By George Kaplan
EIA US Reserve Estimates
The EIA publishes reserve data for the USA, usually in December of the following year - so that the figures presented here are for 2019. Only proved category reserves are shown and the numbers are based on companies' annual reports and 10-K or 20-F filings (so that last year's numbers are now being addressed as most companies have filed). Not every company is included, otherwise the net acquisitions and dispersals (the yellow bars) would surely have to sum to zero, but most are and all the big players. Net adjustments include revisions (which may be technical or economic) and other adjustments, which are fiddle factors to make the numbers add up but are usually zero or small; improved recovery is here included as discoveries and extensions. The yellow dashed line shows the net change.
Most of the non-producing reserve (shown as open diamonds for the last four years) is proved, undeveloped (PUD) but some may be proved, developed, nonproducing (PDNP), such as wells awaiting a work-over or completion. The percentage for oil and gas is about the same at 26 to 28%. There is also not much difference between the US as a whole, which is mostly unconventional reserves, and the GoM (see below), which is conventional, although ultra-deep reserves are sometimes alternatively categorised. I found this a bit surprising as one is built around many low-flow, rapidly depleting wells and the other on fewer, high flowing wells, often with long plateau periods.
Net additions of reserves peaked in 2018 for oil and gas, and total remaining reserves peaked in 2018 for gas and will in 2019 for oil (whether locally or globally time will tell). This rear is likely to show downgrades at least as big as those in the 2015 price collapse. Whether a recovery as seen in 2017 will happen depends on the economy, but the oil companies' shareholders must be getting a bit wary of committing development capital when prices have been so volatile, much of LTO production is at best marginally profitable, and the politics of climate change is becoming increasingly important.
The R/P (reserves over production) values have been normalized to fit on the left hand scale. Oil was at a maximum in 2013 and natural gas in 2018. Both have been declining quickly in recent years, which implies production has been maintained at higher levels than the reserve base, however fast it has grown, can support over the long term.
EIA GoM Reserve Estimates
The boost to crude reserves from ultra-deep fields looks to have run its course starting in 2017/2018. R/P values have been falling since 2012 as production has increased as discoveries have fallen, although it is likely to rise in 2020 as production took a big drop from the effects of the pandemic, the largest annual impact from hurricanes and natural decline because of a hiatus in new start-ups.
Note that the EIA discoveries are not backdated, so they will include any projects reaching FID for the given year. Actual discoveries have dropped far lower in recent years than shown (see previous posts on GoM reserves). The BOEM curve shows remaining reserves backdated to original discovery date, which explains some of the difference between the curves. They are converging but as the EIA estimates include only proved reserves but are higher than those from BOEM that include proved and probable, something else is going on. BOEM figures are only through 2018 but are likely to show a decline for 2019 and more for 2020 - very few new field discoveries are recorded in the BOEM database in the last five years and are much outnumbered by new lease start-ups (i.e. most have been smaller, near field tie-backs following infrastructure led exploration).
For natural gas, the proved estimates from the EIA pretty much coincide with the proved plus probability estimates from the BOEM, which is to be expected in a basin approaching exhaustion. It also appears that the larger companies are divesting their assets to leaner players, as they have been doing in the North Sea.
The largest IOCs (with the I variously standing for integrated, international or independent) are Chevron (CVX), Exxon Mobil (XOM), BP (BP) and Shell (RDS.A) (RDS.B), which can have various and changing rankings depending on market worth, reserve holdings or production. Here I've just shown them alphabetically.
Total Oil is often included as the fifth super-major but it has not yet reported for 2020, though anecdotally, I think it has had better reserves replacement numbers, especially for gas, than the others.
BP oil production has held up well and still the reserve to production (R/P) ratio has been increasing, so discovery or acquisitions have also been doing well. In common with all the companies here, the R/P for gas has been declining noticeably faster and even as production has dropped (similarly for the others except Chevron).
Organic reserve replacement ratios (R-R) include all revisions, adjustments, discoveries and extensions (i.e. it reflects the effectiveness of the companies' reservoir and development teams compared to production depletion) while the total figures include net acquisitions (sometimes called drilling on Wall Street). BP has kept oil R-R stable at around 100% but hasn't done so well with gas. BP had some oil sands holdings but never produced them and sold up in 2017, so I haven't included them.
BP does more transfer of assets with other companies than the other three companies, but overall the net result is about even.
