# Presentation: 424617

## Natural Gas Productive Capacity for the Lower-48 States

- May 2001

- Information about this presentation may be obtained from John Wood (john.wood@eia.doe.gov), Gary Long (gary.long@eia.doe.gov), Hafeez Rahman (hafeez.rahman@eia.doe.gov), or Velton Funk (velton.funk@eia.doe.gov).

## Natural Gas Productive Capacity for the Lower-48 States

- An important issue facing the U.S. natural gas markets is whether natural gas production will rise to meet expected growth in demand and replenish natural gas storage to more normal levels.  Gas well completions have increased steadily since April 1999; however, lags of several months in the availability of natural gas production data, and the fact that production levels tend to be revised upward over time, leaves considerable uncertainty regarding the supply response resulting from these increased drilling levels.  This assessment attempts to estimate the increases in natural gas productive capacity which should be expected given recent natural gas drilling and price trends.

## Natural Gas Productive Capacity for the Lower-48 States- Summary -

- This presentation contains monthly projections of natural gas *effective productive capacity* in the Lower-48 States for 2001.  *Effective productive capacity* declined in 1998 and 1999, increased through 2000, and in 2001, is projected to increase faster than production.
- Natural gas *effective productive capacity* measures the maximum production available from natural gas wells.  It is measured in billion cubic feet per day (Bcf/d).
- The difference between *effective productive capacity* and actual production is called surplus capacity.
- The ratio of actual production to *effective productive capacity* is called the effective capacity utilization rate.
- Four cases are developed in this analysis:
- The Base case uses the corresponding oil and gas price paths and production path in EIA’s January 2001 *Short Term Energy Outlook* (*STEO*) (Table 1).  Oil and gas prices were reduced or increased 25 percent for the Low and High cases.
- The Constant Drilling case estimates *effective productive capacity* if drilling stays at some constant rate (879 active gas rigs starting in January 2001) independent of the actual or projected gas price path.

## Natural Gas Productive Capacity for the Lower-48 States- Summary -

- All cases show a change from declining to increasing *effective productive capacity* beginning in 2000 and continuing through 2001 (Figures 1 & 2).
- Natural gas *effective productive capacity* declined in 1999 - following a large decline in drilling - increasing the effective capacity utilization rate.  Any rate over 90 percent effective capacity utilization can lead to price volatility (orange line on Figures 1 & 2).  Effective capacity utilization rose to 95 percent in 1999.  This supply tightness carried over into 2000.
- This supply tightness, along with low gas storage levels and higher demand, created the conditions for price volatility and rising prices typically associated with high effective capacity utilization rates.  An exceptionally cold November and December spurred gas demand and price increases.
-  Significant changes in drilling levels can affect both *effective productive capacity* and actual production in a relatively short time.
- If drilling stopped completely, any surplus *effective productive capacity* would disappear in a matter of months.
- Conversely, significant drilling increases can add significant increases in effective productive capacity in a matter of months.  Such increases are expected throughout 2001.

## Slide 5

## Natural Gas Productive Capacity for the Lower-48 States- Summary -

- If this increase in *effective productive capacity* is not utilized by increased demand, a surplus will develop.
- The following sections describe the methodology and national-level results.
**Note:**  This study uses average monthly values, which do not model phenomena - such as a severe cold snap - which might push production to full capacity (100% utilization rate) for a short time.  Monthly peak winter natural gas demand is usually 1.5 times or greater than natural gas production; the deficit is met by withdrawals from natural gas storage and imports.  Potential uncertainties of up to several percent may exist in some monthly production and *effective productive capacity* estimates for 2000 used in this study.

## Natural Gas Productive Capacity for the Lower-48 States- Methodology -

- This study employs a new methodology to determine the *effective productive capacity*.
- Previous studies were based on a demonstrated wellhead productive capacity calculated by summing the maximum measured monthly production rates of each well in each year.  While this sum is a demonstrated upper bound to production, a review of the historical data indicates that (at least for some States) there is a lower *effective productive capacity* limit acting on wellhead production.
- One or more of the following factors that can prevent all wells from producing at their wellhead capacity at the same time include field processing equipment, limitations from gathering and pipeline systems, limiting compression capability, and natural gas plant throughput capabilities.
- The *effective productive capacity* better reflects the ability of producing wells to deliver gas into the gathering and transportation system.  An *effective productive capacity* has been estimated for each area included in this study and is used to assess natural gas supply in the Lower-48 States through 2001.

