[rockdoc123]

Hmmm... to what degree would you guess are O&G reserves estimates malleable when it's time to fill out the tax forms? A little pessimism when the IRS comes calling, and a little more optimism when it's time to bolster share prices?

I've posted this a number of times but to repeat a publicly traded company has very little leeway to work around reserve declaration to the SEC or OSC (or others) given laws that have been put in place, the very clear directives from a number of participating groups (SEC, AAPG, SEG, CSPG etc) and the fact that companies are required to have their reserves audited by third parties who are legally at risk for what they sign off on.

The rule used to be the price by which reserves were assessed each years was someday late in December (I think the 21st but can't remember). That was changed a few years back so that the price assumed was an average of the year. So for company X the third party auditors would use the average of the price in 2015 to come up with reserves for 2016. The price forecast is generally current price plus current inflation rate going forward.

There is an assumption by some out there that private companies can get away with a lot more. This is only as true as said companies are thinking they will never have to sell or do an IPO or other form of equity event. Try to get the approvals to do an IPO or RTO without an official third party audit....ain't going to happen. Most private companies I know of are looking for that equity event in the future, hence they adhere to all of the rules as if they were publicly traded.

[Zarquon]

Anyway, I'm trying to get an idea of what "failed to replace reserves" means. Here's Shell, 2014:
http://reports.shell.com/annual-report/ ... serves.php

I'll take Shell subsidiaries only:

Before taking production into account, Shell subsidiaries added 271 million boe of proved reserves in 2014. This comprised 42 million barrels of oil and natural gas liquids and 229 million boe (1,329 thousand million scf) of natural gas. Of the 271 million boe:
276 million boe were from the net effects of revisions and reclassifications;

Revisions - we took another long, hard look at all the numbers again and they look better this time?
Reclassifications - from Probable to Proven? It's the biggest item, but probably the most complicated, too. Effects of changing oil prices must be hidden in here, somewhere. The rest is engineering and advances in development planning.

9 million boe were from improved recovery;

We pump more water and CO2?

191 million boe came from extensions and discoveries;

Extensions - infield drilling? New wells in old fields?

and a net decrease of 205 million boe related to purchases and sales.

We sold more fields than we bought?

After taking into account production of 925 million boe (of which 30 million boe were consumed in operations), Shell subsidiaries’ proved reserves decreased by 654 million boe in 2014.

Finally something I understand. 30 million boe for the cracking towers, the tankers and heating the offices in Den Haag. They sold the rest.

Shell subsidiaries’ proved developed reserves decreased by 12 million boe to 6,777 million boe, while proved undeveloped reserves decreased by 642 million boe to 3,404 million boe.

The total addition of 271 million boe before taking production into account included a net positive impact from commodity price changes of 43 million boe of proved reserves.

Ah! There's the price effect in "reclassifications".

So Shell subsidiaries produced 925 million boe in 2014, and they found "191 million boe [...] from extensions and discoveries". I understand that oil from reclassifications, enhanced recovery etc. is real oil when produced, but only the 191 mboe seem to be "new oil".

Unfortunately this part of the report does not differentiate between oil and NG. The table at the bottom does, but it does not say anything about growth.

I admit this post is becoming a mess. Not enough time to think it through... more later.

[Zarquon]

I've posted this a number of times but to repeat a publicly traded company has very little leeway to work around reserve declaration to the SEC or OSC (or others) given laws that have been put in place, the very clear directives from a number of participating groups (SEC, AAPG, SEG, CSPG etc) and the fact that companies are required to have their reserves audited by third parties who are legally at risk for what they sign off on.

OK, thanks. I guess my question was due to the usual paranoia of the uninitiated.

[vtsnowedin]

After taking into account production of 925 million boe (of which 30 million boe were consumed in operations), Shell subsidiaries’ proved reserves decreased by 654 million boe in 2014.

Shell subsidiaries’ proved developed reserves decreased by 12 million boe to 6,777 million boe, while proved undeveloped reserves decreased by 642 million boe to 3,404 million boe.

OK doing a bit of sixth grade math here (No laughing Rocdoc.)
Add 6777+3404=10181 million boe "reserves"
10,181/654 decline per year present rate=15.6 years to End of reserves.
Houston we have a problem.
Then consider the oil- gas split.
As only 42 million bl of new additions was liquids =15% of new additions which is much less then the percentage of liquids in the 895 million boe sold. They may get to zero liquids reserves much sooner then that.

