Oil executive calls for slashing N.D. tax by more than half

Posted in: Bakken Labor Staffing News, Bakken Oilfield Financing News, Factoring Companies, frac, fracking, Labor News, Oilfield Business Financing, Oilfield News- Sep 27, 2013 No Comments

DICKINSON, N.D. — The vice president of corporate and government relations for Whiting Petroleum said Thursday that the oil extraction and production tax in North Dakota should be slashed by more than 50 percent.

Speaking at the annual North Dakota Association of Oil and Gas Producing Counties meeting in Dickinson, Jack Eckstrom said the state’s current combined extraction and production tax rate of 11.5 percent could eventually drive petroleum companies out of North Dakota in favor of states with lower tax rates.

“There is competition that (North Dakota) is going to face, and it’s starting right now,” Eckstrom said during a presentation with several other oil and gas industry executives. “We have a fairly substantial development going on in Colorado. Our boss said (Wednesday) on a tour with the investment community that we might ramp that up to as many as 30 rigs, which is a lot of rigs for northeast Colorado. Part of the problem that you all have here is that you have a very high severance tax.”

Eckstrom — who noted that Whiting is set to spend $1.3 billion in North Dakota this year — said the Bakken figures to be quite busy for several years to come, but that tax rates could eventually lead to more exploration operations being moved to places like Colorado or the Eagle Ford play in Texas.

“The tax rate down in Colorado is 5 percent and that’s a big differential,” Eckstrom said. “Is that going to matter now? I don’t think so. Is it going to matter in two years or three years? Probably not, but down the road, if that severance tax that you have does not find a creative way to be fixed, you will face more competition from the Eagle Ford and other plays.”

Eckstrom said Whiting has three unnamed “stealth plays” that he referred to as “highly prospective” and that are all outside North Dakota.

“I’m not saying North Dakota is bad. North Dakota is great,” Eckstrom said. “I’m just raising a warning flag that the money you’re getting in severance tax now, in the full flush and blush of this boom, is in danger down the road because of competition from states that have lower tax rates. You must compete on that level.”

When asked directly, Eckstrom said he would favor the current tax of 11.5 percent in the Peace Garden State be slashed by more than half.

“I would look at every other state and model myself after the median,” Eckstrom said. “This 11.5 percent is really an outlier. It works fine now, but down the road, it is going to be a problem. I’d say the tax should be somewhere around 5 percent.

- See more at: http://www.bakkentoday.com/event/article/id/35409/#sthash.KhK9cYR0.dpuf





Is the World on the Verge of a Shale Oil Boom?

Posted in: Bakken Labor Staffing News, Bakken Oilfield Financing News, Corpus Christi Financing News, Eagle Ford Shale News, Eagle Ford Shale Staffing Fianncing News, Factoring Companies, frac, fracking, Invoice factoring, Labor News, Oilfield Business Financing, Oilfield News, Permian Basin Financing News- Sep 23, 2013 No Comments

According to a new report from research firm IHS Global Insights, the world may be on the verge of a shale energy boom. But before investors get too excited, it’s important to remember that oil and gas drilling will depend more on market forces than what’s in the ground.

There’s big potential…
There’s a lot of excitement as to whether North America’s shale energy boom could be replicated internationally. New drilling techniques like hydraulic fracturing and horizontal drilling techniques have unlocked vast quantities of hydrocarbons. Explosive growth from formations like the Texas Eagle Ford and the North Dakota Bakken has driven U.S. oil production to its highest level since May, 1989. Previous studies by IHS have shown North America has about 43 billion barrels of commercially recoverable tight oil.

But the group’s latest report suggests that shale formations outside of North America potentially hold seven times this amount. The study identified 143 global shale plays that have a combined 300 billion barrels of technically recoverable oil. The report makes it clear: the potential for shale oil globally is huge.


And the IHS isn’t the only research outfit praising shale’s international promise. In June the EIA echoed a similar sentiment when it reported that shale makes up 30% of the world’s technically recoverable natural gas and 10% of the world’s crude oil.

…but don’t pop the cork yet…
But these impressive figures above come with an asterisk. The report indicates potential for international shale oil and gas, but the extent to which these technically recoverable reserves will be profitability exploited remains unclear. Already, hype surrounding shale plays outside of the United States have failed to materialized.

Five years ago there was lots of excitement surrounding Poland’s vast natural gas deposits. Companies like ExxonMobil Chevron, ConocoPhillips, and Marathon Oil  flocked to the country after the government started offering incentives to attract foreign investment.

But no boom materialized. Last year, ExxonMobil pulled the plug on its exploration program in the country after two pilot wells failed to yield commercial results. The company is looking to sell its stakes in four shale concessions there. In May, Marathon Oil announced that it was pulling out of Poland as well. The company is looking for options to dispose its 11 licences after the search failed to produced commercial quantities.

China’s shale potential is also exciting. The country has 1.1 trillion cubic feet of shale gas-nearly double the size of reserves in the United States. But there too, no boom has occurred.

PetroChina , Asia’s largest energy producer, has plans to drill 400 shale wells in the country over the next few years. But management only expects to drill 20 pilot wells by year-end. It wants to see production results before committing to a full-scale program.

In China the problem is cost. Of the 130 shale gas wells drilled in the country, only a few are producing over 40,000 cubic feet per day. At $13 million to $16 million to complete each well, this is the production figure needed just to break-even.

…because drilling for shale is a tough business.
But these problems aren’t limited to China and Poland. Shale plays elsewhere will face the same issues as well for a couple of reasons.

First, the biggest issue preventing a global shale boom is cost.  According to The Financial Times, the IHS study estimates the cost of the average shale well inside North America at $5.6 million versus with $8 million outside North America.

