Natural gas pipeline operators' net income reversed much of 2015's gains as revenues fell for the second straight year. Additions to gas pipeline operators' systems also softened, down more than 9% from 2015. This slowing came despite a $1.7-million/mile drop in pipeline construction costs.
US oil pipeline operators' net incomes, however, soared in 2016, rising by more than 57% as huge losses experienced by two operators in 2015 rolled of the current year's ledger. Revenues rose for the eleventh time in as many years, up nearly 5% from 2015. Investment in oil pipeline carrier property continued to slow, rising roughly $6 billion after climbing about $8.5 billion the year before and $17 billion in 2014.
Details
The sharp rise in oil pipeline profits as compared with revenues saw earnings as a percent of revenue surge to more than 45%. Natural gas pipeline operators meanwhile saw their profits drop more than 9% to about $4.9 billion on revenues roughly 10.5% softer than 2015 (Fig. 1).
Proposed new-build natural gas mileage was roughly 20% of 2016's announced build, despite the lower construction costs. Planned compression horsepower additions also fell sharply, despite 10% lower construction costs. Both totals were skewed by the lack of an estimated project cost filing as part of the Alaska Gasline Development Corp.'s Federal Energy Regulatory Commision (FERC) application to build an 800-mile pipeline to supply the Alaska LNG project.
A dramatic drop in outlays for labor was the primary driver of lower land pipeline construction costs, rates falling by nearly 50% to $1.96 million/mile from $3.6 million/mile. Material costs were the only category to rise, moving from $989,000/mile to $1.3 million/mile The roughly $1.71-million decrease in total estimated $/mile land pipeline construction costs brought them to $5.94 million per mile, 22% lower than 2016.
Actual land pipeline construction costs for projects completed in the 12 months ending June 30, 2017, were roughly $120,000/mile more than estimated costs. For the second straight year, higher than expected labor and ROW costs more than made up for lower than estimated materials and miscellaneous charges. Actual compressor station costs were nearly identical to estimated costs for projects completed by June 30, 2016, also for the second consecutive year.
US pipeline data
At the end of this article, two large tables (beginning on p. 79) 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 FERC classifies as 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 2016 at the end of this article.
The deadline to file these reports each year is in April. For a variety of reasons, companies often 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 spent.
OGJ monitors these filings from July 1 to June 30 each year, collecting them, and analyzing their numbers.
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.
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.
Reports for 2016 show a decrease in FERC-defined major gas pipeline companies: 90 companies of 165 filing, from 96 of 169 for 2015.
The FERC changed reporting requirements in 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 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 fell slightly in 2015 (Table 1), final data showing a decrease of 851 miles, or 0.45%.
Rankings; activity
Natural gas pipeline companies in 2016 saw operating revenues fall nearly $2 billion or roughly 8.4% from 2015, accelerating the previous year's declines. Net incomes softened at roughly the same pace, falling about $462 million (8.6%).
Oil pipeline earnings, however, rose by $3.85 billion (57.6%), with a more than $1 billion (4.9%) increase in revenues as well (Table 2). The increased earnings more than erased the segment's substantial 2015 decline.
Crude deliveries for 2016 decreased by nearly 135 million bbl or 1.2%, while product deliveries rose 502 million bbl (6.9%).
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, earnings for the 10 oil pipeline companies rose 26% compared with the 58% overall increase, suggesting that the upswing was broad based. The top 10 companies' share of the segment's total earnings shrank accordingly, standing at 53% vs. the almost two-thirds share of earnings held in 2015.
Net income as a portion of natural gas pipeline operating revenues improved to 22.82% in 2016, the highest level seen since 2011. The percentage of income as operating revenues for oil pipelines surged to 45.64%, but remained below 2014's record 49.64%.
Net income as a portion of gas-plant investment eased to 3.28% in 2016, reversing the upward trend seen since the 17-year low of 2.93% in 2013. Net income as a portion of investment in oil pipeline carrier property rebounded to 10.59% but remained below 2014's recent high of 11.3%.
Major and nonmajor natural gas pipelines in 2016 reported total gas-plant investment of roughly $158.5 billion, the highest level ever, up from $158 billon in 2015, $152 billion in 2014, about $147 billion in 2013, more than $142 billion in 2012, $138.6 billion in 2011, $124.7 billion in 2010, almost $121.3 billion in 2009, and nearly $105.8 billion in 2008.
Investment in oil pipeline carrier property continued to surge in 2016, surpassing $99.5 billion, more than double the values seen just 5 years before. Carrier property in 2015 totaled $93 billion, after reaching nearly $85 billion in 2014, $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 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 2016 increased their overall investment in carrier property by more than $1 billion (7.8%), further slowing the gains seen the previous 3 years but still outpacing the segment as a whole. All the companies increased investment in carrier property, but roughly $700 million of the overall gain came from a single operator.
The five products pipeline companies saw their overall investment in carrier property accelerate in 2016, adding more than $600 million, or 7.1%.
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 how investments in the crude oil and products pipeline companies were divided.
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, 2016, to June 30, 2017, 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, 2017, fell after jumping last year.
• Roughly 530 miles of pipeline were proposed for land construction, with 22.3 miles of offshore work submitted. The land level was down sharply from the nearly 2,500 miles proposed for land construction in 2016 and the 2,192 miles proposed for land construction in 2015.
