Weather, construction inflation could squeeze North American pipelines

Warren R. True
Pipeline/Gas Processing Editor

Offshore pipeline construction, as shown here from a reel barge in the U.S. Gulf of Mexico, can be among the most expensive and is a major factor in increasing labor costs for North American pipeline construction.

Major North American interstate and interprovincial pipeline companies appear headed for a squeeze near-term: 1997 earnings from operations were down for the second straight year even as the companies expected new construction to begin this year or later to cost more.

The effects of warmer-than-normal weather during 1997 in North America made a showing in annual reports filed by U.S. regulated interstate oil and gas pipeline companies with the U.S. Federal Energy Regulatory Commission (FERC).

Declines in deliveries of oil and gas last year were evident across the board in these companies' statistics. And those declines showed up in bottom lines: operating revenues and net incomes for both oil and gas pipelines all dropped in 1997 (Fig. 1 [95,096 bytes]; Table 3 [25,324 bytes]).

At the same time, plans submitted to their respective regulatory bodies by these same U.S. companies and by Canadian pipelines suggest they expect the costs of installing new pipeline to rise.

Canadian companies submit construction applications to the National Energy Board (NEB) for interprovincial work or to provincial regulators, such as the Alberta Energy and Utilities Board, for intraprovincial construction.

Other reports by U.S. and Canadian companies, however, comparing past estimated-vs.-actual costs of construction, indicate for the second year in a row that estimates for new projects are running slightly ahead of eventual spending.

The U.S. interstate system

At the end of this report can be found two large tables that present a variety of data for U.S. oil and gas pipeline companies: revenue, income, volumes, miles operated, and investments in physical plants. These data make possible an analysis of the U.S. regulated interstate pipeline system available nowhere else.

Year-to-year, for example, the table on natural-gas companies has tracked the historic change in the U.S. gas-transmission industry wrought by less regulation. This report began tracking volumes of gas transported for a fee by major interstate pipelines in the 1988 Pipeline Economics Report (OGJ, Nov. 28, 1988, p. 33) as pipelines after 1984 gradually moved from owning the gas they moved to mostly providing transportation services.

Reporting changes

Comparing annual U.S. petroleum and natural-gas pipeline mileage must be done carefully.

For any calendar year, for example, the number of companies that must file reports with the FERC may vary as some companies become jurisdictional and others are declared non-jurisdictional.

Comparisons were complicated further after 1984 when the FERC instituted a two-tier classification system for companies (OGJ, Nov. 25, 1985, p. 55).

Definitions of the categories can be found at the end of the table "Gas pipelines" (p. 53) and in FERC Accounting and Reporting Requirements for Natural Gas Companies, para. 20.011.

Only major gas pipelines (51 of 113 reporting for 1997) are required to file miles operated in a given year. The other companies ("non-major") may indicate miles operated but those numbers are not specifically required.

For several years after 1984, many non-majors did not describe their systems. But in recent years, filing a description of their systems has become standard, and most have been providing miles operated.

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 does not provide miles of line operated but does give 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 [22,167 bytes] has been adjusted to reflect only transmission mileage operated since 1988.

FERC-regulated natural-gas pipeline companies and petroleum liquids pipeline companies operated fewer miles in 1997 than in 1996 (Table 1). Final data show a decline of more than 11,000 miles, a decline of nearly 3%.

A decline of more than 3,200 miles (1.67%) is evident for all transmission-pipeline mileage operated to move natural gas in interstate service; mileage used in deliveries of petroleum liquids in common-carrier service declined by nearly 7,800 miles (4.4%).

Gas-transmission mileage overall (majors plus non-majors) declined in 1997, compared to 1996, with transmission mileage for majors falling by more than 5,000 miles (2.9%).

Liquids pipelines' gathering lines fell by more than 1,500 miles ( 2 4.8%); crude trunk miles operated, also by more than 1,500 miles (nearly 2.7%); and product trunk mileage, by more than 6,000 miles (-7.7%).

Whether FERC designates a liquids pipeline company an interstate common-carrier pipeline determines whether the company must file a Form 6 FERC annual report for oil-pipeline companies.

Deliveries

Nowhere are the effects of the unusually warm weather in 1997 more evident than in the shipments of natural gas over the U.S. interstate system.

In 1997, gas pipelines gathered and moved nearly 30 tcf of other companies' gas and sold slightly more than 1 tcf from their own systems. The gas transported for a fee represented a decrease of nearly 3.4% over volumes moved in 1996; the gas sold, an 18.6% drop over volumes sold a year earlier.

Companies in 1996 had moved nearly 30.7 tcf of other companies' gas and sold more than 1.3 tcf from their own systems. The gas transported was a decrease of more than 3.5% over volumes moved in 1995; the gas sold, a 14% drop over volumes sold a year earlier.

