Gas processing margins are in structural decline

Sept. 15, 2003
Historical oil and gas pricing data show that gas processing margins are in a long-term decline, a phenomenon not welcomed by processors.

Historical oil and gas pricing data show that gas processing margins are in a long-term decline, a phenomenon not welcomed by processors. As the most recent unprecedented duration of gas prices higher than $5/MMbtu shows, low or nonexistent margins are compelling processors to accelerate a contract restructuring campaign to restore processing plant earnings.

For the present purposes, processing margins or the "frac spread" are defined as the difference between the price of NGLs at Mont Belvieu, Tex., (based on the national average NGL composition) and the price of natural gas at Henry Hub, La., represented by near-month prices on the New York Mercantile Exchange.

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Fig. 1 shows the monthly average processing margin during the past 15 years. Fig. 2 shows NGL and natural gas price data for the margin calculation.

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These indicative margins do not account for the NGL transportation and fractionation fees that typically reduce the netback NGL price at a specific gas plant. They do not reflect the geographic differentials from Henry Hub gas that typically reduce the shrinkage cost in recovering NGLs at a specific plant.

They do, however, indicate the economic framework within which gas processors historically operate.

Oil-gas ratio

A simpler approach for tracking the processing margin is the price ratio between crude oil and natural gas. The oil-gas ratio (OGR) alone is insufficient for long-term forecasting or for day-to-day decision making; however, it does provide a rough proxy for the "keep-whole" processing margin over time.

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This is because NGL prices except ethane correlate closely to crude oil prices. Fig. 3 shows this correlation in a plot of propane-and-heavier NGL prices vs. West Texas Intermediate crude prices.

When the price of oil is approximately 5.8 times the price of gas, the two commodities are priced at parity in terms of heating value. Because NGLs have historically traded at a premium to crude oil on a btu basis, an OGR at btu parity does not necessarily mean processing is uneconomical. As the OGR sinks below parity, however, gas processing soon ceases to be a value-added function.

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Fig. 4 shows the 15-year history of the OGR, using Nymex near-month pricing for West Texas Intermediate at Cushing, Okla., and natural gas at Henry Hub. Although the plot is "noisy," the long-term trend is unmistakable.

Before 1997, the OGR was consistently greater than 8, with the exception of a few months, most notably in late 1993 and early 1994. The OGR first dropped below 7 for an extended period in early 1998, beginning a notoriously bad time for gas processing.

Since 1998, the ratio has continued its long-term decline, occasionally reaching 8 or greater, and it continues to find new lows. During the last 60 months, the OGR averaged 6.9. In contrast, the average value of 7.8 in 2002 was good. The processing margin's relative health last year was obliterated by the bull market for gas, which squeezed the OGR to 5.4 in the first half of 2003.

High-priced gas

For keep-whole processing—in which the producer receives full-btu value for gas at the delivery point and the processor gets the NGL upgrade, if any—the greatest problem is high-priced gas. With a peak monthly average of $6.65/MMbtu in February, gas did not dip below $5.00/MMbtu in the first half of 2003.

It got to this level as a result of persistently strong demand throughout 2002, prompted in part by $2.50-3.50/MMbtu gas prices until September 2002.

The strong demand going into the winter combined with a new influence—apparent tightness of gas supply—driven by less drilling activity, lower initial production rates, and higher initial decline rates for many of the newly drilled gas wells.

A new 28-week gas storage season (Apr. 12-Oct. 24) is now under way; the US Energy Information Administration's weekly gas report has provided clues about the likely trajectory of gas prices.

Beginning in Week 7 of the storage season (week ending May 30), the weekly addition to storage hit 114 bcf. The following week established a new record of 125 bcf, prompting a 60¢ drop in near-month gas on the Nymex.

Despite the extraordinarily high weekly buildups through June, however, gas prices held at higher than the $5.00/MMbtu level until the week of July 16.

The last time gas prices were at comparable levels was in 2001. The weekly inventory build hit 105 bcf on Apr. 27, 2001, and averaged 103 bcf/week for the 12 weeks through July 13. In response, gas prices fell steadily for the entire year.

Last year, in contrast, the weekly build exceeded 90 bcf only twice and averaged 71 bcf/week in the same 12 weeks that 2001 had its big build.

A combination of increased drilling and supply and decreased demand that resulted from higher prices led to the 2003 build rate.

With 2003 weekly storage builds now slightly ahead of the 2001 rate, gas prices may follow a downward trajectory through the end of storage season. Whether this comes true, many industry observers accept that the gas market has reached a new pricing plateau.

Gas-contract design

The long-term erosion and occasional disappearance of processing margins have accelerated the movement away from keep-whole contract design. Major gas processing companies have sustained an effort to reform the processing terms in gas contracts to reflect the narrowed or nonexistent long-term processing margins.

In the course of this contract reformation process, three tiers of gas contracts, correlating chiefly with the richness of the gas, have emerged:

Top tier: rich gas with more than 4 GPM (gal of NGL/Mcf). Gas of this quality is mainly associated gas from oil wells. Rich-gas producing regions like the Permian basin and the central fairway of Oklahoma are where percent-of-proceeds contracts started and where they now predominate.

