Basin Resources Fall 2015 by Majestic Media

4 BASIN RESOURCES

FALL 2015

content OWNING THEIR OWN ELECTRIC UTILITY Bloomfield sues Farmington after negotiations fall flat

Don Vaughan puBliSHER

Cindy Cowan Thiele EDiTOR

Dorothy Nobis Debra Mayeux CONTRiBuTiNG WRiTERS

Josh Bishop CONTRiBuTiNG pHOTOGRApHER

FROM BORDER TO BORDER AND COAST TO COAST

Suzanne Thurman

EPA: ‘TRAGIC AND UNFORTUNATE INCIDENT’

DESiGNER

Clint Alexander SAlES STAFF

lacey Waite ADMiNiSTRATiON

For advertising information Call 505.516.1230

Column

Unique and invaluable

Column

Securing Bloomfield’s future

Nearing capacity

Oil and gas businesses flock to Bloomfield Industrial Park

BLM Proposes Changes

13 23

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

Last Update was 1991 Gov. Martinez dicusses new state energy policy at SJC

We need grassroots activism and pressure

Column The Animas spill and the problem with the EPA

Column

Bureau seeks public comment

The Future

Open for Learning

www.basinresourcesusa.com

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Thriving in the New Normal

Column

Luck and the Gold King Mine Spill

Energy News

Majestic Media 100 W. Apache Street Farmington, NM 87401 505-516-1230 www.majesticmediausa.com Basin Resources magazine is published four times a year by Majestic Media. Material herein may not be reprinted without expressed written consent of the publisher. Opinions expressed by the contributing writers are not necessarily those of the publisher, editor or Basin Resources magazine. Every effort has been made to ensure the accuracy of this publication. However the publisher cannot assume responsibility for errors or omissions. © 2015 Basin Resources magazine.

www.basinresourcesusa.com • FALL 2015

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6 BASIN RESOURCES

UniqUe and invalUable

Our students are the true measure of success 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 facility? When I learned the collection was from Sherman Dugan’s private collection, my excitement turned to a deep appreciation. Sherman 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 geology and its importance to us all. When we first started our journey to build a new School of Energy, 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 unexpected generosity of Tom Dugan with the Sherman Dugan Museum 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 people 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

* Pacheco 35

randy Pacheco dean of School of energy San JUan college www.basinresourcesusa.com • FALL 2015

8 BASIN RESOURCES

Owning their own electric utility Bloomfield sues Farmington after negotiations fall flat 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 community, so much so that bloomfield’s attorney 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, attempting 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 opportunity 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 ownership 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

“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,”” — Mayor Scott Eckstein

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 entities we are trying to enforce.” The city of aztec was allowed to purchase 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 www.basinresourcesusa.com •FALL 2015

BASIN RESOURCES 9 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 revenue 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 during 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 independent 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.

Securing Bloomfield’s future 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 electric 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 – including Gallup, Raton, Jicarilla Apache Nation, and the Navajo Nation – successfully run their own electric utilities, so this is hardly unusual. We recognize that Farmington significantly invested in the electric system in Bloomfield over time, which is why we wish 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 independent appraiser to determine the fair market value of those assets. Bloomfield’s residents and businesses generate approximately $1 million annually in surplus that is added to Farmington’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 Bloomfield’s residents to take control of their future. Last year we initiated a good-faith effort to negotiate with Farmington, attempting to avoid burdening taxpayers with a costly legal battle. When our efforts were rebuked, we were forced to file a lawsuit. We are committed to determining

eriC Strahl Bloomfield City manager FALL 2015 • www.basinresourcesusa.com

whether Bloomfield will have its own electric utility by following a thorough methodical process that adheres to the letter of the law. This takes time, but we are determined 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.

