NATURAL GAS SUPPLY ASSOCIATION

805 15th Street N.W., Suite 510
Washington, D.C. 20005

NATURAL GAS SUPPLY ASSOCIATION SURVEY:

NATURAL GAS FIELD DELIVERIES & PRODUCTIVE CAPACITY

AS OF JANUARY 1, 1996

EXECUTIVE SUMMARY

The 1996 Natural Gas Supply Association (NGSA) natural gas field deliveries and productive capacity survey reveals the following trends for the 103 gas producer survey respondents. These 103 producers were responsible for 59 percent of the 1994 lower-48 natural gas production.

METHODOLOGY

In February of 1996, NGSA requested the top 500 natural gas production companies to provide survey information on their regional natural gas sales and productive field capacity in the lower-48 states. This ninth annual NGSA survey provides an estimate of the relative 1994 and 1995 utilization levels of natural gas productive capacity, as experienced by 103 survey respondents. The 103 companies included in the 1996 survey tabulation are listed in Appendix A.[1]

This year's survey techniques are identical to those employed last year. All survey information was collected on an operator basis, rather than on an ownership basis, for the seven lower-48 regions defined in Appendix B. A gas field's operator generally has a better understanding of that field's operating characteristics and potential capacity than the non-operator owners. Conducting the survey on an operating basis also eliminated the possibility that co-owners of a gas field would report on the same field more than once, thereby causing a double counting problem for the survey.

The survey collected information on both connected and unconnected gas field capacity. Connected gas field capacity is defined as volume of natural gas that can be injected into the transmission system on a sustainable thirty (30) day basis at a particular reference point in time. Unconnected gas field capacity is the volume of gas (associated with completed gas wells) which could not be injected into the transmission system at a reference point in time, but could be injected within a year after that reference point. For further clarification of these and other survey terms, a Glossary Of Terminology accompanies this report in Appendix C.

Respondents could answer the survey on either a "wet" or "dry" gas basis. All "wet" gas figures were converted into the equivalent "dry" gas figures, by the accountants doing the tabulation, using the conversion factors developed in Appendix D. The conversion ratio between "wet" gas and "dry" gas was developed using the natural gas production data reported by the Energy Information Administration document entitled: "U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 1994 Annual Report". The conversion ratio equals a region's total gas production, as expressed on a dry basis, divided by the region's total gas production, as expressed on a wet basis. Multiplying this conversion factor by the survey's "wet" gas volumes provides the estimated "dry" gas volumes.

The 1996 survey requested all survey respondents to submit estimates of connected and unconnected field capacity for both January 1, 1995 and January 1, 1996. Annual and December field deliveries were also requested for both 1994 and 1995. The reporting of the same information for two points in time permits an analysis of year-to-year trends for a consistent set of respondents.

All survey respondents were asked to neutralize the impact on productive capacity and deliveries that would result from the sale or purchase of gas producing properties which they operated. If a purchase or sale had occurred during 1995, then the respondents were to adjust the January 1, 1995 productive capacity figures and the 1994 field delivery figures to put these figures on a totally consistent basis with the more recently reported volumes. Thus, the sale and/or purchase of gas producing properties should not play a role in either increasing or decreasing the reported amounts of gas productive capacity and gas deliveries.

Finally, the survey asked respondents to estimate the connected capacity's maximum feasible capacity utilization level on both an Annual and December basis. These maximum feasible capacity utilization levels are compared to the actual capacity utilization levels as a means for determining how close capacity was operating to the practical productive limits imposed by maintenance and weather conditions. The maximum feasible capacity utilization levels, however, are neither well defined nor well measured. Rather, they are intended to provide a rough estimate of the practical operating limits previously experienced by the industry.

The individual survey responses were collected and aggregated on a confidential basis by the accounting firm of Deloitte & Touche.

SURVEY COVERAGE OF LOWER-48 NATURAL GAS PRODUCTION

The 103 survey respondents were responsible for 59.0 percent of 1994 lower-48 dry gas production (see Schedule 1). Regional survey coverage is illustrated in Figure 1. On a regional basis, the survey respondents accounted for over 50 percent of the 1994 production in four survey regions: the Offshore Gulf with 81.9 percent coverage, the Rocky Mountain/Pacific with 58.1 percent coverage, the San Juan Basin with 55.9 percent coverage, and the Permian Basin with 54.2 percent coverage. Two of the regions reported between 40 and 50 percent coverage: the Onshore Gulf with 49.0 percent coverage, and the Anadarko Basin with 47.9 percent coverage. Only the East/North Central region posted a survey coverage of less than 40 percent -- specifically 32.9 percent coverage.

Because the survey was not conducted on a random statistical basis, it is impossible to ascertain whether the capacity utilization results are indicative of industry-wide conditions. The survey results regarding connected capacity and field deliveries should not be extrapolated to represent the entire natural gas production industry. Rather, these survey results should be construed as pertaining only to the circumstances reported by the 103 survey respondents.

However, the capacity utilization levels reported for the survey may be more representative of the industry in regions with a high survey coverage. For example, the survey results are probably representative of deliverability conditions in the Offshore Gulf region because the survey coverage is over 80 percent. Conversely, the 33 percent survey coverage for the East/North Central region implies that the survey results tell us little or nothing about deliverability conditions in this region.

