Written by rjs, MarketWatch 666
Here are some selected new articles from the week ended 30 December 2018.
This article is a feature every Monday evening on GEI.
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Oil and natural gas prices both down again in volatile trading; warm spell gives natural gas stores a breather.
Oil prices ended lower for the 3rd week in a row in quite volatile trading that largely synched with the wild gyrations in wall street markets this week, which in turn were driven by year end tax strategies of hedge funds and institutions rather than any specific economic developments…after falling $5.61 or 11% to $45.59 a barrel, largely on technical factors last week, contract prices of US oil for February delivery plunged another $3.06 or 6.7% to $42.53 a barrel to start the week on Monday, as fears of an economic slowdown rattled global financial markets and drove unrequited selling in light pre-Christmas trading…those fears apparently dissipated over the holiday, as financial markets roared back to their largest gain in history on Wednesday while oil prices shot back up $3.69, or 8.7%, to $46.22 a barrel, their largest daily gain in more than two years…however, as stock indices retreated again on Thursday, so too did crude prices, as they fell $1.61, or 3.5%, to $44.61 a barrel, “giving back some of the gains that were brought along with the euphoria in the stock market“…oil prices then staged a modest rally on Friday, rising 72 cents to $45.33 a barrel, after the weekly EIA inventory data showed a small drop in US crude inventories, in contrast to Thursday API figures that had showed a massive crude supply build…nonetheless, February US crude still finished with a decline of 0.6% for the week, while the global benchmark February Brent crude, which did not participate in the Friday rally, ended the week 3.0% lower at $52.20 a barrel, after having seen a 4.2% drop on Thursday…
Natural gas prices, meanwhile, fell for a fourth consecutive week, as unusually warm weather for December continued to reduce demand for natural gas and thus took the edge off the deep supply deficit we started the winter with…quoting natural gas contracts for January delivery to start the week, prices fell 34.9 cents to $3.467 per mmBTU on Monday, as the forecasts for early January cold which had held up prices the prior week had been lifted over the weekend…prices then edged back up 7.6 cents on Wednesday and another 9.9 cents on Thursday as trading in the January gas contract expired at $3.642 per mmBTU…at the same time, natural gas contracts for February delivery, which had ended the prior week priced at $3.750 per mmBTU, fell 32.7 cents on Christmas eve, rebounded 3.5 cents on Wednesday and 8.8 cents on Thursday, and then crashed 24.3 cents to an 8 week low of $3.303 per mmBTU on Friday, as the temperature forecasts again backed off earlier cold forecasts and the EIA reported the smallest withdrawal of natural gas from storage yet this winter….the February natural gas contract price thus ended down nearly 12% for the week, and 13% below where the January natural gas contract had settled the prior Friday….
The natural gas storage report for the week ending December 21st from the EIA showed that the quantity of natural gas in storage in the US fell by 48 billion cubic feet to 2,725 billion cubic feet over the week, which left our gas supplies 623 billion cubic feet, or 18.6% below the 3,348 billion cubic feet that were in storage on December 22nd of last year, and 647 billion cubic feet, or 19.2% below the five-year average of 3,372 billion cubic feet of natural gas that are typically in storage after the third week of December….this week’s 48 billion cubic feet withdrawal from US natural gas supplies was just about what most analysts had been expecting, but it was well below the average of 121 billion cubic feet of natural gas that have been withdrawn from US gas storage during the third week of December in recent years…natural gas storage facilities in the Eastern US saw a 16 billion cubic feet draw from their supplies over the week, half of their average withdrawal over the past five years, as the region’s gas supply deficit was reduced to 14.4% below normal for this time of year, while natural gas supplies in the Midwest fell by 23 billion cubic feet, in contrast to the normal 40 billion cubic feet pull, as their supply deficit was reduced to 12.2% below the normal for the third weekend of December…the South Central region only saw a 2 billion cubic feet drop in their supplies, in contrast to their normal 30 billion cubic foot withdrawal, as their natural gas storage deficit was reduced to 25.5% below their five-year average for this time of year…at the same time, 3 billion cubic feet were pulled out of natural gas supplies in the sparsely populated Mountain region, which normally pulls out 7 billion cubic feet for the week, as their deficit from normal fell to 21.9%, while 4 billion cubic feet were withdrawn from storage in the Pacific region, vs 12 billion cubic feet normally withdrawn, and their natural gas supply deficit fell to 27.4% below normal for this time of year….
So, we’ve just seen our weekly withdrawal drop from 141 billion cubic feet during the week ending December 14th to just 48 billion cubic feet during the current reporting week ending December 21st…as we’ve mentioned several times, natural gas demand and hence withdrawal of gas from storage is largely driven by changes in temperature, relatively steady industrial and export demand notwithstanding…that can be illustrated quite well with a couple graphics we’ve pulled from the EIA’s natural gas storage dashboard and included below; both are similar, with the first showing daily regional average temperatures from November 30th to December 13th, and the second showing daily regional temperatures from December 14th to December 27th:
The graphics above from the EIA’s natural gas storage dashboard gives us both the average daily temperature covering the period from November 30th through December 27th in each of the five natural gas regions, and also a color-coded variance from normal for each of those daily temperature averages, with shades of brown indicating the average temperatures in the region were above normal on a given date, while shades of blue indicate average temperatures that were below normal for the date, as indicated in the legend at the bottom….thus this graphic gives us not only the actual average temperature for each region for each day, but also indicates how much that temperature deviated from the norm…as you can see in the first graphic above, temperatures for the heavily populated East, Midwest and South Central regions were generally below normal over the period from December 8th thru December 14th, with the temperatures in the East, which accounts more than a third of the population, consistently averaging in the mid-30s, while temperatures in the Midwest saw average temperatures in the 20s for four days to start the period…that colder than normal period, which included 3 days that were 5 to 9 degrees colder than normal for each of those regions, is what resulted in the 141 billion cubic feet withdrawal from our natural gas supplies over the week ending December 14th, just modestly above the 5 year average withdrawal of 136 billion cubic feet…
Now look at the period from December 15th thru December 21st, representing the dates of this week’s report; not only were the temperatures in the East, Midwest and South Central regions above normal for each day during the period, but temperatures for all 5 regions were above normal for every day during the period, with temperatures in the East averaging in the mid-40s, and temperatures in the Midwest averaging in the upper 30s over the period…in fact, except for a few counties on the Gulf Coast, the entire US saw above normal temperatures during the week, with the broad area from the northern Rockies to the Great Lakes all more than 10 degrees above normal, as you can see on the map below, also from the natural gas storage dashboard….overall, we can estimate that temperatures for the lower 48 averaged at least 7 degrees warmer during the week ending December 21st than they were during the week ending December 14th…as a result, the daily production of 87.2 billion cubic feet was nearly adequate to meet the country’s needs, and hence only 48 billion cubic feet, or about 7 billion cubic feet per day, needed to be withdrawn from storage during the week…furthermore, if we look at the daily regional average temperatures over the 6 days beginning December 22 shown above, they too are all above normal, with the small exception of the 30 degree average on December 27th for the mountain states…that means that the coming week’s report for the week ending December 28th will again show a withdrawal from storage much below normal, also serving to alleviate the natural gas deficit which had been running 20% below normal nationally in recent weeks…
The Latest US Oil Supply and Dispostion Data from the EIA
This week’s US oil data from the US Energy Information Administration, reporting on the week ending December 21st, indicated a modest increase in our oil imports and a big jump in our oil exports, while our commercial crude supplies nonetheless remained statistically unchanged, resulting in a large jump in unaccounted for crude….our imports of crude oil rose by an average of 233,000 barrels per day to an average of 7,656,000 barrels per day, after rising by an average of 30,000 barrels per day the prior week, while our exports of crude oil rose by an average of 644,000 barrels per day to an average of 2,969,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,687,000 barrels of per day during the week ending December 21st, 411,000 fewer barrels per day than the net of our imports minus exports during the prior week…over the same period, field production of crude oil from US wells reportedly increased by 100,000 barrels per day to 11,700,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from wells totaled an average of 16,387,000 barrels per day during this reporting week…
Meanwhile, US oil refineries were using 17,350,000 barrels of crude per day during the week ending December 21st, 58,000 barrels per day less than the amount of oil they used during the prior week, while over the same period 7,000 barrels of oil per day were reportedly being pulled out of the oil that’s in storage in the US….hence, this week’s crude oil figures from the EIA would seem to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 957,000 barrels per day short of what refineries reported they used during the week….to account for that disparity between the supply of oil and the consumption of it, the EIA inserted a (+957,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that is labeled in their footnotes as “unaccounted for crude oil”…with our unaccounted for crude reaching 957,000 barrels per day, the largest amount in recent history, all of this week’s oil supply and disposition figures that we have cited must be taken with a big grain of salt…(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 7,423,000 barrels per day, now 2.3% less than the 7,598,000 barrel per day average that we were importing over the same four-week period last year….the statistical 6,000 barrel per day decrease in our total crude inventories included a rounded 7,000 barrel per day withdrawal from our commercially available stocks of crude oil, while the oil stored in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported 100,000 barrels per day higher at 11,700,000 barrels per day because the rounded figure for output from wells in the lower 48 states rose by 100,000 barrels per day to 11,200,000 barrels per day, while a 1,000 barrel per day decrease to 497,000 barrels per day in oil output from Alaska was not enough to change the rounded national total…last year’s US crude oil production for the week ending December 22nd was at 9,754,000 barrels per day, so this week’s rounded oil production figure was almost 20% above that of a year ago, and 38.8% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
US oil refineries were operating at 95.1% of their capacity in using those 17,350,000 barrels of crude per day during the week ending December 21st, down from last week’s 95.4% of capacity, but still a high capacity utilization rate for December or for any time of year….the 17,350,000 barrels per day of oil that were refined this week were no longer at a seasonal high for the time of year, however, as they were fractionally lower than the previous seasonal high of 17,398,000 barrels of crude per day that were being processed during the week ending December 22nd, 2017, when US refineries were operating at 95.7% of capacity…
With the small drop in the amount of oil being refined, the gasoline output from our refineries was also lower, decreasing by 190,000 barrels per day to 10,334,000 barrels per day during the week ending December 21st, after our refineries’ gasoline output had decreased by 123,000 barrels per day during the week ending December 14th…with that decrease in this week’s gasoline output, our gasoline production during the week was 0.8% lower than the 10,222,000 barrels of gasoline that were being produced daily during the same week last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 51,000 barrels per day to 5,444,000 barrels per day, after that output had decreased by 152,000 barrels per day the prior week….even with that increase, this week’s distillates production was fractionally lower than the 5,476,000 barrels of distillates per day that were being produced during the week ending December 22nd, 2017….
