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See related, CEA "Call To Action" here…. -dh |
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U.S. Sen. Lisa Murkowski, (NGP Photo), today conducted a business meeting to markup an original bill to approve the Keystone XL pipeline — reported favorably by the committee on June 18, 2014. 
Below is a note that our friend, reader and Independent Energy Analyst, James Halloran provided. This viewpoint, from one of our favorite oil and gas experts, should be read and fully absorbed by every elected official in Alaska — whose state operating budget is over 90% dependent on oil revenue. Note: Alaska has the highest state per capita debt and per capita spending in America Reference 1, 2, 3). Elected officials and voters should not be playing a blame game with each other or upset with the oil industry for basing a superstructure of state spending based on a volatile commodity. Instead, they should intently focus now on reducing spending and debt so that a high dependency on oil does not portend disaster in the future when prices plunge.
-dh
"Speaking of a natural gas-oriented project being affected by the price of crude oil, here is something to consider (much more on it sometime soon)":
When the US imported more crude oil and a fair amount of natural gas, there was some oil-on-gas competition in some markets. As a result, there was a correlated price between the two commodities. The BTU exchange was one barrel of crude oil for about 6MCF of natural gas, but for marketing reasons the average balance came in one barrel for an average of 8.5 MCF.When we expanded the shale plays and no longer imported much natural gas, the exchange balance disappeared; there was no more oil-on-gas competition. The ratio went to 25 (gas)/1 (oil) or even higher. Heat (BTU) value had nothing to do with it.
Now that we are on the cusp of perhaps exporting crude oil and natural gas, the price relationship, on a global stage, is starting to reappear. We are willing to bet this pricing convergence will only get stronger.
The next day, we ran into Rusty Braziel’s “top ten prognostications for 2015” on his website blog (see below for links). A central theme in many of his ten points deals with the several market tangents of natural gas and crude oil showing up on the global market. In general, we agree with Rusty’s prognostications. We may deal with a few quibbles in future notes, but any such discussion would only detract from getting through this longer-than-normal post.
The Bottom Line: As the various hydrocarbon forms have more global markets, the pricing will become more intertwined and complex.
To assist the time-challenged, we use our usual highlights to help ease through the material.
https://rbnenergy.com/the-top-ten-rbn-energy-prognostications-for-2015-year-of-the-goat
https://rbnenergy.com/the-top-ten-rbn-energy-prognostications-for-2015-year-of-the-goat-5-1
As we enter 2015, the new theme is clearly price. If the combination of domestic markets and exports are not enough to balance supply and demand, something has to give. And that something is price. Price must drop low enough to discourage production by someone. But the realignment of price relationships goes far beyond just producer economics. It impacts all aspects of energy markets, from producers to consumers and from petchem plant operators to gas processors. So this year’s prognostications are mostly about price – where prices are headed and what happens when they get there.
Like any good New Year’s top ten list, we’ll start at number ten and work our way down to number one.
10. Crude prices won't 'rebound' or ‘recover’ any time soon. Welcome to the new normal. $100/bbl crude oil prices are in the rear view mirror, at least for a couple of years. Since 2008, U.S. crude oil imports are down 3.3 MMb/d, and net petroleum product imports have reversed to become exports to the tune of another 1.5 MMb/d. Those barrels that the U.S. used to import are now looking for new homes, and having a hard time finding those markets. With no production cuts in the offing and a significant demand response years away, oversupply looks to be with us for a while. How long? No way to tell. But if you want a corollary, look back at what happened in the crude crash of 1986. (The 1986 crash is a good comparison because it was mostly driven by developments in the crude markets, not like the crash of 2008, which was more driven by macroeconomic factors.) Crude prices declined by more than 60% in early 1986, came back to about 50% of the pre-crash level for the next year, and did not get back to the pre-crash price until three years after that. That rebound (in 1990) only lasted about three months. Then crude prices sunk back below pre-crash levels for another ten years. Ten years! We are certainly not saying that it is going to take fourteen years for prices to recover this time. But don’t expect quick. There is a lot of oil out there in them thair shales.
