ARE PROCESSING FEES GOING UP, OR GOING DOWN?

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ARE PROCESSING FEES GOING UP,

OR GOING DOWN ?

by

Ib Moller, P.Eng.

President

Moller & Associates Ltd.

Joint Venture Consulting

This paper looks at the general state of gas processing fees today, by comparison to processing fees calculated over the past 30 years. Scenarios are painted and processing fees are calculated for a sample gas plant at various stages in its life, from first construction in 1970, to today. Using these scenarios, the paper compares how processing fees were calculated, the conditions facing the processor that was calculating the fees, and the effect on the producers that used the plant for processing of their gas. Using this analysis, an opinion on the direction of gas processing fees, up or down, is developed.

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Are Processing Fees Going Up, or Going Down ?

by Ib Moller

The question is "Are Processing Fees Going Up, or Going Down?" The answer is "it depends" on your perspective and circumstances. In my informal poll of joint venture representatives and operations engineers, I found some felt that processing fees are going up, and some felt that processing fees are going down. One thing that all agreed on, was that processing fees are going down when there is competition for processing. They also agree that the major companies that control the larger processing facilities, have generally adjusted their processing fees (down) to meet competition, or to avoid producers taking their processing fee issues to the regulatory bodies. These companies are reluctant to admit that they have actually lowered their processing fees over the past few years, but most agree that they "have become more sensitive to their producer customers."

In order for processing fees to be lowered, they must at some time in the past have been higher. To really understand the current industry perceptions about processing fees, we need to take a look at the derivation of processing fees, and reference the circumstances under which these processing fees were calculated. We also need to analyze the producers' reactions to processing fees at various stages in the short history of the gas production and processing in Western Canada.

Jumping Pound Formula

In Western Canada, the calculation of processing fees started with a 1959 decision of the Public Utilities Board in which producers were given approval to deduct the cost of processing gas from royalties payable for gas produced in the Jumping Pound Field west of Calgary. The Public Utilities Board ruled that reasonable processing fees should be calculated by allowing the producer a return on capital invested in the processing facilities, plus a return of operating costs. This was the start of the Jumping Pound Formula, that has since been used by the Crown in Alberta to calculate processing deductions for Crown royalties. It is also commonly referred to as Gas Cost Allowance, or "GCA". Processing fees, and royalty deductions have been calculated using derivations of the Jumping Pound Formula since the early sixties. One of the keys to the Jumping Pound Formula is that, along with operating costs, the processor should be allowed a return on its capital invested in processing facilities. The rate of return ("ROR") was derived independently for each case in front of the Public Utilities Board. For instance, in a 1961 case involving the British American Oil Company and the Pincher Creek Unit royalty owners, BA argued that most oil producers used equity to finance facilities, so they requested a 13.5% ROR on 85% equity, and a 5.09% on 15% debt, for an average ROR of 12.25%. The royalty owners argued that the facilities were constructed based on the issuance of shares, so th ROR

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should be 12.75% on 25% equity and 5.75% on 75% debt, for an average ROR of 7.5%. The Board ruled that the ROR should based on the following:

• 50% Debt @ 5.09%

• 10% Preferred @ 7.00%

• 40% Common @ 12.5%

for an average ROR of 8.25%. This ROR was then subject to a complex tax calculation which included such items as deductability of interst paid on the "debt" part of the investment; which all resulted in an equivalent ROR before tax of 13.95%being required by the processor. A corporate tax rate of 50% was used in the calculations. We need not further examine processing fee claculations in the early 60's. At that time, many of our larger gas fields were just bing developed and gas processing plants were being constructed by the owners of the gas reserves. Most plants were also full, at least in the winter time during peak gas demands, so little capacity was available for processing third party gas.

