Potential Xcite valuation

I am posting Gramacho's excellent post below from the iii.co.uk Xcite bulletin board which has a thorough analysis of the potential valuation of the company. Great piece of work!

I dare say following Oilbarrel you are all suffering a bit of post meeting minutes fatigue by now. This post attempts to provide insights from what was said in relation to guideline reserves and potential value. It contains quite a bit of info and analysis so you might want to read it a couple of times. The following is IMO and of course is based on publically available information.

BENTLEY VALUE BASED ON M&A ACTIVITY
Although C L-C did say there is room to double or triple the share price just in Bentley alone, i.e. excluding the exploration upside, he did not directly say this would be in the next 12 months. He made a joke about a 2 – 3 fold increase being adequate after 800% and 700% increases in 2009 and 2010. He also talked about “moving down the line” in the next 12-18 months.

I have no doubt there will be a significant increase in sp in 2011 as contingent resources in the core area of the field are moved into the 2P category. The example in Slide 5 of the presentation shows XEL valued at $4.65/bbl based on a sp of £3.80 and the guideline estimate of 200 mmbbl contingent resources. C L-C used Sinochem’s purchase of a 40% stake in Statoil’s Peregrino heavy oil field (13 API) in 2010 as an example of what Bentley’s reserves could be valued at. The deal was estimated by analysts to be worth over $15/bbl to Statoil.

Whenever anyone mentions valuing reserves at $ X/bbl and then goes on to use this figure to value an asset or company it is important to realise that there is a huge simplification in doing so. Clearly 200 mm bbl reserves that have a full production facility in place are worth more than 200 mm bbl reserves that require $2 Bn to be spent on facilities before the reserves can be accessed. (This is where a DCF analysis with good quality cost input provides more insight into forward value.)

So what’s the story with Peregrino? The field will be developed with wellhead platforms and an FPSO to process and store the crude. A key point here is that the 1 Bn Euro FPSO is being leased by Statoil (from Maersk). This makes a $/bbl bid figure less dependent on the timing of the bid within the construction phase than if the FPSO was being purchased and being paid for. Sinochem will pay for their WI share of the FPSO contract costs via lease payments commencing on production start up (there will be a mob fee too). In other words, from Sinochem’s perspective, a large component of the total development costs, the FPSO, is yet to be spent even though the deal was done in the year prior to startup. Nevertheless Peregrino was still worth more than $15/bbl to it.

So would the Bentley field also be worth $15/bbl to Sinochem or another NOC and when would that be the case? There are a number of aspects to consider.

Firstly is the size of Bentley reserves of similar strategic significance to Sinochem and other NOCs as Peregrino? If Bentley P50 is in the range 200 – 225 mm bbl then its reserves would be about half those currently attributed to Peregrino. Its relative importance would then depend on whether the deal with Statoil contained rights to purchase Statoil’s 60% production stream from Peregrino. Statoil has large downstream interests and has announced refining projects in Brazil and is a leader in upgrading heavy oil. Hence it is likely Statoil believes it can add value to its Peregrino crude and it would be reasonable to assume it has elected to retain control of its share, particularly as there was no mention of Sinochem rights to purchase Statoil liftings in the coverage of the deal. Without this Sinochem would have rights to 120 – 240 mm bbl crude (field total reserves range is 300 – 600 mm bbl).

XEL on the other hand has no downstream interests. Rights to all the 200+ bbl of Bentley crude would put Bentley on par with Peregrino. However there is an agreement with BP that it markets the crude. The agreement incentivises BP to minimise the discount to Brent so whether this agreement would prevent an NOC structuring a deal to secure XELs share of production is uncertain.

Hence Bentley has the potential to rank alongside Peregrino from an NOCs security of supply perspective but existing commercial arrangements may or may not restrict its potential to do so.

BTW the above discussion is based on the assumption that the Peregrino figures refer to P50 (2P) reserve estimates. In my experience when a field’s reserves numbers are discussed and when analysts estimate production profiles to value a field they are based on the proven + probable reserves. XEL has also made this assumption as shown in slide 5 of the Oilbarrel presentation.

