Business plan and structure pg.2
5.2 Pricing
Introduction
Like prices of other commodities the price of crude oil experiences wide price swings in times of shortage or oversupply. The crude oil price cycle may extend over several years responding to changes in demand as well as OPEC and non-OPEC supply. We will discuss the impact of geopolitical events, supply demand and stocks as well as NYMEX trading and the economy.
Throughout much of the twentieth century, the price of U.S. petroleum was heavily regulated through production or price controls. In the post World War II era, U.S. oil prices at the wellhead averaged $28.52 per barrel adjusted for inflation to 2010 dollars. In the absence of price controls, the U.S. price would have tracked the world price averaging near $30.54. Over the same post war period, the median for the domestic and the adjusted world price of crude oil was $20.53 in 2010 prices. Adjusted for inflation, from 1947 to 2010 oil prices only exceeded $20.53 per barrel 50 percent of the time.
Until March 28, 2000 when OPEC adopted the $22-$28 price band for the OPEC basket of crude, real oil prices only exceeded $30.00 per barrel in response to war or conflict in the Middle East. With limited spare production capacity, OPEC abandoned its price band in 2005 and was powerless to stem a surge in oil prices, which was reminiscent of the late 1970s.
The price of petroleum as quoted in news in North America generally refers to the WTI Cushing Crude Oil Spot Price West Texas Intermediate (WTI), also known as Texas Light Sweet, is a type of crude oil used as a benchmark in oil pricing and the underlying commodity of New York Mercantile Exchange's oil futures contracts. WTI is a light crude oil, lighter than Brent Crude oil. It contains about 0.24% sulfur, rating it a sweet crude, sweeter than Brent. Its properties and production site make it ideal for being refined in the United States, mostly in the Midwest and Gulf Coast regions. WTI has an API gravity of around 39.6 (specific gravity approx. 0.827) per barrel (159 liters) of either WTI/light crude as traded on the New York Mercantile Exchange (NYMEX) for delivery at Cushing, Oklahoma, or of Brent as traded on the Intercontinental Exchange (ICE, into which the International Petroleum Exchange has been incorporated) for delivery at Sullom Voe. Cushing, Oklahoma, a major oil supply hub connecting oil suppliers to the Gulf Coast, has become the most significant trading hub for crude oil in North America.
The price of a barrel of oil is highly dependent on both its grade, determined by factors such as its specific gravity or API and its sulphur content, and its location. Other important benchmarks include Dubai, Tapis, and the OPEC basket. The Energy Information Administration (EIA) uses the imported refiner acquisition cost, the weighted average cost of all oil imported into the US, as its "world oil price".
The demand for oil is highly dependent on global macroeconomic conditions. According to the International Energy Agency, high oil prices generally have a large negative impact on the global economic growth. Peak oil is the period when the maximum rate of global petroleum extraction is reached, after which the rate of production enters terminal decline. It relates to a long term decline in the available supply of petroleum. This, combined with increasing demand, will significantly increase the worldwide prices of petroleum derived products. Most significant will be the availability and price of liquid fuel for transportation.
The US Department of Energy in the Hirsch report indicates that “The problems associated with world oil production peaking will not be temporary, and past “energy crisis” experience will provide relatively little guidance. The U.S. Energy Information Administration estimates that the United States will be the world's top producer of petroleum and natural gas hydrocarbons in 2013, surpassing Russia and Saudi Arabia. For the United States and Russia, total petroleum and natural gas hydrocarbon production, in energy content terms, is almost evenly split between petroleum and natural gas. Saudi Arabia, on the other hand, heavily favors petroleum.
5.3 Distribution Channels
SELLING THE OIL EXAMPLE: barges of oil as big as football fields for a living. He calls his route “the loop,” which starts with him guiding his boat and two empty 300-foot barges into the Port of Catoosa, outside Tulsa, Okla. Meredith steers toward a cluster of seven storage tanks brimming with crude that’s been trucked in from wells in Oklahoma and Kansas.
Moving 43,000 barrels of oil from the tanks into the barges is a 12-hour process, and one mistake can mean disaster. “You get 4,000 barrels going through that hose every hour, and you let something ass up. … Man, it makes a big mess,” Meredith says in his Florida drawl, his face deeply tanned from 19 years on a tugboat. At dawn the next day he’ll leave for Mobile, Ala. The route of winding rivers is more than 1,300 miles long and takes about a week.
“It’s a haul, man,” says Meredith. “You leave here and go back out the Arkansas River. Then you hit the Mississippi and take it down to New Orleans and into some industrial locks. Once you’re through those, you scoot across Mississippi Sound and on over to Mobile Bay and into the Mobile harbor.” Next stop is a storage facility in Mobile leased by Hunt Oil. Meredith says Hunt will take this domestic crude and mix it with lower-grade oil from Venezuela. He’ll then barge the blend up to Hunt’s refinery in Tuscaloosa, where it’ll be turned into gasoline, diesel fuel, jet fuel, and asphalt. Meredith then will head back to Catoosa and start all over again.
These are 24/7 days for oil production in the U.S. North Dakota now produces more oil than Alaska—and more than Ecuador, too. Geologists estimate that Oklahoma still has 80 percent of its reserves in the ground. The majority of this oil is of the highest quality: light, sweet crude that’s low in sulphur, lighter than water, and cheaper to refine into gasoline than the heavier sour (high in sulphur) crude from Venezuela and the Canadian tar sands. Goldman Sachs (GS) predicts that by 2017 the U.S. will be the world’s biggest oil producer.
All this oil needs to get stored somewhere, and the largest facility in the country is 60 miles west of Catoosa in the small town of Cushing (pop. 7,890). Each day some 900,000 oil futures and options contracts are traded on the New York Mercantile Exchange (CME). The oil at Cushing is what’s bought and sold. The town’s hundreds of storage tanks are the country’s biggest bank vault of oil. And it’s getting bigger. In September 2008 there were fewer than 15 million barrels of oil parked there. Today there are 44 million, 16 million more than in January. And that’s a problem. Oil is flowing into Cushing faster than it’s getting piped out.
The giant pool of crude stuck in the middle of the country has done strange things to the oil market. The light, sweet crude that Meredith transports is priced against the domestic benchmark West Texas Intermediate. It’s so plentiful right now that for the past year it has traded at an average $95 a barrel, $16 below the price of its international equivalent, Brent crude. At its peak last October, the spread—the price differential between WTI and Brent—was $27. That’s the biggest gap in the history of those two oil contracts, which for most of the last 20 years have moved within $1 of each other. What’s helped push down the price of WTI? The fact that it’s stuck in Cushing. Oil that can’t be moved to where it needs to go quickly drops in price. The result has been one of the biggest arbitrage opportunities in recent memory: Buy oil low in Cushing, and sell it high—just under the price of Brent—to refineries along the Gulf Coast. The trouble is getting it there. The race is on to get the oil out of Cushing. Pipeline companies are pushing to build new pipes and, in some cases, reversing the flow of existing ones. For 17 years, the 500-mile-long Seaway Pipeline pumped imported crude from the Gulf Coast into Cushing. In May it was reversed, and now Seaway pumps 150,000 barrels a day south to the refiners on the Gulf Coast. TransCanada (TRP), based in Calgary, is spending $2.3 billion to extend its Keystone Pipeline south of Cushing. (Its Keystone XL pipeline still awaits approval.) When completed next year, it’ll move 700,000 barrels a day.
