By George Kaplan
Production is dominated by major international companies, particularly, and maybe surprisingly, European ones. Principally Shell (NYSE:RDS.A) (NYSE:RDS.B) and BP (NYSE:BP), but with Equinor (NYSE:EQNR), Eni (NYSE:E), Total (NYSE:TOT) and Repsol (OTCQX:REPYF) (OTCQX:REPYY) also active and many are (or were) seemingly wanting to expand in the area. Maybe this is an example of reciprocal technology transfer: the North Sea was initially developed with a lot of American offshore know-how and there it may now be the reverse is happening as deeper water fields using floating and subsea systems are developed.
The recent growth in production has come from the larger players, and they are taking a bigger slice of the expanding pie. The medium sized independents and smaller non-operating owners held many assets in shallow water but do not have the money, risk acceptance or knowledge to participate in the deep and ultra deep projects.
Each lease has a nominated operator, and the proportion of production for each operator is shown. This is not the same as the operator of the surface processing platform; for example, Julia is a subsea lease operated by Exxon Mobil (NYSE:XOM) but the fluids are processed in the Chevron (NYSE:CVX) operated Jack FPU. Exxon Mobil provided the subsea control system that interfaces with the subsea wells and Chevron installed and now operates it. Operatorship of the leases is concentrated, and the proportion growing, amongst the major oil companies (shown), and still more so for the operations of the surface facilities.
The big three operators dominate the drilling activity, which is now almost all deepwater, even more than they do production.
Reserves are concentrated among the larger players; they also mostly show reserve growth (from brownfield growth I think), whereas the smaller companies mostly show decline. These figures are BOEM estimates and only go to 2018, but I think the trend would continue in 2019 as the projects announced for FID, and therefore that allow booking of reserves, are owned by the super majors. Lord knows what’s going to happen for 2020, though. Note that the numbers are more fuzzy even than the BOEM estimates as I don’t know how reserves are shared when a field is split across several leases with different ownership, so the best I could do was a simple equal pro-rationing of the field across each lease. The R/P numbers are around six to ten years but they change a lot from year to year. Only 2018 numbers are shown; in 2017, there was a clear trend of larger companies having higher R/P but that disappeared.
The large E&Ps keep up pretty well with their plug and abandon commitments for wellbores. They have a low proportion of temporary abandoned wells, although their number of completed and operating wells is growing because production is growing. Medium sized E&Ps, and still less the small independents are not; even as their proportion of operating wells fall their proportion of temporarily abandoned wells, and the total numbers of wells requiring future P&A are growing significantly. I think there is a good chance that many of these smaller operators will go bankrupt leaving a number of potentially leaking wells, presumably for the tax-payer to clean up (Fieldwood is quite a large company but with large liabilities – see below – and is leading the bankruptcy charge).
These liabilities are based on BOEM estimates and I’ve only added them based on the operatorship. In reality, it is likely to be a lot more complicated with lease owners having to contribute so that more cost would devolve to the smaller companies. However, the huge liabilities against “Others” is apparent. I’m not exactly sure how this would be included against the company’s net worth, but it wouldn’t be a surprise if many were technically bust. The shallow water wells, which make up most of the inventory for the independents may be a bit easier to abandon, but there is no guarantee as they are not necessarily shorter and may require a MODU to access, whereas many of the deep-water platforms have dedicated rigs. Similarly floating deep-water production units are easier to remove than piled jackets.
In the following charts, the red band at the top of a company’s production shows the total equivalent gas, pale blue at the bottom is shallow C&C production, deep C&C is yellowy-green and ultra deep is greeny-blue. The more green for deep, and blue for ultra deep, the hue means the larger the present size of the field. Only the most significant fields in a company’s portfolio are named. The average line is the twelve-month trailing average for the combined production of the companies shown, and operatorship the combined operated lease production.
Shell is the biggest producer and operator, mostly thanks to Mars-Ursa, which is the biggest basin in the GoM. To date it has concentrated in deep water rather than ultra deep, but that is now changing as Appomattox continues to ramp up and with Vito due. Shell has a 60% ownership in Whale, described as one of the decade’s largest discoveries in the Gulf, and expected to be a 100 kbpd development, even if it has been mooted as a tie back to Perdido and tie-backs that size are rare (in fact, I don’t think I know of one). Shell has enough reserves, developments and prospects to stay top and increase production even given the latest slowdown.
