7 Responses

  1. avatar
    mv at |

    Pezzo molto interessante, che ricorda a tutti l'importanza del ciclo delle materie prime.

    Completerei però con un'osservazione: per le stesse ragioni per cui la produzione da shale oil può tornare a crescere rapidamente ("non appena i prezzi risalissero, gli investimenti tornerebbero a aumentare immediatamente in modo massiccio, perché il tempo necessario a remunerarli è brevissimo, spingendo di nuovo in alto la produzione"), così i bassi prezzi richiedono meno tempo per tradursi in minor produzione. Non immediatamente, come abbiamo visto. Ma è fortemente probabile che gli effetti dei minori investimenti si faranno sentire con forza dall'ultimo trimestre di quest'anno. Inoltre, a ottobre arriverà la revisione delle linee di credito di molti operatori: plausibilmente, l'effetto sarà meno denaro e più caro, ossia meno investimenti e dunque meno produzione. La produzione shale statunitense vale a spanne 4 milioni di barili al giorno: volumi che non scompariranno di certo da un trimestre con l'altro, ma c'è una sacco di spazio per il riequilibrio del mercato globale.

    Reply
  2. avatar
    Anonimo_2 at |

    Sono parzialmente d'accordo con l'analisi di Maugeri… il meccanismo che regola l'offerta di petrolio è diverso: i produttori decidono la messa in produzione di un giacimento (la c.d. FID) quando hanno già venduto tutta la produzione mediante contratti a lungo termine al prezzo vigente al momento della negoziazione. Questo è il motivo per cui i prezzi al consumatore finale hanno un'inerzia maggiore rispetto al prezzo spot riportato dai giornali. Quotazioni depresse hanno effetto solo sulla crescita futura dell'offerta di giacimenti non in sviluppo con un break even marginale (ovvero il cui costo di produzione comprensivo di costi di sviluppo e di estrazione si trova al margine della curva di offerta). In questo ragionamento si innesta il comportamento dell'Arabia Saudita che avendo i costi più bassi di sviluppo ed estrazione, accellera la messa in produzione dei propri giacimenti spiazzando così i paesi marginali. Detto ciò, confermo la view al 2018 con il brent a 50-60 USD in linea con l'arbitraggio teorico (a parità di potere calorifico) con i prezzi del gas. Un saluto a tutti

    Reply
    1. avatar
      mv at |

      Anonimo__2, a quel che mi risulta, i contratti di lungo periodo hanno normalmente durata di un anno, più eventuali rinnovi. E sono molto utilizzati proprio dai produttori mediorientali (che vendono solitamente direttamente alle raffineri), oltre che dalla Russia, per garantirsi le quote di mercato.

      I contratti di lunghissimo periodo (oltre dieci anni) e siglati prima dell'avvio della produzione sono quelli del gas – fuori dal Nord America – ma non sono utilizzati per il petrolio.

      Reply
  3. avatar
    Anonimo_2 at |

    Featured Commentary: The New Oil Order: Lower for even longer as the market searches for a new margin of adjustment

    Published September 11, 2015

    1. Although oil prices have revisited the lows of last winter, this time both financial and fundamental metrics are much weaker. Forward demand expectations are lower as the emerging market economic outlook continues to deteriorate. Supply from core-OPEC and other low-cost suppliers continues to surprise to the upside even against our aggressive expectations. Non-OPEC supply outside of the US has managed to beat expectations, and with the recent EM currency devaluations, the risks from these regions are now for more, not less, supply. While the EIA recently reported a decline in US production, it is important to note that it also increased the stock build and the “balancing term”, leaving uncertainty around the reported decline that was reiterated in yesterday’s weekly data. In addition, our own modeling, pipeline data and company guidance suggest US production has only flattened, not declined sharply. Nonetheless, the market has likely priced in sharp declines in US production given the EIA data, but we believe this has likely been offset by expectations of increased production in Iran (we assume production will grow by 260 kb/d on average in 2015).

