are paramount to the U.S. shale story,” said Boyd Skelton, vice president of operations for Westwood. “The public and private E&Ps we monitor are feeling the constraints in the Permian market. You can see the softening demand for horsepower, frack sand and water based on the decline in last month’s observed completions. The market,” he added, “is fluid with operators acting swiftly to changing conditions.” After a peak in well completions—510—that took place in June, Westwood’s team said completions in September across the Permian were down six percent to 472. According to the company, SatScout can identify when an operator has constructed a pad, rigged up for drilling, or started fracturing the well with a frack crew. Westwood’s aerial scouting service can provide such information on activity of public or private oil and gas operators before the information is reported in quarterly earnings, investor presentations or via state regulatory organizations. The system utilizes daily satellite imagery and a proprietary algorithm designed to identify key stages of well development. “We can analyze thousands of images in a fraction of the time it would require to do manually,” the company said. Energent Group, a Houston-based energy and shale analyst firm, creates and operates SatScout. In 2017, Westwood Global Energy acquired Energent. Mariner East 2 to Start Service.  U.S. energy company Energy Transfer LP plans to start service on its Sunoco Mariner East 2 natural gas liquids pipeline in Pennsylvania during the fourth quarter of 2018, an analyst following the company said on Monday: Energy Transfer told analysts at Height Capital Markets in Washington, DC, that the pipeline “will be in service as soon as it is mechanically complete, which is expected to be in the next few weeks.” That fits with the timing the company has told several customers of the pipeline, including U.S. energy producer Range Resources Corp and U.S. ship owner Dorian LPG Ltd , which owns very large gas carriers (VLGCs). When Energy Transfer’s Sunoco subsidiary started building the $2.5 billion Mariner East 2 in February 2017, the company expected to finish the project by the third quarter of 2017. Merkel Opens Germany to U.S. LNG.  German Chancellor Angela Merkel is  a move to open up Germany's market to U.S. gas companies, following a lobbying push from President Trump, The Wall Street Journal reported. Merkel told a group of lawmakers over breakfast in October that her government will co-finance a $576 million liquefied natural gas (LNG) shipping terminal in northern Germany, the Journal reported, citing people familiar with the meeting. The project had been stalled for years, but Trump has lobbied hard for Europe to increase LNG purchases from the U.S. while reducing their reliance on Russia. Germany gets most of its gas from Russia, and American efforts to open its market to U.S. companies have stalled due to lack of government support. Merkel told lawmakers that the decision to co-finance the LNG terminal was "strategic" and could pay off in the long term, people familiar with the meeting told the Journal. A German government spokesman told the Journal that the move was made because of Germany's economic interests, not U.S. pressure. Less than a week after the reported Merkel meeting with lawmakers, an international consortium filed its first official bid for government financing for a terminal in a town near Hamburg. XTO Bullish on the Utica.  The Appalachian Basin’s Utica Shale holds great potential, according to XTO Energy’s Andree Griffin. Speaking to roughly 900 attendees Wednesday at the Shale Insight 2018 conference in Pittsburgh, Pa., at the Shale Insight 2018 conference. Griffin, XTO’s vice president, Geology and Geophysics, is a big believer in the Utica, found mostly in eastern Ohio, Kallanish Energy reports. “Do not underestimate the potential of the Utica Shale,” she told the audience. What’s happening there is “staggering and very exciting,” she added. It is a shale play where the surface has barely been scratched, she said. Only the beginning “You can tell this is only the beginning,” Griffin said of the Utica Shale. “The potential in the Utica is enormous.” The gassy Utica Shale is newer in terms of production and smaller than the neighboring Marcellus Shale and it's generally lumped together with the Marcellus Shale in reports. 40% of U.S. production Together, the Utica and Marcellus produce 40% of the natural gas in the U.S. -- about 29 billion cubic feet per day. Production in the Appalachian Basin could hit 8 trillion cubic feet this year. If they were a separate country, the Utica and Marcellus would rank third in the world for natural gas production behind the rest of the U.S. and Russia, Griffin said. To date, only about 2,400 Utica wells have been drilled in Ohio, plus about 230 in Pennsylvania and 15 in West Virginia, she said. The first Utica wells were drilled in Ohio in late 2011/early 2012. The Utica is deeper in West Virginia and Pennsylvania and that makes drilling more costly and more risky for drillers. Griffin's company has drilled roughly 75 wells in Ohio’s Belmont and Monroe counties, according to state records. XTO, an ExxonMobil subsidiary, has about 56,000 acres in Ohio and is producing 240 million cubic feet of natural gas per day (Mmcf/d), the company says. In Pennsylvania, XTO holds 534,000 acres and produces 220 Mmcf/d from 12 counties. In West Virginia, XTO has 140,000 acres with production totaling 50 Mmcf/d from eight counties, the company says. Happy 10^th Anniversary Eagle Ford Shale.  