SURVEY RESULTS FOR THE U.S. LOWER-48 STATES

I. Natural Gas Field Productive Capacity

A. Changes In Connected Gas Field Capacity Between January 1, 1995 and January 1, 1996

For the 103 survey respondents, lower-48 connected field capacity declined by 194 MMcf/day for a 0.6 percent decrease from January 1, 1995 to January 1, 1996 (see Schedule 2). Five of the seven survey regions posted declines in connected capacity; they are: the Anadarko Basin (-161 MMcf/day; -3.7 percent), Onshore Gulf (-115 MMcf/day; -1.7 percent), Offshore Gulf (-77 MMcf/day; -0.6 percent), Permian Basin (-64 MMcf/day; -2.4 percent), and the San Juan Basin (-28 MMcf/day; -2.0 percent). The two regions posting increases in connected capacity were the Rocky Mtn./Pacific region (+164 MMcf/day; +5.1 percent) and the East/North Central region (+86 MMcf/day; +12.5 percent).

SCHEDULE 1 - RESULTS OF THE
1996 NGSA NATURAL GAS PRODUCER DELIVERABILITY SURVEY:
SURVEY COVERAGE RELATIVE TO EIA 1994 PRODUCTION

SURVEY REGIONSANNUAL 1994
SURVEY PRODUCTION
(MMcf/Day)(Bcf/Year)
1994 EIA GAS PRODUCTION
(Bcf/Year)		PERCENT OF EIA GAS PRODUCTION
1 OFFSHORE GULF11,0864,0464,94281.9%
2 ONSHORE GULF6,3282,3104,71749.0%
3 PERMIAN BASIN2,4368891,64054.2%
4 SAN JUAN BASIN1,37350189655.9%
5 ANADARKO4,1731,5233,17847.9%
6 EAST/NORTH CENTRAL64823671832.9%
7 ROCKY MOUNTAIN/PACIFIC2,8611,0441,79858.1%

TOTAL LOWER-48		28,90310,55017,88959.0%

ONSHORE & OFFSHORE GULF REGIONS COMBINED		17,4146,3569,65965.8%
EIA Data Source: "Advance Summary U.S. Crude Oil, Natural Gas, and Natural Gas Liquids: 1994 Annual Report", Energy Information Administration, DOE/EIDA-0216(94) September 1995, Table 3.

FIGURE 1

SCHEDULE 2 - RESULTS OF THE
1996 NGSA NATURAL GAS PRODUCER DELIVERABILITY SURVEY:
CONNECTED & UNCONNNECTED NATURAL GAS PRODUCTIVE FIELD CAPACITY
(On A Dry Gas Basis)

CONNECTED NATURAL GAS PRODUCTIVE FIELD CAPACITY

(MMcf/Day)
SURVEY REGIONJAN. 1st
1995		JAN. 1st
1996		CHANGE IN MAGNITUDEPERCENT CHANGE
1 OFFSHORE GULF12,53212,456(77)-0.6%
2 ONSHORE GULF6,8376,722(115)-1.7%
3 PERMIAN BASIN2,6372,573(64)-2.4%
4 SAN JUAN BASIN1,4291,401(28)-2.0%
5 ANADARKO BASIN4,3904,230(161)-3.7%
6 EAST/N. CENTRAL6897768612.5%
7 ROCKY MTN/PACIFIC3,2013,3641645.1%
TOTAL31,71531,521(194)-0.6%


UNCONNNECTED NATURAL GAS PRODUCTIVE FIELD CAPACITY

(MMcf/Day)
SURVEY REGIONJAN. 1st
1995		JAN. 1st
1996		CHANGE IN MAGNITUDEPERCENT CHANGE
1 OFFSHORE GULF1,159994(165)-14.3%
2 ONSHORE GULF281112(169)-60.1%
3 PERMIAN BASIN2815(13)-46.0%
4 SAN JUAN BASIN92516168.5%
5 ANADARKO BASIN6850(18)-26.1%
6 EAST/N. CENTRAL1817(1)-3.4%
7 ROCKY MTN/PACIFIC9354(39)-42.0%
TOTAL31,7151,266(368)-23.5%


TOTAL CONNECTED & UNCONNNECTED NATURAL GAS PRODUCTIVE FIELD CAPACITY

(MMcf/Day)
SURVEY REGIONJAN. 1st
1995		JAN. 1st
1996		CHANGE IN MAGNITUDEPERCENT CHANGE
1 OFFSHORE GULF13,69213,450(242)-1.8%
2 ONSHORE GULF7,1176,833(284)-4.0%
3 PERMIAN BASIN2,6652,588(76)-2.9%
4 SAN JUAN BASIN1,4481,425(13)-0.9%
5 ANADARKO BASIN4,4584,279(178)-4.0%
6 EAST/N. CENTRAL7077938612.1%
7 ROCKY MTN/PACIFIC3,2933,4181253.8%
TOTAL33,36932,786(582)-1.7%


UNCONNECTED CAPACITY AS A PERCENT OF TOTAL CAPACITY

(Percent)
SURVEY REGIONJAN. 1st
1995		JAN. 1st
1996
1 OFFSHORE GULF8.5%7.4%
2 ONSHORE GULF3.9%1.6%
3 PERMIAN BASIN1.0%0.6%
4 SAN JUAN BASIN0.6%1.7%
5 ANADARKO BASIN1.5%1.2%
6 EAST/N. CENTRAL2.5%2.1%
7 ROCKY MTN/PACIFIC2.8%1.6%
TOTAL5.0%3.9%

B. Changes In Connected And Unconnected Gas Field Capacity Between January 1, 1995 and January 1, 1996

As of January 1, 1996, unconnected field capacity accounts for 3.9 percent of the total connected and unconnected capacity, which is lower than the 5.0 percent proportion reported for January 1, 1995 (see Schedule 2). Even though the proportion of unconnected capacity declined during 1995, the 3.9 percent level is consistent with unconnected capacity levels reported in prior surveys.