    2. We estimate that supply is now up 3.0 million b/d yoy, a growth rate which demand has met only once, in 2004 when the emerging markets had clean balance sheets and few macro imbalances. As demand is unlikely to balance the market, the focus needs to turn to what type of market forces will create a now larger adjustment in supply. As we have argued in the past, the New Oil Order provides the market with far more levers to adjust in creating a balanced market: credit, equity, cash flow or operational stress, i.e. breaching storage capacity constraints such that a surplus can no longer be maintained due to no physical storage availability and supply must be bought down in line with demand immediately such that prices trade below cash costs. However, the backlog of drilled but uncompleted shale wells, another feature of the New Oil Order, complicates this margin of adjustment even further, as the “fracklog” is just another form of storage.

    3. With a larger physical surplus for the market to cope with, the uncertainty around which metric will be the margin of adjustment has increased significantly. In other words, the search for a new equilibrium has now become the search for the new margin of adjustment. While which margin will ultimately drive the rebalancing remains uncertain, they all point to lower for even longer oil prices. For financial stress near current price levels to create adjustment, it needs to be maintained. Although prices are near our autumn WTI price forecast of $45/bbl, to reflect this need to keep prices lower for even longer, we have reduced our 2016 WTI price forecast to $45/bbl from $57/bbl. Although our 2017 WTI forecast remains unchanged at $60/bbl, it now sits above the forward curve given the recent sell off. As we continue see significant downside risk in long-dated prices as the market nears rebalancing, we would not interpret that as a current signal to buy long-dated oil futures or go overweight equities. Historically, once the storage arb that connects spot to forward prices is no longer needed, bear markets typically end with a sharp sell-off in long-dated oil prices that creates a shift in producer and investor behavior that gives birth to a new bull market.

    4. The key to lower for even longer is that a weaker EM demand outlook combined with stronger-than-expected low-cost supply growth, now requires non-OPEC production to shift from growth to large declines in 2016. Damien Courvalin estimates that now 800,000 b/d of marginal supply needs to be taken out of the market next year to achieve balance by the end of 2016 (see Lower for even longer). His base case has the US bearing the largest portion of this adjustment. Although a large EM-driven demand shock that pushes oil demand down into a steeper part of the supply curve where a cartel could exist once again has the potential to bring OPEC to action, we believe this is unlikely as the EM economic weakness is still mostly contained and relatively small. Given the size of the new required adjustment and the increased uncertainty on how and where that adjustment will take place, the focus of the adjustment is shifting to financially more healthy companies.

    5. However, given the deeply entrenched expectation that shale production growth will be required within the next couple years, investors’ willingness to fund US production will remain high. The result is a Catch-22 that only expectations for lower for longer will resolve. Even if the current surplus breaches logistical and storage capacity constraints and forces spot prices to $20/bbl, deep into the cash cost curve, such a drop would likely prove transient. As a result, despite a quick rebalancing of the supply and demand for barrels, it would likely do little for the longer-term capital imbalance in the energy market. New capital would likely take ownership of higher quality assets and capex would actually rise again in places like the US. Only expectations for lower prices for longer will rebalance the capital markets for energy. The sooner the backend of the futures curve gets near to our 2016 forecast, the more likely our above strip 2017 forecast can play out.

    6. Earlier this year, the focus was on E&P companies with significant high yield credit exposure and the potential for financial stress in highly levered companies to help create an adjustment. However, as Jason Gilbert notes (see Fortune may not (yet) favor the bold: Reducing ’16 WTI; Still Neutral), the market surplus is now too large for this group of companies to have a meaningful impact on fundamental balances as they only represent c.15% of US oil output. He also argues that this reduces the importance of borrowing basis redeterminations, as the focus moves to the larger investment grade producers where managements and equity, not debt markets, are a more coercive force. Although high yield credit will likely experience a rough patch over the next several months, what ultimately happens to high yield credit is a by-product of what the larger companies and private equity end up doing. As Jason emphasizes, it is liquidity for these companies that matters far more than the credit metrics, which is likely to sustain this group of companies for several more quarters at current price levels. As a result, he does not see a large wave of bankruptcies in 2016.