Determining the Value of Your Producing Mineral Rights
In order to get an idea of what your oil or gas royalty stream is worth, one must look at a number of factors. Location, size of the land tract, depth restrictions, operating costs – all of these play into valuing royalties. The price of crude oil or natural gas, and the production decline rate are two of the more important variables. Of course estimation must be made several years into the future as to how these elements will fluctuate. When exchanging a cash payment now for an expected future cash flow stream, the time value of money also plays into the calculation. (A dollar in hand now is worth more than a dollar promised next year, because the dollar in hand can be used to earn interest over the course of the year). Also, mineral and royalty interests may qualify for use in Like-Kind Exchanges (1031 Exchanges) which can defer taxes. Under the Case Study section, you’ll find examples where oil and gas royalties have been exchanged for an immediate cash payment.
Shifting commodity prices are a given in the oil and gas industry, but sometimes the industry landscape changes in unexpected ways. In this interview with The Energy Report, Oppenheimer & Co. Managing Director and Senior Energy Analyst Fadel Gheit discusses the effect of Middle Eastern geopolitical issues on oil production, dissects the changing oil and gas production situation in the U.S. and explains how the shift in natural gas prices has turned the refinery business from the industry's perennial ugly duckling into a beautiful swan.
Oil and Gas Journal's semiannual Worldwide Construction Update shows an increase in refining construction activity compared with the previous edition of the update (OGJ, Nov.5, 2012, p. 48). Following are details from the latest survey, which is available on OGJ Online (see box). Refining In US refining news, CHS Inc., St. Paul, Minn., will boost refining capacity at the 85,000 b/d National Cooperative Refinery Association facility at McPherson, Kan., to 100,000 b/d by 2016 in a $327 million project (OGJ Online, Mar. 12, 2013). Completion will take place in phases during the second half of 2015 and the first months of 2016, with production expected in early 2016. The expansion will occur ... A Chinese oil company has purchased a cargo of North Sea oil, in a rare move into the European crude market that highlights the extent to which supply disruptions have left buyers scrambling to secure alternatives. ...U.S. refineries are expanding their diesel-production capacity, not so much for truckers in the U.S., but for drivers in places such as Mexico City and Santiago, Chile. Already running at their highest levels in six years, U.S. refineries are finding strong demand for diesel fuel, used widely in cars outside of the United States, and other distillates, like jet fuel.
Refiners have been pinched as crude oil prices rise, and the narrowing of the gap between U.S.-produced West Texas Intermediate and the international benchmark Brent crude, has taken away some of the advantage U.S. refiners had in the global marketplace. Exxon Mobil, for instance, pointed to refining margins for part of its surprisingly steep profit decline in the second quarter, and others, like Marathon and Valero, also blamed a contraction in refining margins for reduced profits. Refineries continued to operate at a high level of 90.9 percent of capacity, though off recent highs. Gasoline production rose slightly to 9.6 million barrels per day, and distillate fuel, mainly diesel production, increased to 4.9 million barrels per day.
North American crude oil markets are in a state of flux. The advent of new oil drilling techniques, has unlocked enormous quantities of crude oil previously thought unrecoverable. US crude oil production is expected to grow 60% from pre-recession levels by 2017. This has led industry commentators to project that the US will be able to produce enough crude oil to meet domestic demand by 2030, something that hasn’t occurred within the last 40 years. This astronomical growth in supply has overwhelmed traditional pipeline infrastructure, leading to bottlenecks. The inability to connect oil production to market has caused a supply-demand imbalance, leading to depressed oil prices in certain regions. The North American benchmark oil price, West Texas Intermediate (WTI), has traded at a discount as large as $30 to world oil prices, which trade at around $110/ barrel (bbl).
Refining in North America
Crude oil is transported from the oil wells to refineries by pipeline, railcar, or tanker. Pipelines are the primary and safest method of transportation in North America. There are two types of oil, light and heavy crude, both of which refineries can process. Light oils are refined into gasoline, while heavier crudes produce diesel and jet fuel. Not all refineries can process both types of oil, reconfiguring a refinery to process light from heavy and vice-versa requires billions in capital investment and years to complete, making this option unattractive.
Refineries are expensive to build, have long payback periods (20-30 years) and sell low-margin products. They make their money off of the difference between the crude oil input costs and the refined product sales price. This is called the “crack spread”. Unfortunately, the prices for both commodities are very volatile and do not always move together. Additionally, refineries built outside North America are far more cost effective due to lower overhead costs, cheaper labor, and more lenient environmental regulations. These factors, along with stringent environmental and emissions legislation in the US make it clear why few new refineries have been built in the US since the late 1970s.
5.4 Promotional Plan
Public Company Stock Promotion
Email Answers is an experienced, well managed marketing company that works with third party investors/owners who are interested in adding volume and increasing the price of a publicly traded companies stock. Whether you are a stock promoter or a third party investor looking for a stock investor email list, stock investors mailing list or a specialized, highly targeted marketing list, we have the capabilities to provide you with the most up to date and accurate stock investor lists that exist in the industry for your stock promotion campaigns.
With thousands of publicly traded companies in the financial world, it is almost impossible for small but growing companies to attract the attention of the investment world and that is where Email Answers can help.By focusing on timed press releases to the individual Small Cap, OTC, Pink Sheet and Nasdaq investors, our stock promotion programs work extremely well to get your current news into the investors hands in a timely and trustworthy manner.Email Answers has the data and expertise to meet all of your stock promotion needs.Our Stock Promotion Services Consist Of:Email Marketing ListsFull Creative Deployment ServicesNewsletter, Copyrighting and Creative DesignCampaign TrackingMaterial Development: Website, Corporate Packages, Brochures, etc.Direct Marketing ServicesData AcquisitionsNational & Wire Press Releases.
Starting a new business is hectic,
what with obtaining the funding, finding the right location, and leaping all the bureaucratic hurdles the various local, state, and federal governments put in your way. When you’re finally done with the set-up tasks, you may just want to rest on your laurels and take it easy for a while.
While investor sentiment toward stocks has been negatively influenced by the recent volatility in the financial markets, interest in IPO’s has remained steady.
The number of global IPO filings in 2010 is about 120 and indications are that there are many to follow. Of the companies that already have filed, a staggering 65% have come from Asia, with China leading the pack. So the uptick in filings year to date is a global phenomenon, which speaks in part to the resilience of the global economy.
The benefits of going public are fairly universal: greater and more inexpensive access to capital, enhanced opportunities to pursue mergers and acquisitions, increased liquidity for shareholders, a stronger corporate image and another tool to incentivize executives and employees. Here are ways to promote a new public company.
Communication Benefits:
Communication is the affection of every organization. Everything you do in the abode after-effects from communication.
When most people think about communication it is usually speaking that first springs to mind, however, being able to listen well is a large part of effective communication. A major benefit of good communication within the workplace is that it may very likely lead to an improvement in office morale.
