The other Bakken pipelines: Water for fracking

Much pipeline development in the Bakken region of North Dakota and Montana is focused on transporting crude oil. But pipe is also being laid to carry a humble commodity essential to oil production in the region: water.

Copious amounts of water are required to extract oil from the Bakken’s shale beds. The fracking process—injecting a mixture of water and chemicals into shale rock to release oil—consumes up to 8 million gallons of freshwater per well. And along with oil and natural gas, wells produce even larger amounts of subterranean saltwater over their operating life. “The first thing that’s produced out of a well is water; the last thing ever produced out of a well is water,” said Rodney Wren, president of New Frontier Midstream, a Texas-based developer of oil and gas infrastructure.

Today, most freshwater used for fracking is trucked to wellheads, and tanker trucks also haul away saltwater and used frac (“flow back”) water for disposal in deep wells. Trucking water raises costs for producers—fees in the Bakken range from 2 to 10 cents per gallon, depending on miles traveled—and contributes to wear and tear on rural roads.

It’s cheaper to pipe water to and from the wellhead, especially in areas where wells are close together. Brigham Exploration, an oil company acquired by Statoil of Norway in 2011, was a leader in laying water pipelines in the Bakken, installing them simultaneously with crude oil and gas lines. Incoming pipe delivers freshwater for fracking from municipal or rural water systems; outgoing pipelines carry away wastewater for disposal.

There are no public data on oil-industry water networks in the Bakken, but Statoil, New Frontier and other petroleum and energy transportation firms are laying new water pipe to wellheads. New Frontier has plans to build wastewater gathering systems and disposal wells near Dickinson, N.D., and Sidney, Mont., to serve oil and gas producers in those areas.

The next step in oilfield water management is recycling frac flowback water. Statoil has tested a fracking method that uses a 50:50 mixture of flow back water and freshwater. The company aims to raise the proportion of flow back water used to 80 percent—greatly reducing the volume of freshwater that must be transported to the wellhead.

For much more on pipelines and other energy transportation infrastructure in the Bakken, look for the upcoming April issue of fedgazette.

More evidence that businesses expect to grow, increase hiring

Signs are upbeat that the Ninth District economy will continue to grow, according to a recent poll of more than 300 business contacts from across the district (see methodology below).

For starters, 40 percent plan to increase employment at their firms, and nearly three-quarters of these firms cited expected high sales growth as the most important factor. Only 7 percent plan to decrease employment. In the same survey a year ago, 38 percent planned to increase employment and 10 percent planned to cut jobs.

Other important factors cited for new hiring were overworked staff, improved financial condition of firms and the need for additional skills. The majority of respondents plan to use word of mouth and advertising to get new employees. Twenty-eight percent plan to use a recruiting firm, and surprisingly few (9 percent) plan to raise starting pay.

For those respondents not planning to hire additional people this year, most expected low growth sales and a desire to keep operating costs low. Many reported difficulty finding skilled candidates. Though fiscal policy developments were not a factor for most respondents, 35 percent said they had a detrimental effect on hiring and 4 percent said they would increase hiring plans.

The survey also asked about wages and benefits; 36 percent expected wage growth of 2.5 percent or more, and a similar amount expected positive wage growth of less than 2.5 percent (see Chart 1). Respondents generally believed benefit increases would be larger than those for wages (see Chart 2).

 

Methodology: On Jan. 15, the Minneapolis Fed invited, via email, about 1,000 Beige Book contacts from across the Ninth District to answer the special question in a web-based survey. By Jan. 31, 303 contacts had filled out the survey. The respondents come from a variety of industries (see table below).

Some oil for the kids, too

Oil has meant many things to North Dakota over the past decade. Along with reversing the state’s population decline, it has pumped new life—students, workers and revenue—into many of the state’s K-12 schools.

The state’s K-12 population has risen from 94,000 in 2007-08 to 99,000 in the current school year, according to the state Department of Public Instruction. Some of the strongest growth has occurred in the 17 western counties in or near the Bakken oil patch. The school district of Williston, the heart of the Bakken, has seen its enrollment rise from 2,100 to 2,800 students over this period.

