Facts & Rumors # 309
October 20, 2018
Expo/Industry events for the next few months
Shale Insight
October 23-25, 2018
David Lawrence Conference Center
Pittsburgh, PA
http://shaleinsight.com/
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
For other events visit
Latest facts and a rumor from the Marcellus, Utica, Permian, Eagle Ford, Bakken and Niobrara Shale Plays
5 Companies Prospering in the Eagle Ford. After years of playing second fiddle to the prolific Permian, the Eagle Ford shale play is slowly eyeing a comeback post the oil bust.
Make no mistake, the Permian Basin still remains the most sought-after unconventional basin and continues to post the biggest production gains in the United States. However, pipeline bottlenecks out of the region, which is expected to last well into 2019, has triggered spending outside of the Permian with one of the beneficiaries being the Eagle Ford.
The Eagle Ford Shale is already a well-known domestic oil play that churns out around 12% of America’s daily crude. But the producing basin is likely to experience heightened activity in the near-to-medium term with a portion of Permian capital set to land in this rich oil and gas-producing formation.
Eagle Ford Shale: Abundant in Oil and Gas
A sedimentary rock formation spread over 400 miles across Texas, the Eagle Ford Shale stretches from the Mexican border in the west to the Texas-Louisiana border in the east. It’s roughly 50 miles wide with massive recoverable oil and natural gas resources. Per the U.S. Geological Survey, Eagle Ford has an estimated average of 8.5 billion barrels of oil, 66 trillion cubic feet of natural gas, and 1.9 billion barrels of natural gas liquids there for the taking.
Permian’s Loss is Eagle Ford’s Gain
By now, it is well documented that serious logistical constraints in West Texas’s Permian ‘super basin’ is forcing operators in the region – especially those without committed pipeline capacity – to sell their produce at hefty discounts, which recently went up to $20 per barrel. EIA’s latest Drilling Productivity Report puts Permian oil production at around 3.5 million barrels per day, ahead of the current pipeline capacity of about 3.1 million barrels per day (per Bloomberg Intelligence).
The Permian bottleneck issue has compelled companies to shift drilling capital out of the area to other shale basins in the United States and the Eagle Ford has received a boost as a result.
Output, Investments Climb
Oil production from the Eagle Ford shale play is expected to see a monthly climb of 15,000 barrels a day to 1.438 million barrels a day in November, according to the most recent figures available. It’s the second largest climb among the big shale plays after Permian. One must also note that the formation has strongly rebounded from the low of 1.1 million barrels of a day in August 2017. Meanwhile, some 77 drilling rigs are currently active in the region, more than double from a low of 33 two years ago.
Investment in Eagle Ford is picking up as well. According to Canadian financial services provider Scotiabank, M&As in the field hit a whopping $15 billion so far this year – second only to Permian’s $45 billion. While not as ‘hot’ as the Permian, the region’s cheap acreage, coupled with proximity to the pipelines and refineries in the Gulf Coast, keeps the assets very relevant indeed. Finally, with oil prices likely to head higher, output in the second largest producing shale play is expected to stay strong.
Eagle Ford Shale Oil Stocks in Focus
With the hectic pace of drilling activity set to continue in the Eagle Ford play and investor’s strong appetite for stocks focused in that region, we present five companies that investors should watch out for.
EOG Resources, Inc. (EOG - Free Report) is the largest crude producer and acreage holder in the Eagle Ford shale, boasting of more than 500,000 net acres. The company has identified 7,200 locations — both drilled and undrilled — with resource potential of around 3.2 billion barrels of oil equivalent.
WildHorse Resource Development Corporation (WRD - Free Report) is one of the largest operators in the Eagle Ford play, holding a total of 418,000 net acres. In fact, following two separate acquisition deals, the company has become a pure play Eagle Ford operator with a 70% oil-weighted portfolio.
SM Energy Company (SM - Free Report) controls around 165,000 net acres in the Eagle Ford. The company is currently running a rig and a fracking fleet in the play and expects to complete four net wells in the upcoming quarter.
Marathon Oil Corporation (MRO - Free Report) has 145,000 net acres in the Eagle Ford. In the second quarter, Marathon Oil churned out an average of 106 thousand barrels of oil equivalent per day (59% oil) from the play. The company’s holdings in the area are a significant contributor to its free cash flow on the back of strong of well performance.
Penn Virginia Corporation (PVAC - Free Report) is another pure play Eagle Ford shale operator, having approximately 84,000 net acres (92% held by production). The company expects to grow production by 30% in the second half. Moreover, Penn Virginia’s acreage contains 82.6 million oil equivalent barrels in proved reserves.