9. U.S crude oil production won’t decline any time soon. There is some expectation, at least in the popular media, that declining crude prices will soon result in declining U.S. production. After all, tens of billions of dollars have just been whacked out of producer 2015 expected revenues. Last week we calculated $16 billion out of the Bakken alone in Boom Clap – The Sound of My Netback. But those production declines are months away, for at least four reasons: (a) Producers are cutting back drilling, but the rigs that are left are focused on their highest yield sweet spots. No more science projects. The producer’s goal is to maximize revenue, and that means maximize production volume. (b) In recent years a lot of leases signed by producers have HBP (held by production) clauses, requiring drilling and production to hold leases that were acquired at significant costs. Some wells will be drilled and produced to hold these leases, regardless of short term economics. (c) Some producers were wise enough to hedge their prices, and will continue to drill and produce against those higher priced forward sales, and (d) producer economics will be improved by lower drilling service costs, which will be coming down fast in response to lower drilling activity. Continuing high levels of production will not be good for prices. We’ve seen this movie before. Those that were in the gas markets a few years ago when gas prices crashed below $4.00 will remember these factors kept big plays like the Haynesville going strong for years after spot price economics no longer justified most drilling activity.
8. Gas processing has a problem. We explored this issue two weeks ago in Ratio Ga-Ga? – Consequences of a Lower Crude-to-Gas Price Ratio. At that point the Frac Spread (the difference between the price of NGLs and natural gas on a Btu basis) had dropped below $2/MMbu for the first time since 2009. That number is a pretty good indicator of the health (or lack thereof) of natural gas processing. The Frac Spread had averaged $6/MMbtu since mid-2012, and back in 2011 enjoyed a Golden Age above $12/MMbtu. But sadly for gas processors and NGL producers, the Frac Spread closed out 2014 below $2/MMbtu. That spread hardly justifies the cost of processing, much less the cost of transporting the NGLs to market. Don’t blame it on ethane. As of year-end, ethane is back to a price about equal to natural gas, so the frac spread calculation is indifferent as to whether ethane is rejected or not. When the economics for gas processing evaporate (so to speak), processing becomes a cost of doing business, no longer a revenue enhancing opportunity. Whether the pain goes to the processor or producer depends on how the processing contracts between the parties are structured. But one way or the other, someone will be experiencing that pain.
7. Ethane-only petrochemical crackers have a problem. It seemed like a good idea at the time. Build a petrochemical cracker to produce ethylene from cheap ethane, and keep capital costs low by designing only for a single feedstock. It certainly made sense with ethane cheap relative to other NGL feedstocks like propane, butane, and natural gasoline. Well guess what. Back in November, with NGL prices falling with crude oil prices, the margin for running propane in a typical Gulf Coast ethylene cracker nudged above ethane. In early December, butane moved above ethane Then earlier this week, for the first time since 2011, the margin for running natural gasoline was better than ethane.
6. Marcellus gas still has a problem. In 2014, TGP Zone 4 Marcellus prices averaged $1.70/MMbtu below Henry Hub. That was $2.62/MMbtu on an absolute basis. As mentioned above, on New Year’s Eve, TGP Zone 4 was down to only $1.12/MMbtu. From the stand point of producers in the region unfortunate enough not to have take-away capacity out of that market, this is a big problem. Even the most efficient producers drilling the most prolific wells in Northeastern Pennsylvania need at least $2.00/MMbtu to break even. There are new pipelines coming that eventually will help from Spectra, Williams, Kinder Morgan and others (see the blog last week titled I Believe (This) Can Fly—Pursuing Gas Pipeline Projects in the Northeast). But most of those projects won’t be done for another three or four years. In the meantime, TGP Zone 4 Marcellus prices will stay in the doghouse, as will prices across most of the Marcellus and much of the Utica.