Second, environmentalist will also play a role in the global shale development. Politicians in Texas and North Dakota may be less concerned about the environmental consequences of shale drilling, but you can be sure their counterparts in other nations won’t be. Fracking has already been banned in France and will likely face opposition in other countries as companies look to tap new shale plays.

And finally, the pace of global development would hinge on many above-ground issues as well. Government policies-such as regulation, land access constraints, and taxation-could slow development.


Oil and ag compete for role of ND’s biggest industry

Posted in: Bakken Labor Staffing News, Bakken Oilfield Financing News, Factoring Companies, frac, fracking, Labor News, Oilfield Business Financing, Oilfield News- Sep 23, 2013 No Comments

Is the oil industry now bigger than farming in North Dakota?

The latest figures are rather startling, raising eyebrows on even oil industry experts gathered in Grand Forks this week who are most in touch with the boom that hasn’t leveled off after six years.

In the 12 months ended July 30, the value of the record amount of crude oil and natural gas produced in North Dakota totaled $24.9 billion, based on production figures and average prices for Bakken sweet crude and gas reported monthly by Lynn Helms, director of the Department of Mineral Resources and the state’s chief regulator of the industry.

Like nearly all numbers in the Oil Patch during this boom, that figure is a record.

It’s also more than double what was the record value of the state’s crops and livestock grown and raised in 2012, based on prices received by farmers.

The total value of the state’s crops and livestock, in prices received by farmers and ranchers, hit a record $12.1 billion in the calendar year 2012, said Darin Jantzi, director of the U.S. Department of Agriculture’s North Dakota office of the National Agricultural Statistics Service in Fargo.

And that was a record by a long shot, far outpacing the previous record of $9 billion in 2010, including $8.1 billion for crops, mainly corn, wheat and soybeans. Revenue from cattle constitutes 90 percent or more of livestock prices received.

Crop values are expected to be down substantially this year, farm experts say, because of lower production and prices.

Following the money

But oil and gas production keeps growing as the Bakken boom hasn’t slackened. In fact production was up a hefty 6.4 percent in July, according to Helms. And oil prices have risen this summer, to about $97 per barrel for Bakken crude this week, about 14 percent above the average price received the past 12 months of $85.83, according to Helms’ figures.

However, that doesn’t mean the oil and gas industry is twice the size or impact of agriculture in the state’s economy, says Dean Bangsund, a research scientist at North Dakota State University who tracks the state’s economic sectors.

The two industries, agriculture and petroleum, aren’t easily comparable even in dollar amounts, Bangsund said this week. For one thing, the ways revenue gets spent, and where, are quite different, he said.

Much of the money from agriculture’s harvests remains in the state, since its prices are received by farmers who pretty much have to be here to get the prices.

Meanwhile, much of the money received for crude oil pumped out of the more than 9,000 wells in the state leaves North Dakota because oil companies tend to be based in other states, even other nations, Bangsund said. Even most of the royalties paid to the owners of mineral rights to the oil — which now averages nearly 18 percent of every dollar’s worth of oil — goes to people who live outside of North Dakota, he said.

Still, because this is still boom time, petroleum companies and others who share the revenue from crude oil are investing huge amounts in the state in needed infrastructure to handle it all, Bangsund said.

Bangsund said the latest study found that about 43 percent of mineral owners collecting royalty payments from oil wells live in the state.

His analyses of the state’s economic base do not track investment dollars, or how oil companies, which often operate worldwide portfolios allocating revenue in complicated ways that are about impossible to track, Bangsund said.

But some of the oil and gas money that might go initially to an oil firm’s headquarters in, say, Denver or Houston, comes back to North Dakota in that company’s work here, not just in wages but in capital investments, he said.

Meanwhile, a “very high percentage of crop and livestock sales go to producers who live and work in North Dakota,” Bangsund said.

However, his research has shown that petroleum is grabbing a bigger slice of the state’s economic pie, while agriculture’s share is shrinking. The good news is that the pie itself is rapidly swelling.

North Dakota’s economic base grew from $8.3 billion in 1990 (or $13 billion in 2011 dollars) to $33.2 billion in 2011, Bangsund reported this spring. Agriculture’s share of that base fell from 37 percent in 1990 to 23.5 percent in 2011, while petroleum (exploration, extraction and refining) grew from 7.2 percent to 15.9 percent, he says.

It’s a fair question now, Bangsund said, to wonder if petroleum’s share is larger than agriculture’s. But it’s not clear yet, he said.

Good times

Despite the changing places of oil and agriculture, farming has never been better in North Dakota, in economic and production terms, said Andy Swenson, an agricultural economist with NDSU.

The dramatic improvement in recent years in farming revenue can be seen in two numbers: From 1999-2006, North Dakota’s crops averaged $2.93 billion in value each year; from 2007-2012, they averaged $7.34 billion in value, based on prices received by farmers, an increase of 150 percent, according to figures provided by Jantzi’s office.

Swenson said this year’s crop values will be down substantially from last year’s, but still could end up being the second-highest ever.

Meanwhile, if crude oil production has kept up the pace it set in July, the state now is pumping very nearly 1 million barrels of crude a day, although the official figures for September won’t be in until November.

It’s unlikely the same pace seen in July’s increase can be maintained, Helms said.

“We should get there by year end.”

The state’s crude oil production has more than quintupled since 2006, when it was 40 million barrels, to 243 million barrels in 2012. At the estimated production now of more than 900,000 barrels a day by Dec. 31, 2013 crude production will total more than 300 million barrels. Already by July 30, 170 million barrels had been pumped this year and output increases nearly every month.

Based on recent rising oil prices nearly $90 million worth of crude is being pumped every day, said Ron Ness, president of the North Dakota Petroleum Council, this week in Grand Forks.

He knows firsthand the effects of the Bakken boom, but he was one of several insiders at this week’s petroleum conference in Grand Forks whose eyes widened on hearing the latest figures on the value of the bounty.