Even with the pullback in our gasoline production, our supply of gasoline in storage at the end of the week increased by 3,006,000 barrels to 233,106,000 barrels by December 21st, the 5th increase in the past 10 weeks, which nonetheless still left our gasoline supplies 3,066,000 barrels lower than they were on the 5th of October, at a time of year when gasoline inventories are usually increasing….our gasoline supplies rose this week even though the amount of gasoline supplied to US markets rose by 105,000 barrels per day to 9,348,000 barrels per day while our exports of gasoline fell by 97,000 barrels per day to 851,000 barrels per day and our imports of gasoline fell by 86,000 barrels per day to 509,000 barrels…with this week’s increase, our gasoline inventories are once again at a seasonal high for the third week in December, 2.1% higher than last December 22nd’s level of 228,374,000 barrels, and roughly 4% above the five year average of our gasoline supplies for this time of the year…
Even with the ongoing elevated level of our distillates production, our supplies of distillate fuels increased for just the 3rd time in fourteen weeks, but just by a statistically insignificant 2,000 barrels to 119,902,000 barrels during the week ending December 21st, after our distillates supplies had decreased by 4,237,000 barrels during the prior week…our distillates supplies eked out that small increase because the amount of distillates supplied to US markets, a proxy for our domestic demand, fell by 644,000 barrels per day to 4,242,000 barrels per day, while our imports of distillates rose by 65,000 barrels per day to 204,000 barrels per day, and while our exports of distillates rose by 155,000 barrels per day to 1,406,000 barrels per day….despite this week’s increase, our distillate supplies finished the week 7.7% below the 129,935,000 barrels that we had stored on December 22nd, 2017, and roughly 11% below the five year average of distillates stocks for this time of the year…
Finally, with the caveat that oil which was unaccounted for this week approached a million barrels per day, our commercial supplies of crude oil slipped by a statistically insignificant 46,000 barrels to 441,411,000 barrels on December 21st, from 441,457,000 barrels on December 14th, the fourth straight decrease after 10 weekly increases, and the 25th down week during 2018….but even after four straight decreases, our crude oil inventories still remained roughly 7% above the five-year average of crude oil supplies for this time of year, and over 28% above the 10 year average of crude oil stocks for the first week of December, with the disparity between those figures arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…however, since our crude oil inventories had been falling through most of the past year and a half until this Fall, our oil supplies as of December 21st were only 2.2% above the 431,882,000 barrels of oil we had stored on December 22nd of 2017, and remained 9.2% below the 486,063,000 barrels of oil that we had in storage on December 23rd of 2016, and 3.0% below the 455,106,000 barrels of oil we had in storage on December 25th of 2015..
This Week’s Rig Count
US drilling activity increased for the second week in a row, and was thence up for the 8th time in the past 14 weeks during the week ending December 28th, as drilling for oil continued to expand despite depressed prices and a 6.7 month backlog of uncompleted wells… Baker Hughes reported that the total count of rotary rigs running in the US increased by 3 rigs to 1083 rigs over the week ending December 28th, which was also 154 more rigs than the 929 rigs that were in use as of the December 29th report of 2017, but down from the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC announced their attempt to flood the global oil market…
The count of rigs drilling for oil increased by 2 rigs to 885 rigs this week, which was also 138 more oil rigs than were running a year ago, while it was still well below the recent high of 1609 rigs that were drilling for oil on October 10, 2014…at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 1 rig to 198 natural gas rigs, which was also 16 more rigs than the 182 natural gas rigs that were drilling a year ago, but way down from the modern high of 1,606 natural gas rigs that were deployed on August 29th, 2008…
Drilling activity in the Gulf of Mexico was unchanged at 24 rigs this week, which was up from the 18 rigs deployed in the Gulf of Mexico a year ago at this time…since there is no other offshore drilling off either coast or off Alaska at this time, nor was there during the same week of 2017, those Gulf of Mexico totals are identical to the US totals..
The count of active horizontal drilling rigs increased by 5 rigs to 945 horizontal rigs this week, which was also 149 more horizontal rigs than the 796 horizontal rigs that were in use in the US on December 29th of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014….on the other hand, the vertical rig count decreased by 1 rig to 68 vertical rigs this week, which was still up from the 65 vertical rigs that were in use during the same week of last year…at the same time, the directional rig count also decreased by 1 rig to 70 directional rigs this week, which was still up from the 68 directional rigs that were operating on December 29th of 2017…
The details on this week’s changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes…the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of December 28th, the second column shows the change in the number of working rigs between last week’s count (December 21st) and this week’s (December 28th) count, the third column shows last week’s December 21st active rig count, the 4th column shows the change between the number of rigs running on Friday and those running on the equivalent weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 29th of December, 2017…
In something of an oddity, both this week’s state variance table and the shale basin table match the summary figures we have just reviewed; not necessarily because there was no change in activity outside of these major states or basins, but because if there was, it netted out to no change, and thus doesn’t show any in either the Current and Historical Rigs by State xls spreadsheet, nor the count by basin table of the North America Rotary Rig Count excel file that we check each week…the Permian basin, which accounts for more than 40% of US drilling activity, also shows a net no change, even though two rigs were added in Texas Oil District 8, the core Permian – Delaware basin, and even though another rig was added to Texas Oil District 7C, or the southern part of the Permian Midland, because 3 rigs were pulled out of Texas Oil District 8A, or the northern Permian Midland…meanwhile, natural gas rigs were added in Ohio’s Utica shale and Louisiana’s Haynesville, while one natural gas rig was pulled out of Oklahoma’s Ardmore Woodford, which shows no net change because an oil rig was added in that basin at the same time…
Oil and gas company eyes drilling in north-central Ohio – Canton Repository –Cabot Oil & Gas is getting ready to drill test wells in Ashland and surrounding counties in north-central Ohio.“We’ve got a really neat group of geologists who think they see something in Ohio,” said George Stark, a Cabot spokesman based in Pittsburgh. “They see something, and we want to go touch it.”Cabot is looking for natural gas and oil a hundred miles northwest of the Utica Shale play’s core in eastern Ohio.The Houston-based company has filed paperwork with the Ohio Department of Natural Resources for two well pads in Ashland County, and plans to drill up to five test wells in an area that includes parts of Richland, Knox, Wayne and Holmes counties. During the early days of Utica exploration, Devon Energy drilled a few wells in the area Cabot is targeting, but moved on. Cabot is planning to explore below the Utica Shale, Stark said.Paperwork filed with ODNR indicates the company is targeting the Rome and Knox formations, but Stark declined to be specific. The agency has yet to issue the company a drilling permit.The company plans to drill vertical wells and take samples that will show the ratio of oil to natural gas and the pressure and thickness of the rock, factors that determine whether it makes economic sense to drill more wells, Stark said. Cabot has obtained the right to drill vertical wells into rock formations 3,000 to 4,000 feet beneath a natural gas storage field owned by Columbia Gas Transmission, but Cabot still needs to get horizontal-drilling rights from surface landowners.