During 1995, total capacity for the 103 survey respondents declined by 582 MMcf/day for a 1.7 percent decrease. This decrease in the total capacity is due to declines in both connected capacity (-194 MMcf/day, -0.6 percent) and in unconnected capacity (-388 MMcf/day, -23.5 percent).

Five of the seven survey regions posted declines in total connected and unconnected field capacity. The Onshore Gulf showed the largest decline in total capacity, which fell by 284 MMcf/day for a 4.0 percent reduction. The next most significant reduction in total capacity occurred in the Offshore Gulf which posted a decline of 242 MMcf/day (-1.8 percent). Other reductions in total capacity occurred in the Anadarko Basin (-178 MMcf/day, -4.0 percent), the Permian Basin (-76 MMcf/day, -2.9 percent), and the San Juan Basin (-13 MMcf/day, -0.9 percent). Increases in total capacity occurred in only two regions: the Rocky Mtn./Pacific (+125 MMcf/day; +3.8 percent) and the East/North Central Region (+86 MMcf/day; +12.1 percent).

II. Connected Gas Field Capacity Utilization Levels

Capacity utilization (i.e., field deliveries divided by connected capacity) can be viewed relative to both prior year utilization levels and to the maximum feasible capacity utilization level. Comparing the current year's utilization level to that of prior years indicates whether the capacity surplus is growing or diminishing. Comparing the current utilization level to the maximum feasible capacity utilization level indicates the degree to which the industry is operating close to its full potential.

A. Productive Capacity Utilization Levels For 1994 And 1995

Schedule 3 and Figures 2 and 3 show each survey region's annual capacity utilization level. Because lower-48 connected capacity for the 103 respondents declined by 0.6 percent during 1995, while 1995 field deliveries increased by 1.7 percent, capacity utilization increased from 91.1 percent in 1994 to 93.3 percent in 1995.

SCHEDULE 3 - RESULTS OF THE
1996 NGSA NATURAL GAS PRODUCER DELIVERABILITY SURVEY:
ANNUAL CONNECTED CAPACITY UTILIZATION LEVELS
(On A Dry Gas Basis)


CONNECTED NATURAL GAS FIELD CAPACITY

(MMcf/Day)
SURVEY REGIONJAN. 1st
1995		JAN. 1st
1996		CHANGE IN MAGNITUDEPERCENT CHANGE
1 OFFSHORE GULF12,53212,456(77)-0.6%
2 ONSHORE GULF6,8376,722(115)-1.7%
3 PERMIAN BASIN2,6372,573(64)-2.4%
4 SAN JUAN BASIN1,4291,401(28)-2.0%
5 ANADARKO BASIN4,3904,230(161)-3.7%
6 EAST/N. CENTRAL6897768612.5%
7 ROCKY MTN/PACIFIC3,2013,3641645.1%
TOTAL31,71531,521(194)-0.6%


ANNUAL NATURAL GAS FIELD DELIVERIES

(MMcf/Day)
SURVEY REGIONANNUAL
1994		ANNUAL
1995		CHANGE IN MAGNITUDEPERCENT CHANGE
1 OFFSHORE GULF11,08611,455369-3.3%
2 ONSHORE GULF6,3286,37042-0.7%
3 PERMIAN BASIN2,4362,4415-0.2%
4 SAN JUAN BASIN1,3731,341(32)-2.4%
5 ANADARKO BASIN4,1733,989(183)-4.4%
6 EAST/N. CENTRAL6487399114.0%
7 ROCKY MTN/PACIFIC2,8613,0642037.1%
TOTAL28,90329,3974941.7%


ANNUAL GAS FIELD CAPACITY UTILIZATION

(Percent)
SURVEY REGIONANNUAL
1994		ANNUAL
1995		CHANGE IN PERCENTANNUAL MAXIMUM FEASIBLE CAPACITY LEVEL
1 OFFSHORE GULF88.5%92.0%3.593.0%
2 ONSHORE GULF92.6%94.8%2.295.7%
3 PERMIAN BASIN92.4%94.8%2.595.2%
4 SAN JUAN BASIN96.1%95.7%-0.495.3%
5 ANADARKO BASIN95.0%94.3%-0.794.8%
6 EAST/N. CENTRAL94.0%95.2%1.295.7%
7 ROCKY MTN/PACIFIC89.4%91.1%1.796.7%
TOTAL91.1%93.3%2.194.5%
ONSHORE/OFFSHORE
GULF REGIONS COMBINED		89.9%92.9%3.093.9%

As shown in Figure 3, five regions posted significant increases in capacity utilization. The largest regional increase in capacity utilization occurred in the Offshore Gulf which increased from 88.5 percent in 1994 to 92.0 percent in 1995. The Offshore Gulf's increase in utilization is due to both a 3.3 percent rise in gas field deliveries and a 0.6 percent decline in connected capacity. The next largest regional increase in capacity utilization occurred in the Permian Basin which rose from 92.4 to 94.8 percent. Permian Basin capacity utilization rose primarily because connected capacity dropped by 2.4 percent while gas deliveries essentially remained constant. The Onshore Gulf posted the third largest increase in utilization of 2.2 percentage points. The Onshore Gulf's increase in annual utilization occurred because connected capacity declined by 1.7 percent while field deliveries rose by 0.7 percent. The Rocky Mtn./Pacific's capacity utilization rose by 1.7 percentage points as the growth in gas field deliveries (+7.1 percent) outstripped the rise in connected capacity (+5.1 percent). The small East/North Central region posted a 1.2 percentage point increase in annual capacity utilization.