FERC Commissioner is an “Anti.” For some time we’ve noticed that both of the Democrat members of the Federal Energy Regulatory Commission have been voting against NatGas pipeline projects using the excuse of mythical man-made global warming (euphemistically labelled “climate change”). It used to be, under Lord Obama, that Commissioner Cheryl LaFleur didn’t use the climate change excuse when deciding about projects. But something happened. Someone got to her. Maybe Chuck Schumer? Nancy Pelosi? Somebody has told LaFleur if she ever wants another job in the DC swamp after she leaves FERC, she needs to start vetoing pipeline projects. And so she does. Using global warming as the excuse. LaFleur talked about her new-found penchant to use global warming in FERC decision making at the North American Gas Forum this week in DC.
Initial Impact of Atlantic Sunrise. (Thank you, BTU Analytics) Last week, FERC authorized Williams to place the remaining Atlantic Sunrise facilities into service, which they did on October 6
th. This is big news for Northeast Pennsylvania where production growth has been limited by infrastructure constraints, and the facilities placed into service over the weekend bring another 1.15 Bcf/d of capacity out of the region (0.55 Bcf/d of mainline capacity was placed into service earlier this year). Several of the largest shippers on Atlantic Sunrise indicated that they will initially fill their commitments with a combination of new production and redirected gas, and in the first few days, gas in Susquehanna County has been redirected primarily from Tennessee (TGP) to help fill Atlantic Sunrise’s Central Penn North line.
As the chart above shows, production receipts are relatively flat versus a few weeks prior, and production even slumped at times in September when prices weakened (check out the latest
Northeast Gas Outlook for more details). Production receipts have hovered around 10 Bcf/d for the last six months as shown in the chart below.
As we discussed in a previous analysis that applied
learnings from Rover to Atlantic Sunrise, we are not expecting a one-for-one increase in production alongside increased capacity.
Atlantic Sunrise’s path bridges Northeast Pennsylvania with Southern Pennsylvania via the Central Penn South line stretching from Columbia County to Lancaster County at the River Road interconnect where gas can either continue along the mainline towards the Atlantic Seaboard or move into New Jersey. So far, flows along this segment are nearly 100% utilized, and Transco is constrained moving gas into Maryland. Flows into Maryland have been constrained outside of peak winter months since 2015, but expansions on the Transco mainline as part of Atlantic Sunrise have allowed flows to increase from 1.57 Bcf/d in April to 2.34 Bcf/d over the last three days, an increase of 0.77 Bcf/d.
East Coast pricing volatility is top of mind after this year began with the ‘Bomb Cyclone’ event that sent some prices well above $100/MMbtu, and with storage in the east well below 5-year averages, many are concerned about how prices would respond with severe weather this winter. While Atlantic Sunrise increases the gas supply in Southern Pennsylvania and Southern New Jersey (Transco Zone 6 South), there are other system bottlenecks to consider when thinking about Transco Zone 6 pricing. Check out the
Northeast Gas Outlook for our views on how Atlantic Sunrise, Rover, Nexus, Gulf XPress, and other projects influence production and pricing through 2023.
Kinder Cancels Utica Marcellus Texas Pipeline. Kinder Morgan has decided to shelve its Utica Marcellus Texas Pipeline project, the company said at the presentation of its third-quarter financial results. Instead, Kinder Morgan said, it will focus on its existing Tennessee Gas Pipeline, which transports natural gas from the Gulf Coast in Louisiana to the northeast, including New York and Boston.
The UMTP was supposed to transport natural gas liquids from the Utica and Marcellus shale plays to the Gulf Coast in Texas. Back in 2015, the company filed with the Federal Energy Regulatory Commission to abandon the TGP project in favor of the UMTP, which would have had a design capacity of 430,000 barrels daily. Now, the company will instead start working on reversing the flow of the TGP and is looking for producer commitments for the route between Appalachia and the Gulf Coast.
Kinder Morgan exceeded analyst expectations with its third-quarter results, reporting a net profit of US$693 million and announcing a quarterly dividend of US$0.20 per share. The net result compares with US$334 million booked in the third quarter of 2017. Cash flow also improved, rising 4 percent from Q3 2017 to US$1.1 billion, Kinder Morgan said
October Oil Production Up. Crude oil production in the Lower 48 U.S. states’ seven most productive unconventional basins/plays is projected to increase by 98,000 barrels per day from October to November.
According to the Energy Information Administration’s October Drilling Productivity Report (DPR), November’s total daily crude production will reach 7.71 million barrels per day (Mmbpd), from 7.62 Mmbpd in October. (All numbers are rounded.)
