A Guest Post by George Kaplan

This post covers recent C&C production and future prospects, with a bit on gas, for several mid-size non-OPEC producers. A few have been omitted (e.g. Canada, Kazakhstan, Egypt, UK) for no particular reasons other than lack of time or anything much to say, but may be covered in the future. Many of the countries here have held a bumpy plateau over the last twelve to eighteen months. For most this has come after a period of decline, and some are showing signs that decline might be starting again. Brazil has been on a plateau after a period of increase, and may be about to renew that growth. There is a general theme that oil discoveries and developments are drying up and most of the countries are looking more to gas, but with the current gas glut looking like it might end up worse than the 2014/15 oil glut that strategy may prove difficult in the near term.

Brazil

Brazil production peaked in March and has been on a plateau since (data below is through July, there should have been an August update but ANP aren’t very consistent in release dates). They have had several large FPSOs offline for maintenance (generally their FPSOs don’t have the best availability and they have had recent common mode failure issues with the high pressure gas risers, though I don’t know if this is a direct cause of the recent turnarounds). The Campos fields’ average water cut seems to be accelerating, which might also be contributing to a plateau rather than allowing a new peak.

All the new production growth is coming from the Santos basin. PetroBras production contributes about 82% to the total, but gradually falling as the new Santos production is partly foreign owned, e.g. by Shell – one reason they bought BG, and may fall faster now as PetroBras are trying to divest older fields. Their figures come out quicker than ANP and they report a new record in August, but falling slightly in September and October. They have bought the Libra extended test production on-line this month which will add production, and give some indication of future expectations.

There are ten new, large FPSOs due through 2021, and a couple of others possible, which would altogether add about 1.5 mmbpd extra nameplate. However the overall decline rate now indicates they need about three major new projects per year just to maintain plateau, and if the Campos FPSOs’ performance is repeated then the earliest Santos facilities should start to decline this year or next, and can go quite quickly.





Data from: ANP and PetroBras.

Mexico

Mexico had a big drop in September production because of hurricanes and planned turnarounds, which has mostly been recovered, but they still continue on a general decline, losing an average of about 15 kbpd C&C per month from August to October (10% y-o-y drop from October 2016). With KMZ showing more signs that it might be coming off plateau this may accelerate (i.e. Ku field looks to have recent gas breakthrough and overall y-o-y decline is up to 1.9%). Abkatun-A2 is due on stream in 2019 (a replacement for a previous platform lost to an explosion and with 60 kbpd nameplate) and there were some recent significant discoveries that should add production in 2021 or so provided the appraisal drilling is successful. There have also been some onshore discoveries that could be brought on-line quickly, but Pemex just seems to keep on losing money so CAPEX funding could be a problem.

Data from: Pemex.

Norway

Norway data is through September. They are in slight decline this year, which has accelerated recently because the Goliat platform is being held offline for safety reasons. Gina Krog (60 kbpd nameplate) is ramping up and Maria (40 kbpd) started this month. The other recent start-ups are showing fairly early and relatively steep decline. There’s no new oil due in 2018 but about 140 kbpd in 2019 (in particular Martin Linge and Oda) and then more than 300 kbpd to start ramping up in 2020 when Johan Sverdrup comes on-line. Martin Linge has had problems and this month Total sold its stake to Statoil, who take over operatorship.

Data from: NPD Fact Pages.

Colombia

Colombia is holding a plateau that will allow them to meet this year’s target of 840 kbpd. There isn’t much else immediately in prospect but plans for more offshore drilling, which has so far been disappointing, and shale deveelopment.

Data from: Colombia Ministry of Mines.

China

China has had some success in arresting their decline rate, but have a lot of ageing fields which use various EOR methods and only a few, smaller, offshore fields in development. There’s quite a bit of exploration activity in the South China Sea.

Data from: National Bureau of Statistics of China.

Azerbaijan

Most Azerbaijan oil production comes from the BP operated offshore Azeri-Chirag-Gunashi facilities, and it is declining pretty much in line with the original production application for that development. There isn’t much additional oil in the pipeline but Shah Deniz II (also BP), a large gas field has just started and will add about 50 kbpd condensate, and a similar Total project, Absheron, is in early engineering and due to start-up in 2021.

Data from: SOCAR.

Selected Other Mid-size Producers

All the producers shown are oil importers except Oman, with Indonesia, Vietnam, Thailand and Malaysia switching from exporters in the last fifteen years and India and Australia showing rising import rates in the same period.

Data from: Jodi, EIA, IEA and OPEC.

Oman

Oman has a nice new data and statistics government website but seems to have forgotten to employ anybody to keep it updated, so there’s no production data there after May. They also stopped reporting to Jodi last year but, as with all countries I’ve looked at, EIA estimates look pretty good. They have been meeting their commitments to NOPEC cuts and holding at 970 kbpd. It’s possible, however, that this cut is hiding a peak in C&C production, as they redeveloped some pretty mature and declining, heavy oil fields starting about ten years ago using various EOR methods, including miscible gas, chemical and steam injection projects, and those gains were obviously fading before the cuts. They have some new gas developments, e.g. the Khazzan tight gas project for BP at 200 kboed started in September, but no major oil developments, and nothing big on the cards (Yibal Khuff is a small field at 10 kbpd due in 2020).

