Plans for new natural-gas pipelines in the US took a jump through June 2000, as companies appeared to take seriously forecasts of a 30-tcf US market by 2005.
Markets in Florida, the US Northeast, and West are the main targets of this activity.
And, as if anticipating the increase, reports of completed costs (in $/mile) for pipeline laid vs. estimates at time of proposal showed an up tick for both land and offshore construction.
More generally, while consolidations, reorganizations, and asset swapping continued among federally regulated natural gas pipeline companies in 1999, the financial health of these and their sister companies moving oil and oil products in regulated interstate markets appeared sound.
These trends and more were evident in annual-report filings by US regulated interstate natural gas and common carrier oil pipelines to the US Federal Energy Regulatory Commission (FERC) for 1999 and by requests to FERC from natural gas pipeline companies between July 1, 1999, and June 30, 2000, for certificates to build new pipeline facilities or expand existing ones.
US pipelines
At the end of this article, two large tables offer a variety of data for US oil and gas pipeline companies: revenue, income, volumes transported, miles operated, and investments in physical plants. These data enable an analysis of the US regulated interstate pipeline system.
The table on natural gas companies, for example, has tracked how the US gas-transmission industry has changed under lessening regulation. OGJ's exclusive, annual Pipeline Economics Report began tracking volumes of gas transported for a fee by major interstate pipelines for 1987 (OGJ, Nov. 28, 1988, p. 33) as pipelines moved gradually after 1984 from owning the gas they moved to mostly providing transportation services.
Additionally, this table for the past 2 years has indicated the asset consolidation taking place in an effort to improve transportation efficiencies and increase bottom lines.
Reporting changes
Comparing annual US petroleum and natural gas pipeline mileage must be done carefully.
For any calendar year, for example, how many companies are required to file reports with the FERC may vary, as some companies become jurisdictional, others are declared non-jurisdictional, and still others are merged or consolidated out of existence.
Institution by FERC of a two-tier classification system for natural gas pipeline companies further complicated comparisons after 1984 (OGJ, Nov. 25, 1985, p. 55).
Definitions of the categories can be found at the end of the table "Gas pipelines" (p. 86) and in FERC Accounting and Reporting Requirements for Natural Gas Companies, para. 20.011.
Only major gas pipelines are required to file miles operated in a given year. The other companies ("non-major") may indicate miles operated but are not specifically required to do so.
For several years after 1984, many non-majors did not describe their systems. But recently, filing descriptions of their systems has become standard, and most have been providing miles operated.
Reports for 1999 show a drop in FERC-defined major gas pipeline companies: 57 companies of 114 filing for 1999 from 60 of 121 for 1998.
The FERC made an additional change to reporting requirements for 1995 for oil pipelines, which includes crude oil and petroleum products.
Exempt from requirements to prepare and file a Form 6 were those pipelines whose operating revenues have been at or less than $350,000 for each of the 3 preceding calendar years.
These companies must now file only an "Annual Cost of Service Based Analysis Schedule," which provides only total annual cost of service, actual operating revenues, and total throughput in both deliveries and barrel-miles.
More changes came for 1996: Major natural gas pipeline companies were no longer required to report miles of gathering and storage systems separately from transmission.
Thus, total miles operated for gas pipelines consist almost entirely of transmission mileage. To continue to convey a 10-year trend, Table 1 has been adjusted to reflect only transmission mileage operated since 1990.
Resuming a trend, FERC-regulated natural gas and oil pipeline companies operated fewer miles in 1999 than in 1998 (Table 1): Final data show a decrease of more than 5,000 miles, or less than 1%.
This decline in majors-operated gas transmission pipeline mileage reflected an overall and slight decrease of more than 5,000 miles (-2.7%) for all transmission-pipeline mileage operated to move natural gas in interstate service in 1998.
Oil pipeline mileage in common-carrier service in 1999 remained relatively flat, declining by nearly 3,000 miles (-1.7%), nearly the same drop as for 1998 from 1997.
