Oil pipelines lead way in strong 2014

Proposed new-build natural gas mileage was more than four times 2014's announced build, while planned horsepower additions exceeded 1.6-million, more than doubling the 705,604 proposed last year.

Labor remained the most expensive construction component, but was only marginally more costly on a per mile basis than the miscellaneous costs category of which contingencies make up a large part. Both categories were substantially cheaper per mile than the year before.

The roughly $1.3-million decrease in estimated $/mile land pipeline construction costs brought them to $5.24 million per mile, 20% lower than 2014. Pipeline labor prices remained the single most expensive per-mile item at $2 million/mile, but were 28% lower than last year. Both material costs and ROW costs increased on a per mile basis.

Actual land pipeline construction costs for projects completed in the 12 months ending June 30, 2015, were roughly $400,000/mile less than estimated costs. Lower than expected miscellaneous costs more than made up for higher than estimated labor and ROW charges. Actual compressor station costs were more than $100/hp less than estimated costs for projects completed by June 30, 2015.

US pipeline data

At the end of this article, two large tables p. 123 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 are gathered from annual reports filed with FERC by regulated oil and natural gas pipeline companies for the previous calendar year.

Data is also gathered from periodic filings with FERC by those regulated natural gas pipeline companies seeking FERC approval to expand capacity. OGJ keeps a record of these filings for each 12-month period ending June 30.

Combined, these data allow an analysis of the US regulated interstate pipeline system.

• Annual reports. Companies that, in FERC's determination, are involved in the interstate movement of oil or natural gas for a fee are jurisdictional to FERC, must apply to FERC for approval of transportation rates, and therefore must file a FERC annual report: Form 2 or 2A, respectively, for major or nonmajor natural gas pipelines; Form 6 for oil (crude or product) pipelines.

The distinction between "major" and "nonmajor" is defined by FERC and appears as a note at the end of the table listing all FERC-regulated natural gas pipeline companies for 2014 at the end of this article.

The deadline to file these reports each year is April 1. For a variety of reasons, a number of companies miss that deadline and apply for extensions, but eventually file an annual report. That deadline and the numerous delayed filings explain why publication of this OGJ report on pipeline economics occurs later in each year. Earlier publication would exclude many companies' information.

• Periodic reports. When a FERC-regulated natural gas pipeline company wants to modify its system, it must apply for a "certificate of public convenience and necessity." This filing must explain in detail the planned construction, justify it, and-except in certain instances-specify what the company estimates construction will cost.

Not all applications are approved. Not all that are approved are built. But, assuming a company receives its certificate and builds its facilities, it must-again, with some exceptions-report back to FERC how its original cost estimates compared with what it actually spent.

OGJ spends the year July 1 to June 30 monitoring these filings, collecting them, and analyzing their numbers.

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.

Volumes of natural gas sold by pipelines have been steadily declining, so that, beginning with 2001 data in the 2002 report, the table only lists volumes transported for others.

The company tables also reflect asset consolidation and merger activity among companies in their efforts to improve transportation efficiencies and bottom lines.

Reporting changes

The number of companies required to file annual reports with FERC may change from year-to-year, with some companies becoming jurisdictional, others nonjurisdictional, and still others merging or being consolidated out of existence.

Such changes require care be taken in comparing annual US petroleum and natural gas pipeline statistics.

Institution by FERC of the two-tiered (2 and 2A) classification system for natural gas pipeline companies after 1984 further complicated comparisons (OGJ, Nov. 25, 1985, p. 55).

Only major gas pipelines are required to file miles operated in a given year. The other companies 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 filing descriptions of their systems has become standard, and most provide miles operated.

Reports for 2014 show an increase in FERC-defined major gas pipeline companies: 93 companies of 165 filing for 2014, from 92 of 163 for 2013.

The FERC made an additional change to reporting requirements for 1995 for both crude oil and petroleum products pipelines. Exempt from requirements to prepare and file a Form 6 were those pipelines with operating revenues 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.

In 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.

FERC-regulated major natural gas pipeline mileage rose marginally in 2014 (Table 1), final data showing an increase of 279 miles, or 0.15%.

Rankings; activity

Natural gas pipeline companies in 2014 saw operating revenues rise by more than $3.2 billion or roughly 15% from 2013, continuing the gains seen the past few years. Net incomes also returned to growth, climbing more than $473 million (about 11%), to roughly the levels seen in 2012.

Oil pipelines fared even better, with earnings rising nearly $2.6 billion (37.1%) on the back of a more than $3.6 billion (22.6%) increase in revenues (Table 2). Crude deliveries for 2014 increased by roughly 1.2 billion bbl or 14.4%, while product deliveries rose 409 million bbl (6.3%).

OGJ uses the 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 in these rankings shift year to year, reflecting 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.

For instance, the growth in overall oil pipeline earnings was larger than that for the top 10 companies (34%), suggesting ongoing strength for the smaller companies in this particular transport segment. The top 10 companies' share of the segment's total earnings was roughly 49% in 2014 compared with 50% a year earlier.

