December 2015 ENERGY PIPELINE 1
2 ENERGY PIPELINE December 2015
December 2015 ENERGY PIPELINE 3
Features
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34
ANADARKO LOOKS TO THE FUTURE
AVOIDING THE MOUSE TRAP
By Sharon Dunn
By Dan Larson
Anadarko unveils its Central Oil Stabilization Facility, which promises to reduce its footprint, emissions.
16
ROCK BOTTOM
New way to bet on oil wipes out billions in investor savings.
24
BURNING THROUGH MONEY
Why does firewood cost so much? Fracking is part of it. An Associated Press story
20
2015 EARNINGS REPORTS
A look into Weld County major players’ third quarter numbers. By Sharon Dunn
4 ENERGY PIPELINE December 2015
AN OIL & GAS CONVERSTATION
ON THE COVER
Bud Weinstein with Maguire Energy Institute discusses the future of the energy industry
An Associated Press story
18
UNC alum guides Synergy Resources through industry downturn.
Photo by Sharon Dunn
By Gary Beers
26
TECH TALK
Can energy in produced water be used to desalinate produced water? By Gary Beers
38
IMPECCABLE TIMING
DCP Midstream opens Lucerne II plant just in time to reduce line pressures. By Sharon Dunn
44
MAKING HOLE
Departments 8
Support Company Profile
10
Field Worker Profile
12
Executive Profile
43
News Briefs
46
Data Center
Exploring the U.S. offshore histroy. By Bruce Wells
Symmetry Oilfield Solutions
Meet Mike West, Green Earth Environmental
Meet Jeff Wadsworth, Poudre Valley Electric Authority
See What We’re Made Of. Storage, separation and control solutions when you need them, where you need them.
Let us show you the Worthington difference.
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Dickinson, ND Garden City, KS December 2015 ENERGY PIPELINE 5
Our SERVICES shine bright with
SERVICE EXCELLENCE
PUBLISHER Bart Smith EDITOR Randy Bangert
Happy HOLIDAYS! Need an electrical distributor that’ll spread good cheer to your business all year long? We’ve got the best products and service. It’s what we, as employee-owners, call the perfect package. » Inventory management » Technical support and training » Job site project management trailer » Lighting and energy management
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December 24 open until 12 p.m. December 25 closed December 31 open until 12 p.m. January 1 closed
GENERAL MANAGER Bryce Jacobson ACCOUNT/PROJECT MANAGER Bruce Dennis BUSINESS MANAGER Mike Campbell
ADVERTISING DIRECTORS T.J. Burr Sabrina Poppe ACCOUNT MANAGERS Cristin Peratt Mary Roberts Kristy Zado CREATIVE MANAGER Alan Karnitz
MANAGING EDITOR Sharon Dunn
CREATIVE TEAM SUPERVISOR Afton Pospíšilová
CONTRIBUTING WRITERS Gary Beers Dan Larson Bruce Wells
ART DIRECTION & DESIGN Darin Bliss
ENERGY PIPELINE MAGAZINE 501 8th Ave. P.O. Box 1690 Greeley, CO 80632 For all editorial, advertising, subscription and circulation inquiries, call (970) 352-0211. Send editorial-related comments and story ideas to: editor@energypipeline.com For advertising inquiries, contact: bjacobson@energypipeline.com December 2015, Volume 3, Issue 4. Published by Greeley Publishing Co., publisher of The Greeley Tribune, Windsor Now, the Fence Post, and Tri-State Livestock News.
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SUPPORT COMPANY PROFILE
Symmetry Oilfield Solutions
SERVICES OFFERED? Whether the need is simply solidification, or complete bioremediation treatment, Symmetry has the solution.
CORPORATE HEADQUARTERS 1 Industrial Park Johnstown, CO 80534 970.587.7863 303.265.9426
WEBSITE www.symmetryoilfield.com
ABOUT SYMMETRY OILFIELD SOLUTIONS Symmetry Oilfield Solutions is a small, family owned and local business representing a total solution for transforming contaminated soil and drill cuttings into a commercially viable reclamation and construction material.
GeozorbTM, a proprietary solidification product, is a 100 percent cellulose organic-mineral blend absorption agent uniquely devised to alter the physical characteristics of the sludge drill cuttings into a stackable pile. GeozorbTM amends and solidifies sludge producing a granular, free-flowing compactable material. This proprietary, nontoxic, organic compound has beneficial environmental effects and absorbs moisture
generated from oil, water, and saltwaterbased mud systems. Symmetry’s bioremediation products are intended to remediate drill cuttings either on the well site, or at a centralized oilfield waste recycling facility. Working closely with CSU Microbiologists, Symmetry has isolated and propagated proprietary strains of bacteria specifically designed to remediate water and oil based hydrocarbons, sodium (SAR), and chloride contaminates.
HOW LONG HAS YOUR BUSINESS BEEN OPERATING IN WELD COUNTY? 5 years.
HOW LONG DO YOU ANTICIPATE BEING IN BUSINESS IN NORTHEAST COLORADO? WSymmetry’s products have successfully solidified and/or remediated over 200 wells in the DJ Basin.
IS YOUR COMPANY IN A GROWTH MODE? Symmetry is currently expanding product sales in Weld County, North Dakota, Texas, and Wyoming by developing strong, longterm relationships with interested producers and solids-control service companies within the target markets.
SYMMETRY OILFIELD SOLUTIONS For more information, send an email to info@symmetryoilfield.com 8 ENERGY PIPELINE December 2015
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FIELD WORKER PROFILE
Mike West GREEN EARTH ENVIRONMENTAL STAFF REPORT • FOR ENERGY PIPELINE
HOMETOWN Longmont, Colo.
WHERE DO YOU LIVE? Milliken, Colo.
HOW LONG HAVE YOU BEEN WORKING IN NORTHEASTERN COLORADO? I am a Colorado native and have worked in northeastern Colorado my entire life.
HOW DID YOU GET INTO THE INDUSTRY? Having been around farming my entire life and spending a lot of time on my grandparents farm in North Eastern Colorado I have learned
10 ENERGY PIPELINE December 2015
the value of hard work and taking care of what we have. I love nothing more than giving back to mother nature as she has given so much to all of us and feel so blessed to do it with Green Earth Environmental.
WHAT IS YOUR JOB TITLE AND DUTIES? Reclamation division, ground preparation, seeding, blowing straw, straw crimping.
WHAT IS THE MOST INTERESTING THING ABOUT YOUR JOB? The most interesting thing about my job is how I can turn a bare piece of ground back into its natural state.
WHAT IS THE BEST PART OF YOUR JOB? The best part of my job is that I get to do what I have always loved doing and had a passion for and being able to work with a great group of people at Green Earth, who truly care about their jobs.
WHAT IS THE HARDEST PART ABOUT YOUR JOB? The hardest part about my job is working with mother nature. No matter how much you plan out your day, she always seems to make the final decision on how much and what you get done. At times we have to be real creative to work around the elements.
WHAT DO YOU DO IN YOUR SPARE TIME? VOLUNTEERISM, SCHOOL, SPORTS? In my spare time I love spending time with my lovely wife and three kids. Going to their school sports and activities.
WHAT ARE YOUR FUTURE AMBITIONS IN THE INDUSTRY? I would love to see the oil and gas industry pick back up and make jobs more plentiful.
WHAT DOES THE WATTENBERG FIELD AND THE DJ BASIN MEAN TO YOU?
It means jobs, and a way of life for so many.
HOW DO YOU FEEL ABOUT THE CURRENT ENVIRONMENTAL DEBATE GOING ON WITH “FRACKING” IN COLORADO? I think without fracking we wouldn’t be able to produce the products that we are producing. There are a lot of things in this world that people think are bad for it and think shouldn’t be done. I think with out it we would see prices on everything go up cause it will make it that much more difficult to get it out of the ground.
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December 2015 ENERGY PIPELINE 11
EXECUTIVE PROFILE
POUDRE VALLEY ELECTRIC AUTHORITY CEO
Jeff Wadsworth BY SHARON DUNN • SDUNN@ENERGYPIPELINE.COM
for years, those in the oil and gas
industry have said, if you like it when your lights turn on, thank your local oil field worker. Jeff Wadsworth, one of the men behind that light switch, not only thanks the oil and gas industry, but gets a chance to mix in all kinds of energy companies, now that renewables are taking a larger role in generating electricity. Wadsworth, the CEO of Poudre Valley Rural Electric Association, has been on the front lines of the electric needs of this growing Front Range community of northern Colorado for the last five years, embracing change as fast as he can put his arms around it. But he likes his toolbox the way it is - a true “all-of-the-above” strategy for electric generation that includes coal, natural gas, and a growing cadre of renewables such as geothermal, hydropower and solar. Together, all of those keep his rural electric cooperative consistent and stable in delivery of electric needs of the company’s more than 35,000 customers, including oil and gas companies, in Larimer, Boulder and Weld counties. It also keeps consumer costs down. In that vein, he’s not a fan of the Environmental Protection Agency’s Clean Power Plan, which will take effect Dec. 23. The plan requires existing fossil fuel12 ENERGY PIPELINE December 2015
based power plants to achieve an overall carbon dioxide reduction of 32 percent below 2005 levels by 2030, according to the National Rural Electric Cooperative Association, which joined several states in opposing the plan by filing lawsuits challenging its legality. EPA set emission budgets for each state to meet beginning in 2022. Wadsworth can’t see the plan working as it assumes each state is independent of others when it comes to their power generation. The reality is, the grid is intertwined He said the new plan may all but eliminate coal-fired plants, which utilities such as his rely on in large part to provide that magic at the switch. According to the U.S. Energy Information Administration, in 2013, 64 percent of the electricity generated in Colorado came from coal, 20 percent came from natural gas, and 17 percent from renewable energy resources. Without coal, thats a lot to make up, and natural gas and renewables are poised to do so, but prices will go up, Wadsworth said. “Coal generation is still a big mix of the generation not only in Colorado but across the nation,” Wadsworth said. “The cost will go up, where you’ll have to look at building new generation (plants), or have to look at paying significant amount on the market. ...
“Some of the coal plants could very well could shut their doors, before their useful life is up,” he said. “When you start shutting baseload units down, the reliability becomes the question, making sure we can provide reliable power 24/7. ... The biggest impact will be price increases. Rather than being an economical dispatch to the lowest price, it will turn into a renewable, clean power plan dispatch, what plant will you call on to provide the energy to meet the clean power plan rather than calling on the plant that still has a useful life of 20-plus years.”