Following are a few guidelines to help you become aware of how to take advantage of the benefits and avoid the obstacles.
Learn the 3 Rules:
If an affective media relations program can help you increasing the demand for company stock, then the newly public companies will learn quickly that the rules of the road are very complex, than while operating under the protection of private ownership. Media relation is vital if you know their rules. Come let’s see three basic rules.
Rule 1: Audience Changes
When a company lists its share on a public exchange; its key share holder extend far beyond media, customers, market researchers, business partners, and employees to include financial analysts, share holders, share holders interest groups, and government regulators.
Rule 2: Increase of Scrutiny
Public companies often comes under instance scrutiny and attacks in traditional as well as media such as the blogosphere, which can provide forums for watching investors and disgruntled employees. It also has potential to become hostile.
Rule 3: Avoid being too Strict
Quick period / speed rules strive to lower company awareness in the market just as media and public interact may be picking up, also cost of non compliance with quiet periods and numerous other restrictions may be devastating.
New Communications Approach
New public companies can avoid costly missteps by adopting a new communications approach that addresses all stakeholders and encompasses all pertinent communications disciplines.
Communications Teams for Help:
Communications team members need to function as strategic counselors to management teams and ambassadors to broader staff. They need to clearly understand and advocate the subtle differences between media activity that brings benefit and safety versus potentially risky and damaging during a quiet period – helping to maintain and build company awareness in the market while simultaneously abiding by new regulations.
Investor relations, corporate affairs, public affairs and crisis management must be equipped to manage and contain media reactions during turbulent times though the rapid dissemination of accurate, comprehensive information. It’s much easier for a company to keep its credibility than to rebuild it.
Social Media – a New Communication Approach
Social media as a group of Internet-based applications that build on the ideological and technological foundations of Web 2.0 and it allows the creation and exchange of user generated content. Social media is media for social interaction as a super-set beyond social communication. Enabled by ubiquitously accessible and scalable communication techniques, social media has substantially changed the way of organizations, communities, and individuals communication.
Social Media as practiced with tools like Facebook and Twitter creates an entirely new set of uncharted disclosure issues. On one hand, some companies simply restrict using social media for investor communications, despite the widespread popularity and advantages of these media in crisis situations.
On the other hand, companies may opt toward transparency and provide information in direct opposition to fair and equal disclosure requirements.
Employee Education
The employee communications discipline can take the form of a program aimed at educating employees on behavioral changes and expectations within a newly public company. For example, once a company goes public, employees have no right to material information before other shareholders.
Employees are an especially important group. Experience has proven that employees are more motivated when they clearly understand company actions and decisions and have a sense of personal stake in the outcome.
Despite the desire for transparency, an advice to the clients is—that corporate legal and IR teams must get involved in social media to protect the company from violating disclosure requirements. The risks simply don’t outweigh the benefits.
So what do public relations agencies do?
PR agencies, as opposed to advertising agencies, promote companies or individuals via editorial coverage. This is known as “earned” or “free” media — stories appearing on websites, newspapers, magazines and TV programs — as compared to “paid media” or advertisements.
PR agencies and advertising agencies share the same goals: promoting clients and making them seem as successful, honest, important, exciting or relevant as possible. But the paths to creating awareness are vastly different. Most people understand advertising is paid for by the client and should be viewed with skepticism. Articles or TV appearances in respected publications have the advantage of third-party validation and are generally viewed more favorably.
Ideas Given To Us To Use:
When you build name recognition, your laboratory pops into your dentist-client's mind first. In this tight economy, consider using downtime to develop your public relations (PR) strategy, thereby increasing your exposure while reinforcing trust, loyalty and respect in your relationships.
While PR initiatives are often no- or low-cost, they do require a commitment of time to develop your message and broadcast it regularly through the press, your own media and community involvement. And although success may be hard to quantify in accounting terms, studies show companies that cut back on their investment in PR activities often have a simultaneous decrease in sales.
The two questions to ask when developing a PR plan are: "What information will benefit our clients?" and "How can we broadcast it?"
Following are some ideas for jumpstarting your foray into public relations:
Be Delivered—Through the Newspaper
Is there a hot dental issue in the general media? Call your local paper's health editor and offer to answer any questions he may have.
Send a letter to the editor offering the dental laboratory perspective on concerns about lead in restorations, offshore outsourcing or other issues.
Send a press release to the local newspaper when you have a noteworthy business development, such as opening a new denture department, a 10-year anniversary in business, or hiring new managers. Or, if your employees pitch in for a day at a local charity, send their picture to the paper.
These mentions are the little reminders that keep your name on the tip of many tongues not just of the general public, but also the editors when they're looking for an expert source. More importantly, it validates your credibility to be featured by a third party rather than in your own promotional pieces.
Be Seen as an Expert
Speak before civic organizations and senior groups on relevant patient-education topics, such as restorative options and how healthy smiles affect self esteem and overall health and contribute to helping victims of domestic violence, bulimia or drug abuse get back on their feet.
Offer to speak on these topics on locally produced cable and talk radio as well as at health and wellness fairs.
Be Your Own Media
Develop an e-newsletter for dentists. Use it to call attention to time-saving opportunities on your website, such as customized prescription forms, delivery schedules, impression-taking tips, practice management strategies, and requests for tool and equipment loans if you offer them.
Provide patient education materials for your dentist-clients such as brochures or information sheets on metal-free options, nightguards, understanding the process of try-ins and provisional cases for denture patients.
Be a Part of the Community
As a member of the local business community, you need to network and be involved. Being seen in the community makes it harder for dentists to outsource if they understand that it hurts your business and employees who are, in turn, customers in their local businesses. It may also smooth the way if you need to face your neighbors or the zoning board to expand your facility.
Team up with a dentist and a local nonprofit organization to donate your services to those in need.
Sponsor a work day for your employees to assist a community group or family in need through organizations like the United Way or Habitat for Humanity.
Sponsor a local youth sports team and be amazed by the visability your lab's name will have on the backs of 12 Little Leaguers.
Take out a small ad in your local symphony or chamber music series program book to show that you support organizations that your dentist-clients value (doctors and dentists make up a dedicated demographic that support arts organizations).
What is Investor Relations?
Investor relations is the term used to describe the ongoing activity of companies communicating with the investment community. While the communication that quoted companies undertake is a mix of regulatory and voluntary activities, investor relations
is essentially the part of stock market life that sees companies interacting with existing shareholders, potential investors, analysts and journalists. For many quoted companies, the dialogue will begin in the pre-IPO phase, when the company is profiling itself to what is often a new set of potential investors. Once on market, the communication continues with shareholders and financial market commentators, as well as with other potential investors.Fundamentally, the remit of investor relations is not only to create an awareness and understanding of your company amongst the investment community, it is also to help quoted companies gain access to capital and achieve liquidity in, and fair valuation for their shares. The ability to raise capital and the ease with which
that capital is raised are often seen as key measures as to how successful a company’s investor relations efforts are. Entering into a dialogue and developing relationships with the investment community over time so that its participants become cognisant with the company and its investment proposition is generally seen as a worthwhile exercise when trying to achieve efficient, cost-effective access to capital.
