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The NOG guidance for 2020 remains at 19.0 kboe/d of sales.

NOG reported average January sales of 23.8 kboe/d, average Q1 sales of 22.9 kboe/d and average H1 sales of 22.6 kboe/d.

Therefore, it is a trivial exercise for anyone to calculate the expected December 2020 sales rate, which will be ±12 kboe/d.

That means a ±50% per annum decline rate for 2020.

Previously, the sales decline rate has been around 30% per annum, so, according to NOG’s own reported sales volumes and published 2020 guidance the decline rate is accelerating.

Game over.

The NOG guidance for 2020 is 19 Mboe/d (or kboe/d, as preferred).

It is trivial to calculate that that represents a ±33% per annum decline in 2020. This means production at YE 2020 of =15 Mboe/d. As half the production is gas, it will be at limit that the two smaller gas trains can operate. So, by 2021 gas production can be expected to end and so will LPG and condensate production. Only oil production will be left and based on past product splits will be ±2 Mb/d, and declining.

Put the 2020 guidance production into a simple cashflow and NOG needs an average 2020 Brent price of ±$39 to end the year with zero cash in the bank. The message is clear.

As early as late 2017 the company had two options, 1) Rat’s wheel: spend $s drilling, and try to arrest production decline, or 2) Stop all activity: have a party on the $s in the bank until we are broke. It took them until the end of 2019 to change from 1) to 2).

And indeed a ‘party’ there is. The ex-CEO left in December with a package of $1.4 million, as thanks for building the GTU white elephant and destroying 99% of shareholder value. It has to be said, in all fairness, that does take a certain skill.

The Chairman in the annual report is smiling. He should be, he took $500,000 overseeing this exceptional performance.

To boot the NOG Board confirms NOG’s imminent demise in the conclusion of their 2019 Annual Report’s Viability Statement!

The 1.1.2019 reserves report is finally out. The 2P reserves are reduced by 66% to 138 MMboe. In my post of 21.05.19, my prediction was that the best the 2P reserves volume could be was =120 MMboe. That was very close and they are probably overstated even now, after this massive revision.

Currently, the cash in hand is just $65 MM, and production decline continues.

On 01.02.19 I predicted that the company would experience negative cashflow in 2020, with zero cash and a debt of $1.1B at the end of 2020. And so it will be.

There is zero 3rd party gas, that is ZERO, in the vicinity of Nostrum’s operations. Yet another piece of misinformation from the NOG Board. So, the entire plant of 400 MMscf/d of capacity will have to be mothballed in 2021. End of story - lights out.

Exactly as expected.

Referring to my previous posts (see dates below) the summary remains unchanged:
• Production continues to decline, as NOG acknowledges (with no solutions proffered)
• Gas production <70 MMscf/d and falling, only 1 train (either GTU-1 or -2 required), as predicted in January
• There are/will be zero reserves in Trident/Stepnoy Leopard as, by definition, these resources can only be Contingent Resources, which have zero value
• Operating cash position expected to be negative during 2020, with >$1B of debt, as stated previously
• Chinarevskoye reserves must be overstated, as stated earlier, and by definition would fall to zero at the time the bullet immediately above transpires
• GTU-3 takes gas production capacity to 400 MMscf/d, so
• GTU-3 is redundant - in fact a white elephant that shareholders paid for
It takes a special kind of skill to destroy 97% of shareholder value in 5 years, which can be expected to reach 100%
Schlumberger can not be expected to salvage this situation.
No-one can be expected to buy this company, and certainly not a major.

Previous post dates: 18.12.18; 2.1.19; 21.5.19; 31.7.19

NOG’s Q2 operations report shows half-year sales of 29.2 Mboe/d. However, based on the Q1 average sales rate this Q2 result implies an end of Q2 rate of ±24 Mboe/d. That equates to ±25% decline from the end of Q1 to the present. All earlier conclusions stand, other than that the bondholders should be seriously concerned by the announcement of a sale of NOG.