QA &
with Jeff Wadsworth
Energy Pipeline sat down with Wadsworth to discuss more of the issues and challenges facing the electric utility.:
Answers begin on page 14
Wadsworth, however, is glad natural gas can provide that baseload in coal’s stead, and he sees that as a boon in the fossil fuels circles. Still, there’s a place in the Clean Power Plan to affect natural gas plants as well, he said. “Natural gas will still get hit, when it comes to the price of generating that,” he said. “They’re not getting a clean pass, because of their emissions. The cost will still be there.” Meanwhile, he will work on his end to find the next best thing for his customers, whether it be in energy storage options, more renewable energy options or plain energy efficiencies built into customers homes.
ABOUT
Jeff Wadsworth SPOUSE Trisha.
LAST GOOD BOOK YOU READ “Trustology: The Art and Science of Leading HighTrust Teams,” by Richard Fagerlin.
BEST ADVICE YOU EVER GOT/GAVE
6 years.
Don’t blink. Because a lot of times in your career you can make decisions, and it doesn’t mean you can’t hear other avenues and different approaches. When you make a decision do it with all the facts you have and move forward. If you continue to waver as a leader of an organization, it causes questions.
YEARS IN THE ENERGY INDUSTRY
PROFESSIONAL HIGHLIGHTS
CHILDREN Corbin, Peyton and Tyler.
CURRENT JOB TITLE CEO, Poudre Valley Electric Association.
YEARS WITH PVREA
15 years.
CITY YOU GREW UP IN Leadville, Colo.
CITY YOU LIVE IN NOW Larimer County.
SCHOOLS YOU ATTENDED/DEGREES Fort Lewis College, Durango. Bachelor’s degree in accounting and economics.
WHAT DO YOU DO IN YOUR SPARE TIME? Fish, hunt, camp, sled with my kids and coach my kids’ events - anything that is family oriented.
Jeff was appointed CEO of PVREA in January 2014, after serving four years as the company’s chief operating officer and chief financial officer. Prior to that, he was the manager of finance and accounting at the Nebraska Public Power District, from 2008-09; the CFO at La Plata Electric Association in Durango from 2006-08; and worked as the assistant general manager at Canby Utility, an electric and water utility in Oregon, from 200205. He also served as a staff accountant to audit manager of KMBG in Portland, an international accounting firm, from 1998-2002.
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December 2015 ENERGY PIPELINE 13
QA &
ENERGY PIPELINE: How is energy changing on your doorstep? JEFF WADSWORTH: When you look at electricity and how it’s generated, that certainly is changing. You still have the fossil fuels that make that up, and that isn’t going anywhere anytime soon. Coal and natural gas are base-load units that are needed to keep the grid stable. It will be here for the foreseeable future, but certainly, with what we’ve seen in renewable and alternative energy such as solar ... the price has come down significantly. We’ve also done two community solar farms that sold out to where our members come in and buy those panels, and get a credit on their bill, that payback is certainly not short-term, but long-term is an investment you’re making. We have a lot of hydropower, too. EP: Is PVREA adding more solar into the mix because of legislative mandates, or is this an inside initiative? JW: We’re doing this because it’s the right thing to do for Poudre Valley. There have been state mandates that have come down, that are requirements for distribution cooperatives and electric providers to do a certain amount of renewable. But we had already met those and were in the process of meeting those before they came down the road. We did it because it met three things for us: it maintains reliability, helps with the affordability and as well as conserves natural resources. If it does all those things, when we’re looking at it, we want to make sure those three things are met. For our generation provider, we have a wholesale contract with Tri-State, they are required to be 20 percent (fueled by alternative energy) by 2020, and they are on track. We were required to do a portion for ourselves, which was 14 ENERGY PIPELINE December 2015
continued from page 12
1 percent of our total sales and we have met that, and we’re looking at 3.5 percent is where we’re at. Electric generation that’s produced here locally from renewables, a little over 27 percent of the power we provide is from renewables. That includes Tri-State and the Poudre Valley portion.
the lights are there. That certainly is a drawback or a challenge, if you will, to make sure where you place the utility scale solar farms to make sure you place them in advantageous places where distribution system that can interject with our system and not cause reliability issues as you go forward.
EP: You didn’t mention wind power. Is that part of the plan?
EP: What is a major challenge facing your industry today?
JW: Currently, wind is not part of our picture. If you love wind you have to love transmission. Where wind is blowing it’s not by the load centers where the energy is needed; it’s out in very much the rural parts of Colorado and Wyoming. We do have some good wind opportunities in our service territory, but the transmission capability is not there. Trying to build transmission lines is very difficult, and sometimes impossible. For alternative energy, our focus is for solar, utility scale, community solar, as well as looking at for those customers who want to do net-metering with rooftop solar. We want to be there and part of that, and perhaps provide that service.
JW: One of the things we’re seeing, is what I call an age bubble, and that’s happening not just in our industry, but across the country. Skilled workers are reaching retirement age and retiring, and the pipeline of those skilled workers to bring them in, line workers, engineers, it’s not there. We’re actively involved, we offer scholarships, and are very much a part of the community. We have 22 scholarships that go to local high school students that we provide each year. That age bubble has taken place. We continue to manage through that, we’re hiring as we speak, and we continue to manage through that to make sure the work force is there to take on the challenges.
We’re looking at any type of small hydro off of irrigation ditches, where it makes sense and we can put in small hydro that will have a good impact. Hydro is very good, it runs and starts and goes for a good 24 hours.
EP: What is the biggest misconception about electricity generation that you must correct constantly?
EP: What are the drawbacks to renewables from your point of view? JW: Depending on where the renewables are getting placed on the system, they can have reliability issues, when the sun is not shining, (it’s not working). It’s amazing, if you look at a solar production unit, it goes from 90 percent down to almost 0 and that can happen with a cloud passing over the sun. You have to have the resources and capacity there to makes sure the electricity is there,
JW: It gets down to renewables. I you put rooftop solar it doesn’t mean you’ll no longer have a utility bill, or you’ll not use electricity anymore, you can no longer disconnect. Some of the things we’ve seen is energy usage goes up. They put in rooftop solar, and think they don’t have to worry about it anymore. They’re not as energy efficient as they were before. Just with the impact of renewables. When you put one on, it’s not running 100 percent of the time, it’s not baseload. We have to have baseload. We talked about brownouts. At 8 p.m. on a hot summer evening, you want your air conditioning on, you want your lights
on. The renewable resources, there’s no guarantee they are going to be there. EP: How is it that you have so easily embraced new technologies and renewable energies to contribute to your power distribution mix? JW: There has been no significant philosophical changes for us. Part of PVREA’s long standing mission is to provide reliable and affordable service to our members, as well as maintain environmental stewardship. In that light, PVREA believes all energy projects are a good opportunity when they balance three important factors: reliability, economics and conservation of natural resources. Until recently, most new technologies and renewable energy sources did not meet one or more of these important criteria. We have turned the corner and are now seeing many new technologies and renewable projects that do meet all three of the criteria. Our Board of Directors recognize this and provide the direction to move on opportunity to fulfill our mission for the membership. EP: You started out in accounting, but moved into this energy industry. How would you describe your move into the industry, and what is the challenge for you personally? JW: My background in performing financial audits in the energy industry allowed for me to have a unique perspective and see different ways of doing day to day business. In the world of accounting most answers are black and white. Moving from an accounting focus to a CEO focus has allowed me to appreciate that there is more than one way to solve a problem. EP:Do you have any final words? JW: Change is not something you should be scared of, but something you should embrace.
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December 2015 ENERGY PIPELINE 15
ROCK BOTTOM New way to bet on oil wipes out billions in investor savings BY BERNARD CONDON • ASSOCIATED PRESS
- When Karen Robinson’s husband died, she worried she wouldn’t have enough money to raise her two young girls and save for retirement. Then she met a financial planner, Tom Parks, who told her about investment partnerships that would allow her to ride the boom in U.S. oil and gas production while receiving a steady stream of payments to help pay her bills. “He showed me this picture of the United States, and said they were getting oil out of shale, and energy was the way to go,” says Robinson, a high school teacher from Cranfills Gap, Texas. She liked that Parks seemed so confident. “I trusted him.” Two years later, her partnerships have plunged in value and Robinson has lost more than half of the $202,000 she invested, according to a complaint filed with regulators against Parks and his firm, Ameriprise Financial Services. Parks did not return phone calls and emails; Ameriprise declined to comment. For years, brokers have been luring savers like Robinson into drilling partnerships with the promise of fat payouts. With yields on safer investments like government bonds so puny, it wasn’t a hard sell. But now this once hot business, a big source of fees for brokers and banks, is coming to a messy end. In the past year, investors have lost $20 billion in publicly traded drilling partnerships, or $8 of every $10 they had invested, according to a report prepared by FactSet for The Associated Press. That figure does not include losses from $37 billion of bonds sold by the partnerships in the five years since 2010, many down by half in last 12 months, or losses from bets on private partnerships that don’t trade publicly and are difficult to track. new york
16 ENERGY PIPELINE December 2015
IN THE PAST YEAR, INVESTORS HAVE LOST $20 BILLION IN PUBLICLY TRADED DRILLING PARTNERSHIPS, OR $8 OF EVERY $10 THEY HAD INVESTED A plunge in the price of oil that few anticipated explains much of the loss. But many partnerships had borrowed heavily and were running big risks even when oil was twice as high a year ago, suggesting that either investors were too sloppy in their hunt for steady income or brokers too reckless in their hunt for fat fees - or some ugly combination of both. “If you were trying to preserve your capital, oil and gas producers were not for you,” says Ethan Bellamy, a financial analyst at R.W. Baird. “They were always higher risk investments.” The losses on partnerships are piling up as investors are having second thoughts about their headlong rush into other high-yield, high-risk securities, like bonds from volatile emerging markets or from highly indebted U.S. companies, called “junk” because they are so dangerous. In the first eight months this year, investors have yanked $4 billion each out of junk funds and emerging-market bond funds, according to the latest figures from Morningstar, a research firm.
A NEW WAY TO PLAY OIL The energy partnerships, formally called master limited partnerships, can avoid some corporate taxes by passing much of what they earn straight to their investors, called partners. These payments explain why the firms used to mostly stick to storing and transporting oil, unsexy businesses that generate a steady stream of cash. Bankers called them “toll booth” businesses, and it was meant as a compliment. With much of the cash going out the door as soon as it came in, you want boring predictability. Then the Federal Reserve slashed interest rates to near zero to help revive the economy in the financial crisis, and that helped send yields on conservative investments like U.S. government bonds plunging. Investors scrambled for alternatives to earn a bit more. Partnerships focused on drilling sprung up to meet the demand, dangling yields of 6 percent or more, and Wall Street got busy selling their stocks and bonds. In the five years through 2014, energy partnerships of all kinds raised $21 billion in initial stock sales, more than twice what they sold in the five years before the financial crisis, according to financial data provider Dealogic. For help with the sales, banks like Citigroup, Barclays and Wells Fargo pocketed an estimated $1.1 billion in fees, according to Dealogic. Fees from follow-up stock sales, plus bond offerings, added to their haul.