Even though two survey regions posted reductions in capacity utilization, these reductions were relatively small. The Anadarko and San Juan Basins posted annual capacity utilization reductions of 0.7 percentage points and 0.4 percentage points, respectively.

B. Comparing Annual Capacity Utilization To The Annual Maximum Feasible Capacity Utilization

A comparison of actual annual utilization levels to the maximum feasible capacity utilization establishes the relative size of the surplus in productive gas field capacity. Figure 2 compares 1994 and 1995 lower-48 capacity utilization levels to the Annual Maximum Feasible Capacity Utilization Level. Because of the small 1.3 percentage point spread between the 1995 utilization level of 93.3 percent and the annual maximum feasible capacity utilization level of 94.6 percent, it appears that the gas production industry is operating at close to full capacity.

The spread between the actual annual utilization, and that which is feasible, is fairly small in most regions. Indeed, one region -- the San Juan Basin -- reported its 1995 annual capacity utilization of 95.7 percent, slightly exceeding the region's annual maximum capacity factor of 95.3 percent.[3]

C. Comparing December Capacity Utilization Levels To The December Maximum Feasible Capacity Utilization

While it is clearly important to have information on the capacity utilization of productive capacity on an annual basis, it is equally important to compare this annual capacity utilization to winter utilization levels. December capacity utilization is one measure of the productive capacity employed during winter production periods.

Schedule 4 reports the 1994 and 1995 December capacity utilization levels along with the December maximum feasible capacity factors. Two differences with the annual figures are apparent. First, December 1995 utilization levels are 3.1 percentage points greater than the 1995 annual utilization levels, while December 1994 utilization is 3.8 percentage points greater than the 1994 annual level. This is consistent with prior surveys which have always reported December utilization levels to be higher than the annual average utilization level. Second, December 1995 capacity utilization of 96.4 percent is 1.5 percentage points higher than the prior December 1994 figure of 94.9 percent.

The fact that the December utilization levels were higher in 1995 than in 1994 is not surprising. December 1994 experienced 1,550 heating degree-days on a national basis, while December 1995 had 1,819 heating degree-days, a 17.4 percent increase.[4] The increase in 1995 December capacity utilization was not commensurate with the increase in national heating degree-days because much of this increased heating load was served through increased gas storage withdrawals rather than through increased gas production.[5]

As shown in Figure 4, December 1995 capacity utilization significantly increased in four of the seven survey regions. The largest increases in December 1995 utilization levels occurred in the following four regions: the Permian Basin (+2.8 percentage points), the Offshore Gulf (+2.4 percentage points), the Onshore Gulf (+2.2 percentage points), and the San Juan Basin (+2.0 percentage points). The Rocky Mountain/Pacific region posted a modest increase in December utilization levels, amounting to a gain of +0.4 percentage points.


SCHEDULE 4 - RESULTS OF THE
1996 NGSA NATURAL GAS PRODUCER DELIVERABILITY SURVEY:
DECEMBER CONNECTED CAPACITY UTILIZATION LEVELS
(On A Dry Gas Basis)


CONNECTED NATURAL GAS FIELD CAPACITY

(MMcf/Day)
SURVEY REGIONJAN. 1st
1995		JAN. 1st
1996		CHANGE IN MAGNITUDEPERCENT CHANGE
1 OFFSHORE GULF12,53212,456(77)-0.6%
2 ONSHORE GULF6,8376,722(115)-1.7%
3 PERMIAN BASIN2,6372,573(64)-2.4%
4 SAN JUAN BASIN1,4291,401(28)-2.0%
5 ANADARKO BASIN4,3904,230(161)-3.7%
6 EAST/N. CENTRAL6897768612.5%
7 ROCKY MTN/PACIFIC3,2013,3641645.1%
TOTAL31,71531,521(194)-0.6%

DECEMBER NATURAL GAS FIELD DELIVERIES

(MMcf/Day)
SURVEY REGIONDEC. 1994DEC. 1995CHANGE IN MAGNITUDEPERCENT CHANGE
1 OFFSHORE GULF11,40411,6322282.0%
2 ONSHORE GULF6,5126,548360.5%
3 PERMIAN BASIN2,5872,59690.3%
4 SAN JUAN BASIN1,3841,38510.0%
5 ANADARKO BASIN4,4174,187(231)-5.2%
6 EAST/N. CENTRAL674738639.4%
7 ROCKY MTN/PACIFIC3,1203,2921725.5%
TOTAL30,09930,3772780.9%


DECEMBER GAS FIELD CAPACITY UTILIZATION

(Percent)
SURVEY REGIONDEC.
1994		DEC.
1995		CHANGE IN PERCENTANNUAL MAXIMUM FEASIBLE CAPACITY LEVEL
1 OFFSHORE GULF91.0%93.4%2.494.0%
2 ONSHORE GULF95.3%97.4%2.296.3%
3 PERMIAN BASIN98.1%100.9%2.895.6%
4 SAN JUAN BASIN96.9%98.9%2.097.6%
5 ANADARKO BASIN100.6%99.0%-1.696.5%
6 EAST/N. CENTRAL97.8%95.1%-2.797.1%
7 ROCKY MTN/PACIFIC97.5%97.9%0.497.3%
TOTAL94.9%96.4%1.595.5%
ONSHORE/OFFSHORE
GULF REGIONS COMBINED		92.5%94.8%2.394.8%


FIGURE 4
FIGURE 4

FIGURE 5
FIGURE 5


The Anadarko and East/North Central regions both posted declines in December utilization, amounting to -1.6 and -2.7 percentage points, respectively. Even though the Anadarko posted a decline in 1995 December capacity utilization, this region operated at essentially full capacity in both December 1994 and December 1995, given that the reported December utilization levels for both periods exceeded that region's December Maximum Feasible Capacity Level.

