Basin Resources Fall 2015

BASIN RESOURCES4

www.basinresourcesusa.com • FALL 2015

Don Vaughan

puBliSHER

Cindy Cowan Thiele

EDiTOR

Dorothy Nobis

Debra Mayeux

CONTRiBuTiNG WRiTERS

Josh Bishop

CONTRiBuTiNG pHOTOGRApHER

Suzanne Thurman

DESiGNER

Clint Alexander

SAlES STAFF

lacey Waite

ADMiNiSTRATiON

For advertising information

Call 505.516.1230

www.basinresourcesusa.com

Basin Resources magazine is published four times ayear by Majestic Media. Material herein may not bereprinted without expressed written consent of the pub-lisher. Opinions expressed by the contributing writersare not necessarily those of the publisher, editor orBasin Resources magazine. Every effort has been madeto ensure the accuracy of this publication. However thepublisher cannot assume responsibility for errors oromissions. © 2015 Basin Resources magazine.

Majestic Media

100 W. Apache Street

Farmington, NM 87401

505-516-1230

www.majesticmediausa.com

FALL 2015

Column 6Unique and invaluable

The Future 23Effects of removing restrictions

on U.S. crude oil exportsEnergy News 44

BLM Proposes Changes 13Bureau seeks public comment

Last Update was 1991 26Gov. Martinez dicusses new state

energy policy at SJC

Column 9Securing Bloomfield’s future

Column 38Thriving in the New Normal

Column 36The Animas spill and

the problem with the EPA

Column 40Luck and the Gold King Mine Spill

Nearing capacity 10Oil and gas businesses flock

to Bloomfield Industrial Park

Open for Learning 30We need grassroots activism

and pressure

content

8

FROM BORDER TO BORDER

AND COAST TO COAST

20

EPA: ‘TRAGIC AND

UNFORTUNATE INCIDENT’

OWNING THEIR OWN ELECTRIC UTILITYBloomfield sues Farmington

after negotiations fall flat

16

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When Tom Dugan offered to share an extensive collection of

minerals and rocks with San Juan College to display in the new

School of Energy, I was excited.

What better way to celebrate the energy industry than with

minerals that signify the heart of the industry – and to have them

offered for the public to view and appreciate than at our new facil-

ity?

When I learned the collection was from Sherman Dugan’s pri-

vate collection, my excitement turned to a deep appreciation. Sher-

man is the son of Tom Dugan – his only son who, unfortunately,

passed away in December of 2013.

Sherman loved geology and he enjoyed searching the area for

the finest specimens he could find. Sherman wasn’t interested in

ordinary rocks and minerals, however. He wanted the unique, and

the unusual. He was justifiably proud of his collection, which was

far more than a simple “rock collection.” Sherman found minerals

and rocks that were museum quality and he cared for them as such.

His love of geology began as a young boy and continued

throughout his life. He was passionate about rocks and minerals

and he was always willing to share that love with others.

The Sherman Dugan Museum of Geology has already become a

highlight of the new School of Energy. Visitors are amazed at the

beauty and variety of minerals displayed, and it’s been gratifying

to have tours of students come to the school to learn about geol-

ogy and its importance to us all.

When we first started our journey to build a new School of En-

ergy, several years ago, we knew we’d receive support from the

community and the industry we represent. What we didn’t know,

however, was the extent of that support. In addition to the unex-

pected generosity of Tom Dugan with the Sherman Dugan Mu-

seum of Geology, we were blessed with the artistic talents of Tom

and Bev Taylor, who created a beautiful display as a welcome to

the new school.

But it hasn’t just been the financial donations or the beautiful

gifts we received that have made this new facility a gift to our

community.

It has been the gifts of time and talent offered by our students,

the faculty and staff of San Juan College, the encouragement and

backing of our local and state legislators and the unending support

of our industry partners that have created not just a new facility,

but a new center that will provide the education and training peo-

ple need to find good jobs which will help them support their

families and our local economy.

The grand opening of the San Juan College School of Energy

provides a closure to one path on our road to success and it opens

the door for countless opportunities for the staff and instructors at

the School of Energy to continue to make a positive difference in

the lives of our students.

A new facility is wonderful. Grand openings are fun. But the

real success comes in the form of diplomas and certificates that

provide our students with jobs and reinforce our commitment to

them and to our community.

As we enjoy and appreciate the Sherman Dugan Museum

BASIN RESOURCES6


randy Pacheco

dean of School of energy

San JUan college

UniqUe and invalUable

Our students are the true measure of success

* Pacheco 35

BASIN RESOURCES8

www.basinresourcesusa.com •FALL 2015

Debra Mayeux

Basin Resources

The city of bloomfield wants to own

the electric utility that provides power to

its residents. The utility, however, is

owned by the city of Farmington, and

Farmington doesn’t want to sell.

bloomfield’s leaders believe owning its

utility would greatly benefit the commu-

nity, so much so that bloomfield’s attor-

ney ryan Lane has filed a complaint in

the eleventh Judicial District Court of

San Juan County asking the court to

force Farmington’s hand in the sale.

The two cities have been negotiating

for more than a year to enter a sales

agreement.

“Last year we initiated a good-faith

effort to negotiate with Farmington, at-

tempting to avoid burdening taxpayers

with a costly, legal battle,” bloomfield

City Manager eric Strahl said in a letter

provided to Majestic Media. “When our

efforts were rebuked, we were forced to

file a lawsuit.”

There is legal precedence for such a

sale, according to Lane, and the opportu-

nity for the purchase is written in the

contract for power entered into by the

two governmental entities in 1960.

Prior to april 20, 1960, basin electric

owned the electric utilities in aztec,

bloomfield and Farmington. at that time,

basin filed a lawsuit against the three

governments and a stipulation agreement

was signed, giving Farmington owner-

ship of the utility, so long as the city

agreed to allow aztec or bloomfield to

purchase the utility systems within their

boundaries at any time in the future.

“This case is unique, because from

bloomfield’s perspective the entities

agreed to allow Farmington to acquire

the utility, so long as bloomfield would

be allowed to acquire the electric utility

system within its city limits.” Lane said.

“It is the agreement between the two en-

tities we are trying to enforce.”

The city of aztec was allowed to pur-

chase its utility from Farmington in

1963, after the city filed a lawsuit against

Farmington. The court upheld the 1960

contract.

“based on past court decisions and

aztec’s continued acquisition of electric

utility assets as the community expands,

we believe there is no question regarding

bloomfield’s legal right to purchase and

maintain all of the electric utility assets

within its boundaries,” Strahl wrote.

bloomfield may not have wanted an

electric utility in 1960s, but Mayor Scott

eckstein said owning one now makes

sense. He has two reasons for taking this

stance.

“When a citizen of bloomfield pays his

electric bill, the money goes to the city

of Farmington, and that money goes to

Piñon Hills Golf Course, to the parks, to

infrastructure for quality of life in the

city of Farmington,” eckstein said.

“The money goes to pay for emergency

services and all of the basic things a city

depends on. We feel the profit should

Bloomfield sues Farmington after negotiations fall flat

Owning their own electric utility

“When a citizen of Bloomfieldpays his electric bill, the moneygoes to the city of Farmington,and that money goes to Piñon

Hills Golf Course, to the parks,to infrastructure for quality oflife in the city of Farmington,””

— Mayor Scott Eckstein

BASIN RESOURCES 9

FALL 2015 • www.basinresourcesusa.com

Contrary to recent misinformation, the

city of Bloomfield is lawfully moving to

acquire electric utility assets within its

boundaries in order to form its own elec-

tric utility.

The 1960 Culpepper case established

our legal right to acquire. It declared that

while Farmington may have operating

rights to the utility system, both Aztec and

Bloomfield have the right to acquire the

“entire properties” within their respective

boundaries.

Aztec exercised this very right in 1963.

Over 2,000 communities nationwide – in-

cluding Gallup, Raton, Jicarilla Apache Na-

tion, and the Navajo Nation – successfully

run their own electric utilities, so this is

hardly unusual.

We recognize that Farmington signifi-

cantly invested in the electric system in

Bloomfield over time, which is why we

wish to negotiate a fair price for those as-

sets. With fairness in mind, we requested

information from Farmington to develop a

detailed system inventory. We hired an in-

dependent appraiser to determine the fair

market value of those assets.

Bloomfield’s residents and businesses

generate approximately $1 million annu-

ally in surplus that is added to Farming-

ton’s General Fund. These moneys fund

projects (Ricketts Park, Piñon Hills Golf

Course, Riverwalk, etc.) that improve

Farmington’s quality of life. We seek the

opportunity to use surplus funds generated

by Bloomfield to support needed projects

in Bloomfield, thus empowering Bloom-

field’s residents to take control of their

future.

Last year we initiated a good-faith ef-

fort to negotiate with Farmington, at-

tempting to avoid burdening taxpayers

with a costly legal battle. When our ef-

forts were rebuked, we were forced to

file a lawsuit.

We are committed to determining

whether Bloomfield will have its own elec-

tric utility by following a thorough me-

thodical process that adheres to the letter

of the law. This takes time, but we are de-

termined to get it right.

Based on past court decisions and

Aztec’s continued acquisition of electric

utility assets as that community expands,

we believe there is no question regarding

Bloomfield’s legal right to purchase and

maintain all of the electric utility assets

within its boundaries.

We want to make the best decision for

Bloomfield’s future.

eriC Strahl

Bloomfield City manager

Securing Bloomfield’s future

stay in Bloomfield.”