The mileage sub-category of gas transmission overall (majors plus non-majors) fell by 2% in 1999, compared with 1998; transmission mileage for majors alone dropped by more than 5%.
Operated oil gathering lines fell by more than 3%, and operated crude oil lines dropped by nearly 9%. Product mileage, however, rose by nearly 3%. Overall, oil pipeline mileage was flat for 1999, falling less than 2%.
Whether FERC designates an oil pipeline company an interstate common-carrier pipeline determines whether the company must file a Form 6 FERC annual report for oil-pipeline companies.
Deliveries
Gas pipelines in 1999 gathered and moved nearly 30.5 tcf of other companies' gas and sold slightly less than 1 tcf from their own systems. The gas transported for a fee represented a marginal increase over volumes moved in 1998; the gas sold, a nearly 7.5% drop over volumes sold a year earlier.
In 1997, companies moved slightly less than 30 tcf of others' gas and sold slightly more than 1 tcf. Companies in 1996 had moved nearly 30.7 tcf of other companies' gas and sold more than 1.3 tcf.
Oil pipelines moved nearly 3.1% more in 1999 than in 1998 with an overall increase of almost 404 million bbl of crude oil and product delivered.
Product deliveries increased by nearly 500 million bbl (9.3%). This followed 3 years of falling deliveries of product. Higher prices for motor gasoline, evident in the second half of 1999 do not appear to have dampened demand, in line with what most analyses at the time were showing.
Crude-oil shipments (slightly more than 56% of total movements) were flat, declining by only 1%.
Trunkline-traffic (1 bbl moving 1 mile = 1 bbl-mile) for US crude-oil and product pipelines increased over traffic for 1998, following a sharp decline in 1998.
Total barrel-mile movements increased by nearly 300 billion bbl-miles, or nearly 9%.
Rankings
Oil & Gas Journal uses FERC annual-report data to rank the top 10 pipeline companies in three categories (miles operated, trunkline traffic, and operating income) for oil-pipeline companies and three categories (miles operated, gas transported for others, and net income) for natural gas pipeline companies.
Positions among these rankings shift year to year and reflect normal fluctuations in companies' activities and fortunes. But also, because these companies comprise such a large portion of their respective groups, the listings provide snapshots of overall industry trends and events.
Company financial data for all companies, not only majors in both types of pipeline service, provide a view of the ongoing condition of these industries (Fig. 1; Table 3).
For all natural gas pipeline companies, for example, net income as a portion of gas-plant investment fell in 1999 after rising in 1998. It had also fallen in 1997 for the second consecutive year.
The term "gas plant" refers to the physical facilities used to move natural gas: compressors, metering stations, and pipelines.
Another measure company performance and health is provided by a calculation of return on investment: net income as a portion of gas-plant investment. The trend since 1995 would appear to be down: In 1999, net income was 3.8% of operating revenues; in 1998, it was 4.7%; in 1997, 3.8%; 1996, slightly more than 4.0%; 1995, 4.9%.
Overall for the 1990s, however, this indicator of companies' health has risen steadily. In 1984, it stood at 8.7%-the year the FERC began (with Order 436) restructuring the interstate gas-pipeline industry, culminating in 1992 with Order 636.
Beginning with 1985, net income as a portion of gas-plant investment fell precipitously through 1987 then began a gradual comeback.
All gas-pipeline companies (majors and non-majors in 1999) reported an industry gas-plant investment totaling nearly $65.9 billion, up from more than $63 billion in 1998 and $59.8 billion in 1997. The industry's investment in facilities since 1992 has been steadily growing.
In 1999, for oil pipeline companies, net income as a percentage of investment in carrier property rose to more than 8.6%, reversing a 2-year decline: 6.8% in 1998 and 7.3% in 1997.
In 1996, this indicator had stood at nearly 8.5%, off from more than 9.5% in 1995. In 1994, the percentage stood at 8.2% compared to 5.5% for 1993, 7.6% in 1992, and 6.6% in 1991.