In total, five regions posted a December 1995 capacity utilization which exceeded their December Maximum Feasible Capacity Utilization; they are: the Onshore Gulf, the Permian Basin, the San Juan Basin, the Anadarko Basin, and the Rocky Mountain/Pacific Region. The regional propensity to exceed the maximum feasible utilization level is replicated on a total lower-48 basis, where the December 1995 capacity utilization of 96.4 percent exceeded the December Maximum Feasible Capacity Level of 95.5 percent. This indicates that gas producers were operating close to or at full capacity during December 1995.

III. Comparing Capacity Utilization Levels For The Last Five NGSA Surveys

Even though the identity of the survey respondents changes for each survey cycle, there is sufficient continuity in the respondent group, especially among large producers, to permit a comparison of this year's survey results to that of the four prior surveys (see Schedule 5 and Figure 5).

Both Schedule 5 and Figure 5 provide insight on the long-term direction of lower-48 capacity utilization trends. For the survey period spanning 1990 through 1995, overall lower-48 capacity utilization increased by approximately +9.3 percentage points, going from 84.0 percent in 1990 to 93.3 percent in 1995.

However, just as annual capacity utilization has increased, gas producers also report an increase in their annual maximum feasible capacity levels. In the 1992 survey, producers reported the annual maximum feasible capacity level to be 91.7 percent for 1990 and 1991. In the 1996 survey, producers raised their estimate of this factor to 94.6 percent for 1994 and 1995. So, gas producers have estimated their maximum feasible utilization levels to have increased by +2.9 percentage points. This increase in the maximum feasible capacity utilization level could have resulted for a couple of reasons. First, as gas producers get closer to a facility's full productive potential, they obtain a clearer estimate of what could realistically be produced. Second, improvements in management and technology could also be responsible for this assessment for a higher maximum. Irrespective of the underlying reasons, the survey indicates that producers are capable of producing a higher proportion of their connected capacity than they were able to do earlier this decade.

SCHEDULE 5 - RESULTS OF THE
1996 NGSA NATURAL GAS PRODUCER DELIVERABILITY SURVEY:
COMPARABLE ANNUAL CONNECTED CAPACITY UTILIZATION LEVELS
FOR THE LAST FIVE NGSA SURVEYS

1992 SURVEYACTUAL CAPACITY UTILIZATIONANNUAL MAXIMUM FEASIBLE CAPACITY LEVELSPARE CAPACITY IN LATEST YEAR 1/
199019911992199319941995
1 OFFSHORE GULF81.9%81.5%----92.2%10.7%
2 ONSHORE GULF87.2%87.4%----92.5%5.1%
3&4 PERMIAN/SAN JUAN86.7%89.2%----91.2%2.0%
5 ANADARKO BASIN83.6%83.4%----90.0%6.6%
6 EAST/N. CENTRAL86.3%92.3%----92.8%0.5%
7 ROCKY MTN/PACIFIC81.3%84.3%----91.2%6.9%
TOTAL84.0%84.5%----91.7%7.2%
1993 SURVEYACTUAL CAPACITY UTILIZATIONANNUAL MAXIMUM FEASIBLE CAPACITY LEVELSPARE CAPACITY IN LATEST YEAR 1/
199019911992199319941995
1 OFFSHORE GULF-84.0%88.5%---92.6%4.1%
2 ONSHORE GULF-87.4%90.4%---93.4%3.0%
3&4 PERMIAN/SAN JUAN-86.6%88.4%---92.6%4.2%
5 ANADARKO BASIN-82.9%84.4%---90.1%5.7%
6 EAST/N. CENTRAL-94.6%93.9%---94.9%1.0%
7 ROCKY MTN/PACIFIC-84.6%88.7%---93.5%4.8%
TOTAL-85.2%88.4%---92.5%4.1%
1994 SURVEYACTUAL CAPACITY UTILIZATIONANNUAL MAXIMUM FEASIBLE CAPACITY LEVELSPARE CAPACITY IN LATEST YEAR 1/
199019911992199319941995
1 OFFSHORE GULF--88.6%88.8%--93.8%5.0%
2 ONSHORE GULF--89.2%93.9%--94.4%0.5%
3&4 PERMIAN/SAN JUAN--84.9%92.2%--94.4%2.2%
5 ANADARKO BASIN--85.0%88.2%--91.4%3.2%
6 EAST/N. CENTRAL--93.1%93.8%--95.8%2.0%
7 ROCKY MTN/PACIFIC--89.0%92.7%--96.0%3.3%
TOTAL--87.8%90.7%--93.9%3.2%
1995 SURVEYACTUAL CAPACITY UTILIZATIONANNUAL MAXIMUM FEASIBLE CAPACITY LEVELSPARE CAPACITY IN LATEST YEAR 1/
199019911992199319941995
1 OFFSHORE GULF---87.5%90.3%-94.5%4.2%
2 ONSHORE GULF---93.2%93.1%-95.2%2.1%
3&4 PERMIAN/SAN JUAN---84.9%92.2%-94.4%2.2%
5 ANADARKO BASIN---89.0%92.9%-93.3%0.4%
6 EAST/N. CENTRAL---93.6%91.7%-94.9%3.2%
7 ROCKY MTN/PACIFIC---91.8%89.6%-95.6%6.0%
TOTAL---90.2%91.5%-94.6%3.1%
1996 SURVEYACTUAL CAPACITY UTILIZATIONANNUAL MAXIMUM FEASIBLE CAPACITY LEVELSPARE CAPACITY IN LATEST YEAR 1/
199019911992199319941995
1 OFFSHORE GULF----88.5%92.0%93.0%1.0%
2 ONSHORE GULF----92.6%94.8%95.7%0.9%
3&4 PERMIAN/SAN JUAN----93.7%95.1%95.2%0.1%
5 ANADARKO BASIN----95.0%94.3%94.8%0.5%
6 EAST/N. CENTRAL----94.0%95.2%95.7%0.5%
7 ROCKY MTN/PACIFIC----89.4%91.1%96.7%5.6%
TOTAL----91.1%93.3%94.6%1.3%

