Monday Jun 24, 2013
- Tuesday Jun 25, 2013 -
Philadelphia, Pennsylvania - USA
Data Informed´s Marketing Analytics and Customer Engagement provides marketing, sales, and customer support managers with the information they need to create an effective data-driven customer strategy. more...
Monday May 20, 2013
- Saturday May 25, 2013
- 8:30 AM Eastern -
Stowe, Vermont - USA
Legal Essentials for Utility Executives: May 19 to 25, 2013 and October 6 to 12, 2013 This rigorous, two-week course will provide electric utility executives with the legal foundation to more fully understand the utility regulatory framework, the role of more...
We know you have something to say!
There is an immediate need for articles on
the hot topics in the Power Industry!
EnergyPulse, like no other publication,
also provides a means for our readers to
immediately interact with experts like you.
I published an article in EnergyPulse November of last year regarding stable electricity markets. The same analysis applies to natural gas – there are fundamental changes in the natural gas market structure that is amplifying the swings in market prices and shortening the oversupply/undersupply swings.
The months to expiration graph is a forward looking expression, in this case 60 months, of the relationship between the last date a producer can decide to drill a new well and have it on line (“production option”) and the last date a consumer can decide to buy gas and have it delivered (“purchase option”). As everyone in the natural gas industry realizes, that time spread is significant since the consumer can always wait until at least the day before delivery to purchase. The time spread between the expiration of the production option and the purchase option have profound impacts on the stability of a commodity market – any commodity market.
The market price axis indicates – in the producer case – what price must be obtainable, risk free, by the producer when the well will be producing for the investment to be made now or – in the purchaser case – what price must be made to win the competition for available resources on the purchase date if no other supply is added. Note that the purchase price can easily rise above the replacement cost in the short term at any time after the production option expires. This seems reasonable – once the production option expires the only way to assure purchase of the commodity is to out compete other buyers for the available resource. We have seen this in natural gas, electricity, crude oil and other commodities.
In this case I have taken a two-year lead-time for the time between the decision to drill and the flow of gas to the pipe – not far off for offshore Gulf of Mexico in the existing offshore pipeline gird region, shorter for onshore, longer for deep water. This graph illustrates the reality that the ability to add new supply expires significantly before the purchaser must make the election to consume. The option to build new supply capacity cannot influence the market price for natural gas once it has expired unexercised. Unlike electricity, natural gas has never incorporated capacity charges in its structure so that open market pricing is the only revenue source for the producer (capacity charges can act as revenue assurances for producers – reducing the risk for exercising the production option and therefore the market price needed to induce investment). I would argue the old “take or pay” contracts were another mechanism that paid for reliability in that consumers “paid” for capacity even if they didn’t use it. As we saw, it ended up paying with the market paying for “too much” reliability at too high a price.
A significant difference between natural gas and electricity is the presence of storage. Everyone always talks of the “influence” of storage on natural gas and the “special” nature of electricity because of its lack of storage. But why does it make the market more stable? The reason is the interaction of the storage capacity and the production option – not just the purchase option.
Storage allows the shifting of excess supply capacity from one period to another – allowing reliability to “accrue” forward as an inventory. In doing so it makes the apparent expiration of the production option occur closer in time to the purchase option, thereby allowing a closer coupling of pricing signals. If the production option is not exercised, the inventory can be drawn on. As the inventory is drawn on market prices go up, creating more incentive to exercise the production option. If the inventory can assure any given annual demand is met, then the market price will be “stretched” forward – reducing the apparent lag time between the production and purchase options. Three factors have changed in natural gas to reduce that coupling effect.
First, the amount of storage vis-à-vis the total annual demand has decreased. That means that the ability of the storage to provide multi-year shifting of supply reliability has diminished. Therefore, the apparent expiration of the production option is sliding further away from the purchase option. The producer has greater risk of shift in the supply/demand balance (what if a big new field is discovered before the well comes on line) and in the market price between the exercise date of the option and the commencement of production.
Second, actual turn around time for the production process has lengthened. It used to be significant production could be found in onshore Mid-continent and Gulf Coast fields near existing pipelines. Those fields are not as plentiful today. Therefore fields must be found that are more constrained in pipeline capacity or in deeper water – increasing the lead-time to market. Therefore, expiration of the production option slides further out in the future.
Third, this also means that the producer has to extend further out in the future to hedge the investment risk. The collapse of market liquidity and the increasing collateralization of transactions mean that there is a huge working capital at risk issue associated with long dated hedging. What if the producer hedges 50% of three years worth of production at current prices and prices go up 100% (can we remember last winter)? The margin call would add 1.5 times annual revenues to the investment before a single molecule flows. This is a significant factor in the investment risk decision – for if you don’t risk you have the opposite risk of a price drop destroying the expected return on investment.