Early 70's

By the late 60's and early 70's, natural gas had become the heating fuel of choice for most Albertans, in the cities at least, and for most Canadians from Ontario west. Developlment of new gas fields was continuing at a rapid pace, as was construction of new gas plants. Some "spare" capacity was available in gas plants and owners were making deals for processing third party gas. Most processing agreements from this era included a formula for calculating the processing fee; this formula was generally patterned after the Jumping Pound formula. The formula included returns on capital invested depreciation and operating costs, and was calculated based on plant throughput. Some of these formulas required the annual input of enourmous amounts of data; for instance the Hudson's Bay Oil and Gas formulas included calculations of the average capital employed in the plant warehouse over the years. Overall, the processing fee formula covered two complete pages. Typically, the ROR in the formula was calculated based on an after tax rate of return of 8-10%, requiring that the processor charge a before tax rate of return approximately 16%.

In order to compare fee calculations through various periods, we can calculate fees in a sample plant, assumed to have been built in 1970. In the sample calculation (using a much simplified formula), we have assumed that a 50MMCFD plant was constructed for $6.9 million, that it was full, with 10MMCFD of third party gas being processed, and that it cost $680,000 per year to operate.

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Processing Fee - 1970

Capital Rate Base $6,900,000 (as built)

Rate of Return 15.6% Before Tax (8.25% AT)

Depreciation 5% /year

Working Capital $ 113,333 /year

Capacity 50,000 MMCF/D

Capital Fee $ 0.08 /mcf Custom Processed 10,000 MMCF/D Lost GCA $ - /year Operating Costs $680,000 /year

Throughput 50,000 MMCF/D

Operating Fee $ 0.04 /mcf Processing Fee $ 0.12 /mcf

The formula calculates a capital fee of $0.08/mcf, operating fee of $0.04/mcf, for a total fee of $0.12/mcf. Many producers today would feel that this was a good processing fee, some may even expect similar fees today. However we have to evaluate this fee in the context of the then current economics of gas production. In 1970, the long term bond rate was 7.5%; and the average gas price was $0.18/mcf, with a $0.005/mcf annual escalation. (The perceived "good" fee was 67% of the gas price paid to the producers.) At that time, producers were probably concerned about the "high processing fees".

Late 70's

After the oil crunch and the establishment of OPEC, gas prices jumped in 1974, rose rapidly thereafter as oil prices rose. Producers were exploring and developing oil and gas reserves at an ever escalating pace. Oil companies were also taking on debt at an alarming rate. Generally, oil companies were "too busy" to optimize their processing arrangements, so processing fees were still being calculated using the same formula as in the early 70's, with one exception. Most companies were squarely focused on "after tax present value" as their method of evaluating their oil and gas plays, so evaluation of processing arrangements also faced a present value test. This resulted in ROR's being revised to return a corporate hurdle rate of 15% after tax; which required a 30% ROR before tax. This, even though long term bond rates in 1977 were only up slightly from 1970, at 8.15%.

Our sample plant is still full, with 10MMCFD of third party gas being processed. The Processing fee calculation assumes that the rate base for the 1970 vintage plant is the original invested capital depreciated at 5% per year; and that it costs $1,040,00 per

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year to operate. (Operating and capital fees for the sample plant were escalated using the Nelson - Farrar Cost Index).

Capital Rate Base $4,830,000 (depreciated) Rate of Return 30% Before Tax

Capital Fee $ 0.10 /mcf Custom Processed 10,000 MMCF/D

Lost GCA $ - /year Operating Costs $1,040,000 /year

Throughput 50,000 MMCF/D Operating Fee $ 0.06 /mcf Processing Fee $ 0.16 /mcf

The formula calculated a capital fee of $0.10/mcf, and an operating fee of $0.06/mcf, for a total processing fee of $0.16/mcf. This fee is only slightly higher than the fee in the early 70's, but gas prices have risen to above $1.00/mcf, and everyones forcast is for 10-20% annual rises in prices. (This was the era of the famous "hockey stick" forcasts; prices rose faster than the corporate hurdle rates, so the longer you waited, the higher the NPV).

