Savannah Energy Share Chat (SAVE)

happysparrow- have a look at PRD and DELT as well. You might see similarities with TXP/PANR.

DYOR

No malice that should read. doh :)

Sorry for off topic but I noticed you were in JSE happy, I am dumfounded re the current price v revenue and see little risk even with current and previous oil price - seems a no brainer ?? happy for your thoughts . So as not to cross boards happy to read on JSE board

My posts are light hearted towards to with malice. We are all here and elsewhere to hopefully make a few. All the best with your investments but don’t leave it too late to get back in as I believe SAVE and VOG are worlds apart but that’s just opinion :)

Thanks, Mr B - what's really not good for my health is this bloody stupid lockdown - I should be out in the tropics right now.
With SAVE I trade in and out currently (currently out), but really planned to build a bigger holding here come Summer - waiting for stronger confirmation on trade receivables first, and perhaps getting closer to Niger progress. Too, I'm hoping my TXP, PANR, JSE, and yes, VOG, will all come in big in the next 6 months, so some of that should go into SAVE then (if I've not missed the boat here - with my luck, I often do).
I know we joke about it, but the VOG business is really very close in concept to Accugas and thus you should all here understand the problems and possibilities more than most; and I think it's worth reading some of the last few days posts there on LSE VOG (could easily go up 3 times in the next 6 months imo - but high risk). Still, no point plugging it further... lead a horse to water and all that.
Meanwhile GLA on here, hope it comes in for you, with or without me.

Thanks Mr. B.

Includes SAVE.
http://www.proactiveinvestors.co.uk/register/event_details/325

Happy stop wasting your time on VOG it’s not good for your health :)
Concentrate on SAVE after all you are invested, are you not ? :)

Another great start to the week :)

I put a post just now on the VOG board about 7E liquidation that may be of interest to some (also mentions PANR). Posters here are probably in a better position to comment (perhaps put replies on the VOG board?).

energy prices on the move should be much higher

https://financialpost.com/pmn/business-pmn/nigerias-president-approves-set-up-of-2-6-bln-infrastructure-firm

Pt 6

Which finally brings us back to the bullish demand story for US natural gas. Given the
severe imbalance between global LNG demand and supply, we believe that demand for US
LNG will remain robust and that present export capacity (approximately 10 bcf/day) will
operate at near 100% capacity over the next several years. Also, the US has almost 5 bcf/d
of LNG export capacity that is fully permitted and now under construction. The new Calcasieu
Pass LNG project is expected to come online with 1.4 bcf/d in 2022. Tellurian’s Driftwood
Project (stage 1) is expected to come online in 2023 with 1 bcf/d of capacity, and
Exxon’s GoldenPass LNG project is projected to come online with 2.5 bcf/d of capacity in
2025. Our modeling shows that strong growth in US natural gas supply has come to a halt
and that the demand created by LNG exports, including another 4–5 bcf per day in additional
expansions in the next five years, means that, gas could very well trade at a BTU equivalent something the US gas market hasn’t seen in over 12 years. At $50 per barrel for oil, this would translate to a $8/mmbtu gas price, almost 3 times higher than the $2.70 per mmbtu price at which gas trades today.