His second reason has to do with the

fact that Farmington controls the utility

rates and Bloomfield residents do not have

a voice in that matter. “Their voices are

better heard when they go to their local

council.”

Electric utility customers in Bloomfield

generate approximately $1 million in rev-

enue for the city of Farmington, according

to Strahl. “We seek the opportunity to use

surplus funds generated by Bloomfield to

support needed projects in Bloomfield,

thus empowering Bloomfield’s residents to

take control of their future,” he said.

Farmington will file a response to the

lawsuit by mid- to late-September, but dur-

ing the negotiations the city of Farmington

said Bloomfield “has the right to acquire

whatever belonged to Basin in 1959,

which is two or three utility poles,” Lane

said.

Strahl added that “while Farmington

may have operating rights to the utility

system, both Aztec and Bloomfield have

the right to acquire the entire properties

within their respective boundaries.”

Strahl also said that the city of Bloom-

field recognizes Farmington has invested

in the utility over time, and Bloomfield

wishes “to negotiate a fair price for those

assets. With fairness in mind, we requested

information from Farmington to develop a

detailed, system inventory. We hired an in-

dependent appraiser to determine the fair

market value of those assets.”

Lane, Strahl and Eckstein all say the city

of Bloomfield has a legal right to purchase

and maintain the electric utility within its

boundaries.

“We want to make the best decision for

Bloomfield’s future,” Strahl said.

BASIN RESOURCES10


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Debra Mayeux

Basin Resources

animas Industrial Park in bloomfield has

been nine years in the making, but the 80 acres

along Highway 550 north of town is almost at

capacity.

The park was just a thought in 2004, when

bloomfield Mayor Scott eckstein joined the

bloomfield City Council. “at that time I got ex-

cited about it. I jumped in with both feet and

totally embraced it,” eckstein said.

The park came to fruition when the city was

able to purchase 80 acres from the bureau of

Land Management, and on that same day turn

NeariNg capacityOil and gas businesses flock to Bloomfield Industrial Park

BASIN RESOURCES 11


Oil Changes & More

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around and sell it to Rio Real Estate Development in Albuquerque.

“It was the perfect public-private partnership,” Bloomfield

Mayor Scott Eckstein said.

The first business to go into the park was Wagner Equipment

Company, which Eckstein says supports all industry through the

sales and rentals of Caterpillar big machines.

Recently purchasing land in the park were Pyramid Instrumen-

tation, 4 Rivers Equipment – which sells John Deere big machines,

and Precision Fitting and Gauge, according to Tim Cummins,

owner and developer of the park.

“There is one lot left and Tim can subdivide that,” Eckstein said.

All these businesses are tied to the oil and gas industry, but are

not exclusively oil and gas, said Eckstein, who added that any new

business entering the park will be good for the city and nearby

property owners.

Through this public-private partnership, the 80 acres has been

converted to private business holdings that will help the city. “We

see the profits through gross receipts with the industrial park fill-

ing up,” Eckstein said. “This also makes other property in that area

more appealing to outside businesses that will look at the Animas

Industrial Park and say, ‘Something must be working in Bloom-

field.’”

BASIN RESOURCES 13


DeBra Mayeux

Basin Resources

The Bureau of Land Management

made a move July 10 to replace the On-

shore Oil and Gas Order Number 3 to

prevent theft and loss of natural re-

sources, according to press release from

the federal agency.

This proposed rule, according to the

BLM, would update Order 3, which was

last changed in 1989. Order 3 “sets mini-

mum standards for ensuring that oil and

gas produced from leases overseen by the

BLM are properly secured and handled,”

The release stated. “The BLM determined

that updates to these standards were nec-

essary based on its experience with oil

and gas measurement in the field and the

changes in technology and industry oper-

ations” since 1989.

“The BLM’s rules concerning oil and

gas measurement are over 25 years old

and are long overdue for an update,”

BLM Director Neil Kornze said. “The

reasonable and commonsense updates we

are proposing today represent an impor-

tant step forward toward modernizing

our program and will help us ensure that

oil and gas sites are properly and respon-

sibly managed.”

updates to the proposed rule would:

• establish uniform procedures for des-

ignating official points for oil and gas

measurement for royalty accounting pur-

poses, known as facility measurement

points, that are applicable to new and ex-

isting leases;

• Codify existing guidance related to

approving commingling - combining of

production from multiple leases in unit

participating areas, communitized areas

DeBra Mayeux

Basin Resources

New Mexico is set to receive more

than $33.4 million on the sale of 53 fed-

eral oil and gas leases that were auc-

tioned recently by the Bureau of Land

Management.

The auction netted more than $70

million in from 69 oil and gas leases sold

in New Mexico, Oklahoma and Texas, as

part of President Barrack Obama’s “all-

of-the-above strategy to continue to ex-

pand safe and responsible domestic

energy production,” according to a press

release from the BLM.

The federal agency awards oil and gas

leases for a period of 10 years or more as

long as there is production in paying

quantities. The revenue from the sale of

these leases, as well as the 12.5 percent

royalties collected from production will

be shared between the federal govern-

ment and the state, with 52 percent of

the revenue going to Washington and 48

percent being paid out to New Mexico.

The sale included more than 21,500

acres of federal land in New Mexico,

3,178 acres in Oklahoma and 73 acres in

Texas. Thus Oklahoma stands to receive

nearly $336,000 from 15 leases, and

Texas will receive $30,192 from one

lease.

The past 10 years has brought $4.3

billion from energy production into the

state of New Mexico from BLM-managed

leases. all of those funds were allocated

to support the state’s public education

system, according to the BLM.

For information about upcoming lease

sales go online to www.blm.gov/nm/oi-

landgas.

BLM proposes changes

Bureau seeks public comment

53 oil and gas leases auctioned in N.M. by BLM

“The BLM’s rules concerning oiland gas measurement are over 25years old and are long overdue

for an update.”— Neil KornzeBLM Director

BASIN RESOURCES14


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or fee or state properties before the point

of royalty measurement;

• Establish conditions for the approval

of off-lease oil and gas measurement;

• Update requirements related to the

use of valve and drain seals, prohibitions

on the use of meter by-passes, and re-

porting requirements;

• Require operators of new and exist-

ing oil and gas facilities to provide new

site facility diagrams designed to help

BLM meet its oversight responsibilities;

and

• Require purchasers and transporters

to comply with the same standards as op-

erators with respect to records.

“The proposed rule represents an im-

portant set in the BLM’s modernization

of its oil and gas regulations,” said Janice

M. Schneider, assistant secretary for Land

and Minerals Management. “These up-

dates will help ensure that oil and gas

produced from leases overseen by the

BLM is properly measured, that American

taxpayers receive fair value for public re-

sources, and that Indian tribes allottees,

states and local governments receive the

full royalties they are due.”

These proposed changes came about

after the BLM consulted with various

tribes beginning in 2011 and continuing

through 2013. This was done through

public listening sessions, which included

representatives from Indian lands, envi-

ronmental groups, the oil and gas indus-

try, other federal agencies and

stakeholders. The agency’s management

of oil and gas came under the scrutiny of

the Government Accountability Office,

which placed it on a “high risk list.”

The rule responds to recommenda-

tions from the Government Accountabil-

ity Office, the Department of Interior’s

Office of the Inspector General and the

Interior Departments Subcommittee on

Royalty Management.

The total value of oil and gas produc-

tion on public lands is more than $33 bil-

lion, generating $3 billion in annual

royalty revenue from leasing activities on

public lands – shared between the state

and local governments; as well as nearly $1

billion in royalty revenues on tribal lands.

This domestic production has grown each

year since 2009, allowing for the nation’s

dependence on foreign oil imports to drop

to less than 40 percent.

The proposed rule can ben viewed on-

line at

https://www.federalregister.gov/oublic-

inspection. Comments on the proposal

may be submitted online at

http://www.regulations.gov.

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BASIN RESOURCES 17


Debra Mayeux

Basin Resources

The manufacturer of a top digital tank

gauge has been producing its product in

Farmington and shipping it “from border

to border and coast to coast,” according to

brad Walls, owner of advanced Telemet-

rics.

Walls purchased advanced Telemetrics

three years ago from a company in San an-

tonio, Texas. He then moved the manufac-

turing business to Farmington and put it

under the umbrella of his resource Pro-

duction Company, which opened in 1996.

“We had open manufacturing space –

square footage we were not using,” Walls

said, adding that his company was the No.

1 distributor of the digital tank gauge at

the time, and advanced Telemetrics was

not able to supply him with the product he

needed.

“They were probably manufacturing

From border to border

and coast to coast Local Advanced Telemetrics No. 1 distributor of the digital tank gauge

Photos by Josh Bishop

300 to 500 a year,” he said of the former owners. “We produced

4,000 units last year.”

The digital tank gauges are being used at various oil and gas

industry sites and also are being used to measure diesel fuel at

railroad yards.“What sets it apart is it’s a float system with three

different floats,” said Scott Emrich, product line manager. “The

first float will measure water in the tank, the second will measure

oil.”

Advanced Telemetrics also manufactures custom industrial con-

trol panels that can be tied in to the gauges for reading the levels.

The tank owners can run it either wirelessly or can wire it into a

control panel to get their levels, Emrich explained.

Advanced Telemetrics also produced a mineral-insulated cable.

“This cable can take the place of conduit, and it’s a flexible cable,”

Emrich said. “You can run it and still keep your classified rating.”

With these three products, the company really prides itself on

the accuracy of the digital tank gauge, which Emrich said has a

level accuracy to 0.10 in and a temperature accuracy to plus or

minus .10 degrees Fahrenheit. There also are no hang-ups and no

false reading, and the tanks are corrosion resistant, explosion-

proof and dust-ignition proof.

