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 Expo/Industry events for the next few months

Veolia Water Treatment Seminar
Wednesday, November 8
Hilton Garden Inn Pittsburgh/Southpointe
1000 Corporate Drive
Canonsburg, Pennsylvania 

For other events visit

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

Two Major FERC Approvals.  Federal regulators on Friday approved two major natural gas pipelines for construction on the East Coast, a move heralded by business leaders and condemned by environmentalists.

The Federal Energy Regulatory Commission granted approvals for the Mountain Valley and Atlantic Coast pipelines, according to The Associated Press. One of the three commissioners dissented.

Court Refuses Constitution Pipeline Rehearing.  A federal appeals court has refused to grant a rehearing for Constitution Pipeline Co. concerning its legal fight with New York state over a water permit, Kallanish Energy reports.

That decision came last week from the U.S. Second Circuit Court of Appeals in New York City. Last August, the appeals court ruled against the pipeline and supported the state’s actions.

New York has refused to issue a water certification permit for the $1 billion project, effectively blocking the 121-mile natural gas pipeline from northeast Pennsylvania into New York. That action by the state Department of Environmental Conservation came in April 2016.

The project had been approved by the Federal Energy Regulatory Commission.

The pipeline is a joint project by Williams, Cabot Oil and Gas, Piedmont Natural Gas and WGL Holdings.

It would run from Dimock, Pa., to Schoharie County in New York, and transport 650,000 million cubic feet per day (MMcf/d) of Marcellus Shale-produced natural gas, or enough gas to heat 3 million houses.

Underground Storage Ramping up in Monroe County, OH.  Mountaineer NGL Storage said Thursday it’s planning to invest $150 million over the next three-to-five years in an Appalachian storage facility and said, if market demand is strong enough, their total private investment could top $500 million.

Mountaineer NGL Storage Managing Director David Hooker said support for the regional effort has been strong “and we believe that the Mountaineer NGL Storage Project highlights how the private sector can take steps to address critical storage solutions for the burgeoning petrochemical industry.” Hooker said they think the investment “will encourage significant additional NGL infrastructure support in the region, as well.”

Hooker said the project is still in the planning stages, pointing out the company has worked with state officials on permitting “and at least we have a path forward.”

“Our expectation is we should see our permits sometime in the first or second quarter next year,” he said. “We should be able to begin construction at that point.”

Cabot 3rd Qtr. Update.  Domestic energy explorer  Cabot Oil & Gas Corporation COG reported third-quarter 2017 earnings per share - adjusted for special items - of 7 cents, missing the Zacks Consensus Estimate of 8 cents on lower-than-expected natural gas price realizations, increased costs and weaker-than-expected production. The Zacks Consensus Estimate for natural gas realization was pegged at $2.32 per thousand cubic feet as against the reported $2.03. Further the estimated current production stood at 172 billion cubic feet equivalent (Bcfe) as against the reported $169.5 Bcfe.

However, earnings of 7 cents compares favorably with the year-ago quarter's adjusted loss of 4 cents. Results advanced year over year and were driven by improvement in the commodity pricing environment which in turn led to higher realized oil and gas prices.

Houston, TX-based Cabot's quarterly revenues improved 24.2% year over year to $385.4 million but was below the Zacks Consensus Estimate of $407 million.

Volume Analysis

Cabot's overall production during the quarter totaled 169.5 Bcfe as against 150.8 Bcfe in the prior-year quarter. Natural gas output was 161.2 Bcf in the quarter under review; while crude oil production came in at 1,268 thousand barrels (MBbl) and natural gas liquids was 124.7 MBbl.

Realized Prices

The average realized natural gas price improved by 16% from the year-ago quarter to $2.03 per thousand cubic feet, while average crude/condensate price realization rose 13% to $45.53 per barrel. Meanwhile, natural gas liquids fetched $17.04 per barrel, an increase of 35% compared to third-quarter 2016.

Costs & Expenses

Total operating expenses rose to $332.1 million, 9.3% higher than third-quarter 2016. In particular transportation and gathering expenses were up 11.6% to $117.9 million. Further, Cabot's exploration and depreciation costs also increased. Depreciation charges incurred in the quarter came in at $146.3 million, as against $139.5 million in the year-ago quarter. Exploration charges stood at $6.5 million compared with $2.9 million in the third quarter of 2016.

Drilling Statistics, Capital Expenditure & Balance Sheet

During the quarter, Cabot drilled and completed 13.2 net wells and placed 15.2 net wells on production. Operating cash flows were $189.1 million for the quarter compared with $105.4 million in the prior-year quarter. Capital expenditures totaled $193.5 million (up 126%). As of Sep 30, 2017, the company had $510.3 million in cash and $1,284.6 million in long-term debt with a debt-to-capitalization ratio of 32.7%.

Guidance Update

For the fourth quarter, the company projects net production of 1,775 to 1,850 million cubic feet per day for natural gas 13,250 to 14,250 barrels per day for crude oil and condensate and 1,350 to 1,450 barrels per day for NGLs. Cabot has reiterated its capex budget for 2017 at $845 million.