Marksmen Energy drilling in Ohio’s Clinton Sandstone – Calgary-based Marksmen Energy reports it’s making progress in drilling a Clinton Sandstone well in southeast Ohio, Kallanish Energy reports. Completion of milling and drilling the 1,500-foot lateral is expected to begin this week. The lateral drilling is expected to take 10 to 15 days. The sandstone was previously stimulated with a 12-stage hydraulic fracturing or fracking process. Marksmen said it has interests in 5,500 acres of additional land with several potential Clinton Sandstone wells locations that could be developed under its agreement with its operator. The company has said it’s planning “an aggressive drilling program in 2019 to fully develop the acreage,” subject to financing. The drilling is different than the horizontal wells being drilled in the Utica Shale in eastern Ohio. There are no horizontal Utica wells in Hocking County. However, Marksmen has targeted the Clinton Sandstone previously drilled in many parts of Ohio. EnerVest, it said, is evaluating plans to drill multiple horizontal wells on its 115,000 gross acres of leases in Ohio’s East Canton oilfield in Stark County. It spills into surrounding counties. EnerVest operates roughly 1,600 vertical-only Clinton Sandstone wells in that area, some dating back to the late 1940s. The oil recovery from those wells has been estimated at 7% by EnerVest, Marksmen said. EnerVest reports a nearly 10-fold increase in Clinton Sandstone production by using horizontal wells, and it reported its horizontal wells encountered near virgin reservoir pressures within the field, the Canadian company reported. It also said U.S. Energy OH LLC is also drilling Clinton Sandstone wells in the East Canton field and has drilled and completed nine of 21 permitted locations.
Columbus proposes $649,000 settlement for homeowners in Upper Arlington gas explosion – The city of Columbus has proposed nearly $649,000 as its portion of a settlement payment to owners of homes damaged by a catastrophic natural gas explosion in Upper Arlington in 2015. Columbia Gas of Ohio told Columbus Business First it also has reached a confidential settlement amount with plaintiffs in several lawsuits.Upper Arlington’s proposed settlements total $80,000, the city said, covered by the Central Ohio Risk Management Association and insurance. A gas leak filled the basement and exploded a home at 3418 Sunningdale Way in March 2015, causing damage to surrounding homes, some irreparable. Numerous lawsuits by homeowners were consolidated in Franklin County Common Pleas Court in 2016.Upper Arlington owns its water system, but Columbus operates it. The city’s settlement will come from Columbus’ water operating fund, as did a separate$37,500 settlement paid to a different homeowner in 2016.Columbus denies liability but wants to end the litigation, according to the proposal up for a vote Monday by Columbus City Council. According to the original complaint by the homeowners, Hidefumi and Mariko Ishida, Columbia Gas had abandoned a gas line in the 1990s, but failed to disconnect and seal it properly. In 2000, Columbus’ water division misidentified that line as a water line, and neither utility caught the error for years.
Utica Shale Oil, Natural Gas Production Both Increased 30% in Third Quarter — Unconventional oil and natural gas production in Ohio’s Utica Shale saw robust year/year gains in the third quarter of more than 30% each, according to newly released data from the state Department of Natural Resources.Utica oil production continued to move higher during the period, when volumes came in at about 5.5 million bbl — up roughly 32% from the year-ago quarter and a strong increase from 2Q2018, when volumes rebounded at 4.5 million bbl.Until earlier this year, oil production in the state had fluctuated in a reflection of the broad shift to dry gas production that occured about two years ago across much of the Appalachian Basin, when oil prices were lower. While they’ve recently slid from high points, stronger oil prices this year pushed operators back into the Utica’s wetter areas. Natural gas production, meanwhile, showed no signs of slowing down. Producers set another state record with 605.7 Bcf reported for the third quarter, up about 31% from the year-ago period. Volumes were also higher than the 554.3 Bcf reported in 2Q2018.The state’s third quarter report lists 2,242 horizontal shale wells, 2,198 of which reported oil and gas production during the period. The average amount of oil produced by each well during the quarter was 2,523 bbl, while the average amount of gas from each was 275.6 Bcf. The average number of third quarter days in production was 84. Ohio law does not require separate reporting of natural gas liquids or condensate. Those volumes are included in the oil and gas totals. To date, 2,953 horizontal Utica permits have been issued in Ohio, while 2,469 of those have been drilled, according to state data. That compares to the 2,703 horizontal Utica permits and 2,469 drilled Utica wells reported at about this time last year.
Ohio gas production surges 39%; Ascent blows away projections – Ohio’s Utica Shale gas production grew 39% in the third quarter year on year, nearing 7 Bcf/d, driven largely by continued growth in dry gas production from three counties along the state’s Ohio River border with West Virginia and the need to fill new pipelines. Jefferson, Belmont and Monroe counties accounted for 74% of Ohio’s 6.95 Bcf/d of shale gas production in Q3, according to data from the state Department of Natural Resources, while Carroll County, the original home of the Utica, continues to see declines in output. With the opening or expansion of Energy Transfer Partners’ 1.7 Bcf/d Rover Pipeline, Columbia Gas Transmission’s 1.5 Bcf/d Leach XPress and the 1.5 Bcf/d DTE Energy Nexus Gas Transmission pipeline, producers had 4.7 Bcf/d of new capacity open in 2018 to markets in the Midwest and Gulf Coast. Privately held Ascent Resources, with a C-suite stocked with executives who cut their teeth opening the Utica while working at the play’s pioneer, Chesapeake Energy, continued to be the state’s top producer. Ascent more than doubled its Q3 production year on year in the third quarter, well ahead of its own forecasts. According to a June 2018 presentation Ascent gave to close a $1.5 billion private equity investment, the company hoped to average 1.375 Bcf/d of gas production. In Q3, output topped 1.9 Bcf/d after starting 2018 with 1.2 Bcf/d. Gulfport Energy, previously the state’s top producer, decided in 2018 to shift its spending south to Oklahoma’s SCOOP shale oil and gas play. Its production in Ohio grew 6% year on year in Q3, but that could change in 2019. Gulfport’s longtime CEO, Michael Moore, stepped down at the end of Q3, and the board hired a veteran Appalachian shale executive to take his place. After years at Murphy Oil, incoming CEO David Wood was chairman and CEO at West Virginia driller Arsenal Resources and was a senior adviser at First Reserve, one of the private equity backers of Ascent Resources.
Ohio moves into top five for recoverable shale natural gas reserves – Ohio has moved into the top five for recoverable shale natural gas reserves in the United States. Data released by the U.S. Energy Information Administration shows the state saw a 24.5 percent increase in proved shale gas reserves from 2016 to 2017, bringing it to 25.6 trillion cubic feet. That moves Ohio past Oklahoma and behind only Pennsylvania, Texas, West Virginia and Louisiana. Proved reserves is a measure of oil and natural gas that can be recovered in the future. JobsOhio and economic development groups have said that a robust shale industry will create jobs in Appalachia and reduce energy costs, making it cheaper for other businesses to invest here. Before development of the Utica Shale, Ohio’s peak year for natural gas production was in 1984 at 186 billion cubic feet. In 2017, it was 1.7 trillion cubic feet, said Dan Alfaro, spokesman for Energy in Depth, an advocacy group launched by the Independent Petroleum Association of America. “What the EIA data tell us is Ohio’s status as a premiere gas-producing state is secured,” Alfaro said. “Most importantly, the trends for the natural gas market bode well for continued economic growth and investment in the region.”Proved reserves of both U.S. crude oil and natural gas broke records from the year before – crude jumped 19.5 percent to 39.2 billion barrels and surpassed the previous peak level of 39 billion barrels set in 1970. Proved reserves of natural gas were up 36.1 percent to reach 464.3 trillion cubic feet in 2017, surpassing the 388.8 trillion cubic feet record set in 2014.