The tanks have an Official UL 1203 Approval, which means

they “can be installed in an explosion-proof area,” Emrich said.

“We went through the process to get that certification. There’s

few devices like ours that are actually a classified device.”

He also was proud to say, “It is all manufactured here with local

labor.”

Resource Production has 80 employees, with eight of them

working for Advanced Telemetrics. “You can do stuff on a small

scale but have a major impact around the country,” Emrich said.

BASIN RESOURCES18


BASIN RESOURCES 19


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This is because the items produced by

those eight employees are being shipped to

Texas, Oklahoma, Louisiana, Pennsylvania,

Colorado, Wyoming, West Virginia, Wash-

ington, D.C., and California, to name a few.

And while the tanks, the control panels and

the mineral cables are produced here and

being shipped out, that has not been without

difficulty.

“There are logistics involved in getting

product in and out,” Walls said. The closest

interstate is a 2 ½-hour drive from Farming-

ton. “It’s a concern because there is not a di-

rect pipeline in and out of Farmington.”

Despite the sometimes difficult aspects of

shipping to and from San Juan County, Walls

was dedicated to making Farmington the

home base for Advanced Telemetrics. “We

wanted to manage the company in a way

where we could increase production and

keep an eye on it, rather than have it 800

miles away,” he said.

BASIN RESOURCES20


Debra Mayeux

Courtesy photos

It was a toxic spill for the history books

when on august 5, contaminated water

began spewing from the defunct Gold King

Mine near Silverton, Colo. The environmen-

tal Protection agency was on site assessing

water releases from the mine and determin-

ing how to remediate the old facility and

treat the existing standing water within it.

The excavation, however, took a turn

when pressurized water began leaking

from a tunnel, resulting in a spill of more

than 3 million gallons of water into Ce-

ment Creek, a tributary of the animas

river. The contaminated water flowed out

of the mine at a rate of 600 gallons per

minute into the animas, and the water

flowed south through Durango, Colo., and

into Farmington.

EPA: ‘Tragic and unfortunate incident’

Gold King Mine Spill had devastating effects

BASIN RESOURCES 21


State of emergencyNew Mexico Gov. Susana Martinez on

Aug. 10, declared a state of emergency,

after touring the spill, which left the Ani-

mas River a deep, burnt orange color. In

addition to the state of emergency declara-

tion, Martinez directed a multi-agency

team to remain in northwest New Mexico

to offer on-the-ground support, at a time

when the EPA remained tight-lipped about

the cause of and possible devastation of

the spill.

“I had the chance to see the spill with

my own eyes. It is absolutely devastating,

and I am heartbroken by this environmen-

tal catastrophe,” Martinez said. “As I’ve

said before, I am very concerned by EPA’s

lack of communication and inability to

provide accurate information. One day, the

spill is 1 million gallons. The next, it’s 3

million. New Mexicans deserve answers we

can rely on.”

Her declaration released $750,000 in

state funds to test water wells, study long-

term effects of the spill and support efforts

to mitigate the spill. “I want New Mexi-

cans to know that we are committed to

working around the clock to keep local

communities informed and protected, and

providing whatever resources we can to as-

sist communities in the affected area,” Mar-

tinez said, as she directed her staff to be

prepared to take legal action against the

EPA.

EPA Director Gina McCarthy, while not

directly taking responsibility for the spill,

called it a “tragic and unfortunate inci-

dent.” She said the EPA routinely works

throughout the southwest to clean up

abandoned mines, and was using a con-

tracting team with heavy equipment to

enter the mine and begin treating the con-

taminated water inside. The agency set up

a command center in Durango and an

Emergency Operations Center in D.C. to

help.

“EPA is an agency whose core mission is

ensuring a clean environment and protect-

ing public health, so it pains me to see this

happening,” she said. “But we are working

tirelessly to respond and have committed

to a full review of exactly what happened

to ensure it cannot happen again.”

Only a few days later, the EPA stated in

a press release that the contaminated water

reached Lake Powell by Aug. 12, but there

were “no significant impacts to the lake,

the Colorado River, or any water bodies

downstream.”

Courtesy photo

Area communities and businesses pitched in to help when access to irrigation water was shut off. Triple S Trucking,

owned by Aztec Well, brought a watertank and filled it with water for Sutherland Farms when water from the Animas

River was shut off because of the Gold King Mine Spill. Area farmers relied on irrigation water from the Animas

River to irrigate their crops. “We are so grateful for all the caring concern from this community,” D’Rese Sutherland

said.

BASIN RESOURCES22


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State launches investigationBy August 19, questions about the

spill remained unanswered, so Gov. Mar-

tinez announced that she ordered the

New Mexico Environment Department to

launch an investigation into the spill. She

was seeking the specific cause of the spill

and all details surrounding how the EPA

allowed such a large amount of waste to

flow out of the mine and into the river.

She stated that her office became aware

of the spill when she received a call from

an officials of the Southern Ute Tribe.

“New Mexicans deserve answers as to

why this catastrophe happened and why

the EPA failed to notify us in a timely

manner,” Martinez said.

Navajo NationShe also spoke with Navajo Nation

leaders, who plan to bring litigation

against the EPA for the spill.

In addition to the investigation, Mar-

tinez announced a multiagency long-term

impact review team to monitor the ef-

fects of the spill. The team will conduct

research, collaborate with local commu-

nities, federal officials, and members of

the public, and share information to learn

more about the potential long-term im-

pact of the spill on local communities,

wildlife, and agriculture.

The EPA, however, has stated that the

water is safe, based on data from the

Agency for Toxic Substances and Disease

Registry, which does not “anticipate ad-

verse health effects from exposure to the

metals detected in the river water samples

from skin contact or incidental inges-

tion.” The agency also stated that a risk

to livestock was low.

“We are certain that crops are safe for

consumption,” the agency stated in a

press release. “When the plume came

through, irrigation ditches that impacted

crops and livestock were shut down.

Water quality data we have seen indicate

no harmful effects on agricultural prod-

ucts.”

The ban on private domestic well

water from the Animas was lifted as of

August 14, with the ban on the drinking

water systems in the region having been

lifted as of Aug. 15.

“There were no fish kills along the An-

imas during the plume event. Biologists

walked and paddled the river looking for

dead fish,” The EPA stated. “There was

also no evidence of scavenging by birds

or other mammals.”

The EPA said it has continued work at

the site to reduce further instances of

runoff. This included the construction of

retention ponds where water could be

treated, as well as the installation of a

water-treatment system on site.

“Planning is in place for a treatment

solution that includes pipes to allow the

mine water to flow to a lower mine site

with a better location for water treatment

to continue into the fall,” the EPA state

in a press release. “Longer-term treatment

needs and options are being evaluated.”

EPA considers building a wastewater treatment plant

The EPA is considering plans to build

a wastewater treatment plant for an inac-

tive Colorado gold mine after the agency

inadvertently triggered the 3-million-gal-

lon spill of polluted water there last

month.

The EPA released documents Septem-

ber 16 outlining possible plans to build

the plant quickly below the Gold King

Mine near Silverton.

“This is an emergency response ac-

tion,” a request for proposal says.

The document also shows the EPA is

working on a tight schedule. It calls for a

fully operational system within 21 days

of a contract being awarded.

EPA spokeswoman Nancy Grantham told.

The Denver Post that the agency received six

bids but hasn't yet decided on one – or if

the plant ultimately will be built.

“The treatment plant is a contingency

option,” Grantham said. “The agency

continues to evaluate data to determine

the impacts of the Gold King Mine on

water quality currently and going into

the winter months.” An EPA-led crew

triggered the spill on August 5, tainting

rivers in Colorado, New Mexico and

Utah.

BASIN RESOURCES 23


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United States oil production has grown

rapidly in recent years. Data reflecting com-

bined U.S. production of crude oil and lease

condensate show a rise from 5.6 million bar-

rels per day (b/d) in 2011 to 8.7 million

b/d in 2014. EIA's August 2015 Short-

Term Energy Outlook forecasts U.S. crude

oil production of 9.4 million b/d in 2015

and 9.0 million b/d in 2016, with the de-

crease in production between 2015 and

2016 reflecting recent and forecast changes

in drilling activity following the sharp de-

cline in oil prices since mid-2014.

AEO2015 projects domestic production

growth beyond 2016, although the pace

and duration remain uncertain.

Recognizing that some options, such as

like-for-like replacement of import streams,

are inherently limited, the question of how

the relaxation or removal of current limita-

tions on crude exports might affect domestic

and international markets for both crude oil

and products continues to hold great interest

for policymakers, industry, and the public.

The fuTure

Effects of removing restrictions on U.S. crude oil exports


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Executive Summary

Recent increases in domestic crude oil production and the prospect

of continued supply growth have sparked discussion on the topic of

how rising domestic crude oil volumes might be absorbed, including

the possibility of removing or relaxing current restrictions on U.S.

crude oil exports.

In response to requests from Congress1 and the Administration,

EIA developed several analyses that address these issues. Recent EIA

reports have addressed gasoline price determinants (EIA, What Drives

U.S. Gasoline Prices?, October 2014), changes in U.S. crude oil im-

ports to accommodate increased domestic production (EIA, "Crude oil

imports continue to decline", This Week in Petroleum, January 23,

2014), options for refinery capacity expansion (EIA, Technical Op-

tions for Processing Additional Light Tight Oil Volumes within the

United States, April 2015), and refinery responses to higher, but fixed,

levels of domestic crude oil production under both current crude oil

export restrictions and with unrestricted crude oil exports (EIA, Impli-

cations of Increasing Light Tight Oil Production for U.S. Refining,

May 2015). EIA also developed projections of domestic crude oil pro-

duction by crude type through 2025 (EIA, U.S. Crude Oil Production

to 2025: Updated Projection of Crude Types, May 2015), supple-

menting the overall production projection provided in theAnnual En-

ergy Outlook 2015 (AEO2015) and updating a previous report issued

in May 2014.