Liquidity:
One of the outcomes quoted companies aim for from their investor relations activities is to attract liquidity – frequency of trading in their shares. Profiling and explaining the company to the investment community on a continual basis can assist in creatinggreater awareness of a company. Depending on the availability of shares, this can then assist a company in attracting pools of buyers and sellers and the potential for higher frequency in the trading of its shares.
5.5 Feedback
Getting Customer Feedback Right
Most companies devote a lot of energy to listening to the “voice of the customer,” but few of them are very happy with the outcome of the effort. Managers have experimented with a wide array of techniques, all useful for some purposes—but all with drawbacks. Elaborate satisfaction surveys that involve proprietary research models can be expensive to conduct and slow to yield findings. Once delivered, their findings can be difficult to convert into practical actions. The results also may be imprecise: Our research shows that most customers who end up defecting to another business have declared themselves “satisfied” or “very satisfied” in such surveys not long before jumping ship. The practice of sending executives out to spend time in the field can generate fresh insights, but few management teams sustain such efforts—and even if they do, they often struggle to convert those insights into prescriptions that frontline employees can follow. Bringing in “power customers”—heavy spenders who tend to be deeply committed to the company—to talk about their experiences can shine a spotlight on critical issues. But frontline employees can’t easily learn about their own behaviors from those customers or develop remedies for the problems they raise.
A growing number of companies have developed effective customer feedback programs that head off those challenges right from the start. Instead of building elaborate, centralized customer research mechanisms, these firms begin their feedback loop at the front line. Employees working there receive evaluations of their performance from the people best able to render an appraisal—the customers they just served. The employees then follow up with willing customers in one-on-one conversations. The objective is to understand in detail what the customers value and what the front line can do to deliver it better. Over time, companies compile the data into a baseline of the customer experience, which they draw upon to make process and policy refinements.
A Five-Point Customer Feedback Checklist we need to follow:
1. Have you reached a consensus on your business’s five most critical “moments of truth” with customers?
2. Do employees and managers get customer feedback routinely, on a daily or weekly basis?
3. Do you let customers know the impact their feedback had on improving your processes?
4. Do you know what percentage of detractors your operations now convert into promoters through service recovery processes?
5. Can you put a dollar value on turning a detractor into a promoter?
The strongest feedback loops do more than just connect customers, the front line, and a few decision makers in management, however; they keep the customer front and center across the entire organization. A number of tactics, such as hiring “mystery shoppers” to test customer service or arranging periodic forums between employees and customers, help strengthen this organization-wide focus. One approach that we believe works well across a range of industries is the Net Promoter Score (NPS), which one of the authors of this article, Fred Reichheld, created seven years ago.
6. Operating Plan
We aspire to be an independent oil and gas company in North America and to provide our shareholders with returns over the long-term. To achieve this, we strive to optimize our capital investments to maximize growth in cash flows, earnings, production and establish reserves. We will do this by:
1.Generating cash flow,
2.Securing financing to acquire our planned acquisitions,
3.Exercising capital discipline,
4.Ensuring financial strength, and
5.Investing in oil and gas properties with strong full-cycle margins.
The Company plans to acquire producing or near producing oil and gas properties that will provide cash flow and an upside for future development. Such activities are concentrated in North America onshore, primarily in the United States. We are currently scouting and evaluating properties in Texas, Oklahoma, Pennsylvania, Kansas and in Canada. There is no assurance that we will be successful in raising the necessary funds to acquire any of producing oil and gas properties.
The implementation of our business plan will require significant capital. We do not have this capital and as a result, we will require additional financing to acquire and develop our leasehold obligations. We may use debt or equity to fund our ongoing operations. There can be no assurance that any financing will be available, and if available, will be on terms and conditions acceptable to the Company. If we rely on equity financing, our shareholders will experience significant dilution. If we rely on debt financing, we may not be able to satisfy our debt obligations.
The Company plans to acquire producing or near producing leaseholds that will provide cash flow and an upside for future development. However, it is unlikely that we will be able to exploit these leaseholds without a significant capital infusion.
The Company may acquire the leaseholds in consideration for cash or shares of the company or a combination of cash and shares of the Company and may include an Overriding Royalty. Typical Overriding Royalty’s range from 2.5% to as much as 25% depending upon the current production on the leaseholds and the potential for Oil and Gas production.
A typical leasehold grants the Company the exclusive right to explore the land (“Property”) covered by the Oil and Gas Lease by geophysical and other methods, and to operate same for and produce there from all naturally-occurring oil, gas, casing-head gas or gasoline, gas condensate and/or all other liquid or gaseous hydrocarbons and other marketable or non-marketable substances produced therewith ("Oil and Gas"); and the exclusive right to inject gas, water, brine and other fluids into subsurface strata; and rights of way and easements for laying pipelines, telephone, telegraph and power lines, and the right to erect or install power stations, compressor stations, roadways, storage tanks or other storage facilities, separators and any fixtures and other structures thereon for producing, treating, processing, maintaining, storing and caring for the oil and gas; and oil and gas from other properties and any and all other rights and privileges necessary, incident to, or convenient for the economical operation of the Property and other lands for the production of Oil and Gas, and the injecting of gas, water, brine and other fluids into subsurface strata.
The Company may, at any time and from time-to-time pool all or part of the Property with other properties to create one or more drilling units. The production of Oil or Gas from such a pooled unit is generally treated as though the production occurred from a well on the Property, except the Lessor shall be entitled to royalty only on its pro-rata share of such production.
It is intended that the leasehold also include all lands and interests of the Lessor, which are contiguous to or in the vicinity of the Property.
Usually the leasehold will remain in force for a term of one year from the date executed and for as long thereafter as Oil and/or Gas is produced from the Property, or as long as operations for drilling are continued or as long as operations are continued for injection of gas, water, brine and other fluids into subsurface strata.
When a well is worked over or offset well drilled, an access road is constructed to the well site or upgraded. This results in surface damages that the surface owner is compensated for the loss of property. Timber may also be cut down during construction, the Company may cut and stack the timber at a location convenient for the surface owner to sell or a value may be assessed on the timber and the surface owner compensated.
Depending upon jurisdiction of the leasehold, the state can force a "pooling" of the oil and gas interests of a landowner with the interests of other landowners where the size or condition of lands does not allow the neighbor to find a drill site while respecting distance limits from property lines. A mineral owner has five options in the context of forced pooling. They can:
1.Lease their mineral interest.
2.Sell their mineral interest.
3.Participate materially in the development of the gas field.
4.Be a non-consenting owner.
5.Protest forced pooling
A rework well or producing well requires maintenance by a company representative sometimes referred to as a “pumper” to insure the well(s) produce at their capacity and to monitor production. As per the terms of the lease, a gate may be installed by the well Operator to prohibit access to the Property by unauthorized personnel. The gate is typically locked and a key may be provided to the landowner. The well may require periodic maintenance by a service rig during the life of the well. Surface equipment includes a wellhead, gas meter, storage tank (for oil wells), separator, and pipeline. Lease is held-by-production during the life of the well(s).