DEATH SPIRALS Because they can tap stock and bond markets to raise money, publicly traded partnerships appear to have plenty of
financial flexibility. But that’s not true in troubled times when investors are scared and money is needed most. One of the partnerships in Robinson’s account, BreitBurn Energy, has sold stocks and bonds to investors 10 times since 2011. It needed to raise money because nearly half the $1.6 billion it took in from selling oil and gas from its wells since 2011 went to investors. Then oil began to fall last year and BreitBurn stock tumbled. It cut its payments to investors in half to conserve cash, but by March this year the stock was still under pressure and it had to strike a deal with an investment firm for a $1 billion infusion in exchange for fat monthly payments. In just 12 months, its stock has plunged 85 percent. BreitBurn declined to comment. “It’s a little like a death spiral,” says Andrew Stoltmann, a lawyer representing Robinson. “When the bad news inevitably hits, they don’t have a cash cushion.”
BELLS GOING OFF Partnerships that don’t trade publicly have dangers of their own. Managers carve out big
payments for themselves and for the brokers who raise money for them, a dangerous move for businesses frequently in need cash to secure new wells to replace old ones running out. Ron Vaerewyck and his wife, Jeanine, found out about these risks the hard way. While their checks were coming in, the retired couple never suspected any danger in their two private partnerships, run by Reef Oil and Gas Partners in Richardson, Texas. Then production at some wells fell short, threatening the stream of income. And the big money going to Reef management and an affiliated brokerage firm, Reef Securities, left little financial cushion. Of the $90,000 they had invested, nearly $14,000 went to those two groups right from the start. The checks got smaller and infrequent, and the Orlando, Fla., couple started to worry. “The bells were going off, and we started questioning things,” says Ron, 73, a retired Dow Chemical human resources executive. “Why are your expenses so high?” In 2012, the Vaerewycks and seven other investors filed a complaint with regulators accusing the brokerage of not vetting the deals properly and misrepresenting the risks.
Last year, a panel of arbitrators ordered Reef to pay the investors $188,000, about 40 percent of what they had invested. The Vaerewycks got $45,000. Reef Oil and Gas says that the risks of the deals were clearly disclosed, with the term “risk” itself appearing dozens of times in the offering document.
THE FUTURE While partnership losses mount, other investors are hurting, too: those who poured billions of dollars into partnership bonds. Fearing they won’t get their money back when their drilling bonds mature, investors have been dumping them. A $250 million issue due in six years from Houston partnership Atlas Energy Group, once offering 9.25 percent in annual interest, has dropped 55 percent in 12 months. “When interest rates are zero and junk bonds are paying 9 percent, that is high risk,” says David Miller, a Houston lawyer who recently settled eight investor claims involving energy partnerships. “I would expect to see a wave of defaults.”
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BURNING THROUGH MONEY Why does firewood cost so much? Fracking is part of it BY RIK STEVENS • ASSOCIATED PRESS conocord, n.h. (ap) - Northeasterners who are digging deeper
into their pockets to pay for firewood this season can add a new scapegoat to the roster of usual market forces: fracking. Yep, a timber industry representative in New Hampshire said those hydraulic fracturing well sites in Pennsylvania’s Marcellus Shale formation to suck natural gas out of the ground are using construction “mats” made of hardwood logs - think of the corduroy roads seen in sepia-toned photographs from the 1800s - to get heavy equipment over mucky ground, wetlands or soft soils. That increased demand has crept down the chimney into fireplaces. Prices in parts of New England are averaging $325 a cord and can even push past $400 for a seasoned, delivered load. That’s anywhere from $50 to $75 more a cord than last year - or an increase of 18 percent to 23 percent. Jasen Stock, executive director of the New Hampshire Timberland Owners Association, said it’s not just fracking sites that are hogging the logs. Pipelines and transmission wires - really any large-scale construction project - have in the past three years ramped up the appetite for the perfect mat log: a hardwood trunk, 16 to 20 feet long and 8 to 10 inches in diameter. As a result, the cost of cordwood on the stump (that is, live trees) went from $10 in 2012 in northern New Hampshire to $15 this year, Stock said. “If you’re putting in a power line or gas line over wetlands or soft soil, they use thousands and thousands of these mats, and they’re made of hardwood logs,” Stock said. “If you’re in the firewood business, that’s your sweet spot. That’s the log you want.” About 2.5 million households in the U.S. burned wood to keep warm in 2013, just 2.1 percent of total households but up from the 1.7 percent that stoked stoves in 2005, according to the U.S. census. The percentages get significantly higher in more heavily forested New England states such as Vermont (16.3 percent), Maine (12.7) and New Hampshire (7.7), as well as the Pacific Northwest, including Idaho (7.8) and Oregon (7.1). While New England shivered and shoveled through the winter whomping of 2014-15, the Pacific Northwest stayed mild, meaning more supply and steadier prices this year. If the National Weather Service’s forecast of a warmer-than-average 18 ENERGY PIPELINE December 2015
winter in New England holds up, that Clever stacking of could mean fewer logs burned this winter, firewood on the front more robust stockpiles of seasoned porch of Terri and Bob Tomchak’s cozy home wood come springtime and potentially in Bridgton, Maine, lower prices next year. But it won’t help allows them to enjoy consumers who’ve already locked in their the view from their supplies this fall. living room window, Other uses - pulp and paper mills still Friday, Oct. 23, 2015. value hardwood and pellet producers and biomass plants also nibble on stockpiles have also given loggers more markets. “There’s only so much wood around,” said Jonathan Clark, owner of Treehugger Farms in Westmoreland, New Hampshire. The price for his kiln-dried cord went up $10 this season to $360. Demand, he said, has stayed the same. “Our calls started early this year and have continued steady,” he said. “Even now, we’re getting people who are having trouble getting their wood in.” When oil prices started to bubble up, more people in the forest states saw wood as a desirable, locally sourced, cleaner and cheaper alternative. But even as heating oil prices tanked this year, wood got more expensive. In Maine, where seasoned firewood is selling for about $300 a cord or more, many customers are buying less firewood because of heating oil prices around $2 a gallon. A few are even ditching firewood altogether. “In a year where oil spikes, we just can’t crank the firewood out fast enough. But this just isn’t one of those years,” said Jeff Lemon from Four Seasons Firewood in Searsmont, Maine. Some of the continued demand is likely coming from people who converted to woodstoves and are sticking with it. In Plainfield, Vermont, Donny Osman will heat his farmhouse with about six cords of wood this year at a cost of $230 each. Vermonters paid $180 a cord five years ago. “I think that’s fairly reasonable, when you consider how much work goes into getting you a cord of wood,” said Osman, 68, who isn’t planning on switching fuels anytime soon. “I would only do that if I couldn’t do it (handle wood) physically,” Osman said.
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2015
EARNINGS REPORTS
TURNING IT DOWN A FEW NOTCHES Anadarko reports $2.2 billion loss for third quarter; cuts Weld capex by 50 percent BY SHARON DUNN • SDUNN@ENERGYPIPELINE.COM
weld county’s largest oil and gas
producer has cut its local spending by 50 percent since the first part of the year amid a continuing downward spiral in the industry, but the local drilling program still commands the majority of the company’s spending in the United States. Anadarko Petroleum Corp., officials reported a $2.2 billion loss for the third quarter of the year, while commodity prices continue to sag. Given the price decline, oil and gas officials have had to re-evaluate their spending, raise capital and sell assets. Continued low crude prices will result in Anadarko spending less in Weld in the next quarter and next year. “We don’t have any better crystal ball than anyone else, but our mantra is we plan for the worst and hope for the best,” said Al Walker, Anadarko’s chairman, president and CEO in an earnings call with analysts. With the Wattenberg Field, one of the main drilling areas in Weld County, being one of Anadarko’s crown jewels, spending cuts hurt deep. The company spent $282 million in Weld in the third quarter compared to $574 million in the first quarter of the year. But company officials explained in its earnings call that they’re readying themselves to pounce when the market is hot again. “The Wattenberg is one of the most attractive and economic plays in our portfolio 20 ENERGY PIPELINE December 2015
... though we’re not choosing to chase growth on our 650,000 gross acre position, the work we’re doing is laying a foundation for the future,” Walker said. “Growth will not be rewarded in this environment, and building value is more appropriate, looking ahead, enhancing wellhead margins ... improving efficiencies and reducing costs, ... The value we create today will give us the foundation for future success.”
ANADARKO SPENDING IN WELD COUNTY Here’s how Anadarko’s 2015 capital spending breaks down in the Wattenberg Field, Weld’s major oil and gas drilling area: FIRST QUARTER
$574 million
SECOND QUARTER
$405 million
THIRD QUARTER
$282 million
2014 QUARTERLY SPENDING AVG.
$550 million
The company has intentionally delayed production on about 200 wells across the United States, mostly in the Wattenberg Field. Essentially, the company drilled the initial portions of the wells, but stopped short at “completion,” or their efforts to hydraulically fracture and produce oil and gas from those wells. Those wells will be ready for completion when necessary, and can represent a quick turnaround and suck up less capital spending when company officials do decide to bring them online. And though crude production in Weld County was up through July - with companies pulling out an average 2 million barrels a month more than last year - the last half of the year will likely show a dramatic production drop. The intentional production delay has resulted in about half the capital spending Anadarko had in the first quarter, when it spent $574 million in drilling the Wattenberg. That number fell to $282 million in the third quarter of this year, based on the company’s most recent operations report. Future spending will likely fall more, though company officials have not yet settled on a 2016 spending program. This year, the company reduced in half from last year its total capital spending to $2.7 billion, and Walker explained that is likely a number the company will stick with, allotting 40 percent of that what it calls “short-cycle” programs (the ones with most immediate returns), and a “large percentage” of that will
TEMPERING EXPECTATIONS go toward drilling in Weld and Texas. Darrell E. Hollek, executive vice president of U.S. onshore exploration and production said holding off on well completions may be a blessing in disguise. “There’s not nearly as much capital waiting on completion as you might otherwise expect,” Hollek told analysts. “One of big benefits people don’t recognize, if you look back at the savings on completions. To have completed these wells earlier when the cost structure was higher... we see benefit sin completing wells a year later, because it will push our costs down, and prove our economics on these wells.” While it delayed those wells, the company also has been perfecting its formula for well completions, one of the remaining areas where it can still find more cost-efficient ways to operate. Officials reported the company was able to reduce drilling times in the Wattenberg by 20 percent and its cost per foot by 15 percent from the previous quarter. Drilling costs sunk to $73 a foot this quarter from $86 per foot last quarter. Costs were at $142 per foot in 2014, the company reports. Overall, the operations report states Anadarko has been able to see a 30 percent reduction in its completion costs so far this year. Delaying completions, Hollek said, will give the company more flexibility next year. “If you look at ‘16 for sure, as we look to pull back capital, these will be efficient opportunities for us to maintain volume and spend less, so you can look at them as a huge lever for 2016,” Hollek said. The company also has been able to drill 14-16 wells per section, and expects it can get to 20-30 wells per section in the future. “We feel pretty good, we think there’s more to be recovered as we continue to get our well costs down,” Hollek said. “We think there’s an opportunity to increase that density, and we feel good that we’ll end up adding to that.”