Secretary of Energy and former Texas Governor Rick Perry traveled to San Antonio to participate in the Shale-a-Thon, the celebration of the 10th anniversary of the completion of the first successful horizontal oil well into the Eagle Ford Shale formation.  That first well, drilled by Petrohawk Energy (later acquired by BHP Billiton), was announced on October 21, 2008, but the company's Chief Operating Officer, Dick Stoneburner, was notified of its successful completion via an email he received on October 11 while sitting in the stands in the Cotton Bowl as he watched the annual grudge match between the Texas Longhorns (Stoneburner is a UT graduate) and Oklahoma Sooners. Petrohawk's discovery set off a drilling boom over the next six years that at times saw the traditionally sleepy, rural area of South Texas become one of the hottest economic development regions in the country.  Traffic jams became commonplace in a 23-county region whose largest city, Beeville, boasts a population of around 14,000 on a good day.  At the boom's peak in 2014, more than 300 rigs operated in the region, with as many as 275 plumbing the dense rock in the Eagle Ford formation. Many wonder why it is called the "Eagle Ford" shale.  The formation is named for the community of Eagle Ford, which was once an incorporated city, but is now a neighborhood of Dallas, by which it was annexed in the mid-1950s. Not far from the center of the community, a small cliff face reveals an out-cropping of the Austin Chalk formation, which had become famous during the 1970s and again in the 1990s for the production of prodigious amounts of crude oil. In fact, the Chalk is experiencing a bit of a third revival today. Immediately beneath the Chalk outcropping, another formation displays what seems to be a rocky, clay-like profile. This formation is actually a shale formation, one that happens to be the source rock for the Austin Chalk. It was the oil migrating up from the Eagle Ford Shale that made the Chalk such a prodigious formation to begin with. More oil through Dakota Access pipeline.  The developer of the Dakota Access pipeline is gauging shippers’ interest in a possible expansion of the volume of crude oil moved through the pipeline from 500,000 barrels to 570,000 barrels per day, despite ongoing tribal efforts to shut the pipeline down. Texas-based Energy Transfer Partners on Oct. 19 began seeking commitments from shippers to transport additional oil. The pipeline’s permit in North Dakota allows it to ship up to 600,000 barrels per day. North Dakota produced nearly 1.3 million barrels of oil per day in August, the most recent month for which data is available. Companies can increase pipeline capacity by adding a chemical to make oil flow more easily, or by adding more pumping power or pumping stations, according to North Dakota Pipeline Authority Director Justin Kringstad. Company spokeswoman Vicki Granado told The Bismarck Tribune that an expansion would require minimal modifications to the actual pipeline system. Dakota Access was subject to prolonged protests during its construction in North Dakota in late 2016 and early 2017 because it crosses beneath the Missouri River, just north of the Standing Rock Sioux Reservation. The tribe draws its water from the river and fears pollution. ETP insists the pipeline is safe. That tribe and three others are fighting in federal court to get the pipeline shut down. Lack of Fractionation Causing Problems for Ethan Crackers.   A surge in production of natural gas from U.S. shale gas and tight oil plays, combined with new petrochemical ethane crackers coming online, have created a major hurdle for producers/purchasers of ethane due to a lack of adequate NGL fractionation. Simply put, a lack of capacity to separate/fractionate mixed natural gas liquids (Y-grade) into purity ethane is causing chemical producers major consternation, according to business information provider IHS Markit. “The U.S. upstream shale gas and tight oil revolution has translated into a petrochemical feedstock bonanza and significant cost advantages for U.S. chemical producers, but a misalignment between ethane purity product supply capacity and demand has driven a tight ethane market and a spike in price,” said Yanyu He, executive director, Asia and Middle East NGLs and Global NGL pricing at IHS Markit He is an author of IHS Markit Midstream and NGLs Analysis: Ethane—What Went Wrong? “We expect purity product ethane supply and demand to be tight through 2020, and ethane market price volatility is expected to persist through 2020," according to He. "The energy industry strives for alignment, but the unconventional upstream industry is much more nimble and responsive to price signals than the midstream sector. “We are now seeing the fall-out of underinvestment in midstream infrastructure that