This report builds on these earlier efforts by applying EIA's energy

models to directly compare cases over the next decade with and with-

out the removal of current restrictions on crude oil exports. Four base-

line cases using EIA's National Energy Modeling System are

considered to reflect a range of outlooks for resources and technology

as well as prices, which are key drivers of domestic crude oil produc-

tion.

Current laws and regulations allow for unlimited exports of petro-

leum products, but require licensing of crude oil exports. Exports of

crude oil to Canada for use there are presumptively granted licenses, as

are exports of crude oil from Alaska’s North Slope (ANS crude), re-ex-

ports of foreign-sourced crude, and certain exports from California. In

addition, recent rulings by the U.S. Department of Commerce’s Bureau

of Industry and Security (BIS) have clarified that condensate processed

through a distillation tower is classified as a petroleum product and is

therefore exportable without a license. For this analysis, EIA generally

assumes that all streams with API gravity of 50 degrees and above

(API 50+) would be eligible for processing and export under recent

BIS guidance. Through the first five months of 2015, crude oil ex-

ports averaged 491,000 b/d. In addition, exports of processed con-

densate through the first five months of 2015 are estimated to have

reached an average of 84,000 b/d.

Although the current policies outlined above are characterized by

some as a crude oil export ban, crude oil exports have been rising

steadily in recent years (EIA, "Crude exports and re-exports continue

BASIN RESOURCES 25


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to rise; some volumes sent to Europe and

Asia," Today in Energy, October 31, 2014).

Even with current restrictions, a further in-

crease in crude exports, including additional

flows to Canada and more exports of ANS

crude, is possible. In this analysis, projections

under current policies are compared to alter-

native cases that allow unrestricted exports

of crude oil, paralleling the current treatment

of petroleum product exports.

Key analysis resultsThe effects of eliminating restrictions on

crude oil exports depend on the level of fu-

ture domestic production, which itself de-

pends on the characterization of resources

and technology as well as future crude oil

prices. Under current policies, projected do-

mestic crude oil production (including lease

condensate) in 2025 ranges from 9.5 million

b/d in the Low Oil Price (LP) case to 13.6

million b/d in the High Oil and Gas Re-

source (HOGR) case, with production in

other cases (the Reference case, and a case

that combines HOGR with the LP case

(HOGR/LP)) falling within this range

(Table ES-1).

The discount of West Texas Intermediate

(WTI) crude to North Sea Brent, the latter a

key marker for waterborne light crudes, is

expected to increase to more than $10/b in

cases where current crude oil export policy

is maintained and domestic production

reaches or exceeds about 11.7 million b/d

by 2025. Under current export policies, the

Brent-WTI spread averages roughly $15/b

over 2020-25 in the HOGR case, reflecting

the price discount required to spur invest-

ment in additional processing capacity to

convert incremental volumes of domestic

crude oil into exportable petroleum prod-

ucts. In the Reference case, where produc-

tion averages 10.4 million b/d over

2020-25, there is no need for a wider

Brent-WTI spread to encourage more invest-

ment in domestic processing capacity addi-

tions. The average annual Brent-WTI spread

remains close to $6/b in the Reference case

whether or not restrictions on crude oil ex-

ports are removed, and unlike the HOGR

case, projected total U.S. distillation capacity

is the same whether current crude oil export

restrictions are maintained or removed

(Table ES-1). It should be noted the $6/b to

$8/b range for the Brent-WTI spread with

unrestricted crude exports differs signifi-

cantly from historic experience in which

Brent and WTI typically traded close to par-

ity. A Brent-WTI spread in the $6/b-$8/b

range is consistent with the costs of moving

WTI from Cushing, Oklahoma to overseas

markets where it might compete with Brent.

The historical situation of approximate par-

ity reflected competition between Brent- and

* The Future 41

BASIN RESOURCES26


All eyes were focused on the energy in-

dustry on Tuesday, September 15, in Farm-

ington. The day included a visit from New

Mexico Gov. Susana Martinez to discuss the

state’s new energy policy and concluded

with the grand opening of the BP Center

for Energy Education at San Juan College.

The day began at the Quality Center for

Business where Gov. Susana Martinez who

outlined the new policy.

She said that since it has been 25 years

since the policy has been updated it was

“about time” for a fresh approach.

The 2015 Energy Policy and Improve-

ment Plan, according to Gov. Martinez, de-

parts from the 1991 plan, which assumed

future energy scarcity in New Mexico and

the nation. It begins, instead, by embracing

energy abundance and attempts to focus on

how to use energy for the general welfare

and long-term security of New Mexico’s cit-

izens.

In the preface to the new policy she

writes that a key principle to the plan is

Last update was 1991Gov. Martinez discusses new state energy policy at SJC

After her speech at the Quality Center for Business at San Juan College Gov. Martinez toured the new school of energy at San Juan College.

“New Mexico cannot afford to exclude any energy asset from our

portfolio of development opportunities. With an “all of the above”

approach that encourages and prizes energy development of all

kinds, New Mexico can bet-

ter lead economically, create

well-paying jobs across our

state, and better respond to

the changing needs of the fu-

ture energy marketplace.”

Gov. Martinez debuted the

plan at the third annual

Southeastern New Mexico

Mayor's Energy Summit in

Carlsbad earlier this month.

The framework of the en-

ergy policy includes 12 ob-

jectives.

Energy, Minerals & Natu-

ral Resources Department

State Secretary David Martin,

author of the plan was also here to discuss the plan.

Martin said that within this plan, there are many important ac-

tions we can begin to take that will move our state forward, includ-

ing:

Infrastructure Creating or improving en-

ergy infrastructure will not

only create jobs, but also open

up new markets for New Mex-

ico’s energy and products.

From new rail lines to addi-

tional electric transmission, our

state can better move our en-

ergy and its derived products

around New Mexico, the

Southwest, and Mexico. Infra-

structure in oil and gas devel-

opment attracts new project

capital investment and can

help clear export bottlenecks.

EducationEducational institutions—from K-12 schools to junior colleges

and research universities—are the biggest benefactors of our state’s

energy revenues, and they return scientists, engineers, and other

trained workers to the energy industry. New Mexico’s higher educa-

tion institutions also offer advanced energy research to industries

that are dependent on technology innovation.

Energy Tax Incentives All New Mexicans depend on energy, not only in their homes,

businesses, and vehicles, but also for their livelihoods. Our state can

remain competitive with neighboring states through additional in-

vestment in infrastructure, exploration, and production through

smart tax incentives.

Regulatory StreamliningRemoving unnecessary requirements from energy industry opera-

tions will expand growth. Regulatory balance and timely actions

can be achieved without compromising on health, safety, and envi-

ronmental standards. We can be prosperous producers while protect-

ing our resources.

New Collaboration with Federal AgenciesNew Mexico’s energy resources exist in many jurisdictions, in-

cluding state, tribal, federal and fee (private).

This Administration has established a precedent in assisting fed-

eral/tribal agencies with limited means to process permits, helping

to promote additional oil and gas development in the San Juan

Basin. Building on this precedent, the state can continue to

BASIN RESOURCES 27



identify opportunities to remove bottlenecks in federal processes

and create new pathways for other states and resource owners to

follow.

Many of the key points in the plan are items that Northwest

New Mexico producers have been discussing for a number of

years.

At the San Juan Basin Energy Conference held here in March

many oil and gas industry speakers touched on the problems in-

frastructure creates for their companies.

WPX CEO Richard Muncrief was a keynote speaker for the

event said the greatest challenges WPX faces is permitting and

getting the production out.

Ken McQueen, vice president for the WPX San Juan Region,

also spoke at the conference and added that it is important that

rail better critically important this happens sooner rather than

later.

Energy and the EconomyThe plan states that total energy revenue in New Mexico,

specifically revenue derived from the oil and gas sector, has grown

over the past decade, as has energy revenue’s relative proportion

of the state General Fund. This demonstrates increased reliance

upon natural resource development, which can be challenging for

the state during cycles of low prices and decreased production.

In Fiscal Year (FY) 2013, production taxes, royalties, and other

direct sources of state revenue from the oil and gas industry ac-

counted for 31.5percent of New Mexico’s General Fund. This is a

conservative estimate, as it does not include induced or secondary

effects. Oil and gas was directly responsible for 86percent of the

Severance Tax Permanent Fund and 96.6 percent of the Land

Grand Permanent Fund.

In FY 2014 the New Mexico State Land Office generated a

record $726 million in revenue from oil and gas royalties alone

for the state’s public schools, universities, and hospitals.

However, with an unanticipated decline in oil prices at the end

of 2014, and therefore oil exploration and production activities,

the state budget has been adversely impacted for FY 2015 and

2016.

In late 2014, the Organization of Petroleum Exporting Coun-

tries (OPEC), with Saudi Arabia at its core, drove down oil prices

to protect against its losses in market share to U.S. shale oil pro-

duction. Between the second quarter of 2014 and the first quarter

of 2015, the three-year West Texas Intermediate (WTI) average

per barrel price for oil dropped from approximately $100 to $48

(a price that is further discounted for New Mexico producers due

to transportation bottlenecks that raise the cost of transporting oil

to market).

