Natural Gas Supply: Owning Capacity or Buying Delivered Supply

Around our homes and around the office, much of what we do revolves around food.  We all need food for survival.  It is pretty straight forward.  When we are hungry, we want to eat, we want to know what time we are going to eat and we always like food to be available.  Large volume natural gas customer needs are also pretty straight forward.  They want their natural gas on time, at a specified point, and available to meet their demand.

While the options available to us when it comes to dietary choices seem endless, the options of how we purchase natural gas are not quite as lengthy.  There are however, options available and choices that need to be made.  Most options can be categorized into two groups:  Customers who own capacity on a pipeline and customers who purchase delivered supply from a natural gas marketer.

When a customer owns their own natural gas pipeline capacity, they are committing to an “a la carte” way of buying natural gas.  Just like going to an up-scale restaurant, you are purchasing each piece of your meal separately to complete the experience.  Buying natural gas supply from a marketer is more like buying a combo meal from any of the local fast-food restaurants.  Most everything is provided for you in an all-inclusive price and in a nice little pre-decided package.  The results of each are the same; you are now less hungry and you have received natural gas at your facility.  Everything else just depends on what your needs are at a given point of time.

We can all relate to why we may choose a nice steakhouse over a combo meal, so let’s leave the food analogy behind for just a moment.  Let’s consider the reasons you may choose between owning capacity and buying from a marketer.  Owning capacity on a pipeline means you are committed to a receipt and delivery point at a specified price for the length of the agreed upon term.  The terms of the agreement are very specific on how the natural gas flows and can be 10 to 15 year contracts.

Customers may elect to own capacity for any of the following reasons:

  • They have constructed their own pipeline attached to a major inter/intrastate pipeline;
  • Their business plan and subsequent production schedule certainty extends far into the future;
  • Their facility is located in a constrained area;
  • Or their operation cannot be interrupted for any reason.

Owning capacity gives a great deal of control to the customer.  Along with this control comes the responsibility of managing the capacity or contracting with a third party to manage it for you. When buying from a marketer, you agree to a price, delivery point and level of management you require for the natural gas.  Because a marketer potentially owns multiple pieces of capacity, there is flexibility within the terms of the agreement as to how the natural gas may flow to the delivery point.  Marketers may also have specialized products they have developed that offer benefits to customers based on a geographic, utility or pipeline dynamic.

Capacity and marketer choices available in the region around your facility can be overwhelming.  Sorting through the options and offering solutions is where U.S. Energy can help.  We are here to assist your teams through the entire procurement process.  We can help you identify options in the natural gas world that you are not aware of.  Give U.S. Energy a call and allow us to assist your team.

The Drilling Rig Count is Not Necessarily Indicative of Future Gas Production

Author: Kurt Garst, Account Manager, U.S. Energy Services

For many years the number of active drilling rigs has been used as a general indicator of future gas production. This premise was never perfect and developments over the past few years have continued to break down this indicator relationship.

Chart 1 below shows oil and gas drilling activity since 2008. From 2009 through 2014 oil prices were generally increasing and natural gas prices were declining. Oil and gas drillers reacted to this pricing environment by shifting drilling resources from gas to oil. However during this time of decreased drilling of gas wells, gas production increased substantially as shown in Chart 2. Clearly the decreased gas drilling count did not lead to lower gas production during this period.

oil-gas-chart1

Chart1.

gas-prod-chart2

Chart 2.

The drilling rig count is an enumeration of how many rigs are drilling wells, not how many wells are producing gas or oil. Also the number of rigs actively drilling doesn’t necessarily indicate how much gas the new wells being drilled will produce. Further, a well that has been drilled isn’t ready to produce gas until it has been completed and connected to a gas pipeline. Delays can occur between drilling and connection. There can be several reasons for delays. For instance, gas prices may have dropped too low to justify completing and connecting the well. Another reason can be that a pipeline connection is not immediately available or there is not sufficient capacity in the connecting pipeline to transport gas to market. Also, crews may not be available to finish the well completion work.

The past ten years have seen remarkable advancements in drilling oil and gas wells. This has further strained the relationship between the count of active drilling rigs and gas production.

