Sharp Cycles Ahead

Our work over the past few years, including our close involvement with U.S. natural gas restructuring in the early 1990s and Texas electric power restructuring in the 2000s, has taught us many lessons about U.S. and North American energy dynamics. Our overall observations and assumptions were laid out broadly in part one of this article, “Forward Curves In Energy,” which appeared in the August 2013 issue. Since fall 2011 we have been exploring alternative scenarios that could clearly be described as contrarian. In our view, “stress testing” the possibility of sharp cycles ahead in oil and gas prices is a logical line of reasoning to pursue.

This outcome clearly flies in the face of conventional wisdom. The details underlying our logic test can be found elsewhere (for example, in white papers from the Bureau of Economic Geology’s Center for Energy Economics, The University of Texas).

A major factor is the intrinsic nature of the U.S. natural gas resource base. The cheapest and, at present, most easily available dry-gas supply comes from production that is associated with crude oil or nonassociated gas from condensate wells or derived from wet gas. Discipline is being forced on producers by virtue of the very low Henry Hub price relative to oil.

The drilling wave has reversed upon itself. Domestic activity was spurred first in conventional and then, overwhelmingly, in unconventional gas plays as the Henry Hub price shocks of the 2000s played out. As natural gas and then natural gas liquids (NGLs) prices softened, oil took over to sustain domestic activity. BEG shale-gas resource assessment work funded by the Alfred P. Sloan Foundation demonstrates this shift in the Barnett, where associated gas production from the “wet” section of the play helped to maintain gas production from the play, even in 2012. Gas- and oil-directed rig counts (based on Baker Hughes data) flipped. The industry and its home communities—from Houston to Fargo—have been incredibly lucky. The ability for capital expenditures to migrate from methane to oil and/or NGLs in upstream portfolios allowed many operators to shelter acreage positions and preserve staffs and competence.

Eventually, the much softer natural gas price will exert further discipline. Early indications are that many of the large domestic gas producers have reduced and are reducing methane output in the face of an unattractive commodity price. A key factor affecting producer behavior through 2012 was the ability to lock in hedges and other price-risk-management strategies of at least $4 per MMBtu and, for many, between $4 and $5 or higher.

With forward prices difficult to discern, spending is being curtailed on low-volume, marginal gas properties with coalbed methane (CBM) absorbing the brunt of the adjustment. We estimate that 2012 CBM production declined about 9% on top of an estimated 6% drop during 2011, based on company disclosures and information from individual states. The Outer Continental Shelf (OCS), Gulf of Mexico may post as much as a15% drop following the roughly 18% decline in 2011 as shallow-water fields play out. The hope is that growth in shale production will soften declines from long-established fields and plays as they reach the end of asset life.

The inevitable maturity in GOM shelf production and older onshore conventional fields has been part of the conversation about U.S. natural gas supply-demand balances for more than a decade. Is too little attention being paid to timing and the risk that shale production may not cover these eventual losses? The constricted focus on unconventional resource plays has sucked a great deal of oxygen from traditional, conventional exploration pursuits.

Apart from shales and other tight-rock prospects, exploration success continues to be constrained on many fronts. Add to this the steep declines in Canada’s Western Sedimentary Basin and commensurate drop in Trans - Canada Pipeline eastbound gas throughput, along with extreme difficulties in achieving market access for British Columbia and Alaska production, and the gas supply picture is perhaps more interesting than some would bargain for.

Costs for oil and gas exploration and production remain high and greatly variable, a consequence of increased oil prices and diverse operating conditions. Meanwhile, the lack of spreads continues to manifest in midstream bottlenecks. Given the large number of downstream projects under construction, planned and proposed, natural gas demand could outpace dry-gas supply and deliverability, creating the potential for higher prices in the 2015 to 2020 time frame.