There is one big difference between petroleum and agriculture, Ness said:

“We harvest every day.”

- See more at: http://www.agweek.com/event/article/id/21705/#sthash.YoIwOz0m.dpuf

Plains & Enterprise Announce Eagle Ford JV Pipeline Expansion

Posted in: Corpus Christi Financing News, Eagle Ford Shale News, Eagle Ford Shale Staffing Fianncing News, Factoring Companies, Oilfield Business Financing, Oilfield News, Permian Basin Financing News- Sep 23, 2013 No Comments

Partners Will Spend $120 Million to Increase Capacity to 470,000 b/d

Plains All American and Enterprise Products are planning a $120 million expansion of the Eagle Ford JV Pipeline system. The expansion will increase the pipeline’s capacity to 470,000 b/d of light and medium crude grades, as well as increase storage capacity in Corpus Christi, Gardendale, and Tilden by 2.3 million barrels.

The JV pipeline system is largely in service and will be completed by September 30, 2013. The companies will add capacity by looping pipelines and adding pumping capacity. The expansion will be complete by the second quarter of 2015. The JV pipeline was initially planned with potential for 350,000 b/d of capacity.

The expansion will be completed in time to support production moving through Plains’ Cactus Pipeline. The Cactus Pipeline will have the capacity to move 200,000 b/d from West Texas into the Eagle Ford region.



Plains All American and Enterprise Products Announce Agreement to Expand Eagle Ford Joint Venture Pipeline

HOUSTON–(BUSINESS WIRE)–Sep. 19, 2013– Plains All American Pipeline, L.P. (NYSE: PAA) and Enterprise Products Partners L.P. (NYSE: EPD) today announced they have agreed to expand their Eagle Ford Joint Venture (JV) crude oil pipeline. The expansion will increase the pipeline’s capacity to 470,000 barrels per day of light and medium crude oil grades to accommodate additional volumes expected from PAA’s Cactus pipeline that is currently under construction. The Eagle Ford JV pipeline expansion is expected to cost approximately $120 million and is expected to be in service in the second quarter of 2015.

The Eagle Ford JV Pipeline system, most of which is currently in service and expected to be completed by September 30, 2013, is a 50/50 joint venture between Plains and Enterprise that serves the Three Rivers and Corpus Christi refineries and other markets via marine transport facilities at Corpus Christi. The pipeline supplies the Houston-area market through a connection to the Enterprise Crude Pipeline terminal at Lyssy in Wilson County, Texas. The pipeline expansion will be completed in stages that include adding pumping capacity and looping certain segments of the existing system. The expansion also includes constructing an additional 2.3 million barrels of operational storage capacity in Gardendale, Tilden and Corpus Christi.

The Cactus Pipeline is being constructed by PAA from McCamey, Texas in the Permian Basin area to Gardendale in La Salle County, Texas. The pipeline will have an initial capacity of 200,000 barrels per day and is expected to be in service in the second quarter of 2015.

For additional commercial information on the Eagle Ford JV pipeline, please contact:
Bill Keener, Director Pipeline Business Development at Plains All American, 713-993-5144.

Plains All American Pipeline, L.P. is a publicly traded master limited partnership engaged in the transportation, storage, terminalling and marketing of crude oil and refined products, as well as in the processing, transportation, fractionation, storage and marketing of natural gas liquids. Though its general partner interest and majority equity ownership position in PAA Natural Gas Storage, L.P. (NYSE: PNG), PAA owns and operates natural gas storage facilities. PAA is headquartered in Houston, Texas.

Enterprise Products Partners L.P. is one of the largest publicly traded partnerships and a leading North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and petrochemicals. Our services include: natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation and storage; LPG import and export terminals; crude oil and refined products transportation, storage and terminals; offshore production platforms; petrochemical transportation and services; and a marine transportation business that operates primarily on the United States inland and Intracoastal Waterway systems and in the Gulf of Mexico. The partnership’s assets include approximately 50,000 miles of onshore and offshore pipelines; 200 million barrels of storage capacity for NGLs, crude oil, refined products and petrochemicals; and 14 billion cubic feet of natural gas storage capacity. Additional information regarding Enterprise can be found on its website, www.enterpriseproducts.com.

Forward Looking Statements

This release includes forward-looking statements that involve certain risks and uncertainties that could cause actual results or outcomes to differ materially from results or outcomes anticipated in such forward-looking statements. These risks and uncertainties include, among other things, various factors that could delay, prevent, increase costs of or otherwise adversely impact the construction, operation or performance of the joint venture’s pipelines and other facilities, including the following: (i) the availability of adequate third-party production volumes for transportation, (ii) factors that could cause declines in volumes shipped on the existing and proposed pipelines, such as declines in production from existing oil and gas reserves or failure to develop additional oil and gas reserves, (iii) continued creditworthiness of, and performance by, the joint venture’s customers and counterparties, (iv) shortages or cost increases of supplies, materials or labor, (v) difficulties obtaining necessary rights of way and permits, (vi) weather interference, (vii) the impact of current and future laws, rulings, governmental regulations, accounting standards and statements and related interpretations, (viii) general economic, market or business conditions and the amplification of other risks caused by volatile financial markets, capital constraints and liquidity concerns, and (ix) other factors and uncertainties discussed in the respective filings of PAA and EPD with the Securities and Exchange Commission. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of their respective dates. Except as required by law, PAA and EPD do not intend to update or revise their respective forward-looking statements, whether as a result of new information, future events or otherwise.

Source: Plains All American Pipeline, L.P. & Enterprise Products Partners L.P.