Noble Energy reports $283 million loss on third quarter BY SHARON DUNN • SDUNN@ENERGYPIPELINE.COM
noble energy reported a third-quarter loss of $283 million, but officials stated drilling
and completion efficiencies in the field - especially in Weld County - will help move the company forward. The news of a loss is not surprising in today’s commodities markets, and especially since Weld County’s No. 1 producer, Anadarko Petroleum, posted a $2.2 billion loss on the quarter just the week prior. Noble is the second largest oil and gas driller in Weld County, drilling the Denver-Julesburg Basin, with a headquarters on the west end of Greeley with more than 500 employees. Company officials in November further shaved its workforce by 25 positions in Greeley and 45 in Denver. In total, the company cut 180 positions. Last April, the company cut 20 positions in Greeley, and 80 in Denver as well as a part of a 225-position cut. Noble operates across the globe but focuses its U.S. drilling in Colorado, Texas and Pennsylvania. In its earnings call, officials hinted at moving capital more toward highproducing areas of Colorado and Texas, with a reduction in capital spending on its East Coast assets, which produce primarily natural gas. “The plan going into next year is to focus on completion activity and we’re being pretty selective on how we manage (that),” said David Stover, Noble Energy’s chairman, president and CEO. “We’ll have to keep watching the market. This doesn’t feel like the gas prices to drill into. We’ll continue to watch how that changes.” For the year, however, Noble has already trimmed $100 million from its capital budgets across the board. Fourth-quarter capital is expected to be reduced further to $575 million to $675 million, less than half the company’s spending at the same time last year. Noble Energy doesn’t publicly break down spending allocations per asset, as other producers do. “As we look to next year, we’ll make sure we maintain our financial strength, allocate capital to projects with the greatest returns and value, and maintain our financial strength,” Stover said. “We’ll keep operational capacity such that as things do turn around, we’re well-positioned to take advantage of that quickly. Those are things we think about as we look at next year.” The company reported efficiency gains in drilling times, and on its recipe for producing a well, with a continued increase in production. In the DJ Basin in Colorado, the company reported sales volumes averaged a record 116,000 barrels of oil equivalent (crude, natural gas and natural gas liquids) per day in the third quarter, up 13 percent from the same time last year.†During the quarter, the company operated with four rigs, but has since dropped that to three, and has plans leave 40 wells uncompleted, or hydraulically fracked. Companies have increasingly chosen to not finish their well drilling until commodity prices returned to more favorable levels. When that time comes, they can finish the wells, but spend less, since half of the job has been done. The company plans to hold back on completing 50 wells in Texas, and 80 in the Marcellus in Pennsylvania, in addition to the 40 in Weld. December 2015 ENERGY PIPELINE 21
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Q - Can you explain how that dynamic is working globally?
QA &
with
BUD WEINSTEIN MAGUIRE ENERGY INSTITUTE
AN OIL & GAS CONVERSATION BY SHARON DUNN • SDUNN@ENERGYPIPELINE.COM
What’s going on in the global discussions and politics involving oil and gas? We went to Bud Weinstein, an associate director of the Maguire Energy Institute and an adjunct professor of business economics in the Cox School of Business at Southern Methodist University in Dallas. Weinstein has been a student of and an expert on global economics for decades. He sat down with Energy Pipeline magazine to discuss the current state of oil and gas in the United States and the globe:
QUESTION - Have you looked in your crystal ball for oil and gas recently? What did you see? WEINSTEIN - Crude prices: I think we’re looking at more of the same. There’s still a glut of about 2 million barrels a day on the world market. I don’t think we’re going to get into the export business, even though the House passed a bill, and the Senate will go along to repeal the export ban, but Obama said he’d veto it if it reached his desk. That could provide little relief to American producers. On one hand, there’s too much supply on the market, and so far OPEC and Russia have indicated no willingness to cut back on production. They’re increasing production. 24 ENERGY PIPELINE December 2015
On the other side of the coin, there’s weak demand. By that I mean, the growth in demand for oil around world has been sluggish, mainly because the global economy is not in good shape. The U.S. economy is doing OK, but third-quarter numbers weren’t so great, with a 1.5 percent growth rate. I think one of the reasons we’re seeing a slowdown in economic growth is because of contraction in the oil and gas industry. The media never writes about it. The fact is, energy production has become a much bigger share of the business economy over the last decade, and ... it pulled us out (of the recession), and now that sector is contracting. ... Now the economy going back down again.
BW - I like to argue, and data supports the fact, that energy is a much bigger share of economic activity than it was a decade ago. The downside is the multiplier effect on the negative. ... It’s one of the reasons the economy has been slower. Demand is so weak around the world. Europe is going into its third recession, growth is slowing in China, Brazil’s economy is falling apart, and Japan can’t get its mojo back. Go around the world and there is not a lot of economic growth. In fact, the world bank and IMF (International Monetary Fund) keep marking down their projections. If there was some way to stimulate the global economy, and it grew at a respectable pace, that would in turn increase demand. I don’t see that happening in 2016, which is why I think we’re looking at subdued prices certainly for the next year, like $45 to $50 (a barrel) and if you look at the futures market, they don’t think prices will go up any time soon. WTI (West Texas Intermediate) in November, said in 2020, five years from now, oil would be trading $60 a barrel. So the market thinks oil and natural gas prices will remain low. Q - Will that pull the country into another recession? BW - I don’t think the energy sector by itself will put us in recession. There’s a positive for the energy industry. The refining sector is doing well. The petrochemical industry was doing well at least until recently. ... We all consume energy, so cheaper energy is good, not only for households, but energy intensive manufacturers and the transportation industry. Diesel prices are down a third over the past year, so trucking is happy. Airlines are earning record profits, mainly because fuel prices don’t cost so much. All the airlines are reporting profits for the first time in years. ... It’s hurting the U.S. economy because we’re the world’s largest energy producer. On balance, is $45 a net plus for the economy? I’d say probably yes. What I mean is ... just thinking it through. Say you have 170 million households, and energy costs are down, so they’re paying less ... for power and home heating. For some energy-intensive manufacturers,
the costs of production are falling. Those are the positives. But the downside is there are 8 million people whose livelihoods who depend on what’s happening in the oil and gas industry. It’s not just Colorado and North Dakota and Texas. There are 32 states that produce commercial amounts of oil and gas. There are job losses in the oil patch, falling stock prices for companies, rising numbers of bankruptcies, more exposure to banks in the business of energy lending. ... If prices stay at $45-$50, we’ll see a greater pace of contraction, a lot of independents will bite the dust. The big guys can tough it out. Exxon’s profits weren’t down nearly as much as expected because they’re making money in refining. Smaller operators, even large independents who are just involved in exploration and production, not into pipelines, refining, distribution ... they’re hit hardest, particularly if they got into the business late and are highly leveraged. At $100, anyone can make money in the oil business. At $45, you have to be really smart. Everyone is getting more efficient, and production has been increasing. But it’s not a pleasant picture for the industry. Q - Will we see the end of independents, and smaller operators? BW - I don’t think so. There are hundreds if not thousands of drilling companies, and a limited number of oil field service companies. Then you have the majors, who weren’t even interested in shale until recently. Exxon is the only one that has substantial holdings in shale, because they bought XTO a couple years ago. For years, the majors weren’t interested in shale. They were more interested in deep-water drilling. That was the traditional mindset of the majors. They haven’t been that big into shale. It was the independents that perfected the technology and are responsible for the huge increase in U.S. oil production. Most don’t have the cash reserves or the credit lines to survive without substantial asset sales, or mergers, or in some cases bankruptcies. It varies from company to company.