Pt 5

And then there is India, a country that we have highlighted over the last several years in our
various energy discussions. In the last 10 years, due to rapid economic growth and its surging
coal consumption, India has developed a severe pollution problem. Much like China, India
has expressed its strong desire to aggressively increase its natural gas consumption. Natural
gas consumption represents only 6% of India’s energy mix (coal represents 55%) and, like
China, India has announced a plan to push natural gas to 10% of their energy mix by 2025,
and to 15% in 2030. In order to accomplish this, the Indian government is now investing
$60 bn to build out its pipeline infrastructure and its ability to import LNG. India has six
LNG import terminals in operation today with four additional terminals scheduled to come
online by 2023, bringing LNG import capacity to almost 8 bcf/d, very much in line with
our modeling of what will be needed.
At present, India is consuming approximately 6 bcf/d of gas: domestic gas production
amounts to 3 bcf/d while 3 bcf/d of LNG fills the gap. Because India is surrounded by hostile
neighbors, it imports no gas via pipeline and has no plans to do so in the future. If energy
consumption in India grows at 3% per year for the next five years and natural gas use reaches
10% in the energy mix, India would consume almost 12 bcf/d of gas. Given the lack of exploration
success in the KG basin off the east coast of India, we believe that Indian gas production
will only increase by at most 1.5 bcf per day by 2025 to 4 bcf/d. LNG imports will have
to rise to 8 bcf per day (up 3 bcf/d from today) in order to fill the gap between demand and
supply. Given India’s historical problems of pricing natural gas and its lack of infrastructure,
this huge increase in LNG import will be hard to achieve in the next five years, but it shows
that the pressure is on.
If our modeling is correct, we project that China and India together will consume almost
75% of all new LNG supply in the next five years. Outside of China and India, the pressure
to increase natural gas consumption in the developing world remains intense. In the OECD
world, gas consumption represents 28% of the energy mix, and coal represents only 14%.
In the non-OECD/non-FSU world (the FSU is unusually gas dependent given its abundant
domestic resources), natural gas consumption represents only 18%, and coal consumption
represents 40%. Given the rapid economic growth in the non-OECD/ non-FSU world and
its desire to shift from coal consumption to natural gas we expect demand to surge. Our
modeling tells us that if total energy demand grows by 3% per year and natural gas goes
from only 18% to 20% of the energy mix, then gas consumption will grow by 70 bcf/d from
205 to 275 bcf/d by 2025. Most of this gas will have to be supplied by LNG overwhelming
the 40 bcf/d of new expected supply.

Pt 4

Our modeling assumed China’s domestic natural gas production would double—going
from 10 bcf/d to 20 bcf/d, while pipeline imports from Turkmenistan, Myanmar, and Russia
would grow from 2 bcf/day to 13 bcf/d. The deficit between demand and land-based supply
would need to be filled by LNG imports which would grow from 2.5 bcf/d in 2013 to 17
bcf in 2020—a surge of 14 bcf/d.
Looking back, many of our assumptions were off, but the direction was correct. Total energy
consumption in China only grew 4% annually during that period versus our modelled 6.5%.
Much of the shortfall can be explained by the Trump-related trade war. Natural gas consumption
increased to only 31 bcf/d versus our modelled 59 bcf/d, but domestic gas production
and pipeline imports both significantly disappointed as well. Domestic production hit 18
bcf per day and total pipeline imports hit only 4.6 bcf /day—a significant shortfall versus
our modeled 13 bcf/d. LNG imports have now reached 8 bcf per day, representing 8% of
China’s energy mix. However, even with our overoptimistic modeling of demand, China
itself has consumed over 60% of the increase in global LNG supply over the last seven years.
Looking forward, China’s LNG importation numbers could be huge. If total energy consumption
only grows by 3% over the next five years, and if China hits its goal of 15% gas penetration
of its energy mix, consumption will hit 65 bcf /day in 2025—up 35 bcf/day from today.
Given the slowdown now taking place in China’s domestic gas production (a combination
of slowdown in conventional production and disappointing shale gas production) we calculate
Chinese supply will only grow 3 bcf /day reaching 21 bcf/d in 2025. Ramping up
Gazprom’s pipeline gas from Eastern Russian by almost 4.9 bcf per day by 2022 and completing
pipeline “D” from Turkmenistan will add an another 3 bcf per day of new pipeline supply.
Given these expansions, we believe pipeline supply of natural gas will grow from 4.5 bcf/d
in 2020 to over 12 bcf/d in 2025. However, even given these large expansions, the gap between
Chinese consumption and its land-based sources of supply will grow considerably wider. By
2025, China will have to import over 30 bcf/d of LNG to satisfy internal demands, an
increase of 22 bcf/d from 2020 levels. The global LNG industry is planning on adding almost
40 bcf/d in new liquefying capacity by 2025, and, if our modeling is correct, China will
consume over 50% of this new capacity.