Similarly, liquids pipelines saw nearly the same throughput in 1997 as in 1996 with an overall decline of more than 154 million bbl of crude oil and product delivered.

Product deliveries dropped by nearly 40 million bbl (-0.7%). This followed a decrease in deliveries in 1996 of 4.2% that followed an increase in 1995 of 4.6%.

Crude-oil shipments (more than 54% of total liquids movements) decreased by more than 326 million b/d.

Trunkline-traffic (1 bbl moving 1 mile = 1 bbl-mile) for U.S. crude-oil and product pipelines decreased by 51 billion bbl-miles (-1.7%) over traffic for 1996. This decline was led by a 2.2% drop in product deliveries last year.

Rankings

Oil & Gas Journal ranks the top 10 pipeline companies in three categories (miles utilized, trunkline traffic, and operating income) for oil-pipeline companies and three categories (miles, gas transported for others, and net income) for natural-gas pipeline companies.

These rankings are broken out from the accompanying pipeline-company tables.

For all natural-gas pipeline companies, net income as a portion of gas-plant investment in 1997 fell for the second consecutive year after rising 4 consecutive years and seven times in 9 years.

The term "gas plant" refers to the physical facilities used to move natural gas: compressors, metering stations, and pipelines.

As a portion of gas-plant investment, net income in 1997 was 3.8%, again a second consecutive year of decline: 1996, slightly more than 4.1%; 1995, 4.9%. This indicator of companies' return on investment had been rising steadily until 1996: 4.2% in 1994, 3.6% in 1993, 3.1% in 1992, and 0.5% in 1991.

This indicator stood at 8.7% in 1984, the year the FERC began (with Order 436) its restructuring of the interstate gas-pipeline industry that culminated in 1992 with Order 636.

Beginning with 1985, net income as a portion of gas-plant investment fell precipitously through 1987 then began its gradual comeback.

For 1997, all gas-pipeline companies reported an industry gas-plant investment totaling $59.8 billion, nearly equal to the $59.5 billion for 1996. The industry's investment in facilities since 1992 has been steadily growing.

In 1997, for oil-pipeline companies, net income as a percentage of investment in carrier property fell to more than 7.3%, another year of decline. 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.

For the third year in a row, actual investment in carrier property rose, to more than $30.6 billion in 1997, an increase of more than 9% over the $28 billion in 1996 and nearly $27.5 billion in 1995.

Carrier-property investment this decade has been steadily advancing, dropping only 2.7% in 1994 over 1993.

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 [112,307 bytes] indicates that investment by the five crude-oil pipelines was more than $2.3 billion, up from $2.1 billion in 1996, $2 billion for 1995, $1.97 billion for 1994, and $1.91 billion for 1993.

Investment in 1997 by the five product pipeline companies was slightly less than $3.7 billion, about level with the more than $3.6 billion in 1996. In 1995, investment by the companies stood at $3.5 billion; $3.3 billion in 1994; and $3.2 billion in 1993.

Fig. 2 [72,504 bytes] 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 [25,324 bytes]).

Through 1987, trends for 10 years for liquids-pipeline companies and for natural-gas pipeline companies had been heading in opposite directions.

In 1997 for liquids-pipeline companies, income as a portion of operating revenues fell for the second year in a row to 31.2% from more than 32% in 1996; it was nearly 35% in 1995.

In 1994, it was 29.5%; 25.4% in 1993, 28.8% for 1992, and 26.3% for 1991.

As a portion of revenues for all natural-gas companies last year, income rose to slightly more than 14% in 1997 from slightly less than 14% for 1996, 17.75% for 1995, 14.3% in 1994, and 9.1% in 1993.

Construction

Modifying gas-transmission facilities in U.S. interstate service (adding pipe or compression or abandoning, selling or removing it) requires approval by the FERC.

In Canada, all pipelines must apply to either their provincial regulatory body or to the NEB for such modifications.

These applications, except under special circumstances for U.S. companies, 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 such tracking in this report since its inception 40 years ago.

Canadian figures for major activity were added in recent years' reports for the first time.

Table 4 [163,574 bytes] and Table 5 [97,838 bytes] show companies' estimates during the period July 1, 1997-June 30, 1998, 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. For 1997, no project was filed with the FERC for a compressor station in federal waters.

Near-term increase

For any period, not all projects that are proposed are approved; not all approved ones are eventually built. Those which proceed can be tracked in OGJ's twice-yearly construction survey.

Filings during the 12 months ending June 30, 1997, provide a look at the immediate future of gas-pipeline construction on U.S. interstate system and Canadian construction for all types of service:

Nearly 2,800 miles of land pipeline were proposed for both countries compared to almost 2,200 miles for the 12 months before June 30, 1996 (Table 4).
More than 550,000 hp of new or additional compression were applied for, compared to nearly 500,000 hp for the same the year before (Table 5).