Production CostsBreakeven costs for oil producers are estimated to range from

$52 to $70 in the San Juan Basin and $40 to $55 in Southeast

New Mexico. Oil producers respond to these market signals by

BASIN RESOURCES 29


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reducing the number of new wells drilled,

potentially shutting in some producing

wells, and stopping production on margin-

ally producing wells. All of these activities

have implications for New Mexico’s econ-

omy.

Oil revenue vs. natural gasThe relative importance of oil revenues

compared to natural gas revenues for the

state budget has reversed in recent years; in

2007 natural gas accounted for nearly 70

percent of all state oil and gas revenues,

while in 2013, oil accounted for 70per-

cent. While oil and gas production revenue

is primarily generated in the southeastern

and northwestern regions of the state, the

revenue from oil and gas production bene-

fits all reaches of New Mexico through

General Fund disbursements, capital fund-

ing projects, gross receipts taxes, and ad

valorem taxes that go to the counties.

The oil industry expansion between

2010 and 2014 accounted for unprece-

dented job growth in the state.

It is estimated that in 2012 9 percent of

all employment in New Mexico, or 68,800

jobs, were directly or indirectly related to

the oil and gas industry. In oil producing

counties such as Lea and Eddy counties,

the December 2014 unemployment rates

were 3.1 percent and 3.0percent, respec-

tively, compared to the statewide Decem-

ber average of 6.0percent. However, with

the recent downturn in the oil market,

there have been layoffs in the oil and gas

industry.

Energy sector jobs are well paying, pri-

vate sector jobs, and the New Mexico De-

partment of Workforce Solutions reports

that the mining (oil and gas) and utility in-

dustries supply the first and second highest

wages of all private industries in New

Mexico.

CoalBeyond oil and gas, there are other

sources of revenue and jobs in the energy

sector.

Coal mining has traditionally been a sig-

nificant source of revenue and jobs for north-

western New Mexico, and in 2013 the coal

industry returned $23 million in revenue to

New Mexico and employed 1,600 people.

RenewableRenewable energy and energy efficiency

industries are also contributing to New Mex-

ico’s economy: in 2013, $131 million was

invested in New Mexico to install solar en-

ergy for home, business, and utility use

through 87 solar companies that employed

1,900 workers. Annual land lease payments

from wind energy generation in New Mex-

ico—which primarily is paid to the State

Land Office or rural landowners—

* Last Update 35

BASIN RESOURCES30


DEbra MayEux

Basin Resources

The bP Center for Energy Education at

San Juan College opened its doors in mid-

July, and welcomed 250 students to classes

at the start of the semester in august.

These students are learning everything

from oil and gas drilling and refining to

power plant operations in the 65,000-

square-foot building that cost $15.8 mil-

lion to construct.

“It came in on time and in budget,”

School of Energy Dean randy Pacheco

said. The building was designed by albu-

querque architects Dekker Perich Sabatini

and was built by Jaynes Corporation.

There are 16 classrooms, two conference

rooms, a number of offices and an outdoor

kitchen. “The industry – they love to bar-

becue and we want them to barbecue

here.”

While the focus has long been to pro-

vide a top-notch fossil fuel extraction and

production education to people in the Four

Corners region, Pacheco said the school

and this new building can offer so much

Open fOr learningNew School of Energy an educational hub for the industry

San Juan College courtesy photo

From left, Gov. Susana Martinez and New Mexico Higher Education Department Cabinet Secretary Barbara Damron listen as San Juan College President

Toni Pendergrass explains at exhibit in the Sherman Dugan Museum of Geology in the new BP Center for Energy Education..

BASIN RESOURCES 31

FALL 2015• www.basinresourcesusa.com

more. “We see this as a hub or a center for

the industry,” Pacheco said.

His vision includes bringing in various

energy companies and providing them

with a venue for meetings, trainings and

celebrations. Just since opening its doors,

the building already has played host to

ConocoPhillips, BHP Billiton and Public

Service Company of New Mexico. Each

industry player used the facility for its own

unique purpose, and that is what will make

this facility special, according to Pacheco.

“We want to solve industry issues by

bringing together industry, students, and

the government. We can talk about safety

issues, regulatory issues and workforce is-

sues,” he said. “There’s a lot of collabora-

tion happening here. Different people are

hosting their own classes here.”

Why in Farmington?The School of Energy is located just off

of College Boulevard north of the San

Juan College Campus and the Quality

Center for Business, or QCB. It was moved

from its former location in south Farming-

ton, where it operated for several years

under Pacheco’s leadership. He admitted

that he often hoped and dreamed the facil-

ity would someday be located on the col-

lege campus.

“I guess there was a time when I would

pull into the QCB for a meeting and

dream about what it would look like –

how the students would come in and out

and what programs we would offer,” he

said, adding that some in the oil industry

outside of the Four Corners did question

why such a facility would be built in San

Juan County.

“At a conference in Louisiana, a guy said

to me, ‘Great idea, great facility. Why are

you building it in Farmington? You should

be building it in Houston’,” Pacheco said.

His response was that the community

support was in Farmington. The college

and the state of New Mexico were behind

it. He also argues that while the industry

might not be as vast in San Juan County as

it is in Houston, Texas, there still will be

people who will travel to Farmington to

study in the programs offered.

The community has offered a great deal

of support with various energy businesses

pumping money into the college for the

construction of the School of Energy, and

even after its completion more donations

were being given.

Tom Dugan, owner of Dugan Produc-

tion Company, donated funds to have an

outdoor seating area with a flagpole to

honor veterans. “He wanted a veterans’ me-

morial to honor all of those who have

served,” said Gayle Dean, executive direc-

tor of the San Juan College Foundation.

Photos courtesy of San Juan CollegeSan Juan College President Toni Pendergrass addresses the crowd at the ribbon cutting forthe new School of Energy.


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“Tom Dugan is a huge philanthropist.”

Sherman Dugan Museum of GeologyDugan and his grandchildren, Sean and Megan Dugan, also

wanted to honor the memory of Sherman Dugan, Tom’s only

son. “Mr. Dugan donated a lot of his (Sherman’s) minerals when

he passed away,” Dean. “Dugan and Sherman’s children wanted

to share their dad’s collection because they were very excited

about the School of Energy.”

With the donation of the collection, San Juan College estab-

lished The Sherman Dugan Museum of Geology within the

School of Energy. It includes 200 specimens, including the re-

mains of a 35-million-year-old mammal, named “Bob.”

“The excitement their donation creates resulted in the dona-

tion of other specimens for our museum,” Dean said. Donations

came from the natural history museums in Albuquerque and in

Denver, Colorado, and the School of Mines and Mineral Mu-

seum in Socorro.

The museum will continue to grow, according to Dean, who

said it also includes a virtual sandbox, which was part of Col-

lege President Dr. Toni Pendergrass’ request to have interactive

* School of Energy 34

exhibits. “She wanted to have items children could come and enjoy,”

Dean said. “We want kids here.”

The museum will be open during the School of Energy hours

from 8 a.m. to 5 p.m. Monday through Friday.

A skilled workforce

While the community got behind the construction of the School

of Energy, there has been a big downturn in the oil and gas industry.

There also has been a closure of units at both Arizona Public Ser-

vice’s Four Corners Power Plant and PNM’s San Juan Generating

Station. There even have been recent layoffs from companies such as

Halliburton – this as the EPA pushes for more alternative fuels,

which are not part of a curriculum at the School of Energy.

“We touch on the maintenance of wind and solar,” Pacheco said,

adding the alternative fuel curriculum is offered at other New Mex-

ico Colleges and Universities, and San Juan College did not want to

duplicate programs. The School of Energy is unique. “We are strate-

gically placed to be looked at as one of the premier industry training

centers in the United States.”

Pacheco, however, believes his energy program will continue to

grow, despite a slowdown in the fossil fuel industry.

“When we were at $400 a barrel, there were community colleges

all over wanting to offer a program like this,” he said. “The slow-

down will allow the School of Energy to place itself as one of the

key facilities in the U.S. The price doesn’t change realities in the

world. There are still jobs in the industry.”

Pacheco said the focus has changed over the years from just hir-

ing as many people as the industry can use when there is a boom, to

looking for skilled workers. “The industry is pausing and taking a

breath. The companies are more focused on a quality workforce.”

It is Pacheco’s vision and hope that the workforce will be made

up of graduates from the San Juan College School of Energy.

BASIN RESOURCES34


Financing Options Available • Blueprints with estimates (not guesstimates)

505-327-75253005 Northridge Drive, Suite K

www.basinelectricnm.com

• Residential Projects• Commerical Projects

• Industrial Projects

• New Construction

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SPECIALIZINGIN

School of Energy continued from 32

Josh Bishop photos

BASIN RESOURCES 35


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of Geology, we are reminded that each student is unique and in-

valuable, just like the minerals and rocks in our display. We appre-

ciate our students, we are committed to providing the training and

education they need, and will continue to partner with the com-

munity and industry to move forward.

Our journey continues and we are grateful to those who have

joined us in our quest for a new training facility. We look forward

to retaining those relationships and building new partners as we

move forward to help our students – our number-one priority –

succeed.

Pacheco continued from 6

is estimated to be over $2.9 million.

Listening SessionsWith regional economic development or-

ganizations as hosts and partners,

listening sessions were held across New

Mexico to gather input from diverse stake-

holders about existing energy production

conditions and future opportunities for en-

hancing energy development and deploy-

ment in New Mexico. These listening

sessions drew approximately 450 attendees

and focused on specific topics of relevance

to the region in which they were held.