Secondly does a comparison of the fiscal regimes between Brazil and the UK support the view that a strategic UK asset in the development phase could also command $15/bbl? The answer is yes.

The three main elements of the Brazil fiscal regime are Royalty (10%), Special Participation Tax and CT (34%). SPT is a tiered tax with multiple rates at various production levels and varies by year until year 4+. Peregrino will plateau at about 100 k bbl/d. It turns out that the marginal rate of tax at this rate and down to 83 k bbl/d is 50-55%. In addition there are other indirect taxes that can increase the state take.

In contrast in the UK there is no Royalty and CT is 30%. Although there is a 20% Supplementary CT charge, a large element of SCT relief was granted to promote the development of heavy oil fields. My calcs suggest Bentley would pay very little SCT during the first 6 years of full field production by which time almost 60% of the reserves would have been produced taking into account the FPS production. Hence a marginal rate of tax of only 30% is applied to over half of the reserves.

The third aspect is whether development costs would prohibit Sinochem et al from offering $15/bbl for Bentley. A comparison of development costs between Bentley and Peregrino is tricky without access to proprietary cost information and it is easier to assess this by reference to a project economic model. As inferred earlier in this post a DCF model has been set up for a nominal 200 mmbbl case. Cost and profile input is quick look with a view to not being overly optimistic. (It could be more sophisticated but that can wait until an updated CPR is released. In the meantime it draws on the 2009 CPR info and experience.)

NOCs have the financial latitude to base acquisitions on a lower discount rate than the 10% commonly used by oil majors and independents. Goldman Sachs noted that the Peregrino deal was one of the most aggressive to date and estimated it was based on a discount rate of about 6% whereas many NOC deals are done at a 7 or 8% discount rate.

The model is summarised below, figures in brackets are the 2009 CPR 166 mm bbl case.
Reserves: 200 mmbbl (166)
Peak Rate: 60 k bbl/d (64)
Full Cycle Capex: $3.0 Bn ($2.7 Bn note not clear if 2009 CPR includes FPS costs)
Main Production Phase Capex: $2.7 Bn excluding P&A costs
Opex: $3.0 Bn ($2.2 Bn)
Field Life: 19 yrs (15 yrs)

And economics are as follows:
Brent Oil price: $80/bbl flat real ($80/bbl flat real)
Bentley discount 12%
NPV10 1/1/12 $2283MM ... “This will be a $2Bn company” ($1535MM)
NPV10 1/1/12 $11.5/bbl ($9.3/bbl)

I believe the CPR pre-dates the introduction of the heavy oil supplementary tax allowance in June 09 so this explains the higher NPV10 in $/bbl terms for my model. Also it is not clear if the CPR is full cycle or main development only.

The Bentley NPV6 is $3410MM or $17.8/bbl which is slightly higher than the $15.4/bbl ascribed to the Sinochem Peregrino purchase (slide 5 Oilbarrel presentation) and sugges Bentley could indeed support a bid based on $15/bbl. (DCF calculations assume NOC does not need to pay finance interest costs.) Note the above NPV10 is equivalent to a sp of 930p and the NPV6 is equivalent to a sp of 1390p.

This is all well and good but it assumes XEL receives a competitive bid from an NOC for the entire 100% W.I. The NOC would then have to commit to become the field operator, with the organisational impact that would have, rather than be a non operating partner. This might be a barrier.

What if such a bid is not forthcoming? XEL would then need to consider how to get the development funded. E-type01 has raised the question of financing. He is obsessed with finance. Do you think this is because the HP company repossessed his Ford Granada lol!