10 BASIN RESOURCES

NeariNg capacity Oil and gas businesses flock to Bloomfield Industrial Park 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 excited 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

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BASIN RESOURCES 11

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Oil Changes & More ,2 ,-4(2 (1-$&(.(/4 (26,&( 540.$4,& 2$/3.,33,0/ (26,&( $%,/ ,2 ,-4(2 (26,&( 5(- ,-4(2 (1-$&(.(/4 (26,&( 5(- 734(. -($/,/* 8 ($'-,*+4 (3402$4,0/ ($'-,*+4 $,--,*+4 (1-$&(.(/4 $',$402 -53+ (21(/4,/( (-4 2,6( (1-$&(.(/4 ,2( 04$4,0/ (26,&( !,1(2 -$'( (1-$&(.(/4 (26,&(

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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 Instrumentation, 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 filling 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 Bloomfield.’”

www.basinresourcesusa.com •FALL 2015

BASIN RESOURCES 13

BLM proposes changes Bureau seeks public comment DeBra Mayeux Basin Resources The Bureau of Land Management made a move July 10 to replace the Onshore Oil and Gas Order Number 3 to prevent theft and loss of natural resources, 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 minimum 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 necessary based on its experience with oil and gas measurement in the field and the changes in technology and industry operations” 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 important step forward toward modernizing our program and will help us ensure that oil and gas sites are properly and responsibly managed.” updates to the proposed rule would:

“The BLM’s rules concerning oil and gas measurement are over 25 years old and are long overdue for an update.” — Neil Kornze BLM Director

• establish uniform procedures for designating official points for oil and gas measurement for royalty accounting purposes, known as facility measurement points, that are applicable to new and existing leases; • Codify existing guidance related to approving commingling - combining of production from multiple leases in unit participating areas, communitized areas

53 oil and gas leases auctioned in N.M. by BLM DeBra Mayeux Basin Resources New Mexico is set to receive more than $33.4 million on the sale of 53 federal oil and gas leases that were auctioned 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 “allof-the-above strategy to continue to expand safe and responsible domestic FALL 2015 • www.basinresourcesusa.com

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 government 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/oilandgas.

14 BASIN RESOURCES 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 reporting requirements; • Require operators of new and existing 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 operators with respect to records. “The proposed rule represents an important 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-

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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 resources, 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, environmental groups, the oil and gas industry, 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 recommendations 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 production on public lands is more than $33 billion, 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 online at https://www.federalregister.gov/oublicinspection. Comments on the proposal may be submitted online at http://www.regulations.gov.

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BASIN RESOURCES 17

From border to border and coast to coast Local Advanced Telemetrics No. 1 distributor of the digital tank gauge 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 Telemetrics. Walls purchased advanced Telemetrics three years ago from a company in San antonio, Texas. He then moved the manufacturing business to Farmington and put it under the umbrella of his resource Production 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

FALL 2015 • www.basinresourcesusa.com

Photos by Josh Bishop

18 BASIN RESOURCES 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 control 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, explosionproof 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.

www.basinresourcesusa.com •FALL 2015

BASIN RESOURCES 19 This is because the items produced by those eight employees are being shipped to Texas, Oklahoma, Louisiana, Pennsylvania, Colorado, Wyoming, West Virginia, Washington, 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 Farmington. “It’s a concern because there is not a direct 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.

FALL 2015 • www.basinresourcesusa.com

20 BASIN RESOURCES

EPA: ‘Tragic and unfortunate incident’ Gold King Mine Spill had devastating effects 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 determining 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 Cement 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. www.basinresourcesusa.com •FALL 2015

BASIN RESOURCES 21

State of emergency New Mexico Gov. Susana Martinez on Aug. 10, declared a state of emergency, after touring the spill, which left the Animas River a deep, burnt orange color. In addition to the state of emergency declaration, 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 environmental 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 longterm effects of the spill and support efforts to mitigate the spill. “I want New Mexicans 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 assist communities in the affected area,” Martinez said, as she directed her staff to be prepared to take legal action against the EPA. EPA Director Gina McCarthy, while not

FALL 2015 • www.basinresourcesusa.com

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.

directly taking responsibility for the spill, called it a “tragic and unfortunate incident.” She said the EPA routinely works throughout the southwest to clean up abandoned mines, and was using a contracting team with heavy equipment to enter the mine and begin treating the contaminated 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 protecting 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.”

22 BASIN RESOURCES

State launches investigation By August 19, questions about the spill remained unanswered, so Gov. Martinez 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 Nation She also spoke with Navajo Nation leaders, who plan to bring litigation against the EPA for the spill. In addition to the investigation, Martinez announced a multiagency long-term impact review team to monitor the effects of the spill. The team will conduct research, collaborate with local communities, federal officials, and members of the public, and share information to learn more about the potential long-term impact 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 adverse health effects from exposure to the metals detected in the river water samples from skin contact or incidental ingestion.” 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 products.” 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 Animas 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 inactive Colorado gold mine after the agency inadvertently triggered the 3-million-gallon spill of polluted water there last month. The EPA released documents September 16 outlining possible plans to build the plant quickly below the Gold King Mine near Silverton. “This is an emergency response action,” 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.