Net income as a portion of natural gas pipeline operating revenues slipped to 19.48% in 2014, continuing the fall from the record highs seen in 2010 to the lowest levels seen in more than 11 years. The percentage of income as operating revenues for oil pipelines rebounded sharply to 49.64%, passing its own 2011 record of 48.63%.

Net income as a portion of gas-plant investment rose to 3.19%, rebounding from a 17-yr low of 2.93%, in 2013. Net income as a portion of investment in oil pipeline carrier property rose to 11.3%, following a 10.3% drop in 2013. Income as part of investment in carrier property in 2004 stood at 11.4%, having risen steadily toward that level from 6.8% in 1998.

Major and nonmajor natural gas pipelines in 2014 reported an industry gas-plant investment of roughly $152 billion, the highest levels ever, up from about $147 billion in 2013, more than $142 in 2012, $138.6 billion in 2011, $124.7 billion in 2010, almost $121.3 billion in 2009, nearly $105.8 billion in 2008, and $95.5 billion in 2007.

Investment in oil pipeline carrier property continued to surge in 2014, to more than double the values seen just 7 years before, reaching nearly $85 billion after hitting $68 billion in 2013, topping $54 billion in 2012, hitting roughly $49 billion in 2011, more than $45 billion in 2010, roughly $42 billion in 2009, $39 billion in 2008, almost $36 billion in 2007, and beginning its current upward momentum in 2006, rising to $32.7 billion from the lowest level seen since at least 1997, $29.5 billion in 2005.

OGJ for many years has tracked carrier-property investment by five crude oil pipeline and five products pipeline companies chosen as representative in terms of physical systems and expenditures (Table 3). In 2003, we added the base carrier-property investment to allow for comparisons among the anonymous companies.

The five crude oil pipeline companies in 2014 increased their overall investment in carrier property by more than $3.7 billion (49.3%), accelerating the smaller gains seen in 2013 and 2012 and reflecting the activity seen in the segment as a whole. All of the companies increased investment in carrier property, but nearly all ($3.6 billion) of the overall gain came from a single operator.

The five products pipeline companies also saw their overall investment in carrier property accelerate in 2014, adding more than $1.2 billion, or 17.3%, with all companies increasing their investment here as well.

Comparisons of data in Table 3 with previous years' must be done with caution as mergers, acquisitions, and sales can make comparisons with previous years' data difficult.

Fig. 2 illustrates the investment split in the crude oil and products pipeline companies.

Construction mixed

Applications to FERC by regulated interstate natural gas pipeline companies to modify certain systems must, except in certain instances, provide estimated costs of these modifications in varying degrees of details.

Tracking the mileage and compression horsepower applied for and the estimated costs can indicate levels of construction activity over 2-4 years. Tables 4 and 5 show companies' estimates during the period July 1, 2014, to June 30, 2015, for what it will cost to construct a pipeline or install new or additional compression.

These tables cover a variety of locations, pipeline sizes, and compressor-horsepower ratings.

Not all projects proposed are approved. And not all projects approved are eventually built.

Applications filed in the 12 months ending June 30, 2015, jumped after falling last year.

• Nearly 2,200 miles of pipeline were proposed for land construction, the highest level since more than 2,700 miles were proposed in 1998. No new offshore work was submitted. The land level was up from the 523 miles proposed for land construction in 2014, a drop from the 820 miles of pipeline were proposed for land construction in 2013.

• New or additional compression proposed by the end of June 2015 measured more than 1.7-million hp, more than doubling the high of roughly 706,000 hp proposed the year before, itself up from the 450,000 hp proposed in 2013.

Putting the uptick in US gas pipeline construction in perspective, Table 4 lists 46 land-pipeline "spreads," or mileage segments, compared with:

• 31 land and 0 marine projects (OGJ, Sept. 1, 2014, p. 122).

• 26 land and 2 marine projects (OGJ, Sept. 2, 2013, p. 117).

• 11 land and 0 marine projects (OGJ, Sept. 3, 2012, p. 118).

• 31 land and 0 marine projects (OGJ, Sept. 5, 2011, p. 97).

• 8 land and 0 marine projects (OGJ, Nov. 1, 2010, p. 108).

• 21 land and 0 marine projects (OGJ, Sept. 14, 2009, p. 66).

• 19 land and 0 marine projects (OGJ, Sept. 1, 2008, p. 58)

• 25 land and 1 marine project (OGJ, Sept. 3, 2007, p. 51)

• 42 land and 1 marine project (OGJ, Sept. 11, 2006, p. 46).

• 56 land and 4 marine projects (OGJ, Sept. 12, 2005, p. 50).

Seven of the spreads in 2015 measured 100 miles or more, as proposed large transmission lines returned, one measuring 374.5 miles and another 509 miles.

For the 12 months ending June 30, 2015, the 46 land projects would cost an estimated $11.5 billion, as compared with 31 land projects for $3.43 billion a year earlier.

It is helpful to remember that these statistics cover only FERC-regulated pipelines. Many other pipeline construction projects were announced in the 12 months ending June 30, 2015, but as mentioned earlier, many involved connecting developing natural gas shale plays such as Eagle Ford and Marcellus to already operating transportation infrastructure and may have lied outside of FERC's jurisdiction.