For all of their richness, oil wells do not yield enough associated gas to satisfy all of Lower 48 U.S. expected incremental consumption. Demand growth, including pent-up demand stemming from economic recovery along with new investment in gas-fired power generation, industrial use, and even some natural gas transportation, could unfold in the face of declining imports from Canada and increasing exports to eastern Canada and Mexico. Imports from the U.S. now constitute about 20% of gas supply in both countries. Exports of liquefied natural gas (LNG) could add to demand build. This means a pronounced likelihood of sharper, higher prices in order to pull drilling activity back into incremental dry-gas locations as well as to attract LNG imports, if necessary.

Down the road, the impact of higher prices on demand suggests some eventual erosion in consumption that, along with other factors, could create a second cycle later in our time horizon (2030). Throughout, the need to move to more marginal locations for gas drilling and supply is indicative of a gently rising cost industry. Our cycle scenario represents a typical commodity business “reality check” to the flatter, less volatile gas-price outlooks that predominate. Our scenario still yields a healthy resource base in booked reserves and contingent resources, a tribute to the inventiveness of the domestic industry, but also a price trajectory that is more convincing with regard to deliver-ability going forward. Throughout, we assume continued difficulties in resolving “aboveground” risk factors encompassed in real or perceived public concerns about drilling and exploitation of unconventional oil and gas resources.

Oil-price drivers

Since the late 1980s, the portion of dry-gas supply obtained from gas wells (both dry- and wet-gas locations) has dropped from almost three-quarters of domestic production to about two-thirds. If nonassociated gas from condensate and NGL-rich wells is included, the portion of domestic gas supply that is oil-price dependent or influenced is even larger. That split will be bolstered further by the eventual capture of gas currently being flared or reinjected from oil-producing areas like the North Dakota Bakken and Texas Eagle Ford. In a context of higher oil but lower gas prices, the predominance of gas yield from liquids-rich locations could be expected to persist. All of this means that any consideration of natural gas supply and price drivers must incorporate views on global and domestic oil markets.

Here, conventional wisdom is even more entrenched. Expectations are that oil prices will remain stubbornly high, even when U.S. domestic production growth is factored into the equation. There are plenty of good reasons for these views. For one, oil producing and exporting nations, especially those with restive populations and unresolved “Arab Spring” dynamics, have been working to retain a global price target that will yield their critical revenue targets at home. In the face of generally low interest rates and a relatively cheap dollar and Euro, this has meant a higher rather than lower Brent oil price. Emerging market customers—oil users in the large and fast-growing “BRICs” (Brazil, Russia – itself a major producer—, India, China and smaller emerging market countries) – have long been expected to soak up the surplus that a weaker U.S. and very weak Europe might help to create.

And yet, the emerging market growth path appears stretched. Raw materials demand is deteriorating. The bloom has fallen first from the nonfuel commodity rose, with the major metals firms suffering what appears to be the leading edge of a possible global commodity price index retrenchment. A “normal” (read, lower) gross domestic product (GDP) for China coupled with enlargement of the global oil-supply pie that the huge Chinese oil companies are helping to create means lots of barrels looking for markets. Trade deficits from oil imports and the associated fiscal burdens long absorbed by India and other countries are starting to become manifest in lackluster growth outlooks and more cautious views on sovereign risk from capital markets.

For the most part, emerging market and developing countries have maintained expensive subsidies for petroleum products as well as natural gas, electric power and other energy sources. Should these countries find the political will to dispense with expensive administered pricing policies, the downward effect on prospective global oil demand could be profound. China and India have both made moves in this direction. Phasing out subsidy programs usually meets with broad and often violent public reactions. Only time will tell the extent of government fortitude. Add to this unstable mix fears about how the U.S. and other central banks might (or might not) deal with shifts away from accommodating monetary policies used to prop up economies and speed recession recovery, and it becomes easy to push oil prices lower, perhaps sharply. The persistent differential between Brent and U.S. light sweet crude already has tightened. If a softer international oil price market were to develop, the U.S. domestic price would follow suit.