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BASIN RESOURCES 23

The fuTure Effects of removing restrictions on U.S. crude oil exports United States oil production has grown rapidly in recent years. Data reflecting combined U.S. production of crude oil and lease condensate show a rise from 5.6 million barrels per day (b/d) in 2011 to 8.7 million b/d in 2014. EIA's August 2015 ShortTerm Energy Outlook forecasts U.S. crude oil production of 9.4 million b/d in 2015

FALL 2015 • www.basinresourcesusa.com

and 9.0 million b/d in 2016, with the decrease in production between 2015 and 2016 reflecting recent and forecast changes in drilling activity following the sharp decline 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 limitations 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.

Executive Summary

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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 imports 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 Options 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, Implications of Increasing Light Tight Oil Production for U.S. Refining, May 2015). EIA also developed projections of domestic crude oil production by crude type through 2025 (EIA, U.S. Crude Oil Production to 2025: Updated Projection of Crude Types, May 2015), supplementing the overall production projection provided in theAnnual Energy 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 without the removal of current restrictions on crude oil exports. Four baseline 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 production. Current laws and regulations allow for unlimited exports of petroleum 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-exports 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 exports averaged 491,000 b/d. In addition, exports of processed condensate 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 www.basinresourcesusa.com •FALL 2015

BASIN RESOURCES 25 to rise; some volumes sent to Europe and Asia," Today in Energy, October 31, 2014). Even with current restrictions, a further increase 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 alternative cases that allow unrestricted exports of crude oil, paralleling the current treatment of petroleum product exports.

Key analysis results The effects of eliminating restrictions on crude oil exports depend on the level of future domestic production, which itself depends on the characterization of resources and technology as well as future crude oil prices. Under current policies, projected domestic 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 investment in additional processing capacity to convert incremental volumes of domestic crude oil into exportable petroleum products. In the Reference case, where production averages 10.4 million b/d over 2020-25, there is no need for a wider

Brent-WTI spread to encourage more investment in domestic processing capacity additions. The average annual Brent-WTI spread remains close to $6/b in the Reference case whether or not restrictions on crude oil exports 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 significantly from historic experience in which Brent and WTI typically traded close to parity. 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 parity reflected competition between Brent- and

* The Future 41

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26 BASIN RESOURCES

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.

Last update was 1991 Gov. Martinez discusses new state energy policy at SJC All eyes were focused on the energy industry on Tuesday, September 15, in Farmington. 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 Improvement Plan, according to Gov. Martinez, departs 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 citizens. In the preface to the new policy she writes that a key principle to the plan is www.basinresourcesusa.com •FALL 2015

BASIN RESOURCES 27 “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 better lead economically, create well-paying jobs across our state, and better respond to the changing needs of the future 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 energy policy includes 12 objectives. Energy, Minerals & Natural 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, including:

Infrastructure Creating or improving energy infrastructure will not only create jobs, but also open up new markets for New Mexico’s energy and products. From new rail lines to additional electric transmission, our state can better move our energy and its derived products around New Mexico, the Southwest, and Mexico. Infrastructure in oil and gas development attracts new project capital investment and can help clear export bottlenecks.

Education Educational 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 education 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 investment in infrastructure, exploration, and production through smart tax incentives.

Regulatory Streamlining Removing unnecessary requirements from energy industry operations will expand growth. Regulatory balance and timely actions can be achieved without compromising on health, safety, and environmental standards. We can be prosperous producers while protecting our resources.

New Collaboration with Federal Agencies New Mexico’s energy resources exist in many jurisdictions, including state, tribal, federal and fee (private). This Administration has established a precedent in assisting federal/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 FALL 2015 • www.basinresourcesusa.com

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 infrastructure 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 Economy The 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 accounted 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 Countries (OPEC), with Saudi Arabia at its core, drove down oil prices to protect against its losses in market share to U.S. shale oil production. 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 Costs Breakeven 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 www.basinresourcesusa.com •FALL 2015

BASIN RESOURCES 29 reducing the number of new wells drilled, potentially shutting in some producing wells, and stopping production on marginally producing wells. All of these activities have implications for New Mexico’s economy.