[ROCKMAN]

Z - It may seem messy but you appear to have a pretty good handle on the variables and what-if's. And yes: given the huge drop in oil prices many bbls of "proved economically recoverable" oil as doc described have fallen from the count in recent times.

And you'll see a huge gain in their boe for 2016 thanks to their $54 BILLION acquisition of BG

[vtsnowedin]

Z - It may seem messy but you appear to have a pretty good handle on the variables and what-if's. And yes: given the huge drop in oil prices many bbls of "proved economically recoverable" oil as doc described have fallen from the count in recent times.

And you'll see a huge gain in their boe for 2016 thanks to their $54 BILLION acquisition of BG

I would hope that would also show a big gain in production and sales. The question is will the purchase improve the ratio of reserve growth to sales.

[ROCKMAN]

vt - I haven't seen the details but probably not as big a bump in production or sales. Much of the asset is Aussi NG that will be exported as LNG for decades. Given how far the price of LNG exports have fallen this deal might not look that great on paper...today. And while that acquisition was definitely part of a long game they do get the immediate publicity value of a big bump up in proved reserves. A metric all public oils just love.

As far as the ration of reserves vs sales it won't be very impressive when looked at in the short term. But given the numbers I've seen it will take looking back after at least 10 to 15 years to see the true value of the acquisition. Big Oil doesn't sweat the quarterly or even yearly bumps in the road: it has to be developing strategic plans decades into the future. Which is why Shell paid $54 BILLION for LNG is the current price depressed market: what benefits they derive in the next few years weren't the driving force behind the purchase.

[vtsnowedin]

vt - I haven't seen the details but probably not as big a bump in production or sales. Much of the asset is Aussi NG that will be exported as LNG for decades. Given how far the price of LNG exports have fallen this deal might not look that great on paper...today. And while that acquisition was definitely part of a long game they do get the immediate publicity value of a big bump up in proved reserves. A metric all public oils just love.

As far as the ration of reserves vs sales it won't be very impressive when looked at in the short term. But given the numbers I've seen it will take looking back after at least 10 to 15 years to see the true value of the acquisition. Big Oil doesn't sweat the quarterly or even yearly bumps in the road: it has to be developing strategic plans decades into the future. Which is why Shell paid $54 BILLION for LNG is the current price depressed market: what benefits they derive in the next few years weren't the driving force behind the purchase.

Well now is the time to buy reserves while prices are depressed and the present owners have cash flow problems.
I thought it was a $70. billion US deal, did it change between announcement and closure?

[ROCKMAN]

From the WSJ last Feb. I didn’t realize Brazil was a significant portion of the deal:

Royal Dutch Shell PLC on Monday completed its roughly $50 billion acquisition of BG Group PLC, giving the Anglo-Dutch oil company a dominant footprint offshore Brazil—one of the most prized oil plays in the world, but one that presents a number of challenges. The prize for Mr. van Beurden is significant. The acquisition of U.K.-based BG will bolster Shell’s already significant position in the fast-growing liquefied-natural-gas market and turn it into the largest foreign oil company in Brazil.
It is a boost Shell sorely needs.

The company’s reserves dropped 20% last year as low oil prices erased 1.4 billion barrels from the volume of oil and gas it expects to develop. The BG acquisition will help damp the impact of that, boosting Shell’s production by roughly 20% and increasing its reserves 25%.

[ROCKMAN]

vt - An update of the Big Picture for RDS:

(Bloomberg) - Royal Dutch Shell Plc is in talks with potential buyers for some North Sea assets, mostly fields it got this year as part of the record acquisition of BG Group Plc, according to people familiar with the matter.

The Anglo-Dutch energy giant has been in talks with companies including privately held chemical producer Ineos Group AG and Neptune Oil & Gas, set up by former Centrica Plc chief Sam Laidlaw, the people said, asking not to be identified as the information is private. Shell is seeking to sell a package of assets and is talking with companies to gauge their interest before a formal sale process is launched, the people said. No final decision has been made and Shell may decide to retain the properties, they said.

Europe’s biggest oil company is planning to raise $30 billion from asset sales in three years after the $54-billion acquisition of BG increased debt and lowered its credit rating. While the move made Shell the world’s second-biggest oil company by market value, it also brought it properties in areas like the North Sea where costs are high. Crude continues to trade below $50, making it difficult for Shell to sell oilfields at what it thinks is a good price.

[vtsnowedin]

Ahh!!! so buy a basket of fruit , sort it out and keep the good cherries while selling the pits.

