| $45.88 | 12/20/2018 | 12/20/2017 | 12/20/2016 | 12/20/2015 | 12/20/2014 |
|---|---|---|---|---|---|
| Active Rigs | 69 | 51 | 41 | 64 | 182 |
Conventional oil makes up around two-thirds of the world’s recoverable oil resources and accounts for 93 percent of today’s oil mix. More than half of this oil comes from oil fields that are past their peak and declining, revealed by a loss of about 3 million barrels of output last year.
To accommodate this yearly natural decline from old wells and to satisfy rising demand, the world needs a fresh supply of 5.7 million barrels each year according to the International Energy Agency (IEA).
With so much attention focused on the exceptional growth in U.S. tight oil supply to 11.5 million barrels per day (MMbpd) this year and forecasts of 12 MMbpd in 2019, it is easy to forget the pivotal role of the Middle East in global oil supply.
Rystad Energy analysts expect Middle Eastern oil production to grow by 2.7 MMbpd by 2025, driven largely by supply additions of 1.5 MMbpd from Iraq and another 1.2 MMbpd from the re-opened Neutral Zone—the area between Saudi Arabia and Kuwait—as well as the UAE and Iran.
OPEC countries hold nearly 82 percent of the world’s crude oil reserves of which the bulk 65 percent are in the Middle East, led by Saudi Arabia, Iran, Iraq, Kuwait and the UAE. The world’s cheapest oil producers, with costs between $9 and $10 a barrel in 2016, were respectively Saudi Arabia, Iran and Iraq because their oil lies close to the surface and is pooled in mega fields.
Moreover, the Middle East's producing countries have some of the lowest oil decline rates in the world, which matters greatly since, as one estimate suggests, the difference between a 5.7 percent (2017) and a 7.5 percent (2016) decline rate yields another 900,000 barrels online.
Rystad Energy notes that output from conventional fields beyond the Middle East peaked in 2010 and they expect it to continue falling to 45.6 million barrels a day, a 2.3 million barrel decline from current levels.
This is largely due to the oil price collapse in 2014, which triggered fierce cuts to exploration budgets in 2015 and 2016, flat investment during 2017, and only a slight uptick this year.
In essence, capital investment fell from $750 billion to $460 billion in 2016 and has yet to recover, says the IEA.
The impact is seen in discoveries of new oil, which fell to a record low in 2017 with less than 4 billion barrels of crude, condensate and NGLs.
Discoveries in 2018 are led by offshore Guyana with an estimated 4 billion barrels of oil equivalent, the Barents Sea, the north slope of Alaska, the Dorado field offshore Australia and new finds in Oman and by Norway.
However, unlike oil fields in the Middle East and U.S. tight oil for that matter, conventional offshore oil fields are huge, complex and expensive projects that take years to come to fruition. This has encouraged big energy companies in recent times to invest in acreage, drilling wells and hydraulic fracturing in U.S. shale, especially in the premier Permian Basin stretching from Texas to New Mexico. Drilling a tight oil well costs between $5 and $10 million, is fast—measured in days rather than years—and brings a return on investment within months.More at the link.
The world’s cheapest oil producers, with costs between $9 and $10 a barrel in 2016, were respectively Saudi Arabia, Iran and Iraq because their oil lies close to the surface and is pooled in mega fields.
A combination of winter weather and sluggish upstream investment in the Williston Basin because of declining oil prices will likely cause output growth to plateau or slow in early 2019, potentially until May, Lynn Helms, North Dakota's top oil and gas regulator, said.
Helms added that investments in drilling, fracking and well completions all are slowing down because of the decline in Bakken oil prices.
Bakken crude oil price differentials saw pressure in October and November as growing production in the Williston Basin began to outpace available pipeline takeaway capacity.
Other factors that put pressure on prices was prolonged seasonal maintenance at Midwest refineries this fall and record-low prices for competing Canadian crude as oil there faced issues with takeaway constraints as well. Bakken crude in the Williston basin was assessed at a multi-year low November 1 at a $20.50/bbl discount to the NYMEX WTI calendar-month average.
The differential averaged WTI CMA minus $12.75/bbl in October and November. At their strongest level this year in June, Bakken Williston was trading at WTI CMA plus $1.75/bbl.