    7. Taking the E out of E&P, as producers focus on production (P) as opposed to exploration (E): In a lower for even longer oil price environment, the focus needs to shift towards optimizing production via productivity gains. While Brian Singer broadens the US production adjustment to a larger universe of companies (see US oil output decline in 2016 needed for recovery in oil prices, equities), he remains positive on the cohort that have demonstrated superior improvements in productivity. In addition, he argues that this group is poised to gain the most should the market rebalance by the end of 2016 as we expect. In Asia, Franklin Chow believes efficiency gains (along with capital discipline) could allow Asian oil companies to generate free cash flow, maintain relatively stable dividend payouts, and still further deleverage. However, during the second phase of a bear market before prices recover, Brian and John Nelson show that the companies with more robust hedging programs tend to outperform (see E&Ps get knocked down, will they get up again? Adjusting ratings). In the current environment, only 11% of oil/NGLs production is hedged for 2016, well below recent averages around 25%. Accordingly, he argues that a lack of hedging adds greater constraints on producers which could potentially add urgency to asset sales and M&A.

    8. While it is still uncertain about where, when and how the full supply adjustment will take place, we can say with far greater confidence that oil supply growth in North America, will likely slow down if not reverse given recent drilling and investment patterns. As a result, Ted Durbin has downgraded the US midstream sector to Neutral from Attractive (see Sector down to Neutral; adjusting ratings to reflect slower for longer). Lower volume growth drives less infrastructure spend; therefore, investors will likely require a higher upfront dividend yield to compensate for lower future dividend growth.

    9. Compounding the uncertainty around the adjustment process is the market structure of the New Oil Order. As we have emphasized in the past, high-quality producing assets are on average owned by weak balance sheets while strong balance sheets on average own the lower-quality producing assets. This takes away the linearity that used to exist between financial stress and willingness to reduce supply, as historically the weaker balance sheets with higher cost assets would run into financial pain at the company level first. Accordingly, Neil Mehta and Felipe Mattar emphasize the importance of focusing on the larger integrated companies with positive free cash flow (see New Oil Order: Lowering our 2016 crude outlook – tilting towards downstream vs. majors) as opposed to negative cash flow trends (see Latin America: Energy: Oil – Adjusting TPs for lower GS 2015-16 oil price deck). Further, in the US, Neil prefers the integrated oil companies with a large downstream presence despite excess global refining capacity due to cost advantages in the US.

    10. We have also emphasized in the past the importance of focusing on variable/cash costs as opposed to “all-in” costs that include both fixed/capex and cash costs. This distinction becomes increasingly important in an oversupplied market that no longer needs new capacity driven by capex. As oil prices near the top of the cash cost curve, this brings to the forefront all of the components of costs, particularly dividends paid to shareholders of equities. This issue has been far more of a focus in Europe where integrated oils pay relatively higher dividends. Henry Tarr now believes that current yields for the European integrated oil sector already imply a c.20% dividend cut against expectations of a c.25% cut required to be free-cash-flow neutral under our lower for longer forecast. Even with this, he believes valuations are not yet compelling, but is moving the sector to Neutral from Cautious. This should be viewed as tactically defensive, given the extremely strong balance sheets of the European integrated oils, as we maintain that the core of the New Oil Order is the need to keep capital sidelined until physical markets rebalance (see Nearing bottom in oil; Coverage View to Neutral; Total to CL Buy).

     

    Jeffrey Currie – Goldman, Sachs & Co.
    (212) 357-6801 jeffrey.currie@gs.com

    Reply
    1. avatar
      mv at |
      Reply
  4. avatar
    Anonimo at |

    <<Questo è il motivo per cui i prezzi al consumatore finale hanno un'inerzia maggiore rispetto al prezzo spot riportato dai giornali>>   INERZIA  che  si ANNULLA  quando  il prezzo  del  petrolio  sale. ;-))

    Reply
  5. avatar
    Anonimo_2 at |

    😀

    Reply

Leave a Reply


(obbligatorio)