Oil revenue vs. natural gas The 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 70percent. 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 benefits all reaches of New Mexico through General Fund disbursements, capital funding projects, gross receipts taxes, and ad valorem taxes that go to the counties.

The oil industry expansion between 2010 and 2014 accounted for unprecedented 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, respectively, compared to the statewide December 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, private sector jobs, and the New Mexico Department of Workforce Solutions reports that the mining (oil and gas) and utility industries supply the first and second highest wages of all private industries in New Mexico.

Coal Beyond oil and gas, there are other sources of revenue and jobs in the energy sector. Coal mining has traditionally been a significant source of revenue and jobs for northwestern New Mexico, and in 2013 the coal industry returned $23 million in revenue to New Mexico and employed 1,600 people.

Renewable Renewable energy and energy efficiency industries are also contributing to New Mexico’s economy: in 2013, $131 million was invested in New Mexico to install solar energy 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 Mexico—which primarily is paid to the State Land Office or rural landowners—

* Last Update 35

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30 BASIN RESOURCES

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..

Open fOr learning New School of Energy an educational hub for the industry DEbra MayEux Basin Resources The bP Center for Energy Education at San Juan College opened its doors in midJuly, 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 65,000square-foot building that cost $15.8 million to construct. “It came in on time and in budget,” School of Energy Dean randy Pacheco said. The building was designed by albuquerque 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 barbecue and we want them to barbecue here.” While the focus has long been to provide 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 www.basinresourcesusa.com •FALL 2015

BASIN RESOURCES 31 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 issues,” he said. “There’s a lot of collaboration 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 Farmington, where it operated for several years under Pacheco’s leadership. He admitted that he often hoped and dreamed the facility would someday be located on the college 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

FALL 2015• www.basinresourcesusa.com

Photos courtesy of San Juan College San Juan College President Toni Pendergrass addresses the crowd at the ribbon cutting for the new School of Energy. 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 Production Company, donated funds to have an outdoor seating area with a flagpole to honor veterans. “He wanted a veterans’ memorial to honor all of those who have served,” said Gayle Dean, executive director of the San Juan College Foundation.

“Tom Dugan is a huge philanthropist.”

Sherman Dugan Museum of Geology Dugan 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 established The Sherman Dugan Museum of Geology within the School of Energy. It includes 200 specimens, including the remains of a 35-million-year-old mammal, named “Bob.” “The excitement their donation creates resulted in the donation 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 Museum in Socorro. The museum will continue to grow, according to Dean, who said it also includes a virtual sandbox, which was part of College President Dr. Toni Pendergrass’ request to have interactive

* School of Energy 34

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34 BASIN RESOURCES

School of Energy

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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 Service’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 Mexico Colleges and Universities, and San Juan College did not want to duplicate programs. The School of Energy is unique. “We are strategically 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 slowdown 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 hiring 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.

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BASIN RESOURCES 35

Last Update

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is estimated to be over $2.9 million.

Listening Sessions With regional economic development organizations as hosts and partners, listening sessions were held across New Mexico to gather input from diverse stakeholders about existing energy production conditions and future opportunities for enhancing energy development and deployment 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 generation • Crude oil, natural gas, water, and nuclear power • State and federal oil and gas regulation Las Cruces: March 19, 2014 • Renewable energy: biofuels, solar, geothermal energy • Water/energy nexus • Commercialization, infrastructure, financing

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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 opportunities for New Mexico To view the State Energy Policy and Implementation Plan go to http://www.emnrd.state.nm.us/EnergyPolicy.

continued from 6

of Geology, we are reminded that each student is unique and invaluable, just like the minerals and rocks in our display. We appreciate our students, we are committed to providing the training and education they need, and will continue to partner with the community 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.

36 BASIN RESOURCES

The Animas spill and the problem with the EPA So much has been said and written about the EPA-induced debacle on the Animas 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 Corners area of the New Mexico part of the . The areas are beautiful and attract tourists from all over the world for activities such as as skiing, fly fishing, mountain 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 Durango 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 scientific understanding of the potential environmental 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 earlier in 1970 with celebration of the first Earth Day on April 22. American attitudes about the environment 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 original design – with dire economic impacts. 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 rio

President Grande Foundation www.basinresourcesusa.com •FALL 2015

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 experiment” 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 Washington, could states perhaps opt out of some or all EPA regulations 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 activity, 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 freedom and individual responsibility.