India

India is holding a plateau, but never seem to meet monthly targets. They don’t have much new oil production in development (one platform at 75 kbpd due in 2020, and some smaller shallow and heavy oil facilities) and seem to be switching over to concentrate on gas, like a few other countries.

Australia

Australian oil production is in terminal decline. A large proportion of their production is condensate, which has been holding steady, so all the drop is in the crude, which is falling at about 15% per year. A small offshore development, Greater Enfield at 12 kbpd, is due in 2019, but they have potential for natural gas both offshore and onshore (with tight gas and coal bed methane).

Data from: Australian Petroleum Statistics, Commonwealth of Australia 2017.

Vietnam

Vietnam oil production is in terminal decline at aroud 8 to 10% per year, and gas production may have peaked this year. The Ca Rong Do project (a tension leg wellhead platform and chartered FPSO at 30 kbpd) is due in 2020. I haven’t heard much about new exploration but there has been a dispute with China in the South China Sea, which is supposed to have been rectified and may open up some offshore prospects.

Thailand

Thailand is the smallest of the producers shown and has held a plateau for eight or nine years at just above 200 kbpd. It doesn’t have much in prospect for new developments and exploration has been a disappointment recently.

Malaysia

Malaysia has high quality, light, sweet oil (its Tapis grade is among the priciest) and is a large LNG exporter, though gas production looks like it may be plateauing. C&C production has increased from a low in 2015 but is now again in decline with nothing major due for oil after Malikai completes ramp-up this year (60 kpbd, Shell operator), but some smaller gas developments. Almost all discoveries since 2012 have been gas or gas-condensate. There are prospects for deep-water exploration and EOR on some of the mature fields, but these probably need much higher oil prices.

Indonesia

Indonesia had Banya Urip extension, large ExxonMobil oil project, ramp-up last year but is now back in decline. There are some small oil tie-backs due in 2019 at Natuna. The government has promised to attract $200 billion investment to try to stop its production declines, for both oil and gas (in which it has been a major producer but peaking in 2001). However so far there hasn’t been much to show for this. East Natuna is a huge gas field development ($40 billion estimate) that ExxonMobil recently pulled out of saying it wasn’t commercial in current conditions. Masela (Abadi) is another multi-billion project for LNG, much delayed but possibly now in pre-FEED with Shell and Inpex. Ande Ande Lumut is a heavy oil development that looked likely to go ahead but the operator has now down graded the resources from 2P to contingent. Other prospects are mostly gas. The small gas-condensate field, Madura BD at 110 mmscfd and 6 kbpd condensate, started up in August.

Off Topic Finish – USGS Undiscovered Conventional Resources

I posted these charts as comments on a previous thread and made a bit of a mess of them. They show USGS estimates for global, undiscovered, conventional oil (or actually all liquids) and gas by area and region, from a 2012 analysis: Supporting Data for the U.S. Geological Survey 2012 World Assessment of Undiscovered Oil and Gas Resources, by U.S. Geological Survey World Conventional Resources Assessment Team. It’s worth keeping in mind that these are technically recoverable numbers, i.e. at any cost (for example it’s been suggested – not by the USGS – that a lot more oil in the North Sea could be recovered if coffer dams were built north and south and the sea completely drained so that wells could be drilled all over and produced without needing expensive offshore facilities). These are probabilities and with a wide range from P5 to P95 in all the numbers (nominally there is a non-zero chance that nothing will be found) and I don’t know if the USGS goes back and re-does the analyses as actual data becomes available. On some of their assessments there is a constraint the the resources are expected to be discovered within thirty years, but I don’t think that can be the case here and couldn’t find a statement either way in the briefing reports.

The largest expected resources from the USGS analysis are in offshore regions, and mostly in deep water or other inhospitable areas. The P50 cases (i.e. most likely) given are about 400 Gb oil offshore, 200 Gb onshore and 550 Gboe gas offshore, 200 Gboe onshore.