## Natural Gas Productive Capacity for the Lower-48 States- Methodology -

- The monthly capacity projections are the sum of capacity forecasts for older wells and new wells.
- New well capacity is a function of the number of new well completions, which depends on the monthly drilling rig forecast based on the monthly price and production forecasts in EIA's January 2001 *Short Term Energy Outlook* (*STEO*).
- The Drilling Rig Model uses oil and gas revenue to project total active rigs and the percent of rigs drilling for gas.  A well/rig ratio for each of ten U.S. supply areas is used to convert the number of gas rigs to well completions.  This ratio includes an efficiency factor that models the efficiency losses normally seen when the number of drilling rigs increases.
- The wellhead capacity to produce gas from these new well completions is determined by a hyperbolic function relating monthly production rate to cumulative production and calibrated to the most recent 3 years of data.
- To determine old well capacity, the wells are grouped by vintage year.  Productive capacity is modeled for each vintage using the same hyperbolic function relating monthly production rate to cumulative production.  A monthly projection is made for each vintage and then all vintages are summed.

## Natural Gas Productive Capacity for the Lower-48 States- Methodology -

- The production forecast is based on the U.S. production forecast in the January 2001 *STEO*, which represents an expectation of normal weather.
- The U.S. production forecast is distributed among the ten supply areas considered in this study according to each area's 1999 share of production.
- Each area's *effective productive capacity* is then compared to its monthly production forecast.  If the area’s production forecast is greater than the *effective productive capacity*, the unmet production requirement is allocated to other supply areas that have surplus *effective productive capacity*.
- A Constant Drilling case independent of price forecasts was developed to show what would happen if drilling remained close to January 2001 levels (Figure 2).
- Approximately 879 rigs were drilling for natural gas in January 2001.
- This gas rig count was held constant through the forecast period as was the resulting number of gas well completions.
- The next section explains in further detail the basis of *effective productive capacity*, using Oklahoma as an example.

## Slide 10

## Natural Gas Productive Capacity for the Lower-48 States

***- Methodology -***

-    Oklahoma is a good example of why the methodology was changed to estimate *effective productive capacity *and how the methodology works.
-     Prior to the early 1990s, Oklahoma production was limited by neither wellhead capacity nor *effective productive capacity*, but by demand.  More recently, production has been capacity limited with a utilization of 95 percent or more.  During the late 1980’s, when *effective productive capacity *surpluses existed, annual production was rising and there were substantive seasonal variations as demand changed during the year (Figure 3).
-    U.S. production and demand have been slightly increasing in most recent years, but Oklahoma production was declining even with a surplus demonstrated wellhead capacity of 15 to 25 percent (Figure 3).
-    The fact that Oklahoma’s production did not grow during this period, but  declined, indicates that production was not limited by wellhead productive capacity, but by a lower *effective productive capacity*.
-    For Oklahoma the *effective productive capacity* was found to be about 83 percent of the demonstrated wellhead capacity.
-    In Oklahoma, as in other areas, the relative impact of field processing equipment, limitations from gathering and pipeline systems, limited compression capability, and natural gas plant throughput capabilities varied across the State and over time.

## Slide 12

## Natural Gas Productive Capacity for the Lower-48 States

***- Methodology -***

-    Oklahoma production peaked when its effective capacity utilization (production divided by *effective productive capacity*) reached 90 percent in 1990 - 1991.  The State has been producing at 95 percent or more of its *effective productive capacity* for most of the last 9 years, and  production has been at or very close to 100 percent of *effective productive capacity* for the last 5 years (Figure 3).
-    The disappearance of seasonal production fluctuations is also an indicator of shrinking surplus capacity and declining *effective productive capacity* limit.  By the early 1990s, seasonal fluctuations in production had faded as the capacity utilization reached 90 percent.  (Gas storage operations may also affect seasonal production.)
-    The rapid price increases of 2000 lead to increasing production and *effective productive capacity* because the EIA Drilling Rig Model is essentially driven by prices.  Specifically, the drilling rig forecasts are based on forecasts of oil and gas revenue (production times price).  In turn, the rig forecast generates the new wells and the substantial new well component of the projected *effective productive capacity*.  Compared to price, production has little impact on the rig count because it varies by only a few percent and therefore changes revenue by only a few percent while prices can double or triple revenue.