  • Drillers are better at knowing where to drill for oil and gas than in the past. Technological advancements provide better indications of what is below the earth’s surface. This increases the success rate of drilling wells which in turn reduces the number of rigs needed to drill wells that successfully produce gas and oil.
  • Advancements in fracking and horizontal drilling methods have allowed drillers to successfully produce gas from less permeable rock formations (shale) than ever before. Better fracking techniques rupture rock formations and create better paths for gas and oil to reach the well. Improved horizontal drilling allows drillers to bore a well better following the oil and gas producing zone rather than previous techniques that only punctured zones perpendicularly. This exposes the well to more productive areas of the oil and gas reservoir and increases gas flow. Fewer rigs are needed to drill wells into productive areas than before.
  • Many of these shale formations containing oil and gas are relatively shallow. Wells drilled into these producing areas can be drilled quicker because drillers don’t have to penetrate as far into the earth as the wells being drilled prior to the availability of fracking and horizontal techniques. This decreases the drilling time and costs which decreases the number of rigs needed to drill wells.
  • Multiple wells can be drilled from the same location using directional and horizontal drilling. This means drilling rigs don’t have to be shut down, relocated and set back up before drilling a new well. A single rig can drill more wells faster.

Another important change over the last decade is that it is no longer as easy to designate a well as an oil or gas well. Many more wells are producing both oil and gas. Therefore looking at a count of the rigs drilling for gas can underestimate the future number of wells that will be producing gas.

In conclusion, the number of rigs drilling for gas is related to future gas production, but cannot be used as a primary indicator without consideration being given to other important factors.

Going Underground: A Focus on Natural Gas Storage

Author: Doug Allen, Account Manager, U.S. Energy Services

U.S. Energy Information Administration (EIA) is an agency within the U.S. Department of Energy that collects and analyzes energy-related data and statistics.  The EIA was created in the 1970’s to provide lawmakers, industry and the public with unbiased and independent energy related information for the purpose of promoting sound policy, ensuring efficient markets, and helping the public understand energy and its relationship to the economy and the environment.

Each week the EIA releases data on the levels of natural gas in storage in the United States.  This closely watched indicator can have a significant impact on the natural gas prices, often moving the market sharply within moments of the release.   Since the U.S. must rely on natural gas from storage to meet winter demand, reports that show levels that are lower than anticipated or that might portend insufficient storage levels in the future tend to push prices higher.   If the expectations are that storage levels may become too high, and thus create a natural gas glut, the market may have a more bearish price reaction.

Natural gas is primarily stored underground in depleted oil and gas fields, natural aquifers converted to storage facilities and salt caverns.  There are about 400 underground facilities currently in use with a cumulative working gas capacity of 4.659 tcf (trillion cubic feet).   The total U.S. consumption of natural gas was about 27.47 tcf in 2015.

nt-gas-storage-facilities

While 126 operating entities own these facilities, the actual storage capacity is contracted to many customers.  Data from the EIA website shows us that the 20% of all storage operators manage nearly 70% of the storage in the lower 48 states.  Most of these are interstate pipelines and utility companies.  A deeper dive into the index of the pipeline customers shows that they contract out most of their storage to natural gas and electric utility companies.  Ultimately, utilities control the bulk of U.S. natural gas storage.

storage-facility-operators

To collect the data for the Weekly Natural Gas Storage Report, storage companies that are “statistically selected by the EIA from a listing of all underground natural gas storage operators in the United States” must complete and submit a form detailing their natural gas storage levels.  The EIA estimates the total natural gas storage level based on this sample.

The EIA’s Weekly Natural Gas Storage Report is released each Thursday at 10:30 a.m. Eastern and can be found at this website: http://ir.eia.gov/ngs/ngs.html.  The website also includes historical data, reporting methodologies and any changes to the report release schedule for holidays.   The Weekly Natural Gas Storage Report is a key component of the EIA’s Natural Gas Weekly Update.