BP is top dog in ultra-deep and is likely to keep expanding with Mad Dog II under development and Atlantis III in ramp-up. Mad Dog II (aka Argos) at one time had break even price of $80, the highest of the GoM prospects at the time by about $20. It was considerably simplified afterwards and costs have decreased but current economics must be marginal at best. Thunder Horse and Atlantis were something of disappointments initially but recent brownfield developments and in-fill drilling have continuously raised reserve values. Most of the super majors tend to sell off assets once the get to run down stage but BP does this more than most.
Jack/St. Malo is the Chevron flagship, taking over from Tahiti. Both now seem to have completed the major development phases. Stampede and Big Foot are still ramping up.
At the end of 2019, when oil was still at $60, Chevron booked writedowns of around $10 billion and stated that much of its deep water resource was not commercial at this price range, although I think most was not in the GoM. Chevron has significant undeveloped assets as operator at Anchor (in mid development); Ballymore (a qualified field in BOEM but with no FID until 2021 and the last news I saw was that it was planned as a tie-back to Blind Faith, which would tend to imply maximum production around 30 to 50 kbpd); and also has minority ownership in Shell’s Whale (no FID before 2021) and BP’s Mad Dog II. In December 2019, the IHS Upstream Capital Cost Index, a measure of development costs, was 180, down from 230 when oil prices were at their peak. Given a supply shortfall enough to cause a price spike, it is likely this index would rise significantly, made worse by the loss of workforce through demographic changes and the two recent price crashes. Therefore, prices of $100 or more could be required to make some of deep-water projects attractive again. Will this ever be seen – the camp that says the world economy can’t afford them seems to be winning at the moment, but maybe some kind of shale-like economic con or government intervention would allow it.
Originally Anadarko had interests in deep-water fields with platforms operated by others. In 2016, Anadarko acquired and took over full operation of assets from Freeport-McMoRan (NYSE:FCX), which, in turn, had got them mostly from BP. It did completed several in-fill wells through 2018, which just about kept production increasing slightly, but that activity stopped and Anadarko mostly switched to share buybacks. Before that its two big new projects were Lucius and Heidelberg, neither of which, I think, has done quite as well as expected (originally there was a phase two planned at Heidelberg that seems to have faded away and Lucius processing system is more used for tie-backs: Buckskin, North Hadrian. Anadarko was taken over by Occidental (NYSE:OXY) before the current crash (though BOEM still have Anadarko as the operating entity) in what now looks like a bit of a nightmare deal. Occidental mostly wanted Anadarko’s shale holdings so their GoM assets might have been seen as a bit of a millstone even with $60 oil.
Exxon Mobil would like to find a buyer for their GoM assets, but is probable going to be frustrated without dropping the price unrealistically or a sudden oil price spike. It operates a few leases, the largest producer is Julia; there has been talk of a Julia II expansion (larger than the original) but seems to have gone quiet – maybe waiting for spare capacity at the Jack floater. It had one of the original large deep-water projects at Lena but that has been abandoned over the last few years.
Fieldwood and EnVen (Apache, Noble and Marathon)
EnVen (ENVN) and Fieldwood (OTCPK:FWDEQ) are fairly new E&P companies with exclusive interest in the GoM. Fieldwood was formed during the irrational exuberance high price era in 2013 from Apache shallow water assets, with a lot of gas. It later took over the rest of Apache, and Sandridge and Noble assets in 2018. Production has been steadily falling and it declared bankruptcy in early August 2020 with $1.8 billion in debts and for the second time in two years. It has very high P and A liabilities for shallow water fields and a lot of end of life deep fields (all grouped in the pale yellow strips, which represent several similarly coloured lines) including Bullwinkle, which has the highest platform decommissioning costs. Its larger deep-water fields of Dantzler, Big Bend and Gunflint are all processed through the Thunder Hawk platform; combined they are over 50% depleted by BOEM reserve figures, unless there have been significant revisions since 2017, with Big Bend and Dantzler at end of life. It has operatorship of Katmai, a deep water field with 25kbpd design capacity and due this year. I don’t know how that will proceed now.