The other side of the equation is the consumer. A stable open market price of any commodity only occurs when the producing community is able to invest in exercising production options at a price that the demand side of the market is willing to pay for reliable supply of that commodity. If the price necessary to incentivize investment in adequate supply is higher than the short-term price, then the market will have “boom-bust” cycles. The corollary that seems to be frequently ignored is that if short-term prices rise because of inability to get adequate supply, then the demand side will seek other methods to reduce the cost of that reliability (increased efficiency, fuel switching, etc.) Therefore, long-term supply shortages are unlikely to occur – the demand for reliability (production options) is too price elastic in the mid to long term.
The implication is that natural gas is looking less and less like the crude oil market and more and more like the electricity market (though crude is getting there too – please note the SPR would not be a factor in this analysis as it is not available to the market to provide reliability except as a political decision). This does not mean we are looking at always increasing natural gas prices. In fact, the longer lead time leads to the logical conclusion that natural gas will see similar over investment in production capacity as we saw in the 1998-2002 period in the electricity market. This leads to the expectation of greater likelihood of systemic oversupply and undersupply problems. This model works well for finding the regulatory structures in the curtailment periods of the late 70’s and then price deregulation in the early 80’s – the storage system actually caused the extension of the “gas bubble” into the “gas sausage” – causing over subscription of the production option and then collapse of the open market price and volatility. The model now indicates that the swings will every bit as violent as that period just much shorter in duration.
All this being said, the model argues strongly against decade long chronic shortages. Belief that “the paradigm has changed” and “we are in a new environment” is the basis for foreclosure sales. The relationship of the lag between the production option and the purchase option works just as well in the natural gas market as it does in the electricity market as it does in the crude market as it does ….
This story first ran in substantially similar form in a recent issue of the weekly trade journal, The Desk.
For information on purchasing reprints of this article, contact sales. Copyright 2013 CyberTech, Inc.
It should be possible for customers concerned about assured supply and/or stable prices to contract with suppliers concerned about the same issues, without take-or-pay provisions. Such contracts would help damp the price cycles in the market in general. They would also reduce the perceived risks of drilling in deeper water or in tighter formations, which will be necessary to develop the quantities of gas required to meet growing demand.
Anne Keller 12.12.03
In my opinion, this is your best article so far, Tom. Great way of using real options language to make the point that "high prices are the cure for high prices". And a reason why we're forecasting a falloff in gas prices in the not too distant future. All the excitement about LNG is based on today's prices, and conveniently ignores the impact that the passage of too much time will have on demand. Customers who believe that we're in a new world of high prices will react as well.
This is also another argument for the return of the bilateral contract - a new form of take or pay, if you will, negotiated in a deregulated environment. The certainty of having an ongoing relationship with a supplier and the ability to manage price risk in an actively traded futures market could set the stage for a bright future for the companies who can make it happen. Consumers savvy enough to be able to price the risk of downtime or lost production will be in a good position to know the "real" price they can pay, which in the future will need to include some type of baseload fee to ensure deliverability, as producers are no longer in the position of having lots of working capital to finance long term development and a hedge program.
Charles Masterson 12.16.03
In retail electricity, sellers and buyers prefer fixed price contracts - 2 to 3 years. They put it to rest and don't worry about it - unless rates come down and they can extend and blend. In natural gas, it seems the opposite. It is hard to get either party interested in fixed prices. Its like they don't know how to do it.
Producers love to ride the market up, but then neglect to lock in. They always wait until its too late. Likewise, consumers ride the market down, then fail to lock in when rates are low. They wait too long, too!
It seems to me it is a cultural thing. They never go for the bird in hand, always hoping to squeeze a bit more out of the market, not willing to give up a nickel, but willing to lose a dime. Maybe it is just hard to change old habits, or maybe they just like the volatility and excitment. Whatever it is, both buyers and sellers are contributing.
Murray Duffin 12.17.03
The problem with this analysis is that the underlying model is based on the unstated assumption that supply is available at some price, and the demand is readily destroyable or substitutable. What if such assumptions are not valid? On the supply side, gas drilling rigs in use in the USA went from about 500 in Q2 1999 to near 1300 in Q3 2001 and domestic supply went from 51 Bcf/d to 50.8. The corresponding price run up led to a major one time demand destruction and substitution that cannot be repeated. When rig use dropped back to about 750 in Q2 2002, because there was a price collapse resulting from the demand destruction, and from some increase in supply from Canada, domestic production dropped to 48.1 Bcf/d. As prices recovered in 2003 rig use went back up to 1110 and supply continued to drop to under 47Bcf/d. This time Canadian supply is dropping also, because Canadian production is also in decline, despite increased drilling. Canadian exports to the USA YTD Sept. '03 were down about 7% and down 13% for the month of Sept., vs 2002, despite strong prices. LNG supply has about doubled from a vanishingly small number to a miniscule number, but can't grow much more in the short run brcause the infrastructure (terminals and tankers) doesn't exist. Reduced NGL stripping helped supply this summer, but is likely to be a negative going forward because of rising oil prices. Demand is now very sticky because the easy industrial demand destruction and substitution already took place before 2003, and because other demand continues to grow, both because of baseline growth in the consumer and electrical generation sectors, and because of economic recovery. Price volatility is now due to demand outstripping supply at any reasonable price, and at even pretty unreasonable prices, to the extent that summer injections to storage cannot meet needed winter withdrawals, unless weather is exceptionally benign. Higher prices cannot change the supply picture to any degree because there aren't enough drilling rigs or good prospects to offset the declining production of large old basins at any price. New developments during 2003 in the deepwater GOM should stabilize supply for a few months in 2004, but that will only lead to more volatility later. Your model needs to be refined to include non-price determined supply constraints. Murray Duffin
Thomas Lord 12.18.03
Actually the model does inherently consider non-price determined supply constraints. If the supply response can not meet the market demand, then the "cost" of reliability - i.e., the price at which supply can be assured must rise to force demand away from the product until the remaining consumers are tose willing to pay the clearing price for available supply. Obviously, the short -term price will rise above that stability price because the new supply will arrive AFTER the shortage starts. Your point is that the supply "pulled" into the market by higher prices may not equal the prior supply level. Tius is true - but significantly higher prices will encourage some supply response. This will mean that the supply should exceed that available in the interim period - that would then require the price to sink to a level to encourage some of the "demand destruction" to come back. But, if as you argue, the deliverability decline drops the available supply quickly again, then the price will repidly escalate again to drive demand away, causing another supply response, and so on and so on.