5. It is nice that condensate exports are legal, but…. the economics of condensate exports don’t make much sense, at least so far. There is just not enough difference between condensate prices in the U.S. and prices in Asia (the primary international market for U.S. condensates) to justify transporting barrels there from South Texas. The first cargo of condensate under the new BIS rules moved out on July 30th to Korea (new BIS FAQs here). No more than one or two cargos per month have moved out since. Part of the slow start is just getting the export process up and running. But the bigger problem is economics. Most of the cargos that have moved out do not appear to make economic sense. Let’s say it costs you $5 bucks to get from the Eagle Ford to Houston, and $6 bucks to get across a Houston dock and then via ship to the Asia/Pacific region (some of the other cargos were a lot more expensive than that). Then let’s say the international market pays $5 below Brent for stabilized condensate. So back at the wellhead the producer is getting $16 below Brent, or $12 below WTI (Brent vs. WTI was $3.73/bbl on 1/2/2015). Can the producer do better than that in the domestic market? Yup. So we understand most of these cargos have been moving out for strategic reasons – to provide supply diversity to buyers, and to enhance their negotiating leverage with their traditional suppliers – mostly from the Middle East. How much of that strategic buying can continue at current market price differentials is an open question, but probably not enough to justify significant condensate exports unless we see a widening of the Brent vs. WTI differential.
4. Ethane rejection will get messy. Actually it already has. Ethane production remained at 1.1 MMb/d in October according to EIA, and that was before the ethane-to-gas ratio (an indication of the relative value of ethane to the alternative of selling it as gas – called rejection) dropped into historically low territory. That ratio fell into the low 80% range in November, then collapsed to the low 60% range in early December 2014, meaning that Mont Belvieu ethane on a BTU basis was worth only 60% of Henry Hub natural gas. [Backstage Pass subscribers can see the Spotcheck Ethane-to-Gas Ratio Graph, updated each day on rbnenergy.com
During that period of time it is possible that ethane rejection reached somewhere between 400-500 Mbbls, a historically high level. And there was a lot of ethane being burned as fuel in gas plants, at fractionators and other facilities that had access to ethane But the use of ethane as fuel via rejection could have been much more. The economics during most of November and December would justify rejection of almost all ethane everywhere in the U.S. As we pointed out inBack to the Ethane Asylum, there are a variety of reasons why ethane that could be sold for more money as natural gas is recovered anyway, including (a) – inadvertent rejection of propane, (b) timing/consensus on rejection decisions, and (c) the fact that producers have made volumetric and take-or-pay commitments to gas processors, NGL pipelines and fractionators, effectively making those costs ‘sunk’ and thus ignored in the economic decision to reject ethane.
But there is a fourth reason that is becoming a much bigger deal these days, and that is quality problems with the plant tailgate gas. When ethane is rejected, the BTU content of the residue stream increases. Depending on the gas quality, rejection can result in violation of natural gas pipeline BTU content specifications. Up to now, most gas quality problems have been in the Marcellus and Utica markets, and those problems are being solved by new processing and take-away capacity. But if ethane volumes continue to increase, those BTU issues will loom larger in other parts of the country as well. How this plays out depends on a complex interplay between petrochemical cracker demand and growth in wet gas production.
3. There is (another) market share battle coming to Henry Hub natural gas. All that Marcellus and Utica gas moving out of the Northeast (prognostication #6) has to go somewhere. Most of it is slated to move directly to the Gulf Coast on reversed gas pipelines, or will displace gas that previously moved from the Gulf Coast to the Northeast. Either way, a lot of gas looks to be headed toward Louisiana, home of the Henry Hub, price reference point for spot gas prices in the U.S.
Unfortunately, for producers that is not the only gas targeting Louisiana. Northeast gas will slam into supplies moving in to Louisiana from the west, sourced from “wet” gas and associated gas from crude oil plays in TX, NM, OK and ND. Demand from gas fired power generation, industrial gas use and LNG exports should eventually absorb the incremental supply, but not for a few years. The whole scenario is similar to what happened in the 2008-10 timeframe when Rockies gas battled it out with new shale supplies from the Haynesville and Fayetteville, and that was bad for Henry Hub prices. But this time the impact could be even more dramatic, because there is a big difference in the economics of production today.