As a result, school districts are hiring more teachers and other staff. A fedgazette survey of North Dakota school district administrators (with 65 respondents out of about 180 districts statewide) found that more than half added staff last year (see left chart). Employment gains were realized in every quadrant of the state, but were more prevalent in the west. Among 18 respondents in the northwest part of the state, 15 reported employment gains and three reported no change.

School officials have more modest employment expectations for this year—about one-quarter believed they will add school workers (see right chart).

But regardless of location, the large majority are expecting higher revenues. That comes, in part, from higher enrollments, which are part of the education funding formula. But it’s also due to a state education trust that, thanks to fast-growing taxes on oil activity, has grown from $1 billion to $2 billion over the past three years. This after it took more than 100 years to earn the first billion dollars, according to a state source.

The so-called Common Schools Trust Fund distributed about $92 million to school districts in the 2011-13 biennium—about 5 percent of statewide education expenditures—and trust fund officials have said they expect that figure to go up considerably in the next biennium.

Beige Book, Minneapolis: Ninth District economy slowly improving

The Ninth District economy expanded modestly during late summer and early fall, according the most recent Beige Book released this week by the Federal Reserve Bank of Minneapolis.

Each of the 12 Federal Reserve district banks drafts a similar report, which in sum are a summary of regional economic conditions across the country, in preparation for the Oct. 23-24 Federal Open Market Committee meeting, where interest rates and other monetary policy issues are decided.

In the Ninth District, improved activity was seen in construction and real estate, consumer spending, tourism and professional services. Energy and mining continued to perform at high levels, while agriculture varied widely, with crop farmers generally in better condition than animal producers. On the softer side, manufacturing activity slowed in late summer, and wage increases remained subdued, although stronger increases were reported in some areas. But labor markets tightened somewhat, and price increases were generally modest.

For those interested in other regional, national or historical Beige Book reports on economic conditions, the Minneapolis Fed offers everything in one spot.

The efficiency of energy efficiency programs

Everyone knows a penny saved is a penny earned. The environmental adaptation: A penny not spent on power is a penny earned and a carbon unit saved. More utilities (and their government regulators) are using that mantra to encourage investments in energy efficiency so that households and businesses will be convinced to sip rather than guzzle power to save money on monthly bills and lessen their carbon footprint.

A recent report on Minnesota’s utility-based Conservation Improvement Program shows that much more is being spent on energy efficiency projects. The amount of electricity saved by CIP more than doubled to 900,000 megawatt hours (MWh) between 2006 and 2010. But efficiency expenditures—paid for by all ratepayers—went up in roughly equal proportion (see Chart 1), which suggests that there have not been any returns to scale in terms of efficiency gains. In fact, on a per MWh basis, electricity savings have come at slightly higher cost in 2010 ($207) compared with 2006 ($200). (Carbon emission reductions mirror energy savings over time because they are estimated by formula. One MWh of electricity savings equals 0.9 tons of CO2 savings on average.)

 

The increase in CIP costs stems from a change in state policy, which shifted from an expenditure requirement to an energy-savings requirement that is equivalent to 1.5 percent of a utility’s annual retail sales, according to the Minnesota Department of Commerce, in response to questions from the fedgazette. This change also offers one explanation why efficiency programs, in aggregate, have not become more cost effective over time in a nominal sense.

To meet higher levels of energy savings, the agency pointed out, utilities have had to create new programs and eliminate others that were not cost effective. They’ve also had to increase some incentives and invest in outreach activities and program measurement, all of which costs money. New efficiency programs are typically less cost effective than legacy programs (like residential lighting), but the agency expects these to become more cost effective over time.

Also notable, individual utilities vary widely on the average cost of their efficiency investments in a given year (see Chart 2). Size has little to with the variation, with the exception that small utilities had both the highest and lowest average CIP costs on a per MWh basis.

The Commerce Department said there were several likely reasons for the disparity. For example, utilities have different customer and consumption bases (what the industry calls “load profile”). Efficiency projects at commercial and industrial users—who typically consume much more energy—are usually more cost effective than residential projects (whose users are small and dispersed). “So utilities with high residential loads may have to spend more to achieve the same savings,” the agency said.