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34 BASIN RESOURCES

Thriving in the New Normal It’s still about our people 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 motivated people to do the work. As busi-

ness owners and executives, we sometimes get so hung up on how much our people cost that we don’t pay attention to their productivity, which usually reflects on their well-being. I was really taken aback recently on one of my visits with a local

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BASIN RESOURCES 39 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 latest 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 budgeting 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” financial literacy forum at 3 p.m., October 6. Your employees’ well-being is at stake, and so is your profitability.

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40 BASIN RESOURCES

Luck and the Gold King Mine spill 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 agriculturally rich river floodplain until the Animas flowed into the San Juan River at Farmington. It then turned northwest through another 37 miles of productive bottomland that almost reaches Utah. Another 70 miles downstream, the flow entered Glen Canyon National Recreational Area, then 70 miles further joined the Colorado River at the upper end of Lake Powell. Early reports suggest the lake will dilute the pollutants to safe levels. Let’s be optimistic and hope so. Damage has already occurred 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 different 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 consequences would have been especially bad. Caves are the natural pipelines that transmit groundwater in karst. Twenty-five percent 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. Natural filtration is effectively non-existent, especially 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 environmental 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 releases 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 environmental 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 legislation and funding to clean up our toxic legacy from past generations, and to protect our environment from future, avoidable, disasters. Editors NotE: dr. George Veni is an internationally renowned karst hydrogeologist and the Executive director of the National Cave and Karst research institute, based in Carlsbad, New Mexico.

Dr. GEorGE vENi NatioNal

ExEcutivE DirEctor cavE aND Karst rEsEarch iNstitutE www.basinresourcesusa.com •FALL 2015

BASIN RESOURCES 41

The Future

continued from 25

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 respond with additional production. This effect is evident in the HOGR and HOGR/LP cases, where projected levels of domestic production in 2025 in cases without export restrictions are, respectively, 3.5 percent (470,000 b/d) and 3.2% (380,000 b/d) higher than in corresponding cases that maintain current export policies. In contrast, in the Reference and LP cases, where projected annual average Brent-WTI spreads generally remain in the $6/b to $8/b range under current ex-

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port restrictions, the removal of those restrictions does not increase wellhead prices or projected domestic crude oil production. In EIA's analysis, domestic production 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 restrictions on crude oil exports that is not offset by reduced production outside the United States would also represent an increase 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 report (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 restrictions 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 production, the global supply/demand balance becomes looser unless increased domestic

42 BASIN RESOURCES production is fully offset by production cuts elsewhere. The looser balance implies 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 policies. 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 combined 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 removal of crude oil export restrictions, total combined crude and product exports 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 restrictions on crude oil exports than with them in high-production cases where export 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 processing capacity to convert domestic crude into petroleum products that can be exported, the discount of domestic crude prices compared with global crudes such as Brent will widen to encourage investment in such capacity, notwithstanding the risk of future changes in crude oil export 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 removal of export restrictions limits growth of the Brent-WTI spread (Table ES-1), limiting growth in refining margins. However, even with the removal of export restrictions, the projected BrentWTI spread would still be higher than its average level in 2014. For upstream oil

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BASIN RESOURCES 43 producer margins, the opposite prevails – in addition to an increase in production in cases where unrestricted crude oil exports result in higher domestic prices, production that would occur with or without a change in crude oil export policy is more profitable with domestic wellhead 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 supply 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 removing restrictions on U.S. crude oil exports either leaves global prices unchanged or

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lowers them modestly, global price drivers unrelated to U.S. crude oil export policy will affect growth in U.S. crude oil production 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 assumptions. 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 applied, would likely show crude oil export restrictions to be binding at lower domestic production volumes and show larger effects from their removal for cases in this analysis in which they already have an impact on domestic production and crude export volumes. Ability to back out existing crude oil imports To date, import substitution has been a key part of the response to increased domestic crude oil production. Between 2011 and 2014, U.S. light crude imports (35 API or greater) decreased by 1.0 million b/d, while imports of medium crude (27 API up to 35 API) decreased by 0.8 million b/d. Heavy crude imports (below