Sources: http://www.eia.gov/

Atlantic Coast Pipeline

Author: Kelly Zabel, Account Manager, U.S. Energy Services

Despite abundant natural gas supplies in the Marcellus shale play, lack of pipeline capacity and infrastructure to get this natural gas supply to the growing demand of Virginia and North Carolina has contributed to residents and companies not being able to reap the benefits of the bountiful harvest that has been occurring there for a few years now.  To remedy this situation, four companies – Dominion, Duke Energy, Piedmont Natural Gas, and AGL Resources – have teamed up in a joint venture to build and own the Atlantic Coast Pipeline (ACP).  Some of the benefits of this new pipeline include increased electric generation from a cleaner fuel source (vs. coal), improved service reliability, and room for further customer growth and economic development.  The need for this new pipeline is so heavily felt and widespread that 96% of the capacity is already spoken for under various purchase agreements.

The proposed route is approximately 550 miles long, originating in Harrison County, West Virginia, stretching southeast to Greensville County, Virginia, and then continuing to southern North Carolina.  This includes an almost 70 mile long eastern lateral to Hampton Roads.

acp-project-map

Currently, the ACP Team is in the middle of surveying along the proposed route and about 90% of landowners have granted permission for their land to be surveyed.  However, this pipeline is facing strong opposition from rural landowners, especially in Virginia.  Governors of Virginia, West Virginia, and North Carolina are behind the project, stating that this will boost their economies, help their communities, and bring more manufacturing business to their areas.  Yet dozens of landowners are refusing to allow the ACP Team to survey on their land, resulting in numerous lawsuits with more to come.  Opposition groups state a decrease in tourism and damage to the environment and economy as some of the reasons for their reluctance to cooperate.

The ACP Team has also been busy with FERC, submitting the necessary filings to keep this major project moving.  Below is the estimated timeline of the Atlantic Coast Pipeline Project.

project-timing

Underwater Pipelines

Author: Sandy Zoulek, Account Manager, U.S. Energy Services

Did you know there is an oil pipeline crossing under the water at the five-mile stretch between the Upper and Lower Peninsula of Michigan, where Lake Michigan and Lake Huron meet? The area between the two Great Lakes is called the Straits of Mackinac.  The pipeline, called “Line 5” by its owners, Enbridge Energy, is part of an extensive system which transports oil and liquefied natural gas throughout the Midwest and Canada.

Mackinac Bridge, spanning 5 miles, and connecting the Lower and Upper Peninsula

Mackinac Bridge, spanning 5 miles, and connecting the Lower and Upper Peninsula

Built in 1953, Line 5 is a 30” diameter pipeline that runs 645 miles, originating in Wisconsin, running under the Straits of Mackinac, and ending in Sarnia, Canada.  When underwater, the pipeline consists of two side by side 20” diameter pipes which span the distance shore to shore of approximately 5 miles.  The pipes range in depth, up to 270 feet underwater and 20 million gallons of light crude oil and natural gas fluids pass through them each day.

map-pipeline


Did you also know that “The Great Lakes and their connecting channels contain more than 90% of the freshwater of the United States and 20% of the world’s supply of fresh surface water?” National Wildlife Federation 2012


With this fact, and since the pipeline is 63 years old (some consider 50 years the ‘life expectancy’), many activist groups (Patagonia commissioned a Documentary:  Great Lakes, Bad Lines) and Michigan Counties are calling for its retirement.  Reasons range from the obvious risk of a spill, to failure to comply with easement rules, poor safety record by the pipeline’s owner, and the example of the spill on the Kalamazoo River (MI) in 2010 from Line 6B of the Enbridge portfolio. (The Kalamazoo River spill is the largest inland oil spill in US history, releasing one million gallons of heavy crude oil.)

Due to the impending risk of a spill, some Michigan legislators have filed suit to have the pipeline be re-categorized as an off shore pipeline.  Under the Oil Pollution Act, the liability for cleanup costs for owners or operators of onshore facilities is capped at $634 million, whereas companies operating pipelines classified as offshore facilities are required to demonstrate they have sufficient resources to pay for all cleanup costs.

In March of 2016, David Schwab, PH.D., of the University of Michigan Water Center, conducted a study of what he determined was the “worst possible place for an oil spill”. (Statistical Analysis of Straits of Mackinac Line 5: Worst Case Spill Scenarios)  The study, complete with animation to determine to potential flow of the spill, shows that 700 miles of shoreline would be affected by a spill in the Straits.  The Straits are subject to wide and varying factors including constantly changing currents, wind, and ice that would contribute to the complexity of a spill.