Producers may have been willing to part with a share of NGLs and gas in these areas because revenues from those products are relatively small compared to oil revenues. Also, the high cost of the low-pressure gathering service required for these wells is often included in the gas contracts.

Bottom tier: lean gas with less than 2 GPM and offshore often less than 1 GPM. Much processing, particularly ethane and propane extraction, is discretionary in these regions and agreements often do not require either party to process when it is uneconomical.

When the keep-whole margin disappeared, pipelines in Louisiana would often accept unprocessed gas streams. The pipelines could ignore the btu specification because they could blend the slightly off-spec 1,050-1,070 btu raw Louisiana gas with large volumes of on-spec gas from Texas.

Middle Tier: 3 GPM gas is the benchmark in the middle tier, which extends roughly 2.5-3.5 GPM. This is where processors have had the greatest difficulty in restructuring contracts away from a keep-whole basis. Gas in some of the best gas areas—San Juan basin, New Mexico and Colorado, Hugoton field, Kansas, Laredo Lobo field, Texas, East Texas—falls precisely in this middle zone.

Two factors make the conversion process difficult in these areas.

First, processing has historically provided a value upgrade most of the time. When ethane margins cycled downward, margins on propane and heavier NGLs continued to provide an upgrade.

Second, most middle-tier gas comes from gas wells. The processing upgrade on this gas is an integral part of well economics when gas prices are low and margins are strong.

Although most of this gas must be processed to satisfy pipeline specifications, producers historically could negotiate contracts in which they share the upside of processing but take little or none of the downside risk of negative margins—a more-frequent scenario in recent years.

January 2001 price inversion

Keep-whole processing first suffered in January 2001, when gas prices exceeded $9.00/MMbtu and any extracted NGLs sold for as little as half of their value if left in the gas stream. The industry didn't just go into ethane-rejection mode; plants throughout the Gulf Coast either shut down or operated to recover as little NGL as possible and still make downstream pipeline specifications.

Prompted by a new phenomenon—the disappearance of the processing upgrade on propane-plus products—rich gas in many places went straight to sales. The processors wanted to capture the gas price for all the btus in the stream.

This lasted only a short time before several pipelines in Louisiana issued operational flow orders not to accept unprocessed gas. This created an uproar in the industry because the pipelines were previously relaxed about enforcing the maximum btu or heavy-end (C5+) specifications.

Nobody accounted for the fact that the pipelines were no longer receiving lean residue gas from Texas. Texas gas streams were close to pipeline specifications and any off-spec gas from Louisiana exacerbated the situation, increasing the chances of liquid slugs reaching pipeline market areas.

In response to the price inversion and pipeline operational flow orders, new provisions were added to many Louisiana gas contracts. The most significant provision is the conditioning clause that allows and compensates for some minimal level of plant operation even when the processing margin is negative. Offshore producers were generally amenable to these changes because they needed to keep $9.00/MMbtu gas flowing in the absence of a contractual requirement for the processor to process it.

New middle-tier contracts

The middle tier is still awaiting wide-scale contract reform. This gas may have longer-term contracts providing producers a keep-whole floor while requiring the processor to process, even at a loss.

Even though only a small portion of this gas could go straight to pipeline, because of quality specifications, some pipelines would historically take some of this middle-tier gas directly into the pipes. This would provide a "keep-whole backstop" for producers when negotiating processing agreements.

As contracts in the middle tier are slowly updated, it is important for producers and processors to focus more on how to maximize overall revenues than only individual revenues. More than any other factor, more money is left on the table between producers and processors in the middle and top tiers due to a failure to invest modest capital in debottlenecking.

The increasing cost of fuel used for gathering and processing, for example, offers numerous optimization opportunities. In the past, the processor would invest capital to modify a plant or gathering system for greater fuel efficiency; however, incremental benefits flowed disproportionately to the producer.

It would be beneficial to all parties to include incentives in gas contracts so that processors could make the investments needed to raise fuel efficiency or reduce gathering-line pressures for the benefit of producers.

One way to accomplish this is for the processor to share incremental production volumes as an incentive to make the investment. Processors and producers both stand to benefit when their interests become better aligned in new contracts that reward either party for increasing overall revenues. F

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The authors Dan Altena is a senior consultant with Barnes & Click Inc., Houston. He spent 3 years with Duke Energy Field Services LP as vice-president-commercial for East Texas, Austin Chalk, and offshore regions; and 14 years with Union Pacific Resources Inc. as engineering manager, business development manager, and in various operations management positions. Altena holds a BS (1981) in chemical engineering from Purdue University.

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Jack Whiteside ([email protected]) is president of Barnes & Click Inc., Dallas. He joined the company in 1977 after working for 7 years at Exxon Corp.'s Baytown, Tex., refinery and 2 years at Howe-Baker Engineers Ltd., Tyler, Tex. Whiteside holds a BS (1968) in chemical engineering from Texas A&M University.

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Jack Brewster founded GPR Advisors in 2000. In 1983, he founded Gas Processors Report and was the editor for 17 years. Before then, he served 2 years with the Gas Processors Association as director of industry affairs. He holds a BA (1965) in economics from Duke University.