Some will hold on. We’re already seeing a fair amount of mergers and acquisitions activity. The industry is in the process of restructuring itself. In the oilfield service business, we’ll be down to two major players because you’ve got Halliburton acquiring Baker Hughes, so No. 2 acquiring No. 3, and Schlumberger is acquiring Cameron International, which is No. 4. So you’ll have two oilfield services companies with almost a duopoly. Q - Given your history, how does this downturn look to you? BW - We had a pretty sharp downturn in the Great Recession in 2007-09. Prices were down in the $30s, but they didn’t stay there long. They rebounded quickly, when the economy started to pick up steam. What’s so different this time around, it’s not a question of a lack of demand, well that’s part of it, but the lower prices today are mainly a result of global oversupply, and a change in OPEC’s tactics. In the past, OPEC would counter a price slide by cutting production to maintain market share. Now OPEC, or really Saudi Arabia, they said, “Hey, we’re not responsible for the glut on the market, it’s the North Americans. Let the U.S. and Canada cut back their production because they’re responsible,” which is true. The problem is, OPEC can’t play that game too long because they’re losing money. Saudi Arabia can lift out of the ground at $8 a barrel, but they need $100 a barrel to balance their budget. They all need revenue to maintain social peace. There is a lot of dissension in OPEC, a lot of pressure being put on by the haves and have-nots. The rest of OPEC, Algeria, and Nigeria, and Yemen, Iran, Iraq, those countries are hemorrhaging economically at these prices, and there’s tremendous potential for social unrest. When the revenue source on which you depend is 90 percent of government funds, there are some observers who believe that at their next meeting, in the spring, OPEC may announce a small cut in quotas, particularly with North American production continuing to decline. That would be good for the market, but it wouldn’t stimulate a rally to get us back up to $70. But it would certainly, if nothing else, set a floor on prices and maybe even
boost prices. It’s so hard to predict, and OPEC has political agendas. Q - What do you think will be the game changer to jump-start the industry and the economy? BW - In terms of the fossil fuel industry, what’s really going to be needed is a new set of policies. This may be a pipe dream. If we had public policies that are designed to both to recognize we’re the world’s No. 1 energy producing country, and to encourage us to produce more of all forms, while at the same time encouraging competition among energy resources, we’d phase out some of the egregious subsidies to renewables, remove the (crude export) ban, expedite the permitting of LNG for exports. We’d approve the Keystone XL pipeline, we’d make it easier to essentially complete the infrastructure for both domestic and international markets. ... But as I said, the Obama administration doesn’t like fossil fuels. The coal industry is going away, partly because of the EPA, maybe more importantly because natural gas is so abundant and so cheap ... it’s replacing coal. Coal exports were rising until about a year ago, and now they’re falling, for couple of reasons. A strong dollar has made our coal exports more expensive, and second, the environmentalists are fighting coal exports. Interestingly, the Canadians are building new export terminals for coal. Compared to a lot of coal around the world, ours is pretty clean, but the enviros don’t want us exporting coal, because we’re
exporting pollution. It’s immoral to sell dirty fossil fuels around world, particularly to developing countries. My lament is that we’re an energy superpower but we don’t exercise the economic and political leverage that gives us. One perfect example, Russians annexed Crimea, and invade eastern Ukraine ... we say let’s get back at those Ruskies by selling oil and gas in Europe. You hear this mantra, but we haven’t made it any easier to do that. Q - Will policy change be as simple as getting a Republican president? BW - Of course not. Nothing is easy these days, regardless of which party is in power. What happened over the last 20 years, Congress has decided that rather than make policies, they’ll give regulatory agencies the authority to make policy. That’s why in the end, more policy is being made in lawsuits, because Congress, particularly in the environmental sphere, has decided it doesn’t want to be in the policy-making business. You just give the White House more executive power, the regulatory agencies more power, and Congress starts to complaining about regulatory over-reach. Q - What do you hope happens with the 2016 election? BW - Whoever is in the White House, I hope that individual is No. 1, able to work with Congress, and No. 2, get realistic and
sensible about an energy policy and try to come up with one. We don’t really have an energy policy. When you’re the world’s largest energy producing nation, you do have to have an energy policy. It doesn’t have to be very specific and you won’t do away with regulation. You just need to think about the strategic advantages we have because we’re No. 1. If you’re talking energy, let’s face it, the American public doesn’t care a hoot about energy or energy policy, as long as gas is below $3 a gallon. It’s true, the only time the public is concerned and politicians really focus on energy is when there’s a price spike and it gets above $3. In 2012, average prices were over $4, then the finger-pointing starts, it’s drill baby drill, nonsensical debates that last only as long as prices are high. That’s exactly what happened 2012. For three to four weeks in the campaign, Mitt Romney and Obama were talking energy. Romney had a good energy package. Obama never did. I don’t know that energy will be a big issue in 2016. What worries me ... everyone is getting used to $2 gas now. We’ll all get used to paying $2 for gas, then what will be the reaction when it goes to $3 again? It will be the same nonsense about greedy oil companies and drill baby drill. The public’s memory is very short, and politicians’ memories are even shorter. You get used to it, and then prices go up to what they were five years ago, and there’s a conspiracy going on.
December 2015 ENERGY PIPELINE 25
TECH TALK
CAN ENERGY IN PRODUCED WATER BE USED TO DESALINATE PRODUCED WATER? BY GARY BEERS • FOR ENERGY PIPELINE
in many rural arid areas, the generation of
produced water in oilfields would be a welcome new source of water - but the elevated salt content of produced water hinders agricultural and domestic uses. Petroleum-related organic chemicals can be economically removed but, currently, expensive additional treatment (i.e., reverse osmosis) is needed to remove the salts (desalination). The latter process is complex and requires access to large amounts of electricity from the grid. Consequently, salt-laden produced waters (a potential water resource) are wasted through disposal in injection wells.
WHAT IF WASTEWATER CAN PROVIDE ITS OWN ENERGY FOR TREATMENT? Scientists estimate wastewater contains about 10 times more energy than is required for treatment and that this locked-up energy is present in three forms: organic matter (19 percent), thermal heat (74 percent), and nutrients (7 percent) (Source: Beneficial Bioelectrochemical Systems for Energy, Water, and Biomass Production, J. Microbial & Biochemical Technology, 2013). Technological breakthroughs in applications of microbial fuel technology by scientist and engineers at universities in the United States and China have engineered bioprocesses that generate energy from organic matter in wastewater for use in self-treatment. Leading-edge research on using locked-up energy to self-treat produced water is going on in Colorado. Dr. Z. J. Ren and co-researchers (University of Colorado’s Center for Sustainable Infrastructure Systems) have developed microbial desalination
26 ENERGY PIPELINE December 2015
cells (MDC) to fill the need for self-driven, energyefficient, modular, and mobile water-treatment systems for produced waters in oilfields. This unique, stand-alone process generates, rather than consumes, energy while removing hydrocarbons, salts, and metals from produced waters.
HOW DOES A MICROBIAL DESALINATION CELL (MDC) WORK ? A typical MDC consists of three chambers (see graphic, source: Development of Bioelectrochemical Systems to Promote Sustainable Agriculture, Agriculture, 2015) that contains the following chemical processes (source: Microbial Desalination Fuel Cells: Assessment of Technology Status and Potential Benefit for Reclamation, Bureau of Reclamation, Denver, 2014 ). In the anode chamber, naturally occurring bacteria survive and grow on the anode as a result of their decomposing organic matter present in the produced water. Through a bio-electrochemical reaction, the bacteria release protons into the water. The protons cannot move out of the chamber because they cannot diffuse through the anion exchange membrane (AEM).
For over 50 years, GARY BEERS, has worked in numerous fields of environmental science as a consultant, regulator and educator. This career included senior management position with major consulting, nonprofit and public organizations. He has founded several successful firms to capture emerging resource management markets. One of his latest ventures, EnviroScienceINFO, provides content for public media.
In the cathode chamber, a catalyst serves to remove protons from the fresh water supply, as oxygen is reduced on the cathode. The desalination chamber holds the produced water. To maintain the change balance in the anode chamber, anions (i.e., chloride) move out through the AEM to the anode chamber. Concurrently, to maintain balance in the cathode chamber, cations (i.e., sodium) move out through the cation exchange membrane (CEM) to the cathode chamber. Produced water leaving the desalination chamber has reduced levels of salts. The net result is the production of electricity as electrons flow between the two electrodes. The researchers at the University of Colorado conducted experiments on treatability of produced water from oil wells in western Colorado. The chemical profile of the produced water was as follows: total dissolved solids (15,870 mg/l), chemical oxygen demand (800 to 1,100 mg/l), and pH (7.4 to 7.8). After the treatment cycle, which lasted four hours, the treated produced
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water leaving the MDC contained 5,270 mg/l of total dissolved solids (i.e, 65 percent removal). Some of the electricity generated by the MDC can be harvested for other uses. The details of this project are available in a recent paper (Microbial Capacitive Desalination for Integrated Organic Matter and Salt Removal and Energy Production from Unconventional Natural Gas Produced Water. Environmental Science Water Research & Technology, 2015)
HOW SOON WILL MDC-BASED TREATMENT UNITS BE COMMERCIALLY AVAILABLE ? While basic technology for MDC-based treatment units is proven at the laboratory scale, the commercial development is low on the technical readiness scale - perhaps where solar power development was in the 1990s. In 2013, a start-up company (BioElectric, Inc.) was founded to turn the MDC technology
into a commercial reality for treating produced water. Certainly, the scale-up of MDC technology to commercialization requires a high capital investment. The key technical barriers to commercialization of this innovative technology include needed production of large-scale cathodes with a cost of less than $90 per square yard, improvement in adsorptive materials, more efficient module configurations, understanding bacterial population dynamics, pH control and electrode stability. In the coming years, the first commercial application of MDC-based treatment units may be realized as a pretreatment step for conventional desalination (i.e., reverse osmosis) to render produced water suitable for agricultural or domestic uses. This pretreatment step would reduce the salt content and provide energy for the downstream desalination process. Thus, the expensive cost of convention desalination would be significantly decreased and produced water would become feasible as a new water resource.
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11/9/2015 3:49:15 PM
BY SHARON DUNN • SDUNN@ENERGYPIPELINE
ANADARKO UNVEILS ITS CENTRAL OIL STABILIZATION FACILITY, WHICH PROMISES TO REDUCE ITS FOOTPRINT, EMISSIONS Anadarko Petroleum has just opened a monstrous facility in the Wattenberg Field, its latest and greatest weapon in the stalwart war against fugitive emissions and reducing the company’s footprint. The global oil and gas company has spent the last two years building this latest technological advance that will take in the company’s oil production from throughout its holdings in the Wattenberg Field, and feed it to the pipelines to trading hubs through a network of unseen pipes and pumps and tanks. Plopped on top of 67 acres in south-central Weld County, the massive site straddles Weld County roads 49 and 30, just 12 miles east of Platteville, among a landscape dotted with random industry equipment and well sites along a country road.The massive site straddles Weld County roads 49 and 30, just 12 miles east of Platteville, among a landscape dotted with random industry equipment and well sites along a country road. The Central Oil Stabilization Facility is kind of tucked out of site, as it sits back from the road adjacent to the White Cliffs pipeline. Walking into the gates, there’s a seemingly never-ending network of steel and industrial machinery that uses a combination of temperature and pressure to refine oil to its best condition before it is shipped on
30 ENERGY PIPELINE December 2015
CLOCKWISE FROM TOP PHOTO: Contractors work to install values on inlet surge tanks at Anadarko’s Centralized Oil Stabilization Facility in southcentral Weld County. The tanks are the first process crude oil goes through when it enters the faclity from being piped in from the wellhead. There it is preheated; and water and gas are separated. The tanks also act as a buffer for any surges in the system. Workers weld equipment near the heaters, which provide the main heat for the oil heating towers in the background of Anadarko’s Centralized Oil Stabilization Facility in southcentral Weld County. The facility was due to open the first week of December. Anadarko officials tour an existing well pad that will go by way of the dinosaur very soon. The company’s new Centralized Oil Stabilization Facility will eliminate the need for vapor recovery units, such as these shown here. Once the facility is commissioned, oil from a multi-well pad such as this will be piped directly to the facility, rather than stored here in tanks that emit gas.
the White Cliffs pipeline or the Tampa Rail facility along Interstate 76 down to Cushing, Okla., the West’s oil trading hub. Anadarko officials unveiled the new facility in a private tour in October, showing off the facility that they say will take thousands of trucks off the road, reduce well-site emissions, take equipment off the landscape and reduce the company’s growing footprint. The facility, with a complex contortion of pipes, massive heating towers, more tanks, more pipes, and one massive 227,250-barrel storage tank lined by an impenetrable synthetic liner shielding the earth below it from any potential spills, is a sight to behold. The noise of systems running and humming is palpable. Workers can be spotted welding throughout the plant in the hurried pace to open. Trucks with the word “Safety” plastered on each side seem to stroll along a makeshift road surrounding the facility. As many as 200 contractors have helped put this conglomeration together. But it will take less than a dozen to run it every day. It stands as a symbol of sorts, representing some of Anadarko’s greatest technological gains to date as it takes the place of the separation equipment that dots the landscape at individual well pads, as well as individual pads’ vapor recovery units that chew up fugitive emissions on site. In three short years, the company has moved from the traditional one well per well pad to several wells per pad with
several storage tanks, to tankless facilities. The Centralized Oil Stabilization Facility is the next generation in that evolution. As the company moves forward, it will operate its well pads with no storage tanks on site, instead piping crude directly from the wellhead to the stabilization facility, never once being given a chance to allow fugitive methane emissions that naturally emanate from the bubbling crude to hit the atmosphere. “I’ve never seen on the production side of our operations a facility like this,” said Ed Schicktanz, a health, safety and environment representative for Anadarko. “I’ve been doing this 34 years. You see the tanks like (those at the COSF) in refineries. I’ve never seen a facility like this in the upstream oil and gas business. ... This is unique in the (DJ Basin) and it would be unique anywhere.”