Cabot has also provided preliminary guidance for 2018. It projects the production growth to be in the 15-20% range in 2018. The production growth is based on a capex range of $1.02-$1.15 billion.

Cabot plans to operate three rigs in the Marcellus Shale during 2018. It has forecasted a capex of $750-$850 million in the Marcellus region. The company anticipates delivering a three-year Marcellus production compounded annual growth rate from 2017 to 2020 of 20%.

EQT’s Bullish Comments on Rice Acquisition.  Natural gas producer EQT today touted its recent $6.7bn acquisition of Rice Energy ahead of a November 9th shareholder vote.

On an earnings call, EQT executives said the Rice purchase will increase its Marcellus Shale acreage and allow it to drill longer horizontal wells.

Shareholders will vote to approve the transaction to make EQT the largest natural gas producer in the US with a 2017 combined production of 1.3 Tcf of natural gas equivalent (Tcfe/d) (37bn m³/d). The boards of directors of both companies approved the deal in June, starting off a rare consolidation in a sector that has increasingly seen asset sales in recent years amid weak gas prices. EQT would gain a total of 421,000 acres across the Utica, Marcellus and other gas-producing formations in the northeast US, boosting its total holdings to 1.5mn acres.

EQT's new acreage would allow the producer to raise its average drilling length to 12,000ft laterals in the Marcellus from its current 8,000ft, drilling further into the shale along contiguous acreage in order to boost output, executives said today.

"The primary driver of success is being a low-cost producer, and the most impactful way to drive costs lower is through longer laterals," chief executive Steve Schlotterbeck said. "A dominant footprint of contiguous acreage is a real competitive advantage, and this is what the Rice transaction creates for us."

Schlotterbeck said EQT has had "hundreds of conversations" with shareholders since the company announced the acquisition in June. Shareholder suggestions resulted in the company committing to add two new independent directors to the board with a focus on midstream, among other measures.

Schlotterbeck pointed to Greene County, Pennsylvania, as one example where the combined acreage provides opportunity. The Rice Energy deal will allow EQT to control 212,000 acres there, or 57pc of the total county. Of the acreage that would be under EQT control, 80pc has yet to be drilled at all.

"There's a lot of remaining inventory acreage and a tremendous amount of lease sources in play, and we are very confident in our ability to deliver on that," Schlotterbeck said.

EQT's 1.9 Bcf/d Mountain Valley pipeline (MVP) is one way the producer plans to move its ballooning output out of Appalachia. The line was approved by the US Federal Energy Regulatory Commission (FERC) during the third quarter. MVP still needs approvals from West Virginia and Virginia before FERC will provide notice to proceed with construction, but EQT has been in "constant conversations" with the two states and does not expect any major obstacles, senior vice president of Midstream Jerry Ashcroft said.

The pipeline would ship gas produced in West Virginia to Transcontinental Gas pipeline's compressor station 165 in Pittsylvania County, Virginia. EQT has 80pc of the pipe ready to install and will be ready to begin construction in the beginning of 2018 and place the line into service by the end of that year.

"Station 165 gives us the opportunity to move into the southeast and into the Gulf coast. Petrochemical facilities in Louisiana and Texas are really expanding, and also population growth in the southeast is a big pull," Ashcroft said.

EQT had sales volumes of 2.2 Bcf/d of natural gas equivalent (Bcfe/d) during the third quarter, up by 5pc from a year earlier. EQT's third quarter average realized price was $2.76/1,000 cf, up by 26pc on the year.

Range 3rd Qtr. Update.  Range Resources Wednesday reported record-high third quarter production, Kallanish Energy reports.

The Fort Worth, Texas-based company reported production of 1.99 billion cubic feet-equivalent per day (Bcfe/d), a 32% increase from Q3 2016.

Natural gas accounted for 66.6% of Q3 production, with natural gas liquids and oil/condensate together accounting for 33.4%, mostly in the Marcellus Shale in Pennsylvania.

Oil production jumped by 59% and NGLs increased by 32% from the year-ago quarter. The company is projecting Q4 production of roughly 2.17 Bcfe/d.

Production in the Marcellus Shale in the Appalachian Basin averaged 1.6 net Bcfe/d, a 15% increase over Q3 2016, Range said.

The company brought on line 22 Marcellus wells in the third quarter: 11 in the super-rich area of the play; 10 in the wet area; and one in the southwest dry area.

Two four-well pads were completed in the super-rich area with seven wells turned to sales in the quarter. The wells averaged 41.3 million cubic feet-equivalent per day (MMcfe/d), with 64% liquids, including 20% condensate. The company said it expects to begin sales on 46 wells in the Marcellus in the fourth quarter.

It also began sales in Q3 from seven wells in northern Louisiana and expects to begin sales on 16 additional wells in the Q4.

Range said it’s drilling longer laterals and getting better results. It averaged 6,171 feet per lateral in Q3 2016 and averaged more than 11,700 feet in Q3 2017, the company said.