Prices quickly rebounded in December, however, after refinery maintenance was complete and there was an announcement that the Alberta government ordered a 325,000 b/d curtailment of Canadian crude production, starting January 1. Differentials spiked in December and Williston basin crude reached WTI CMA minus $3.50/bbl before leveling off at the end of the trade cycle for February. A few trades for January Bakken continue to get done and it was heard bid Thursday at WTI CMA minus $3.25/bbl.By the way, Bakken companies might have actually made money when prices dropped this past autumn. Counterintuitive but very possible.
| Pool | Date | Days | BBLS Oil | Runs | BBLS Water | MCF Prod | MCF Sold | Vent/Flare |
|---|---|---|---|---|---|---|---|---|
| BAKKEN | 10-2018 | 31 | 5442 | 5430 | 7290 | 48543 | 48182 | 0 |
| BAKKEN | 9-2018 | 24 | 14997 | 15318 | 8282 | 25391 | 25111 | 0 |
| BAKKEN | 8-2018 | 24 | 23088 | 22640 | 13335 | 741 | 33 | 428 |
| BAKKEN | 7-2018 | 2 | 30 | 30 | 3177 | 255 | 253 | 0 |
| Pool | Date | Days | BBLS Oil | Runs | BBLS Water | MCF Prod | MCF Sold | Vent/Flare |
|---|---|---|---|---|---|---|---|---|
| BAKKEN | 10-2018 | 31 | 28781 | 28254 | 17395 | 17798 | 13505 | 2136 |
| BAKKEN | 9-2018 | 23 | 24802 | 24934 | 13472 | 22897 | 19134 | 1830 |
| BAKKEN | 8-2018 | 22 | 17630 | 17288 | 14201 | 37668 | 36095 | 245 |
| BAKKEN | 7-2018 | 3 | 377 | 377 | 5564 | 386 | 384 | 0 |
| Pool | Date | Days | BBLS Oil | Runs | BBLS Water | MCF Prod | MCF Sold | Vent/Flare |
|---|---|---|---|---|---|---|---|---|
| BAKKEN | 10-2018 | 31 | 19769 | 19437 | 13546 | 10323 | 6835 | 2396 |
| BAKKEN | 9-2018 | 29 | 20509 | 20645 | 9906 | 21541 | 10950 | 9485 |
| BAKKEN | 8-2018 | 6 | 15963 | 15653 | 11699 | 27597 | 26549 | 71 |
| BAKKEN | 7-2018 | 1 | 157 | 157 | 2862 | 596 | 592 | 0 |
A lot of crazy crap happens in the oil market every now and then. You get used to it. But at least when it happens there is normally a reason (however crazy) to explain it. What's happening to price this week is just nuts...Disclaimer: this is not an investment site. Do not make any investment, financial, job, travel, or relationship decisions based on what you read here or think you may have read here.
Note to liberals who now support military force in Syria because of the Kurds or Russia or Iran or Turkey or humanitarian reasons: NONE OF THOSE WAR ACTIONS WERE AUTHORIZED BY CONGRESS. Only authorized use of force was to go after terrorists. President Trump is right to withdraw troops.
KMI, Suggesting Canada Is Closed For Business, To Sell All Canadian Assets -- September 17, 2018.It appears ExxonMobil has also figured that out -- that Canada is closed for business. This is absolutely incredible.
U.S. oil major Exxon Mobil Corphas withdrawn its WCC liquefied natural gas (LNG) export project in Canada from an environmental assessment.
British Columbia rules require large projects to obtain an Environmental Assessment Certificate before they can be developed.
An examination of the project by the Canadian Environmental Assessment Agency has been going on since February 2015.
LNG demand is growing but environmental groups say exports will boost carbon emissions in Canada, both through gas extraction and the liquefaction process.Let's see, simple arithmetic suggests that as of February, 2019, the Canada's Stop-All-Development Agency, will have held up this project for four years.
Exxon’s decision signaled it is concentrating on LNG projects with Qatar Petroleum and a proposed expansion of its chilled-gas operation in Papua New Guinea.Well, duh.
Here's the same historical comparisons that I ran last week:
Putting this week's storage data into historical perspective, the 2,773 billion cubic feet of natural gas that we had in storage on December 14th was 15.8% lower than the previous five year low for the 2nd week of December of 3,295 billion cubic feet that was set on December 12th of 2014, and was 12.4% below the previous 10 year low of 3167 billion cubic feet that was set on December 12th of 2008.
This year's December 14th storage level was also 1.0% below the 15 year low of 2,802 billion cubic feet of natural gas that we had in storage on December 16th of 2005, and 2.7% below the 2,850 billion cubic feet that were in storage on December 12th of 2003, a year when supplies had peaked at a lower level than this one.
