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1.5¢ samson oil & gas limited

Cmon & all, some good points worth considering. I've read a...

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Rob79

1,593 Posts.

6

18/12/14

02:16

Post #: 14478277

Originally posted by cmonaussie ↑

Think my calcs are about right ...

This is likely my final - but long - post on SSN (hold the cheers) as I've finished reviewing the materials and have come to the conclusion that SSN (beaten down as it is) is not a value play for me. I'll answer any cordial questions (or flames robustly - & @leverage its patience not patients unless you're planning to see a therapist).

Most of my commentary comes from the SSN AGM preso, their Qtrly and Ops review with some reference to CLR. I went back & read through all AGM meeting presentation posts. Remember of course that the meeting occurred well before the Thanksgiving OPEC massacre, with WTI at around $85 in early Nov.

IMO the real topic was danced around the perimeter. The presentation is quite clear on this.

(A) "Full cycle economics estimated breakeven is $68/Bbl"

The perspective you should be keeping is:
1. APPLY THE BAKKEN DISCOUNT of $11-$16 (that figure comes straight from CLR who I think you can all concede knows the Bakken)
2. WTI Index price SSN needs for economic breakeven FOR NEW WELLS is $79-$85 Bbl
3. Hedges - that opportunity has slipped by with WTI at $55 (currently) so committing capital to drill and complete new wells is not prudent
4. Terry Barr is right (forced?) to suspend any further new capital commitments.
5. The decline treadmill will take over and production will decrease - but you're still in the game if oil recovers quickly.

(B) "Lifting cost is $29/Bbl so existing production is economic"

The perspective you should be keeping is:

1. There is actually a legal definition for lifting costs.
http://definitions.uslegal.com/l/lifting-costs/
"The term lifting costs relates to a portion of the cost of producing oil and gas exclusive of drilling and equipping costs. However, the term defies a more precise definition. According to revenue ruling, the term lifting costs is usually considered to be synonymous with operating costs and consists of those deductible costs incurred in the production of oil and gas after completion of drilling and before its removal from the property for sale or transportation."

More detailed regulatory info is here - its in alphabetical order so scroll down to production costs.
http://www.law.cornell.edu/cfr/text/17/210.4-10

Production Costs (sometimes referred to as Lifting costs) can be quite variable and are typically current period. Based on the Sep 10Q, it seems that $29/Bbl as lifting cost is a stretch.

The ONLY way to know what has gone into the $29/Bbl figure is to ask specifically

It might be meant to convey the "Cash Margin". If so I would suggest a review of CLR Dec preso from their website - slide 23 - which shows the cash margin for various period and calculated as the sum of:
Production expense ($5.69) +
Production tax ($5.99) +
G&A ($2.09) +
Interest ($4.61)
which for the 9 MTD averaged $18.33 and for which average $/BoE received was $72.52. You can see how it moves around.

Now for CLR's MRQ the cash margin was $51.26 (avg price $69.08 excluding derivatives - cash costs $17.82)

With CLR monetizing its hedges they might well be looking at a avg $/BoE in mid 30s and if cash costs were the same, their cash margin has dropped to around $13-$17.

There is of course no real point in shutting in a producing well as the Capex has been spent and your G&A costs remain as does the interest payment.

(C) DEBT

1. Understand the relationship between your proven reserves and your borrowing base. The whole credit agreement is here
http://www.sec.gov/Archives/edgar/data/1404079/000114420414005289/v366863_ex10-1.htm
and Article IV describes the Borrowing Base.

SSN BB re-determination is April & October, based on last stated 1P Reserves. That I think is most fortunate timing. SSN will revise its Reserves Dec 31. Very likely that the NPV10 will go down as the formula is likely to follow SEC Strip Pricing. It follows then that SSN might have a Borrowing Base deficiency (not the only ones - that could be a problem for a lot of companies) if they have drawn the full $19M - might be why that pulled the pull on some Capex spending.

2. Covenants - noted earlier the concern on Debt/EBITDAX ratio - For the full calculation being used refer to Exhibit C - Schedule 2.