The company reported a Q3 net loss of $127.7 million, compared to a net loss of $41.9 million in the year-earlier quarter. The company reported Q3 2017 revenue of $482.2 million, a 17% increase from one year ago.

Its price realization in the quarter was $1.82 per thousand cubic feet (Mcf), up 15% from a year earlier. Prices paid for natural gas rose 12%, NGLs jumped 29%, while oil prices fell 3%.

“This is an exciting time for Range, as we are nearing an inflection point in our Marcellus development and as we continue to improve well results in north Louisiana,” said CEO Jeff Ventura, in a statement.

“In the Marcellus, the last of our natural gas transportation projects are coming on line over the next few months, which will allow us to develop our Marcellus position over the long-term while having access to better priced markets,” Ventura said.

“This buildout process has been years in the making and we believe Range’s combination of high-quality assets and infrastructure provide a solid foundation to deliver strong returns for many years.”

EQT Not Concerned WV DEP Delays.  Yesterday EQT provided an update for both its drilling and midstream operations. On the midstream side, EQT had an interesting comment about its biggest project on the books–the Mountain Valley Pipeline (MVP). MVP is a $3.5 billion, 303-mile natural gas pipeline that will run from Wetzel County, WV to the Transco Pipeline in Pittsylvania County, VA. The Federal Energy Regulatory Commission (FERC) issued a final approval for the project two weeks ago. However, the West Virginia Dept. of Environmental Protection (WVDEP) which had issued a federal water crossing permit for the project in March, withdrew the permit in September. The permit process has now restarted in WV. Anti’s in Virginia are pressuring the state’s Dept. of Environmental Quality to reject the project. Apparently the absence of permits in WV and VA isn’t bothering the brass at EQT because they said this about the project: “We don’t see any major obstacles.”

Doddridge County, WV – Marcellus Central.  There’s no question that Doddridge County is one of the most active counties in West Virginia, with respect to the Marcellus/Utica industry. Doddridge is home to MarkWest’s Sherwood complex, the single largest gas-processing complex in the Northeast with eight cryogenic processing facilities. Antero Resources, an active (really big) driller in Doddridge, is building a huge wastewater recycling facility in the county. As we reported in September, the tax base in the county has tripled over the past seven years. Dominion Energy also has a large presence in the county with hundreds of miles of gathering and interstate pipelines. Yes, Doddridge is a happenin’ place when it comes to the Marcellus. 

Nexus Construction Has Begun.. NEXUS Pipeline notified the Federal Energy Regulatory Commission (FERC) they had begun construction on the $2 billion, 255-mile interstate pipeline that will run from Ohio through Michigan and eventually to the Dawn Hub in Ontario, Canada. MDN purposely held off on sharing this exciting news until it could tell you where construction has begun. Each week NEXUS, like other interstate pipelines answering to FERC, provides a weekly update on construction and other project activities. Preliminary activities are taking place to move equipment, put up signage, and begin to work in “Spread 1”–meaning somewhere within Columbia, Stark, Summit, and Wayne counties in Ohio. Similar work is happening in “Spread 4”–meaning counties in Michigan. Initial site preparation is already happening at three of the four planned compressor stations. 

FERC Looking to Act on 62 Applications.  The Federal Energy Regulatory Commission last month approved three pipelines to take natural gas from the Marcellus and Utica shales to market.

The three projects were the Supply Header Pipeline, to transport 1.5 billion cubic feet per day (Bcf/d) via a 38-mile pipeline from West Virginia to Pennsylvania; the 600-mile, $5 billion Atlantic Coast Pipeline from West Virginia to North Carolina; and the 40-mile Eastern Shore 2017 Expansion project in Pennsylvania, Maryland and Delaware.

They were the first three projects to win FERC approval since the agency regained its quorum and thus its ability to approve projects that had been lost last February, Kallanish Energy reports.

With a resignation in February, the agency had only two commissioners, one member short of a quorum to take action. On July 1, FERC had but one commissioner.

Two new commissioners were approved by the Senate in August. Two additional commissioners are still awaiting a floor vote in the Senate.

Before losing its quorum on Feb. 3, FERC had certified more than 7 Bcf/d of pipeline capacity. Since then, as of Oct. 24, the agency had received 12 pre-filing applications for natural gas pipeline projects in the U.S. and 50 pipeline projects have FERC applications in process.

The capacity of those projects is about 43 Bcf/d, covering slightly less than 3,000 miles of new or upgraded pipeline construction, the Energy Information Administration reported.

At present, there are roughly 300,000 miles of interstate and intrastate natural gas pipelines in the U.S, it said.

The nine largest projects by capacity with applications before FERC have a total capacity of slightly more than 21 Bcf/d, or 63% of the capacity of all pending natural gas pipeline applications, EIA said.

Six of those projects, in Texas, Oklahoma and Louisiana, are intended to support liquefied natural gas (LNG) exports.