Farmington: November 13, 2013

• Fuels, fuel stocks, and power generation

• Natural gas, crude oil, and coal

Santa Fe: November 19, 2013

• Renewable power generation

• Energy efficiency and conservation

• Transmission

Hobbs: January 14, 2014

• Fuels, transportation, and power gener-

ation

• Crude oil, natural gas, water, and nu-

clear power

• State and federal oil and gas regulation

Las Cruces: March 19, 2014

• Renewable energy: biofuels, solar, geot-

hermal energy

• Water/energy nexus

• Commercialization, infrastructure, fi-

nancing

Socorro: March 27, 2014

• Technical and science-based input on

concerns related to energy development

• Water use and water recycling

• Science and technology assistance to

New Mexico counties and municipalities

Albuquerque: May 29, 2014

• Energy technology innovation

• Energy innovation and business oppor-

tunities for New Mexico

To view the State Energy Policy and Im-

plementation Plan go to

http://www.emnrd.state.nm.us/EnergyPol-

icy.

Last Update continued from 29

BASIN RESOURCES36


So much has been said and written

about the EPA-induced debacle on the An-

imas River. To be clear, living in New

Mexico as I do, I have spent a great deal of

time in and around Silverton, Colorado

and Durango,, as well as in the Four Cor-

ners area of the New Mexico part of the .

The areas are beautiful and attract

tourists from all over the world for activi-

ties such as as skiing, fly fishing, moun-

tain biking, and riding the

Durango-Silverton narrow gauge train.

There also is a rich mining history in

the area. You can scratch almost any ski

area in the region, such as, such as Du-

rango or Telluride, and find it originally

settled as a mining town.

Yes, there are abandoned mines

throughout the area. The Gold King Mine

last operated back in 1922, long preceding

EPA regulations as well as modern scien-

tific understanding of the potential envi-

ronmental impacts of allowing mine waste

to flow freely into rivers and other bodies

of water.

The EPA was created only in December

of 1970 with Richard Nixon’s signing of

an executive order. As usual, this was an

example of a politician seeing a parade

going by and stepping out in front so as to

appear to be leading it.

The environmental movement had been

growing rapidly in the preceding years

with the publication of Rachel Carson’s

Silent Spring in 1962 and the devastating

Santa Barbara oil spill in 1969. The

strength of the movement culminated ear-

lier in 1970 with celebration of the first

Earth Day on April 22.

American attitudes about the environ-

ment and its stewardship were changing

fast. The environmental movement is

now one of the most powerful interest

groups in Washington. Not surprisingly,

the EPA has grown far beyond its origi-

nal design – with dire economic im-

pacts. The agency’s annual budget is

“just” $11 billion, but according to the

Competitive Enterprise Institute’s study

of federal regulations, EPA regulations

alone cost the United States’ economy a

staggering $353 billion annually.

The way the EPA does business is also

problematic and could fill many books.

Just recently, The New York Times

Paul GessinG

President

rio Grande Foundation

The Animas spill and the

problem with the EPA

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revealed that the agency colluded with environmentalist groups in

a campaign to manufacture public comments in favor of its new

“Waters of the U.S. Rule.”

That, of course, preceded the debacle on the Animas River, a

three-million gallon spill of arsenic and heavy metals which was

caused by EPA contractors. From the start, this was a high-risk

strategy the failure of which was predicted by a local geologist

who went on to argue in a letter to the Silverton Standard –

which ran a week before the disaster – that it was a “grand exper-

iment” which would fail while creating a “Superfund blitzkrieg.”

Clearly, the EPA is doing a less than stellar job of balancing

economic needs with those of the environment. Is it perhaps time

to allow a new type of federalism to flourish?

Rather than a one-size-fits-all regulatory power out of Wash-

ington, could states perhaps opt out of some or all EPA regula-

tions and regulate environmental issues themselves? I don’t

foresee Congress, no matter the political makeup, voting to get rid

of the EPA in its entirety, but Washington clearly doesn’t have all

the answers to our environmental issues.

Currently, hydraulic fracking, to name just one important activ-

ity, is regulated at the state level. And, while environmentalists

have repeatedly attacked the process, even the EPA has found no

ill effects on groundwater from the widely-used process.

Untying the EPA knot will not be an easy or fast process. In

just 45 years, the agency has spread its tentacles into every facet

of the American economy and our lives. Perhaps the Animas spill,

like the Santa Barbara spill of the 1960s, will alter the direction,

but in a more free market direction that also respects American

federalism and state prerogatives.

Paul Gessing is the President of New Mexico’s Rio Grande Foundation.

The Rio Grande Foundation is an independent, non-partisan, tax-exempt

research and educational organization dedicated to promoting prosperity

for New Mexico based on principles of limited government, economic free-

dom and individual responsibility.

BASIN RESOURCES34


I have a saying that my staff gets tired

of hearing. “Economic development is all

about people development.”

If we have all the best sites, logistics,

opportunities and incentives, we will still

fail if we don’t have productive and mo-

tivated people to do the work. As busi-

ness owners and executives, we some-

times get so hung up on how much our

people cost that we don’t pay attention

to their productivity, which usually re-

flects on their well-being.

I was really taken aback recently on

one of my visits with a local

ray HagErmaN

CEO

FOur COrNErs

ECONOmiC DEvElOpmENT

Thriving in the New Normal

It’s still about our people

BASIN RESOURCES 39


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energy-related company. They employ well over a hundred

people and pay some of the highest wages in the area. When I

asked if there were any issues we could help them with, the

owner’s response was, “I pay my folks really well, but you’d

never know it by how they handle their money.”

What he was saying between the lines is that even though

they are well paid, they are not as productive, due to constant

financial trouble. They owe too much, spend too much, and are

so busy trying to make it to the next payday that their work

suffers.

Financial literacy and personal financial management is a

very necessary component for our success as a community. The

number of payday loan stores and pawn shops in San Juan

County is a constant reminder of how much we need it.

At Four Corners Economic Development, we want to set the

right thinking in motion. On October 6, we are hosting the lat-

est session of “Thriving in the New Normal” at the Farmington

Civic Center. No less than eight personal financial management

resource providers will share on subjects ranging from budget-

ing to simple spending practices and credit score repair. The

objective is for you, the business owner/manager, to discover

resources to which you can refer your employees. There will

even be a fun session on Extreme Couponing.

So come on out to the “Thriving in the New Normal” finan-

cial literacy forum at 3 p.m., October 6.

Your employees’ well-being is at stake, and so is your prof-

itability.

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Catastrophe struck. Three million gallons

of toxic brew spewed from the Gold King

Mine into Cement Creek on August 5,

2015.

Seven miles downstream, it flowed

through Colorado’s scenic town of Silverton

and joined the Animas River. It soon crossed

nearly 30 miles of the San Juan National

Forest before entering New Mexico.

The brew entered about 30 miles of agri-

culturally rich river floodplain until the Ani-

mas flowed into the San Juan River at

Farmington. It then turned northwest

through another 37 miles of productive bot-

tomland that almost reaches Utah.

Another 70 miles downstream, the flow

entered Glen Canyon National Recreational

Area, then 70 miles further joined the Col-

orado River at the upper end of Lake Pow-

ell.

Early reports suggest the lake will dilute

the pollutants to safe levels. Let’s be opti-

mistic and hope so. Damage has already oc-

curred to drinking water supplies,

agriculture, and wildlife that could take years

to repair. And we should be thankful for our

good luck.

Despite the growing list of damages, the

spill could have been a lot worse in a differ-

ent location.

Most of its course was along a gaining

stream, where groundwater flows into the

rivers from aquifers, keeping the toxic mix

mostly on the surface. Some localized areas

of groundwater may be affected, but so far

no major aquifers appear impacted.

Cleaning surface water is relatively cheap

and easy compared to cleaning aquifers. If

the spill entered a karst aquifer, the conse-

quences would have been especially bad.

Caves are the natural pipelines that trans-

mit groundwater in karst. Twenty-five per-

cent of the U.S. is karst, a landscape which

contains the most hydrologically complex,

productive, yet most vulnerable aquifers on

Earth.

Worldwide, groundwater flows through

caves at an average rate of 1 mile/day. Natu-

ral filtration is effectively non-existent, espe-

cially for the types of poisonous chemical

and metals associated with mines.

The convoluted paths of karst aquifers

and the destinations for their flows are often

poorly understood and unmapped. Many of

the “rules” governing other aquifers don’t

apply to karst.

The Gold King miners didn’t know much

about karst, aquifers, or the potential envi-

ronmental consequences of their work when

they started digging in 1887.

If the preliminary reports I’ve read hold

true, the mine’s location was lucky in regard

to aquifers, and very lucky to avoid major

karst aquifers. But what about the location of

other mines?

The U.S. Environmental Protection

Agency has 1,372 sites proposed or listed

on the National Priorities List (often

called “Superfund”) for their “known re-

leases or threatened releases of hazardous

substances.” They are scattered around the

country. Many are mines. Many occur in

karst and other highly sensitive locations.

The Gold King Mine was not on that list.

EPA has not yet released a clean-up

cost estimate, which will undoubtedly

cost millions.

For several years, federal and state envi-

ronmental offices around the country have

been challenged to do as much or more

work to protect public health but with less

money. Such an administrative environment

spawns oversights and blunders.

No one wants the PR of a Superfund or

other toxic clean-up site in their backyard.