occurred during 2014 to 2016, after oil prices cratered and put the brakes on NGL-centric midstream infrastructure build-out,” he said. He said U.S. shale gas and tight oil producers have drastically improved their efficiency and can now bring a well into production in a matter of months, while adding capacity at a natural gas processing plant can take 12 to 18 months, expanding Y-grade pipelines and purity product NGL fractionation capacity can take up to three years, and steam crackers require four to five years to bring online from final investment decision (FID) to completion, Kallanish Energy finds. “From an investment standpoint, you have a months-versus-years cycle that causes misalignment across the upstream through midstream to downstream value chain,” He said. “Ironically, the increasing efficiency of the U.S. unconventional upstream energy sector has rapidly increased oil, natural gas, and correspondingly, by-product Y-grade NGL-production rates. The current production has surpassed the midstream supply chain’s capability to receive, process, produce, and deliver purity product ethane supply to the new U.S. Gulf Coast ethane crackers,” He said. And there is more demand coming as the industry is in the middle of the first wave of new U.S. ethane cracker-capacity additions built to consume advantaged ethane, IHS Markit said. Change at FERC.  Federal Energy Regulatory Commission Chair Kevin McIntyre said late Wednesday that he was relinquishing his chairmanship due to health problems and will simply serve as a commissioner, and President Donald Trump tapped Commissioner Neil Chatterjee to take McIntyre's place leading the agency. Nexus Seeks FERC Approval. Less than two weeks ago NEXUS Pipeline, a $2.6 billion, 255-mile interstate pipeline that runs from Ohio into Michigan, received permission from the Federal Energy Regulatory Commission to begin operation. NEXUS has begun to flow close to 1 billion cubic feet (Bcf) per day out of its eventual 1.5 Bcf/d capacity. NEXUS’ recent startup was a partial startup. NEXUS is now taking the next step. They asked FERC yesterday for an OK to start up service at two more compressor stations–one in Medina County, the other Sandusky County. Atlantic Coast Pipeline Gets FERC Approval.   Dominion’s 600-mile Atlantic Coast Pipeline (ACP) from West Virginia to North Carolina has had its share of setbacks. But these days, it appears the project is building momentum and government/regulatory decisions are breaking in ACP’s favor. The project is on track to finish by the end of 2019, so says Dominion. The latest win for ACP came yesterday when the Federal Energy Regulatory Commission (FERC) granted permission for ACP to begin construction pretty much in all locations in West Virginia. The only prohibitions are small areas in National Park Service land and a few locations where there may be Indiana bats. Two Permian Drillers Going on the Market.  Felix Energy LLC, a closely held Denver-based oil producer with operations in the largest U.S. shale field, is exploring a sale that could value the company at more than $3.5 billion, two people familiar with the matter said on Wednesday. The U.S. oil producer has hired investment bank Jefferies to solicit buyers, the sources said. Premium prices paid this year for acreage in the Permian Basin of West Texas and New Mexico, the largest and fastest growing oilfield, has smaller companies looking to cash in on their holdings. At the same time, higher crude oil prices have allowed bigger oil producers to acquire new holdings. Endeavor Energy Resources LP, an oil producer in Texas, also is exploring a sale that could value the company at more than $10 billion. Earlier this year, RSP Permian and Energex Corp were bought by Concho Resources Inc for $8 billion and Diamondback Energy Inc for $9.2 billion, respectively. Concho paid more than $70,000 an acre in its deal. Felix's management team sold assets in Oklahoma to Devon Energy Corp in January 2016 for more than $1.9 billion, according to the company's website. The company's acreage in the Permian Basin is concentrated in the oil-rich Delaware Basin in Loving, Winkler and Ward counties in Texas. Felix has more than 70,000 net acres in the Permian Basin, one of the people familiar with the matter said. PA NatGas Production Surpasses 17 billion cfpd.  Pennsylvania Department of Environmental Protection (PA DEP) published preliminary oil and gas well production data for August 2018 earlier this week. While we still observe marginal underreporting for August (with 250 million cfpd missing from HG Energy, which also delayed reporting for July), it is already obvious that shale gas production increased further from the level seen in July 2018. Taking into account reporting delays, we estimate that shale gas production in Pennsylvania surpassed 17 billion cfpd in August 2018 for the first time in history. In addition to a new all time-high production level, year-over-year growth reached a staggering 2.87 billion cfpd, which has not been seen since 2H 2012 – 1H 2014. Joe Barone jbarone@shaledirectories.com 610.764.1232 Vera Anderson vera@shaledirectories.com 570.337.7149

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