## Natural Gas Productive Capacity for the Lower-48 States

***- Methodology -***

-    Oklahoma gas well completions (including recompletions) are projected to increase to a level comparable to that of the mid-1980s (Figure 4).  This translates to a small production increase that reverses the long decline in Oklahoma production.  Production can increase because the *effective productive capacity* increases through 2001 due to the increase in drilling.  Because production is modeled to rise, no surplus *effective productive capacity* develops in 2001.
-    Historically, when rig counts have increased, the number of wells drilled per rig has dropped due to a decline in rig efficiency.  The wells per rig ratios used here compensate for this expected drilling inefficiency.
-    During times of higher prices the average yield per new well completion may decline due to the drilling of wells that are uneconomic at lower prices.  No adjustment was made here for potential changes in the initial production rate of new well completions because these rates have been relatively stable in recent years due to technology improvements.

## Slide 15

## Natural Gas Productive Capacity for the Lower-48 States

***- Results -***

-    The Lower-48 States were producing at rates close to 95 percent of estimated *effective productive capacity* in 1999 (Figure 1).
-    Lower oil and gas prices in 1998 and early 1999 resulted in reduced gas rig counts and new gas well completions, causing wellhead capacity to drop.  The gas completions which include both new wells and recompletions of existing gas wells did have a small increase in 1999 (Figure 5).
-    Higher drilling now and in the near future will increase *effective productive capacity*.  The Low, Base, and High case projections of *effective productive capacity* through 2001 all indicate increasing future capacity.
-    Due to high drilling rates, capacity utilization is trending down during 2001.  If this trend continues during 2002, capacity utilization could drop below 90 percent, the level that indicates a “tight” natural gas market.
-    Capacity utilization below 90 percent would create the potential for lower and less volatile natural gas prices.

## Natural Gas Productive Capacity for the Lower-48 States

***- Results -***

-    This study used the same prices as EIA’s January 2001 *Short Term Energy Outlook* (*STEO*).  These were relatively high by pre-2000 standards, but in the Base Case return to $4.40 per Mcf by July 2001 (Table 1).
-    A Constant Drilling case (879 rigs) was also developed to provide one effective capacity estimate independent of price forecasts.  The resulting productive capacity is between the Low and Base Cases (Figure 2).
-    Lower-48 annual well completions are projected to increase over 1999 levels by 61 percent through 2001 in the Base Case (Figure 5).
-    This represents a return to completion levels last seen in the early 1980s.
-    There are about 8500 more gas well completions and recompletions projected in 2001 compared to 1999.

## Slide 18

## Natural Gas Productive Capacity for the Lower-48 States

***- Results -***

-    The contribution of new well completions to capacity has been roughly flat from 1996 through 1999 then increased in 2000 and 2001 (Figure 6).
-    About 30 percent of total wellhead productive capacity is from wells one year old or less in 2000.  Similarly, about 44 percent of wellhead productive capacity is from wells 2 years old or less, and 52 percent is associated with wells only 3 years old or less.
-    A substantial reduction in drilling can dramatically affect both the *effective productive capacity* and production.  If drilling were to stop completely, any surplus capacity would erode in a matter of months.
-    Conversely, a dramatic increase in drilling, as projected through 2001, can add significant capacity.
-    This very large increase in drilling (61 percent from 1999 to 2001) accounts for about a 5.2 Bcf per day (about 10 percent) increase in *effective productive capacity* by December 2001.