Appalachian producers set the stage for production growth – Appalachian Basin gas producers are expected to focus production strategies to take advantage of new pipeline takeaway capacity that will be serving the region in 2019 and beyond. The substantial completion of two pipeline projects, Energy Transfer’s Rover Pipeline and Atlantic Sunrise, in the second half of 2018 has added about 5 Bcf/d of capacity in the region. Rover, a 713-mile, 3.25-Bcf/d pipeline, is designed to carry gas from the Marcellus and Utica shale-producing regions of southwestern Pennsylvania, West Virginia and eastern Ohio to markets in the Midwest and through interconnects to the Gulf Coast, as well as northward into the Union Gas Dawn Storage Hub in Ontario. Additionally, Transcontinental Gas Pipe Line in October got the go-ahead from the US Federal Energy Regulatory Commission to place into service large portions of the 1.7-Bcf/d Atlantic Sunrise project, which will move gas out of the dry gas region of northeastern Pennsylvania. Other projects that have recently come online or that are expected to in the near term will add another approximately 1 Bcf/d of takeaway capacity in the region by early 2019. Range Resources said the approval for both the Majorsville and Burgettstown laterals of the Rover project allowed Range to begin flowing volumes on the pipeline in September. The EQT, the biggest US gas producer, in November completed the spinoff of its midstream assets in order to become a pure-play Appalachian E&P company. In announcing the formation of Equitrans Midstream, EQT President and CEO Robert McNally said the spinoff would allow EQT “to develop the premier natural gas asset base in Appalachia.” Another big producer in the region, Southwestern Energy, also moved to refine its focus on Appalachia, with the completion of the sale of its Fayetteville Shale assets in early December to privately held Flywheel Energy for $1.865 billion in cash. The sale would allow the company to “to drive greater value from our highly attractive and significant asset base in Appalachia,” In what was perhaps the biggest 2018 M&A deal to affect the future of Appalachian Basin gas markets, Chesapeake Energy in July announced its plans to sell its Utica Shale assets in Ohio to allow the company to focus on growing its oil production in Wyoming’s Powder River Basin. As a result, privately owned Encino Energy, which acquired the assets for $2 billion, became a major Appalachian player almost overnight. CEO Hardy Murchison said the company plans to actively develop the assets, which include more than 900,000 net acres of leasehold, spanning the condensate, liquids-rich and dry gas windows of the Utica play. As part of the deal, Encino acquired about 900 gas wells that currently produce more than 600 MMcf/d of gas equivalent.
Residents: Fracking disposal well would make Plum ‘a dumping ground for the oil and gas industry’ – Pittsburgh Post-Gazette – Opening the state’s largest drilling and fracking wastewater disposal well in Plum could lead to earthquakes and contaminated groundwater, according to opponents of the proposal who testified at a state Department of Environmental Protection hearing Monday. More than a dozen speakers urged DEP regulators not to approve a permit sought by at Delmont-based Penneco Environmental Solutions, a subsidiary of Penneco Oil Co. The company wants to convert an old oil and gas well into a wastewater injection well allowed to accept more than 2.2 million gallons of salty and chemically laced fracking wastewater a month. “This injection well would put a lot of young families at risk,” said Angela Billanti, a member of Citizens 4 Plum, a community group opposed to the wastewater injection well. “This, along with new zoning that will allow the drilling of hundreds of shale gas wells, will make Plum Borough a dumping ground for the oil and gas industry.” In addition to accepting more wastewater than any other disposal well in the state, it would be the first such well in Allegheny County. Matt Kelso, a Plum resident and manager of data and technology for the Fractracker Alliance, a non-profit that maps shale gas industry operations, said the potential for earthquakes caused by the disposal well poses a significant risk, not only due to the underlying geology, but also because of the many abandoned mines in the area. “For decades, (the DEP) determined that the subsurface geology of most of Pennsylvania was unsuitable for underground injection. But now they are tasked with overseeing an oil and gas industry that produced 58 million barrels, or 2.4 billion gallons, of toxic liquid waste in 2017 alone,” Mr. Kelso said. “Just because there is more waste to deal with does not make our area suddenly suitable to be a dump for toxic liquid waste.”
US fossil fuel exports spur growth, climate worries – The boom in fossil-fuel production in the United States has been matched by a rush on the other side of the Pacific to build the infrastructure needed to respond to the seemingly unquenchable thirst for energy among Asia’s top economies. When Congress lifted restrictions on shipping crude oil overseas in 2015, soon after the Obama administration opened the doors for international sales of natural gas, even the most boosterish of Texas oil men wouldn’t have predicted the U.S. could become one of the world’s biggest fossil-fuel exporters so quickly.Climate experts say there is little doubt increased American production and exports are contributing to the recent rise in planet-warming carbon emissions by helping keep crude prices low, increasing consumption in developing economies.Backers of U.S. exports of liquefied natural gas, or LNG, argue that the boom will produce environmental benefits because it will help China and other industrial nations wean themselves from coal and other dirtier fossil fuels.Environmentalists counter that the massive new supplies unleashed by American advances in extracting natural gas from shale doesn’t just make coal-fired power plants less competitive. LNG also competes with such zero-carbon sources of electricity as nuclear, solar and wind – potentially delaying the full adoption of greener sources. That’s time climate scientists and researchers say the world doesn’t have if humans hope to mitigate the worst-case consequences of our carbon emissions, including catastrophic sea-level rise, stronger storms and more wildfires. “Typically, infrastructure has multi-decadal lifespans,” said Katharine Hayhoe, a climate scientist and director of the Climate Science Center at Texas Tech University. “So, if we build a natural-gas plant today, that will impact carbon emissions over decades to come. So those are the critical and crucial decisions that are being made today. Do we increase access to and use of fossil fuels, or do we make decisions that limit and eventually reduce access to fossil fuels?”
Fracking accountability will be legislative topic – Lawmakers are likely to face renewed debate in the next legislative session about how or whether to hold oil and gas companies accountable for property damage caused by earthquakes in Kansas. Earthquakes have increased in Kansas since 2013 when fracking, or hydraulic fracturing, became more common for oil and gas exploration. Some researchers believe injection of wastewater from the explorations into underground wells contributes to the quakes. The Topeka Capital-Journal reports Joe Spease, of the Kansas Sierra Club, says lawmakers should require oil and gas companies to pay a fee to help pay for damages from earthquakes. But Ed Cross, executive director Kansas Independent Oil and Gas Association, says companies would go out of business and jobs would be lost if such fees were imposed on the industry.
Death in the oilfields | The Center for Public Integrity – Drilling is an inherently dangerous undertaking, with a fatality rate nearly five times that of all industries in the United States combined in 2014, the last year such rates on oil and gas extraction were published by the government. Production pressures – and the temptation to cut corners – intensify during boom times, as America is experiencing now due to a rush of fossil-fuel exports.The work of coaxing oil and gas from thousands of feet underground is performed in biting cold and breathtaking heat by stoics like Parker Waldridge, who burned to death at 60 in a driller’s cabin, known as a doghouse, atop the floor of Rig 219. “They get up in the morning and eat nails for breakfast. We need those people to do that kind of work. We’ve just got to find a way not to kill them.”“We need those people to do that kind of work. We’ve just got to find a way not to kill them.” From 2008 through 2017, 1,566 workers died from injuries in the oil-and-gas drilling industry and related fields, according to data from the U.S. Department of Labor’s Bureau of Labor Statistics. That’s almost exactly the number of U.S. troops who were killed in Afghanistan during the same period. From 2008 through October 25 of this year, the department’s Occupational Safety and Health Administration cited companies in the extraction industry for 10,873 violations, a Center for Public Integrity analysis of OSHA data found. Sixty-four percent of the violations were classified by the agency as “serious,” meaning inspectors found hazards likely to result in “death or serious physical harm.” Another 3 percent were classified as “repeated,” meaning the company previously had been cited for the hazard, or “willful,” indicating “purposeful disregard” for the law or “plain indifference to employee safety.” During that period, OSHA investigated 552 accidents resulting in the death of at least one worker. Initial penalties in the 552 accidents averaged $16,813, but later were reduced, on average, by 30 percent. (OSHA often cuts fines in exchange for quick settlements and hazard abatement). Some violations are still being contested by employers. Others were dropped by OSHA after negotiations with companies. The number of workers exposed to death, injury and illness in the upstream portion of the oil and gas industry – exploration and production – is growing, especially in the frenetic Permian Basin of West Texas and southeastern New Mexico. At the beginning of December, according to figures from oilfield services firm Baker Hughes, the basin accounted for more than half of the nation’s operating drilling rigs – 489 in all.