The two largest projects are the 137-mile Rio Bravo Pipeline in Texas, with 4.5 Bcf/d of capacity, and the 96-mile Driftwood Pipeline in Louisiana, with 4 Bcf/d capacity.

WV DEP Allows Mountain Valley Pipeline to Proceed.  The West Virginia Department of Environmental Protection has lifted the suspension of the state storm water permit for EQT’s Mountain Valley Pipeline project, according to Cabinet Secretary Austin Caperton.

The storm water permit was suspended in September to allow the state agency to properly respond to all public comments received.

The agency has also chosen to waive the individual 401 certification of the federal permits for the pipeline project. The Army Corps of Engineers recently reissued, with provisions that are specific to West Virginia, the nationwide 12 permit which is used for stream crossings.

These new conditions, when combined with specific requirements that are included in the state storm water permit, will allow for better enforcement capabilities and enhanced protection of the state’s waters, Caperton said.

Dominion Looking for Quick Approval of Atlantic Coast Pipeline.  Dominion Energy is confident the Atlantic Coast Pipeline will win final state approvals by mid-December, and construction can begin late this year, Kallanish Energy reports.

That assessment came Monday from Dominion Energy chairman, president and CEO Thomas Farrell II in a report and an  earnings call with analysts and the media.

Cooling West Cuts Permian Production. (Thank you, BTU Analytics) As temperatures in the Western US begin to show signs of cooling, US oil production continues to heat up as it recovers from hurricane impacts. However, cold weather induced supply disruptions are just around the corner as winter approaches. Permian freeze offs will continue to add to the market’s questions on the pace of US supply growth and the re-balancing of the 2018 oil market.

The graph below shows natural gas pipeline receipts on the interstate pipelines originating in the Permian basin versus Midland, Texas low temperatures.

As overnight lows drop in West Texas below 32 degrees, the amount of gas hitting the interstate pipelines begins to drop off. In part this is due to demand in the intrastate market absorbing a portion of the supply before it ever reaches the interstate pipeline network. But as temperatures plummet below freezing, bigger disruptions in gas and subsequently oil volumes become more evident in the data, with the worst Permian basin freeze offs occurring in January and December 2015.

Production interruptions due to freezing temperatures in the Permian  occur for two primary reasons. The first reason is that as the air temperatures fall, natural gas liquids and water that would otherwise normally be a vapor in gathering lines condenses. The condensed liquids clog up flow lines and restrict production across the system. Days with high variations in temperatures may see gathering pipelines experience freeze offs overnight only to have the afternoon temperatures warm up enough to naturally unclog the lines allowing flows to resume without sending workers into the field. However, extended periods of cold can result in more material freezing events which require time and effort to restore normal operations at the wellhead.

The second driver for production interruptions due to freezing temperatures is snow and ice on the roads. Significant volumes of crude in the Permian basin have historically been trucked from the wellhead to market. As cold weather strikes and brings ice storms to the region, truck traffic can decline dramatically. In addition to existing production, drilling and completion operations also see delays impacting the pace of new supply additions. So as winter approaches, how much impact might we expect from freezing temperatures in the Permian?

The table above reviews the impacts of freeze off events from the monthly state production data and allows us to remove the noise of volumes serving the intrastate market. Every winter experiences some level of freeze off event where production declines relative to the start of winter, though the magnitude and longevity of supply declines can vary significantly from year to year. In percentage terms, the Permian freeze offs in February 2011 knocked out 10% of monthly supply of natural gas and 8% of oil and in January 2015 outright volumes fell by more than 0.5 Bcf/d  of natural gas and 100 Mb/d of oil. However, last winter oil volumes grew despite natural gas volumes declining each month between Nov. 2016 and Jan. 2017. This likely occurred due to older wells with higher gas to oil ratios being more impacted than newer wells with lower gas to oil ratios.

The graph above highlights the risks to Permian volumes based on BTU Analytics’ Upstream Outlook forecasts for Permian natural gas and crude oil volumes for January 2018. Should winter of 2017-2018 experience an average freeze off, natural gas volumes would decline by nearly 0.5 Bc/d and nearly 75 Mb/d of crude oil would be taken offline. Should a colder and icier winter hit the Permian basin like in February 2011, at least 0.9 Bcf/d could be disrupted over the course of the month (a total of 27.5 Bcf shut-in) and nearly 200 Mb/d of oil or 6.4 million barrels of crude. While official start to winter is still two months away, the risk of weather based supply disruptions remains due to Permian freeze offs.

TX August Production.  Production in Texas in August totaled 75.18 million barrels (MMBbl) of oil and 583.79 billion cubic feet (Bcf) of natural gas, according to new data from the Railroad Commission of Texas.

Those are preliminary figures reported by operators and will be updated as new figures are provided to the state, Kallanish Energy reports.

In August 2016, the production figures initially reported were 75.03 MMBbl of crude oil, updated to the current figure of 84.13 MMBbl; a preliminary natural gas total of 606.93 Bcf, updated to the current total of 690.61 Bcf.