Actual investment in carrier property increased sharply to nearly $33.8 billion from $30.1 billion in 1998 and $30.6 billion in 1997. The figure reflects the overall advance made by the industry, especially for the last 5 years of the 1990s: $28 billion in 1996 and nearly $27.5 billion in 1995.
For many years, Oil & Gas Journal has been tracking carrier-property investment by five crude-oil pipeline and five products-pipeline companies chosen as representative in terms of physical systems and expenditures.
Consistent with the overall trend of increasing property investment, these companies have been increasing their investments steadily in recent years. Table 2 indicates that investment by the five crude-oil pipelines was almost $3.6 billion, up from nearly $3.2 billion in 1998.
The trend in the 1990s has been steadily higher: $2.3 billion for 1997, $2.1 billion in 1996, $2 billion for 1995, and $1.97 billion for 1994.
But in 1998, a major crude-oil pipeline company that had been included in this list merged with two other large pipeline companies. Comparisons with earlier years must, therefore, be qualified.
In 1999, investment by the five product pipeline companies topped $4 billion, capping a rise for much of the 1990s: nearly $3.8 billion in 1998; slightly less than $3.7 billion in 1997; $3.6 billion in 1996; $3.5 billion in 1995; and $3.3 billion in 1994.
Fig. 2 illustrates the investment split in the crude-oil and products pipeline companies.
Another measure of the profitability of oil and natural gas pipeline companies in recent years is the portion net income represents of operating income (Table 3).
For oil pipelines, the percentage of income in operating revenues had been hovering in the mid-20s for the first 5 years of the 1990s; for the last 5 years, however, it pushed into the 30s.
Construction
In the US, regulated interstate natural gas pipeline companies must apply for a "certificate of public convenience and necessity" from the FERC to modify facilities (adding pipe or compression or abandoning, selling, or removing it).
Except under certain circumstances, these applications must contain estimates of what such modifications will cost.
Annual tracking of the mileage and compression horsepower applied for and of the estimated costs indicates future construction. And Oil & Gas Journal has been doing that since this report began more than 40 years ago.
Tables 4 and 5 show companies' estimates during the period July 1,1999-June 30, 2000, for what it will cost to construct a pipeline or compressor station.
Those tables cover a variety of locations, pipeline sizes, and compressor-horsepower ratings.
Plans abound
For any period, not all projects that are proposed are approved; not all approved ones are eventually built. Those that proceed can be tracked in OGJ's twice-yearly construction survey.
Filings during the 12 months ending June 30, 2000, offer a look at the immediate future of gas-pipeline construction on US interstate system:
- More than 2,500 miles of pipeline were proposed: Nearly 1,500 miles of land pipeline plus another 1,000 miles for offshore. This compares to almost 900 miles of only land pipeline for the 12 months before June 30, 1999 (Table 4).
- More than 254,000 hp of new or additional compression were applied for compared with nearly 234,000 hp for the same period the year before (Table 5). All applications then were for land-based compression.
Table 4 lists 115 land-pipeline construction "spreads," or mileage segments, and 6 marine projects, compared with:
- 39 land and no marine projects (OGJ, Aug. 23, 1999, p. 45).
- 34 land and 2 marine projects (OGJ, Aug. 31, 1998, p. 33).
- 35 land and 4 marine projects (OGJ, Aug. 4, 1997, p. 37).
- 62 land and 2 marine projects (OGJ, Nov. 25, 1996, p. 39).
- 66 land and 3 marine projects (OGJ, Nov. 27, 1995, p. 39).
This year's report and last year's (2000 and 1999) and the one for 1996 covered only US applications; the others included data from Canada.
For the 12 months ending June 30, 2000, the 121 projects would cost more than $4 billion.
In this list, however, are two proposals for extensive land and offshore pipeline projects from supply areas in the Central Gulf of Mexico, across the eastern gulf, and into Florida markets.
It is unthinkable that both would be built; and even problematic that either will be built, given environmental resistance to activity in the eastern Gulf of Mexico.