MOVING BEYOND LEGACY
Company officials dreamed up this industrial complex two years ago when it made a 100,000-acre trade with Noble Energy, which consolidated each companies’ Weld County operations into a north-south divide rather than the patchwork quilt it had been. Anadarko took the southwestern portion of Weld County, while Noble took the northeast.
December 2015 ENERGY PIPELINE 31
This heat-exchange tower is one of five at the Centralized Oil Stabilization Facility, which will be used to heat oil in a circular pattern providing a heat exchange between incoming and outgoing oil that will reduce the need for extra heating, and thus reduce energy needs at the facility.
COMPANY OFFICIALS DREAMED UP THIS INDUSTRIAL COMPLEX TWO YEARS AGO WHEN IT MADE A 100,000-ACRE TRADE WITH NOBLE ENERGY “When we looked at our premiere land position after the Noble trade, we had a core acreage position that was very consolidated and it was in our benefit to think about the long term. How do we move our oil product to market as efficiently, effectively and safely as we can?” said Craig Walters, vice president of operations for Anadarko from his Denver office. Anadarko has been slowly building the plant since February 2014, and it is scheduled to be commissioned the first week of December. To date, in addition to the sprawling network of steel and tanks and towers at the facility, the company also has build 200 miles of gathering pipe to move oil from wellheads to the facility. Company officials intend to keep its existing infrastructure in the field. That means existing well pads will stay as they are, and some legacy wells will continue to have storage tanks on site.
32 ENERGY PIPELINE December 2015
The economics of these low-producing wells wouldn’t justify the cost of building infrastructure to connect to the oil stabilization facility, officials said. “Everything built in the last two years, will come here,” said Joe Straley, a production supervisor for Anadarko during the facility tour. “About 90 percent of our total production will come through here.” The company produces roughly 100,000 barrels of oil per day now, and officials expect that number to stay flat in 2016. The Central Oil Stabilization Facility can handle 125,000 barrels of oil per day. “We’re not making quite 125,000 right now,” Straley said. “Part of it is the economy. With oil prices dropping, we’re in a downturn, so we elected to invest our money in other areas in Colorado. We’re not drilling wells with the level of activity we were a year ago.” During the two-year construction phase of the facility and building up its pipeline network, Anadarko began switching its program from oil storage tanks on each site to tankless facilities on newer facilities built. There, the oil was separated at the wellhead, and could be moved off-site into the oil gathering pipelines. The Central Oil Stabilization Facility goes a step beyond, by taking the separation function off the well sites. The oil is separated from the natural gas and natural gas liquids, both of which are piped off-site to different existing processing facilities, designed specifically for those hydrocarbons.
CONTINUED INNOVATION
While this will be the latest in innovations for the company, it certainly won’t be the last. The company is using this facility as a testing ground, if you will, for new products, as well as improving ways to reduce its own energy use by recycling its energy. As an example, the on-site stabilization towers heat the incoming oil to a specific temperature. While doing so it runs all oil in a circular pattern, so the hot oil warms the cooler oil without extra energy use. As it stands, the facility needs 5 megawatts of electricity to operate. “We use a lot of heat exchange,” said facility superintendent Sean Brown. “As oil is coming in, it’s preheated with the oil going out. ... It eliminates the need for extra heating.” The facility has five towers, six compressors and five inlet surge vessels, which heat the crude coming in and separate the water and gas. Each vessel can hold 200 barrels apiece. Its massive storage tank on the northeast side of the plant is capable of holding two to three days worth of production in the field, giving the company flexibility in case something happens along the pipeline that would prevent a smooth flow to Cushing. The tank itself is lined with an impenetrable liner, which Anadarko officials are testing in this field. “That two days of rain we (recently) got, none of it soaked in,”
said Dale Fiorini, production superintendent at Anadarko. The tank itself sits in a bowl, large enough to hold its contents. “This place was a swimming pool.” The liner replaces the clay liners that Anadarko typically uses beneath storage tanks. “This is really new for us to have a surface liner that attaches to the tanks,” Schicktanz explained. “This is big enough to hold close to a 25-year rain. When something happens, it’s easily repaired and we’re providing the same level of environmental control. It’s flexible enough to you can drive trucks on it. I’m excited we’re trying this out on such a large scale. “This is the first surface-use trial. It’s a pretty big test platform,” Schicktanz said. “It enables us to clean up spills immediately, with no ground contamination.”
REDUCING ITS FOOTPRINT
This new mega-project came just in time in an environment in which regulations have been getting tougher on the industry amid a clamor of public concerns about the industry’s effects on their surroundings. Just a few months after construction started, the Colorado Oil and Gas Conservation Commission implemented new, stricter emissions rules. Going forward, companies would be required to capture 95 percent of emissions from their equipment in the field, with tighter requirements for regular emission detection via infrared cameras and regular repairs of leaking equipment. The paperwork involved in documenting such efforts had many company leaders envisioning foot-tall stacks of paperwork atop their desks in a regulation nightmare. Reducing emissions from sites will take much of that regulator burden off of Aandarko. “With oil (storage) tanks on location, the oil itself wants to give off natural gas, so you have vapor recovery units sucking on that all the time to recover that gas and put it into the pipeline,” Walters explained. “With this facility, we’re able to eliminate that infrastructure.” That is one of the biggest pluses to the centralization facility, Walters said. “The emission is a big story around the Centralized Oil Stabilization Facility,” Walters said. “To eliminate tankage off individual well sites and additional equipment, we’ve reduced the amount of potential fugitive emissions off those locations. This is a huge win in my eyes, from an environmental and emissions standpoint. “We like to put every molecule of oil an gas through the sales meter and this facility allows us the capacity to do that,” he said. Piping the product directly from the well to the centralized facility will not only eliminate the vapor recovery units, and the potential for failure that always comes with industrial equipment, but it will take hundreds of trucks off the road. The heavy trucks associated with the oil and gas fields, contribute to the volatile organic compounds in the air, which help cause smog. “When you talk about our gross oil production, and how many trucks it takes to pick up that oil, that’s about 600 18-wheelers a day,” Walters said.
As part of the environmental side of the company, Shicktanz applauds this next generation of footprint reductions. “We’ve been forced to innovate, times have changed and we want to be better operators and we want to maintain our (social) license to operate,” Shicktanz said, “and this is the next step in being able to do that.”
CONTROLLING COSTS
The facility also is a bonus for the company’s shrinking capital program. The company revealed in its third-quarter earnings reports that it had shrunk new capital spending in half in the Wattenberg this year, with numbers expected to also go down in the fourth quarter. The money for the central facility had already been spent. Officials will not reveal the cost of the plant, but they do know that less equipment in the field means less overhead costs as they move forward with their drilling program. “I’d say that we’ve invested a significant amount of dollars in both the COSF as well as the oil gathering system,” Walters said. “Those investments will pay for themselves over the long run in relation to capital savings we’ll have on individual well sites, with the differentials we see on production. If you have to put it on a truck, there’s a lot more labor and cost involved with that than putting in on a fixed asset to get it on the pipeline.” Walters said there is room on site to add another storage tank and even expand existing operations, but that would only come with future growth. For now, production will stay flat, he said. “On the near term, in the next three to four years, we have enough capacity to easily expand the existing COSF to handle those capacity needs.”
Sean Brown, the facility superintendent at Anadarko’s Centralized Oil Stabilization Facility, overlooks the day-to-day construction of the facility about a month before it is due to be commissioned. Brown, originally from Guyana, has worked with Anadarko for about eight years.
December 2015 ENERGY PIPELINE 33
BY DAN LARSON â&#x20AC;˘ FOR ENERGY PIPELINE
AVOIDING THE
MOUSE TRAP UNC ALUM GUIDES SYNERGY RESOURCES THROUGH INDUSTRY DOWNTURN
ABOVE: Ed Holloway, co-CEO of Synergy Resources, has navigated his company through the downturn by beefing up assets and his team. After 35 years in the industry, Holloway has vowed to never let a downturn dictate company growth. Photos by Dan Larson, for Energy Pipeline.
34 ENERGY PIPELINE December 2015
Ed Holloway smiles when he refers to the predicament some companies now find themselves in as the oil and natural gas industry wades through the slow-moving waters of a persistent downturn. “i call it the mouse trap,” says Holloway, co-chief executive at Synergy Resources, based in Platteville. “When prices are high, they lever up and drill as many wells as they can and use new cash to stay ahead.” As prices fell below $50 per barrel this year and stayed there, those companies with debt-laden balance sheets are unable to drill the new wells needed to generate enough cash to repay their creditors. “That’s when the mouse trap gets them,” Holloway says as he makes a closing gesture with his hand. The ups and downs of the oil and gas industry, new rules companies must navigate, finding a balance between competing interests and the importance of seeing the other person’s point-of-view were among the topics Holloway, an alumni of University of Northern Colorado in Greeley, discussed in an interview in early November. “This is the fourth downturn I’ve seen,” Holloway says. “I learn something new each time around.” The 35-year veteran of the oil and gas industry says he
learned early in his career how quickly a company can go from a growing business to one that is trapped by debt. Borrowing to develop new wells in the early 1980s, Holloway’s first company got caught mid-decade in the price drop that hit the entire industry hard. “When the value of your main asset is cut in half, you can’t grow and generate enough cash to repay your loans. I vowed not get into that situation again, and I haven’t,” he says. With a management team that boasts many decades of combined experience in the Denver-Julesberg Basin, Synergy has seen three years of rapid growth in reserves and production. And behind a mantra of cash-funded growth, the company is positioned to ride out the downturn in good shape, Holloway says. Synergy plans to drill 36 wells over the next fiscal year, Holloway notes. Over the past six months, the company beefed up its management team, added 15 people to its staff and moved its headquarters to the Denver Energy Center in downtown Denver. “Our company profile has changed,” Holloway observes. “As a public company, we have to create value and in the current market, low-debt growth is how we will get there.” The company took a significant step forward in September when it acquired production and acreage from K.P. Kauffman Co. in a cash and stock deal worth $78 million. Holloway says he sees the acquisition as part of an overall consolidation in the Wattenberg Field that will play out over the next few years. Synergy Resources Corp. describes itself to the financial world as “following a balanced risk strategy” that invests in proven low-risk projects, adds reserves with high potential and is the operator of most of the wells it holds to better control expenses, timing and selection of which wells to develop. It reported a market capitalization of $1.1 billion as of Aug. 31, the end of the company’s fiscal year.