Utilities also charge different power rates, and those with low electricity costs might have to offer higher incentives to convince users to pursue efficiency projects. Utilities can similarly vary in their experience and ability to promote and execute efficiency programs. Those with a “high level of engagement with its CIP programs” are typically more cost effective, according to Commerce.

But back to those pennies: While costs for energy efficiency projects are borne on an annual basis, energy savings accrue over a number of years. Agency guidelines suggest a weighted average payback period of 15 years or less for individual efficiency projects to be worthwhile. With average electricity costs at roughly $85 per MWh, none of the 2010 projects (in aggregate, at the utility level) faces more than a 10-year payback, and most have payback schedules of about one to five years.

Makin’ power while the wind (subsidy) is still blowin’

Like a nice, steady breeze, the nation’s wind power capacity has been expanding, with Ninth District states making a major contribution. But whether that arc of increase continues could well depend on what Congress decides regarding an expiring tax credit.

After five years of strong growth, the United States now trails only China in installed capacity (47 to 62 gigawatts, respectively) and has 1.5 times the wind-generating capacity of Germany and seven times that of France, according to a comprehensive August report by the U.S. Department of Energy. Wind still makes up a small portion of domestic power generation, at 3.3 percent, but that’s a fourfold increase just since 2006.

Texas is the leader in wind development, and by a wide margin (see Chart 1). But Minnesota and North Dakota are in the top 10 in wind capacity. Minnesota installed as much new wind capacity last year—542 megawatts (MW)—as many states have in sum. South Dakota also made its mark. It has almost 800 MW of wind capacity, virtually all of it installed since 2007, and representing almost all of the state’s increase in power generation over this period. Wind’s share of electricity capacity in the state leapt from less than 2 percent in 2007 to 22 percent, the highest rate in the country (see Table 1).

But the industry is nervously awaiting congressional action on a federal wind energy production tax credit of 2.2 cents per kilowatt hour—currently equal to more than $1 billion annually and set to expire at the end of the year. The credit was created two decades ago and has been extended numerous times or reborn after being allowed to expire. Its renewal is questionable this time around given sentiment in Congress about budget deficits.

The credit's expiration could affect not only future wind power generation in district states, but also district employment at a fair number of manufacturing facilities that supply the various components and services for wind farm development (see map).

Already there have been rumblings, according to local news reports. Otter Tail Corp., of Fergus Falls, Minn., has announced plans to sell DMI Industries, a maker of wind towers in West Fargo, N.D., with the eventual fate of 216 employees unknown. St. Paul-based WindLogics, a wind forecasting company, recently cut 10 employees because development work has stopped.

Officials with Mortenson Construction, one of the largest wind farm builders in the country and located in Golden Valley, Minn., said several hundred jobs could be eliminated if the tax credit expires. In Aberdeen, S.D., officials at the Molded Fiber Glass plant have reportedly put on hold a plan to add 100 to 200 jobs in light of the tax credit limbo.

 Source: U.S. Department of Energy

Wisconsin ratepayers hot over staying cool

In a summer with record heat, Wisconsin residents and businesses are finding out firsthand the high cost of keeping things cool inside. In fact, they are paying more than most for that comfort, according to a June energy assessment by the Public Service Commission of Wisconsin. But that wasn’t the case just a decade ago.

Back in 2002, retail power prices for residential, commercial and industrial customers were average to below average compared with neighboring states and the nation. Over the next eight years, Wisconsin’s electricity rates for all types of customers went up steadily. The state now has the highest, or nearly the highest, electricity rates among neighboring states across all three customer categories. It also has higher rates than the national average for residential and industrial power, and very similar rates for commercial power (see chart).

Among several drivers behind these rate increases, like higher costs for input fuels and spot-power purchases, the report offers some historical context, attributing the state’s rising prices mostly to its position in the long construction cycle for new power generation and transmission, and the subsequent timing of two recessions.