1/ Equals the Annual Max. Feasible Capacity Factor minus the latest period's Annual Utilization Level.

Even though the earlier surveys posted modest annual increases in the annual maximum feasible capacity utilization, this year's survey posts an annual maximum which is identical to that reported by producers in last year's survey. Whether this indicates a stabilization of producer expectations regarding the limits to their production is not clear at this time.

Because wellhead gas utilization has increased much faster than the increase in the annual maximum feasible capacity level, the amount of spare productive capacity has declined from 7.7 percentage points in the 1990 calendar year to 1.3 percentage points in the 1995 calendar year (See Schedule 5). In this context, the improvement in gas field utilization was partly matched by an improved ability of gas producers to operate closer to full capacity (i.e., 100 percent of connected capacity).

APPENDIX A

SURVEY RESPONDENTS INCLUDED IN THE NGSA DELIVERABILITY SURVEY RESULTS

    1. Alamco Inc.
    2. American Exploration Co.
    3. Amoco Production Company
    4. Anadarko Petroleum Corp.
    5. Atlantic Oil Corporation
    6. Badger Oil Corporation
    7. Bright & Company
    8. Browning Oil Company, Inc.
    9. Burk Royalty Co.
    10. Cabot Oil & Gas Corp.
    11. Callon Petroleum Operating Co.
    12. Chevron U.S.A. Production Co.
    13. Clinton Gas Systems
    14. CMS NOMECO Oil & Gas Co.
    15. CNG Producing Company
    16. Coastal Oil & Gas Corp.
    17. Cockrell Oil Corp.
    18. Columbia Natural Resources, Inc.
    19. Columbus Energy Corp.
    20. Conoco Inc.
    21. Continental Resources, Inc.
    22. Crawley Petroleum Corp.
    23. CXY Energy Inc.
    24. Devon Energy Corp.
    25. Dorchester Hugoton Ltd.
    26. Dugan Production Corp.
    27. Eastern America Energy Corp.
    28. Energy Development Corp.
    29. Enex Resources Corp.
    30. Enron Oil & Gas Co.
    31. Ensign Oil & Gas Inc.
    32. Exxon Company U.S.A.
    33. Forest Oil Corporation
    34. Giant Expl. & Prod. Co.
    35. Great River Oil & Gas Corp.
    36. Greenhill Petroleum Corporation
    37. Hexagon Oil & Gas Inc.
    38. HS Resources Inc.
    39. J-W Operating Co.
    40. John H. Hendrix Corp.
    41. John H. Young, Inc.
    42. Kamlok Oil & Gas, Inc.
    43. Kelley Oil & Gas Corp.
    44. Kerns Oil & Gas Inc.
    45. Kerr-McGee Corp.
    46. K.N. Production Company
    47. Luff Exploration Company
    48. Maguire Oil Company
    49. Maralo Inc.
    50. Marathon Oil Company
    51. Meridian Exploration Corp.
    52. Mesa, Inc.
53. Michael Petroleum Corporation
54. Mitchell Energy Corporation
55. Mobil Natural Gas Inc.
56. Murphy Exploration & Production Co.
57. Nearburg Producing Company
58. Newfield Exploration Co.
59. North American Resources Company
60. ONEOK Inc.
61. ORYX Energy Corp.
62. Oxford Oil Company
63. Oxley Petroleum
64. OXY USA Inc.
65. PetroCorp. Inc.
66. Petroleum Development Corp.
67. Phillips Petroleum Corp.
68. P.N.G. Operating Co.
69. Pogo Producing Company
70. River Gas Corporation
71. Seagull Energy E&P Inc.
72. Seneca Resources Corp.
73. Shell Oil Company
74. Slawson Exploration Co., Inc.
75. Southwestern Energy Corp.
76. St. Mary Operating Co.
77. Sullivan and Company
78. Swift Energy Corp.
79. Taurus Exploration, Inc.
80. Tennessee Gas Pipeline Co.
81. Tesoro Expl. & Prod. Co.
82. Texaco Exploration & Production Inc.
83. The Louisiana Land & Expl. Co.
84. The Wiser Oil Company
85. Thums Long Beach Company
86. Tidelands Oil Production Co.
87. Toklan Oil & Gas Corp.
88. Tom Brown Inc.
89. Torch Energy Advisors
90. Trans Texas Gas Corp.
91. Total Minatome Corp.
92. U.S. Department of Energy
93. U.S. Department of Energy-NPOSR-CUW
94. Union Oil of California
95. Union Pacific Resources
96. Vastar Resources, Inc.
97. Vessels Energy Inc.
98. Wagner & Brown Ltd.
99. Walter Oil & Gas Corporation
100. Western Gas Resources, Inc.
101. Williford Energy Company
102. Williston Basin Interstate P/L Co.
103. Yates Petroleum Corp.