Chevron has recently increased gas production, through LNG projects, well ahead of any reserve gains. Oil production has fallen slightly.
Overall, though, its production and reserve holdings have been least affected by this century's price swings than the other three companies presented here.
Before 2009, oil sands production (bitumen and synthetic crude) was included in the C&C numbers and, from what I can see, reserves were not counted anywhere. Shell and Exxon Mobil provided enough information in earlier years to be able to back out the numbers but Chevron does not, so the added reserves appear as a sudden upward revision from zero in 2009. Chevron left the oil sands business in 2017.
Chevron had been fairly successful at maintaining a healthy replacement ratio without reverting to the chequebook, but reserves started to drop in 2017, possibly explaining its interest in buying Anadarko, where it dodged a bullet, but it made a big purchase of Noble assets last year, which only slowed rather than reversed the decline.
Exxon Mobil has done well on the crude side for production, R/P and R-R, but has the worst performance of the four (maybe equal to Shell) for gas.
The latest downgrade to Exxon Mobil's oil sands reserves means that little of that remaining is profitable at 2020 prices with R/P now at only around four years. For oil sands, especially mining based, production does not fall off as reserves deplete, so I guess unless prices rise and stay high the operation would have to be shut down by mid-decade. The assets were massively downgraded in 2016, restored in 2018 and then cut by even more in 2020. Replacement ratios are off scale but oscillated between 3000% and -3000%. In such volatility, it is difficult to see how shareholders will allow any future capital development. Like the other super-majors, Exxon Mobil has kept crude replacement ratio at almost 100% (but now falling) but for natural gas discoveries have been much lower and falling faster and last year showed a notable write-down, mainly in shale gas.
There's a theory that countries and companies build their biggest skyscrapers at a peak just before a collapse (e.g. the Empire State building preceding the Great Depression). Exxon Mobil opened a huge central campus north of Houston in 2013/2014 (not a skyscraper but low-rise buildings over a large area), which corresponded with its recent peak in proved reserves. Reserves are likely to be further depleted by divestment of holdings in mature basins like the GoM and the North Sea.
Shell has managed to maintain production but R/P numbers are now falling quite rapidly, although maybe less so for crude.
Organic replacement ratios have all been falling steadily and for crude and natural gas have consistently averaged below 100%, and last year both were negative.
Overall, Shell's reserves seem in the worst shape of the super-majors (although Exxon Mobil's impairments in 2020 after years of stonewalling were pretty dramatic) and have shown accelerating decline since 2016, and I think it is still in the mood to clear debt through dispositions. This possibly explains why it has been so keen to switch to renewables and promote peak oil expectations. Last year, it wrote off gas assets as economic revisions but also had some disappointing results from new fields in the GoM. Its oil sands reserves were little affected because much had been sold off and the rest had been downgraded after the 2015 crash and never reinstated (I'd guess because of the pervading price volatility).
Combined Reserves and Production
The reserves shown are the current annual remaining reserves plus all production since 2006. As assets reach end of life, these would normally show creaming behaviour (i.e. tending towards an asymptote), but since 2018 the combined value has been falling due to impairments and sales by the four companies. To put this in context, the production shown at 5 Gboe is around 8 to 9% of the global total.
Total hydrocarbon production had risen slightly over the period until 2019 before falling last year. A constant production with falling reserves results in accelerating decline in R/P and in a short time something has to give. Either the reserves have to increase through some large discoveries (unlikely given their recent dearth and current drilling demobilisation) or reserve revisions (requiring prolonged high and stable oil prices as necessary but probably not sufficient) or production is going to drop.
Possible future posts
SEC filings are now required to be available as Excel files and in the past most majors and large US companies have opted to do so, which makes extracting and manipulating their data relatively straightforward. However, that is not the case for smaller firms in the US and non-majors overseas, especially non-European and non-Canadian, so I'm not sure how much of the following I'll be able to do. Canadian firms are interesting because they publish figures for probable reserves, although much of their reserves are bitumen and have different characteristics than conventional oil and gas; and the frac'ing companies' responses to the price crash are worth scrutiny (plus the EIA issues reserve data for each basin). If nothing else, I'll be able to show overall changes to the developed and undeveloped reserves for the last decade for the largest IOCs and independents.
Part II - Reserves for Canada
Part III - Reserves for Shale Oil and Gas
Part IV - Reserves for Other IOCs and Large Independents
Editor's Note: The summary bullets for this article were chosen by Seeking Alpha editors.