Enbridge is fighting back stating that the U of M Water Center modeling study was based on unrealistic assumptions.  Additionally, they have  “introduced new measures to help ensure the line continues to safely transport light crude oil and natural gas liquids……” further stating that “It does not and will not, carry heavy oil.” (heavy oil includes bitumen which was a key factor in the spill cleanup issues at Kalamazoo) Enbridge also states that the line is being operated at less than 25% of its maximum pressure capacity for enhanced safety.

Since the Kalamazoo spill, Enbridge has changed the way it operates, implementing numerous enhancements to operating and safety procedures.  They have established a Pipeline Control System and Leak Detection (PCSLD) department to better focus on maintenance needs. The response time for a spill is listed as 3 minutes in their many online brochures about Line 5.

Enbridge carries out hundreds of safety drills each year, but also embarked in a mock oil spill drill in 2015 specifically in the Straits of Mackinac to show their commitment to the safety of the Straits, Lake Michigan, Lake Huron, and the lakeshore.

This pipeline, as are all 2 million+ miles of pipeline, is governed by the Pipeline Hazardous Material Safety Administration (PHMSA) who is carefully monitoring the safety practices of Enbridge and Line 5. PHMSA’s focus is on public and environmental safety, holding Enbridge and all other pipeline owners and operators accountable for proper maintenance and safe operations.

Emails from Enbridge spokesperson, Ryan Duffy, state that “Line 5, while not perfect, is in very good condition and meets or exceeds today’s standards for new pipelines.”

Everyone, including Enbridge, agrees that an oil spill in the pristine waters of the Straits of Mackinac would be catastrophic.

 

Capacity Cost in the American Midcontinent

Author: Carl Doten, Account Manager, U.S. Energy Services

The 4th Midcontinent Independent System Operator (MISO) capacity auction was held earlier this month and the results of the auction have now been published (MISO Resource Adequacy Auction Results). The recently published prices offer insight into both expected energy costs for the coming delivery year of June 1, 2016 through May 31, 2017, and trends within the capacity supply/demand balance of each respective zone.

miso-territoryA map of MISO’s territory by zone is shown to the right. Electric consumers located in any of these zones, are likely to be impacted by the auction results either through potential cost changes in base rates in fully regulated service territories or cost changes in the capacity line item component in deregulated service territories.

The extent to which a consumer is impacted by the auction depends on a number of factors including:

  1. Which zone a consumer is located in (unit cost)
  2. Assigned capacity requirement (kW units)
  3. Energy contract structure (exposure)

The auction results (shown in $/Megawatt Day) by zone are shown in the table below along with the results of prior years.

auction-results-table

A review of the results with an understanding of the wider context prompts a few observations:

  1. All regions will be adequately supplied with capacity for the coming delivery year.
  2. Six of ten zones within the MISO will see higher capacity prices, while Zone 4 will find welcome relief from the prices of the last delivery year.
  3. The results indicate a shrinking in the available pool of capacity offerings. Most notable was the approximate 2,000 MW of capacity at the price taker point (bid in around $0/MW-day), and 3,000 MW of capacity this last year at the $160/MW-day price point. These losses represent approximately 5% of the bid capacity within the region.
  4. Regional capacity varied only slightly from what was expected, with much of the differential attributed to Reciprocating Internal Combustion Engine (RICE) regulations causing early retirements.

Finally, it should be acknowledged that within the MISO territory, the price set by the auction is only one approach to setting the cost to end users for the capacity component of pricing, and therefore should be looked at more as a price trend indicator than a specific unit cost.

From a higher level, the variability of pricing year over year, and from zone to zone provides a reasonable defense for the efforts that are underway to revise the capacity auction framework in MISO zones that rely on competitive markets to satisfy capacity needs (currently limited to Zone 4 as proposed).  The proposed shift to an annual auction covering the coming 3 delivery years (similar to PJM) would allow end users to better forecast costs, and would allow generators to finance and plan their generation resources based on a longer term view.