Plains All American
Roy I. Lamoreaux, 713/646-4222 – 800/564-3036
Director, Investor Relations
Brad Leone, 713/646-4196 – 800/564-3036
Manager, Communications
Randy Burkhalter, 713/381-6812 – 866/230-0745
Vice President, Investor Relations
Rick Rainey, 713/381-3635
Vice President, Public Relations



Gen X Oil Workers in Danger of ‘Burning Out’

Posted in: Bakken Labor Staffing News, Bakken Oilfield Financing News, Corpus Christi Financing News, Eagle Ford Shale News, Eagle Ford Shale Staffing Fianncing News, Factoring Companies, frac, fracking, Invoice factoring, Labor News, Oilfield Business Financing, Oilfield News, Permian Basin Financing News, Staffing Factoring, Staffing Financing News- Sep 11, 2013 No Comments

Generation X oil and gas industry workers are in danger of burning out due to a combination of increasingly few mid-career professionals working in oil and gas, family commitments and an ever-increasing workload connected to an expanding energy sector, according to a senior member of the UK’s Health and Safety Executive (HSE).

Taking part in the Offshore Europe 2013 conference’s final keynote session, Steve Walker – Head of Strategic Inventions for the HSE’s Energy Division – said: “We [know] there’s not enough of Generation X and yet they are extremely valuable, so I think there’s a real danger of the burn out of Generation X.”

Walker said that while Generation X employees aged between their early 40s and early 50s are seeking better work/life balance and roles mentoring younger workers, the current increase in activity in the oil and gas sector suggests they are likely to be working harder than ever, directly involved in carrying out projects.

“I think there’s a real tension there and it’s very easy to speak theoretically about how we want look at and nurture Generation X [workers] but I do wonder whether, just because of the pace of the industry, there is a real danger we are overusing them,” he added.

Also taking part in the keynote session – titled “Oil and Gas Skills – Your Future Today” – were Sara Caplan, a partner at business consultancy Price water house Coopers, and Ferdinand von Prondzynski, principal of Robert Gordon University.

Caplan noted:

“People in the middle [of their careers] tend to suffer from not an awful lot of investment because they are steady people, they know their job and are really good at it. What we find is that people don’t tend to move on for more money unless something has made them think about money. And the thing that tends to make them think about money is dissatisfaction in a job and that might be because no-one is investing in their development and they don’t feel valued anymore.”

Prof von Prondzynski added that educational and training organizations like the recently-formed Oil & Gas Academy of Scotland (OGAS) have a role to play in helping Generation X.

“OGAS, along with the institutions that make up OGAS will be much better at addressing that generation of employees,” he said.

“Previously, universities and colleges were used to dealing with school leavers, taking them through an educational program and then saying goodbye to them. Now, we are used to engaging with people who are later on in their careers… to develop them at that point and also help the companies concerned.”


Article Source:RigZone.com

Help (Will Be) Wanted: Overcoming Labor Shortages in Canada’s Oil and Gas Industry

Posted in: Factoring Companies, frac, fracking, Invoice factoring, Labor News, Oilfield Business Financing, Oilfield News, Permian Basin Financing News, Staffing Factoring, Staffing Financing News- Sep 11, 2013 No Comments

One of the most talked about issues in Canada’s oil and gas industry today is the topic of labor shortages. Projections ­indicate that Canada will face a shortage of both skilled and unskilled labor in the near future. This lack of access to labor is ­limiting the capacity of the industry as a whole to grow and be ­economically ­successful. If there are not enough people with the right skills to ­complete a job, the job simply cannot get done. Or, if the number of people who have the necessary skills to complete a task is so small that they can command very large wages, these increased wage costs could render a project economically unviable.

How significant is this labor shortage problem? While projections vary, the vast majority of authors agree that labor shortages are a ­significant hurdle for future economic growth in the sector. For example, the ­Petroleum Human Resources Council of Canada estimates that up to 9,500 jobs will be unfilled in the oil and gas industry by 2015. While this is not consistent across all sub-industries—some will expand while others contract—the overall trend indicates that labor shortages will be a significant barrier to growth for Canadian oil and gas companies as they move forward.

If this is a significant problem, what is driving these labor shortages? Two broad trends are seen as the root causes of projected shortages in labor:

  1. A lack of workers who possess the skills and technical knowledge needed to complete certain jobs within the industry (for example, many individuals in the pipeline or oil sands sector require specific skills and accreditation to complete their work) creates a shortage of certain skilled workers.
  2. Older workers retiring will create an additional demand for workers within the oil and gas sector.

What can be done to address labor shortages? While there is no ­single “silver bullet” change that can immediately solve the ­problems, a ­number of small changes introduced by private companies and ­Canadian ­provincial governments could collectively help to ease ­labor shortages. These changes are designed to either increase the ­number of skilled workers that the Canadian economy can draw upon in the ­future, or to attract skilled workers from around the world to fill the ­demand for skilled work in the country. Examples of some of these changes are listed below:

