Sunken history behind Penobscot dams

As two dams come out of Maine's Penobscot River, the conservation organization leading the dam removal effort has discovered what historians might view as sunken treasure: submerged mill dam structures from centuries past.  At the same time, these sunken dam remnants may continue to impede fish passage once the modern dams are removed, potentially frustrating the dam owner's intent in removing them.

The Penobscot River Restoration Trust is undertaking the removal of the Veazie and Great Works Dams on the Penobscot River.  Following a 2004 settlement agreement among previous dam owners, environmental and conservation groups, and governmental agencies, the Federal Energy Regulatory Commission approved their removal, along with the installation of fish passage equipment at the upstream Howland dam on the Piscataquis River.

Dam removal is expected to help fish and other aquatic wildlife, but FERC required the Trust to develop a plan to mitigate any adverse impacts of dam removal on infrastructure and archaeologic resources.  For example, the Trust knew that the historic remnants of previous dams and lumber mills lay submerged in the impoundment behind the Veazie Dam.  The remnants are associated with a series of lumber mills successively known as the Penobscot Mill Dam Company Mills, the City Mills, the Corporation Mills, and the Veazie Lumber Company Mill, which consisted of two sets of saw mills connected along water-control structures that ran parallel to the Penobscot River, and which were constructed in the mid-nineteenth century. Moreover, the site was purchased in 1889 for use as one of Maine’s first
hydroelectric facilities.

The Trust, along with the state historical preservation office, entered into a memorandum of agreement requiring the Trust to document the Veazie remnant structures after the modern dam is removed.  Because the historic mill dam is expected to impair natural river flow after the modern dam is gone, the Trust also plans to remove the historic structure after it is documented.

As it turns out, the historic Veazie dam is not the only historic or archaeological resource submerged beneath the Penobscot River's waters. While finalizing plans for removal of the Great Works dam, the Trust discovered that a similar, inundated, remnant structures exist in the Great Works impoundment.  The structural remains within the impoundment of the Great Works Dam were constructed as two structures in the early 19th century to provide water for two early sawmill complexes on the Penobscot River at Great Works: for the mills of Rufus Dwinel on the west bank, and for the mills of the Great Works Milling and Manufacturing Company on the east bank. These original dams, on each side of the river, were built as wing dams that extended upriver and out from the river bank, and likely were built independently of each other. The two dams were then consolidated under a single ownership in the early 1880s by the Penobscot Chemical Fibre Company, who built an early mill for producing wood pulp for paper on the Penobscot River.

Both of these sites may be eligible for nomination to the National Register of Historic Places as historic archaeological sites.

As a result of the re-discovery of these additional historic remnants, the Trust sought and obtained FERC's approval to document and remove part of the historic Great Works structures.  The Trust anticipates removing the modern Great Works dam as early as this summer.

spring-fed small hydro in Idaho?

Small-scale hydroelectric projects are receiving renewed interest as society looks for cost-effective ways to produce electricity using local, renewable resources.  Depending on available sites and on what alterntative resources might be available, microhydro or small-scale hydroelectric projects can fit the bill.  Even if you own a first-class site for a microhydro project, before you can build or operate your project, you need to understand what federal and state regulations may apply.  Some small hydro projects are treated much like full-scale dam-based hydropower projects, while others (like small projects using existing conduits, pipes or canals) can get an easier regulatory path to approval.

A small hydro project proposed near Grace, Idaho illustrates some of these regulatory considerations, and the importance of understanding how regulators apply the rules.  Grace is a town of about 1,000 people located in Idaho's Gem Valley.  The Bear River runs through the valley on its course flowing out of Bear Lake, around the Bear River Range by Soda Springs, and then south through Grace into Utah's Cache Valley.  In the early twentieth century, recognizing the area's water resources and topographic variation, a series of dams, diversion pipes and powerhouses were built along the Bear River to produce hydroelectricity.  One side effect was that a stretch of river known as Black Canyon was largely dewatered, as an aqueduct carried the water around the canyon to a downstream powerhouse.  Ultimately, Utah Power and Light (and then PacifiCorp) came to operate these assets, and chose to remove one of the dams, an aqueduct and one powerhouse in 2006 and 2007, and to provide some increased flows through the Black Canyon section.