For Risk Averse Fuel Consumers, Now May Be A Good Time To Forward Purchase Your Diesel And Gasoline Supplies.

Author: Craig Petter, Account Manager, U.S. Energy Services

Diesel fuel retail price falls below $2.00 per gallon for first time since 2005

weekly-retail-diesel-prices

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Source: U.S. Energy Information Administration

In mid-February the weekly diesel price survey showed an average retail price for on-highway diesel fuel at $1.98 per gallon. This is the first time the price for diesel has fallen below $2.00 per gallon since February 2005. These lower prices are a reflection of lower per-barrel crude prices and significant storage inventories.

 

Fundamentals Driving Low Prices

Increases in production               

na-oil-production

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Source: U.S. Energy Information Administration

 

Increases in national storage inventories

distillate-fuel

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  • EIA data showed a 9.4 million barrel increase in domestic stockpiles.
    • Inventory levels have risen by over 50 million barrels since the start of the year and sit at the highest level since 1930.
  • Global crude market remains bearish amid oversupply and tepid demand.
  • Crude market traded at significant bottom in February, but fundamental reasons surrounding the price collapse are still very much in place.
  • With a shrinking wholesale market, consumers are benefiting from lower supplier markup.

 

Bullish signals

Exploratory rig counts dropping

oil-gas-rig-count-spill

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Source: U.S. Energy Information Administration

 

Petroleum exports continue to rise

us-petro-exports

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Source: U.S. Energy Information Administration

  • Rigs searching for new production sources are at historic lows.
  • The cost to produce supplies is greater than the current market for many suppliers.
  • Suppliers are capping off already drilled wells in anticipation of higher per barrel pricing in the future.
  • Smaller suppliers being pushed out due to bankruptcy or acquisition.

 

Consumer Options

With the significant decline in diesel and gasoline pricing over the past few years, many end users are taking advantage of these low prices and developing a Price Risk Management Program (aka Hedging). This is a program where the consumer can forward purchase fuel supplies at a known price.  Locking in all or a percentage of your future fuel costs (hedging) is a powerful tool to mitigate the volatility of an unpredictable market.

Some of the benefits of a disciplined Price Risk Management Plan are:

  • Allows you to “fix” your future diesel and gasoline costs today
  • Reduces market price volatility
  • Increases price certainty
  • Allows you to budget diesel and gasoline costs more accurately
  • Current market conditions are approximately $.45/gallon less than last year

Contact Us

info@usenergyservices.com

763-543-4600

Congress Extends Tax Credits for Solar & Wind

The week before Christmas Congress passed a pair of budget bills that contained multi-year extensions of tax credits to encourage solar and wind energy development. The extensions were part of a package deal that included extensions for other renewable energy sources such as geothermal, landfill gas, and hydro in exchange for lifting the 1970s ban on the export of crude oil.

The solar energy Investment Tax Credit (ITC) was set to decline from 30% to 10% at the end of 2016. The legislation extends the tax credit at the 30% level through the end of 2019, after which it will decline annually until it hits 10% in 2022. The extension will help the solar industry avoid the boom and bust cycles that have plagued the wind industry due to chronic uncertainty around the production tax credit.

The wind Production Tax Credit (PTC) was extended at the $0.023/kWh level through 2016. The PTC will then decline 20% per year from 2017 through 2020.

The extension of the ITC will help solar to continue its rapid growth trajectory. GTM research attributes a 30% increase in solar investment through 2020, more than $40 billion, to the extension of the ITC. Overall, GTM is predicting that nearly 100 gigawatts of installations, representing $130 billion in investments by 2020. Though a net positive, Bloomberg New Energy Finance (BNEF) is predicting that the extension of the ITC will reduce the amount of solar installed in 2016 as developers no longer have to rush to meet the ITC expiration deadline at the end of 2016. Overall, BNEF predicts the total solar installations in 2016 will be down about 2.8 gigawatts, but the 2017 increase will more than make up for this reduction.