In the least, a lower oil price through 2015 to 2020 would trigger an inverse force on the U.S. domestic natural gas price signal. Shale-oil plays in particular are quite sensitive to crude-oil-price expectations. A higher Henry Hub would be needed to pull investment into incremental dry-gas locations. Whether oil would or could follow a flatter, less volatile long-term price path, which many have suggested in the face of shale-oil production gains, may be just as questionable an expectation as for the U.S. gas price index. There is much geopolitical uncertainty that can undermine oil markets.

Stuck in the middle is wet-gas production and NGLs offtake. A lower oil price means generally lower values for NGLs, which are also in a surplus supply mode and heavily discounted relative to even a year ago or so. Lower NGL prices are impacting drilling decisions. An array of midstream investments are proposed for gas processing and NGL handling, but fractionation margins have deteriorated in the key supply regions.

A test of the master limited partnership (MLP) model is under way as midstream MLPs look to undertake major, leveraged capital investments and restructure their revenue streams through more secure and predictable fee-based contracts with producers. Meanwhile, many producers are rolling out creative midstream strategies to try to balance production.

The industrial link

A potential, still nascent, industrial surge is under way in response to product streams and favorable pricing. We count roughly $110 billion in possible investment, mainly in the Gulf Coast region and mainly in Texas and Louisiana. More than half of this expansion is for projects under consideration, and thus is more speculative. On our base industrial demand of about 19 billion cubic feet per day, the range of additions to demand runs from about 2 billion cubic feet per day (projects in progress) to about 2.7 billion per day (if projects in FEED and permitting are included) to 3.5 billion per day (if the most speculative concepts are counted).

Given the fleet of natural gas demand-building projects that are sensitive to prices, spreads and international arbitrage, a higher gas price and lower oil price would diminish expectations that spreads could support all of the investments being considered. Even a robust oil price with a stronger Henry Hub price would challenge expectations. A worst case would be a resumption of strong domestic prices for both oil and natural gas, given the tenuous economic recovery. Gas-to-liquids (GTLs), natural gas for vehicle transportation (especially in diesel markets), and gas feedstock industries looking to export product (methanol and others) could be revisited and investment streams delayed or shelved.

The last time that natural gas was a “byproduct” of oil production was the late-1940s to early 1950s. By the late-1990s, oil and gas were near parity—price relationships reflected the typical roughly six-to-one conversion. In 2012, natural gas was once again a byproduct. Given the cyclical nature of these businesses, a fair question is whether the prevailing “oil premium” and “gas discount” can be expected to remain over the long run.

The gas-power link

One of the more alluring ideas is to use gas to fuel an increasing share of generation. Increased gas generation already is a reality, with emissions reductions and other benefits to boot. One of the more peculiar paradoxes has been the drag on gas-generation assets with lower natural gas prices. A lower gas price has meant a lower electric power price and, especially for gas turbines installed when Henry Hub was stronger, diminished revenues and asset values.

When gas—or nuclear or coal—units dispatch electricity, they find themselves increasingly bumped by wind-power projects. Dispatch curve surprises have been especially revealing in Texas, where wind power has even, at times, forced baseload lignite off the grid. Dispatch curve tensions are likely to increase as regulators and environmental groups urge build-out of high-voltage transmission to accommodate more wind-power capacity.

Key to power market mysteries is whether organic growth in power will resume. As was alluded to in Part I in the August issue, many electric power managers are convinced that growth in electric power consumption is un- likely to be restored to pre-recession rates. At least in certain regions of the U.S., this assumption is being challenged head on by stronger state economies and population shifts, with the southeastern U.S. and states like Texas in the vanguard. The uncertainty created by the wide, polarized differences concerning future electric power demand makes deployment of gas generation uncertain, albeit more predictable than the future for nuclear and coal. Apart from debate about future growth in electricity demand, a long laundry list of factors impacts the power sector generally, not least gas-fired power, complicating planning and decision making.