Total Texas production from July 2016 through August 2017, was 999 MMBbl of crude and 7.6 trillion cubic feet (Tcf) of gas, the commission reported.

Crude oil totals are limited to oil produced from leases and does not include condensate, which is reported separately.

In August 2017, preliminary crude oil production averaged 2.43 million barrels per day (MMBPD), compared to 2.42 MMBPD in August 2016.

Preliminary natural gas totals in August 2017 averaged 18.83 Bcf/d, compared to 19.58 Bcf/d in August 2016.

Texas production in August came from 179,726 oil wells and 92,729 gas wells.

The top county in August for crude oil production was Midland, with 7.6 MMBbl. It was followed by Karnes, Reeves, Upton and Martin counties.

Webb County was No. 1 for natural gas with 61.9 Bcf in August produced. It was followed by Tarrant, Dimmit, Panola and Midland.

Dimmit County was No. 1 for condensate in August, with 1.4 MMBbl produced. It was followed by Culberson, Webb, Karnes and Dewitt counties.

Gulfport 3rd Qtr. Update.  Gulfport Energy reported third-quarter production averaged 1.2 billion cubic feet-equivalent per day (Bcfe/d), Kallanish Energy reports.

That is a whopping 63% increase from third quarter 2016 production, the Oklahoma-based company said. That production was 88% natural gas, 8% natural gas liquids and 4% oil, Gulfport said.

The company reported realized natural gas prices of $2.21 per thousand cubic feet, oil prices of $36.32 per barrel and natural gas liquids prices of 41 cents per gallon in the third quarter. That produced a total price of $2.41 per thousand cubic feet-equivalent.

Gulfport is forecasting its realized 2017 natural gas price will be in the range of 62 to 68 cents per thousand cubic feet (Mcf) below NYMEX settlement prices.

Its 2017 natural gas liquids price will be 45% to 50% of West Texas Intermediate crude oil, and its 2017 realized oil price will be in the range of $3.25 to $3.75 per barrel below WTI.

In Q3, Gulfport turned to sales 19 gross (17.9 net) operated wells in the Utica Shale in Ohio and six gross (5.6 net) operated Woodford wells in the SCOOP play in Oklahoma.

The company will release its quarterly financial reports on Nov. 1, with a scheduled earnings call on Nov. 2.

Chesapeake 3rd Qtr. Update.  Chesapeake Energy has used new well-completion techniques to coax more production from its Utica Shale holdings.

Oklahoma City-based Chesapeake has drilled 735 Utica wells in Ohio, the most of any company.

In July, the company’s eight-well Ellie pad in Carroll County’s Orange Township began producing at an initial rate of 1,100 barrels of oil equivalent per well per day. Sixty-five percent of the production came from liquids, the company reported Thursday before a conference call with investors to discuss third-quarter results.

In the dry-gas part of the Utica, the three-well Schiappa Trust A pad in Jefferson County had an initial production rate of 20 million cubic feet of gas per well per day.

The company said new completion techniques improved 120-day Utica well results by 25 percent, and it planned to continue testing new completions designs in the Utica and Marcellus shales.

Chesapeake’s Utica production grew 24 percent from the previous quarter to 120,000 barrels of oil equivalent, but was still short of the 127,000 barrels equivalent produced in the third quarter last year.

Chesapeake’s total production averaged 541,600 barrels of oil equivalent per day during the quarter, including 86,000 barrels of oil, 2.4 billion cubic feet of natural gas and 58,600 barrels of natural-gas liquids.

The company’s revenue dropped 15 percent from a year ago to $1.9 billion, and it reported a net loss of $41 million, or $0.05 per diluted share for the quarter.

But that was an improvement over the third quarter of 2016, when Chesapeake lost $1.26 billion.

Halliburton 3rd Qtr. Update.  Houston-based oilfield services company Halliburton said Monday it’s pleased with the progress made in the third quarter in North America towards normalizing margins, proving its strategy is working, Kallanish Energy reports.

“Our North American business is hitting on all cylinders and our international business proved resilient in a challenging environment,” said Halliburton’s CEO Jeff Miller, in its quarterly results statement.

Total company revenue grew 10% compared to the second quarter, to $5.4 billion, while operating income reached $634 million vs. $128 million in Q2 2017 – mainly driven by continued strengthening of market conditions in North America and improved profitability in its Drilling and Evaluations product lines.

Profitability margins in the Drilling and Evaluations division, however, were seen by investors as “disappointing,” pushing the company’s shares down. Operating margins for this segment increased roughly 9%, while its revenue was up 4%.

“We outgrew our peers on a global basis, demonstrating that we are taking market share globally, and we generated industry leading returns,” defended Miller. He added the company’s “North American revenue increased by 14%, significantly outperforming the average sequential U.S. land rig count growth of 6%.”

The executive reassured analysts and investors on a conference call there are three things he plans to do to improve fracking profit: raise prices, maximize use of machinery and cut costs.

"Increasing pricing is important, but it’s just one component we can leverage to reach our goal," he said. "Ultimately, we will utilize a combination of all three levers to return to normalized margins."