Energy Management Increasingly Seen as a Source of Competitive Advantage

Deloitte’s 2015 Resource Study found that business increasingly views an active energy management program as a way to create and maintain competitive advantage. The study, first conducted in 2011 and update annually thereafter, is based on a survey of over 600 corporate energy management decision-makers. Fully 44% (up 10% from 2014) of respondents identified energy management as integrated into corporate strategy, while 37% said energy management is integrated at the business unit or site level. Reducing electricity costs was identified as a key goal:

  • 79% identified reducing electric costs as important to financial competitiveness
  • 77% identified reducing electric costs as important to image/brand competitiveness

The latter suggests that companies are motivated by more than just cost-cutting; they are also taking into account external stakeholder views.

Businesses are spending capital to achieve their energy management goals. Goals have been set around electricity (88%), natural gas (64%), transportation fuels (59%), carbon (57%), and water (70%), with approximately one-quarter of goals across all five areas being targeted reduction goals.  Ninety-three percent of businesses indicate they invested capital over the last five years to achieve energy goals, totaling around 17% of overall capital spending.

The most popular technologies and strategies for achieving energy management goals in 2015 were:

  • 55% timers/sensors to control when equipment is powered on
  • 53% motion sensors
  • 47% building energy management systems
  • 41% demand response programs
  • 39% onsite generation technology such as solar panels
  • 34% energy recovery systems
  • 26% batteries for load shifting and peak shaving

New technologies will continue to drive increased corporate energy efficiency. A 2015 study by McKinsey & Company finds that operational improvements can improve energy efficiency 10-20%, but investment in new technologies can increase the savings to as high as 50%. Overall, the study finds that adoption of innovative technologies could save industry over $600 billion per year globally. The report outlines new technologies for the following nine sectors.

  • Advanced Industries (e.g. semiconductors, electronics)
  • Cement
  • Chemical
  • Oil Refining
  • Consumer Goods
  • Mining
  • Power
  • Pulp and Paper
  • Steel

The full report can be found here — Greening the future: New technologies that could transform how industry uses energy.

REAP: Rural Renewable Energy & Efficiency

The Rural Energy for America Program (REAP) was created by Congress in the 2008 Farm Bill. Administered by the U.S. Department of Agriculture (USDA) the REAP program provides grants and guaranteed loans to agricultural producers and rural small businesses for renewable energy projects or energy efficiency improvements. In August, the USDA announced $63 million in loans and grants for 264 renewable energy and energy efficiency projects so far in 2015. Several of U.S. Energy’s ethanol clients have made applications to the REAP program to support their energy efficiency improvement efforts.

Applicant Eligibility

Agricultural producers may be in rural or non-rural areas as long as they derive at least 50% of gross income from agricultural operations

Small businesses must be in an area other than a city or town with a population of 50,000 or more. Small businesses can check if they are in an eligible rural area here.

Project Eligibility

Renewable Energy Systems – funds may be used for purchase, installation, and construction of systems. Examples of eligible renewable energy systems include:

  • Biomass
  • Geothermal
  • Hydropower
  • Wind
  • Solar

Energy Efficiency Improvements – funds may be used for purchase, installation, and construction of improvements. Examples of eligible efficiency improvements include:

  • Lighting
  • Insulation, doors & windows
  • High efficiency HVAC
  • High efficiency motors and pumps

Funding Types

Grants and loan guarantees are available through the REAP program and individual projects may apply for one or both. Combined grant and loan guarantee funding cannot be more than 75% of the total project cost.

Grants

  • Grants up to 25% of total project cost
  • Renewable energy system grants range between $2,500 – $500,000
  • Energy efficiency grants range between $1,500 – $250,000

Loan Guarantees

  • Loan guarantees up to 75% of total project cost
  • Minimum loan amount of $5,000
  • Maximum loan amount of $25 million

Energy Audits and Assessments

When applying for energy efficiency improvement (EEI) funding an energy audit or assessment is also required as part of the application package. For EEI projects with a total cost greater than $200,000 an Energy Audit must be conducted. For EEI projects with a total cost of less than $200,000 an Energy Assessment or Energy Audit may be done. In general, the Energy Audit requires more in-depth analysis of the proposed EEI, such as detailed specifications, measurement plan, and calculation of direct and indirect costs.

REAP Resource Links