The energy industry has seen a remarkable transformation in recent years. Economic uncertainty, coupled with growth in unconventional oil and gas plays in North America, has created a very different operating environment compared with just five years ago. These are some of the main questions that guide our research as the year starts.
The Effects of the North American Energy Reset
Since 2006, North America has seen a surge in production from unconventional oil and gas plays. Production is slated to return to levels of growth that have not been seen since the postwar era. While this has already changed the landscape in the United States and Canada – from E&P and pipeline players to IOCs and utilities – the impact is being felt around the world as North American crude displaces foreign imports, domestically-produced gas displaces coal and energy players small and large seek ways to replicate success in unconventional plays elsewhere.
How will rising North American production affect global crude balances?
North American crude has displaced some foreign imports to the United States. Regardless of export allowances, rising shale oil production has the potential to further narrow light-heavy differentials for US refiners. This has global implications in that most major refinery investments have been tailored toward increasing conversion capacity, a strategy based on wide light-heavy differentials. As these narrow, many large-scale investments become less profitable.
What is the outlook for LNG exports from the continent?
Aside from the question of whether the United States can legally limit exports to free trade partners, one LNG project – the 9.0 mmtpa Sabine Pass LNG T1-2 – has already been sanctioned. Another 269 mmtpa of capacity has been proposed elsewhere on the continent. While PFC Energy does not expect more than a total of ~46 mmtpa of LNG production capacity to move forward in the United States and Canada by 2020, this volume is still a tremendous capacity – especially for the United States, which just ten years ago expected to have to import significant volumes of natural gas to meet existing demand.
In Canada, the number of proposed LNG projects continues to grow. Chevron's entry into Kitimat has reenergized that project, although it still faces a structural problem (buyers' demand for hub-linked pricing). Will Shell's LNG Canada outpace other projects because it has potential offtakers already in the partnership? Does PETRONAS view Pacific Northwest LNG as a long-term project to meet a future demand problem in Malaysia?
How will global oil, gas and product prices be affected by North American production?
The price differentials between inland-produced crude in North America and WTI/Brent have been as wide as ~$30-50/bbl. Will these continue and who will benefit? What types of infrastructure projects will move forward to address the discrepancy?
Henry Hub gas prices closed 2012 without a single month averaging more than $3.50/MMBtu. This had a number of effects: demand for gas in the power and petrochemicals sectors surged; E&P companies shifted their focus to liquids-rich plays; and more integrated companies seriously considered exporting LNG from North America. Will these various demand sources combine to start a sustained rally in 2013?
Asian LNG buyers have long eyed the discrepancy in gas prices – but have now openly started discussing shifting from the traditional, fixed-destination, long-term, oil-linked LNG contract to hub-based pricing systems as North American projects seek buyers. Still, there are few cracks in the oil-linked system in Asia and the question remains whether Asian buyers can find traditional sellers willing to sell them LNG at non oil-indexed pricing. Will the system finally change in 2013?
Will the unconventional oil and gas story be repeated elsewhere?
Is this the year when shale oil and gas plays outside of North America will finally gain traction? If so, which country will deliver the next breakthrough in terms of material volume growth? In Argentina, Chevron and YPF have agreed to a $1 bn drilling program that would bring "factory drilling" to the Vaca Muerta play – but with regulated prices, can even this make a material difference? The UK government has granted regulatory approval for multi-stage fracking, albeit under stringent new guidelines. Ukrainian authorities continue to push for developments there, approving a $400 million exploration program by Shell to be followed by a similar program from Chevron. Finally, in China, unconventional resource plays are proceeding under a number of JV arrangements between Chinese NOCs and large IOCs, led by Shell's technology transfer agreement with CNPC. Still, will this early and dominant basin positioning by the Global Players be successful in replicating the environment in North America pioneered by small-scale players?
In the wake of these transformational changes, companies are seeking new ways to capture value. Reversing historic trends, capital flows shifted toward North America in recent years, but frontier plays still prove attractive. While unit costs are rising, investors are demanding higher returns – stretching traditional value propositions.
Will cost escalation put the brakes on long-lead time, large CAPEX projects?
Though North American prices are eroding returns, there has been a marked decline in operational metrics in the last year driven by a transition to a higher-cost resource base and new technological challenges. How will companies manage these costs in 2013? Will additional experience slow rising unit costs? What kind of efficiency gains can companies begin to gain?
What is next for the Global Players?
The last few years have seen an unusual degree of separation among the Global Players in terms of focus and strategy. Will these distancing moves deliver differentiating returns shareholders are demanding? Or do the next generation of large-scale development opportunities (oil sands, LNG, GTL, Arctic plays) lend support for further consolidation, creating ever-larger entities to reduce the portfolio risk posed by any single development or asset type?
Who will be the next to de-integrate?
The past few years have seen a number of large competitors seek value through de-integration, with one-time Global Major ConocoPhillips' spin-off being the most notable. Already in 2013, smaller IOC Hess has announced its intention to sell and/or close much of its downstream portfolio. While this is not quite the same path pursued by ConocoPhillips or Marathon, it underscores that integration may not be as en vogue as it once was. Will other companies follow suit? BP, whose portfolio is already virtually unrecognizable from its pre-Macondo days, may be the likeliest candidate among the remaining Global Majors.
What opportunities will NOCs pursue?
National Oil Companies continue to seek out new investments, both to grow their production portfolios and increase company value. Although frontier or geopolitically risky plays have been a particular focus for some firms over the last decade, the changing environment in North America has spurred interest in investments in the United States and Canada. This has been met with some skittishness, notably in Canada where the government placed restrictions on foreign ownership of Canadian E&P companies. Will more restrictions be put in place as investment increases? Will the United States follow that lead?
Geopolitics adds additional uncertainty to the effects of advancing technology and rising production from new oil and gas provinces. Sanctions and unrest in the Middle East and continued economic uncertainty in Europe and the United States raise questions over the viability of current supply and demand scenarios.
How will OPEC react to changing market dynamics?
Rising unconventional oil production in North America, combined with tepid global demand growth, has already begun to impact OPEC production targets. While sanctions against Iran limited crude volumes from that country andallowed Saudi Arabia to continue production in spite of increasing non-OPEC volumes, it is unclear this will continue in 2013. Saudi Arabia cut production twice in the last three months; how far will the Kingdom go before they begin to pressure their OPEC partners to begin cutting production as well?
How will the changing dynamic in the Middle East affect oil and gas production?
The effects of the Arab Spring continue to be felt across the region. The fall of autocratic regimes across the Middle East and North Africa has led to greater fragmentation and reduced state capability, increasing broad security risks. The political situation in Egypt and Libya and civil war in Syria already had investors concerned, but the January 2013 attack on Algeria's In Amenas gas production facility adds new risks. How will IOCs secure their current investments and amend future plans in reaction to the attack? Will the attack serve to cement perceptions in Europe that North Africa is a declining and unreliable source of gas? Will these types of attacks continue to destabilize the region?
With regard to Syria, will there be a concerted and coordinated regional or international effort to contain the conflict by shoring up the governments of neighboring states? Or will the conflict continue to weaken Syria's neighbors and reshape dynamics in the broader region?
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