GAS-PROCESSING PROFIT MARGIN SERIES BEGINS IN OGJ (2024)

Keith J. Kovacs
Wright Killen & Co.
Houston

Oil & Gas Journal will begin publishing next week a profit-margin indicator for U.S. natural gas processing plants.

This monthly series will be based on plants in Texas, which are the most representative of the industry.

The series will be based on analyses by Wright Killen & Co. (WK), Houston, which also compiles profit-margin indicators for both U.S. refineries and ethylene plants and publishes them monthly in OGJ.

Outlined here are the bases and methods employed by the WK profit-margin indicator for U.S. gas-processing plants. Additionally, this article reviews the historical profitability of the gas-processing industry and key factors affecting these trends.

Texas was selected as the most representative for the industry, reflecting the wide spectrum of gas-processing plants.

The profit performance of Texas' gas plants is of special significance because of the large number of plants and high volume of NGL production in the region (OGJ, July 22, p. 54).

DATA SOURCES

Analysis of various public and private information will indicate the profitability of U.S. gas-processing plants.

The principal public data sources used in WK's analysis are:

NGL production volumes from the Monthly Petroleum Supply (Energy Information Agency of the U.S. Department of Energy)
NGL product prices from Oil Buyers Guide, Platt's Oil-gram Price Report, and Oil Price Information Service
Natural gas prices from Oil & Gas Journal, Natural Gas Week, Inside FERC, Texas Comptroller's office, Natural Gas Monthly (EIA/DOE), plant fuel and shrinkage, and Texas Railroad Commission (RRC) reports.

TYPICAL YIELDS

Texas gas plants produce more NGL than any other U.S. region.

In 1990, Texas production was approximately 664,000 b/d. This production came from more than 300 different gas plants, mostly processing onshore gas with a liquid content averaging approximately 2.6 gal/Mcf processed.

The average Texas gas plant capacity is approximately 54 MMcfd with a 1990 capacity utilization of approximately 65%. The average plant produces approximately 2,100 b/d of raw mix NGL.

Texas NGL yields are shown in Table 1.

Individual monthly yields were used to derive monthly plant revenues. These yields were extracted from DOE data with certain adjustments.

Adjustments were made from 1985 forward to remove isobutane production from certain isomerization units, which is included in the DOE data. These data include finished product output from both standalone NGL fractionators as well as gas plants.

Some of the fractionators have isomerization units, which convert normal butanes into isobutane. This results in an over reporting of isobutane and a corresponding under reporting of normal butane derived only from gas processing at the plant level.

Prior to 1984, the DOE separately reported only the input to these "unfractionated stream" standalone facilities. DOE also reported separate production figures for butane-propane and ethane-propane mixtures.

Therefore, adjustments to the 1981, 1982, and 1983 production data were also made to show only five finished products (that is, ethane, propane, isobutane, normal butane, and natural gasolines).

PROCESSING REVENUES

WK's analysis of gas-plant revenues focuses solely on the production and sale of five NGL products: ethane, propane, normal butane, isobutane, and natural gasoline.

Spot-market product prices were assessed (where available) based on several different publications. Spot low quotes were averaged over each month. Using the low quotes imparts a measure of conservatism to the revenue calculation.

Table 2 presents WK's assessment of historical average annual spot-market prices.

Mont Belvieu was selected as the most representative market for Texas gas-plant NGL production.

Approximately two thirds of the state's production interacts with Mont Belvieu's fractionation, storage, and distribution facilities. Furthermore, nearly all of the state's NGL production is generally priced relative to this market with appropriate location or transportation differentials.

The average gas-plant revenue per gallon of NGL is calculated by multiplying the monthly yields by the appropriate Mont Belvieu prices. The resulting average historical plant gross revenue is summarized on Table 3 on a per-gallon-of-NGL basis.

OPERATING COSTS

WK's processing-margin analysis reflects only cash operating costs associated with a plant site. The operating costs cover four specific items: transportation and fractionation cost (T&F), shrinkage cost, fuel cost, and direct plant operating and maintenance expenses.