Just three of the seven regions are projected to report double-digit increases from October to November, led by the “hottest” oil play possibly in the world: the Permian Basin in West Texas/southeast New Mexico.
The latest DPR expects crude production in the Permian to grow by 53,000 Bpd, to 3.55 Mmbpd, from 3.50 Mmbpd in October, Kallanish Energy learns.
The Eagle Ford Shale play and the Bakken combined are projected to see a 28,000 Bpd increase in crude production from October to November.
The Eagle Ford will grow by 15,000 Bpd, to 1.44 Mmbpd, from 1.42 Mmbpd, while the Bakken will see a 13,000 Bpd increase, to 1.35 Mmbpd, from 1.34 Mmbpd.
One of the seven basins/plays is expected to see no change in production from October to November. The Haynesville Shale’s crude production should maintain 43000 Bpd, the DPR projects.
Combined, the Anadarko, Appalachia (Marcellus and Utica Shale plays combined), and the Niobrara are expected to see a 17,000 Bpd increase in crude production from October to November.
DUCs Continue to Climb. The number of drilled, but uncompleted wells located in the most productive/busiest basins/plays in the Lower 48 U.S. states continues to rise, up 2.3% from August to September, the Energy Information Administration’s Drilling Productivity Report (DPR) found.
The number of so-called DUCs rose by 192 from August to September, even though just three of the seven regions surveyed reported an August-to-September increase, Kallanish Energy finds.
The largest number of DUCs was in the Permian Basin, up 194, to 3,722 DUCs in September, from 3,528, the October DPR found. The next-largest increase was in the Anadarko, up 31 DUCs, or 3.1%, to 1,045, from 1,014.
Four of the seven major drilling basins/plays reported a drop in DOCs, although the total decrease was just 51.
The biggest August-to-September drop was in Appalachia (the Marcellus and Utica Shale plays combined), which reported a 22-DUC drop, to 665, from 687, the October DPR reported.
The other basins/plays include the Bakken, Eagle Ford, Haynesville, and Niobrara.
Permian Drillers Selling Light Crude. Oil producers in the Permian Basin have started selling a new stream of light crude, said people familiar with the matter, securing a market for the increasingly less dense oil being pumped from the largest U.S. shale play.
Sales of West Texas Intermediate Light, or WTI Light, started in September with deliveries into Midland, Texas, the people said. Most of the supply for WTI Light would likely be coming from more recently drilled parts of the region, such as Loving and Culberson counties, with initial volumes estimated at around 100,000 bopd, they said.
The new stream is being primarily blended to produce so-called Domestic Sweet crude, WTI Midland or benchmark WTI for delivery at Cushing, Okla., the people said. While lighter oil is typically higher-priced, the new grade is being sold at a discount to WTI Midland, the people said.
Separating the light grades would ensure a more consistent specification for the premium crudes, said Sandy Fielden, director of research for the commodities and energy group at Morningstar Inc. There’s a lot of relatively light streams coming out of the Permian, particularly the Delaware Basin, where most of the new drilling is taking place, he said.
"Typically, people try and blend the lighter crude with heavier streams," Fielden said. "But because there’s more light oil, the genuine WTI Midland gets a premium because that’s what refiners want."
WTI Light has a gravity of 45-50 API, lighter than the typical 38-42 API of WTI Midland, the mainstay sweet benchmark.
The sales began after the construction of enough tanks in the region to enable different oil grades to be separated. The new grade will be shipped from Midland in pipelines including those operated by Enterprise Products Partners, Magellan Midstream Partners, Plains All American Pipeline LP, the people said.
Enterprise can transport numerous grades of crude oil, including WTI Light, Rick Rainey, a company spokesman, said by email.
"There’s room for more segregation instead of just West Texas Sour and WTI Midland crudes," Neil Earnest, president of industry consultant Muse Stancil & Co., said in a phone interview. "The growing production from the Permian has given rise to increasing variety of crudes."
Magellan spokesman Bruce Heine couldn’t immediately comment. Plains All American didn’t immediately respond to an email seeking comment.
In fact, the segregation of lighter oil might pave the way for more U.S. crude exports because steady quality of grades that are in demand would ensure regular buyers. "The U.S. has to be competitive in price, a key driver of crude exports," Fielden said. "But it’s more convenient for producers and refiners if the U.S. can compete on quality."