Revenue generated in North America reached $3.2 billion in Q3, compared to $1.6 billion in Q3 2016. Halliburton said the improvement was mainly driven by higher utilization and pricing throughout the U.S. land sector in the majority of its services -- mostly pressure pumping, as well as higher well completion and pressure pumping activity in Canada.

Chevron 3rd Qtr. Update.  U.S. oil supermajor Chevron said Friday its overall third-quarter U.S. production fell despite output increases in the Permian Basin and Gulf of Mexico, Kallanish Energy reports.

The higher production from oil-producing regions was offset by asset sales and the natural decline of wells in other areas, the California-based company said.

U.S. production was down 17,000 barrels of oil-equivalent per day (BOE/d), driven by lower natural gas output.

Despite U.S. production fell, Chevron’s profit was up 52%, and revenue jumped roughly 20% from a year ago.

"We continue to see improvement in the underlying pattern of earnings and cash flow," Chevron chairman and CEO John Watson said, in a statement.

"… our shale and tight rock drilling activity in the Permian Basin is exceeding expectations," he added.

Chevron reported third-quarter earnings of $1.95 billion, on revenue of $36.21 billion. One year ago, the company earned $1.28 billion, on revenue of $30.1 billion.

Earnings in the oil giant's upstream segment improved slightly, to $489 million. The quarterly loss in the U.S. upstream business narrowed to $26 million from $212 million in the year-ago period.

Chevron's refining business saw profit jump 70% from a year ago, to $1.8 billion. The surge came from higher profit margins in the U.S. refining segment and gains from international asset sales.

Shell 3rd Qtr. Update.  Royal Dutch Shell Thursday posted better-than-expected third-quarter financial results, becoming the “top pick in Europe” for investors, according to global investment banking firm Jefferies, Kallanish Energy reports.

The Anglo-Dutch oil major reported $4.1 billion in earnings on a current cost-of-supply basis, its standard measure for profitability. The total is 47% higher than the $2.8 billion registered in Q3 2016, and also surpasses analyst forecasts of $3.6 billion.

Net income attributable to shareholders reached $4.1 billion in the third-quarter – 197% higher than the $1.37 billion posted a year-ago.

The results reflect higher contributions from downstream, upstream and integrated gas divisions. Earnings benefited mainly from stronger refining and chemicals industry conditions, increased realized oil and gas prices and higher production from new fields, offsetting the impact of field declines and divestments, Shell said.

Jason Gammel, global integrated oil & gas equity research analyst at Jefferies, said Thursday fundamentals in the crude oil market are improving and return-focused strategy is what investors are now looking for.

“Shell would be our top pick in Europe right now … and I think Shell has a very good path towards relieving their script dividend in the relatively near-term,” he said. “I think that will be a big catalyst for the stock here.”  

Chief financial officer Jessica Uhl told analysts and media (including Kallanish Energy) on a conference call over the last four quarters the company generated $40 billion in cash flow from operations excluding working capital, and for the fifth consecutive quarter free cash flow more than covered the cash dividend.

“The competitive performance is further evidence of Shell’s growing momentum and strengthens our firm belief that our strategy is working,” she said.

ExxonMobil 3rd Qtr. Update.  ExxonMobil saw its third quarter profit grow by 50%, despite a small financial setback from Hurricane Harvey, Kallanish Energy understands.

The company reported earnings of $3.97 billion, up from $2.65 billion in Q3 2016. The earnings increase was due largely to higher prices for crude oil and natural gas, the Texas-based oil giant reported.

Hurricane Harvey reduced earnings by about $160 million, the company said.

“A 50% increase in earnings through solid business performance and higher commodity prices is a step forward in our plan to grow profitability,” said Darren Woods, chairman and CEO, in a statement.

He added, “For the fourth consecutive quarter, we generated cash flow from operations and asset sales that more than covered our dividends and net investments in the business.”

Expenditures grew from $4.19 billion to $5.99 billion in 3Q 2017, a 43% increase.

The company reported cash flow from operations and assets increased 33% in Q3, to $8.4 billion including proceeds associated with asset sales of $854 million.

Capital and exploration expenditures were $6 billion. That included acquisition of an aromatics plant in Singapore.

ExxonMobil distributed $3.3 billion in dividends to shareholders.

The company reported oil-equivalent production in the quarter was 3.9 million barrels per day, up 2% from the year-ago quarter.

Since May, the company has added 22,000 acres to its Permian Basin holdings in West Texas and New Mexico through acquisitions and acreage trades. The new acreage in the Delaware and Midland basins adds more than 400 million barrels of oil-equivalent assets to the company’s existing Permian resource base of 6 billion oil-equivalent barrels.

Antero 3rd Qtr. Update.  Antero Resources reported a third-quarter net loss of $135 million. compared to a net gain of $238 million in Q3 2016, Kallanish Energy reports.

The company also reported record-high liquids production in Q3 of 112,393 barrels per day (BPD), a 38% increase over the prior-year quarter.