Risks Related to Our Business:
We ceased generating revenue.
We have had limited revenues since inception. We will, in all likelihood, sustain operating expenses without corresponding revenues. This may result in our incurring a net operating loss that will increase unless we consummate an acquisition of an oil and gas producing properties that are profitable. We cannot assure you that we can identify any oil and gas properties that will be profitable at the time of its acquisition by the Company or ever.
Unless we secure additional working capital, the Company can only continue as a going concern for twelve months.
Unless we secure equity, debt financing or Joint Venture partners, of which there can be no assurance, or identify a profitable acquisition candidate, we will not be able to continue any operations for longer than twelve months. We based this estimate on that majority of our operating costs are for salaries of the officers and directors of the Company, which are being accrued. Our negative cash flow is for our auditors, attorneys, transfer agent, EDGAR filer and travel expenses. We have sufficient cash to cover auditors, attorneys, transfer agent, EDGAR filer and limited travel expenses for the next twelve months. After such time, the Company would be forced to cease operations. We will require significant working capital to continue our current development program. There can be no assurance that we will be able to secure additional funding to meet our objectives or if we are able to identify funding sources, that the funding will be available on terms acceptable to the Company. Should this occur, we will have to significantly reduce our development programs, which will limit our ability to secure additional equity participation in acquisitions of oil and gas leases or in various joint ventures.
There may be insufficient oil and gas reserves to develop any of our properties and our estimates may be inaccurate.
There is no certainty that any expenditures made in the development/exploration of any properties will result in discoveries of commercially recoverable quantities of oil or gas. Most development/exploration projects do not result in the discovery of commercially extractable deposits of oil or gas and no assurance can be given that any particular level of recovery will in fact be realized or that any identified leasehold interest will ever qualify as a commercially developed. Estimates of reserves, deposits, and production costs can also be affected by such factors as environmental regulations and requirements, weather, unexpected or unknown results when we re-enter a well, environmental factors, unforeseen technical difficulties, unusual or unexpected geological formations, and work interruptions.
Short term factors relating to reserves, such as the need for orderly development of the wells may also have an adverse effect on our development/exploration, drilling and on the results of operations. There can be no assurance the production of insignificant amounts of oil can be duplicated in a larger exploration program. Material changes in estimated reserves, development/drilling costs may affect the economic viability of any project.
We have no proven reserves.
All of our leasehold interests are without known bodies (reserves) of commercial oil or gas. Development of these properties will follow only upon obtaining satisfactory development/exploration results. The long-term profitability of the Company’s operations will be in part directly related to the cost and success of its development/exploration and development programs. Oil and gas development/exploration and development are highly speculative businesses, involving a high degree of risk. Few properties, which are explored, are ultimately developed into producing oil and gas fields. There is no assurance that our development/exploration and development activities will result in any discoveries of commercial quantities of oil and gas. There is also no assurance that, even if commercial quantities of oil or gas are discovered, a well can be brought into commercial production. Production/discovery of oil and gas is dependent upon a number of factors, not the least of which is the technical skillof the development/exploration personnel involved. The commercial viability of a well is also dependent upon a number of factors, many of which are beyond the Company’s control, such as worldwide economy, the price of oil and gas, government regulations, including regulations relating to royalties, allowable production, and environmental protection.
We face fluctuating oil and prices.
The price of oil and gas has experienced significant price movements over short periods of time and is affected by numerous factors beyond our control, including international economic and political trends, expectations of inflation, currency exchange fluctuations (including, the U.S. dollar relative to other currencies) interest rates, global or regional consumption patterns, speculative activities and increases in production due to improved exploration and d production methods. The supply of and demand for oil and gas are affected by various factors, including political events, economic conditions and production costs in major producing regions.
Drilling operations are hazardous, raise environmental concerns and raise insurance risks.
Drilling operations are by their nature subject to a variety of risks, such as, flooding, environmental hazards, the discharge of toxic chemicals and other hazards. Such occurrences may delay development or production, increase production costs, or result in a liability. We may not be able to insure fully or at all against such risks, due to political or other reasons, or we may decide not to take out insurance against such risks as a result of high premiums or other reasons. We intend to conduct our business in a way that safeguards public health and the environment and in compliance with applicable laws and regulations. Environmental hazards may exist on properties in which we hold an interest which are unknown to us and may have been caused by prior owners. Changes to drilling laws and regulations could require additional capital expenditures and increase operating and/or reclamation costs. Although we are unable to predict what additional legislation, if any, might be proposed or enacted, additional regulatory requirements could render certain operations uneconomic.
Our estimates of resources are subject to uncertainty. The cost of employing this technology maybe cost prohibitive or the cost may exceed the benefit.
Under current SEC standards, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our leases, we would have to employ technologies that have been demonstrated to yield results with consistency and repeatability. The technical data used in the estimation of proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Generally, oil and gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations. Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technical data to assess the reservoir continuity. In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities. Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs, and completion flow data. When using production decline curve analysis or analogy to estimate proved reserves, they would be limited to estimates to the quantities of oil and gas derived through volumetric calculations.
The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering, and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves and future cash flows are based on various assumptions and are inherently imprecise. Even though these estimates may be reasonable and logical, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which the oil and natural gas industry in general are subject.
The oil and gas industry is highly competitive and the success and future growth of our business depend upon our ability to remain competitive in identifying and developing properties with sufficient reserves for economic exploitation.
The oil and gas industry is highly competitive and fragmented with limited barriers to entry, especially at the exploratory stages. We compete in national, regional, and local markets with large multi-national corporations and against start-up operators hoping to identify an oil or gas property. Some of our competitors have significantly greater financial resources than we do. This puts us at a competitive disadvantage if we choose to further exploit development opportunities.
The loss of key members of our senior management team could adversely affect the execution of our business strategy and
our financial results.
We believe that the successful execution of our business strategy and our ability to move beyond the exploratory stages depends on the continued employment of key members of our senior management team. If any members of our senior management team become unable or unwilling to continue in their present positions, our financial results and our business could be materially adversely affected.
Risks Related to Our Stockholders and Shares of Common Stock
We have a large number of authorized but unissued shares of our common stock.
We have a large number of authorized but unissued shares of common stock, which our management may issue without further stockholder approval, thereby causing dilution of your holdings of our common stock. Our management will continue to have broad discretion to issue shares of our common stock in a range of transactions, including capital-raising transactions, mergers, acquisitions and in other transactions, without obtaining stockholder approval, unless stockholder approval is required. If our management determines to issue shares of our common stock from the large pool of authorized but unissued shares for any purpose in the future, your ownership position would be diluted without your further ability to vote on that transaction.
Shares of our common stock may continue to be subject to price volatility and illiquidity because our shares may continue to be thinly traded and may never become eligible for trading on a national securities exchange.