CHANGING LANDSCAPE When Holloway and business partner, William Scaff, agreed to take what at the time was a shell company and turn it into a public oil and gas operator, they turned to friends and acquaintances in Greeley to help jump-start the business. Between an initial public offering and private investors, Holloway says they “raised about $2 million. Seven years later, we are worth many times that and have a solid portfolio of institutional investors, Wall Street and folks from around here.” The past seven years has also seen a tremendous change in how oil and gas companies operate in a December 2015 ENERGY PIPELINE 35
LEFT: Multiple storage tanks on a Synergy well pad show how the industry has grown in the last few years, reducing environmental footprints, by drilling mulitple wells from one pad site. BELOW: A Synergy Resources well site in late October.
“The hard-core opposition plays on fear because it is easier to get folks riled up with talk of industrial operations, air pollution, and flaming faucets than by the facts.” ED HOLLOWAY, co-CEO, Synergy Resources
rapidly growing suburban landscape. One of the top shale plays in the U.S., the Niobrara has ushered in a surge in northern Colorado development unlike its predecessors. Where single oil, gas and liquids production wells dotted wide-open corn fields bounded by unpaved roads, now multiwell pads feature a dozen wells or more and compete for surface acreage with newly platted subdivisions. “Horizontal drilling has changed everything,” Holloway says. “We can reduce the land we need to produce more oil than ever. However, the value of that land just keeps going up.”
FIGHTING THE FEAR Like other companies operating in the Wattenberg, Synergy works with communities impacted by new well development. Holloway is often personally involved in discussions with community groups that take an interest in a new development. If not addressed, that interest can morph into highly visible opposition. 36 ENERGY PIPELINE December 2015
“So much of what people think of the industry is based on fear,” Holloway notes. “The hard-core opposition plays on fear because it is easier to get folks riled up with talk of industrial operations, air pollution, and flaming faucets than by the facts.” Holloway says he finds that taking the time to lay out what a new project will look like can go a long way in easing those fears. Still, companies must respect the interests of neighbors when planning a new well site. “You will never get anywhere if you don’t try to see the issue from the other side,” he says. “The important part is to lay out the whole project from the beginning and go from there.” For example, as new horizontal wells tap the same or adjacent underground formations, older vertical wells may be affected. In such cases, the older well is safely plugged and taken off the books. The site can then be reclaimed and made available for agriculture or other use. “The business has changed,” Holloway says. “I started as a small operator from a small town. We are not a small company anymore, but it is important we keep those values in mind.” As he leads his company through another downturn, Holloway is proof there is a place for small town values in a big business.
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This is a view of the Residue Compression Building in the center, which contains 2 Solar T-70 Gas Turbine Compressor Units at DCP Midsream’s Lucerne II gas processign facility northeast of Greeley. A waste heat Recovery Unit sits at the front of the building. The plant uses waste heat from the turbines to provide most of the process heating for the plant and is supplemented by the heater located to the left in the picture.
IMPECCABLE TIMING
DCP Midstream opens Lucerne II plant just in time to reduce line pressures BY SHARON DUNN • SDUNN@ENERGYPIPELINE.COM
for many, it couldn’t have happened
fast enough. Oil and gas exploration company executives have lamented high line pressures in the Wattenberg Field and surrounding it for a couple of years. The higher the pressure, the harder it is to get the oil and gas out of the well, and that makes for some unhappy producers. DCP Midstream’s O’Connor Plant, which opened in 2013 south of Kersey, was supposed to be the relief valve, allowing for an additional 110 million cubic feet of natural gas processing capacity per day in an increasingly high-volume field. The plant underwent an almost immediate expansion in 2014 to allow for another 50 million cubic feet per day processing capacity. It still didn’t completely alleviate the high volumes producers were experiencing in the field, but Lucerne II already was being built about four miles northeast of Greeley. The $250 million gas processing plant came online in June. “I think you’d hear from a lot of 38 ENERGY PIPELINE December 2015
THE PLANT OPENING GAVE DCP MIDSTREAM THE CAPACITY TO PROCESS 800 MILLION CUBIC FEET OF NATURAL GAS PER DAY OUT OF THE WATTENBERG FIELD (executives) ... this plant from their perspective was possibly a little late,” said Bill Johnson, vice president, North and Permian Business Unit Operations of DCP Midstream. “Our perspective was it was timed right. It’s a very large investment, so we have to know the gas will be there and we can recoup some of that investment.” The plant opening gave DCP Midstream the capacity to process 800 million cubic feet
of natural gas per day out of the Wattenberg Field, and more than 55,000 barrels a day capacity to process natural gas liquids. The plant brought the company’s assets to a total of nine processing plants in the Wattenberg, representing an 80 percent increase in the company’s gathering and processing capacity in the last two years. For many producers, it was an agonizing wait. In a Noble Energy third-quarter earnings release, officials noted the importance of the plant’s opening: “Accordingly, line pressures in the northern part of the field, particularly in and around the company’s Wells Ranch area, have been reduced by up to 100 psi,” the earnings release stated. “... As a result of the reduction in field line pressures, the company’s legacy vertical well production averaged nearly 25,000 barrels of oil equivalent per day in the third quarter, which is a high point over the last year and an increase of more than 5,000 barrels of oil equivalent per day versus pre-Lucerne-2 rates,” the release stated.
The anticipation built as company executives discussed the obstacles in their field in the last year. Scot Woodall, CEO and COO of Bill Barrett Corp., said in a second quarter 2015 earnings call, said the Lucerne II plant quickly provided a significant development in his company’s production. “Definitely Lucerne II is going to help us. Almost all of our gas flows toward Lucerne II, and since it has had some pretty good run times here of recently, I think we are observing a plus-or-minus 100 psi drop in wellhead pressures because of Lucerne II,” Woodall said in an earnings call. DCP Midstream is a must-run business, officials explain, but they don’t build processing plants for the sake of building them. They have to have some reliability that the demand is there, and that it will stay there, to justify the expense and time. The gas processing plants take two years to build. The plants essentially filter the gas and clean it up to certain levels, and they’re about to come up on a busy season with an expected cold winter. “The gas that comes out of the ground isn’t suitable to be sent straight into houses to be burned as natural gas,” Johnson explained. “It has water, contaminants, other things. We basically take the liquids out, the water out, process it so it meets a standard so in everyone’s house, it burns the same. If we just took what came out of the ground, some would burn hot, some wouldn’t burn well at all, and it would be a mess. We clean it up and standardize it and sell it.” Most of the gas that comes out of the ground in Weld County is consumed locally, but it does get shipped to the greater markets. Demand continues to grow, even in a downturn. That demand has allowed DCP Midstream to broaden its reach, officials say, that will keep flows moving, even in the case of system hiccups. The company has strategically located its plants in and around Greeley, all connected, and at the ready. “One of the cool things about our system and the service we offer, you’ll see all bigger, newer plants are connected by these lines, which allows us to move gas from gathering and process it at almost any one of those plants,” Johnson said. “It’s a reliability and sureness of service to our customers that we have everything interconnected, so if we have a little problem, or have to take plants down for maintenance, we have the ability to move gas around the system to other pants, which allows us to continue to process gas for the customers.”
A map of DCP’s service area a year ago showed a growing issue with high line pressures, which prohibit well production. The network of pipe was green, or free flowing, in the core of the Wattenberg. But on the fringes in the west, many pipes were in the yellow, orange and reds, showing higher pressures, depicting more of an urgency to reduce the pressures. The maps that show the system before and after Lucerne II plant opening are eye-opening, and a breath of fresh air for many drillers in the Wattenberg. “Producers were getting a little frustrated with us for not having lower pressures,” Johnson said. The additional processing capacity has reduced line pressures to the point that operators could bring online even old legacy wells, said Lucerne II Plant Manager Tauna Rignall. “Some of our customers have been able to restore some of their old wells,” she said. While the company contemplates a 10th plant, it’s also in the process of building a pipeline that will help producers on the fringes. The company is working on building a 25-mile, 24-inch pipe called the Grand Parkway to allow companies in the field to connect, and ship their gas to processing plants that are further way from them, rather than have to wait on the production of a whole new plant. The $57 million project should be on line in the first part of 2016. That’s advantageous in areas where oil and gas facilities increasingly are moving into urban areas. DCP uses compressor stations to compress producers’ gas for easier/quicker transport. The Grand Parkway pipeline will connected those existing compressor stations, so projects far away from compression can still connect and move gas.
TAUNA RIGNALL Lucerne II plant manager DCP Midstream
BILL JOHNSON Vice president, North and Permian Business Unit Operations DCP Midstream
This map shows a pipeline network that connects to DCP Midstream’s several plants in the Wattenberg Field. December 2015 ENERGY PIPELINE 39
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TOP PHOTO: This is the supplemental hot oil heater and the regen gas heater at DCP Midstream’s Lucerne II Plant northeast of Greeley. The hot oil heater used for any supplemental hot oil heating for process heat and the residue gas heater heats residue gas to regenerate the mol sieve beds. PHOTO ABOVE: This is a view of the amine building in the background, which houses amine circulation pumps, the lean/rich exchanger and various filters at DCP Midstream’s Lucerne II plant northeast of Greeley. The foreground air cooler is the expander/ compressor aftercooler, which the residue gas flows through on the way to the residue compression.