A sip of fracking wastewater? – Finger Lakes Times – In the dry Southwestern state of New Mexico, state officials and the U.S. Environmental Protection Agency are seriously considering an attempt to clean up toxic wastewater from hydrofracked oil and gas wells so it can be used in agriculture. And as drinking water. Seriously? Recycling fracking wastewater for drinking? In published reports in the last two weeks, this notion surfaced against a political backdrop of keeping the oil and gas industry fiscally healthy and profitable. “Oil and gas in New Mexico provide over a third of our general fund,” Ken McQueen, head of the state’s department of Energy, Mineral and Natural Resources said in the Washington Post. “We have to be concerned we’re doing what’s necessary into the future to make sure this industry continues to be alive and vibrant.” McQueen gushed that part of keeping the industry vibrant could include using cleaned-up toxic wastewater to irrigate crops and provide water for domestic taps. He also opined it might be used to revive dried-up wildlife wetlands. An added benefit, which he didn’t emphasize, is that it would save oil and gas companies large sums of money now spent on injecting the toxic wastewater into deep wells. If this cleanup scheme seems a horrendously bad idea, that’s because it is. Hydrofracking wastewater is almost always disposed of by injecting it deep into the earth because the stew of chemicals in it is so toxic. The chemical-laced wastewater also often contains additional hazardous substances picked up in the drilling process, including radioactive material. The idea that fracking wastewater could be cleaned up is certainly attractive in arid oil-producing states. It takes 4 million to 8 million gallons of water to drill each oil or gas well, sometimes resulting in water shortages in communities where fracking takes place. The cleanup option is also attractive because when wastewater is injected into the earth, it can trigger earthquakes. But the technical and political hurdles are huge and complicated. The politics are complicated because the fracking industry is exempt from key provisions of the federal Safe Drinking Water Act. Exempt.
Another boat sinks and spills oil into Hoquiam River – Another boat sank into the Hoquiam River on Christmas morning, polluting the water and creating an oily sheen over the river due to leaked fluid from the boat. This is the seventh vessel to sink at the boat yard just north of Al’s Hum Dinger restaurant, according to the Washington State Department of Ecology. Just after 9 a.m. Tuesday, a citizen reported there was a sheen of fuel on the Hoquiam River, originating from a privately owned boat yard in the 200 Block of Monroe Street, Hoquiam Police Chief Jeff Myers said in a release. Upon arrival by the Hoquiam Police and Fire departments, responders noticed a strong odor of fuel and the sheen of a petroleum product on the river heading downstream toward the Riverside Bridge. Debris was floating adjacent to the boat yard with mooring lines still leading to a vessel completely submerged and not visible in the river. Oil pollution extended about 500 yards both upstream and downstream from the site, said Department of Ecology communications manager Sandy Howard. The department estimates between 10 and 15 gallons of oil were spilled. A person staying at the boat yard indicated that an old Navy patrol vessel was moored at the boat yard and may have been damaged by a piling during the recent high storm tides, Myers said. The boat had been moved and secured with additional floats, but at 1:40 a.m., the witness heard the sound of rushing water and found the boat tilting. The boat sank into the river with fuel or engine oil escaping into the water, but no one notified the Coast Guard or called 911 to report it at the time. The owner of the boat yard was not present upon arrival of police and fire units, Myers said. The state Department of Ecology’s spill response team was sent and assisted with cleaning up the leaking oil. With help from people associated with the private marina, the department deployed floating absorbents around the sunken boat to collect floating oil and any more residual that’s released, Howard said. On Wednesday morning, the oily sheen could still be seen at many spots along the river’s shoreline near the boat yard.
U.S. crude inventories dip slightly – EIA (Reuters) – U.S. crude stocks fell modestly last week, while gasoline stocks increased more than expected, the Energy Information Administration said on Friday. Crude inventories were down by 46,000 barrels in the week to Dec. 21, compared with analysts’ expectations for a decrease of 2.9 million barrels. Crude stocks at the Cushing, Oklahoma, delivery hub rose by 799,000 barrels, EIA said. Refinery crude runs fell by 58,000 barrels per day, EIA data showed. Refinery utilization rates fell by 0.3 percentage points. Gasoline stocks rose by 3 million barrels, compared with analysts’ expectations in a Reuters poll for a gain of 28,000 barrels. Distillate stockpiles, which include diesel and heating oil, rose by 2,000 barrels, versus expectations for a 529,000-barrel drop, the EIA data showed. Net U.S. crude imports fell last week by 411,000 barrels per day.
US Oil Delivers One-two Punch to Middle East Producers — The U.S. oil industry is delivering a one-two punch to Middle East producers already reeling from a collapse in prices. A tussle is playing out in the market for so-called light oils, which have a lower sulfur content and are less dense than heavier varieties. When processed, these grades typically yield a higher amount of fuels like gasoline and naphtha. And now, American supplies are weighing on prices for such crudes as well as fuels made from them. Light oil pumped in U.S. shale fields is increasingly making its way to Asia, undercutting sales by the likes of Saudi Arabia. Additionally, America is exporting a record amount of refined fuel, contributing to a global glut in gasoline and naphtha. That’s hurting some of the biggest members of the Organization of Petroleum Exporting Countries as they prepare to curb crude output in a bid to stabilize the market. Middle East producers — still the dominant suppliers to Asia — are being forced to tackle American crude competition by lowering their oil pricing to defend their market share. The refiners, meanwhile, are contending with booming U.S. fuel shipments dragging down their returns from making processed products. “It is no surprise that Middle Eastern producers are having to cut light crude prices,” said Virendra Chauhan, an analyst at industry consultant Energy Aspects Ltd. Over the course of 2018, the key sources of global oil-output growth have included light crude from U.S. shale fields and Saudi Arabia, he said. While Middle East producers such as Saudi Arabia and Abu Dhabi are reducing the pricing for their lighter crudes, American exports to Asian nations such as India and South Korea are surging. Even a temporary halt by China due to its trade war with the U.S. hasn’t significantly dented overall flows this year. While the rivalry between Middle Eastern producers and sellers of U.S. oil has intensified since 2016, with even relatively heavier American crudes such as Mars and Poseidon coming to Asia, the competition is particularly stiff for lighter grades. Abu Dhabi’s Murban and Saudi Arabia’s Extra Light have similar fuel yields and chemical characteristics as shale crude.
US shale’s financial blanket at risk of wearing thin in 2019 – All industrial revolutions need two things: technology and finance. The US shale revolution was made possible by the advances in horizontal drilling and hydraulic fracturing that allowed oil and gas to be released from previously unyielding rocks. But the industry’s financing was equally important in turning those innovations into a production boom that has shaken the world. The financial model that has dominated the industry has been a highly competitive group of exploration and production companies using debt raised from bond markets and bank loans secured on oil and gas reserves. Often they use derivatives to hedge some or all of their revenues, giving lenders confidence in their ability to make interest payments if oil and gas prices fall. For most of the shale boom, that financial infrastructure has been underpinned by the low interest rates and quantitative easing that followed the financial crisis. The surge in US oil production has been a result of monetary stimulus, just as much as the tech start-up boom and the rise in the S&P 500 have been. As its output has grown, the US E&P industry has been unable to finance its drilling programmes from its operating cash flows, and a constant inflow of capital has been essential for keeping it afloat. With stock markets and oil prices falling, and while the Federal Reserve is still signalling its intention to keep raising interest rates, the financial conditions that have protected the shale industry like a warm blanket may next year start to wear thin. One issue that has been highlighted by Philip Verleger, an energy economist, is the outlook for the hedging used by E&P companies to protect their revenues and reassure their lenders. Strategies vary, but the standard practice is for companies to put a floor under the effective price of some or all of their production by buying put options. Mr Verleger argues that those options have been an important factor in the collapse of oil prices to a 15-month low since October. The investment banks and others that sold those put options have to hedge their own positions, typically by selling oil in the futures market. The more likely it is that the options will be exercised, the more oil the finance companies have to sell, in a practice known as “delta hedging”. That creates a positive feedback loop: as prices fall, financial companies that have sold puts need to sell more oil, which drives the price down further.