44 BASIN RESOURCES 27 API) remained relatively flat in 2011 and 2012, but they have increased since 2013. Consistent with recent experience, the analysis assumes that import substitution or import shifting (for example, reducing imports of medium crudes and increasing imports of heavy crude for blending with light domestic streams) continues to be an option. However, import substitution must remain economic to continue. 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 markets, 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 remaining imports, would result in domestic processing 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 report allows for additional expansion of domestic processing capacity in high production cases, although potential investors in such projects are assumed to require high and rapid return on their investment in new processing facilities, whose economic value could be adversely affected by future changes in crude oil export 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 challenge to increased domestic crude production under current crude export policies. The effects of more restrictive assumptions regarding investment in processing capacity 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 offset to increases in U.S. crude oil production. 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 associated with the removal of export restrictions in the high resource (HOGR and HOGR/LP) cases, while respectively reducing or increasing the projected decline in crude and petroleum product prices at home and abroad.

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46 BASIN RESOURCES

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

Across the Nation

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Crude oil swaps with MexiCo Plan could provide economic, environmental benefits U.S.-Mexico crude oil swaps approved last month by the U.S. Department of Commerce's Bureau of Industry and Security 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 regulations governing U.S. crude oil exports, are expected to be both economically and environmentally beneficial to both parties because of differences in crude oil qualities as well as differences in each country's petroleum refineries. The swaps will allow a greater degree of operational efficiency in both Mexico and the United States while allowing for increased supply of lower-sulfur gasoline from Mexican refineries. With significant coking and desulfurization capacity, U.S. Gulf Coast refineries 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 produce 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 wellconfigured 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 Isthmus, 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 content. The difference in sulfur content is particularly 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 currently 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 supply 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 environmental benefits. More analysis on the potential economic and environmental benefits of swapping crude oils with Mexico is available in This Week in Petroleum. www.basinresourcesusa.com â&#x20AC;˘ FALL 2015

BASIN RESOURCES 47

EIA expects near-term decline in natural gas production in major shale regions 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 significant shale formations in the United States. In order to estimate total natural 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 region, 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 production.

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In any given month, new-well production 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 substantial drop in rig counts since the fourth quarter of 2014 in each of the DPR regions 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 production increases in June, July, and August. Production declines from legacy wells in

the Utica are estimated to total 55.6 million cubic feet per day (MMcf/d) in September. 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 newwell 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 production declines.

* Shale regions 48

48 BASIN RESOURCES

Global solar photovoltaic manufacturing production slows in recent years Growth in solar photovoltaic (PV) module production has slowed in recent years to 4 percent annually from 2011 to 2013 after increasing by an average of 78 percent from 2006 to 2011. In addition, the gap between global PV module manufacturing capability and production has grown, leading to lower utilization rates of manufacturing facilities. The utilization rates of PV module manufacturing facilities (in terms of actual production 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 percent. In 2013, although production and capability increased slightly, the utiliza-

tion rate of manufacturing facilities declined to 66 percent. Sales of solar PV panels manufactured in China into

North American and European markets at extremely low prices have led to complaints of unfair trade practices.

Shale Regions continued 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 production 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 production west on its existing mainline as part of the Zone 3 East-to-West Project. This increase in takeaway capacity may encourage increased production from regions such as the Marcellus and Utica. The DPR provides a very near-term forecast in specific plays based on the most current information. Longer term outlooks that include playlevel detail, such as the Annual Energy Outlook, reflect resource and technology assumptions and projected prices and often move in different directions than the DPR, which reflects short-term factors.

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BASIN RESOURCES 49 of unfair trade practices. Based on an investigation 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 Commission 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 decreased utilization of PV manufacturing capability by downsizing and consolidating PV manufacturing companies. For example, Germany reported to theInternational 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 employees in 62 companies at the end of 2008. Similar trends were reported in

China, with Chinese PV module and cell manufacturers decreasing from 300 companies 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 markets. China ranks just ahead of the United States as the sixth-largest installer of solar photovoltaics. However, China has announced 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

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countries in terms of total installed solar capacity—Germany, Italy, Japan, Spain, France, and China—represented 76 percent 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 manufacturing 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. Furthermore, countries tend to adjust their targets. For instance, India recently increased its solar target from 20 GW to 100 GW by 2022.

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