  1. Tax reform: Canadian governments are changing their tax structures to encourage individuals to develop new skills to match industry demands. For example, Manitoba is using preferential tax treatment to incentivize skilled workers with post-secondary education to move and work in Manitoba. This is in the form of tuition tax rebates that enable up to 60 percent of the cost of tuition to be paid for by the government. This could be up to $24,000 for an individual student as they complete a degree.
  2. Encouraging worker retraining: By encouraging older workers to retrain and acquire new skills, these workers can stay in the workforce longer and reduce the demand for skilled labor. For example, Human Resources and Skills Development Canada has previously funded programs and worked together with the provinces to ensure community organizations have the resources necessary to train older workers to re-enter the labor force. This project was previously extended into 2012.
  3. Pension reforms: Reforming pensions to incentivize older workers to remain in the workforce for a longer period of time. This will reduce the eventual demand for skilled labor in the labor force as people stay in the workforce longer. British Colombia restructured the retirement options of older citizens in 2008, to encourage working later in life. This included raising the retirement age, and creating phased retirement plans so that individuals can work and receive a portion of their pension at the same time.
  4. Encourage interprovincial migration within Canada: By making it easier for workers to move across Canada, workers can go to where their skills are most highly demanded. A significant portion of the “New West Partnership,” an agreement between British Colombia, Alberta, and Saskatchewan, is designed to make it easier for workers to move between these provinces to where their labor is most needed.
  5. Encourage international immigration from abroad: Both federal and provincial governments are working to attract skilled immigrants to come and work in Canada. This enables more skilled workers to be supplied in our labor markets. This involves steps such as relaxing credential recognition from abroad, making it easier for immigrants to be integrated into Canadian society, and improving cooperation between governments when dealing with immigration issues. In 2010, Human Resources and Skills Development Canada completed a pilot project for the “Foreign Credential Recognition Program.” This program overall was positive in coordinating numerous stakeholders involved in recognizing foreign credentials.
  6. Cooperation between education and industry: One consistent call is for additional cooperation between post-secondary institutions and companies to enable graduates to participate in apprenticeship programs. In this way companies can acquire an employee that has skills and exposure to how a company works, while the new graduate gains valuable hands-on experience.

Article Source:The OGM

Oil Rises From Two Week Low

Posted in: Factoring Companies, frac, fracking, Invoice factoring, Oilfield Business Financing, Oilfield News, Permian Basin Financing News, Staffing Factoring- Sep 11, 2013 No Comments

Oil rose from its lowest level in two weeks Sept. 11, on speculation that a U.S. attack on Syria may threaten Middle Eastern oil exports even after President Barack Obama decided to delay military strikes, Bloomberg News reported.

Oil rose 61 cents to $108 a barrel in early electronic trading on the New York Mercantile Exchange after dropping 1.9% to $107.39 Sept. 10, the lowest close since Sept. 4.

The Department of Energy said Sept. 10, diesel fuel will average $3.96 a gallon this year, below its current pump price.

Diesel held at $3.981 a gallon this week, matching last week’s five-month high, while gasoline slipped 2.1 cents to $3.587.

 The flat diesel reading followed a cumulative gain of 8.5 cents in three straight increases, including last week’s 6.8-cent jump.

By Transport Topics

Article Source:Transport Topics

Going With the Flow

Posted in: Factoring Companies, frac, fracking, Invoice factoring, Oilfield Business Financing, Oilfield News, Permian Basin Financing News, Staffing Factoring- Sep 09, 2013 No Comments

By M.D. Wiseman

Fluid management is one of the fastest-growing aspects of the oil industry in North America. Driven by the growth of fracturing and horizontal drilling techniques, both of which rely heavily on oilfield fluids, demand for fluid services has grown rapidly over the last decade. As Key Energy Services CEO Dick Alario remarked, “We have made a lot of new hires. We’ve grown the transporting and storage tank fleet, and the number of disposal wells, starting in about 2004. It has involved adding personnel, equipment, and services under that area. That is the overall 9-10 year picture.”

The field of fluid management takes in a broad spectrum of services. According to Paul Pistono, senior vice president of sales and marketing at Rockwater Energy Solutions, the role of fluid management is “to manage the water, fluids, and chemicals needed in the oilfield. We handle the water required for hydraulic fracturing from start to finish.” The proper management of oilfield fluids goes beyond the task of transporting fluids to and from drilling sites. It entails the tasks of storage and disposal as well. However, as Pistono pointed out, the roles to be filled depend on the kind of oilfield fluid being handled.

Alario listed just some of the fluids which Key manages: “Produced water, [which is] water that is produced alongside oil and gas, salt water from the wells, and fracturing fluids. We transport, store, and dispose of fracturing fluids.”

A fluid management service delivers fracturing fluids to the drilling sites where they will be used. Once the oil or gas has been extracted, they transport the fluids from the site, along with any groundwater produced as a byproduct. These fluids are then either disposed of in disposal wells, or recycled for use in further drilling.

Not only is fluid management a growing field, it is also a changing field. New strategies and technologies are being implemented to meet the challenges of the market. Many of these changes are driven by new fields which have been opened by fracturing. Others have been developed to meet changing regulations, or environmental factors.

Fracturing has opened a number of shale formations to drilling that were previously unproductive. These new markets come with new challenges for fluid service providers, because many of them are in parts of the country that are not traditionally part of the oil field. “That has caused delivery routes to be longer, and storage requirements have increased,” said Alario. He added, “Take, for example the Eagle Ford Shale. A market where, five years ago, Key had little or no activity. Today, it’s a substantial market for our company. This is just one example where we have deployed people and assets which otherwise might not be utilized.”

Companies are therefore looking for ways to increase their storage and trucking capacities. Pistono pointed out that his company has begun using large Above-Ground Storage Tanks (ASTs) to increase storage and hauling capacity: “Our largest AST at 41,000 barrels of capacity can be erected in about ½ day with 3 trucks, and replaces 80 standard size fracturing tanks.” Pistono noted an additional benefit of the larger tank size: “Operators get a lot of pressure to reduce truck traffic, dust, noise, and emissions. Because one tank can replace 80 standard-sized fracturing tanks, it reduces dust, noise, and emissions.”

Others, like Alario, are focused on improving logistics and efficiency to meet this demand. Alario went on to indicate that the demands in this area may be changing again in the near future. “We are just beginning to hear about technology improvements in fracturing that require smaller volumes of water, applicable in certain areas under certain conditions,” he said.

In the area of disposal, fluid management companies are facing a new challenge: water availability. The costs of drilling fluids are increasing as the supply of water becomes more taxed, causing many companies to recycle more drilling fluids in order to keep costs down. This is an aspect of fluid management that some companies are actively embracing. “Recycling water used for hydraulic fracturing is a major focus for us,” Pistono said.