Improvements to electricity infrastructure to meet future power demand and service reliability needs are years—even decades—in the making for utilities. Wisconsin’s economy was quite strong in the 1980s and 1990s and, as a result, “Wisconsin entered the (electricity) construction cycle earlier than other states in the Midwest.” Utilities that built new generation facilities in the 1990s and early 2000s were entitled to recover those costs, which led to higher rates as the state’s economy—and particularly its power-hungry manufacturing base—started to struggle even before the official start of the 2001 recession.

The state’s economy has yet to regain strong footing, and the most recent recession compounded cost-recovery efforts by utilities because many saw a decline in electricity sales (and thus revenue) from the economic slowdown and increased energy conservation efforts. Still, because of their special regulated status, some utilities were allowed to raise rates again.

Even the commission acknowledged the irony, saying that “rate increases during a general usage downturn are confusing to customers … (m)any ratepayers have expressed their anger and frustration publicly and directly to the Commission about utilities raising rates during a time when they are using less in order to reduce their energy costs.”

The report notes, however, that all is not lost for ratepayers in Wisconsin. Having made the investments in new generation, if the economy ever returns to robust growth—and electricity use—“new cost-competitive plants will be positioned to potentially sell any additional energy into the wholesale market benefitting retail customers, because such revenues are directly credited to a utility’s expected revenue requirement during a rate proceeding, reducing the amount of money to be collected from ratepayers.”

A rising oil tide lifts all wages

Average wages have risen dramatically in western North Dakota, where rapid oil and gas development has transformed the economic landscape. Between 2004 and 2011, the average annual wage in counties with substantial oil activity increased over 80 percent in constant dollars, to about $56,000—a surge in compensation that dwarfed increases in the state and nation.

Some of the increase is due to a rising proportion of well-paid workers engaged in activities related to oil and gas—exploration and drilling, transporting oilfield supplies and equipment, building new facilities for oil companies and oilfield service firms. Jobs in mining (a statistical category dominated by oil workers in the region), trucking and construction have posted strong gains during the oil boom (see chart). In 2004, oil-related jobs accounted for just 12 percent of total employment in five core oil-producing counties; in 2011, that share was 41 percent. On average, workers in oil-related industries earned twice the pay of workers in other industries last year.

But most of the increase in oil patch wages stems from labor demand chasing supply, not just in oil-related industries, but in virtually every sector of the regional economy. In communities such as Williston, Watford City and Dickinson, N.D., few workers are available to fill thousands of job openings. Many employers—including those in industries that depend to a lesser extent on oil industry spending—have responded by offering higher pay. For example, in core oil counties, inflation-adjusted wages for hotel and food service workers increased 63 percent from 2004 to 2011. Over the same period, real manufacturing wages increased 21 percent.

An analysis of the relative impact of the two trends—a shift in employment to oil-related activity and across-the-board wage increases—shows that broad wage hikes account for close to three quarters of the average wage increase during the oil boom, while the shift in employment to oil-related activity accounts for about one quarter of the average wage increase. So the oil rush has lifted all workers in the region, not just workers tied to oil and gas extraction.

For much more on labor trends in the oil patch, see the forthcoming April issue of the fedgazette.

Welders have struck gold in the oil patch

In North Dakota and Montana, wages and employment for welders have grown very quickly near the Bakken shale-oil formation in recent years.

The Bureau of Labor Statistics gathers employment data in urban and rural areas of every state and further delineates rural (or nonmetropolitan) areas from each other so that regional patterns can be investigated. Both North Dakota and Montana have four nonmetropolitan areas (in brown in Figure 1) and three metropolitan areas (in white). While the Bakken shale-oil formation covers a significant portion of western North Dakota and eastern Montana, the heart of the Bakken is in red.

 

Much has been written about the economic activity occurring in the district’s oil patch (including in the fedgazette). That growth has led to strong demand for workers in occupations directly tied to oil extraction. That’s particularly the case for welders, which include cutters, solderers and brazers, who are vital in maintaining drilling rigs, pipelines and other oil-related infrastructure.