While we may at some point be able to meet the requirements necessary for our common stock to be listed on a national securities exchange, we cannot assure you that we will ever achieve a listing of our common stock on a national securities exchange. Our shares are currently only eligible for quotation on the Over-The-Counter Bulletin Board, which is not an exchange. Initial listing on a national securities exchange is subject to a variety of requirements, including minimum trading price and minimum public “float” requirements, and could also be affected by the general skepticism of such markets concerning companies that are the result of mergers with inactive publicly-held companies. There are also continuing eligibility requirements for companies listed on public trading markets. If we are unable to satisfy the initial or continuing eligibility requirements of any such market, then our stock may not be listed or could be delisted. This could result in a lower trading price for our common stock and may limit your ability to sell your shares, any of which could result in you losing some or all of your investments.
The market valuation of our business may fluctuate due to factors beyond our control and the value of your investment may fluctuate correspondingly.
The market valuation of emerging growth companies, such as us, frequently fluctuate due to factors unrelated to the past or present operating performance of such companies. Our market valuation may fluctuate significantly in response to a number of factors, many of which are beyond our control, including:
i.changes in securities analysts’ estimates of our financial performance, although there are currently no analysts covering our stock;
ii.fluctuations in stock market prices and volumes, particularly among securities of emerging growth companies;
iii.changes in market valuations of similar companies;
iv.announcements by us or our competitors of significant contracts, new technologies, acquisitions, commercial relationships, joint ventures or capital commitments;
v.variations in our quarterly operating results;
vi.fluctuations in related commodities prices; and
vii.additions or departures of key personnel.
As a result, the value of your investment in us may fluctuate.
Investors should not look to dividends as a source of income.
In the interest of reinvesting initial profits back into our business, we do not intend to pay cash dividends in the foreseeable future. Consequently, any economic return will initially be derived, if at all, from appreciation in the fair market value of our stock, and not as a result of dividend payments.
We expect to issue more shares in an equity financing, which will result in substantial dilution..
Our Articles of Incorporation authorize the Company to issue 900,000,000 shares of common stock. Any equity financing effected by the Company may result in the issuance of additional securities without stockholder approval and may result in substantial dilution in the percentage of our common stock held by our then existing stockholders. Moreover, our common stock issued in any equity financing transaction may be valued on an arbitrary or non-arm’s-length basis by our management, resulting in an additional reduction in the percentage of common stock held by our then existing stockholders. Our board of directors has the power to issue any or all of such authorized but unissued shares without stockholder approval. To the extent that additional shares of common stock or preferred stock are issued in connection with a business combination or otherwise, dilution to the interests of our stockholders will occur and the rights of the holders of common stock might be materially adversely affected.
The Selling Stockholder (anyone whom buys shares from our company treasury) and any of its pledgees, donees, assignees and other successors-in-interest may, from time to time sell any or all of their shares of common stock on any stock exchange, market or trading facility on which the shares are traded or in private transactions. These sales may be at fixed or negotiated prices. The Selling Stockholder may use any one or more of the following methods when selling shares:
·ordinary brokerage transactions and transactions in which the broker-dealer solicits the purchaser;
·block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion
of the block as principal
·facilitate the transaction
·purchases by a broker-dealer as principal and resale by the broker-dealer for its account
·an exchange distribution in accordance with the rules of the applicable exchange
·privately negotiated transactions
·broker-dealers may agree with the Selling Stockholder to sell a specified number of such shares at a stipulated price per share
·through the writing of options on the shares
·a combination of any such methods of sale
·any other method permitted pursuant to applicable law
The Selling Stockholder shall have the sole and absolute discretion not to accept any purchase offer or make any sale of shares if it deems the purchase price to be unsatisfactory at any particular time.
The Selling Stockholder may also sell the shares directly to market makers acting as principals and/or broker-dealers acting as agents for themselves or their customers. Such broker-dealers may receive compensation in the form of discounts, concessions or commissions from the Selling Stockholder and/or the purchasers of shares for whom such broker-dealers may act as agents or to whom they sell as principal or both, which compensation as to a particular broker-dealer might be in excess of customary commissions. Market makers and block purchasers purchasing the shares will do so for their own account and at their own risk. It is possible that the Selling Stockholder will attempt to sell shares of common stock in block transactions to market makers or other purchasers at a price per share which may be below the then existing market price. We cannot assure that all or any of the shares offered in this prospectus will be issued to, or sold by, the Selling Stockholder. The Selling Stockholder and any broker-dealers or agents, upon completing the sale of any of the shares offered in this prospectus, may be deemed to be "underwriters" as that term is defined under the Securities Act, the Exchange Act and the rules and regulations of such acts. In such event, any commissions received by such broker-dealers or agents and any profit on the resale of the shares purchased by them may be deemed to be underwriting commissions or discounts
under the Securities Act.
We are required to pay all fees and expenses incident to the registration of the shares. The Selling Stockholder, alternatively, may sell all or any part of the shares offered in this prospectus through an underwriter. The Selling Stockholder has not entered into any agreement with a prospective underwriter and there is no assurance that any such agreement will be entered into.
The Selling Stockholder may pledge its shares to its brokers under the margin provisions of customer agreements. If the Selling Stockholder defaults on a margin loan, the broker may, from time to time, offer and sell the pledged shares. The Selling Stockholder and any other persons participating in the sale or distribution of the shares will be subject to applicable provisions of the Exchange Act, and the rules and regulations under such act, including, without limitation, Regulation M. These provisions may restrict certain activities of, and limit the timing of purchases and sales of any of the shares by, the Selling Stockholder or any other such person. The Selling Stockholder is not permitted to engage in short sales of common stock. Furthermore, under Regulation M, persons engaged in a distribution of securities are prohibited from simultaneously engaging in market making and certain other activities with respect to such securities for a specified period of time prior to the commencement of such distributions, subject to specified exceptions or exemptions. All of these limitations may affect the marketability of the shares.
6.1 Location
Company Operations
The Company is engaged primarily in the acquisition of producing or near producing oil and gas properties and the development of these oil and gas properties. The Company plans to acquire producing or near producing oil and gas properties that will provide cash flow and an upside for future development. Such activities are concentrated in North America onshore, primarily in the United States. We are currently scouting and evaluating properties in Texas, Oklahoma, Pennsylvania, Kansas and as well in Canada.
The Company may acquire the leaseholds in consideration for cash or shares of the company or a combination of cash and shares of the Company and may include an Overriding Royalty. Typical Overriding Royalty’s range from 2.5% to as much as 25% depending upon the current production on the leaseholds and the potential for Oil and Gas production. The Company may, at any time and from time-to-time pool all or part of the Property with other properties to create one or more drilling units. The production of Oil or Gas from such a pooled unit is generally treated as though the production occurred from a well on the Property, except the Lessor shall be entitled to royalty only on its pro-rata share of such production. Usually the leasehold will remain in force for a term of one year from the date executed and for as long thereafter as Oil and/or Gas is produced from the Property, or as long as operations for drilling are continued or as long as operations are continued for injection of gas, water, brine and other fluids into subsurface strata.