The T&F cost is the fee associated with the movement of the NGL products to Mont Belvieu and the cost for fractionation to produce the finished products.
The typical cost for this service was assessed with known pipeline tariffs from West Texas to Mont Belvieu plus a calculation of fractionation costs or fees with use of the relevant fuel, electrical, labor, and other charges appropriate at that time.
The resulting T&F cost calculated for the period is also shown in Table 3. The T&F cost is deducted from the average plant gross revenue to yield a netback to the plant for the sale of the production.
Shrinkage cost is the cost of the heat content or BTUs removed from the wet-gas stream as a result of liquids extraction. This cost varies with the price of the natural gas processed, with the processing contract, and with the liquids removed.
The fuel cost is the cost of the fuel used during the extraction of the raw NGL production.
The cost varies with gas prices and with the amount of fuel consumed per gallon of product.
In any given plant, the amount of fuel consumed varies depending on plant type, on site fractionation facilities, plant loading, compression, and other treating requirements.
Texas Railroad Commission data on plant fuel consumption were used to reflect the average fuel usage for all Texas plants. The average usage ranges between 5.5 and 6.5% of inlet gas volume. This average was adjusted for residue-gas BTU content and to eliminate nonextraction-related fuel uses from the analysis.
The net result was an average Texas gas-plant fuel usage of 0.013 MMBTU/gal of raw NGL mix before fractionation. This average was fairly constant throughout the time period investigated in this analysis.
Direct plant operating and maintenance costs include labor and supervision for plant operations, maintenance, electricity, chemicals, and all on site direct cash costs.

These costs were calculated for the average Texas plant (Table 4). The calculation is based upon WK's experience and industry studies in this area.

These costs exclude all marketing, administrative, and financial overheads; depreciation; and interest as well as any return on assets. They also exclude any additional costs associated with other services provided at the plant site (such as treating, gathering, and fractionating).

SHRINKAGE COST

The largest component of gas-processing cost is shrinkage: the reduction in the heat content of the gas due to the removal of the NGL from the gas stream.

The valuation of shrinkage cost depends upon the processing contract between the gas owner and the plant operator. Contractual methods vary within the industry for arriving at the payment to the gas owner for the shrinkage due to processing.

These variations typically fall into two categories: "keepwhole" or a "percent of liquids."

Under the percent-of-liquids method, the gas owner physically receives a fixed liquid percentage or a fixed revenue share from the NGL extracted from his gas during a given month.

The gas owner generally absorbs the cost of any T&F fees on his share of the liquids as well as 100% of the shrinkage and fuel costs for processing his gas under this method. The gas owner hopes to earn a value equal to or greater than the BTU value of the liquids in the unprocessed gas stream.

This BTU value can be assessed as the natural-gas selling price at the plant tail gate or gas delivery point to a pipeline.

Under this method the gas owner is exposed to most of the risk associated with fluctuations in gas and liquids prices. At low liquids prices, the gas owner could earn less than the alternate BTU value on the extracted liquids under this method.

To overcome this risk, some contracts have a guarantee or "keepwhole" provision.

The keepwhole method simply pays the gas owner for the BTUs removed from his gas stream due to processing. The keepwhole calculation will generally include the BTUs of processing plant fuel allocated to the owner's gas.

Depending upon the contract terms, fuel consumed in gas gathering, treating, and otherwise moving the owner's gas to market may be excluded from this calculation.

In this method, the gas owner breaks even, and any additional payments over keepwhole are negotiated as part of the overall processing contract.

Additional payments depend upon local circ*mstances and other services provided by the processing plant. In the keepwhole method, the price of the BTUs removed is assessed at the natural-gas selling price at the tail gate or gas delivery point to a pipeline.

Regardless of the contract terms, the keepwhole method generally sets a target value for the shrinkage cost. Gas owners are generally unwilling to accept less than the keepwhole to process their gas without some other offsetting benefits.

Plant operators are generally unwilling to pay substantially more than keepwhole because they can and do provide other services, which allow the gas to be marketed.

WK's assessment of the industry average shrinkage cost uses the keepwhole method without any additional processing payments to the gas owner. Our calculation multiplies the monthly product yield percentages by the BTU heat content of each liquid (that is, ethane, propane, or another).

The BTU heat content of each liquid is a constant from GPA publication 2145. The resulting weighted average heat content of the extracted liquid mix varies with the changing monthly yields. Typically, the heat content of the mix averages about 89 MBTU/gal.