Early 80's

In the early 80's, the financial crunch was finally setting in for the oil companies. (Many oil companies had taken on too much debt by 1983, the banks were pressuring them for additional collateral, and their shares had started falling down the hockey stick.) Most companies started to look at getting extra income wherever they could to pay the interest on their debt. Corporate hurdle rates were generally 20% after tax, which was reflected in the processing fee claculations. Formulas were still used to calculate processing fees, but the formula was often exluded from the agreement, being replaced by a fixed capital rate and a variable operating rate. Through the many mergers in the early 80's, financial records for the individual plants were "lost," so new capital numbers had to be developed for processing fee calculations. This was the start of using "replacement cost" for plant capital. Since the corporate hurdle rates were 20% after tax, most processors used a ROR of 40% before tax in their fee calculations.

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For our sample plant, the replacement cost in 1983 was $16.6 million; operating costs were $1.18 million per year. The processing fee formula also included 5% depreciation of the capital, this was typically calculated on replacement cost. By 1983, our 1970 vintage plant was running at 80% of capacity, with 40 MMCFD throughput. Fees were still calculated based on plant throughput.

Capital Rate Base $16,600,000 (replacement)

Rate of Return 40% Before Tax

Capital Fee $ 0.58 /mcf Custom Processed 10,000 MMCF/D Lost GCA $ - /year Operating Costs $1,180,000 /year

The formula calculates a capital fee of $0.58/mcf (up from $0.10/mcf only 6 years earlier); and an operating fee of $0.08/mcf, for a total processing fee of $0.64/mcf. When processing fees were this "high", why didn't producers complain? Some did, but in context, interest rates and gas prices were also much higher.

Long Term Bond Rate - 5 to 10 Year

0 2 4 6 8 10 12 14 16 18 20 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 Percent

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In the early 80's, interest rates jumped; the 10 year bond rates peaked at 17.95% in September, 1981. (Many oil company staff may remember taking out 19-20% second mortgages in 1991, to buy company shares, or real estate.)

Canadian Export Gas Prices

0 1 2 3 4 5 6 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 $/GJ

Gas prices were above $2.00/mcf; gas exported to the US was priced at $4.94/mcf by the NEB and all producers in Alberta shared in the "export flowback"; this windfall was expected to grow from the then current $0.30/mcf, as gas exports to the US climbed (they were forecast to rise exponentially). In the early 80's, processing fees were generally not an issue for processors, especially when compared to mounting debt, rising interest rates, and pressures from their bankers; coupled with the federal government's moves on oil company profits and their move to "Canadianize" the industry.

Late 80's

By the late 80's, gas marketing had been deregulated, so companies could sell into the export market individually. However, the average price for gas sold to the US had dropped to $2.50/mcf, this equates to an approximate wellhead price of $1.50/mcf. This was also the average gas price in Alberta. On the processing front, most plants were no longer full, and little new gas was being developed as oil companies were reeling from low oil and gas prices. Also, "downsizing" was in vogue, exploration and development of gas reserves was not. Since companies were struggling, processing fees were becoming a big issue: with processors, looking for other sources of income; and with producers, lookin to retain more of the gas revenue.

Processors that had formulas in their processing agreements still used "replacement cost" as the capital base, with 5% depreciation. They now used a ROR of 30% before tax, reflective of a 15% after tax corporate hurdle rate. Fees were still calculated based on throughput, and many added a new "lost CGA" fee to the calculation to reflect the processors loss of deductions for Crown royalties, which was

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caused by the processing of third party gas. The lost GCA fee was highest in underutilized plants, with remaining "GCA capital". Some producers ignored the actual depreciated GCA capital for their plant, instead using "replacement capital' in their lost GCA calculation.)

For our sample plant, throughput has fallen to 60% of capacity, or 30 MMCFD; replacement cost is now $18 million; operating costs are $1.2 million per year (no increase from 1983).