Table 4 lists 34 land-pipeline construction projects and 2 marine projects, compared with 35 land and 4 marine projects for the 1997 Pipeline Economics Report (Aug. 4, 1997, p. 37), 62 land and 2 marine projects in the 1996 report, and 66 land and 3 marine projects in the 1995 report. The 1996 and 1995 reports covered only U.S. applications.

For the 12 months ending June 30, 1998, the 34 land projects would cost more than $3.4 billion, an increase over the previous 12-month total of $2.6 billion, $1.3 billion in 1996, and more than $472 million in 1995.

Combined land and marine construction proposed for July 1997-June 1998 was almost 2,800 miles compared with nearly 2,400 miles for almost $2.8 billion.

The mileage prospects evident in the figures for the period ending June 30, 1998, are, however, somewhat misleading: A couple of major projects whose data are included in those projects have since been shelved. Nevertheless, the projects' cost projections indicate a great deal about where companies believe unit construction costs ($/mile) are headed; and that direction is up.

These cost-per-mile figures indeed reveal more about cost trends than aggregate totals.

For proposed U.S. gas-pipeline projects in the 1997-98 period surveyed, the average land cost per mile was more than $1.2 million/mile. For the 1996-97 period, the average land cost per mile was slightly less than $1.2 million.

For the period ending June 30, 1998, the two marine projects (106.5 miles) proposed averaged more than $1.5 million/mile. For the 12-months previous, the 204 miles of planned offshore pipeline amounted an average cost of $830,000/mile.

A closer look

Year-to-year variations in the four major categories of pipeline construction costs-material, labor, miscellaneous, and right-of-way (R.O.W.)-can also suggest trends within each group.

Materials can include line pipe, pipe coating, cathodic protection, and telecommunications equipment.

"Miscellaneous" costs generally cover surveying, engineering, supervision, contingencies, allowances for funds used during construction (afudc), administration and overheads, and regulatory filing fees.

R.O.W. costs include obtaining right-of-way and allowing for damages.

For the 34 land and 2 offshore projects surveyed for the 1997-98 period covered here, costs-per-mile for the four categories were as follows:

Material-$493,480/mile
Labor-$504,566/mile
Miscellaneous-$219,008/mile
R.O.W. and damages-$34,592/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 [70,215 bytes], derived from Table 4 for land pipelines, shows the major cost-component split for land and offshore-pipeline construction costs.

Material and labor for constructing land pipelines make up more than 79% of the cost. For offshore projects, material and labor make up more than 83%.

Fig. 4 [76,558 bytes], new for this report, plots a 10-year comparison of land-construction unit costs for the two major components, material and labor.

Fig. 5 [58,374 bytes] shows the cost split for land compressor stations based on data in Table 5.

Table 6 [12,748 bytes] lists 10 years of $/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.

Costs-per-mile 1997-98 in Table 6 are somewhat anomalous, as one traditionally tracked category (12 in.) had no projects proposed for it; two others (8 and 16 in.) had only a single project for each.

Year-to-year fluctuations in figures in this table, however, are illustrated in construction figures for a 12-in. pipeline.

These fell for the 1997 period, by nearly 2.75% after rising the previous year by more than 22%. This had dropped by more than 30% 1986 to 1987, jumped by more than 47% in 1988, fell again in 1989, leapt by more than 86% in 1990 only to fall sharply in 1991.

Actual costs

In the U.S., an operator must file with the FERC what the company has actually spent on an approved and built project within 6 months after the pipeline's successful hydrostatic testing or the compressor's being placed in service.

Shown in Fig. 6 [65,426 bytes] are 6 years of estimated-vs.-actual costs on cost-per-mile bases for project totals.

Table 7a [11,743 bytes], Table 7b [12,018 bytes] and Table 8 [56,080 bytes] show such actual costs for pipeline and compressor-station projects reported to the FERC during the 12 months ending June 30, 1998. Also included in Table 7 are estimated and actual costs for gas-pipeline construction in western Canada obtained from the operating company.

Fig. 7 [91,295 bytes], 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," or mileage segments, 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, separating only 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 $47.6 million. If this trend of companies' spending less than they estimate continues, the impact of continued lower revenues and incomes from lower oil and gas demand will be lessened.

Companies spent more than they estimated for materials and R.O.W.; but spent less for labor and miscellaneous items. Costs for labor were significantly less: by more than $45 million, or more than 22%.

Table 8 shows that actual costs for installing compression exceeded estimates by more than $2.5 million (6%).

Equipment costs accounted for much of the difference, exceeding estimates by more than $2.7 million (11.4%).

Actual costs for labor were greater than estimated by 12%.