Economic slowdown doubles challenges facing refiners

Recession will further impact the economics of a refining system that was already heading from the sunlight into a difficult period.

With the world in a recession that may exceed anything since the Great Depression, the implications for refining are profound. Forecasting bodies such as the IEA, EIA and OPEC have recently focused on “reference” / stable continuation of trends, “high price / supply constrained” and “low price / demand constrained” scenarios. What a year ago was viewed firmly as a high price and potentially supply constrained outlook, occurring on the heels of an era of refining tightness, has brutally reversed in recent months into a demand constrained (collapsed!) low oil price outlook – at least for the medium term.

Today’s global refining system faces an unprecedentedly complex situation. Demand has been growing strongly, especially in Asia, but it is now under assault from the fallout of high oil prices, financial crises and recession.

Costs have risen substantially since 2000, in some cases doubling. But recent months have shown that high oil prices – up as much as sevenfold compared to 1990s levels – magnify differentials and margins. They re-write the relationships between crude/product pricing and operating, transport and capital costs.

However, not only is demand flattening but non-crudes supply is growing. NGLs, condensates, biofuels, GTL, CTL, petrochemical returns are rising faster than those of crude – are they mainly light, clean streams. They are eating into ex-refinery demand for primarily naphtha/gasoline at the same time as dieselization through policy in Europe and through growth elsewhere is driving distillates demand; result, inversion of traditional gasoline/diesel price ratios.

Finally, carbon regimes are functioning in Europe and on the horizon in the US and elsewhere. The incoming US administration is committed to move alternative energy and efficiency forward.

So where does this leave global refining?

Flat demand, growing non-crudes supply – too much refining capacity

Even before the current demand collapse, the major statistical organizations were steadily revising downward their projections of future oil demand.  “Reference” cases remain that still show appreciable demand increases. But “high price” and “constrained” cases where demand does not exceed 100 million bpd are increasingly being assigned more likelihood.  The very similar EIA 2008 International Energy Outlook High Price and OPEC 2008 World Oil Outlook Lower Demand cases, show global demand increasing 4-6 million bpd over 2007 by 2015 versus around 10 million bpd under reference cases.  With potentially up to 6 million bpd of additional non-crudes supply by 2015, the net demand for additional refining to 2015 could be negative.

At the same time, several years of strong margins have produced over 20 million bpd of listed refinery projects.  Rigorous analysis of these puts the breakdown at close to 4 million bpd under construction, a further 4 million as probable – although now largely being deferred - and the remainder in the possible to speculative range.  Thus, unless demand does reach close to reference case levels by 2015, the added capacity will – at the global level – simply lower utilizations.

And this is before adding in the current global slowdown which makes the medium term outlook even more bleak. The IEA, EIA and OPEC are all in process of lowering their projections for demand.  November outlooks released by the three have 2009 demand 0.1 to 0.8 million bpd above 2007’s level of 86 million bpd.  But, by 2010, construction adds 4 million bpd of capacity and, critically, per the OPEC 2008 World Oil Outlook, supplies of non-crudes, including NGL’s, condensates and biofuels, will rise by 3 million bpd.  Even if some of these projects and/or non-crude supplies do not materialize, or demand growth staggers to its feet more quickly, refining utilizations can only head in one direction – sharply down.

The current short to medium term global outlooks from IEA, EIA and OPEC project sustained demand decline in OECD that is offset by increases in non-OECD regions.

Global downstream modeling provides a unique method to quantify impacts

With a 20 year track record covering assignments ranging from regional analysis for the World Bank and emergency analyses for the US Department of Energy to regulatory assessments for the EPA and American Petroleum Institute, and from global World Oil Outlooks for the OPEC Secretariat to technology and carbon regime studies for major and specialty oil companies, EnSys has, with its WORLD modeling system, built a unique capability to address and quantify all manner of developments impacting the global downstream, oil markets and refining.

We have already turned our attention to the potential medium term impacts (2010) of the current economic crisis and will follow through early in 2009 with comprehensive assessment of the outlook for refining capacity, utilizations and margins.  Analysis to date already highlights key facets affecting refining requirements and viability.