Liquids revenue accounted for $251 million, or 38% of the company’s quarterly revenue, up from 25% in the prior-year quarter.

Oil production was 6,784 BPD. Ethane production in Q3 averaged 30,319 BPD, while 124,000 BPD of ethane was left in the natural gas stream.

Antero’s overall production in Q3 averaged 2.32 billion cubic feet-equivalent per day (Bcfe/d), a 24% increase from the year-ago quarter.

Antero said it realized a natural gas equivalent price of $3.39 per thousand cubic feet (Mcf), including NGLs, oil and hedges.

The company said it expects to boost production by more than 20% from 2017 to 2020. It intends to spend $1.3 billion on capital expenditures in 2018, $1.5 billion in 2019 and $1.5 billion in 2020.

Antero, chairman and CEO Paul Rady said Antero took steps in the third quarter “to deliver the balance sheet and positioned Antero to generate attractive growth and returns while spending within cash flow in 2018 and beyond.”

The company has entered into a new upstream credit facility with a borrowing base of $4.5 billion and lender commitments of $2.5 billion.

The company also disclosed it is in contract disputes with Washington Gas Light for $55 million after that company failed to transport purchased natural gas, and South Jersey Gas for $47 million for adopting a disputed price.

In Q3, Antero placed on line 31 Marcellus Shale wells with average laterals of 9,500 feet in West Virginia. A total of 25 of those wells were online more than 30 days and had an average 30-day rate (on choke) of 17 million cubic feet-equivalent per day (MMcfe/d).

Last July, the company drilled its three longest laterals in the Marcellus, each 14,000 feet long.

It also placed online six Utica Shale wells in Ohio with average laterals of 9,600 feet.

SWN 3rd Qtr. Update.  Southwestern Energy reported third-quarter net income of $43 million, compared to a loss of $735 million one year ago, Kallanish Energy reports.

“The execution of our strategy continued to deliver strong results in the third quarter,” said president and CEO Bill Way, in a statement.

The company reported third-quarter production of 232 billion cubic feet-equivalent (Bcfe), a 10% increase from a year ago.

The company drilled 47 wells, completed 29 wells and placed 37 wells into service in Northeast and Southwest areas of the Marcellus Shale, plus the Fayetteville Shale in Arkansas.

That quarterly production total includes 153 Bcfe from the Appalachian Basin, a 26% increase, despite third-party gathering downtime in northeast Pennsylvania.

The company achieved a record exit production rate of almost 2.4 Bcfe/d in the Appalachian Basin, a 42% increase from Q3 2016.

The company produced 52 Bcfe in Q3 2017 in southwest Appalachia, a 41% increase from a year ago. It achieved a record exit rate of 958 million cubic feet-equivalent per day(MMcfe/d), a 54% increase from a year ago.

It brought online 18 wells in the quarter: 17 Marcellus and one Utica well.

Southwestern also began work on a new water infrastructure system in northern West Virginia that's expected to reduce well costs by $500,000 per well, starting in late 2018.

The company also drilled its second Utica Shale well in Washington County, Pa. The second well went online in August. It was flowing at a rate of 23 million cubic feet per day (MMcf/d), prior to being shut-in for additional tests. It's expected the well will flow at a rate between 16 and 20 MMcf/d.

The company’s first Utica well is in Marshall County, W. Va.

Southwestern said it set two drilling records in the quarter. It said a 6,202-foot lateral in Brooke County, W. Va., was drilled 100% in zone of a 15-foot target window, setting a 24-hour drilling record.

In addition, a well in Ohio County, W. Va., was drilled to a total depth of 13,927 feet in less than 10 days, from rig release to rig release.

The company also negotiated a new deal with Williams Partners that creates incremental value of about $1.4 million per well from reduced processing rates in the lean gas acreage of southwest Appalachia.

In northeast Appalachia, the company produced 101 Bcfe in the third quarter, a 20% increase year-over-year. It also achieved a record gross operated exit rate of 1.4 Bcfe/d, a 35% increase over Q3 2016.

The company placed 15 wells to sales in the quarter in northeast Pennsylvania.

NEXUS Update – Getting the Final Approvals.  NEXUS Gas Transmission has gone to federal court asking to take temporary or permanent easements through eminent domain on 42 pieces of property in eight Ohio counties.

In its federal lawsuit, NEXUS said it negotiated easements on 97% of roughly 2,000 properties and made final offers to holdouts in September, but those landowners rejected or failed to respond to the company’s proposals, the Canton (Ohio) Repository newspaper reported.

NEXUS asked the court to let it immediately take the easements and start construction. Under the company’s plan, a three-person commission would decide later how much the company owes landowners. NEXUS said it would post a bond to ensure the property owners are paid, the Repository reported.

NEXUS is a 36-inch natural gas pipeline designed to carry up to 1.5 billion cubic feet per day (Bcf/d) of natural gas from the Utica and Marcellus Shale plays to users in Ohio, Michigan and Canada.

The 255-mile pipeline would start near Hanoverton in Columbiana County, Ohio, and connect to existing pipelines in Michigan.