Back in 2010, the breakeven price for Haynesville was some number just below $4.00/MMbtu. But today many producers in Northeast Pennsylvania can profitably produce gas at prices less than $2.50/MMbtu. Those supplies will be duking it out with producers of associated gas from the Bakken, the Permian, the Anadarko and the Eagle Ford, who – until recently – were making most of their money on the sale of crude oil and condensate. In effect, natural gas for those producers has been a byproduct of crude production. If you buy the argument in prognostication #9 that crude oil production will not be dropping off any time soon, that associated gas from crude oil production will keep coming too. The result will be another battle for market share at the Henry Hub, with dire implications for natural gas prices in the medium term. If you are interested in more information on this issue, see The Battle for Henry Hub – Ominous Implications of Natural Gas Oversupply.
2. Low crude prices could push gas prices higher. Yes, prognostication #3 says lower gas prices are coming in the medium term. But how about longer term? What happens when all that new demand from gas fired power generation, industrial gas use and LNG exports comes online? Well, it might just happen at exactly the wrong time from a supply perspective. That is due to a strange paradox between crude oil and natural gas price relationships. If crude oil prices stay low for an extended period of time (prognostication #10), production from those crude oil plays yielding increased volumes of associated gas – Bakken, the Permian, the Anadarko, Eagle Ford and others will ultimately slip into decline. When they do, their production of byproduct gas will be declining at about the same time new demand is ramping up. We all know what higher demand and lower supply would mean – higher prices for gas. So timing is everything. Gas prices may be lower in the medium term and higher in the longer term. Go figure out how to put that into your investment models.
1. The days of cheap gas relative to crude are behind us. Natural gas has been dirt cheap relative to crude oil since 2009. In one way or another, that price relationship has been the primary driver behind tens of billions in infrastructure investment – pipelines, processing plants, petrochemical facilities, export terminals, industrial plants, you name it. Cheap gas justifies those capital expenditures. But cheap relative to what? To liquid hydrocarbons, of course – meaning crude oil and all sorts of other products with prices that rise and fall with crude prices. At RBN we’ve called it the Great Divide, and have measured the relationship as the simple ratio of the WTI crude price at Cushing divided by the Henry Hub natural gas price. From January 2011 until November 30, 2014 the ratio averaged 27X. It hit an all-time high of 54X in April 2012 when gas was $1.93/MMbtu and crude was $103/bbl. But as of Friday gas was $3/MMbtu and crude was just under $53/bbl, so the ratio was more like 17X. It hit 15X a couple of weeks ago – the lowest level since 2010 (see Ratio Ga-Ga? – Consequences of a Lower Crude-to-Gas Price Ratio).
Several of the prognostications in today’s blog are consequences of the changes in this ratio. NGL prices (mostly tied to crude) are down relative to gas, and that puts the squeeze on gas processors (prognostication #8). Natural gasoline is down relative to ethane (less tied to crude) which may cause problems for ethane-only crackers (prognostication #7). The possibilitythat low crude oil prices could push gas prices higher (prognostication #2) shows just how interrelated these commodities are. But these are only a few examples. There are all sorts of ramifications from a shrinking crude-to-gas ratio for any investment based on cheap gas such as LNG export economics (LNG prices tied to crude), the economics of new ethanol and methanol plants (chemical prices tied to crude), and of course gas-to-liquids plants designed to take cheap gas and make liquid fuels. None of those ramifications are good for investors.
If you look at all of the prognostications in this blog, it should be clear that we are not attempting to predict the price of crude oil or natural gas at any point in time with any degree of specificity. However, we will not shy away from predicting something about the relationship between those prices. The recent adjustment in crude prices should leave no doubt that investors can’t rely on natural gas to remain dirt cheap relative to crude oil. More likely, in the future that ratio is going to bounce around a lot, sometimes getting higher but just as frequently dropping well below the levels of the past few years. Don’t forget, the BTU equivalent ratio between crude and gas is only 5.8 MMBtu/Bbl. So here’s the prognostication: The days when investors can rely on dirt cheap gas relative to crude are behind us. We will see dirt cheap gas again, possibly as soon as this summer. But the days of $100/bbl oil and $3/MMbtu gas for any extended period of time are in the rear view mirror.
Put more succinctly, no longer can you believe – with any pretense of intellectual honesty – that over the long run gas prices will be dirt cheap relative to crude oil. And that impacts just about everything that touches energy markets.
James R. Halloren, Independent Energy Analyst
James R. Halloran
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