We have to follow the archived records back 16 years, to December 13th of 2002, when 2,635 billion cubic feet of natural gas were in storage, to find a lower quantity of natural gas in storage at this time in December than we have now.
Here's a temperature graphic from the EIA gas storage dashboard in support of Platt's forecasts for smaller withdrawals: https://rjsigmund.files.wordpress.com/2018/12/December222018regionalaveragetemperaturesfromDec7toDec20.jpg
It's pretty clear that the week to the 20th was much warmer than the prior one in every region.
Later, 3:28 p.m. CT: the NG withdrawal was huge this past week, but it is expected withdrawals will be reduced in the coming weeks. From Platts.But forecasts for January are looking closer to normal again, and January will be the tell as to whether we get in trouble before spring or not.
December 17, 2014: I noted this well on the MRO likely-to-be-refracked wells to have been taking off-line in early January, 2014; curious when it will go back on line; according to FracFocus as of 10/18, not re-fracked:CLR: From an earlier post, we now have re-frac data for this well. Full production profile here.
- 19375, A/AB/IA/308, MRO, Gertrude Tuhy 34-24H, 33-025-01147, Chimney Butte, Bakken, 14 stages; 2 million lbs; t3/11; cum 49K 10/18; last production of any note 1/14; six days of production in April, 2015; back on line as of April, 2015; full month of production May, 2015; full month, 6/15; noted in 11/15 to be inactive; noted to be AB, 12/16; but now back on line, 9/18;
June 25, 2016: CLR re-frack in the Rattlesnake Point oilfield. #17089. Update: this well was taken off-line 7/16; getting ready for a re-frack? Recent sundry form says they are getting ready to drill more wells in this area -- was that reason for coming off-line? API: 33-025-00731. FracFocus does not show this well as having been fracked. Now inactive; still inactive as of 5/17. Active as of 6/17; small production, one day, 6/17. Then, 2,000 bbls over 5 days in 7/17; fracked; completed, tested 8/10/2017 with an IP of 1,344; 40 stages; 14.3 million lbs;
October 18, 2015: follow-up production jump on #16510. There was what appears to be a halo effect in June, 2015, but there are still three more wells waiting to be fracked; it will be interesting to see how fracking these three north/south wells affect the double-lateral #16510. This well, #16510, needs to remain on the list of wells that need to be followed up (March 27, 2016). Follow-up here.Recent production:
| Pool | Date | Days | BBLS Oil | Runs | BBLS Water | MCF Prod | MCF Sold | Vent/Flare |
|---|---|---|---|---|---|---|---|---|
| BAKKEN | 10-2018 | 8 | 1059 | 709 | 855 | 1190 | 619 | 468 |
| BAKKEN | 9-2018 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| BAKKEN | 8-2018 | 1 | 134 | 232 | 160 | 7 | 0 | 0 |
| BAKKEN | 7-2018 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| BAKKEN | 6-2018 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| BAKKEN | 5-2018 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| BAKKEN | 4-2018 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| BAKKEN | 3-2018 | 0 | 0 | 0 | 0 | 0 | 0 | 0 |
| BAKKEN | 2-2018 | 9 | 164 | 226 | 40 | 436 | 436 | 0 |
| BAKKEN | 1-2018 | 31 | 711 | 703 | 184 | 2147 | 2147 | 0 |
| BAKKEN | 12-2017 | 31 | 802 | 923 | 215 | 2021 | 2021 | 0 |
| $46.50 | 12/20/2018 | 12/20/2017 | 12/20/2016 | 12/20/2015 | 12/20/2014 |
|---|---|---|---|---|---|
| Active Rigs | 68 | 51 | 41 | 64 | 182 |
The Cushing, OK, storage and trading hub plays critically important roles in both the physical and financial sides of the crude oil market. Located at a central point for receiving crude from a wide range of major production areas — Western Canada, the Bakken, the Rockies, SCOOP/STACK and the Permian among them — the hub also has numerous pipeline connections to Gulf Coast refineries and export docks, and to a large number of inland refineries. And, with Cushing’s 94 MMbbl of storage capacity and status as the delivery point for NYMEX futures contracts for West Texas Intermediate, the hub’s inventory levels and the WTI-at-Cushing price are closely watched market barometers.
But like a lot of other U.S. energy infrastructure in the Shale Era, Cushing’s place in the energy world has been in flux. Most importantly, Permian production has been surging, the ban on U.S. oil exports is a fading memory, and the Gulf Coast — not Cushing — is where most U.S. crude production wants to go.