Stepnoy Leopard was discovered in the ‘60s and drilling continued into the late ‘70s. At that time the Soviets discovered the Karachaganak field to the east with ±50 Tcf, and they never went back to Stepnoy Leopard as it was uneconomic. These 9 fields stretch in an E-W line stretching 100 km to 160 km from Chinarevskoe (see SPE 36635, ’96). The key issues are: all fields have different fluids, typical field H2S is ±2% (this is a great deal) and distance to Chinarevksoe. Like the Trident fields, if the latter and Stepnoy Leopard can ever be proved to be economic and funding secured, production is up to a decade, or possibly more away.

No, numbers are correct. m=k in oilfield units. Interchangeable.

Indeed. GFI. The question, based on their performance, is: how long will they last? 12 months? 18 months?

Finally, revisiting the NOG’s financials: cash in hand reduced by $5 MM at the end of 2018 compared to 2017. During the 1.4.19 analysts’ conference call NOG confirmed a long-term 10% production decline, along with debt repayments of $85 MMpa. A cashflow analysis with the former decline assumption (bearing in mind the ±30% underlying production decline of the majority of wells), a similar activity level as now to maintain that level of decline, with an oil price of $65, NOG would have zero cash surplus and $1.1B of debt in 2020, with negative annual cashflow thereafter.

What is the conclusion? <20 MMboe of further CKE production could signal the end of NOG’s economic operations.

Some additional analysis since my 1.2.19 post when NOG’s share price was 133p (ie ~2x that of today).

In Q3 2017 NOG’s guidance for 2019 was 90 Mboe/d. Their guidance today for 2019 is 1/3rd of that. Since 2014, the period that shareholders were funding GTU3 NOG would appear to have been providing exaggerated production guidance.

NOG’s reserves claims have always seemed doubtful for a variety of reasons for any industry professional, not least because of the low depletion rate (annual production divided by total 2P reserves ie Proved + Probable). For the 5 years prior to 2018 NOG’s total 2P reserves have been ±500 MMboe. Even at their best daily rate of ±50 MMboe/d that would represent a depletion rate <4% pa (ie very low). It is also notable that NOG stopped publishing its reserves report after the 2012 report, until now. A 4-year blank. Why?

The 30% pa decline rate in production across 2017+2018 has forced the issue on reserves reporting and reserves have been reduced at 1.1.19. The total audited 2P reserves in NOG’s 2018 Annual Report (AR) are purportedly 410 MMboe. However, the Ryder Scott (RS) reserves report 1.1.19 states on the 3rd table on page 5 that the total, net NOG 2P reserves are 362 MMboe. That is 13% less than stated in NOG’s AR.

Further, NOG continues to claim that the Trident fields hold 166 MMboe of Probable reserves, with zero Proved reserves reported. The requirements to define a hydrocarbon resource as reserves are strict. Commerciality has to be demonstrated (i.e. well rates), a development plan needs to be defined and then approved, etc. In the case of Trident a 3-phase, sour fluids, 100 km pipeline (complex & costly) would be required and would require some 3 years for planning, approvals and construction. None of the latter are remotely evident in any of NOG’s reporting. Moreover, a development with zero proved reserves is a non-sequitur. One can only conclude that the Trident resource is in reality a contingent resource (i.e. 2C), which has effectively zero value. How is that RS were persuaded to categorise ‘reserves’? Good question.

In that case the reported total 2P of 362 MMboe would be reduced to 196 MMboe (ie 50% of NOG’s reported 410 MMboe).

However, that is not quite all. Production at Chinarevskoye (CKE) began 14 years ago in 2005, >75 wells have been drilled, >100 workovers have been carried out and total production stands at ±130 MMboe. By any standards CKE can be considered to be a mature field, and such fields would typically be expected to have a difference between 1P and total 2P reserves of =30%. If we assume that CKE’s 1P reserves might represent ‘solid ground’ then that would be RS’s net 1P volume of 86 MMboe (not NOG’s reported number of 98 MMboe). One would then arrive at an expected, theoretical total 2P of =120 MMboe for CKE.