If workers can’t build the pipeline in sequence because of land disputes and the project is delayed, NEXUS would incur tens of thousands, if not millions, of dollars, in extra costs, the company argued in court papers, the Repository reported.

NEXUS has said the pipeline should be running by the third quarter of 2018, Kallanish Energy reports.

Attorney David A. Mucklow represents 25 Summit County landowners in Green and New Franklin. They argue NEXUS doesn’t have the right under the U.S. Constitution and state and federal laws to take land for the pipeline, the Repository reported.

In a different federal case, the landowners have argued the Federal Energy Regulatory Commission certificate that NEXUS needs to use eminent domain is “void and defective” because the pipeline would export natural gas to Canada, Mucklow said.

If any land is taken, NEXUS should pay the owners the entire value of the property because of “the inherently dangerous nature of natural gas pipelines” and a jury, not a three-person commission, should set the amount, Mucklow and his co-counsel, Aaron Ridenbaugh, argued in court papers.

In an email, NEXUS spokesman Adam Parker told the Repository the company wouldn’t comment on pending litigation. But he noted NEXUS had been communicating with landowners for three years and “makes every attempt to reach agreement with landowners in an honest, fair and reasonable manner.”

Detroit-based DTE Energy and Canadian pipeline giant Enbridge are partners in NEXUS.

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PA Permits October 19 to November 2, 2017

   County                     Township           E&P Companies
1. Allegheny Lincoln Boro EQT
2. Armstrong East Franklin Snyder Bros.
3. Armstrong East Franklin Snyder Bros.
4. Armstrong East Franklin Snyder Bros.
5. Armstrong East Franklin Snyder Bros.
6. Armstrong East Franklin Snyder Bros.
7. Butler                    Jefferson PennEnergy
8. Butler Jefferson PennEnergy
9. Butler                      Jefferson PennEnergy
10. Butler                    Jefferson PennEnergy
11. Butler                    Jefferson                   PennEnergy
12. Elk                         Horton Seneca
13. Greene Center EQT
14. Greene Center                         Rice
15. Greene Center Rice
16. Greene Center                        Rice
17. Greene Center                      Rice
18. Greene Center Rice
19. Greene                 Franklin                      Rice
20. Greene Franklin Rice
21. Greene                 Franklin                      Rice 
22. Greene                Franklin                     Rice
23. Greene Franklin                      Rice
24. Greene Franklin                     Rice
25. Greene Franklin                     Rice
26. Greene Franklin Rice
27. Greene Jackson EQT
28. Greene                Jackson                     EQT
29. Greene                Jackson                     EQT
30. Greene                Jackson EQT
31. Greene                Jackson                EQT
32. Greene                Jackson EQT
33. Greene Jackson                    EQT
34. Greene                Jackson EQT
35. Greene                Jackson EQT
36. Greene                Jackson EQT
37. Greene Jackson EQT
38. Greene                Jackson EQT
39. Greene                Jackson EQT
40. Greene                Richhill CNX
41. Greene Richhill CNX
42. Greene Richhill CNX
43. Greene                Richhill CNX
44. Greene                Richhill CNX
45. Greene Richhill CNX
46. Greene Richhill CNX
47. Greene Richhill CNX
48. Greene                Richhill CNX
49. Greene Richhill CNX
50. Greene Richhill CNX
51. Greene                Richhill CNX
52. Lycoming Hepburn Seneca
53. Susquehanna      Forest Lake            SWN
54. Tioga                    Liberty SWN
55. Tioga Liberty SWN
56. Tioga Middlebury             Shell
57. Tioga Middlebury Shell
58. Washington Buffalo Range
59. Washington          Buffalo Range
60. Washington          Buffalo Range
61. Washington Buffalo Range
62. Washington          Buffalo Range
63. Washington          Buffalo                    Range
64. Washington          Mount Pleasant Range
65. Washington          Mount Pleasant Range
66. Washington          Mount Pleasant Range
67. Washington          Mount Pleasant Range
68. Washington          North Bethlehem Range
69. Washington          North Bethlehem    Range
70. Washington          North Bethlehem    Range
71. Washington          North Bethlehem Range
72. Washington          North Bethlehem Range
73. Washington North Bethlehem Range
74. Washington North Bethlehem Range
75. Washington North Bethlehem Range
76. Westmoreland Penn Huntley & Huntley


OH Permits for weeks of  October 21 & 28, 2017

     County           Township          E&P Companies
1. Belmont Mead Gulfport
2. Harrison Archer Chesapeake
3. Harrison Archer Chesapeake
4. Harrison Archer Chesapeake
5. Jefferson Cross Creek Ascent
6. Jefferson Cross Creek Ascent
7. Monroe Center Gulfport
8. Monroe Center Gulfport
9. Monroe Adams Eclipse
10. Monroe Adams Eclipse
11. Monroe Adams Eclipse
Joe Barone 610.764.1232
Vera Anderson 570.337.7149
Utica Summit 2019