Used water is treated using a process of electro oxidation in order to remove solids, iron, oil, bacteria, and other contaminants that have become suspended in the solution. Once these are removed, the water can be safely used in other drilling operations, Pistono added.

Just the same, many companies are not yet getting involved in recycling. “Some companies also do recycling, but thus far that is mainly in the ballpark of other companies, not the large players in fluid management,” said Alario. “Key may get involved in [recycling] as it grows. We do see it as part of the future of the fluid management business, as water availability and cost become more stressed.” For now, though, Key is focusing on improving efficiency, and continues to deal primarily in fluids which cannot be recycled.

Pistono affirmed that the market for recycling fluids continues to grow. “We are also beginning to see more interest in recycling flowback and produced water for reuse for additional hydraulic fracturing jobs,” he said. This growth is, in some cases, being assisted by changing legislation. “There are some states, like Texas, that are streamlining regulations to make it easier for operators to recycle and reuse the water,” Pistono said.

Not every state has been as helpful, though, and Alario indicated that state regulations continue to prevent Key from expanding into certain regions. However, in spite of these restrictions, there is no lack of opportunities for fluid management to grow. As Alario observed, “Even in some of the traditional markets such as the Permian Basin, advent of horizontal drilling requires increased volume of drilling fluids.”

While fracturing is opening entirely new markets to the fluid management industry, horizontal drilling is increasing demand for these services in established fields. Said Alario: “The Permian Basin has typically produced its oil through vertical wells. We are now watching the genesis of the conversion of the Permian Basin from vertical to horizontal drilling. Horizontal drilling requires 2-4 times as much service intensity as vertical wells… So, demand is increasing in this traditional market, just as in some of the non-traditional markets.”

Fluid management is a growing, changing part of the oil industry. Although much of its growth is in new fields opened by fracturing, fluid management continues to play an integral role in established areas, including the Permian Basin.

Article Source:PB Oil & Gas

The oilfield equipment rental industry finds opportunities and competition abound in thriving times.

Posted in: Factoring Companies, frac, fracking, Invoice factoring, Oilfield Business Financing, Oilfield News, Permian Basin Financing News, Staffing Factoring- Sep 09, 2013 No Comments

As the rust belt continues to jettison inhabitants, hurling them at high speed toward the deep flowing wells of the Permian Basin, many newcomers in the service industry land at the corner of Opportunity and Reality streets.

The opportunities in the Basin abound. Many construction projects take weeks or months to get started because existing businesses are swamped. Newcomers could move right in and get to work. Could, that is, if their employers could afford the tens or hundreds of thousands of dollars for heavy equipment needed to build drill pads, roads, frac pits, pipeline routes, and other drilling and production infrastructure.

Large scale equipment rental companies such as ASCO and area newcomer Kirby-Smith are meeting that need by renting and leasing that equipment on a job-by-job basis, says Kirby-Smith Territory Manager Kevin Demel.

“For new customers, rentals are very strong. Most of these new customers are start ups,” Demel noted, adding that, over an eight-month period beginning late in 2012, his company had broken many revenue records. “It’s been incredible,” he said.

Their rentals-to-sales ratio is currently approximately 75 percent to 25 percent. Much of that differential is accounted for by newcomers to town who want earth-moving equipment for pad site construction and pipelines. These newbies want to get the income flow rolling before they purchase equipment. Also, they know they need to learn what kind of equipment is needed in this area, as opposed to where they have been operating.

“Our biggest market these days is helping out-of-state companies know what equipment they need for this area’s soil conditions—which are different from what they’re used to,” Demel said. The thin topsoil here quickly gives way to rock and cliche.

Companies used to doing business in Louisiana, Arkansas, and even East or South Texas are tempted to start with equipment that just moves soil—only to find that machinery is useless within a few inches in many cases.

The newcomers quickly learn to rely on advice from locals about what equipment is needed. Renting allows them to quickly recognize any mistakes and to trade the wrong equipment for the right stuff without a huge cost.

Kirby-Smith is itself somewhat of a newcomer to this area, but not as new as it may appear. They moved to their current location on I-20 just east of Odessa in October of 2012, but Demel was working from his home for two-and-a-half years before that, with equipment and service technicians coming from the company’s Lubbock office. It had been apparent for a while that the Basin boom was calling them loud and clear to set up an office, but that very boom made finding a good location and a reasonable price more of a challenge.

What equipment is most popular varies throughout the year, but there is a pattern, Demel said. Being familiar with the progression of clearing brush and leveling land, then building the pad, grading roads, and digging frac pits, Demel and his staff can often anticipate the work flow, making sure they have in stock the next piece of equipment when it is needed.

ASCO, whose full name is Associated Supply Company, Inc., has had a yard in Midland since 2001, and one in Odessa for a like amount of time. They moved to their current Midland spot on Cotton Flat Road about four years ago because they needed more space than they had had about a block away on Garfield Street.

Branch Manager Nick van Cleave said their highest-demand items on the drilling side are telescoping forklifts. For site building they rent a lot of boom lifts, backhoes, Bobcats, compaction equipment, and some bulldozers and graders. Most of this is rented to the dirt contractors. Van Cleave noted that the producers themselves rarely rent equipment. Even if they pay for it, the contractors will contact ASCO and take care of the pickup and return.

For ASCO, dollar-wise, rentals and sales are “really pretty even.” Volume-wise, in the number of pieces of equipment going out, there is much more on the rental end, he said, but those dollar figures are much smaller per machine since rentals are only a small fraction of the cost of the machine.

With a total of 19 locations in Texas, including those nearby in Odessa and Lubbock, van Cleave said he is able to borrow machinery from those other offices whenever needed, just as they borrow from him on occasion, creating flexibility without the necessity of every location having a huge inventory of every piece of equipment.