Finally, revisiting the NOG’s financials: cash in hand reduced by $5 MM at the end of 2018 compared to 2017. During the 1.4.19 analysts’ conference call N

To recap from December and January posts: 30% pa straight-line production decline established since December_16, small up-tick in production in Q3_18; expect one gas train only required within 2019 as gas rate dips to <80 MMscf/d; cashflow forecast with ongoing decline and realised product price would have NOG with zero cash + net debt of $1.1B around 2020, with obviously negative cashflow henceforward.

Extracting the quarterly production from the Q4 results reveals that, while Q3 average production increased by 600 boe/d wrt Q2 (the up-tick), Q4’s average production decreased by 1000 boe/d wrt Q3. That is a decline of 9% pm and implies December average sales production of just ±24 Mboe/d (with gas of 70 MMscf/d). The Q4 data in effect re-establishes/re-confirms a ±30% pa underlying, longer-term production decline.

In summary:
• The underlying, steep decline of the 45 producing wells appears to continue (NB only ±500 Mboe/d/well on average in December)
• The new production of Q3_18 appears to have reduced to effectively zero, which suggests production from most of these wells/zones has not been sustainable (noting that well 40 was closed-in)
• There is a new up-tick in production reported for January. The question is: will this new ‘January_19’ production decline away as rapidly as observed for the ‘Q3_18’ production increase?

There appears to be no reason to alter: a) the previous end of decade cashflow assessment, or b) the expectation that a single, existing gas train only will be required within 2019.

GTU-3? As appears to have been evident for a considerable time: redundant before completion. $550 MM of shareholders’ funds for what?

Undoubtedly, short-term trading has the potential to deliver +ve returns. There is always going to be a group that believes ‘it can’t be as bad as that’. So, buying on a low, as at around the turn of the year, for example, can work. However, in the end this is a bet on investor psychology, not related to the future performance of NOG’s business as implied by the current performance.

Spot-on wrt the guidance since NOG’s listing in mid-2014. NOG’s listing price was 780p. Based on share price alone that represents value destruction of ±90% as we stand today.

Guidance since listing has indeed been bullish and not delivered upon. For the first time in the Q3 2018 report, there is no production guidance, which has to be ominous. As per my 18th December post, an ongoing base case decline in the range of ±30% pa would be sensible for forecasting, in the absence of any demonstration of a better production performance.

NOG reports boe production. The reported sales gas + liquids has consistently been split around 50/50 over time, and gas is currently reported as 47%. For current and near-term sales of ±30 Mboe/d, ±14 Mboe/d would be gas. That is equivalent to ±80 MMscf/d.

As NOG reports, the combined gas throughput for GTU1+2+3 will be 400 MMscf/d. Of that 240 MMscf/d is GTU-3, with GTU1 and GTU-2 each capable of processing 80 MMscf/d. In other words, somewhere in 2019, it can be expected that only a single gas train will be required at Chinarevskoye (i.e. either GTU-1 or GTU-2). As such GTU-3 would not be needed in the foreseeable future.

In the Q2 2018 analyst teleconference in August NOG reported the agreement signed with UOG covering treatment of up to 50 MMscf/d of UOG gas via NOG’s plant. This is a trial production for a volume that represents =12% of NOG’s 3-train capacity. Further, the MOL Group (Hungary) is a partner in the UOG field and quotes 1st gas only in Q4 2020. At best, assuming UOG’s trial production works for at least a period of time, this small gas volume could help to maintain a single gas train (GTU-1 or GTU-2) operating. However, only if NOG were a viable entity by the end of the decade.

All in all, it would seem that there is a significant probability that GTU-3 may never be required.

Equally, it would seem that analysts have been blind to these basic, publicly available fundamentals.

Seems pretty simple and not specifically related to oil price. Production decline analysis since Q1 2017 to mid-2018 implies a straight-line ±30% pa decline, based on the quarterly reports. There was a small up-tick in Q3 2018 with some new production from a few wells, but that underlying decline trend of the 40-odd producing wells should still be present. Using the realised product price and the annual accounts and assuming a base/worst case production decline of 30% pa would suggest a -ve cash scenario is possible around the end of the decade with $1B of debt. Somewhat more troubling is that so many analysts have had it as a ‘buy’.