The cost is certainly unwelcome. But the

human, environmental, and economic cost of

a release like from the Gold King Mine is far

higher and abhorrent.

The Gold King spill was terrible. My

heart goes out to everyone it hurts. Yet we

were lucky that such a spill didn’t happen

where it could do more and longer-lasting

harm.

Let’s not rely on luck. Let us support leg-

islation and funding to clean up our toxic

legacy from past generations, and to protect

our environment from future, avoidable, dis-

asters.

Editors NotE: dr. George Veni is an in-

ternationally renowned karst hydrogeologist and

the Executive director of the National Cave and

Karst research institute, based in Carlsbad, New

Mexico.


BASIN RESOURCES40

Dr. GEorGE vENi

ExEcutivE DirEctor

NatioNal cavE aND Karst rEsEarch iNstitutE

Luck and the Gold King Mine spill

BASIN RESOURCES 41


WTI-based crudes in the Gulf Coast and

Cushing where Brent-based crudes have

now been largely displaced.

In cases where the Brent-WTI spread

grows beyond $6/b to $8/b, removal of

current restrictions on crude oil exports

would result in higher wellhead prices for

domestic producers, who would then re-

spond with additional production. This ef-

fect is evident in the HOGR and

HOGR/LP cases, where projected levels of

domestic production in 2025 in cases

without export restrictions are, respec-

tively, 3.5 percent (470,000 b/d) and

3.2% (380,000 b/d) higher than in corre-

sponding cases that maintain current ex-

port policies. In contrast, in the Reference

and LP cases, where projected annual aver-

age Brent-WTI spreads generally remain in

the $6/b to $8/b range under current ex-

port restrictions, the removal of those re-

strictions does not increase wellhead prices

or projected domestic crude oil produc-

tion. In EIA's analysis, domestic produc-

tion responds to the increase in domestic

crude oil prices, if any, when crude export

restrictions are removed in each case. Any

increase in domestic crude oil production

that occurs because of the removal of re-

strictions on crude oil exports that is not

offset by reduced production outside the

United States would also represent an in-

crease in global crude oil supplies, which

in turn places downward pressure on

global crude oil prices, as represented by

Brent. To the extent that higher domestic

production results in lower global crude

prices, the increase in the absolute level of

domestic crude prices will be smaller than

the reduction in the Brent-WTI spread,

which reflects both higher WTI prices and

lower Brent prices.

Petroleum product prices in the United

States, including gasoline prices, would be

either unchanged or slightly reduced by

the removal of current restrictions on crude

oil exports. As shown in a previous EIA re-

port (EIA, What Drives U.S. Gasoline

Prices?, October 2014) petroleum product

prices throughout the United States have a

much stronger relationship to Brent prices

than to WTI prices. In the high production

cases considered in this study (HOGR and

HOGR/LP), the elimination of current re-

strictions on crude oil exports narrows the

Brent-WTI spread by raising the WTI

price. As domestic producers respond to

the higher WTI price with higher produc-

tion, the global supply/demand balance

becomes looser unless increased domestic

The Future continued from 25

BASIN RESOURCES42


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production is fully offset by production

cuts elsewhere. The looser balance im-

plies lower Brent prices, which in turn

results in lower petroleum product prices

for U.S. consumers.

Combined net exports of crude oil and

petroleum products from the United

States are generally higher in cases with

higher levels of U.S. crude oil production

regardless of U.S. crude oil export poli-

cies. However, crude oil export policies

materially affect the mix between crude

and product exports, particularly in the

HOGR and HOGR/LP cases, which have

high levels of domestic production. The

result regarding combined net exports of

crude and petroleum products reflects a

market in which domestic consumption

of petroleum products is mainly driven

by the economy, efficiency policies, and

petroleum product prices and does not

depend significantly on the level of U.S.

crude oil production. Looking at the

composition of trade, crude oil exports

tend to represent a larger share of com-

bined crude and product exports in cases

where crude oil exports are unrestricted.

Also, in cases where the level of domestic

crude production increases with the re-

moval of crude oil export restrictions,

total combined crude and product ex-

ports are higher than in parallel cases

with current crude export restrictions in

place.

Refiner margins (measured as the

spread between crude input costs and

wholesale product prices), which tend to

increase as the Brent-WTI spread widens,

would be lower without current restric-

tions on crude oil exports than with

them in high-production cases where ex-

port restrictions lead to a widening

Brent-WTI spread. If domestic crude oil

production reaches a level where current

restrictions on crude oil exports result in

a need for significant additional process-

ing capacity to convert domestic crude

into petroleum products that can be ex-

ported, the discount of domestic crude

prices compared with global crudes such

as Brent will widen to encourage invest-

ment in such capacity, notwithstanding

the risk of future changes in crude oil ex-

port policy or market conditions. For

owners of existing refinery capacity, a

wider Brent-WTI spread will provide

higher margins as refined product prices

continue to move with global crude

prices. In high-production cases, the re-

moval of export restrictions limits growth

of the Brent-WTI spread (Table ES-1),

limiting growth in refining margins.

However, even with the removal of ex-

port restrictions, the projected Brent-

WTI spread would still be higher than its

average level in 2014. For upstream oil

BASIN RESOURCES 43


producer margins, the opposite prevails –

in addition to an increase in production

in cases where unrestricted crude oil ex-

ports result in higher domestic prices,

production that would occur with or

without a change in crude oil export pol-

icy is more profitable with domestic well-

head prices that are not held down by

crude oil export restrictions.

Although unrestricted exports of U.S.

crude oil would either leave global crude

prices unchanged or result in a small price

reduction compared to parallel cases that

maintain current restrictions on crude oil

exports, other factors affecting global sup-

ply and demand will largely determine

whether global crude prices remain close

to their current level, as in the Low Oil

Price case, or rise along a path closer to

the Reference case trajectory. While remov-

ing restrictions on U.S. crude oil exports

either leaves global prices unchanged or

lowers them modestly, global price drivers

unrelated to U.S. crude oil export policy

will affect growth in U.S. crude oil produc-

tion and exports of crude oil and products

whether or not current export restrictions

are removed.

Caveats

The results of this study are sensitive

to key assumptions used in the modeling

as well as the structural features of EIA’s

model. Differences between the results

obtained in this study and other analyses

that address the same subject may result

from differences in models or assump-

tions.

Characterization of current

crude oil export policies

As noted above, current policies restrict,

but do not ban, crude oil exports, and they

are also assumed to allow exports of API

50 and greater material that is processed

through a distillation tower. The use of a

more restrictive characterization of current

policies, which some other studies have ap-

plied, would likely show crude oil export

restrictions to be binding at lower domes-

tic production volumes and show larger ef-

fects from their removal for cases in this

analysis in which they already have an im-

pact on domestic production and crude ex-

port volumes.

Ability to back out existing crude

oil imports

To date, import substitution has been a

key part of the response to increased do-

mestic crude oil production. Between

2011 and 2014, U.S. light crude imports

(35 API or greater) decreased by 1.0 mil-

lion b/d, while imports of medium crude

(27 API up to 35 API) decreased by 0.8

million b/d. Heavy crude imports (below

BASIN RESOURCES44


27 API) remained relatively flat in 2011

and 2012, but they have increased since

2013. Consistent with recent experience,

the analysis assumes that import substitu-

tion or import shifting (for example, re-

ducing imports of medium crudes and

increasing imports of heavy crude for

blending with light domestic streams) con-

tinues to be an option. However, import

substitution must remain economic to con-

tinue.

For example, refiners would be unlikely

to back out heavy crude imports needed

to keep their coking units fully charged,

particularly since suppliers of such crudes

may not be able to find alternative mar-

kets, and may therefore discount their

prices. More severe limits on continued

import substitution, up to and including

the assumption in some studies that it is

nearly impossible to back out any remain-

ing imports, would result in domestic pro-

cessing capacity to become constrained at

somewhat lower levels of domestic crude

oil production than in this analysis.

Additions of domestic processing capacity

After increasing significantly in 2012,

U.S. crude processing capacity has been

rising more slowly over the past few years.

Nevertheless, several splitter and refinery

projects are currently underway. This re-

port allows for additional expansion of do-

mestic processing capacity in high

production cases, although potential in-

vestors in such projects are assumed to re-

quire high and rapid return on their

investment in new processing facilities,

whose economic value could be adversely

affected by future changes in crude oil ex-

port policy.

More restrictive assumptions regarding

barriers to incremental refining capacity

investments, including an assumption in

some studies that no new investment in

U.S. processing capacity could occur given

the risk of a subsequent change in crude

oil export policy, could increase the chal-

lenge to increased domestic crude produc-

tion under current crude export policies.

The effects of more restrictive assumptions

regarding investment in processing capac-

ity would likely be most significant in

cases that assume high resource availability

(HOGR, HOGR/LP).

Global production response to incremental U.S. production

This study assumes a partial global off-

set to increases in U.S. crude oil produc-

tion. A larger (e.g., full offset) or smaller

(e.g., no offset) global production response

would respectively increase or reduce the

size of the projected increase in domestic

crude prices and domestic production asso-

ciated with the removal of export restric-

tions in the high resource (HOGR and

HOGR/LP) cases, while respectively re-

ducing or increasing the projected decline

in crude and petroleum product prices at

home and abroad.

BASIN RESOURCES46


E N E R G Y N E W S. . . . . . . . . . . . . . . . . . . . . . . . . .