Two Basins – Big Contrasts
As indicated in the latest official outlooks, the Pacific Basin will continue to grow, the Atlantic Basin – dominated by OECD regions - will not.  Additional refining capacity will continue to be required in the Middle East and Asia-Pacific, led by China.  The amounts of secondary processing capacity expected to be added there look to be broadly in balance with demand growth across naphtha/gasoline, distillates and residual fuels.

In contrast, in the Atlantic Basin, total call on refining is negative outside Latin America.  Any demand growth is annulled by increases in biofuels in the USA, Europe and South America.  Initial analysis of 2010 with global demand at 87 million bpd shows global refining utilizations a touch under 80% with the Middle East and Asia faring appreciably better (84-90%), USA/Canada around 84% but Europe severely down toward the 70% range.

At a 2010 price around $65/bbl (2007 $) for WTI, differentials versus heavy sour (Mayan) drop to the $10/bbl range.  3-2-1 crack spreads lie in the $6 - $10/bbl range.

Diesel Gasoline Imbalance is Set to Continue
EnSys’ view is that the gasoline-diesel imbalance and associated diesel premiums are a long term phenomenon.  Diesel demand is very much the engine of economic growth worldwide.   The pace of European dieselization must eventually slow but gasoline demand there will continue to decline. With this and the growth in Atlantic Basin ethanol supply, gasoline will remain in regional surplus.  We see new hydro-cracking projects helping to ease today’s diesel-gasoline differentials of $20/bbl or more but long run annual average differentials per WORLD studies lie in the range of $7 - $12/bbl and trend up over time.

The medium term impact of global slowdown is to cut 2010 diesel-gasoline differentials in all regions; to $3/bbl US Gulf, $10/bbl in Northwest Europe and $6/bbl in Asia (Singapore).  Hydro-cracking capacity which otherwise would have been universally full is seen moving as marginally – and likely temporarily - into surplus.

As Europe has shown, once distillate yields from crude have been maximized, the only path remaining to significantly raise distillate output is via hydro-cracking, which is high cost, energy and hydrogen intensive.   Yes, there are FCC catalyst advances which move yields in the right direction – more light olefins/propylene, clarified oil, less gasoline – but hydro-cracking or deep hydro-treating is still needed to deal with the high clarified oil output.  Condensation type processes that would convert naphtha / gasoline range streams into diesel do not yet appear commercial.

These factors will sustain a sharp distinction between margins for refineries oriented to distillate versus those oriented to gasoline.  Major refinery projects going ahead in the US depart from tradition and focus on hydro-cracking – but they will still produce significant incremental gasoline in a basin that does not need any.

High Crude Prices and Diesel Demand Lead to Hydro-cracking
Another factor is evident.  At high crude prices, there is a greater incentive to minimize downgrading of any raw material. This lowers the attractiveness of carbon rejection (coking) for upgrading and raises that for hydrogen addition (hydro-cracking).  The effect is reinforced by the tendency of natural gas prices to not maintain a 6:1 price ratio to crude, i.e. to be at lower levels on a Btu basis.  The effect is more marked if petroleum coke prices, linked as they are to coal, remain low relative to crude.

Crude Quality Flat – Coker Surplus
There is a common perception that “the quality of the crude slate is declining”. Recent detailed studies, such as that underpinning the 2008 OPEC World Oil Outlook, (www.opec.org), challenge this view, projecting little change in global quality. Sufficient sweet and medium sour crude is coming forward, in these outlooks, to support growth in VGO and resid hydro-cracking, with high unit utilizations. In contrast, demand for coking looks flat with prospects for low utilizations – at least through 2015 – stemming from the 40% increase in global coking capacity currently underway and a lack of heavy crude supply increases until the longer term.  Much depends on the quality of the Canadian and Venezuelan syncrudes put to market.   Based on recent projections of Canadian SCO, SynBit and DilBit output, EnSys’ analyses show the mix does not appear to contain enough vacuum residuum to keep US cokers full, given declines in Mayan and heavy Venezuelan (partially offset by rising Brazilian). Recent announcements of deferrals on Canadian upgraders (e.g. Shell Scotford) will help redress the balance if they lead to greater proportions of DilBit rather than SCO.