Global Drilling And Well Services Activity Sees An Upswing – Since the industry’s all-time low in 2016, field service activities have rebounded and are expected to grow at an average annual rate of 4 percent towards 2021. This is in response to stronger demand for oil and gas and to some of the 30 major energy projects that received final investment decisions in 2017. Industry analysts Rystad Energy predicts 72,000 wells will be drilled and completed in 2019, an increase of 3 percent on 2018. However, field services growth will not be evenly spread either between oil and gas sectors or by countries, given that Iranian oil is subject to sanctions on exports, Libya is vulnerable to interruptions by local tribes and insurgents, and Venezuela’s oil industry is in freefall. Local and international factors will govern the level and location of demand for the type of drilling and field development services. It is easy to overlook the fact that well drilling is predominantly land-based, a feature that owes much to the U.S. shale boom. In less than a decade, U.S. companies have drilled 114,000 shale oil wells and large numbers of gas wells, both in established basins and in new areas. Year-on-year, the United States saw an increase in the rig count of 144 to 1075 on Dec. 7. Rapid growth in North America’s shale oil and gas output has made the country the leading growth market for field services; however, fracking activity slowed in the last quarter as wells in the Permian were drilled but not fracked while awaiting three new pipelines to come online in 2019. Exploitation of shale resources, most notably in North America but also in Argentina and China, dominates the demand for high specification rigs to enable drilling of long horizontal wells accompanied by hydraulic fracturing services. Weaker activity in North America has however been compensated by increased activity in the rest of the world. This was seen by the increase in the number of international rigs by 49 to a total of 991, centered mainly in Latin America and the Middle East. Moreover, Russia, the holder of considerable shale resources in the Bazhenov Basin, could potentially provide a growing market for heavy-duty rigs, horizontal drilling and fracking expertise and services once U.S. sanctions are lifted.
US Is Awash with Natural Gas and More Production Is on Its Way – The Energy Information Administration recently released its reserves report, noting that proven reserves of natural gas increased 36 percent to 464.3 trillion cubic feet – a record that surpasses the previous high set in 2014. Natural gas production in 2017 increased by almost 3 percent from 2016 production levels – another record high. Most of this natural gas is coming from the Marcellus and Utica shale plays in Pennsylvania and neighboring states. . The Permian Basin, however, is also a major player in natural gas production, as the Department of the Interior recently found the Wolfcamp Shale and overlying Bone Spring Formation in the Delaware Basin of Texas and New Mexico’s Permian Basin to contain 281 trillion cubic feet of natural gas, or about 48 billion barrels of oil equivalency. However, that production is hampered by pipeline constraints to get the gas to demand centers. Benchmark gas prices in Permian gas markets recently averaged only $0.625 per million Btu because new pipeline capacity is at least 10 months away. Further, at least 10 new offshore platforms in the Gulf of Mexico are expected to begin producing natural gas by the end of 2018 and another eight are expected to begin production in 2019. Last year, the United States became a net exporter of natural gas and U.S. liquefied natural gas (LNG) exports are increasing as export terminals are coming on line. U.S. LNG exports are poised for a big year in 2019. Offshore natural gas production in the Gulf of Mexico has been declining since fiscal year 2009. The number of natural gas wells in the Gulf of Mexico fell from 3,271 in 2001 to 875 in 2017. The new offshore field starts are expected to slow or reverse the declining trend. The 18 new projects are believed to hold 836 billion cubic feet of natural gas reserves, with the energy equivalency of around 144 billion barrels of oil. Most of the natural gas produced in the Gulf of Mexico is associated-dissolved natural gas produced from oil fields. The largest of the new offshore natural gas fields is Cesar/Tonga Phase II in the Green Canyon area – about 186 miles south of New Orleans. The project is believed to contain 158 billion cubic feet of natural gas. Recently, Chevron¬†announced that it had started production on its Big Foot deep-water project, located about 225 miles south of New Orleans. It is expected to produce up to 25 million cubic feet of natural gas per day.
Prices Little Changed As The Market Awaits January Temperatures — Highlights of the Natural Gas Summary and Outlook for the week ending December 21, 2018 follow. The full report is available at the link below.
- Price Action: The January contract fell 1.1 cents (0.3%) to $3.816 on a 42.2 cent range ($3.938/$3.516.
- Price Outlook: This week’s 42.2 cent range was less than half of last week’s 87.9 cent range, but still elevated. While the 15-day forecast was quite bearish, longer-term models suggest the potential for a very cold January as a polar vortex, similar to 2013/14 delivers Arctic air into the lower 48. If this does occur, prices likely have higher to go. CFTC data indicated a (9,370) contract reduction in the managed money net long position as longs added and shorts added. Total open interest fell (52,400) to 3.692 million as of December 18. Aggregated CME futures open interest fell to 1.231 million as of December 21. This is the lowest total delta adjusted open interest since July 31, 2018. The current weather forecast is now warmer than 7 of the last 10 years. Pipeline data indicates total flows to Cheniere’s Sabine Pass export facility were at 3.9 bcf. Cove Point is net exporting 0.8 bcf. Corpus Christi is exporting 0.425 bcf. Cameron is exporting 0.015 bcf.
- Weekly Storage: US working gas storage for the week ending December 14 indicated a withdrawal of (141) bcf. Working gas inventories fell to 2,773 bcf. Current inventories fall (671) bcf (-19.5%) below last year and fall (713) bcf (-20.5%) below the 5-year average.
- Storage Outlook: The EIA weekly implied flow was (8)bcf from our EIA storage estimate. This week’s storage miss is back within our tolerance. Over the last 5 weeks, the EIA has reported a total withdrawal of (294) bcf compared to our (295) bcf estimate.
- Supply Trends: Total supply rose 0.2 bcf/d to 81.8 bcf/d. US production fell. Canadian imports rose. LNG imports rose. LNG exports rose. Mexican exports rose. The US Baker Hughes rig count rose +9. Oil activity increased +10. Natural gas activity decreased (1). The total US rig count now stands at 1,080 .The Canadian rig count fell (43) to 131. Thus, the total North American rig count fell (34) to 1,211 and now exceeds last year by +70. The higher efficiency US horizontal rig count rose +13 to 940 and rises +139 above last year.
- Demand Trends: Total demand rose +8.3 bcf/d to +100.9 bcf/d. Power demand rose. Industrial demand rose. Res/Comm demand rose. Electricity demand rose +793 gigawatt-hrs to 79,940 which trails last year by (1,267) (-1.6%) and trails the 5-year average by (86)(-0.1%%).
- Nuclear Generation: Nuclear generation rose 539 MW in the reference week to 91,595 MW. This is (2,887) MW lower than last year and (1,131) MW lower than the 5-year average. Recent output was at 92,091 MW.
The heating season has begun. With a forecast through January 4 the 2018/19 total cooling index is at (1,244) compared to (998) for 2017/18, (941) for 2016/17, (842) for 2015/16, (1,127) for 2014/15, (1,308) for 2013/14, (1,115) for 2012/13 and (1,091) for 2011/12.