There may be ways to generate hydroelectricity in Grace without diverting water away from the Bear River. Last month, a local farmer with interests in canals and hydro development proposed a new hydro project near Grace.  The Gilbert Hydropower Project proposed to capture the flows of several natural springs and pipe this water about 700 feet to a turbine/generator unit.  Currently, the water is partially used for pasture irrigation with the unused portion flowing into the Bear River; the developer proposes to install a 24‐inch diameter above-ground pipeline to send the water to a Pelton turbine attached to a 75 kW generator.

In its application to the Federal Energy Regulatory Commission (docketed by FERC as Project No. 14367-000), the project developer requested an exemption from the licensing requirements of the Federal Power Act under the so-called "5 megawatt exemption" rule.  That rule allows the Commission to exempt small hydroelectric projects with an installed capacity of 5 megawatts or less that: (1) are located at the site of any dam in existence on or before July 22, 2005, and that use the water power potential of such dam for the generation of electricity; or (2) use a “natural water feature” to generate electricity, without the need for any dam or impoundment.

FERC dismissed the Gilbert project's request for an exemption, noting, "Because [the] project would utilize the flows of a natural spring that travel through 700 feet of pipe to reach the proposed turbine/generator unit, it would neither be at the site of an existing dam nor use the flows from a natural water feature", and thus was ineligible for an exemption.  However, FERC did invite the Gilbert developers to convert their exemption application to a license application, which the developers did earlier this month.  The developers now have until June 18, 2012, to submit the additional information needed for a complete license application.

What's in the future for Grace, Idaho?  What role could using nontraditional water resources such as springs play there or elsewhere in our energy future?

Removing WA's Condit dam, recap

A major dam removal project is underway on the White Salmon River in the state of Washington.  Video footage of its breach (made available by National Geographic) shows something few living humans have seen but which is already recur in the near future: the removal of a major dam and associated dewatering of its impoundment.

In 1913, the Northwestern Electric Company built the Condit Hydroelectric Project to provide electricity to a nearby paper company and even to feed Portland, Oregon.  The dam was rated at 14.7 MW of nameplate capacity - a far cry from the Hoover Dam (2080 MW) or Grand Coulee Dam (6809 MW), but nevertheless a major dam in terms of its power production and significance.

In 1996, increasing pressure on dam owner PacifiCorp to install fish ladders and perform modifications for environmental compliance led PacifiCorp to seek the dam's decommissioning and removal.  In 2010, the Federal Energy Regulatory Commission approved the removal of the Condit Dam.  In late 2011, contractors breached the dam, draining the upstream impoundment.

If you haven't seen a dam breach before, or if you are simply impressed by the immense power of moving water, you may appreciate the National Geographic video footage of the Condit Dam's breach and the resulting rush of water and sediment.

Now that the Condit Dam has been removed, remediation and restoration efforts are under way.  You can track those efforts on the Washington State Department of Ecology's website, as well as on PacifiCorp's website.

Maine regulators approve tidal energy PPA concept

Yesterday, the Maine Public Utilities Commission approved the terms of a power purchase agreement between three large utilities and a hydrokinetic tidal power project in Maine waters.

Low tide at Preble Cove, Great Cranberry Island, Maine.

Hydrokinetic energy projects produce electricity from moving water like tides, waves, ocean currents, or rivers, typically without dams.  As I noted yesterday, a 2010 Maine law required the PUC to conduct a competitive process to solicit proposals for long-term contracts for offshore wind and tidal projects.  The PUC received multiple submissions in response.  Commission staff have been negotiating with some of the bidders, and yesterday approved a proposal by Ocean Renewable Power Co. to sell the output of a small tidal project in Cobscook Bay to Maine's three largest utilities.

Under the terms approved the Commission, ORPC will receive a 20-year contract with utilities Central Maine Power Co., Bangor Hydro-Electric Co., and Maine Public Service Co. to sell the output of its underwater tidal power generation units.  ORPC plans to install the first of these units in Cobscook Bay this summer, and plans to expand its pilot project to include sites off Lubec and Eastport in the next 4 years.

While many of the terms of the resulting contract remain to be worked out, one piece appears firm: the price.  Utilities will pay 21.5 cents per kilowatt-hour for the tide-generated electricity in the first year; this base price of 21.5 cents will escalate at 2% per year, reaching a price of about 39 cents per kWh in the final contract year.  (By way of comparison, the Cape Wind offshore wind PPA approved in Massachusetts starts at 18.7 cents per kWh, with a 3.5% annual escalator over its 15 year term.  The ORPC initial rate is over twice the average rate currently paid by Maine utility customers on "standard offer" default service, or about 5 times higher than the current wholesale price in the New England market.)

