Facts & Rumors # 313

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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

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