BENTLEY VALUE UNDER RETENTION OPTIONS
There are several options to obtain funding in the industry e.g.
1) Issuing Equity
2) Reserves Based Lending
3) Project Finance, bank loans to be repaid from future project production
4) Farming down working interest in return for funding

1) Issuing Equity
Option 1 does not look attractive because it would involve a mega placement and massive dilution. At a current sp of about 360p XEL is valued at about $960 MM which is almost half the $2300 MM value associated with the 200 mm bbl “sale of field” case. This case requires about $2700 MM funding for the main development. Even without taking into account the discount that would be required for a placing, over 450 MM shares would need to be issued to raise this amount. The success case NPV 10 would equate to only about 245p/sh with over 600 MM shares in circulation.

2) Reserves Based Lending
In examining the other options it is important to realise that, despite its market cap, XEL is a minnow at the extreme end of the spectrum. Reserve based lending is based on production from existing wells providing the assurance to lenders that the loan can be serviced. XEL has no other assets in production to use as collateral so Option 2 does not look feasible.

3) Project Finance via Bank Loans
There will be a few wells in production following the FSP. These could amount to about 20 mm bbl proved developed reserves and hopefully 100++ mm bbl proved undeveloped reserves. Slide 4 Oilbarrel presentation indicates XEL believe the low case (roughly equivalent to proved reserves) will be 120+ mmbbl in the pre-FSP reserves assessment. Following the FSP there will be additional reserves proven by a well in Bentley East (aka Prospect A in the 2009 CPR).

Banks try to take as little risk as possible and much prefer to lend on the basis of proved reserves (1P) rather than proved and probable reserves (2P). After all there is an equal probability that ultimate reserves will be lower or higher than a 2P estimate whereas there is a 90% probability that ultimate reserves will be equal to or higher than the proved reserves estimate. The feasibility of Option 3 is therefore very dependent on the economics of the 1P reserves case.

This was examined by building a case in which the facilities are built for 200 mm bbl recovery but the reservoir only produces 130 mm bbl. Development capex for the main development is about $2450 MM (some wells omitted being uneconomic in this downside scenario). This case yielded an NPV10 of about $1000 MM i.e. it remains economic. Moreover it generates $3430 MM cash flow, i.e. 1.4x the capital requirement. Surplus cash would pay off a staged loan equal to the capex in 9 yrs at an 8% interest rate, cumulative production being about 100 MM bbl at this point.

From the above, project finance may well be feasible. TBH I do not know what level of coverage banks feel they need to be comfortable with offering project finance. They would obviously want to look at other scenarios such as low oil price, capex over run etc. XEL are obviously well aware of this and no doubt the FSP has been planned to provide sufficient confidence to facilitate project financing of the subsequent main development. Nevertheless one should realise the scale of the financing required is very large, a world scale investment is needed. The more conservative lenders will consider the risks to be quite high, because XEL has no other assets, and the risks would probably need to be spread over multiple lenders.

This route to field development produces an NPV10 of $1880 MM which equates to an sp of 770p.

4) Farming Out W.I. in Return for Funding
Finally there is Option 4. It is interesting to look at how a similar style of deal to that of Peregrino might look from the perspective of both XEL holders and an NOC.

If an NOC were to pay XELs dev costs for the main phase of development in return for a 50% equity stake this would amount to a cash injection of about $1.35 Bn for 100 MM bbl reserves i.e. the price paid would be $13.5/bbl. TBH I am not sure how to model the tax implications of this but the XEL valuation is currently modelled by assuming zero capex expenditure for the main phase. This generates an NPV10 of about $1800 MM with an equivalent sp of 740p. The deal could be sweetened to pay for FSP back costs to simulate a deal nearer to $15/bbl. As modelled this transaction is not as tax effective as it could be because there is no development capex to reduce taxable income and hence reduce the supplementary charge. If a more tax efficient deal were structured the sp equivalent would be north of 740p.

From an NOC perspective this deal appears attractive. It generates an NPV10 of $350 MM and an NPV6 of $820 MM. This is partly because the NOC is credited with the tax relief afforded by 100% of the field capex set against revenue from 50% of the field production. As mentioned above transferring some of this tax efficiency to XEL would improve the value from an XEL shareholder perspective whilst still retaining sufficient value from an NOC perspective.