[ROCKMAN]

Vt – Exactly. That’s how it has always been done especially during a bust. Many properties that once had positive cash flow actually develop negative value. Two weeks ago we responded to a company with a small property to sell. Between lower revenue and a big plug and abandon liability it had negative vale. The guy wanted $1.5 million and we told him we actually wouldn’t even take the property for free if he offered it to us.

So yes: not only liquidate valuable properties to raise but basket some dogs into the deal. If there is some marginal value left it’s still time consuming and generally a pain in the ass to market them separately. So we let the new owner of the basket deal with those problems. Long ago I negotiated a basket sale and made the seller pull out a really big dog otherwise we wouldn’t make a bid…and nor would anyone else. So they did.

[rockdoc123]

So Shell subsidiaries produced 925 million boe in 2014, and they found "191 million boe [...] from extensions and discoveries". I understand that oil from reclassifications, enhanced recovery etc. is real oil when produced, but only the 191 mboe seem to be "new oil".

Unfortunately this part of the report does not differentiate between oil and NG. The table at the bottom does, but it does not say anything about growth.

I think you are understanding the terminology correctly. Extensions and discoveries are generally linked in the same category as they were never previously assumed to be "reserves" of any type. It is possible they were contingent resources (i.e. wells had been drilled but no announcement ever made of a "discovery" because it was not economic or technically viable at the time) but given the low price environment I suspect at best they were potential resources (i.e. those mapped on seismic or by other means but not tested previously by the drillbit).

Financial reports from oil and gas companies are inherently difficult to decipher. Many investment bankers with MBA's from places like Wharton often get it wrong. I thought it used to be a bit easier before IFSR accounting rules came into play. Now most financial reports whether they are annual, 10K , quarterly etc are somewhat repetitive and confusing. Best place to find out what is really going on is often company presentations or the Manangement Discussion that is often submitted to the regulatory body. It is usually nearly impossible to figure out what is going on in the majors as they lump so much of their business together and there seems to be little want or need to report segregated finances or results. For the smaller companies this is much more transparent.

Having been involved in A&D for a long time I spent many hours ploughing through statements and presentations. It is really a bit of a detective game and can be a bit fun as long as you aren't spending your own money.

[Zarquon]

Thanks. For me, it's just my $0.02 that's at stake.

Again from Shell, the number of exploratory wells drilled, 2011-2014:

Productive - Dry Holes
2014: 99 - 109
2013: 199 - 56
2012: 171 - 34
2011: 102 - 112

That's a lot of dry holes there (most of the drilling took place in N. America, which probably means US shales). Would be interesting to know how many of these were offshore/deepwater, where IIRC drilling can set you back a cool million per day and take several months (OK, that was Deepwater Horizon and a production well).

"An increase in exploration activity has contributed to an increase in dry holes, which more than doubled from 2012 to 2013. Accordingly, exploration expenses increased by 70% over the same period, primarily in North and South America."

Further guesswork: exploratory wells are probably a lot cheaper than production wells - no horizontals, no fracking, no completion - but you have to add the cost of seismic exploration ($50,000+ per square mile onshore?). Some googling shows that Shell spent $7 billion on exploration in 1997, that's 10 billion in current dollars. In 2016 they'll spend $33 billion - after several years of budget cuts. That's about the 400-500% increase in exploration costs that I mentioned in my original post and the figure I wanted to understand. So, how does drilling two hundred holes per year, dry/uneconomic or not, add up to an exploration budget of a few dozen billion dollars?

And the dynamic is that they drill a lot more holes, using better but more expensive technology, in smaller and smaller plays, many of them deepwater, and find less than expected?

At the same time, going by the reserve growth of one or two or three years doesn't paint a clear picture because a) it takes years to develop a field, and b) probable/undeveloped reserves are constantly redesignated. Some are downgraded, according to changes in price and markets. Others slowly go upwards through the 3P cycle of "there is some oil, but we don't know how much or whether we're going to drill, so we can't book it yet" all the way to "the field is well mapped, the wells are drilled and lifting costs are always lower than price". Some of it gets lost on the way from 3P to 1P. And therefore next year could look a lot different that this year, but the general trend is down-ish. Is that it?

[AdamB]

Ahh!!! so buy a basket of fruit , sort it out and keep the good cherries while selling the pits.

That is probably a pretty good description. And then, on occasion (such as most independents fleeing the Appalachia basin and abandoning their deep devonian shale rights long ago) those pits become the largest producing gas field in the USA. Yesterday's pits, tomorrows cherry tree.