Texans Save $60B. Throughout the years, advances in horizontal drilling and hydraulic fracturing have helped boost natural gas production in Texas. In fact, Texas leads the United States in oil and gas production and produces more than one-third of the nation’s crude oil supply. In 2016, Texas led the United States in natural gas production. Production helped consumers save nearly $60 billion between 2006 and 2016, according to a report by the Consumer Energy Alliance (CEA) released Oct. 15. Commercial and industrial users accounted for $52.4 billion of the savings while residential users accounted for $7.2 billion. It’s no secret that Texas’ economy is driven by the oil and gas industry. According to the CEA’s report, the state’s oil production contributed more than $2 billion to the budget and natural gas production contributed almost $1 billion in fiscal year 2017. In July, Texas oil economist Karr Ingham said the Texas upstream oil and gas industry had added 47,000 jobs at mid-year (end of June), with 4,800 upstream jobs added in June alone. Texas was also producing oil at record levels with fewer rigs. In 2018, oil and gas extraction has been the fastest growing sector at 13 percent, year to date, the report finds. This has led to a surge in demand for skilled workers.
OH Supreme Court Keeps Anti-Fracking Issue of the Ballot. The Ohio Supreme Court has denied an effort by environmental group Columbus Community Bill of Rights to get the issue on the ballot after it filed a motion for reconsideration in September. “We are discussing many tactics to face the issue of frack waste in our watershed, as well as the roadblocks to initiatives that many communities and efforts are experiencing,” said Carolyn Harding, a member of Columbus Community Bill of Rights. This marks the third attempt the environmental group has made to get the measure on the ballot. The group was hoping to gain voter support to establish a “bill of rights” for residents related to quality water, soil, and air protection as well as ban oil and gas extraction activities within the city.
PA DEP Overstepped Its Authority. Pennsylvania's Department of Environmental Protection overstepped its regulatory authority by imposing rules on hydraulic fracturing that went beyond what the state allowed in its oil and gas law, an attorney for the Marcellus Shale Coalition argued before the Commonwealth Court of Pennsylvania on Wednesday.
The shale industry group argued that the disputed regulations — over issues such as how companies must restore a site after drilling is completed or what equipment is allowed on-site — were unsupported by the law, while the DEP countered that it was exercising its regulatory authority to interpret and implement legislation, and had based the rules on laws beyond just the 2012 Oil and Gas Act, also known as Act 13.
"There's not express authority for any of these," said Jean Mosites of Babst Calland Clements & Zomnir PC, representing the Marcellus Shale Coalition. "You just have to look at the plain language of the statute side-by-side with the language of the regulations."
Wednesday's en banc arguments before the appeals court in Pittsburgh were the latest step for the years long challenge that put a hold on four of the seven challenged rules while the courts decided them piecemeal. In August, a Commonwealth Court ruling partly upheld the DEP's notification requirements, but scaled back on the types of adjacent properties that would trigger the requirements.
Mosites said Wednesday that the DEP's mandate to protect the environment under the Pennsylvania Constitution's Environmental Rights Amendment didn't give it authority beyond what the legislature gives the department in the law. She also said the department violated the Commonwealth Documents Law — which sets the procedures for amending administrative regulations — by significantly changing some of the rules between their initial publication and their final form.
Judge P. Kevin Brobson said the DEP appeared to be less stringent in interpreting some of its own regulations than the coalition feared they would, but because some of the rules had been on hold following a Supreme Court of Pennsylvania injunction, there had been no cases where some of the contested rules were actually applied.
"Why not wait until you have to actually restore a site ... instead of us sitting here discussing it in the abstract?" he asked.
Mosites replied that some of the challenged rules had not been subject to the injunction and had taken effect, and the others, even if they aren't enforced by the DEP, could still leave drillers open to lawsuits.
"If you leave it on the books when it's clearly contrary to the statutes, it's going to be subject to enforcement by third parties," she said.
Elizabeth Davis, assistant counsel for the DEP's Office of Chief Counsel, disagreed with Mosites and members of the court that some of the rules' provisions were vague or in conflict with the underlying law.
For example, while Act 13 stated that a drilling site has to be restored to its "original contours" of hills and valleys if a driller gets an extension beyond its initial deadline to restore parts of the site that had been given over to equipment and storage, the DEP regulation indicated that sites should always be restored to their original contours. Davis argued it was within the DEP's power to impose that stricter standard.
"Ensuring well sites are properly restored is directly connected to ensuring the protection of the environment," she said. "The legislature sets broad policy, the department interprets and implements it."
Judge Brobson questioned if the regulations could be too narrow and specific, pointing to the DEP's restrictions on what equipment can be on a well site after the initial drilling is finished. The DEP's list of acceptable equipment didn't account for new technology or equipment, even if it might make wells safer, he said, and Davis couldn't say how that might be addressed within the regulatory framework.
Joe Barone jbarone@shaledirectories.com 610.764.1232
Vera Anderson vera@shaledirectories.com 570.337.7149https://www.shaledirectories.com/blog/facts-rumors-309/
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