Pt 3

Back in 2013, we modeled the 40 countries that had or would have LNG import capabilities
by 2020. Based upon the historical relationship between natural gas consumption and
per capita GDP, we estimated that total theoretical global demand for LNG would grow
from 32 bcf/d in 2013 to over 70 bcf/d by 2020, an increase of more than 40 bcf/d. Back
then, most analysts believed that achieving these consumption figures would be impossible
because of the lack of re-gas infrastructure. Announced additions to re-gas capacity made
back in 2013 indicated that total global re-gas capacity would grow by 20 bcf per day—to
approximately 52 bcf per day in 2020—just barely covering planned supply expansion.
However, our modeling back then told us that over the next few years the perceived bottleneck
in re-gas capacity would be resolved through the building of additional import re-gas
capacity. Our research led us to believe that analysts were making a common mistake: they
assumed infrastructure would drive demand, whereas historically we had witnessed just the
opposite. Increased demand, here led by the desire to change the fuel mix away from coal
to much cleaner natural gas, would drive the aggressive construction of new re-gas infrastructure.
This is indeed what happened. Between 2013 and 2020, total global re-gas import
capacity grew by almost 50 bcf per day to reach close to 90 bcf per day of total re-gas
capacity—80% greater than estimates made in 2013.
Back in 2013, we modeled that available LNG would increase from 32 bcf to 57 bcf per day.
LNG supply in 2019 reached 47 bcf per day. Since the global LNG industry operates at approximately 85% of capacity, this production number was very much in line with our
2013 modeling. Given our robust demand projections that far outstripped supply (40 bcf
per day in modelled demand versus approximately 20 bcf per day in new supply), we believed
that the global LNG would remain in structural deficit, not structural surplus.
Using China as a case study, it’s easy to see how the global LNG market absorbed the surge
in supply between 2013 and 2019, and why the structural deficit in the LNG market will
only become more severe as we progress through this decade.
Back in 2013, we modelled that China’s total energy consumption would grow 6.5% for the
next seven years. In 2012, the natural gas consumption represented less than 5% of China’s
total energy mix versus 17% in South Korea, 13% in Taiwan, and 21% in Japan. China back
then was literally choking on its coal-related air pollution leading the government to announce
plans for natural gas consumption to reach 10% of the county’s energy mix by 2020. Using
these projections (which were very much in line with our models), we predicted China’s
natural gas demand would grow 19% per annum, going from 15 bcf/d to 50 bcf/d by 2020—a
staggering 35 bcf/d increase.

Pt 2

In retrospect, we know this bearish outlook for LNG prices was wildly off the mark. Long-term
contract LNG prices did not break from their oil-priced BTU link, and spot LNG prices
(except for the brief period between March and September 2020 when COVID-19 intruded)
never traded significantly below $5 per mmbtu. In the seven years since 2013, even in the
face of a 50% increase in LNG supply, all new LNG supply was effortlessly absorbed into the
market at prices that indicated no market surplus. Both long-term contract prices and spot
prices tracked closely to the BTU price equivalency of oil. In fact, in response to a cold snap
in Asia back in the beginning of January 2021, global LNG spot prices traded at the highest
levels ever. The widely followed JKM ( Japan/Korea Market) LNG spot price hit a record
$32 per mmbtu. On a BTU equivalent basis, this contract should be worth only $8 /mmbtu.
Where did all the experts go wrong in trying to predict the future outlook for LNG prices?
The answer is simple: the experts woefully underestimated the demand for natural gas,
primarily from emerging market countries.
In previous letters, we have often talked of the S-Curve’s impact on the intensity of commodity
consumption in emerging market economies. According to our research, no commodity is
more influenced by S-Curve factors than natural gas. Natural gas is an extremely clean,
highly desirable fuel, albeit one that is very expensive to use.
Natural gas’s biggest problem is that it’s neither a solid nor a liquid, but rather a gas. Large
transportation and storage investments must be made for natural gas to make significant
inroads into a country’s fuel mix. By comparison, fuels such as coal are easily transported,
handled, and stored, needing little in the way of expensive infrastructure. Because the burning
of coal severely degrades the environment, although it is cheaper to use, it is a far less desirable
fuel. It is easy to understand why emerging market economies rely primarily on coal for
both heating and electricity generating needs while affluent industrialized economies prefer
natural gas.