THE NOW CORPORATION AGREES TO REWORK 147 WELLS:
A rework well or producing well requires maintenance by a company representative sometimes referred to as a “pumper” to insure the well(s) produce at their capacity and to monitor production. As per the terms of the lease, a gate may be installed by the well Operator to prohibit access to the Property by unauthorized personnel. The gate is typically locked and a key may be provided to the landowner. The well may require periodic maintenance by a service rig during the life of the well. Surface equipment includes a wellhead, gas meter, storage tank (for oil wells), separator, and pipeline. Lease is held-by-production during the life of the well(s). When the well is no longer considered productive, the Company is required to plug the well under the direction of the Division of Oil and Gas inspector for the State. This involves placing cement plugs at various depths to isolate producing intervals, protect fresh water aquifers and coal seams. The site is reclaimed and vegetation is established to prevent erosion from the well site. After all wells on a lease are plugged, the lease is terminated and returned to the mineral owner.
After completion and testing of a workover well or an offset well, the well is put into production. As in the case of oil, the oil is pumped into a 100 BBL or 200 BBL tank(s). The pumper inspects the well on a daily or regular routine basis and monitors the production of oil. As the tank(s) nears capacity, the pumper will make arrangements for pickup of the oil for delivery to the Purchaser. The cost of hauling the oil to the refinery varies by distance from the well to the refinery and can range from $3 to $6 per BBL. The cost of the freight charge is borne by the Company. Oil collected or shipped during the month is paid by the Purchaser in the following month. The price paid for the produced oil is based on the average monthly market price.
Conflicts of Interest:
Management is not required to commit their full time to our affairs and, accordingly, such persons may have conflicts of interest in allocating management time among various business activities. Our affiliates, officers, and directors may engage in other business activities similar and dissimilar to those we are engaged in. To the extent that management engages in such other activities, they will have possible conflicts of interest in diverting opportunities to other companies, entities, or persons with which they are or may be associated or have an interest, rather than diverting such opportunities to us. As no policy has been established for the resolution of such a conflict, we could be adversely affected should management choose to place their other business interests before ours. No assurance can be given that such potential conflicts of interest will not cause us to lose potential opportunities. Management may become aware of investment and business opportunities, which may be appropriate for presentation to us as well as the other entities with which they are affiliated. Management may have conflicts of interest in determining which entity a particular business opportunity should be presented. Accordingly, as a result of multiple business affiliations, management may have similar legal obligations relating to presenting certain business opportunities to multiple entities. In addition, conflicts of interest may arise in connection with evaluations of a particular business opportunity by the board of directors with respect to the foregoing criteria. There can be no assurances that any of the foregoing conflicts will be resolved in our favor. We may consider Business Combinations with entities owned or controlled by persons other than those persons described above. There can be no assurances that any of the foregoing conflicts will be resolved in our favor.
Forward-Looking Statements:
Certain statements, other than purely historical information, including estimates, projections, statements relating to our business plans, objectives, and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act and Section 21E of the Exchange Act. These forward-looking statements generally are identified by the words “believes,” “project,” “expects,” “anticipates,” “estimates,” “intends,” “strategy,” “plan,” “may,” “will,” “would,” “will be,” “will continue,” “will likely result,” and similar expressions. We intend such forward-looking statements to be covered by the safe-harbor provisions for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995, and are including this statement for purposes of complying with those safe-harbor provisions. Forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties, which may cause actual results to differ materially from the forward-looking statements. Our ability to predict results or the actual effect of future plans or strategies is inherently uncertain. Factors which could have a material adverse effect on our operations and future prospects on a consolidated basis include, but are not limited to: changes in economic conditions, legislative/regulatory changes, availability of capital, interest rates, competition, and generally accepted accounting principles. These risks and uncertainties should also be considered in evaluating forward-looking statements and undue reliance should not be placed on such statements. We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Further information concerning our business, including additional factors that could materially affect our financial results, is included herein.
Our primary financial resource is our base of our unproven oil and gas leases. Our ability to fund our capital expenditure program is dependent upon the availability of capital resource financing. In the next fiscal year, we plan on spending approximately $1.4 MILLION DOLLARS in new capital investments for a 147well offset drilling program including exercising our option for an additional 40 oil and gas wells. However our actual expenditures may vary significantly from this estimate if our plans for to obtain financing changes during the year. Factors such as changes in operating margins due to changes in the price of oil and gas and the availability of capital resources could increase or decrease our ultimate level of expenditures during the next fiscal year.
Governmental Regulations:
The oil and natural gas industry is subject to various types of regulation throughout the world. Laws, rules, regulations, and other policy implementations affecting the oil and natural gas industry have been pervasive and are under constant review for amendment or expansion. Pursuant to public policy changes, numerous government agencies have issued extensive laws and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas exploration, production and marketing and midstream activities. These laws and regulations increase the cost of doing business and, consequently, affect profitability. Because public policy changes affecting the oil and natural gas industry are commonplace and because existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. However, we do not expect that any of these laws and regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size and financial strength.
WHY PENNSYLVANIA FOR LOCATION:
The Pennsylvania oil rush was a boom in petroleum production which occurred in northwestern Pennsylvania from 1859 to the early 1870s. It was the first oil boom in the United States.
The oil rush began in Titusville, Pennsylvania, in the Oil Creek Valley when Colonel Edwin L. Drake struck "rock oil" there. Titusville and other towns on the shores of Oil Creek expanded rapidly as oil wells and refineries shot up across the region. Oil quickly became one of the most valuable commodities in the United States and railroads expanded into Western Pennsylvania to ship petroleum to the rest of the country.
By the mid-1870s, the oil industry was well established, and the "rush" to drill wells and control production was over. Pennsylvania oil production peaked in 1891, and was later surpassed by western states such as Texas and California, but some oil industry remains in Pennsylvania.
Pennsylvania is one of four states looking to capture some of the excess profits enjoyed by the nation’s major oil companies. It is no wonder. In 2006, Exxon Mobil made $39.5 billion in profit on $365 billion in revenue. In contrast, Wal-Mart, the nation’s number two company, earned $11.3 billion, just one-third of Exxon’s profits, on revenues of $345 billion. As citizens have struggled to pay the rising cost of gasoline in the past five years, the profits of major oil companies increased by 344%. The strong world demand for oil, coupled with increased concentration and reduced competition in the industry, will likely result in high oil company profit levels for the foreseeable future.
Even when oil companies have record profits, however, Pennsylvania’s porous corporate tax system currently makes it possible for large corporations, like Exxon Mobil, Chevron, and ConocoPhillips, to shelter billions of dollars of income from taxation. Using transfer pricing and other “paper profit” minimizing techniques, oil companies have the ability to shift profits to low-tax states and nations, reducing their Pennsylvania tax liability
There's a lot of reasons, apparently, why New York should perhaps follow Pennsylvania's lead and lift its self-imposed moratorium. Here are some of them:
Pennsylvania counties with hydrofractured gas wells have performed better across economic indicators than those that have no wells.
The more wells a county contains, the better it performed.
Between 2007 and 2011, per-capita income rose by 19 percent in Pennsylvania counties with more than 200 wells, by 14 percent in counties with between 20 and 200 wells, and by 12 percent in counties with fewer than 20 wells.
In counties without any hydrofractured wells, income went up by only 8 percent.
Counties with the lowest per-capita incomes experienced the most rapid growth.
Counties with more than 200 wells added jobs at a 7 percent annual rate over the same time period.