Capital Fee $ 0.59 /mcf Custom Processed 10,000 MMCF/D Lost GCA $ 0.10 /year Operating Costs $1,200,000 /year

The formula calculates a capital fee (including lost GCA) of $0.75/mcf, and an operating fee of $0.11/mcf, for a processing fee of $0.86/mcf. (Note: this fee is higher than the fee calculated in our 1983 example, even though the 1983 calculation used a 40% ROR.) In context, the gas price in 1989 was $1.50/mcf; the long term bond rate was 9.3%. History repeats itself; just as in the early 70's, processing fees in in the late 80's were more than 50% of the gas prices. One processor with a new sour gas processing plant, that was operating at less than 50% of capacity, actually calculated and charged producers a processing fee of $2.40/mcf of sales gas.

By 1989, producers and royalty owners were clamouring for "lower" fees. This pressure caused the Alberta Government to request that industry try to find a way of negotiating reasonalbe processing fees. The alternative to self regulation was that the government would regulate processing fees. This caused the birth of the JP 90 Task Force, sponsored by CEPAC, IPAC and CPA.

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The JP 90 Task Force recommended that producers and processors negotiate processing fees in a range calculated by the JP 90 formula. This range is calculated by using replacement cost as the rate base in calculatiing the "upper limit", and 50% of cumulative capital as the rate base in calculating the "lower limit". The JP 90 formula also calculates the capital fee based on plant capacity, rather than throughput, thereby leaving the processor with an incentive to increase the utilization of the plant. The JP 90 report provides a formula for calculating a reasonable rate of return. This assumes that the processor should have an after tax ROR that is a 5% premium on the long term bond rate. The formula calculates the required before tax rate of return, assuming the processing income is taxed at an oil company's marginal tax rate. The JP 90 formula includes a lost GCA factor, which is calculated based on the plant's actual remaining GCA capital, after depreciation, and based on the plant actual throughput.

JP 90 required that processors disclose the basis of their processing fee calculations, while negotiating fees. It also provide a dispute reslution mechanism, using the ERCB as a mediator, and ultimate arbitrator of fee disputes. The report was sanctioned by the Alberta government, and the sponsoring industry associations.

Early 90's

After the JP 90 report was issued most processors started to incorporate the JP 90 principles in their processing fee calculations. The lower limit calculation, using 50% of the original capital as a minimum rate base, was quickly adopted by industry. Most processors also started to base capital fees on plant capacity, rather than actual throughput.

In 1993, gas prices firmed up and gas development boomed. Most processors were now more than willing to process gas in their underutilized plants; many needed an infusion of new gas to keep their plants running. Processing fees were generally calculated in accordance with the JP 90 recommendations, but normally negotiated at the "upper limit". Rates of return were also calculated, but usually to give the processor a return equal to its after tax hurdle rate. The most common result was that the processor required a 25% before tax ROR. Some processors were still using the "whatever the market will bear" approach to negotiations, instead of negotiating fees using the JP 90 guidelines.

In our sample plant, throughput had dropped to 20 MMCFD, which is only 40% of capacity; processed third party volumes were 10MMCFD. Replacement cost for our sample plant was $19.2 million; operating costs were $1.15 million (a drop of 2.4% since 1983).

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Capital Fee $ 0.33 /mcf

Custom Processed 10,000 MMCF/D

Lost GCA $ 0.16 /year Operating Costs $1,150,000 /year

The formula calculates a capital fee of $0.48/mcf (including lost GCA calculated per JP 90), and an operating fee of $0.16/mcf, for a processing fee of $0.64. This fee was still considered "high" by producers, who saw long term bond rates of 7.1% and gas prices of $1.60/mcf in 1993. Producers still remembered the $1.25/mcf gas prices in the winter of 91, and the Alberta domestic price bottoming out below $0.90/mcf.

Pressure was still mounting on processors. Some processors were negotiating fees near the JP 90 lower limit in order to tie up the additional gas. To appease a group of owners of outside gas, Gulf started considering ways of rearranging their fee structure at the Rimbey Plant, where outside gas was now over 70% of the plant throughput. This resulted in the Rimbey Plant being set up as a processing center, with all users paying for the functions of the plant used by their gas. This was the first of a wave of gas plants being disassociated from the owners' reserves and production, and being turned into independant processing (profit) centers. Producers, however, generally continued to clamour for "lower" fees.