We tested several scenarios that combined lower and higher natural gas prices (using our own cycle scenario above), environmental regulations, increased dispatch competition, coal retirements (or not) and other combinations of variables. In all cases, natural gas generation increased, although in some scenarios probably not enough to soak up all of the gas deliverability that many feel could be achieved. If the U.S. Environmental Protection Agency is successful in moving toward implementation of new regulations (restrictions on mercury and other hazardous pollutants, the cross-state pollution rule, or a possible rule on greenhouse gas emissions), and if the natural gas price remains lower rather than higher, our results suggest that gas will increase its share of generation significantly by 2020.

With the most assertive regulatory assumptions and even with the “call” on gas resulting in higher price in the short-term, gas use for power generation could almost double from the current base of about 21 billion cubic feet per day by 2030.

Onward through the fog

Apart from the assumptions and issues outlined here is the particular question of whether electric power companies, their customers and regulators will embrace a greater commitment to gas generation. Certainly, it is a relatively cheap option. But many feel that more, rather than less, diversity in the electric power mix is the best way to ensure reliability. Without power to anchor gas supply growth, and without a resumption of growth in domestic gasoline use to anchor increased oil production, producers and developers will agitate for oil and gas export options.

Achieving sales abroad is viewed to be a viable outlet for the larger volumes of domestic production needed to achieve economies of scale and ensure reduced unit costs for the shale plays. And on this point, the political rubber has really hit the road. Industrial natural gas customers, especially feedstock price-sensitive customers, contend that our resource abundance is best deployed at home and that exports will raise commodity prices. Many of their arguments are eloquent, and are striking chords among federal and state policy makers and regulators.

Are oil and gas exports in the public interest? This could well be one of the defining questions for the remainder of 2013 and the foreseeable future. The debate is countering long-accepted mores on international trade. Does it make sense to allow exports of petrochemical products but not the raw materials? Would preventing exports of crude oil and natural gas have unpleasant repercussions in higher energy prices at home, with negative impacts to U.S. industry? Perhaps most of all, would blocking oil and gas exports offset other, much more pervasive problems that underlie the long decline of U.S. manufacturing?

It would be far better to put labor, regulation, health and safety, trade, fiscal and monetary policy and myriad other roadblocks to U.S. industrial revitalization and growth on the table for open discussion. Trade protection is a poor solution to achieving an industrial renaissance.

Beyond our domestic debate, U.S. oil and gas exports, which buyers hope to get at relatively cheap prices, are seen as a panacea for higher-cost energy and burdensome energy policies abroad. Asians pay upwards of $14 or more for oil-indexed LNG while Europeans pay $8 to $10 with the only “gas price” competition coming in the form of American coal imports, which effectively transfers our Henry Hub savings. Even Mexico’s customers operate in a natural gas market that, with price transparency, would offer a premium to Henry Hub. Consuming nations worldwide and their advocates like the International Energy Agency continually seek to neutralize OPEC’s grip on the oil market and to stave off any similar attempts to influence international gas trade.

Why do Asian and European customers pay so much for energy in the first place? For that matter, why do Mexico’s, hooked as they are to the Canada-U.S. production juggernaut? To a large extent, it is because their domestic industries and home governments have not fostered robust energy sector competition, squeezing out both indigenous and foreign direct investment in energy supply, infrastructure and services. Bottom line, this could be the most important lesson the U.S. experience has to offer the world at large.

Michelle Michot Foss is chief energy economist and program manager for the Bureau of Economic Geology’s Center for Energy Economics (BEG/CEE). She publishes separately and with the Oxford Institute for Energy Studies on U.S. and North American oil and natural gas prices, drivers and markets and leads BEG/CEE’s analysis and modeling on energy futures. Gürcan Gülen is senior energy economist and research associate and manages BEG/CEE’s electric power analysis and modeling. Miranda L. Wainberg is a senior energy advisor for BEG/CEE and has an extensive background in corporate energy finance and energy banking. She specializes in upstream metrics.