CONCLUSIONS
1) Bentley Field economics, based on a development of the guideline 200 MM bbl 2P reserves outcome, are sufficiently attractive to support a valuation of greater than $15/bbl for takeover purposes. However this is a limited scenario that would require an NOC to bid with the intention of acquiring 100% W.I. and operating the field. In this outcome, if the bid was based on a 6% discount rate, XEL would be worth about 1390p/share (about 10% less on a FD basis) or 1215p if a bid was based on $15/bbl.

Since this outcome appears to be significantly more advantageous to XEL shareholders than other options involving retention of the field such a bid is likely only to come if a competitive bidding environment can be established.

2) If an attractive bid for the entire field did not transpire then XEL could develop the field and repay a financing loan with an assumed 8% interest rate even under the downside scenario investigated (Brent $80 flat real, Bentley 12% discount, facilities built for 2P reserves of 200 MMbbl but downside reservoir performance produces 1P reserves of 130 MMbbl)

The 2P reserves would generate an NPV10 equivalent to an sp of 770p.

3) The field could also be developed if XEL was able to obtain a carry of its development costs in return for farming down to a 50% W.I. This was modelled in a manner that was somewhat inefficient for tax purposes but nevertheless generated an NPV equivalent to an sp of 740p. The NOC pays $13.5/bbl for its 50% stake.

4) This analysis suggests XEL has multiple options going forward to secure more value for shareholders. The options investigated suggest the share price could double in the next 18 months.

5) Substantial upside exists from Bentley EOR, additional exploration prospects in Dornoch sands and Jurassic sands and possibly further structural upside outside the Bentley core area.


6) All of the above would explain the very high degree of confidence exhibited by the BOD members at Oilbarrel.

Having completed this analysis I am very pleased to retain my investment in XEL. IMO the outlook is excellent with the opportunity of a really good return at a lower risk than many other AIM oil companies.

I would caution that this is all IMO so DYOR. If there are any accountants on the BB it would be useful to hear your thoughts about the tax implications of a Peregrino type deal in which XEL is carried or paid their development costs in return for a stake in Bentley.

Regards and GLA,

Gramacho


Source: http://www.iii.co.uk/investment/detail/?display=discussion&code=cotn:XEL.L&it=le&action=detail&id=7635097&prevpost=7634963&nextpost=7635152

14% rise on Sirius Director share buy and plenty of news to come

Nice 14% rise for Sirius Minerals (SXX) to 21p on further buying after yesterday's York Potash acquisition and also news today that Andrew Lindsay, Chief Financial Officer and Finance Director of the Company, purchased 582,352 ordinary shares in the Company at an average price of 17 pence per share on 17 January 2011.

But the potentially big news is yet to come. The North Dakota potash drilling results and analytics are the key news that will be eagerly awaited in February. Normally after a fairly substantial increase that we've seen this week I would be tempted to "top slice" but I actually invested more in Sirius today following the news of Lindsay's purchase. If all goes to plan, and there's nothing to suggest anything is amiss, 21p will seem like small change.

Sirius looks to be being built as a major global potash producer and we're only at the start of the journey.

Xcite not that exciting this week

Xcite energy (XEL) is stubbornly stuck at a bid of 355p with a wide spread. Market makers not encouraging trades for now with price bouncing off this support. Given it's the 18th of January and deadline for rig signing is end of the month, news can't be far away. But nevertheless pretty dull. At least Sirius Minerals is still moving up with a director share purchase RNS today to 19p.

Rockhopper entry point moves closer

Falkland oilie Rockhopper (RKH) fell about 2 percent yesterday and it is down today about 6p to 366p. Looks like there's a heavy seller in the background looking at level 2. I've put in an order at 350p and I'll see what happens in the next few days. Not rushing in over 360p yet. Patience is the key for a reasonable entry point.