[rockdoc123]

So, how does drilling two hundred holes per year, dry/uneconomic or not, add up to an exploration budget of a few dozen billion dollars?

When companies allocate funds it includes pretty much everything, capital, opex and G&A. Some of Shell’s wells are pretty danged expensive (deep water offshore) which makes up some of large dollar numbers (I believe their offshore Nova Scotia project has a $2 GB budget). As well they no doubt have had to pay signing bonuses in various countries (which can be in the hundreds of millions of dollars). Their G&A would include all exploration division staff from all over the world along with allocated share of overhead (based on number of people). As an example they have about 100,000 full time employees worldwide, if 1/3 were allocated to exploration spending (pulled that number out of a hat) and you used $250K/yr as a average all in salary and allocated overhead (reasonable given some of the employees receive expat compensation) you end up with $7.5 GB in salaries. Large offshore seismic programs can be expensive as well. Also need to remember Shell operates in 90 countries around the world, the additive effect of that many programs increases costs.

[Zarquon]

I read recently that the Big Six control only about 15% of world oil production, but about 25% of refining (the numbers were from 2007 IIRC, but shouldn't have changed much since then). Even all the big ones added together are not very significant in terms of market share, but they all bring a hundred years of experience to the table and in terms of technical and management capability they play in a league of their own, the occasional goof notwithstanding.

Now some national oil companies like Aramco certainly enjoy exclusive access to some of the lowest-cost reservoirs in the world and they hire lots of experienced expats for exploration, engineering and reservoir management. On the other hand: what I've read on this site about NOCs like Pemex makes the problems of Big Oil seem like a minor irritation, compared to the job of propping up a whole banana republic with a bloated and inefficient oil company in times of low prices. Or a return to "normal" prices, if you like.

But these are "normal" prices in times of ever-increasing industry costs, too low even for the best-run firms to fully replace their reserves. And even though you can't compare NOCs like Pemex to Statoil, and even though their definition (and reporting) of reserves is generally up to them and not the SEC - would it be correct to assume that your typical NOC is hit even harder than the IOCs by rising E&P costs and subsequent difficulties of developing new reserves?

[ROCKMAN]

Z - Along the lines of what you're thinking: we keep hearing about how much oil the KSA is producing and not very often how much they are exporting. I think you find digging out the details interesting: oil production vs exports; KSA refining capacity; KSA refined product exports vs internal consumption. For instance who exports more refinery products: the KSA or the USA?

Of course as always with the KSA we have to take any number with a grain of salt..

[rockdoc123]

would it be correct to assume that your typical NOC is hit even harder than the IOCs by rising E&P costs and subsequent difficulties of developing new reserves?

I don't think there is any one answer that covers all of them. SA as an example has very low lifting costs (around $4/bbl I think) so they are making profit at current prices but profit is not enough for them given they require a large amount of capital to pay for social programs, so they are hurting at anything less than $80/bbl (unless they tweak their economy in other manners, which it appears they are attempting to do). Mexico suffers for different reasons. Their lifting costs are not as cheap, the reason being that their employee costs are quite high (unions along with large mandatory severance for anyone who has worked for as little as a few months I believe). As well Pemex is no where near as efficient or effective in the fields they produce compared to Aramco. Less oil produced, lower prices and no relief in G&A is a killer. Venezuela is completely pooched given they were already doing the wrong thing in terms of field efficiency and productivity which was to take almost all of the money normally earmarked for reinvestment in the oil fields to fund social programs (to increase or at least maintain Chavez and his recent clones popularity). Declining production do to lack of investment, lower prices and an economy that is otherwise in the crapper has combined to create a real mess. Countries that do not have the luxury of big legacy fields and count on smaller fields and lots of turnover in the E&P space are definitely in trouble. As an example if we look at Colombia the Llanos basin was a huge activity driver in the oil and gas space back in 2008- 2011 with lots of success. IOC's were climbing on top of each other to participate in the bid rounds and pick up acreage that was going through its second if not third cycle of E&P. The fields discovered, however, were generally small on average (2 - 6 MMB) with high productions rates resulting in a very short life cycle. As long as the price of oil was high there was always someone willing to step in and look for the next small field since the ROI was acceptable for a smaller company with low overhead. Once price dropped there were fewer companies willing to step up to the plate and invest. As a consequence the small fields continue to deplete and be abandoned resulting in an ever dwindling government revenue from oil and gas royalties. A perfect storm for them unfortunately.

Lots of other examples that are all somewhat unique I think.