Natural Gas Stabilizes Into January Options Expiry –It was January contract options expiry for natural gas futures today, though excitement was certainly not what it could have been should December have verified colder. On the day the January contract settled up a bit more than 2% on lingering long-range cold risks following heavy selling Monday. Options expiry seemed to play a role, while loosening balances and expectations for a bearish EIA print to be announced Friday eased concerns about low storage, explaining why the March contract lagged. We accordingly saw a decent bounce in the January/March contract spread today despite only a modest January rally. Today’s intraday bounce was not particularly surprising, as in our Morning Update we explained that prices under $3.5 were “undervalued” headed into options expiry given long-range cold risks. When we wrote this gas prices were down 3% on the day, and we sat bounce and watched them bounce solidly over $3.5 through the day. Prices were aided intraday with GEFS weather model guidance that showed widespread cold risks in the long-range (image courtesy of Tropical Tidbits). Meanwhile, we saw recent balance dynamics as potentially explaining much of the price action since last Friday. We highlighted that in our Note of the Day today, where we also looked at a recent increase in LNG exports as well.
NYMEX January natural gas settles 7.6 cents higher at $3.543/MMBtu – – The NYMEX January natural gas futures contract came out of the holiday Wednesday to rise 7.6 cents to settle at $3.543/MMBtu. February also rose 3.5 cents to close at $3.458/MMBtu. While US demand rose 1.4 Bcf to 87 Bcf Wednesday, it has been on the low side for several days, with consumption averaging 85.8 Bcf/d over the last six days, according to S&P Global Platts Analytics. To date, December demand has averaged 91.6 Bcf/d.The bulk of the consumption was seen in the major demand areas of the Northeast and Upper Midwest, where need was projected to be 39.7 Bcf Wednesday, about 1.6 Bcf below the December average of 41.3 Bcf/d. But Southeast and Texas demand is well behind year-ago levels, due to check in at 29.7 Bcf Wednesday, compared with a the month-to-date average of 33.8 Bcf/d and a year-ago average of 34.1 Bcf/d.Demand does look to rise, however, averaging 94.7 Bcf/d over the next week and 96.7 Bcf/d for the next seven-day period.That coincides with the weather forecast, which shows the bulk of the western half of the country experiencing lower-than-normal temperatures during the front part of that period and the east seeing the same during the back end.US supply continues to run at elevated levels. Wednesday’s gas on hand was 90.6 Bcf, putting the monthly average to 89.9 Bcf/d. By contrast, at this point in 2017, supply was averaging 6.8 Bcf/d less at 83.1 Bcf/d.Inventories are still lagging, but withdrawals have not been too steep of late. Northeast stocks were estimated at 1.493 Tcf, down 4 Bcf from Tuesday. Pulls from storage over the last six days have averaged 3.98 Bcf/d. But the Southeast and Texas were expected to see a 3-Bcf build to 858 Bcf.
January Gas Expires With Strength – (see graphics) It feels like we say this every natural gas contract expiry, but the prompt month contract went off the board exhibiting quite a bit of strength, with January gas contract rallying 3% despite being lower much of the morning. The role of the January expiry was evident with the January contract leading into the settle, even as the February contract led among the winter contracts for much of the day. The result is that the January/February F/G contract spread ticked higher on the day, with the January contract expiring almost 10 cents above the February contract (which has sense pulled back further since the expiry). In our Note of the Day this morning we highlighted that F/G had risen into expiry each of the last 5 years, and that with any colder risks that would continue this year despite weak cash prices. All it took was a cold end to the European operational model to make it 6 years in a row. This came after we outlined in our Morning Update that, “…we see more upside risks for gas prices today thanks primarily to what has been a pattern of very strong contract expiries in this current trading environment. Though the strength seen in the December contract expiry is highly unlikely, there still appear to be enough cold risks in January to combine with the current storage deficit and let the January contract expire with strength.” We saw this strength coming despite overnight GWDD losses. Meanwhile, traders were also preparing for tomorrow’s EIA Weekly Natural Gas Storage Report, where a relatively small storage draw should be announced thanks to widespread warmth last week. Today we looked at when cold weather could return and what stable moderate El Nino conditions per the CFSv2 climate model mean for the rest of the winter. Things should remain busy tomorrow then with significant weekend risk before another holiday-thinned trading day Monday and an EIA report thrown in for added fun.
Natural Gas Gets Crushed As January Cold Delayed – (see graphics)It was another rough week for natural gas bulls, with the February natural gas contract settling over 13% below where the January natural gas contract settled last Friday. With the January contract now off the board, it was the February contract that logged the largest loss on the day while the March contract actually saw the largest weekly loss. Weakness today was not particularly surprising as in our Morning Update we warned that “…overnight weather model guidance was unimpressive enough to put a test of $3.25-$3.3 in play…” Sure enough, this verified well with the February contract setting a low on the day at $3.278 as afternoon model guidance was again unimpressive (images courtesy of Tropical Tidbits). EIA data today did little to spark buying interest in natural gas too, with the EIA announcing a storage draw of 48 bcf. This was just 2 bcf from our -50 bcf expectation, and we quickly labeled the report as “Neutral” but noted that “…with any warmer model guidance gas can test $3.25-$3.3” after the print which verified well on warmer 12z weather model guidance. The print confirmed that the market had loosened in recent warm weather, showing that last week’s tighter print was a bit of an outlier and following right in line with the balance of the last 10 gas weeks. In the Update we noted a clear warming trend in recent Climate Prediction Center forecasts, though this is based off of past weather model guidance. Though gas prices have fallen off quite a bit and implied volatility has taken a plunge, winter is far from over, and there are likely to be quite a few more price moves from here.
Weekly Natural Gas Storage Report: The Bulls Are Giving Up, And That’s A Good Thing – EIA reported a storage draw of 48 Bcf for the week ending Dec. 21. This compares to the -47 Bcf we projected and consensus average of -50 Bcf. The -48 Bcf was smaller than the five-year average of -121 Bcf and last year’s -112 Bcf. For the week ending 12/28, we currently have a forecast of -40 Bcf. We have April 2019 storage at 1.35 Bcf. We published a piece on Wednesday titled, “That cold blast always seems like a week away.” The latest weather model updates do not help the bulls’ cause at all as the first half of January is now expected to be warmer than normal, showing lower than normal heating degree days. (Note: The most important line in that chart is the ECMWF-EPS one.)What the current outlook is basically saying is that there’s not only a cold blast in early January, but that the outlook is actually warmer than normal. With the markets coming into the end of December holding onto the belief that the bulls will get relieved via bullish weather, the latest update is a big disappointment, and hence why prices are falling some ~7%-plus today. Because sentiment and positioning is resetting precisely at a time when the long-range weather outlook shows a much better set-up. Now keep in mind that the long-range is not always accurate, but positioning/sentiment wise, if a colder than normal outlook is the set-up by the end of January just as positions get washed out, that may present the bullish trade opportunity we are waiting for. But still, nothing will eliminate the fact that the first two weeks of January may turn out to be warmer than normal. The damage is being done to our EOS 2019 April forecast which was revised from an initial 1.05 Tcf at the start of the month to 1.35 Tcf. This is what the bearish weather did to storage. For us, we like to see the sentiment washout continue. We think the set-up may be even better going into the end of January, and once traders start thinking that the rest of this winter may remain warmer than normal, that’s when the set-up for a long opportunity may present itself.
B.C. regulator says fracking caused earthquakes near Fort St. John – CBC – The B.C. Oil and Gas Commission has blamed fracking for three earthquakes in northeastern B.C. last month.The provincial regulator says the events 20 kilometres south of Fort St. John on Nov. 29 occurred because of fluid injections during hydraulic fracturing at a Canadian Natural Resources wellsite. The events, which were felt but caused no surface damage, measured 3.4, 4.0 and 4.5 magnitude. Fracking operations within the lower Montney formation, a major shale oil and gas resource near the B.C.-Alberta border, were suspended after the earthquakes and are to remain suspended at the multi-well pad, pending the results of a detailed technical review.The commission says seven wells into the upper Montney formation had previously been drilled and completed by the Calgary-based company with no seismic events larger than magnitude 2.5 detected. The immediate shutdown of operations is required when an induced seismic event in that region reaches or exceeds a 3.0 magnitude.