A report released in March 2014 on behalf of the Interstate Natural Gas Association of America concluded that the United States and Canada will require annual average midstream natural gas, crude oil, and NGL infrastructure investment of $30 billion/year, or $641 billion (in real 2012 dollars) total, over the 22-year period from 2014 to 2035 to accommodate new supplies, particularly from the prolific shale plays, and growing demand for gas in the power-generation sector.

Included in the $30 billion/year are:

• $10 billion/year for new oil and gas lease equipment.

• Nearly $9 billion/year for expanded gas and liquids mainline capacity.

• More than $3 billion/year for new oil and gas gathering lines.

• More than $2 billion/year for new laterals.

• Roughly $2 billion/year for new LNG export plants.

The report also forecasted the need for about 850 miles/year of new gas transmission mainline, more than 800 miles/year in new natural gas laterals to-from power plants, processing plants, and storage fields, almost 700 miles/year of new NGL transmission line, and more than 730 miles/year in new oil transmission line.1

Against this backdrop, estimated $/mile costs for new projects as filed by operators with FERC remained historically high. For proposed onshore US gas pipeline projects in 2014-15 the average cost was $5.2 million/mile, down from the 2013-14 average cost of $6.6 million/mile, but still well above most recent pricing. In 2012-13 the average cost was $4.1 million/mile as compared with $3.1 million/mile in 2011-12; $4.4 million/mile in 2010-11; $5.1 million/mile in 2009-10; $3.7 million/mile in 2008-09; and $3.4 million/mile in 2007-08.

Cost components

Variations over time 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, freight, taxes, allowances for funds used during construction (AFUDC), administration and overheads, and regulatory filing fees.

ROW costs include obtaining rights-of-way and allowing for damages.

For the 46 land spreads filed for in 2014-15, cost-per-mile projections rose in material and ROW and fell in labor and miscellaneous. In 2011 miscellaneous charges passed material to become the second most expensive cost category and they retained this position through 2015:

• Material-$1,012,698/mile, up form $894,139/mile 2013-14.

• Labor-$1,977,938/mile, down from $2,781,619/mile for 2013-14.

• Miscellaneous-$1,867,393/mile, down from $2,547,600/mile for 2013-14.

• ROW and damages-$378,255/mile, up from $343,850/mile for 2013-14.

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 rarely shows clear-cut trends related to either length or geographic area. In general, however, the cost-per-mile within a given diameter decreases as the number of miles rises. Lines built nearer populated areas also tend to have higher unit costs.

Additionally, road, highway, river, or channel crossings and marshy or rocky terrain strongly affect pipeline construction costs.

Fig. 3, derived from Table 4, shows the major cost-component splits for pipeline construction costs.

Labor costs fell as a portion of land construction costs, but remained the single most expensive category. Labor's portion of estimated costs for land pipelines slipped to 37.77% from 42.36% in 2014, 38.84% in 2013, 44.61% in 2012, 44.27% in 2011, 44.61% in 2010, and 37.95% in 2009. Material costs for land pipelines, meanwhile, rebounded to 19.34% from 13.6% in 2014, 23.2% in 2013, 15.99% in 2012, and 14.54% in 2011.

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 land-construction costs for natural gas pipeline with diameters ranging from 8 to 36 in. The table's data consist of estimated costs filed under CP dockets with FERC, the same data shown in Tables 4 and 5.

Table 6 shows that the average cost per mile for any given diameter may fluctuate year to year as projects' costs are affected by location, terrain, population density, or other factors.

Completed projects' costs

In most instances, a natural gas pipeline company must file with FERC what it 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 put in service.

Fig. 6 shows 10 years of estimated vs. actual costs on cost-per-mile bases for project totals.

Tables 7 and 8 show actual costs for pipeline and compressor projects reported to FERC during the 12 months ending June 30, 2015. Fig. 7 depicts how total actual costs ($/mile) for each category compare with estimated costs. The spike in both categories for 2014 stems from a larger than usual proportion of the pipeline mileage completed that year being in high-cost urban northeast US settings.

Actual labor costs for pipeline construction were nearly $400,000/mile lower than estimated costs for the same projects. Overall actual costs were nearly 10% lower than projected costs for the 12 months ending June 30, 2015, despite higher labor and ROW costs.

Some of these projects may have been proposed and approved much earlier than the 1-year survey period. Others may have been filed for, approved, and built during the survey period.

If a project was reported in construction spreads in its initial filing, that's how projects are broken out in Table 4. Completed projects' cost data, however, are typically reported to FERC for an entire filing, usually but not always separating pipeline from compressor-station (or metering site) costs and lumping various diameters together.

The 12 months ending June 30, 2015, saw nearly 222,000 hp completed, up from recent levels. Actual compression costs were 116/hp (3.9%) lower than estimates (Table 8).

References

1. ICF International, "North America Midstream Infrastructure Through 2035; Capitalizing on Our Energy Abundance," Mar. 17, 2014.

Oil Pipelines