APPENDIX B

DEFINITION OF NGSA SURVEY REGIONS

The survey asked for the natural gas field deliveries, productive capacity, and maximum feasible capacity utilization levels for seven lower-48 regions and for the total lower-48 as a whole. The regional breakdown was developed around the major natural gas production basins and the markets they tend to serve. Forty two states are explicitly included in one of the seven regions. Only the six New England states are excluded from consideration due to their lack of any known natural gas production. Any productive capacity in New England should have been included in the East/North Central region.


APPENDIX C

GLOSSARY OF TERMINOLOGY

FOR THE 1996 NATURAL GAS SUPPLY ASSOCIATION

SURVEY ON NATURAL GAS FIELD DELIVERIES

AND PRODUCTIVE CAPACITY

WELLHEAD PRODUCTIVE CAPACITY:

Connected Field Capacity (a.k.a. Connected Capacity)

Connected Field Capacity is defined as the rate at which gas can be physically injected into the intrastate and interstate pipeline network, on a 30-day sustainable basis, under the best of operating conditions (i.e., excluding planned and unplanned downtime). Because the sustainable production rate of a gas field can be lower than the sum of individual gas well deliverability rates, the connected capacity is defined on a field basis rather than on a well basis.

Connected field capacity also takes into account the capacity limitations imposed by gathering systems and gas processing plants. For example, if a group of wells can physically produce 100 MMcf/day of dry gas, but the gathering system can only transport 90 MMcf/day and the gas processing plant can only produce 70 MMcf/day of dry gas, then the connected field capacity is stated as 70 MMcf/day. The difference between the 100 MMcf/day well production potential and the 70 MMcf/day actually produced by the gas processing plant (i.e., 30 MMcf/day) is considered unconnected field capacity.

Gas productive capacity used to operate gas production and processing facilities was excluded from the survey's consideration.

Unconnected Field Capacity (a.k.a. Unconnected Capacity)

Unconnected Field Capacity refers to two different situations. The first situation it addresses is gas wells that have been physically drilled, whether or not physically completed, which could be connected to the pipeline network within a one year period. No specific plans to connect these wells within the next year are necessary for its inclusion in this category. Unconnected field capacity also includes any capacity physically connected to the pipeline network, but unable to produce due to existing gathering and processing limitations.

Natural gas that must be reinjected into the reservoir to maintain reservoir pressure and oil production is excluded from both capacity categories. On the other hand, natural gas being reinjected into the reservoir only because it has no immediate market is either connected capacity (i.e., it could be physically shipped to end-use markets without any impediments) or unconnected capacity (i.e., a bottleneck prevents immediate marketability, but this bottleneck could be removed in one year).

ANNUAL NATURAL GAS FIELD DELIVERIES:

Annual Natural Gas Field Deliveries include all gas deliveries made during the calendar years of 1994 and 1995. The survey emphasizes the level of gas delivered to the transmission network, because a natural gas sale might be put on the accounting books at a time different from that associated with the actual injection of that gas into the transmission network. Natural gas produced and consumed in the field in order to run production and gas processing facilities is not included in the total deliveries figure.

DECEMBER NATURAL GAS FIELD DELIVERIES:

December Natural Gas Field Deliveries include all gas deliveries made during December 1994 and December 1995. The survey emphasizes the level of gas delivered to the transmission network, because a natural gas sales might be put on the accounting books at a time different from that associated with the actual injection of that gas into the transmission network. Natural gas produced and consumed in the field in order to run production and gas processing facilities is not included in the total deliveries figure.

ANNUAL PRODUCTIVE CAPACITY UTILIZATION:

The Annual Productive Capacity Utilization Level equals the January 1st connected capacity divided by the prior calendar year's natural gas field deliveries (e.g. 1995 field deliveries divided by January 1, 1996 connected field capacity).

DECEMBER PRODUCTIVE CAPACITY UTILIZATION:

The December Productive Capacity Utilization Level equals the January 1st connected capacity divided by the prior December's natural gas field deliveries (e.g. 1995 December field deliveries divided by January 1, 1996 connected field capacity).

ANNUAL MAXIMUM FEASIBLE CAPACITY UTILIZATION LEVELS

The Annual Maximum Feasible Capacity Utilization Level is stated relative to the connected field capacity. In general, the maximum feasible capacity utilization level is defined as the highest practical capacity utilization, in percentage terms, applicable to a company's connected field capacity within a specific region, and typical for a calendar year. The maximum feasible capacity utilization level is based on a company's 5 to 10 year experience with planned and unplanned downtime of gas wells and other gas production facilities.

On the other hand, the maximum feasible capacity utilization levels do not factor in the following elements: 1) the level of unconnected field capacity reported, 2) the level of gas demanded by the market place (i.e., any constraints to production resulting from low gas consumption), 3) gas production downtime due to a breakdown in the transmission and distribution system (e.g., transmission and distribution pipeline ruptures, transmission compressor failures, etc.), and 4) the natural decline in field productivity due to gas reservoir depletion effects.