For ORPC, the contract is a significant boon.  Securing a 20-year power purchase agreement should greatly assist the developer in securing financing for the project.  This project is designed as a demonstration or pilot project, but may be able to serve as a proof that ORPC's technology and installation systems will work on a larger scale.

For ratepayers, the volume of the contract is relatively low - as licensed by FERC, the Cobscook Project has a maximum capacity of 300 kW - meaning that its above-market costs will be diluted in the much larger pool of power consumed in Maine.  Nevertheless, if the contract volume grows as ORPC builds more of its scalable tidal generation units, those costs will become less and less dilute.  On the other hand, the contract itself - which still needs approval by the PUC once it is finally negotiated - may include other products or commodities such as capacity or renewable energy credits (RECs).  Developers typically prefer securing long-term contracts for as many commodities as possible, which helps solidify their future revenues, but it can make it harder to compare two contracts.

Many tidal projects today face high capital costs, let alone research and development expenses, but many believe that their fuel-free nature will ultimately enable tidal power to have a low fundamental cost of production of electricity in the future.  ORPC's project may shed some light on how that belief fares in the Gulf of Maine.

Maine PUC considers offshore wind, tidal

Petit Manan Light, several miles off the Maine coast.

Today the Maine Public Utilities Commission considers a term sheet for a long-term contract with the developer of a deepwater offshore wind or tidal energy project.  If the Commission ultimately approves the contract, it could represent Maine utilities' first offshore wind or tidal power purchase agreement.

In recent years, coastal states have become excited by the possibility of developing offshore wind and tidal energy resources.  Proponents hope that technological advances will enable both cost-effective energy production and economic development as the offshore wind sector gains a foothold.  In 2010, following record oil prices, the Maine Legislature enacted a law directing the Public Utilities Commission to hold a competitive solicitation for offshore wind proposals.  The law, P.L. 2009, ch. 615, requires the PUC to solicit proposals for long-term contracts to supply installed capacity and associated renewable energy and renewable energy credits from one or more deep-water offshore wind energy pilot projects or tidal energy demonstration projects.  Projects must employ one or more floating wind energy turbines in the Gulf of Maine, in water at least 300 feet deep and no less than 10 nautical miles offshore, and must be connected to the mainland grid.  The program may also include proposals by small-scale tidal power projects for similar long-term power purchase agreements.

In September 2010, the Maine PUC issued a request for proposals under the program.  Multiple bidders may have responded, although a subsidiary of Norwegian energy company Statoil may be the only entity to publicly announce its interest in developing a floating offshore wind project off Maine.

The Public Utilities Commission has placed the offshore wind contract docket on its agenda for today's deliberations as "Consideration of Long Term Contract Term Sheet".  The Maine PUC has not previously deliberated any long-term power purchase agreements for offshore wind or tidal power, but its past practice for land-based renewable projects suggests a possible procedural path.  If the Commission finds the terms of the proposal to be satisfactory and compliant with law, it may approve the term sheet and direct the bidder to negotiate a final contract with one or more Maine utilities.  Alternatively, the Commission could reject the term sheet and invite the bidder to negotiate more favorable terms.

Deliberations start at 10:00 a.m.  Will the Maine PUC show interest in the deepwater offshore wind or tidal power proposal before it today?

FERC seeks demand response standards

Demand response, an innovative strategy to ensuring the integrity of electric grids, is growing in popularity, prompting federal regulators to consider standardizing how demand response performance is measured.

Managing an electric grid entails ensuring a constant balance between electric generation and customer demand for electricity.  As customer demand rises, grid operators have traditionally called on more and more generating units.  In most markets, grid operators dispatch the lowest-cost units first to keep overall costs down.  As a result, generating units needed to meet peak demand tend to be more expensive than baseload generation.  Many peaking units also emit more pollutants per unit of energy than baseload units.

In a demand response program, customers can volunteer to be available to reduce their load during times of peak demand.  When done right, this reduction in customer demand can play much the same role as dispatching additional generation, but at a lower cost in dollars and environmental impacts.  Energy efficiency resources can also play a similar role.

The U.S. Congress and the Federal Energy Regulatory Commission have both recognized that demand response can be a decentralized, crowd-sourced alternative to peaking power plants.  Utilities and regional transmission organizations across the nation are implementing demand response programs.