Not surprisingly, wages and employment for welders in the oil patch are rising, and BLS data offer a snapshot of how they compare to other regions. Chart 1 below plots average annualized employment and wage growth from 2006 to 2010 among nonmetropolitan regions of North Dakota and Montana. Welders generally had much plumper checks and were on more payrolls in the nonmetropolitan regions in or near the Bakken than their coworkers in other nonmetropolitan areas.

 

The growth of employment and wages near the Bakken is impressive, but it’s also a function of how few welders there are in these nonmetropolitan areas. For example, welders’ employment in eastern Montana almost tripled, from 60 to 170. In fact, in 2010 none of North Dakota’s nonmetropolitan areas had more than 400 welders, and none of Montana’s rural regions had more than 200.

The Minneapolis Fed is currently investigating the employment effects of the oil boom in the Bakken formation. Watch for a cover article on this topic in the April fedgazette.

The buzz (or … zzz?) for green power

Much has been made of efforts to increase the country’s renewable energy. A lot of the effort has been on the production side, requiring utility companies to garner a certain percentage of electricity output from renewable sources, like wind and solar power. (See previous fedgazette articles on renewable energy here and here.)

Despite the widespread public support for more renewable energy, so far it appears that many are not willing to put their money where their green side resides. Over the past decade or so, utility companies have rolled out literally hundreds of programs that allow consumers to consciously choose renewable power, but at a small premium over the normal cost of electricity (more on this in a bit).

Consumers who choose green-pricing programs are not necessarily receiving power from a renewable source when they turn on a computer or flat-screen television—the electricity grid is not capable of such pinpoint delivery. In essence, these programs ask consumers to pay more to support the development of renewable energy, which is more expensive than electricity generated by traditional sources like coal or nuclear.

This summer, the Energy Information Administration (EIA) released data that offer the most complete look at subscriptions to green-pricing programs across the country, and about the only safe conclusions are that such programs appear to be buzzing in some states, while snoozing in others. Oregon is by far the leader in green power subscriptions, with 776 subscribers per 10,000 households, almost triple the next closest state, Texas. At the other end, six states have fewer than three in 10,000 households participating (see chart; Ninth District states are highlighted in rose).

 

It’s hard to pinpoint the exact source of the disparity. Economic theory would suggest that program participation depends to some extent on prices—for both existing retail power and the premium charged to be a renewable power subscriber. Cheap electricity rates, for example, might allow and convince some to pay the premiums necessary to support renewable energy.

Unfortunately, that theory doesn’t appear to offer much of an explanation for the wide divergence among states. Seven of the top 10 states in green-power subscriptions—including Minnesota—have electricity rates that are below the national average. (Wisconsin is also in the top 10, but has above-average electricity rates.) Many other states have similarly cheap power at their fingertips, yet have very low participation in green-pricing programs (see chart).

The premiums charged for green power also offer clues. Oregon, the national leader, has 18 separate utility-run programs, many of which charge a premium of 1 to 2 cents per kilowatt hour (kWh) and have been in place since at least 2003. Even with the premium, participating Oregonians still pay less than the national average for electricity. At the other end of the spectrum, Arkansas has the lowest takeup rate in the country, with just 25 subscribers statewide in 2009. One reason is likely that the cost of the program is 5 cents/kWh—roughly a 50 percent increase in the state’s average power rate of about 11 cents/kWh). The program was also implemented in 2008, a comparatively short span to judge its attractiveness.

But there are also enough exceptions to the relationship between premiums and subscribers to suggest that other factors are at play. Montana barely moves the green-pricing needle despite electricity rates that are significantly lower than the national average, along with five green programs charging just 1.1 cents/kWh or less, and a sixth charging 2 cents/kWh. Ohio’s electricity rates are almost identical to Arkansas’ and it has eight green pricing programs that are significantly cheaper (0.5 to 2.5 cents/kWh), yet its participation rate is only slightly better than that of Arkansas (see chart).

Lastly, some states might have low subscription rates because programs are not widely available or are only newly available (as in Arkansas). Though the EIA’s review included the number of participating utilities in each state—which ranged from one in the District of Columbia to 100 in Minnesota—there was no information regarding green-pricing availability among all households in a state.