OGC says November earthquake caused by fracking – – The B.C. Oil and Gas Commission has determined the three seismic events which occurred approximately 20 km south of Fort St. John on November 29, were caused by fluid injection during hydraulic fracturing operations conducted by Canadian Natural Resources Limited. According to OCG, the events measured 3.4, 4.0 and 4.5 magnitude, with the first event recorded at 18:27 MST followed by two smaller aftershocks ending at 19:15 MST. The Commission received 14 reports of felt events related to this seismicity. CNRL performed wellbore integrity assessments, and no problems were reported. As per the Commission’s Kiskatinaw Seismic Monitoring and Mitigation Area Special Project Order and the Drilling and Production Regulation, CNRL immediately suspended hydraulic fracturing operations.OCG says the investigation included a review of operational and seismological data within a 10-kilometre radius of the epicentres as determined by Natural Resources Canada. “The events occurred during hydraulic fracture operations targeting the lower Montney formation. Seven upper Montney wells had been previously drilled and completed at CNRL’s well pad (5-22-81-18W6) from May to June 2018. No events larger than magnitude 2.5 were detected during that period. A pre-assessment report relating to completion operations for two wells (‘G’ and ‘H’) targeting the lower Montney was submitted as required by KSMMA and concluded induced seismicity was likely to occur, but events larger than magnitude 3 were not expected.” Factors leading to this determination include:
- • The timing of the events coincided with hydraulic fracture operations within the lower Montney zone in the ‘G’ and ‘H’ well of the 5-22 pad which were ongoing from Nov. 27, 2018 until the occurrence of the events on Nov. 29, 2018.
- • The epicentres of the events were located in close proximity to the ‘G’ and ‘H’ wells based on data from both the Canadian National Seismograph Network and a proprietary seismic array deployed to monitor for induced seismicity.
- • Water disposal was occurring in the Septimus area but the closest active disposal well was approximately six km from the epicentre of the 4.5 magnitude event. Further, the depth of the events as determined by the proprietary dense array was significantly lower than the formation where water disposal was occurring.
- • Based on “felt” reports, ground motion appears to have been strongest in the vicinity of the ‘G’ and ‘H’ wellbores.
CNRL has satisfied the pre-operation and active operation requirements as per the KSMMA order. However, all hydraulic fracture operations within the lower Montney formation will remain suspended at the 5-22 well pad pending the results of a detailed technical review. CNRL continues to cooperate fully with the ongoing investigation..
Environmental and economic development choices split Canada’s First Nations – – A Vancouver-area First Nation’s decision to support the Woodfibre LNG project may have come as a surprise to some, considering the nation’s role in helping to derail the Trans Mountain pipeline expansion earlier this year. The Squamish Nation community was one of a handful of First Nations that lined up to convince the Federal Court of Appeal in August to overturn National Energy Board approval of the controversial oil pipeline expansion from Edmonton to the West Coast, leaving its future in doubt. But the nation’s acceptance of the liquefied natural gas export project last month reinforces a simple truth, says historian Ken Coates: While Canada’s first people may approach tough questions differently than non-native Canadians, their decisions are motivated by many of the same factors. “These are complex issues and you’re always going to have people on both sides,” said the Macdonald-Laurier Institute’s senior fellow in Aboriginal and northern Canadian issues and the author of several books and publications on Indigenous relations. “These are communities that need real sustainable, substantial economic benefit, where Indigenous people have been locked out of the market economy for 150 years, since Confederation. They’ve been wanting in for a long period of time.” Woodfibre LNG gained trust through five years of consultations and by agreeing to abide by conditions under the nation’s environmental and cultural assessment process (which operates separately from federal and provincial regimes), said Khelsilem, a spokesman for the Squamish Nation council, and one of its councillors who voted against the proposal in a close 8-6 vote. In return for its support, the community is to receive annual and milestone payments totalling $226 million over the 40-year life of the project, and its companies will be in line to bid on up to $872 million in contracts.
Heritage Petroleum claims sabotage in oil leak – – Predictions of sabotage of T&T’s oil assets are materialising after Heritage Petroleum reported that a crude oil line had been hacksawed on Friday by alleged saboteurs. In a statement, Heritage Petroleum Company Limited said it was now working with the police to find the parties responsible for an act of sabotage on one of its pipelines at CR64 Production Header in Cruze Field, Point Fortin. The cut line was discovered at 3pm on Friday and came a day after a sub-sea leak developed at Soldado North fields in the Gulf of Paria. While the sub-sea oil leak has not been identified as sabotage, Heritage Petroleum said the damage to the pipeline at Cruze Field, Point Fortin seemed to be an act of sabotage. The three-inch bulk pipeline was visibly hacksawed in several places and stolen, resulting in the spillage of approximately 50 barrels of oil. Booms were deployed to contain the spilled oil. “Recovery and clean-up efforts are ongoing,” Heritage Petroleum said. All regulatory agencies, including the Ministry of Energy and Energy Affairs; the Environmental Management Authority (EMA); and the Occupational Safety and Health Agency (OSHA) have been notified. “Heritage Petroleum…is committed to ensure that all our assets and people were operating safely and within the law,” the company said.
US Rig Count Rises As Canadian Drillers Prepare For Winter – Coming off a rather abysmal week for oil prices, Baker Hughes reported a 3-rig increase for oil and gas in the United States this week. The total number of active oil and gas drilling rigs now stands at 1,083 according to the report, with the number of active oil rigs increasing by 2 to reach 885 and the number of gas rigs increasing by 1 to 198. The oil and gas rig count is now 154 up from this time last year, 138 of which is in oil rigs. WTI prices were up slightly on Friday following a uneventful EIA report which showed US crude oil inventories were virtually unchanged for the week, contrary to Thursday’s API report which showed a surprise crude oil inventory build. Brent crude was trading slight down on Friday, at $52.44 (-0.55%) The WTI benchmark was trading up 0.29% (+$0.13) at $44.74, still down for the week. Canada’s oil and gas rigs for the week decreased by 61 rigs this week after losing over 50 rigs in the two weeks prior. Canada’s total oil and gas rig count is now just 70, which is 66 fewer rigs than this time last year, with a 43-rig decrease for oil rigs, and a 18-rig decrease for gas rigs for the week as Canada’s oil patch gears up for winter season. The EIA’s estimates for US production for the week ending December 14 continues to weigh on prices, averaging 11.6 million bpd – a drop off from the high of 11.7 million bpd a few weeks ago. By 1:08pm EDT, WTI had increased by 1.88% (+$0.64) at $45.45 on the day. Brent crude was trading up 1.25% (+$0.66) at $53.39 per barrel.
Canada’s Energy Policy Creates Structural Problems for Oil and Gas Industry – As the U.S. oil industry reels from the collapsing oil prices, Canada’s oil business is seeing its oil prices rallying. How can that be? It is the result of strong political intervention in Alberta’s oil business in an attempt to save it from devastation. When the oil price differential between Western Canadian Select and West Texas Intermediate swelled to $52 a barrel in November, the impending devastation of the Canadian oil industry demanded swift and decisive action. It was delivered, although somewhat reluctantly, and only after an earlier proposed solution failed to change the oil market sentiment. Following an OPEC-like production cut, the oil price differential has shrunk to only $16.60 a barrel, in line with what existed last spring. How the Canadian oil industry got into this mess is a tale of energy policies going off the rails when liberal politicians placed an anti-fossil fuel governing agenda ahead of the economic interests of the country’s largest industry, and a source of substantial government revenue. The tension between Canadian liberal and conservative governing philosophies has existed for decades. It has often revolved around the development of Canada’s natural resources. The first high-profile battle between the governing philosophies occurred in the 1980s, as the world dealt with the dramatic oil price hikes engineered by OPEC in the 1970s and the loss of Iranian oil supplies from the market. Today, the political battle is over constructing additional oil and gas pipelines for exporting more fossil fuels, which, when burned, release carbon emissions that contribute to global warming and threaten the existence of future generations. Stopping the burning of oil and natural gas, and especially the carbon-rich bitumen extracted from Canada’s oil sands, has become a paramount objective of environmentalists. Canada, with the world’s third largest oil reserves, of which 97 percent is oil sands, has become a prime target of the “keep it in the ground” movement. Their key disruption strategy is stopping the building of new pipelines. For Canada, oil exports are critical to its economic wealth. Unfortunately, the lack of pipelines carrying hydrocarbons anywhere other than to the United States has created a unique dilemma for Canada’s oil business. America’s shale revolution success is reducing the need for more Canadian oil. This is a change in the historical relationship between the two countries. While Canada remains the number one oil supplier to the U.S., the slowing of America’s oil use and the growth of its domestic output is forcing Canadian oil producers to seek new markets.
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