“In the past, sometimes, we’d set some compression and customers would decide, ‘I don’t want to drill in that area, I want to drill in this area,’ Then we’re sort of chasing them around with compression. When we have this big pipe out there, we can connect into them wherever they are and don’t have to set compression in any given area.” “It makes it less important for the compressors to be set in the exactly right local area,” Johnson said. Even today, officials contemplate a potential 10th processing plant in the Wattenberg Field - a permit to build already is on the books. The big question will be demand. Certainly, this recently slowdown will be a big player in that decision. DCP earlier this year cut its ranks by 20 percent. “We have an idea out there and a permit filed to build a Mountain View plant, but you can see we don’t have a date,” Johnson said. “It’s really based on the needs of our customers and their timelines. We kind of stand ready to be able to build that plant, permitted and it will depend on the activity in the basin and the needs of the customers.” 40 ENERGY PIPELINE December 2015
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News Briefs Colorado coal production continues to drop as mines slow GRAND JUNCTION - Coal production in Colorado has continued to decline since last year’s record low, with only 13.9 million tons produced through August in 2015. The Grand Junction Daily Sentinel reported that in August 2014 Colorado mines had already produced 15.5 million tons. Production totaled nearly 40 million tons in 2004 and just under 23 million tons last year. Officials attribute the drop in production to mining cutbacks at Peabody Energy’s Twentymile Mine in Routt County and at Bowie Resource Partners’ Bowie No. 2 Mine in Delta County. According to the Colorado Division of Reclamation, Mining and Safety, Twentymile production fell to 2.5 million tons through August, from 4.9 million for the same period last year. The Bowie mine produced about 1.4 million tons, down from 1.8 million. Twentymile employs about 300 miners, according to state data. It employed nearly 390 at the end of 2013. Peabody Energy did not return requests for comment. In September, Bowie announced plans to lay off nearly half of its staff, leaving about 100 people at the mine. “It’s a sad commentary if the day arises that these self-reliant communities would have to rely on assistance from the very entity, government, responsible for those job losses and production declines in the first place,” said Stuart Sanderson, president of the Colorado Mining Association. The federal government recently awarded recent grants of $50,000 to Moffat County and some $1.2 million to the Montrose-based Region 10 League of Economics Assistance and Planning to help diversify the area’s economy. - Associated Press
PDC’s Gysle Shellum to retire in 2016 PDC Energy, Inc.’s Gysle Shellum, chief financial officer, will retire from the company effective June 30, 2016. Shellum joined the company in 2008 and has served as CFO since that time. He will continue to serve as CFO until the appointment of his successor, and will assist the company with the transition and other matters. “PDC has had a remarkable run since I arrived in 2008. I am privileged to be a part of one of the top teams in the industry and I will leave the Company in the best of hands next year. I am looking forward to taking a step back from day to day management and enjoying more time to pursue less demanding interests. I know I will miss my PDC family after I retire, however I will remain a loyal shareholder and participate in what I know will prove to be a very bright future for the Company,” said Shellum in a news release. Bart Brookman, the company’s chief executive officer, stated in the release, “Gysle has been a key part of the PDC team leading the Company to significant growth in cash flow and production throughout his tenure, and has played an integral role in helping the Company maintain an incredibly strong balance sheet. His deep knowledge of the operational, financial and accounting aspects of our industry has been enormously valuable to the company over the years.” - Staff Reports
MAKING HOLE A look back at the origins of oil and gas BY BRUCE WELLS • AMERICAN OIL & GAS HISTORICAL SOCIETY
Exploring U.S. offshore history the history of america’s offshore petroleum
industry might be traced to an 1869 offshore drilling rig patent by a New York engineer. Thomas Rowland, whose Continental Iron Works had helped construct the USS Monitor during the Civil War, patented a “submarine drilling apparatus” that could to drill in up to 50 feet of water. Although Rowland’s small, fixed platform was designed to operate in shallow water, its anchored, four-legged tower resembled today’s offshore giants. His patent was awarded just 10 years after Edwin Drake made the first U.S. commercial oil discovery in Pennsylvania. “My invention consists first, in novel construction of drill frame, or stand, or, as it may be termed, working-platform, by providing or forming it with telescopic legs made up of tubes and plungers,” Rowland noted. Although Rowland’s offshore rig was never constructed, his company became an industry leader in oil storage tank design and construction. As early as 1891, the first submerged oil wells on a lake were drilled from platforms built on wooden piles in Grand Lake St. Marys in Ohio. Wells also produced oil and natural gas from similar platforms built on Caddo Lake, Louisiana, in 1911. The first offshore wells in salt water were drilled in 1896 from piers over the Pacific Ocean. After exploration companies had pursued California’s Summerland oilfield to the beach, Henry Williams built a 300-foot pier and mounted a standard cable-tool rig on it.
44 ENERGY PIPELINE December 2015
By 1897, Williams’ first offshore well was producing oil that extended under the Santa Barbara Channel. Soon 22 companies joined in, constructing 14 more piers and drilling 400 wells in the next five years. In the Gulf of Mexico, Pure Oil Company and Superior Oil Company in 1938 built a freestanding drilling platform. They hired Brown &amp; Root Marine Operators to build a 320foot by 180-foot wooden deck in 14-feet of water about a mile offshore from Creole, Louisiana. But the earliest true offshore well - completely out of sight from land - was not drilled until after World Ward II. It began with the search for a salt dome. “It may be tentatively assumed that the Gulf of Mexico is a potential source of saltdome oil,” geologist Orval Lester Brace had reported in 1941. “Whether or not it will ever be economically feasible to explore these waters for the domes that must exist is a question for the future to answer.”
BRUCE WELLS, is the founder of American Oil and Gas Historical Society, a 501c3 nonprofit organization dedicated to preserving the history of oil and gas. He is a former energy reporter and editor who lives in Washington, D.C.
Although it will never be constructed, Thomas Rowland’s offshore platform with its four telescoping legs was an 1869 technological marvel.
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Sales: John, Mark, Kim, Terry, Todd & Sean This Kerr-McGee drilling platform, known as Kermac Rig No. 16, was the first offshore rig in the Gulf of Mexico that was out of sight of land. Photo courtesy New Orleans Times-Picayune.
Kerr-McGee answered the salt dome question in 1947 with an experimental offshore rig, Kermac No. 16. Dean McGee of Oklahoma-based Kerr-McGee Oil Industries partnered with Phillips Petroleum and Stanolind Oil &amp; Gas Company to secure leases for exploratory wells in the Gulf of Mexico. They hired Brown &amp; Root to build a freestanding platform 10 miles out to sea. “We decided to explore the areas where the really potential prolific production might be - salt domes - the good ones on land were gone, but we could move out in the shallow water and, in effect, get into a virgin area where we could find the real class-one type salt dome prospect,” McGee said. Vessels were needed to provide supplies, equipment, and crew quarters for the drilling site, 43 miles southwest of Morgan City, Louisiana. The gradually sloping Gulf of Mexico reached only about 18 feet deep at the drilling site. The Kermac No. 16 well stood almost 10 miles at sea. Sixteen 24-inch pilings were sunk 104 feet into the ocean floor to secure a 2,700 square foot wooden deck. The wildcat well was spudded in September 1947. Kerr-McGee had invested $450,000 in the project when the biggest hurricane of the season arrived within a week carrying winds of 140 mph. Although the platform was evacuated, damage was minimal and drilling promptly resumed. On November 14, 1947, the Kermac No. 16 well came in at 960 barrels per day. “Spectacular Gulf of Mexico Discovery. Possible 100-Million Barrel Field - 10 Miles at Sea,” proclaimed one trade journal. The historic Kermac No.16 alone produced 1.4 million barrels of oil and 307 million cubic feet of natural gas before being shut down in 1984.
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“Making Hole” is a term for drilling coined long before oil or natural gas were anything more than flammable curiosities. Read more petroleum history at the American Oil & Gas Historical Society’s website, www.aoghs.org.
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DATA CENTER
The oil and gas industry is a large part of Coloradoâ&#x20AC;&#x2122;s economy. Below, find statistics on energy pricing, drilling production, well permits, spills and rigs.
2015 DRILLING PERMITS COUNTY
RIG COUNT BY STATE
NO. (% OF STATE TOTAL)
Weld..........................................................................................1,555 (61.4%) Garfield......................................................................479 (20%) Rio Blanco..........................................104 (4.4%)
State Nov. 6 Oct. Avg. Colorado 33 30 Louisiana 70 69 Oklahoma 83 90 North Dakota 63 63 Texas 340 349 California 12 14 Alaska 13 12 Ohio 20 20 Pennsylvania 28 29 Wyoming 24 25 Source: Baker Hughes Rig Count.
Sept. Avg. 33 72 106 69 367 14 13 18 34 24
Aug. Avg 37 77 105 71 385 13 12 19 37 24
State....................................................2,511 Source: Colorado Oil and Gas Conservation Commission as of Nov. 4.
SPILL ANALYSIS YEAR
SPILLS
2013 624 2014 777 * 2015 485
OIL SPILLED (BBL)
H20 SPILLED (BBL)
ACTIVE WELLS
3,948 2,441 1,062
14,296 17,857 24,470
50,067 51,737 53,054
COUNTY *YTD PRODUCTION (% OF STATE) Weld........................................301,676,948 (32.2%) Garfield...................................284,005,262 (30.3%) La Plata ..................................206,768,504 (22.1%) Las Animas ................................ 45,565,961 (4.9%) Rio Blanco .................................. 30,328,895 (3.2%) Mesa ........................................... 19,417,087 (2.1%) State......................................................936,961,802
PRODUCTION COUNTY *YTD
*As of Oct. 15, 2015 Source: Colorado Oil and Gas Conservation Commission
2015 GAS PRODUCTION
2015 OIL
US RIG COUNT
The U.S. rig count peaked at 4,530 in 1981 and bottomed at 488 in 1999. Area Nov. 6 Oct. Avg. Sept. Avg. Aug. Avg. U.S. 771 791 809 848 Canada 185 184 183 206 Source: Baker Hughes Rig Count, Nov. 6.
PRODUCTION (% OF STATE)
Weld 62,413,086 (88.6%) Rio Blanco 2,577,064 (3.66%) Arapahoe 1,084,592 (1.54%) Lincoln 853,749 (1.2%) Garfield 924,824 (1.3%) Cheyenne 783,601 (1.1%) State 70,473,356
Source: Colorado Oil and Gas Conservation Commission as of Nov. 2.
Source: Colorado Oil and Gas Conservation Commission as of Oct. 8.
COLORADO ACTIVE WELL COUNT 46 ENERGY PIPELINE December 2015
Weld ..........................................................................22,798 Garfield .....................................................................11,002 Yuma ...........................................................................3,881 LaPlata........................................................................3,331
Las Animas .................................................................2,973 Rio Blanco ...................................................................2,906 36 others .....................................................................6,976 State .........................................................................53,886
Source: Colorado Oil and Gas Conservation Commission as of Nov. 4.
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