JP 95

After JP 90, producers still complained that many processors were stating that their fees were calculated in accordance with JP 90, but the processors were either not disclosing the capital and operating data, or were interpreting the JP 90 calculations incorrectly. Misinterpretation of the rate of return calculation by the processors was of particular concern. The JP 95 Task Force was formed by the PJVA to reassess and interpret some of the misunderstood parts of JP 90, and analyse gas processing by third party Gathering and Processing companies ("G&P companies"). Also, JP 90 had called for mediation of fee disputes by the ERCB; the new EUB was no longer staffed to take on this mediation role.

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The JP 95 Report expanded on the ROR calculation, and recommended use of a 20% ROR (before tax) for producer-processors. JP 95 also expanded on the applicability of the JP 90 upper and lower limits in new and old plants. The applicability of the "lost GCA" fee was also discussed; JP 95 recommended that lost GCA be either:

• ignored in processing fee calculations, or

• be calculated based on plant capacity, not plant throughput.

JP 95 was tested in the "courts", by an application by Rider Resources,asking the EUB to declare Canadian Occidental ("CdnOxy") as a common processor, and to set fees for processing at CdnOxy's Keystone Plant. At the EUB hearing, Rider contended that CdnOxy was taking all of Rider's gas products in lieu of a processing fee, and that the equivalent processing fee was in excess of $2.80/mcf. Both sides were made ot submit all data necessary to calculate fees in accordance with JP 90/95; Rider's lower limit calculation was $0.30/mcf; CdnOxy's upper limit calculation was $0.85/mcf. The EUB declared CdnOxy to be a common processor at the Keystone Plant; they also asked that the parties negotiate a fee, rather than hold a "fee" hearing. The parties sucessfully negotiated a processing fee for Rider's gas.

The Rider/CdnOxy hearing set a precedent in producer/processor fee negotiations. The EUB had established that JP90/95 was a reasonable way for processors and producers to negotiate processing fees. Another application was filled with the EUB by Gardiner, on behalf of a group of producers, asking that the Chevron operated Kaybob #3 Plant be declared a common processor and that standard processing fees be set by the EUB. Both sides submitted data in support of JP90/95 fees calculations, and the issue was resolved prior to the EUB hearing. This again supported use of the JP90/95 calculations for negotiating processing fees.

MID 90's

By the mid 90's, the gas prices had stabilized and development of gas reserves continued. Processors were cognizant of:

• the results of the Rider/CdnOxy hearing,

• ever mounting pressure from G&P companies, and

• the need to fill their underutilized facilities.

They were therefore offering "better deals" for processing. Processing fees were now generally calculated using JP90/95 with a capital base that was a reasonable compromise between replacement capital (upper limit JP90/95) and 50% of invested capital (lower limit JP90/95). Most excluded depreciation, choosing instead to have a fixed (undepreciating) capital fee. Lost GCA was seldomly calculated, nor included. The ROR was set at 20%, as recommended by JP95.

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In our sample plant, throughput is still at 40%, or 20MMCFD; third party processing is 10MMCFD. The replacement value of the plant was $19.2 million, but the capital rate base was taken as 50% of the replacement value (tending towards the lower limit of JP90/95); the ROR was 20%; and operating costs were $1.3 million.

Capital Rate Base $9,600,000 (50% of replacement)

Capital Fee $ 0.12 /mcf Custom Processed 10,000 MMCF/D Lost GCA $ 0.01 /year Operating Costs $1,300,000 /year

The formula calculates a capital fee (excludes host GCA) of $0.13/mcf, and an operating fee of $0.18/mcf, for a processing fee of $0.31/mcf. In context, the long term bond rate in 1997 was 7.27%; gas prices were $1.94/mcf. Most producers would have thought that this fee was "reasonable", and a much better alternative than building their own facilities. It was also low enough to prevent competition from G&P companies who were building new, competitive processing facilities in many areas.

