You may recall in my two previous posts on this subject that I sensed EIA production estimates were too optimistic based on large step change (300,000 BOPD or more) production estimates in the weekly Petroleum Status Report (PSR). Now that Texas Railroad Commission (TRC) third month production numbers are in, I can definitively comment on production during the above time frame.
Based on the EIA PSR, US production has increased from 9,430,000 BOPD on August 1, 2017 to 10,251,000 BOPD at the end of January (and 10,525,000 BOPD as of April 6, 2017). That is an increase of 821,000 BOPD (August to the end of January with a further 304,000 to April 6).
It is important to remember that this report projects production four months before the actual numbers are reported. EIA – 914, the monthly report saw production during this time frame increase from 9,192,000 BOPD in August 2017 to 9,964,000 BOPD in January, an increase of 772,000 BOPD. The difference can be explained by the fact that the monthly report is an average whereas the PSR takes into account first and last numbers and therefore averages out for the month. Taking these growth numbers at face value, grossed up to an annual number, gives year over growth of 1.85 million BOPD.
At this level, production growth from the US alone will exceed worldwide market growth in 2018 and oil prices will fall from current levels.
In fact, if these numbers are real, prices should be much lower and OECD storage should be flat or increasing. Clearly this is not the case, as pundits are now saying that the market is in balance.
As I explained in my previous posts, I audited the EIA numbers against state numbers for the period August 2017 through to and including January 2018, from North Dakota, Wyoming, Colorado, New Mexico and Texas as these states represent the majority of US shale oil production, produced from the Bakken, Niobrara, Permian and Eagleford basins, respectively.
Let me be perfectly clear here. US shale production is growing, albeit unevenly from basin to basin, with the Permian obviously leading the way (but not as fast as the EIA is projecting). What I found was quite astonishing in that the EIA numbers are overstated by at least 349,000 BOPD. And to make matters worse based on state numbers, it seems that the rate of growth seems to be slowing in Texas, North Dakota and Wyoming. As the Permian reaches its saturation point of Tier 1 locations, will it face a similar fate as the Eagleford and Bakken and how soon?
Audited state numbers are shown in the Table below:
|Month||Niobrara||New Mexico||Texas||North Dakota||Total|
|Delta to January||15,161||43,785||58,947||64,057||258,912||90,307||472,224|
Note: January Texas numbers include future upward adjustments of 195,000 BOPD. Actual numbers could be much lower. I chose 195,000 BPD as an upward adjustment s this was the largest monthly adjustment over the studied period. The lowest monthly adjustment was only 95,000 BOPD.
Based on state numbers, that overall five state production during the above period has grown by 472,000 BOPD. Not 821,000 BOPD. The point here is what is the real annual rate of growth? Using state numbers, it is about 945,000 BOPD growth per annum versus the projected EIA growth of 1.85 million BOPD per year.
The difference has a huge impact on the supply demand balance.
One obvious “bust” in the EIA numbers is that they carry Texas production of 3.9 million barrels per day whereas the TRC shows production in the range of 3.3 million BPD (crude and condensate). Some have said that future adjustments will narrow the gap. This is a spurious argument as adjustments usually occur in the early months and diminish over time as indicated by the TRC. Open royalty files are the production accountant’s worst nightmare.
Another argument for accelerating Permian growth is that oil takeaway pipelines are full resulting in shut-in production. The recent widening discount of up to $9.00 per barrel represents the cost of trucking to market and the economic rent extracted by pipeline operators as systems reach capacity. Look to the Canadian oil sands and the lengths producers will take to move product to market and to what cost. Almost a million barrels per day is moved by rail in Canada.
That said, solution gas processing and gas takeaway capacity could supress production as the TRC only allows 180-day flaring exemptions where existing pipeline capacity is full. I expect that as regional gas takeaway capacity is reached, producers will have no choice but to slow drilling (there is absolutely no evidence of this as drilling levels remain high), or to manage well production by producing newer wells which produce more oil rather than older wells with higher GOR’s. That said, midstream companies are racing to add more oil and gas takeaway capacity including the Gulf Coast Express Pipeline Project (GCX Project), designed to transport up to 1.92 billion cubic feet of gas per day.
Takeaway infrastructure may be dampening Permian production to a small degree, but producers have the means to build production (I would guess that this is the main focus of the COO of each and every producer in the Permian) under takeaway oil and gas takeaway constraints by trucking, adjusting which wells are produced to maximize oil production and by the 180-day flaring allowance in Texas. Once new infrastructure is in place (and in the US it gets done fast), a one-time bump in Permian production of 100,000 to 250,000 BOPD (similar to the start of DAPL in the Bakken) could occur, followed by normal monthly increases 40,000 to 55,000 BOPD per month.
The expectation of US production growth of well north of a million BOPD in 2018 has a huge impact on current market sentiment, tending to constrain prices. Until such time as the actual rate of growth is determined later this year, we will have to rely on market prices and OECD storage numbers. Based on the latter two metrics, it sure looks like US and non-OPEC producers are falling behind in meeting worldwide market growth. So, prices up or down and by how much? It sure looks prices will trend up not down.
The next six months will be very interesting.
Randy Evanchuk, P. Eng., has 35 years of experience in the patch. From 2007 until he retired in 2015, Mr. Evanchuk was involved in all phases of of unconventional resource development including;evaluation, economics, production and facilities. As as senior consultant with Murphy’s Holdings, he evaluated their Montney holding and was a member of evaluation team. Mr. Evanchuk was the Vice President of new ventures at Daylight Energy where his team was successful in acquiring a substantial Duvernay position. At Seven Generations Energy he was Executive Vice President looking after facilities, marketing, production operations and long range facility and marketing planning