Column 1 Column 2 Column 3 Column 4 Column 5 Column 6 Column 7

1 II. Section 7.12 (b) – Funded Debt to EBITDAX Ratio.

2

3 A. Funded Debt (all outstanding liabilities for borrowed money plus other interest-bearing liabilities, including current and long-term liabilities): $ _____________

4

5 B. EBITDAX

6

7 1.    net income: $ _____________

8

9 2.    less non-cash revenue or expense associated with Swap Contracts from ASC 815: $ (_____________ )

10

11 3.    less extraordinary or non-recurring gains and other extraordinary or non-recurring income: $ (_____________ )

12

13 4.    plus interest expense: $ _____________

14

15 5.    plus income taxes: $ _____________

16

17 6.    plus depletion, depreciation and amortization: $ _____________

18

19 7.    plus other non-cash charges $ _____________

20

21 8.    plus exploration charges $ _____________

22

23 9.    Total EBITDAX: $ _____________

24

25 C.    Ratio (Line II.A ÷ Line II.B.9): ________ to 1.0

I would suggest contacting the company to get their forecast for Dec Qtr EBITDAX (given its almost done and they know roughly what production will be).

3. Hedging - can't help but feel something has gone awry here. From the debt agreement Article 8:09:
"(a) Commodity Contracts. Swap Contracts entered into with the purpose and effect of fixing prices on oil and gas expected to be produced by Borrower, provided that at all times (1) no such contract fixes a price for a term of more than 36 months; (2) the aggregate monthly production covered by all such contracts (as determined, in the case of contracts that are not settled on a monthly basis, by a monthly proration acceptable to Lender) for any single month does not in the aggregate exceed 85% of Borrower's aggregate Projected Oil and Gas Production anticipated to be sold in the ordinary course of Borrower's business for such month; and (3) each such contract is with a Swap Lender or Third Party Counterparty."

So not to exceed 85% of monthly production but no minimum hedging required?

All in all - not one for me. GLTA holders hope it works out (even those who flame non holders for having the temerity to opine).

Expand

Cmon & all, some good points worth considering. I've read a number of times and some good leads which will help in general to further understand O&G.

The Backen discount makes sense - Looking at June/Sept Qtrs company had realised price $92.06 & $86.51. My calc for Wti avg June & Sept was $103.14 & $97.57 and the difference is $11.08 which fits in the range you mentioned. Currently Wti is $63.13 which using $11 would give Dec Qtr avg $74.41 and my estimated realised price after BD of about $63.33.

Re Hedging: I note in the Sept 10Q almost $800k recognized for Hedge gain when marked to market. Looks like an actg jnl rather than actual settlement so I would expect similar to be done in Dec accounts but could be wrong. Rough numbers I think net Dec qtr prodn receipts should cover admin costs with small surplus but the mark to market of hedge's would add to the result & meet the Debt/EBITDAX requirement. If the hedge's can be rolled into 2015 that would be good as could deliver better value and protection if OP continues downward. I don't think the oil is physically delivered into the hedge so unless settled they could possibly be rolled at a cost if worthwhile.

I think the lifting costs include some Royalty & taxes so the $29 could be lower as the lower OP would also flow into these costs. I think the royalty/taxes are about 25% so a $30 OP drop would reduce inflows but also outflows with net of around $23/bbl. No doubt the state depts. and people getting the royalty will also be feeling the pinch atm also.

Costs: There are likely to be some cost efficiencies and economies of scale once all the shut-in and new wells are bought back in line. Also possibly the phasing could bring the most profitable on line first to offset the lower OP. Getting production costs to the lowest possible level imo provide the best natural hedge for lower prices and ensure if price recovers more $$ hit the bottom line in the future. The pad drilling has probably already delivered some Capex savings but those are hard to quantify and just get buried in the exploration & development assets in the balance sheet.

Re value I think the market is not interested in the sector and this is the largest contributor to many O&G SP. Fwiw imo SSN have done a pretty good job this year as many wells drilled and some hedge cover put in place. The underlying results in June/Sept qtrly were good and compared favourably to many others but the move from explorer to producer is tough going, At present a $50k/boed valuation seems most applicable and on that the 1261 boed in the presentation less debt would give value of $47m - $15.5 = $31.2m which is where it's at. Everyone looks at these things differently but atm reserves and future plans don't seem to have much value given. Any change in mkt sentiment, OP, news in the new year could help a rerate to a higher per bbl rate but across the sector that doesn't look likely for a while.

That'll do, these are only my opinions & welcome any corrections
GLTA

SSN Price at posting: 1.1¢ Sentiment: Hold Disclosure: Not Held

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