As demand response grows in importance, the question of how to measure a customer's performance is important.  Different utilities and regions have adopted varying standards for how performance is measured.  In an attempt to standardize the measurement and verification of demand response and energy efficiency resources participating in organized wholesale electricity markets, the FERC has proposed to amend its regulations to incorporate by reference the demand-side management and energy efficiency business practice standards of the North American Energy Standards Board.  NAESB describes itself as "an industry forum for the development and promotion of standards which will lead to a seamless marketplace for wholesale and retail natural gas and electricity, as recognized by its customers, business community, participants, and regulatory entities."

In its Notice of Proposed Rulemaking (29-page PDF), Standards for Business Practices and Communication Protocols for Public Utilities, 139 FERC ¶ 61,041, FERC states its hope that "[a]doption of these standards is intended to improve the methods and procedures used to accurately measure demand response and energy efficiency resource performance" and that their adoption should help regional grid operators "properly credit demand response and energy efficiency resources for their services".

Debate over data center green claims

How green is Apple's iCloud data storage service?  That question provoked debate this week, as environmental activism group Greenpeace released a report critical of Apple's choices of power supply for its data center in Maiden, North Carolina, where the iCloud storage is based.

Greenpeace's report, How Clean is Your Cloud (52-page PDF), notes the explosive growth of cloud-based data and computing services offered by companies like Apple, Facebook, Amazon, Microsoft, Google,
and Yahoo.  These services are made possible by data centers, centralized networks of servers and computer infrastructure.  As Greenpeace put it, "Data centers are the factories of the 21st century information age, containing thousands of computers that store and manage our rapidly growing collection of data for consumption at a moment’s notice."

Data centers can be major consumers of electricity, needing cooling and air handling as well as energy for raw processing operations.  Some data center operators seek out renewable electricity, while others are developing on-site generation.  Most work to improve their energy efficiency, making the best possible use of the energy they need.

Apple has touted the green credentials of its Maiden data center, which was designed to earn LEED Platinum certification from the U.S. Green Building Council.  Apple's Maiden facility will also include a 20 MW solar facility on land adjacent to the data center, as well as a 5 MW biogas-based fuel cell system, systems Apple describes as "the nation’s largest end user-owned solar array" and "the largest nonutility fuel cell installation in the United States."

Greenpeace's report notes that despite these investments, Apple's data center is located in an area where utilities source a significant amount of power from coal-fired power plants.  Greenpeace and Apple dispute how much power the Maiden plant will consume (differing by as much as a factor of 5), and thus what fraction of its electricity will be produced from renewable on-site generation.

Whatever the facts may be, the debate illustrates society's interest in the environmental impacts of our technological choices - as well as the difficulty in evaluating some claims of greenness.

New hydropower from old canals

Innovative approaches could enable a significant increase in the production of hydroelectricity from water flowing through existing canals, conduits and major pipes owned by the U.S. federal government.  According to a recent report prepared by the federal Bureau of Reclamation, the 2012 Site Inventory and Hydropower Energy Assessment of Reclamation Owned Conduits, manmade water control structures managed by the Bureau of Reclamation have the potential to produce an additional 1.565 million MWh of electricity annually.

The U.S. Bureau of Reclamation is a federal water management agency within the Department of the Interior, already experienced at both water management and hydroelectric generation. The Bureau has built over 600 dams and reservoirs in 17 Western states, and is the largest wholesaler of water in the country as well as the second largest producer of hydroelectric power in the western United States. The Bureau's 58 powerplants produce over 40 billion kilowatt hours annually, generating nearly a billion dollars in revenue for the federal government.

Last year the Bureau of Reclamation performed a reconnaissance level assessment of the hydropower potential at 530 sites throughout Reclamation including dams, diversion dams, and some canals and tunnels. In its 2011 report, the Bureau found that 191 sites out of the 530 had some level of hydropower potential, with 70 of those sites (representing a total of 225 MW of generation capacity, or 1.2 million MWh annually) also showing some economic potential for hydropower development.

This year's report found 373 existing Bureau of Reclamation canals and conduits could be used to produce hydropower; together, they could generate an additional 365,219 megawatt-hours of hydropower annually.  Because these canals and conduits are both manmade and already existing, the development of hydroelectric generation facilities using their water may have relatively fewer adverse environmental impacts compared to building a new, traditional dam.  Congress is considering legislation to further enable the development of hydropower from these nontraditional resources, including H.R. 2842, the Bureau of Reclamation Small Conduit Hydropower Development and Rural Jobs Act of 2011.