WK's assessment of gas prices is based upon the averages of the monthly spot market quotes for Texas gas sales delivered to pipelines from several published sources.

The pipeline-delivered quotes are used rather than wellhead prices. This is to account for field gathering costs from the wellhead to the plant.

WK's annual average Texas gas price assessments at the plant tailgate appear on Table 4.

An historical plot of these monthly gas prices appears in Fig. 1.

The resulting shrinkage cost in cents per gallon of raw NGL mix is summarized in Table 5 along with other costs and revenues.

PROCESSING MARGINS

The data and analyses discussed here have been combined into a computerized margin calculation. The results of that calculation are summarized in Table 5. Fig. 2 presents a monthly plot of the gas-processing cash margin resulting from the calculation.

This representation provides the cash operating income for Texas gas plants on a combined average basis. Individual plant margins should in general track this history, but individual plant cash margins will vary depending on the following variables:

Plant location relative to gas and NGL markets
Wet-gas composition
Gas volumes available for processing
Processing contract terms
Plant design, flexibility, and capacity utilization
Additional services provided or required
Gas-transportation costs to and from the plant
NGL-transportation costs from the plant.

This margin analysis can also be used to calculate the average gas owner's breakeven percentage of gross liquids. This is the minimum percentage of gross liquids revenue that the gas owner would need to make the processing an attractive alternative to selling unprocessed gas.

This breakeven percentage is calculated by dividing the shrinkage, fuel, and T&F costs by the gross revenue. The result of that calculation appears in Table 6 and Fig. 2.

When the breakeven value is low (that is, 50-60%), gas plants are more profitable. The plant operator can then offer a slightly higher percentage to the gas owner to induce processing.

When the breakeven value is high (that is, 80-90%), the plant operator typically is operating at a loss and not covering fixed O&M (overhead and maintenance) expenses.

The breakeven percentage will vary for each plant and package of gas processed. The average percentage described here, however, is a good average indicator of the trend in percent of liquids share required by gas owners.

PERSPECTIVE

An examination and analysis of the historical and most recent gas-processing cash margins trends appearing in Fig. 2 lead to the following observations:

During the 5-year period 1981 to 1985, gas-processing profits were able to sustain relatively attractive levels (that is, $0.10-0.30/gal). During this period natural gas was valued substantially below crude oil and petroleum products.
The U.S. average wellhead price for natural gas ranged between 35 and 57% of the BTU value for U.S. refinery average crude cost during this period.
Furthermore, crude oil and related products, like NGLs, experienced higher absolute prices. This is reflected by the net gas-plant revenues of $0.46 to $0.36/gal during this period as compared to values near $0.20/gal starting in 1986.
During the 4-year period 1986 to 1989, gas-processing margins were driven down by a steep decline in crude oil prices.
Gas markets also went through major changes during this period. Most gas prices were decontrolled at this time, and a subsequent spot market for gas developed. Spot gas prices took on seasonal swings which further affected gas-processing margins by driving them higher in the summer but lower in the winter.
Natural-gas wellhead prices ranged from 58 to 84% of a refiner's average crude-oil costs.
These market shifts resulted in a substantial narrowing of the gas-processing margins during this period.
Margins improved starting in the last half of 1990 as crude-oil prices responded to the Persian Gulf crisis. This improvement was also aided by the continued low level of gas prices, which failed to follow the rise in oil prices on a relative basis.
Recent first-quarter 1991 processing margins have dropped $0.20/gal from the $0.30/gal October 1990 values shown in Fig. 2. Second and third-quarter margins continued to improve.
Based upon the past, the longer-term outlook for gas-processing margins would appear to be most affected by those factors also affecting oil and gas prices.

Gas-processing margins will also be affected by such new factors as new olefin-plant demands for ethane and other feeds, alternative transportation fuel use for propane, methyl tertiary butyl ether (MTBE) demand, Rvp reductions for butanes, and changes in international LPG trade patterns.

WK believes that the methods described here provide a reliable basis for analysis of the general gas-processing industry trends and also provide a base upon which to forecast trends.

Direct comparison of any one plant or group of plants to the average, however, must account for the appropriate differences between a local situation and the overall average.