Expo/Industry events for the next few months
Marcellus Utica Houston
November 7-8
JW Marriott Houston Galleria
5150 Westheimer Road
Houston, TX 77056
Downstream Petrochemical Value Chain
November 15, 2018
Eagle Sticks Golf Club
2655 Maysville Pike
Zanesville, OH
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 3rd 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 3rd 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 3rd 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 3rd 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 3rd 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 3rd 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 3rd 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 570.337.7149https://www.shaledirectories.com/blog/facts-rumors-311/
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