Relevant excerpt from the link on LNG follows. Though would also recommend reading their commentary on oil

Pt 1

As already mentioned, we remain very bullish on US natural gas prices, primarily because
of rapidly slowing US production. There are other important reasons for believing North
American natural gas prices have entered into a long -term bull market as well: the increasing
demand for US LNG exports.
The US only began exporting LNG in 2016. Since then, exports have surged as five LNG
export facilities have come online. The US today has 10 bcf per day (almost 20%) of LNG
export capacity. Given our modeling of LNG demand, and extremely low gas prices here
in the US, we believe this export capacity will continue be fully utilized over the next five
years. Furthermore, 4.0 bcf/d in new export capacity is currently under construction with
an additional 25 bcf per day in new initial-phase projects in various states of approval by the
Federal Energy Regulatory Commission (FERC).
Because of the Biden administration’s adverse attitude towards hydrocarbon development
projects (the just-announced cancellation of the Keystone XL being a good example), we
don’t know how many of these new projects will go forward. But the demand for this LNG,
according to our modeling, will be there as we progress through this decade. Even if just a
small amount of this new LNG capacity is built, this will have extremely bullish implications
for pricing in the US natural gas market.
Back in 2013, we updated our models for LNG supply and demand. Energy analysts who
followed LNG markets back then were incredibly bearish regarding the LNG pricing. Led
by huge project expansions in both Australia and Qatar, LNG supply was scheduled to
increase by almost 50% in the next seven years. Long term demand for LNG was poorly
understood and improperly modelled. Everyone expected LNG prices to experience serious
weakness as strong supply overwhelmed weak demand.
Historically, almost all LNG production was priced under long-term contract with the
LNG prices linked to the price of oil. However, by 2013, a significant spot market for LNG
had developed. Given the surge of new supply without a corresponding increase in demand,
consensus thinking believed the long-term BTU pricing link with oil was about to break as
spot LNG cargoes effectively flooded the market without being able to find a home. Many
analysts believed spot LNG prices (which averaged $15/mmbtu at the time) would fall to
Qatar’s marginal cost of supply which was approximately $1 per mmbtu.

' Article in BusinessDayNG on reforms to the power sector bearing fruit

Latest market data shows the power distribution companies collected N65 Billion from the tarrif they charged last month, the most since inception.'

(Approx $170m)

Would thoroughly recommend extensive reading of the thought provoking reports these guys publish.

http://info.gorozen.com/goehring-and-rozencwajg-commentary-confirmation-page-4q-2020?submissionGuid=7ac5caa3-8d0d-49bd-9468-2b1c8b82c748

https://www.ft.com/content/27086ad8-bc84-4e2e-9195-91880fa6916f

3 early trades for a total of under £10 pounds
Yes I admit they were mine I decided to double my holding.

https://www.completesports.com/nigeria-ekuta-qualifies-for-judo-at-tokyo-2021-olympic-games/

https://guardian.ng/news/akwa-ibom-woos-u-s-government-on-deep-seaport-project/

Hee hee :-)

Excellent post as always zen , aj changed tact slightly with his comments on some interview a while back regarding the Niger farm out .
Along the lines of industry partner or an investment company. Never mentioned an investment company before .Seems to go along with your line .
Lots of mid cycle assets majors are looking to offload right now , that just don’t have the scale of production that the big boys require.
I believe it’s a wave of opportunity right now worldwide that was seen in the North Sea 10-15 years back allowing smaller companies get some world class acreage relatively cheap then going on to make substantial size companies.
I wouldn’t be surprised to hear that save were looking at 2-3 of these types of deals