Torrefied wood: biomass to "biocoal"?

As society seeks improved fuels - and as forested regions seek new markets for forest products - torrefied wood or torrefied biomass is gathering interest.  Torrefaction is a roasting process in which wood or other raw biomass material is carefully heated to yield a higher-quality fuel for combustion or gasification. When combined with densification (think compressing, packing, and pelletizing), torrefied wood can be a fuel with a high energy density - and thus a high monetary value.

Trees growing in the Maine woods - is torrefaction in their future?

In torrefaction, raw wood or other biomass is typically heated to between 400 and 600 degrees F, a temperature selected to roast but not burn the material.  (Green coffee beans undergo a similar process when they are roasted.)  Wood and other raw plant material typically contains a large amount of water; this water is driven off by the torrefaction process, as are other volatile chemicals found in the raw material.  Heating also partially breaks down natural biopolymers in the wood (like cellulose, hemicellulose, and lignin), releasing even more volatiles.  The material left behind is solid, dry, and blackened: torrefied biomass.

Torrefied biomass has some advantages over raw wood as a fuel.  Because the volatile chemicals have already been driven off through torrefaction, the combustion of the biomass may have lower environmental emissions when it is finally used.  (A life-cycle analysis would take into account the volatiles driven off during torrefaction.)  Torrefied wood generally has a higher energy density than raw wood (some sources suggest 30% more), so it can be more cost-effective to transport and ship over longer distances.  This could open up more distant markets for forest products.  Torrefied biomass can also be mixed with coal to produce electricity in existing coal-fired power plants; this use, along with its dark color, has led some to call it “bio-coal”.

While torrefaction has been around for over a century, it is still in a relatively early phase in commercial use, particularly in the U.S.  What role will torrefied biomass play in the future of energy resources and forest products?

Utilities face smart meter hacking threat

Electric utilities are converting traditional electric meters to modern, remotely-readable smart meters - but some may be facing a new twist on electricity theft: hacking smart meters.

The term "smart meters" encompasses a variety of devices used by electric utilities to measure how much electric energy their customers consume.  In general, smart meters can eliminate the need for a meter reader to physically visit the customer's premises, relying instead on wireless radio frequency communication to tell the central office about the customer's consumption.  Many smart meters can also allow real-time tracking of customers' use of electricity, a precursor to time-of-use rates and other "smart grid" applications.  Federal and state regulators promote their installation, citing improved customer service, enhanced storm restoration efforts, and reduced costs for both ratepayers and utilities.

Cybersecurity blog KrebsOnSecurity has released part of a document that appears to be a bulletin by the Federal Bureau of Investigation noting a new threat: hacking smart meters.  According to the blog, a Puerto Rican utility may have lost "hundreds of millions of dollars annually" as a result of smart meter hacking.  Apparently some smart meter models are relatively vulnerable to being reprogrammed (or simply subverted) such that they underreport how much electricity the consumer is using.

Theft of electricity is not new, as people have likely attempted to bypass utility meters since their inception in the 19th century.  As society and the electric power industry have become increasingly digital, it may be inevitable that this trend would continue.  As utilities and regulators respond to the new threat, cybersecurity may play an important and increasing role.

Blythe solar project owner bankrupt

Solar energy project developer Solar Trust of America filed for bankruptcy this Monday, delivering a setback to what would be the largest solar energy project in the U.S.: the proposed 1,000 megawatt Blythe solar project under construction in the California desert.

Last April, I noted that the U.S. Department of Energy offered a conditional loan guarantee commitment to Solar Trust of America, a joint venture of German companies Solar Millennium AG and Ferrostaal Inc., for its solar energy project outside the city of Blythe, California, near the Arizona border.  DOE's conditional loan guarantee was offered to help finance the first two units at Blythe, which were originally planned to use parabolic trough mirrors to concentrate solar energy to boil water in a closed loop.  The resulting steam would spin turbine-generator sets to generate electricity. 

In August 2011, as photovoltaic cell prices fell, project partner Solar Millenium announced plans to convert the first 500 MW phase of the Blythe project to solar photovoltaics.  Photovoltaic technology appeared lower cost and more proven than the relatively complex solar thermal steam turbine generation originally conceived of for the project.  However, this shift in project design meant that the Blythe project could no longer take advantage of the federal loan guarantee.