EnVen was also formed in 2014 and acquired assets from Shell, Eni and Exxon Mobil through 2016 and took over Marathon assets. It applied for an IPO in 2018 but withdrew in February this year. Performance has not been impressive and it might be in the cue for the chopping block. It operates four old deep-water platforms, with interest in two others and doesn’t get involved in much greenfield exploration, but concentrates on near field low-risk opportunities.
Murphy, LLOG and Ridgewood/ILX
Petrobras (NYSE:PBR) opted out of the GoM in 2019, mostly selling up to Murphy (NYSE:MUR) in a new venture, MP GOM, in which Murphy holds 80%; Murphy also took over operations. The Petrobras holdings in Cascade/Chinook and its Lucius were pretty disappointing and the Jack/St. Malo project, which has done well, has come to the end of its main development phases. Murphy also got a lot of assets from LLOG, including the development and operation of the 80 kbpd Kings Quay FPU. I wonder what the stake holders think of its expansion plans now. LLOG also sold their holdings in Shenandoah development (70 kbpd originally planned for 2024) to Blackstone, a fairly new private equity player in the GoM.
LLOG seems to have had a bit of a fire sale in early 2019 and it also sold a chunk of assets to Ridgewood/ILX. LLOG is privately owned so maybe the owners were cashing in but they also lost some income in 2017/2018 with a major failure in a subsea template at Delta House FPU. Ridgewood is a private equity company but also partly owns ILX with Riverstone Energy. Both entities concentrate on non-operated deep-water GoM developments, often they have independent holdings in the same leases. LLOG concentrated on one or two well tie-backs and it looks like Ridgewood/ILX are continuing that way and have a number of prospects, though exploration may be delayed.
Other International Oil Companies (Equinor, Eni, CNOOC, Total, BHP and Repsol)
Equinor is a significant producer and expanding, proportionally, faster than any other, and that is likely to continue as it has holdings in Stampede and Big Foot (still ramping up), Vito (in development) and North Platte (in FEED). It does not operate leases or platforms.
Eni looks to be fading away, it owned a part of some small recent tiebacks but nothing planned
CNOOC (NYSE:CEO), which used to be Nexen, was trying to pull out of GoM activities in 2018 because of the Trump trade wars but haven’t done so and are unlikely to find a buyer at the moment.
Total is a small but ambitious producer and will grow as it has 37% of Anchor (80 kboed, due in 2024, but may be delayed) and 60% of North Platte, for which it will be operator (80 kboed in delayed FEED and with 20 ksi completions, like Anchor).
ConocoPhillips (NYSE:COP) is a small producer and would probably like to sell up if possible.
BHP (NYSE:BHP) is a significant but declining producer and a couple of years ago there was talk of shareholders agitation to sell up.
Repsol has an agreement with LLOG to develop Leon and Moccasin as tiebacks. They co-operated on the similar Buckskin project, which, like these two, was originally thought to be a larger field.
Other Large Independents (Talos, Hess, Deep Gulf and W&T)
Most of the assets of these independents are in decline with nothing much new on the horizon. Deep Gulf, owned by Kosmos (NYSE:KOS) since 2018, and Talos (NYSE:TALO), which took over Stone in 2018 and Castex in August this year, have expanded slightly recently, Hess (NYSE:HES) stayed about level (but I think was trying to sell some assets to fund developments offshore Guyana) and W&T (NYSE:WTI) is mostly in shallow water. These sorts of companies tend to go for short cycle, high margin projects, and economics and geology are militating against those at the moment (and for the near future). Combined these companies lost over $700 million in the second quarter (though only W&T is exclusive in the GoM, and Talos mostly there). I’d imagine all are suffering with debt. Hess operates Tubular Bells, tied back to the Williams FPS, Gulfstar. It was supposed to be the anchor field for the platform, to be followed by other tiebacks; there was a small discovery and single well tieback this year, which is counted against the Tubular Bells field, but I don’t know of any other prospects.
Editor’s Note: The summary bullets for this article were chosen by Seeking Alpha editors.