• New or additional compression proposed by the end of June 2017 measured nearly 600,000 hp, down sharply from the 2.2 million hp proposed the year before and retreating below the then high of roughly 706,000 hp proposed in 2014. Neither the proposed miles nor the proposed horsepower, however, included Alaska Gasline Development Corp.'s proposed pipeline, which did not file cost estimates with FERC.
Putting the slide in US gas pipeline construction in perspective, Table 4 lists 27 land-pipeline "spreads," or mileage segments, and 1 marine project compared with:
• 33 land and 0 marine projects (OGJ, Sept. 5, 2016, p. 89).
• 46 land and 0 marine projects (OGJ, Sept. 7, 2015, p. 114).
• 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)
Only one of the spreads in 2016 measured 100 miles or more, with delays in already planned large transmission lines suppressing the appetite for new proposals.
For the 12 months ending June 30, 2017, the 27 land projects filed would cost an estimated $3.1 billion, as compared with 33 land projects for $18.9 billion a year earlier.
These statistics cover only FERC-regulated pipelines. Many other pipeline construction projects were announced in the 12 months ending June 30, 2017, but may have lied outside FERC jurisdiction.
A report released in April 2016 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 $26 billion/year, or $546 billion (in 2015 dollars) total, from 2015 to 2035. Most of this expenditure (roughly 61%) will be dedicated to natural gas development, with crude oil getting roughly 30% and NGL-related assets about 9%.
Included in the $26 billion/year are:
• $7.3 billion/year for new oil and gas lease equipment.
• $6.25 billion/year for expanded gas and liquids mainline capacity.
• More than $3 billion/year for new oil and gas gathering lines.
• Nearly $2 billion/year for new laterals.
• $3.55 billion/year for LNG export plants.
• $1.5 billion/year for gas processing plants.
• $900 million/year for NGL fractionation plants.
• $550 million/year for underground gas storage, crude oil storage, and NGL export terminals.
The report also forecast the need for about 296,000 miles of pipeline 2015-2035, including 23,000 miles of new natural gas transmission lines, 39,000 miles of new pipeline for gas, oil, and NGL transport, and 257,000 of new gas and oil gathering line to collect incremental production from roughly 752,000 new oil and gas wells.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 2016-17 the average cost was $5.9 million/mile, down from the $7.65 million/mile 2015-16 average costs but still more than the 2014-15 average cost of $5.2 million/mile. In 2013-14 the average cost was $6.6 million/mile as compared with $4.1 million/mile in 2012-13, $3.1 million/mile in 2011-12; $4.4 million/mile in 2010-11; $5.1 million/mile in 2009-10; and $3.7 million/mile in 2008-09.
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 27 land spreads filed for in 2016-17, cost-per-mile projections fell in all categories except material. In 2011 miscellaneous charges passed material to become the second most expensive cost category and this year they passed sharply lower labor costs to become the most expensive category of all:
• Material-$1,329,414/mile, up from $988,947/mile for 2015-16.
• Labor-$1,955,725/mile, down from $3,603,334/mile for 2015-16.
• Miscellaneous-$2,413,224/mile, down from $2,615,028/mile for 2015-16.
• ROW and damages-$245,684/mile, down from $441,548/mile for 2015-16.
The continued rise in miscellaneous costs as a proportion of the total is driven by companies increasing the amount set aside for contingencies in their estimates.
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 each strongly affect pipeline construction costs.
Fig. 3, derived from Table 4, shows the major cost-component splits for pipeline construction costs.
Labor's slide as a portion of land construction costs positioned it for the moment as the second most expensive category. Labor's portion of estimated costs for land pipelines fell to 32.9% in 2017 from 47.08% in 2016, 37.77% in 2015, 42.36% in 2014, 38.84% in 2013, 44.61% in 2012, 44.27% in 2011, and 44.61% in 2010. Material costs for land pipelines, meanwhile, rose to 22.37% from 12.98% in 2016, 19.34% in 2015, 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 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 geographic location, terrain, population density, or other factors.
Completed projects' costs
In most instances, a natural gas pipeline company must file with FERC what it ended up spending on an approved and built project. This filing must occur within 6 months after a pipeline's successful hydrostatic testing or a compressor's being put in service.
Fig. 6 shows 10 years of estimated vs. actual costs on cost-per-mile bases for project totals. The spike in both categories for 2014 and again this year stems from a larger than usual proportion of the pipeline mileage completed being in high-cost urban northeast US settings.
Tables 7 and 8 show actual costs for pipeline and compressor projects reported to FERC during the 12 months ending June 30, 2017. Fig. 7, for the same period, depicts how total actual costs ($/mile) for each category compare with estimated costs.
Actual labor costs for pipeline construction were more than $600,000/mile higher than estimated costs for the same projects. Overall actual costs, however, were just 1.4% higher than projected costs for the 12 months ending June 30, 2017.
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 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, 2017, saw nearly 320,000 hp completed, roughly 50% more than the year before. Actual compression costs were $60/hp (2%) lower than estimates (Table 8).
References
1. ICF International, "North American Midstream Infrastructure Through 2035; Leaning into the Headwinds," Apr. 12, 2016.