Now, Solar Trust of America has filed for bankruptcy.  In its Chapter 11 filing, Solar Trust notes that its operations relied on funding from parent Solar Millenium - which filed for bankruptcy in December 2011, cutting off operating funds to Solar Trust.  Likewise, negotiations to sell the company and its projects failed when the prospective buyer, German firm solarhybrid, also went bankrupt.

What does the future hold for the Blythe project?  Along with the nearby Palen project (a two-phase, 500 MW solar thermal development, the Blythe project is Solar Trust's largest asset.  Whether Solar Trust or some successor picks up the pieces and moves forward remains to be seen, but presumably the investment to date in the Blythe project still retains significant value. 

Adding hydro to Army Corps dams

As an energy resource, hydroelectricity has great potential, but siting and environmental concerns make building a new dam in the U.S. difficult.  A new trend of adding renewable electric generation to existing non-hydroelectric dams may help the U.S. grow its hydropower production without building new dams.

Last month the Federal Energy Regulatory Commission issued a license for a new hydroelectric project in Vermont, the Townshend Dam Hydroelectric Project No. 13368.  The project, first proposed in 2010 by Blue Heron Hydro, LLC, involves the installation of hydroelectric turbine-generator arrays at the existing Townshend Dam on the West River near the town of Townshend, VT.  The Townshend Dam project is particularly interesting in that it represents a new model: upgrading existing dams without hydroelectric generation to be able to produce renewable electricity.

The U.S. Army Corps of Engineers owns and maintains the rock-and-earth-fill Townshend Dam, a structure 133 feet high and 1,700 feet long.  The Townshend Dam is part of a system of 14 dams that are operated to provide flood protection for the numerous communities along the Connecticut River.  In addition to flood control, the Corps operates Townshend Dam and Lake for fish and wildlife enhancement and recreation.

Blue Heron Hydro proposes to install twelve turbines and 77-kW submersible generators at the dam site, for a total of 924 kW.  As proposed, the turbines would not change the dam's current run-of-river operation but would rather divert water that currently spills over the dam to flow through the turbines, producing power.  A seasonal downstream fish passage facility would also be installed, primarily for Atlantic salmon.

FERC has now issued an original license for the project.  The license contains a variety of conditions and requirements, but grants Blue Heron Hydro the right to construct, operate, and maintain the project.

The Army Corps manages a portfolio of 693 dams, many of which do not currently have hydroelectric or hydrokinetic generation facilities installed.  Developers are exploring the opportunity to produce hydropower at many of these Army Corps sites, as well as at the thousands of other unpowered but existing dams across the country.  Will the near future bring more interest in adding hydroelectric generation to existing Army Corps dams?

Oil, from crude to fuels and chemicals

Petroleum - what we often think of as oil - powers a large sector of the world economy.  Crude oil, a naturally-occurring mix of substances produced by ancient life and transformed by time and geological forces, lies trapped beneath soil, rock, and the sea floor.  When captured and refined, the crude oil can be transformed into gasoline and diesel, but also into a wide variety of other fuels and chemicals.

In the U.S., crude oil is typically quantified in a 42-gallon unit known as the barrel.  While this bears some historic tie to actual barrels of oil, crude oil today is seldom packed in actual 42-gallon barrels, more typically being shipped in large seagoing oil tankers or pipelines.

At a refinery, each of the components of the crude oil mix is separated.  Some are converted from heavy, low-valued chemicals into lighter, higher-valued products like gasoline.  Processes like cracking, coking, and alkylation allow the production of more exotic petroleum derivatives.

From 42 gallons of crude oils, refineries can produce about 45 gallons of refined petroleum products. Typically, these might include:

• 19 gallons of gasoline
• 10 gallons of diesel
• 4 gallons of jet fuel
• 2 gallons of liquefied petroleum gases (propane, butane, etc.)
• 1 gallon of other distillates (heating oil)
• 2 gallons of residual fuel oil
• 7 gallons of other products

Most of this increase in total product volume comes as different fractions of the petroleum mix are distilled and transformed; the U.S. Energy Information Administration has described the increased volume after refining as "similar to what happens to popcorn, which gets bigger after it's popped".

Because each source of crude oil contains a different mix of hydrocarbons and other chemicals, the refining process yields different mixes of products for each type of crude. The demand for these products drives oil producers' decisions about where to drill and produce oil.