Across the Nation

U.S.-Mexico crude oil swaps approved

last month by the U.S. Department of

Commerce's Bureau of Industry and Se-

curity will likely involve exchanges of

U.S. light sweet crude for Mexican heavy

sour crude that is already being exported

to the United States. The swaps, which

are provided for under longstanding reg-

ulations governing U.S. crude oil exports,

are expected to be both economically

and environmentally beneficial

to both parties because of dif-

ferences in crude oil qualities as

well as differences in each coun-

try's petroleum refineries. The

swaps will allow a greater de-

gree of operational efficiency in

both Mexico and the United

States while allowing for in-

creased supply of lower-sulfur

gasoline from Mexican refiner-

ies.

With significant coking and desulfur-

ization capacity, U.S. Gulf Coast refiner-

ies are well-suited to process heavy sour

crude, but much of the recent crude oil

production gains in the United States

have been light sweet crudes coming

from plays such as Eagle Ford. There are

six major refineries in Mexico. Three of

them, representing 42 percent of total

capacity, have coking units and can pro-

duce lower-sulfur gasoline. The other

three refineries do not have cokers and

related upgrading units. Consequently,

they produce only limited amounts of

lower-sulfur products and are not well-

configured to process heavy sour crude

oil. In 2014, the six refineries processed

1.2 million barrels per day (b/d) of crude

oil, which included 658,000 b/d of Isth-

mus, a medium sour crude, and 497,000

b/d of Maya, a heavy sour crude blend.

Although the full effects of crude oil

substitution in refineries can be complex,

EIA analyzed the relative product yields

and the sulfur levels of the resulting

products for three Mexican crude oils

(Maya, Isthmus, and Olmeca) along with

the same information for U.S. crude oil

and condensate produced from the Eagle

Ford formation of southern Texas. As

shown in the figure, both product yields

and the sulfur levels of the distillation

products vary among the different crude

oils. Notably, while Olmeca has similar

product yields to some of the Eagle Ford

crude produced in the United States, the

Eagle Ford crude has lower sulfur con-

tent.

The difference in sulfur content is par-

ticularly important for the naphtha cut,

which is blended or further refined to

make motor gasoline. Mexico hopes to

achieve a level of 30 parts per million

(ppm) for all gasoline nationwide; fuel

meeting this sulfur specification is cur-

rently available only in major

Mexican metropolitan areas or in

premium fuel.

The partial substitution of

Eagle Ford crude for Mexican

crudes (such as Isthmus and

Olmeca that are run either

straight or blended with heavier

Mexican crudes such as Maya) in

Mexican refineries would free up

sulfur removal capacity in the

Mexican refining system. This would, in

turn, allow that capacity to be used to

produce more lower-sulfur gasoline than

is currently possible. Any increased sup-

ply of lower-sulfur gasoline to Mexico's

motor gasoline market, which consumed

761,000 b/d in 2013, would result in

reduced sulfur emissions and other envi-

ronmental benefits.

More analysis on the potential eco-

nomic and environmental benefits of

swapping crude oils with Mexico is avail-

able in This Week in Petroleum.

Crude oil swaps with MexiCo

Plan could provide economic, environmental benefits

BASIN RESOURCES 47


Natural gas production across all major

shale regions in EIA's Drilling Productivity

Report (DPR) is projected to decrease for

the first time in September. Production

from these seven shale regions reached a

high in May at 45.6 billion cubic feet per

day (Bcf/d) and is expected to decline

to 44.9 Bcf/d in September. In each

region, production from new wells is

not large enough to offset production

declines from existing, legacy wells.

The DPR provides a month-ahead

forecast of natural gas and crude oil

production for the seven most signifi-

cant shale formations in the United

States. In order to estimate total natu-

ral gas production within a DPR region in

a given month, production from both new

wells and legacy wells must be taken into

account. New-well production is estimated

by multiplying estimated rig productivity

by the number of rigs operating in the re-

gion, lagged by two months. Production

from new wells is then compared to the

anticipated production declines from

legacy wells, which are typically based on

well depletion rates, to estimate net pro-

duction.

In any given month, new-well produc-

tion depends on the number of drilling

rigs and the productivity of those rigs and

the wells added through their use. As rig

counts fall, increases in rig productivity are

necessary not only to compensate for the

reduced rig total, but also for rising levels

of legacy-well declines. Given the substan-

tial drop in rig counts since the fourth

quarter of 2014 in each of the DPR re-

gions and growing declines in production

from legacy wells, productivity increases

are less able to completely offset lower rig

counts and legacy-well declines.

The Utica region in eastern Ohio is the

only DPR region expected to show pro-

duction increases in June, July, and August.

Production declines from legacy wells in

the Utica are estimated to total 55.6 mil-

lion cubic feet per day (MMcf/d) in Sep-

tember. Partially countering this decline is

expected production from new wells of

52.2 MMcf/d in September. New-well

natural gas production per rig is estimated

to be about 7 MMcf/d, an increase of

47% from September 2014. Seven rigs

were drilling in the Utica in July (the

most recent data available). Multiplying

the seven rigs by the estimated new-

well gas production per rig yields the

total new-well production estimate for

September. Because this value is lower

than the decline from legacy wells, total

production is expected to fall by 3.4

MMcf/d.

A year ago, the higher number of rigs

operating in the Utica meant that new-well

production more than offset the 26.5

MMcf/d in legacy-well declines, resulting

in a net production increase of 116.5

MMcf/d. Since then, falling rig counts and

increasing legacy-well declines mean the

increase in Utica new-well productivity is

insufficient to overcome legacy-well pro-

duction declines.

EIA expects near-term decline in natural

gas production in major shale regions

* Shale regions 48

BASIN RESOURCES48


Shale Regionscontinued from 47

Several external factors

could affect the estimates, such

as bad weather, shut-ins based

on environmental or economic

issues, variations in the quality

and frequency of state produc-

tion data, and infrastructure

constraints. These factors are

not accounted for in the DPR.

For example, on August 1, the

Rockies Express Pipeline

started to deliver 1.8 Bcf/d of

Appalachian natural gas pro-

duction west on its existing

mainline as part of the Zone 3

East-to-West Project. This in-

crease in takeaway capacity

may encourage increased pro-

duction from regions such as

the Marcellus and Utica.

The DPR provides a very

near-term forecast in specific

plays based on the most cur-

rent information. Longer term

outlooks that include play-

level detail, such as the Annual

Energy Outlook, reflect re-

source and technology as-

sumptions and projected prices

and often move in different di-

rections than the DPR, which

reflects short-term factors.

Growth in solar photo-

voltaic (PV) module produc-

tion has slowed in recent

years to 4 percent annually

from 2011 to 2013 after in-

creasing by an average of 78

percent from 2006 to 2011.

In addition, the gap between

global PV module manufac-

turing capability and produc-

tion has grown, leading to

lower utilization rates of man-

ufacturing facilities.

The utilization rates of PV

module manufacturing facili-

ties (in terms of actual pro-

duction as a percent of

maximum throughput) peaked

in 2011, when production

was 36.6 gigawatts (GW) and

capability was 52 GW, giving

a utilization rate of 70 per-

cent. In 2013, although pro-

duction and capability

increased slightly, the utiliza -

tion rate of manufacturing fa-

cilities declined to 66 percent.

Sales of solar PV panels

manufactured in China into

North American and Euro-

pean markets at extremely low

prices have led to complaints

of unfair trade practices.

Global solar photovoltaic

manufacturing production

slows in recent years

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BASIN RESOURCES 49


of unfair trade practices. Based on an in-

vestigation that found Chinese solar PV

modules were being dumped or subsidized

in the U.S. market, the U.S. Department of

Commerce established anti-dumping and

anti-subsidy duties on PV modules from

China. In Europe, the European Commis-

sion and the major Chinese manufacturers

reached an agreement on minimum prices

and shipping volume.

The market is reacting to the slow

growth of module production and the de-

creased utilization of PV manufacturing

capability by downsizing and consolidat-

ing PV manufacturing companies.

For example, Germany reported to theIn-

ternational Energy Agency that there were

a total of 11,000 employees working in 40

PV companies operating in Germany at the

end of 2013, compared with 32,000 em-

ployees in 62 companies at the end of

2008. Similar trends were reported in

China, with Chinese PV module and cell

manufacturers decreasing from 300 com-

panies to fewer than 100 companies.

Despite the consolidation of Chinese

manufacturing companies, China continues

to be the largest producer of PV modules,

manufacturing 23 GW in 2012 and 26

GW in 2013, or more than 60 percent of

annual global PV module production in

those years, mainly to serve export mar-

kets. China ranks just ahead of the United

States as the sixth-largest installer of solar

photovoltaics. However, China has an-

nounced a goal of installing 100 GW by

2020, almost as much as the 2020 targets

of Germany, Italy, and Japan combined.

Future demand for solar photovoltaics

will be affected by major countries' goals

for installed solar capacity. More than 50

countries have established national solar

targets, amounting to more than 350 GW

by the year 2020. The current top six

countries in terms of total installed solar

capacity—Germany, Italy, Japan, Spain,

France, and China—represented 76 per-

cent of installed capacity in 2012, but only

61 percent of the global target total for

2020. Reaching 350 GW by 2020 would

require average annual installments of 40

GW from 2013 through 2020, which is

equivalent to manufacturing production in

2013 and well within current PV manufac-

turing capability of 60 GW per year.

In some cases, national targets are not

indicative of a country's future solar PV

market. For example, the United States

does not have a national target. Instead,

several individual states have established

renewable portfolio standards, some with

separate targets explicitly for solar. Fur-

thermore, countries tend to adjust their tar-

gets. For instance, India recently increased

its solar target from 20 GW to 100 GW by

2022.

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