In short, weakness in gasoline and heavy crude / coking imbalance will lead to lower margins for all refineries not oriented to distillates. Is there a “silver lining” that could provide support to refining economics between now and 2015?

Marine Fuels Regulations Further the Distillate Trend Offer a Route to Higher Margins
Three or more years ago, there was little interest in marine bunker fuels as a regulated product. However, the progressive reductions to low and now ultra-low sulfur levels of land transport fuels in OECD regions have heightened awareness of the substantial proportions of global pollution marine fuels now account for.  Studies have concluded that emissions from shipping in coastal regions cause extensive health problems leading to thousands of deaths annually.

Most countries adhere to the International Maritime Organisation MARPOL protocol which governs standards for marine bunkers (marine gasoil, diesel and “intermediate” fuel oils).  MARPOL AnnexVI allowed regions with pollution issues to establish Emission Control Area zones wherein SOx emissions and thus fuel standards were set to the equivalent of 1.5% sulfur.

Faced with the EU implementing 2 ECA’s and a marine diesel sulfur rule, and with California and other regions considering local regulations, the IMO acted to implement new, stricter AnnexVI standards, encompassing SOx, NOx and particulates emissions.  In a series of studies using WORLD for the US EPA, the American Petroleum Institute and the IMO, EnSys undertook the leading refining analyses which under laid the IMO decisions that were ratified in October 2008.  These call for the ECA sulfur standard to drop to 1.0% in July 2010 and then to 0.1% from January 2015 on. The maximum allowable sulfur outside ECA’s drops to 3.5% in 2012 and to 0.5% in 2020. This latter date is subject to a feasibility study to be performed no later than 2018 which may lead to the 0.5% global standard being deferred to 2025.

The regulations allow for what are fundamentally SOx emissions standards to be met either by fuel sulfur reduction or by use of on-board scrubbing systems. These are still at the trial stage.  Barring widespread commercial success of scrubbing, and unless breakthrough residual fuel desulfurization technologies become commercial, the new IMO Annex VI regulations will lead to a total conversion of IFO fuels to distillate by 2020 or – latest – 2025.

EnSys evaluated the impacts on global refining under several scenarios.  Total conversion to distillate would require massive investment programs.  These would be all the greater as work by EnSys’ associate Navigistics and others has shown conclusively that marine bunkers global consumption is twice that reported by the IEA, i.e. close to 370 million tpa today not the 150-200 mmtpa often quoted.  Total incremental investment for global conversion to distillate by 2020/2025 was projected at $125 - $145 billion; this at levels of capital cost escalation lower those obtaining in 2008.  The investments would need to center on substantial further additions to hydro-cracking capacity, coking and supporting processes. Potentially, over 6 million bpd of IFO would need to be upgraded to either 0.1% or 0.5% sulfur marine distillate.   Supply costs of all distillate fuels would rise further, and those of naphtha, gasoline and residual fuel decline, in turn extending the trend to higher proportion of distillates in global demand and higher premiums for diesel and jet fuel products.

Partial or total shift from high sulfur marine diesel and IFO fuels to low sulfur marine distillates will occur.  Again, refiners who maximize distillate yields stand to benefit. Aside from the steady movement in non-OECD regions to low and ultra low sulfur gasoline and diesel, marine fuels conversion is arguably the last big opportunity for upgrading the quality of refined products! What is ironic is that the current collapse in product demand, the prospect for medium term slackness in coking, and even possibly in hydro-cracking, create a scenario where refiners would benefit if required to shift early to the long term MARPOL standards.  Coking and other unit utilizations would rise, pulling up refining margins; refinery CO2 emissions would increase but so would the health benefits from the reductions in marine fuel emissions.

A key benefit of working with a global approach to the refining industry is that deepens and also quantifies insights into potential developments, forming a more informed and rational basis for investment and policy decisions. It is EnSys’ goal to continue to bring these insights to all concerned with the global downstream. We look forward to continuing to work with regular and new clients to enumerate base and alternative outlooks. A first priority is to tackle the short and medium term outlook through 2010 and 2015 in the light of new developments. Our new study on this will be available early in 2009.

For further information, please contact: Martin Tallett, President, EnSys Energy  at: (781) 274 8454, martintallett@ensysenergy.com, www.ensysenergy.com