Both Kirby-Smith and ASCO make service work a priority. As to how well they keep up with service work in a booming economy, van Cleave said, “It depends on the day.” If everyone needs service on one day, things stack up more than on a slow day.

For Kirby-Smith, the continued growth is leading to plans for a shop expansion in the near future. “If we continue to grow we plan to add more bays to the shop,” said the company’s branch rental manager, Mike Fuentes. When that happens, Demel added, they will need to add staff.

Onboard diagnostics help Kirby-Smith pace much of their work. Computers on the machines track usage and report that along with any breakdowns through a satellite link. Office personnel are then alerted when it’s time to change oil or when service of any kind is required. For maintenance, the Kirby-Smith office contacts the renter and schedules a time when they can have the machine for the time necessary to do the work. For a breakdown, the computer diagnoses the problem so the technician knows what parts to bring and exactly where to begin working.

Kirby-Smith and ASCO also rent road equipment to paving companies keeping up with the demand for new roads and road repairs that are another byproduct of the oil boom.

The migration to the Basin is not restricted to service companies. Other rental firms have also come to town looking for their piece of the ever-growing pie. Many try to begin by competing on price, a tactic neither ASCO nor Kirby-Smith tries to match. Instead, for ASCO, they fight back by doing their best to “provide better service,” said van Cleave. “We’re good at what we do, we’ve been doing it a long time–and that’s just business, you’ve gotta be better than the next guy.” Kirby-Smith has also been around, as a company, for years, and has built a huge inventory of machinery. For example, “We have 250 cranes in our fleet,” said Demel. They likewise have a sizable inventory of boom trucks and other equipment. Neither company will negotiate to the point that they lose money on a deal.

Smaller companies have more concerns about the new guys. Arayot Rentals, owned by the husband-and-wife team of Ken Levy and Wanda Scroggins-Levy, started out renting light towers and generators. Now, due to undercutting by newcomers, their primary business is in trash trailers and pressure washers.

“They’ve gotten so competitive with the light towers, the whole rental’s like $29 a day,” Scroggins-Levy reported. “We really can’t make any money like that. We try to stay competitive with some of the others, but it’s pretty tough out there right now with that.”

Scroggins-Levy said some future competitors have called her thinking Arayot was a home rental agency—then those people rent some equipment from Arayot to clean up the yard of the house they end up with before beginning their own business. At least that way she knows who is coming to town.

Most rentals are to service companies, but some trash trailers, generators, and pressure washers go to production companies. Some of the pressure washers also go to production companies for use on production equipment.

Arayot is taking several steps to get past the box they found themselves in. They have added cleaning services and hotshot services and have begun doing service and repairs on equipment beyond that which they themselves rent. Pending the procurement of DOT licensing, the company is currently doing just small loads of 10,000-11,000 pounds.

Scroggins-Levy said clients have told her that, for certain equipment, there is only one other service company in the area, and that company is swamped with work.

The good thing about competition is that it keeps everyone sharply focused, van Cleave noted, and it gives customers every opportunity to get the best service and price possible. Scroggins-Levy added that, with the opening up of the Cline Shale, opportunities will continue to abound, but so will competition—a situation that puts rental firms at the same intersection of Opportunity and Reality streets as the service companies.

Article Source:PB Oil & Gas

The Permian Basin is gradually becoming a hatchery and laboratory for some forward-thinking green initiatives.

Posted in: Factoring Companies, frac, fracking, Invoice factoring, Oilfield Business Financing, Oilfield News, Permian Basin Financing News, Staffing Factoring- Sep 09, 2013 No Comments

The oil business has always been about turning black gold into green—but the shade of green has begun to change in the last few years. While still representing money, “green” is a term that now denotes a mindfulness of the environment. It’s a direction some in the industry are embracing, while others seem to be getting dragged along, leaving heel prints in the sand.

“Green” thinking takes many forms, including reduction of the volumes of fresh water used in fracturing and other procedures, as well as the practice of recapturing vented hydrocarbons, capture of waste heat, and use of compressed natural gas in fleets.

Jared Blong, president and CEO of Octane Energy, a drilling startup, is among those who are enthusiastic about greening up the oilfield. Blong, who is the son-in-law of recently deceased PBPA Chairman Mark Merritt, is a 33-year-old entrepreneur who sees himself as new enough to the industry to think outside the box yet savvy enough to know which green initiatives are as yet impractical. The common fallback statement, “We’ve always done it this way,” is Blong’s least favorite expression. “I live to make that statement sound foolish,” he declared. “We’ve got to start behaving differently if we want the public to continue to allow us to do what we do—instead of just feeling entitled as oilmen, which is our general propensity,” he added, with a chuckle.

It was through his conversations with industry veteran Dr. Richard Erdlac, an expert in geothermal energy and other environmental concepts, that Blong learned of a way to capture waste heat and convert it to electricity. “When I heard that I said, well gosh… why hasn’t anybody ever done that before?”

Erdlac is connected with Gulf Coast Green Energy, based in Bay City, Texas, which markets a product called the Green Machine. The device, developed by ElectraTherm in Reno, Nev., collects waste heat from a variety of sources and uses that heat to generate electricity.

Basically, the Green Machine operates by transferring heat from a hot liquid, such as produced water or fluid from the radiator of a diesel generator, over a refrigerant whose boiling point is 53° F. The now-hot refrigerant turns the twin screws in an expander, which operates an induction generator. The incoming hot liquid is cooled in the process.

Octane Energy plans to use AC drilling rigs, which run 100 percent on electricity, all of which is generated on the well site by “almost locomotive-sized diesel engines running almost 24 hours a day,” as Blong describes it. The best diesel engines use only around 40 percent of the energy burned to do their work—the other 60 percent is ejected as heat. Blong wanted to recapture at least some of that other 60 percent, thereby reducing diesel fuel use and cutting CO2 emissions.