Projects' cost projections indicate a great deal about where companies believe unit construction costs ($/mile) are headed. These cost-per-mile figures indeed reveal more about cost trends than do aggregate totals.
For proposed US gas-pipeline projects in the 1999-2000 period surveyed, the average land cost per mile was slightly more than $1.5 million/mile; for the offshore projects, nearly $1.8 million.
For the 1998-99 period, the land pipeline projects' costs averaged slightly more than $1.1 million/mile; for 1997-98, slightly less than $1.2 million (all land).
Components
Variations year-to-year in the four major categories of pipeline construction costs-material, labor, miscellaneous, and right of way (ROW)-can also suggest trends within each group.
Materials can include line pipe, pipe coating, and cathodic protection.
"Miscellaneous" costs generally cover surveying, engineering, supervision, contingencies, telecommunications equipment, allowances for funds used during construction (AFUDC), administration and overheads, and regulatory filing fees.
ROW costs include obtaining right of way and allowing for damages.
For the 115 land spreads surveyed for the 1999-2000 period covered here, costs-per-mile for the four categories were as follows:
- Material-$343,591/mile
- Labor-$619,857/mile
- Miscellaneous-$403,835/mile
- R.O.W. and damages-$143,899/mile
For the 6 offshore spreads surveyed for the 1999-2000 period covered here, costs-per-mile for the four categories were as follows:
- Material-$889,291/mile
- Labor-$556,586/mile
- Miscellaneous-$332,086/mile
- R.O.W. and damages-$1,899/mile
Table 4 lists proposed pipelines in order of increasing size (OD) and increasing lengths within each size.
The average cost per mile for the projects shows few clear-cut trends related to either length or geographic area.
In general, however, the cost per mile within a given diameter indicates that the longer the pipeline, the lower the unit cost for construction. And, broadly, lines built nearer populated areas tend to have higher unit (per-mile) costs.
Additionally, road, highway, river, or channel crossings and marshy or rocky terrain each strongly affects pipeline construction costs.
Fig. 3, derived from Table 4, shows the major cost-component splits for land and offshore pipeline construction costs.
Material and labor for constructing land pipelines make up more than 63% of the cost; for offshore lines, more than 80%. Fig. 4 plots a 10-year comparison of land-construction unit costs for the two major components, material and labor.
Fig. 5 shows the cost split for land compressor stations based on data in Table 5.
Table 6 lists 10 years of unit ($/mile) land-construction costs for natural gas pipelines with diameters ranging from 8 to 36 in. The table's data consist of estimated costs filed under CP dockets with the FERC, the same data that are shown in Tables 4 and 5.
The average cost per mile for any given diameter, Table 6 shows, may fluctuate from one year to another as projects' costs are affected by geographic location, terrain, population density, or other factors.
Completed projects' costs
An operator must file with the FERC what the company has actually spent on an approved and built project. This filing must occur within 6 months after the pipeline's successful hydrostatic testing or the compressor's being placed in service.
Shown in Fig. 6 are 8 years of estimated vs. actual costs on cost-per-mile bases for project totals.
Tables 7 and 8 show such actual costs for pipeline and compressor-station projects reported to the FERC during the 12 months ending June 30, 2000.
Fig. 7, for the same 12-month period, depicts how total actual costs for each category compared to estimated costs.
Some of these projects may have been proposed and even approved much earlier than the 1-year survey period. Others may have been filed for, approved, and built during the 12-month survey period.
If, in its initial filing, a project was reported in construction spreads, that's how projects are broken out in Table 4.
Completed-projects' cost data, however, are usually reported to the FERC for an entire filing, usually but not always separating pipeline from compressor-station (or metering site) costs and lumping several diameters together.
Overall, estimated gas-pipeline construction costs exceeded actual ones by more than $36 million; actual costs for land pipelines were more than $39 million higher than estimate, while those for offshore projects came in nearly $3 million less than estimated.
Savings in material and labor were responsible for the lower actual costs of offshore lines, while all categories came in higher for land pipelines.
Table 8 shows that actual costs for installing compression nearly hit the estimated ones exactly.