I actually see the "non-price" supply constraints as price supply constraints - at a given price x only so much supply is available. A higher price is needed to either encourage more expensive supplies to be brought on line or to destroy demand. That is the nature of free market pricing. My model is simply to describe the lead-lag components of the price volatility damping signals in the market. There is really no conflict with your point except one of definition.
Murray Duffin 12.18.03
My concern is that supply may be physically unable to respond to price due to fundamental physical limitations. USA NG resources are a major unknown, and reserves (known resources) are very limited. The main tapped reserves are large old gas fields that produce NG freely and rapidly and are now in decline. Future decline rates are not forecastable, but are likely to get worse, and could "fall off a cliff". New fields are smaller and deplete faster, requiring much more drilling just to run in place, or are tight sands or coal bed methane that simply will not yield their gas quickly, no matter how much there is. Maybe 3000 or 4000 active drilling rigs would help, but they don't exist, the crews to operate them don't exist, and the attractive prospects to encourage their development are doubtful. All the big guys are fleeing the USA, and Canada is at least as badly off. A 52" pipeline from Alaska, flowing at 2000 ft/sec will only deliver 0.9 Tcf/yr, offsetting a decline of less than 5%, or less than 2 years at recent rates, and won't be available before 2010, regardless of how much NG there may be in Alaska. The USA has no facility to produce 52" pipes, and steelworkers will block imports. Two 36" pipelines, which we can produce, will deliver the same amount of gas, but require much more steel and take longer to build.. To supply only 2 Tcf of LNG will require construction of about 10 additional terminals and 60 to 80 tankers, none of which are started yet. Expanding existing terminals will be done by 2007, but will only increase supply by 1%, and that only if the tankers are available. From now to about 2012 we are likely to see declining gas supply, regardless of price, so the price stabilizer will be demand destruction and substitution, which may stay very sticky up to quite high gas prices, especially if we have some years of good economic growth and/or "normal" (rather than benign) weather. The normally expected economic responses ro prices is very likely not possible. Murray
Thomas Lord 12.18.03
This all may be correct - the model is not predicated on the availability of large cheap reserves. Your comments point to a cyclical price response around an imbedded long term upward price trend. The model, in later incarnations, includes the decline rate of extraction resources as a component of the market structure - a reason why natural gas may have an upward trend whereas a conversion market - such as elecricity - has a "boom-bust" cycle predicated solely on long term demand growth and the minimal impact of the retirement of aging production facilities. (most of which retirements are driven by financial reasons rather than solely engineering ones). I must admit I am less pessimistic than you on the natural gas front. In work done with major oil service firms in the later 90s I was made aware that the changes in technology of drilling have made the front year impacts of rig counts much higher today. Directional drilling and 3D seismic make a rig today about 3 times as efficient as a rig in the early 1980s. This mitigates some of the impact of the decline in prospect quality today. My anecdotal evidence from the mid to small producers and the evidence from their 10K and 10Q filings is that many are showing 100+% reserve replacements this year - not a sign of a massive supply drop off. The market is obviously in a "put up or shut up" mode for any bear on pricing but the long term curve is still unconvinced that shortages - as opposed to just higher structural pricing - are inevitable.
Murray Duffin 12.19.03
See above drilling results for 1999 thru 2003. I assume the late 90's technology you speak of was already in place. 100% reserve replacements have been pretty consistent for at least the last 12 years (could be 20 years but I can't find my reference right now). How much of the replacement was acquisitions? The problem is not quantity per se, it is rate of extraction. Wells in tight sands or coal beds, even with directional drilling, require fracturing, deliver relatively slowly and deplete rapidly. Murray
Murray Duffin 1.1.04
See: http://www.simmonsco-intl.com/files/IAEE%20Mini%20Conf.pdf. Strong support from an expert source. Murray