“What it looks like we’ll be able to do is to power all the ancillary trailers on the location, like the company man’s trailer, our pusher’s bunkhouse, and our crew houses,” he noted. “All of our jobs are camp jobs because the folks that we’re employing, we want to bring in from outside the Permian Basin because we’ve got a labor shortage.” Blong looks forward to furnishing electricity to those facilities for just the cost of the equipment.

He also believes that, because the producer is usually the one paying for these things, his company will be able to offer this as a value-added proposition for its own customers.

Octane is also looking at running a dual-fuel operation, which could use some wellhead gas to generate that electricity. This, in Blong’s view, would both keep the gas out of the atmosphere and save on the use of diesel in the generation process.

His vision in all this is to establish credibility as an environmentally sensitive company and to invite producers to join them in that vision. Heat capture, dual-fuel use, and other efforts do create an extra investment cost, but Blong feels it shows corporate responsibility and, “It’s the right thing to do.”

A startup, Octane plans to begin building rigs in the fourth quarter of 2013, to start drilling by the end of January 2014, and to have four more rigs operating by the end of 2014.

Meanwhile, Erdlac, no less a visionary himself, is excited about this and other uses for the Green Machine, especially its ability to generate electricity from flares. A typical unit generates 65-80 KW of electricity and, Erdlac noted, “A really large flare could require multiple units.”

Erdlac said there is interest in this technology but, as is common, people are hesitant to be early adopters. “We really need to get people off dead center on this,” he urged.

Water use is a huge issue, and there are more and more companies getting involved in the process of treating produced water for reuse in hydraulic fracturing or other uses.

For example, Halliburton recently announced its H2O Forward frac fluid, a product that utilizes water that is much dirtier than was previously usable. Company officials point out that water still may need to be treated, but to a lesser degree than before, which will save producers money on the treatment side.

Instead of injecting produced water into the ground, as has been the practice for decades, the alternative of using it for fracturing solves two problems. It reduces the amount of fresh water for frac jobs that can require supplies in the millions of barrels, and it eliminates the need for injection.

In the last two years the costs of treating water have come down to a generally affordable level, say those in the treatment industry. They point out that treatment reduces the cost of fresh water, which is rising in the prevalent drought conditions, plus it reduces the need for trucking fresh and waste water back and forth.

Every new idea has its own challenges, and one of those with water treatment is storage. Huge ponds, many reaching several acres, are now needed to hold water. When treated water is in those ponds, producers have to worry about two things: losing thousands of gallons to evaporation, and the possibility of pit liners tearing and allowing this still-less-than-pristine water to leach into the ground and possibly into the water table.

This has created a couple of new tools to deal with these issues. Double pit liners with leak detection systems are growing in use, as regulators and communities express concerns about treated water getting into their municipal water systems.

On the evaporation side, pit covers are being developed and marketed that, marketers say, float on top and greatly reduce water loss out the top side.

Speaking of regulators, that is the other side of the push toward green initiatives, especially regarding air quality. Tom Larson is Principal in Charge of the Midland office of Conestoga-Rovers and Associates, an environmental company based in Canada. Their primary focus is on environmental remediation, but they are in touch with other aspects as well.

New EPA air quality regulations, known as “Quad O” or by their formal name, 40 CFR Part 60 Subpart OOOO, are taking effect in full force this fall and, said Larson, are changing the way companies plan and execute their drilling plans.

“Folks used to not worry about the emissions but now, because of the regulations, the awareness of the release of greenhouse gases—when operators do their wells, part of the planning process includes some surface equipment that’s designed to capture those emissions, to reduce them,” he said.

A number of equipment makers, such as Hy-Bon Engineering, OTA Compression, and others are finding a big market for vapor recovery units (VRUs) and related devices as producers rush to meet the new standards.

So far, Larson noted, regulations are less of an issue for water use than for air quality. He pointed out that the main concern for water issues is the drought, especially in Texas.

“In Texas, the water rights are held by the landowner, and then in New Mexico the water rights are with the state,” he said. Therefore, in Texas any landowner can sell as much water as can be pumped without regard to water table restrictions. In New Mexico, he said, a state permit is required to pump water.

A few water districts are found in Texas, he explained, but most oversee an area no bigger than a county.

In general, in the oil industry, “They’re trying to do the right thing in trying to develop these best management practices” by using treated frac water and other conservation methods.

Doing the right thing also includes, for some, use of brackish groundwater that is not suitable for city or irrigation use anyway. With a small amount of cleanup, water in the Santa Rosa formation and others can be used without disturbing public water. Even a golf course in Midland is using Santa Rosa water for its golf course irrigation, cleaning it up with a treatment system supplied by STW Resources.

Green energy is also a focus for the industry, Larson said, pointing to Apache’s web site that lists that company’s growing count of compressed natural gas (CNG) fueling sites and its plan to convert up to 80 percent of its pickup truck fleet to CNG. Larson noted that CNG is currently cheaper than diesel or gasoline and it releases less CO2 than either of the other fuels, but that building the infrastructure is the main challenge to converting it to popular use. Fleets, on the other hand, are the ideal way to expand CNG use because fleets require fewer fueling stations.

Overall, the number of “outside the box” thinkers such as Blong and Erdlac is increasing. Last year, PBOG carried a cover story on the numerous “green initiatives” conceived and implemented by the Midland-based mud company known as Mudsmith. Their renovated and expanded plant is a model of how to operate environmentally while getting some economic incentives, to boot.

As these individuals interact with the Apaches and other producers of the world, perhaps the industry is indeed starting to get off “high center” and move forward to improving its image and its record of corporate responsibility.

Already, no one thinks of dumping sludge in an unlined pit as was the practice in past decades, so things are indeed changing.

Article Source:PB Oil & Gas