The annual maximum feasible capacity utilization level provided for the total U.S. lower-48 is the average value across all seven regions, weighted by each region's connected field capacity.

DECEMBER MAXIMUM FEASIBLE CAPACITY UTILIZATION LEVELS

The December Maximum Feasible Capacity Utilization Level is stated relative to the connected field capacity. Like the Annual Maximum Feasible Capacity Utilization, December maximum feasible capacity utilization level is defined as the highest practical capacity utilization, in percentage terms, applicable to a company's connected field capacity within a specific region, and typical for a "normal" December. And like the Annual Maximum Feasible Capacity Utilization, the December figure should include the same considerations embodied in the Annual Maximum Feasible Capacity Utilization.


APPENDIX D, TABLE 1
1994 RATIO OF REGIONAL DRY GAS PRODUCTION TO WET GAS PRODUCTION
BY DEPARTMENT OF ENERGY PRODUCTION DISTRICT

REGIONWET GAS
(Bcf)		DRY GAS
(Bcf)		WET/DRY RATIO
ALABAMA3973910.985
ALASKA4544230.932
ARKANSAS1861861.000
CALIFORNIA2552440.957
---->COASTAL ONSHORE17160.941
---->LOS ANGELES ONSHORE991.000
---->SAN JOAQUIN ONSHORE2232130.955
---->STATE OFFSHORE661.000
COLORADO4664470.959
FLORIDA870.959
KANSAS7106710.945
KENTUCKY67640.955
LOUISIANA1,5121,4530.961
---->NORTH3353280.979
---->SOUTH ONSHORE1,0309810.952
---->STATE OFFSHORE1471440.980
MICHIGAN1561500.962
MISSISSIPPI83820.988
MONTANA50490.980
NEW MEXICO1,4491,3620.940
---->EAST5154660.905
---->WEST9348960.959
NEW YORK21211.000
NORTH DAKOTA53470.887
OHIO1191191.000
OKLAHOMA1,8271,7210.942
PENNSYLVANIA1421410.993
TEXAS5,15447750.926
---->RRC DIST #1102970.951
---->RRC DIST #2 ONSHORE2422240.926
---->RRC DIST #3 ONSHORE6516000.922
---->RRC DIST #4 ONSHORE1,2781,2260.959
---->RRC DIST #51911850.969
---->RRC DIST #66305960.946
---->RRC DIST #7B77650.844
---->RRC DIST #7C3683340.908
---->RRC DIST #87606880.905
---->RRC DIST #8A112870.777
---->RRC DIST #91191000.840
---->RRC DIST #105505000.909
---->STATE OFFSHORE74730.986
UTAH1981840.929
VIRGINIA51511.000
WEST VIRGINIA1821720.945
WYOMING8147800.958
FEDERAL OFFSHORE4,8454,7720.985
---->PACIFIC COAST48470.979
---->GULF OF MEXICO(LA)3,5053,4400.981
---->GULF OF MEXICO(TX)1,2921,2850.995
MISCELLANEOUS11100.909
U.S. TOTAL19,21018,3220.954

Source:"Advance Summary U.S. Crude Oil, Natural Gas, And Natural Gas Liquids Reserves: 1994 Annual Report", Energy Information Administration, DOE/EIA-0216(94) August, 1995, Tables 3 & 4.

APPENDIX D, TABLE 2
1994 RATIO OF REGIONAL DRY GAS PRODUCTION TO WET GAS PRODUCTION
BY NGSA SURVEY REGION

REGIONWET GAS
(Bcf)		DRY GAS
(Bcf)		WET/DRY RATIO
1 OFFSHORE GULF5,1084,9420.985
2 ONSHORE GULF4,9474,7170.954
3 PERMIAN BASIN1,8321,6400.895
4 SAN JUAN BASIN9348960.959
5 ANADARKO BASIN3,3923,1780.937
6 EAST/N. CENTRAL7387180.973
7 ROCKY MTN/PACIFIC1,8841,7980.954
TOTAL LOWER-4818,74517,8890.954
ALASKA & MISCELLANEOUS4654330.931
U.S. TOTAL19,21018,3220.954

Source: Appendix D, Table 1.

Notes:

  1. Additional surveys had been received but were not included in the final survey tabulation due either to: 1) an incomplete survey response, or 2) data inconsistencies or errors which could not be resolved by the accountants.

  2. "Wet" gas refers to the presence of natural gas liquids (e.g., butane, propane, ethane, etc.) in the gas stream; it does not refer to the water content of the gas. In contrast, "dry" natural gas refers to the absense of natural gas liquids in the gas stream. Both "wet" and "dry" gas has already been stripped of residual water.

  3. The maximum feasible capacity utilization factor is a measure of the historic availability of wellhead gas production, as experienced over the last five to ten years. Consequently, utilization levels for any particular survey period can exceed the values reported for this historic measure.

  4. Source: "Monthly Energy Review", Energy Information Administration, DOE/EIA-0035(96/01), January 1996, Table 1.11, page 18.

  5. Gas withdrawls from storage in December 1994 equaled 465 Bcf and in December 1995 equaled 618 Bcf. In contrast, total U.S. dry gas production for December 1994 and December 1995 equaled 1,655 Bcf and 1,644 Bcf, respectively. (Source: "Natural Gas Monthly", Energy Information Administration, DOE/EIA-0130(96/06), June 1996, Table 2, page 8.



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This page was last updated August 31, 1997