Recent discovery rates have been around 2 to 4 Gb per year for oil, and a bit more for gas, with each seemingly on a falling trend. Giant fields are rarely found now and average discovery sizes are below 50 mmboe, and also falling. Discovery success rates are also falling, down from about one in five wells to one in twelve to one in twenty in frontier areas (where many of the USGS resources are expected to be found). Therefore it might be expected to take well over a hundred years, thousands of wells and trillions of dollars to find the P50 resources, assuming a BAU trend could be continued. In fact fitting a geometric decline to recent years’ data and extrapolating would give only about 25 Gb total of future oil discoveries

Deep-water wells are expensive, probably over $100 million each, though slightly lower at the moment, but likely to increase quickly if activity picks up again (the deep water drillers have been burning the furniture or chucking stuff overboard to keep their ships running – and that includes scrapping many deep water rigs and laying off a lot of experienced staff). As an example of (currently) an extreme case: say twenty wells, including appraisals, per discovery, average of 25 mmbbls per oil discovery, and $100 million per offshore frontier well gives $800 billion expense to find 10 Gb. That is $80 per barrel that might not be paid out for fifteen or more years and does not include operations and development costs (which would be huge for small, isolated offshore fields). Such a scenario would not happen without oil at maybe $200 or $300 per barrel, and maybe EROI considerations make it impossible at any price. Of course extrapolating trends like this from fairly short ranges of stochastic data can make you look pretty stupid, even from just one or two outliers in the near future.

For more details on discovery successes see: 1) HSBC, Global oil supply: Will mature field declines drive the next supply crunch? 2) Rystad, Eyeing Beyond The Short-Term: Discoveries and Their Impact On The Oil Price 10 Years Down The Road. 3) IHS, Oil and gas discoveries dry up to lowest total for 60 years (FT report from February 2017). The image below is from the Rystad report: Rystad.

Usually there are more discoveries in the second half of the year, maybe because of the northern hemisphere summer or because E&Ps like good news for their end of year statements, but 2016 was different and I think this year will be the same and show continued decline. Operators tend to prioritise the best prospects, irrespective of what they think the oil prices will do, therefore every time a well is drilled, whether successful or not, the average chance of success in the pool of prospects declines, and that only changes if some attractive new leases become available, although a discovery will improve other near field prospects. It’s also worth noting that any large, good quality discoveries made recently, like Liza in Guyana or Zohr in Egypt, are almost immediately being fast tracked for development despite depressed oil and gas prices.

The number of wildcat (i.e. frontier exploration) wells has been trending down, and without much correlation to oil price but definitely accelerating since the recent price collapse, for the last twenty five years: for example 2009, following the recession, saw low shallow water activity but no fall in deep-water and a record number of wells for ultra-deep, probably because of new generation DP rigs becoming available, whereas all exploration continued to fall through the high price years from 2011 to 2014. At current trend there will be none drilled within ten to fifteen years (see the FT article referenced above), which suggests to me the E&Ps are running out of places they think there might be things worth discovering. Seismic can’t tell if oil is present but it can find the maximum likely unrisked resource (i.e. the size of the trap), and if that is below a commercial limit then there won’t be any drilling. Gas might be doing a bit better because, although it is significantly discounted against oil price, recently there have been some giant discoveries that can be developed economically, and that trend might continue, plus FLNG might open up some otherwise stranded, smaller prospects.

The chart below highlights some of the high profile basins. I decided on offshore or onshore designation depending on whether the USGS had more than 90% allowance for the basin in the respective location. These are not all the regions considered but include the ten top oil and gas estimates and a few other interesting ones. They are ordered by total, combined P5 estimates, but I’ve only shown the P50 numbers, so riskier areas, like Greenland, stand out.

Santos (Brazil), Mesopotamia (Iraq) and Zagros (Iran) are the three major possibilities for big oil finds (maybe also Arctic Alaska based on recent discoveries). Santos has had mixed lease interest and before that mixed exploration results. E&Ps are probably also waiting for the PetroBras Libra pilot project results. The West Central Coastal basin includes Kwanza province, which had high, and ultimately disappointing, prospects. Nile Delta Basin and Mozambique Coastal have had successful gas discoveries since the report. Guarija is offshore Colombia and has been a disappointment with a couple of dry wells and only gas in the others, though I think Anadarko are planning another well next year. East Barents Basins and Barents Sea indicate mostly gas and therefore it is maybe not surprising that Statoil and Lundin haven’t been successful in their oil exploration (not much gas either, and probably very difficult to develop should they find any). The Red Sea basin has been explored by Saudi and Kuwait, it has pre-salt possibilities, but no announced successes and a distinct waning of interest recently. Guyana-Suriname has had big discoveries by ExxonMobil/Hess. Senegal, I think, includes Mauritania, which Tullow just gave up on, but was the site of the biggest find by far this year: 15 tcf gas (2.5 Gboe) for BP/Kosmos. Campos and Foz do Amazonas, like Santos, are offshore Brazil and have had a fair bit of lease interest but there are ecological issues with the second one. South China Sea has had a border dispute, which might be settled now, and includes interest from Vietnam, Philippines, China and Malaysia.

USGS also show onshore resources by country: they have 12 Gb oil for China but I find it hard to believe that there is a part of that country that hasn’t been thoroughly drilled. For oil China is fourth after Iraq (42 Gb), Iran (13) and Russia (17); Saudi has 10 Gb, but like China that seems to have been thoroughly explored in all the likely spots, and USA 11 Gb. For natural gas onshore the top countries are Russia, Iran, Iraq, Brazil (a surprise to me) and USA.

Data from: USGS and Rystad.