25 posts categorized "Energy"

Head of the 2013 class (again): North Dakota

North Dakota is like the kid at school who gets all the awards. She can’t help it. Everyone else tries hard, but she’s just that good.

The Bureau of Economic Analysis came out with its most recent estimates on state gross domestic product for 2013. Several Ninth District states were well above average, with Montana and South Dakota both cracking 3 percent and Minnesota not far behind at 2.8 percent.

But North Dakota was running laps around most states at 9.7 percent growth last year. It beat the next closest state (Wyoming) by two full percentage points (see Chart 1).

Those following economic activity in the Ninth District know that North Dakota’s performance is no fluke, the result of a sustained oil boom that started in the early part of the last decade. Since 2003, the state has seen its economy grow at an annual compound rate of 6.6 percent (adjusted for inflation). That's double the growth rate of all but four states over this period.

To put that in context, the state’s economy has roughly doubled since 2003 (inflation-adjusted) to $56 billion in annual output. By comparison, the Montana and South Dakota economies have also done very well among states over this period, ranking among the top quarter in annual growth. Considerably smaller in output compared with Montana and South Dakota in 2003, North Dakota easily leapt over both in total output over the past decade (see Chart 2).

2013 state GDP Ch1

2013 state GDP Ch2

 

Bakken tops in oil production growth

In October, the United States reached an important milestone on the march toward energy independence—more crude oil was pumped from domestic ground than was shipped in from abroad. Domestic production topped 7.7 million barrels per day (bbl/d), exceeding imports for the first time since 1995, according to the U.S. Energy Department.

That milestone might not have been reached—or it would have taken longer to reach—if not for surging crude production in the Bakken region of western North Dakota and eastern Montana. In September, the district’s oil patch hit its own milestone, crossing the 1 million bbl/d threshold. The bulk of that production came from wells in North Dakota, the nation’s second-biggest oil-producing state.

North Dakota and Montana account for only about 13 percent of total U.S. production. But output has grown—and is expected to keep growing—faster in the Bakken region than in the rest of the continental United States and in the nation as a whole (see chart). The North Dakota Pipeline Authority, a state agency that supports pipeline development, forecasts at least a 19 percent increase in Bakken production through the end of next year.

The NDPA recently updated its forecast to reflect advances in well development and drilling techniques over the past few years. Oil companies are spacing well sites closer together—a practice known in the industry as “downspacing”—and drilling multiple wells from single concrete pads. Both methods boost drilling efficiency and reduce labor and infrastructure costs. In addition, producers are tapping into deeper oil reserves—layers of oil-bearing shale below already established oil zones in the Bakken and Three Forks formations.

Bakken production -- 12-2-13

These advances—facilitated by high oil prices that have prompted investment in shale oil plays across the country—hold promise for more record-setting months in the Bakken. The chart shows the NDPA’s conservative production forecast; another development scenario projects even higher oil output in 2014 and for years to come. The NDPA’s latest long-range forecast shows Bakken production peaking a decade from now at about 1.5 million bbl/d.

Blowing out the candle? North Dakota improving on flared gas

The well-publicized growth of oil production in North Dakota is bringing with it increased production of natural gas and rising attention to the practice of flaring natural gas. A recent report by the North Dakota Pipeline Authority suggests that progress is being made in getting more natural gas to market, even as more gas (by volume) is being flared.

Over the past three years, natural gas production has roughly tripled (see Chart 1), but so too has the amount of gas burned at the wellhead rather than captured and sold. The pipeline agency estimates that there are almost 4,700 wells flaring natural gas in the state. Most of these are so-called low-flaring wells; roughly half of the wells account for 99 percent of flaring.

Today almost 30 percent of natural gas produced in the state, a byproduct of oil production, is flared off—for the simple reason that its collection requires localized pipeline systems and processing plants. This requires considerable capital investment, not an easy sell at current prices. (For more background and discussion on natural gas production, pipelines and processing in the Bakken region, see “Dealing with gas” in the April fedgazette.)

Of all flared gas, the pipeline authority estimates that about 45 percent comes from wells that are not connected to existing pipelines and processing plants. The rest comes from wells that are connected and selling some of their natural gas production, but existing infrastructure (including processing plants) can’t handle more volume. Also, some natural gas from lower-pressure wells is flared because it’s being displaced on pipelines by gas from newer, higher-pressure wells. The good news is that the percentage of new wells making some sales has increased (see Chart 2).

Natural gas flaring CH 1-2-- 10-31-13

Part of the solution to flaring is more processing capacity. One Bakken pipeline, completed in September, sits idle as it waits for expanded capacity at a Tioga, N.D., processing plant. But more capacity is coming online and planned for coming years (see Chart 3), though it’s uncertain whether it will keep up with rising production. The state currently has 20 natural gas processing/conditioning plants, and six new or expanded plants are expected in the next few years, increasing total capacity by about 45 percent.

The pipeline agency notes that “momentum is shifting in favor of further expansion of natural gas gathering and processing. The same market drivers that have worked to bring nationwide flaring below 1 (percent) in the United States exist today in North Dakota.” But it added that reducing flaring to below 5 percent in North Dakota “will take years to accomplish,” in part because under current practices and energy prices—particularly the high price of oil—producers can flare and still capture 93 percent of the energy content of well production and 97 percent of the economic value (see Chart 4).

Natural gas flaring CH 3-4-- 10-31-13 

All charts reproduced with permission from the North Dakota Pipeline Authority.

Black fiscal gold: North Dakota oil taxes expected to keep pumping

In the midst of a federal government shutdown over raising the debt ceiling, it’s hard not to stop and gawk at North Dakota’s fiscal position stemming from rapidly rising oil and gas production in the western part of the state.

As recently as the 2003-05 biennium, oil and gas production taxes totaled just $120 million. A decade later, this tax revenue is expected to hit $5.2 billion in the current biennium through fiscal year 2015.

Comparatively little of that money—$300 million, by state statute—goes to the state general fund for lawmakers to spend as they please. Property tax relief has also been championed in recent budgets, but allocations for this priority remained unchanged at $342 million despite the rise in oil and gas tax revenue.

North Dakota has taken the unique step of funneling a significant amount of oil and gas taxes to permanent trust funds. This biennium, the state expects to divert $2 billion toward the Legacy and the Common Schools trust funds and does not include several hundred million in expected royalties from production on state lands that will also go to the school trust. (For more background and discussion on permanent trusts in North Dakota and other top energy producing states, see the recent fedgazette article, “Saving for a rainy, oil-free day.”)

But there was still plenty left over to finance new roads, schools and other infrastructure to deal with breakneck development across the Bakken oil-producing region. But rather than dramatically increase departmental budgets, the state has preferred to allocate money to special-use funds (which can be tapped for a variety of purposes), and to send more money directly to local governments to deal with local needs. These allocations also saw the largest increases in the current state budget. (For more on the fiscal trends among North Dakota local and state governments, see “Congratulations on your oil boom” in the July fedgazette.)

This tax revenue shows little sign of slowing. In late September, Department of Mineral Resources Director Lynn Helms told an audience of industry and local government officials that he expects the state’s daily oil production will double to 1.6 million barrels by 2017.

Oil & gas allocations -- 10-8-13

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).

  Ad hoc survey Ch 1-2 -- 2-5-13

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).

Ad hoc survey METHOD TABLE -- 2-5-13

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.

ND school administrators -- 1-25-13

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.)

  EE in CIP CH1 -- 9-13-12

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.

EE in CIP CH2 -- 9-13-12

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).

Wind power Ch1& Table1

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.

 Wind map -- 8-15-12jpgSource: U.S. Department of Energy