## Slide 20

## Other Areas	

- Figures for Texas (10, 11, 12), the Gulf of Mexico OCS (13, 14, 15), and the Lower-48 excluding Texas and the Gulf of Mexico OCS (7, 8, 9) follow.
- Texas and the Gulf of Mexico OCS are the largest supply areas.
- Texas and the Gulf of Mexico OCS produce roughly 13 and 14 billion cubic feet per day respectively.  Together they produce about half of Lower-48 production.
- The Gulf of Mexico OCS is projected to have surplus *effective productive capacity* of about 2.4 billion cubic feet per day at the end of 2001, or about 55 percent of the Lower-48 total surplus *effective productive capacity *(Figure 13).
- The Gulf of Mexico OCS historically has been the area that can rapidly increase production when required.
- Gas wells in the Gulf of Mexico OCS average about 7 times higher initial flow rates than onshore wells.
- Texas reached 100 percent *effective productive capacity* utilization in 1999 due to an oil price driven decline in drilling (Figure 10).  The *effective productive capacity* began increasing in 2000 and Texas is projected to have surplus capacity of about 0.8 billion cubic feet per day at the end of 2001, or about 17 percent of the Lower-48 total surplus.
- However, Texas will still be above 90 percent effective capacity utilization in December 2001 as will the Lower-48 States.

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## Federal Offshore, Gulf of Mexico OCS

- A modification of the methodology was applied to areas (such as the Gulf of Mexico and the Rocky Mountain States) that had exceptional growth in well completions and therefore, wellhead capacity.
- In these areas, growth in *effective productive capacity* will be limited in the short term by the infrastructure rather than the wellhead productive capacity.
- The infrastructure capacity in these areas is expected to grow at a slower rate than the wellhead capacity in the short term.
- Therefore, modeling *effective productive capacity* as a percentage of wellhead productive capacity is not appropriate when wellhead productive capacity growth rapidly exceeds historical infrastructure capacity.
- In these areas, infrastructure capacity was modeled to grow at approximately 1/3 the wellhead productive capacity growth rate based loosely on history.  If infrastructure capacity growth was set at 1/2 the wellhead capacity rate, then *effective productive capacity* would grow faster reducing the effective capacity utilization by roughly 4 percent in the Gulf of Mexico and by 3 percent in the Rocky Mountain States, which decreases the Lower-48 States effective capacity utilization by 2 percent to roughly 91 percent in December 2001.  A slight reduction in the potential for price volatility would result from the lower effective capacity utilization that results from switching the infrastructure growth rate from 1/3 to 1/2 of the wellhead productive capacity growth rate.

## Federal Offshore, Gulf of Mexico OCS

- Due to this modification, the *effective productive capacity* is not parallel to the wellhead productive capacity curve for the forecast years as it is historically.  By the end of 2001, the Lower-48 *effective productive capacity* is about 3.2 Bcf/d less than it would have been modeled without infrastructure restrictions for the Gulf of Mexico OCS and about another 1.0 Bcf/d less for the Rocky Mountain States.  This yields a total reduction of 4.2 Bcf/d from these areas due to this modification.
- The number of new well completions in the Gulf of Mexico OCS was roughly flat from 1996 through 1999 but has a substantial increase in 2000 (Figure 14).  The contribution of new well completions less than one year old to wellhead productive capacity has been roughly flat from 1996 through 1999 at about 40 percent, but increased to 45 percent in 2000 (Figure 15).
- Without new well completions, wellhead productive capacity would decline 40 percent or 10 Bcf/d in a year in the Gulf of Mexico OCS.  Both production and the *effective productive capacity* would be substantially reduced as well.
- This is an exceptionally large dependence on new well completions.  A sustained and successful drilling program above the 1998-1999 levels in the Gulf of Mexico OCS is required to maintain the area’s historical market share of production.

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## Table 1.Lower-48 Natural Gas & Oil Prices and Gas Rig Forecast

## Data Sources

- Production History:  Energy Information Administration, Office of Oil and Gas; and IHS Energy Group.
- Productive Capacity:  Model GASCAP94 C102500.
- Price Forecast:  Energy Information Administration, January 2001 Short Term Energy Outlook
- Production Forecast:  Energy Information Administration, Short-Term Integrated Forecasting System, December 2000; and Model GASCAP94 C102500.
- Well Completions History:  Energy Information Administration, Office of Oil and Gas; and IHS Energy Group.
- Well Completions Forecast:  Energy Information Administration, Office of Oil and Gas, Drilling Rig Model; and Model GASCAP94 C102500
- Previous Report:  The previous report is available on the web and can be accessed for more details on the gas capacity process and model at www.eia.doe.gov/oil_gas/natural_gas/analysis_publications/natural_gas_productive_capacity/cp97.html.
- Methodology Documentation:  A functional description of the methodology used in this analysis will be available on the EIA website in approximately 90 days.