1998

In order to be fair to the G&P companies, who in many ways have created the competition required for producers to get lower fees, we should consider the impact of G&P companies on existing processing facilities. G&P companies continue to buy producers' capacity in gas plants, and to maximize use this capacity to process gas, regardless of ownership. We can assume that our sample plant owner sold the plant to a G&P company, and that the G&P company's attempts to expand use of the existing facilities has been successful.

Our sample plant is now operating at 80% capacity (up from 40% a few years ago). All gas is considered to be custom processed, GCA is not a consideration for the G&P company, who has no owned production. The G&P company may have purchased the plant for something less than the current replacement value of $20

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million, but we will assume a capital base of $20 million. The G&P company needs to compete with various trust companies, so they expect a ROR of 10-12% after tax. A G&P company's income is taxed at 44% for gathering and compression and at 37% for processing (a producer's resource based income is taxed at 37%). Most G&P companies do detailed tax calculations, specific to their company. Assume our G&P company requires a ROR of 18% before tax. Depreciation is excluded, since G&P companies typically fix the capital fee. Operating costs have risen to $1.4 million.

Capital Rate Base $20,000,000 (Capital Investment)

Capital Fee $ 0.21 /mcf

Custom Processed 40,000 MMCF/D

Lost GCA $ - /year Operating Costs $1,400,000 /year

The formula now calculates a capital fee of $0.21/mcf (in 1997, the producer/owner expected a capital fee of $0.13/mcf), and an operating fee of $0.10/mcf (lower because of increased throughput, in 1997 it was $0.18/mcf), for a total fee of $0.31/mcf (same as in 1997). We thus see that the G&P company is keeping fees down by filling the plant. Fees could be lower in the future, if the G&P company is successful in reaching 100% capacity utilization. However, the G&P company also hopes to make a profit from any increase in capacity utilization, therefore processing fees are unlikely to drop further.

SUMMARY

As we have seen, the processing fees at our typical gas plant rose from $0.12/mcf in 1970, to a high of $0.86/mcf in 1989, and have now fallen to $0.31/mcf in 1997/98. Meanwhile, the operating portion of the fee rose from $0.04/mcf to $0.18/mcf in 1997, and may fall if capacity utilization increases in 1998. This is typical of processing fees in an older plant.

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Processing Fees 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1970 1977 1983 1989 1993 1997 1998 $ / mcf Cap Fee Op Fee Total Fee CONCLUSIONS

1. High gas prices in the late 70's and early 80's meant that processing fees were not a "significant" part of the producer's economics, even though the fees were much higher than processing fees calculated in the early 70's. Producers were generally not as concerned about processing fees, as they were about getting their gas on stream.

2. The aberration in fees in the early 80's was not as motivated by greed as many current producers would like to believe. Interest rates in excess of 15% in the early 80's caused corporate hurdle rates to climb to 20% after tax, which then required the use of before tax rates of return of 40% in the calculation of processing fees. 3. In the late 80's, processors were still calculating capital fees based on throughput,

thereby causing increases in processing fees as utilization of processing facilities declined. Processors were also too busy "downsizing" to analyze, or correct their fee calculation practices.

4. JP90/95 is now generally used by processors to set limits on processing fee negotiations, and processors are generally using JP 90/95 correctly. Producers should not expect to have processing fees lower than those determined using JP90/95.

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5. Gathering and Processing companies have caused lower processing fees by creating competition for processing of producers' gas, and by increasing plant utilization.

6. Producers will continue to be unhappy that processing fees are not lower, but concerted producer pressure on processing fees only occurs when processing fees erode a significant part of producers' revenues on gas sales.

7. Are processing fees going up, or coming down? In the opinion of the author, they have gone down, and there is probably not much room for fees to go lower, except where the processors have not yet been subjected to competition for processing.