Where there was no drilling, or only a few wells, the number of county jobs shrank by 3 percent.
Pennsylvania and the entire Appalachian basin in general are referred to as a “mature basin” because there has been more than 100 year of active drilling. So far, drilling activity has occurred primarily within thetop 3,000 to 5,000 feet in a basin that contains up to 30,000 feet of sediments. Some gas fields are producing from depths of 8,000 to 9,000 feet.
Exploration is ongoing for natural gas at depths upwards of 10,000 feet. More oil and gas are being discovered each year, and additional supplies are waiting to be discovered in the future.THE FUTURE OF OIL AND GAS, What have we taken and what’s left?
Since Drake’s discovery of oil in 1859, Pennsylvania oil fields haveproduced more than 1.4 billion barrels of crude oil. That’s more thanenough oil to fill 6.5 million swimming pools 20 feet in diameter and 4 feet deep. Natural gas production has exceeded 1.07 trillion cubic feet, Pennsylvania crude oil is so highly valued because the waxy, sweet paraffinic oils make high quality lubricating oils and greases.
6.2 Facility
When an oilman’s gamble pays off with a producing oil well, much remains to be done before the oil can make it to market. In 1859, “Colonel” Edwin Drake used a common water well hand pump to retrieve oil from 69.5 feet. It wasn’t long before necessity and ingenuity ombined to find something more efficient.
Oil wells will run dry, but advances in technologies can put off the inevitable. Even with the best technologies, more than half of the oil can remain trapped. The evolution of oil production is reflected in thousands of marginally producing oil and natural gas wells quietly reaching for often stubborn reserves. Low-volume “stripper” wells produce no more than 15 barrels a day.
The average stripper well produces only about 2.2 barrels per day. However, according to the Independent Petroleum Association of America (IPAA), these wells comprise 84 percent of domestic oil wells and produce over 20 percent of all domestic oil – an amount roughly equal to imports
Walking Beam Compressors:
Oil Well DiagramOil wells that use pumping units to artificially lift oil from the well are also wells that generally produce natural gas in addition to oil.When the ground oil-formation releases oil into the well bore, the formation also releases natural gas into the casing annulus. The annulus is the volumetric space between the inside diameter of the casing and the outside diameter of the tubing that is located within the casing. The tubing is thestring of pipe through which the sucker-rod string operates the down-hole oil pump attached to the bottom of the tubing-string (see pic, click to enlarge). The down-hole pump forces the oil up through the tubing to the well-head, and then into the flow line away from the well-head.The oil formation pressure moves oil from the formation into the well-bore, specifically into the casing annulus at the location of the down-hole pump.
As oil is released from the formation into the well bore, gas is also released from the oil formation. This released gas will fill the annulus all the way up to the surface casing-head. When the casing-head gas pressure becomes equal to or exceeds the flow line pressure, the gas leaves the casing-head and enters the same flow line as does the well-head oil.
The accumulated gas in the casing annulus exerts a back-pressure on the down-hole oil formation. This down-hole back pressure (hydrostatic pressure) acts on the oil formation in a manner to prevent or restrict free flow of oil and gas from the formation.When the hydrostatic pressure created by the casing gas is reduced, flow of oil and gas from the formation increases, and thus production of oil and gas increases.
For more than one hundred years, various means of “well head compression” have been used to reduce the hydrostatic pressure by removing the casing gas. Well Head Compression refers to the removal of casing-head gas, and the compression of that gas into the higher pressure flow line. Many types of conventional compressors have been used over the years in attempts to successfully and reliably reduce hydrostatic pressure through removal of casing-head gas. Most of the past attempts were forced-lubrication units that required considerable maintenance, adjustments, and attention. And they were prone to continual failures for lack of adequate and practical technology.
Walking beam compressors, while in use now for years have often been saddled with maintenance and other performace issues that make them a risky investment. In recent years, new technology and operating strategies have been developed that easily overcome previous detriments to walking beam compressors. This fact, coupled with the spiraling price of crude oil and gas make these compressors not only financially viable, but quite profitable to use.
One particular walking beam compressor, the Oil Flow Compressor (OFC) was developed in the period since 1992 using state-of-the-art materials, seals, and engineering technology. The result is the world’s unique walking beam gas compressor. It’s powered by the force of the walking beam of a typical pumping unit. Power requirement for the OFC is approximately 3 to 7 horsepower. Both maintenance free and adjustment free, replacement of seals is typically required, at minor cost, about every eight (8) months of continuous operation.
As the primary oil reserves have played out in the old Trenton Oil field in the Midwest U.S., and other regions, small independent oil producing companies in the U.S. have difficulty producing oil using the traditional technology of pump jacks, down hole steel rods, steel tubing, and cups.
Shallow stripper well production is generally uneconomic for several reasons:
• the low oil output of stripper wells (<10 barrels a day) provides less funding to pay labor costs for normal pump-jack maintenance
• pump jack equipment experiences significant wear-and-tear, leading to low reliability and significant downtime for repairs
• the corrosive chemical environment (including salt water and acids) of the shallow wells destroys the equipment Even though a well may still be producing small quantities of oil, the well is capped because the cost to operate such wells has proven to be non-productive.
Starting in 1997, Energy, Inc. began development of a new oil pumping system. Called Airlift, the new pump featured off-the-shelf PVC construction and virtually no moving parts. It relied on pressurized air to force oil through a series of stages until reaching the surface. The design of the unit has solved the problems facing traditional pump-jack equipment, namely reliability and corrosion. As added benefits, the design was safer, environmentally friendly, and required less maintenance. Potentially, the Airlift unit would allow thousands of old abandoned stripper wells to become economically feasible again due to low operating costs.The first version of the Airlift, later referred to as Gen 1, was tested from 1997 to 2000 in a few stripper wells. These earlier tests of the first version indicated the concept was sound, hence the current DOE grant was received in 2000 to take the technology to the next stage of success.
6.3 Operating Equipment
Fundamentally, there are three challenges small producers face in keeping their stripper wells on line. The first is basic economics, the second is basic physics, and the third is access to technology. Because stripper wells operate close to the edge of profitability, if oil and gas prices fall, the value of the oil or gas produced each day can quickly drop below the average daily cost of operating the wells. These costs include maintaining and operating pumps, transporting the produced oil or gas for sale, safe disposal of produced water, salaries, insurance, taxes and of course the royalties paid to the owners of the mineral rights.
Any technology or new operating practice that can help to lower the cost of operating a stripper well directly influences the limit of profitability and the time that well can be kept producing.
Physics controls how fast the oil, gas and water flow into the wellbore from the reservoir, and how difficult it can be to lift the fluids to the surface. Keeping stripper gas wells clear of water so that gas can flow more freely into the wellbore is a major challenge. Remediating wellbore damage so that oil and gas can both flow at higher rates is another. Optimizing the downhole and surface production equipment so that a stripper well produces the maximum amount of oil and gas for the minimum amount of power cost is yet another challenge.
Reducing costs and overcoming the physics of production both rely on technology. Unfortunately, most stripper well producers have neither the dollars nor the manpower to invest in developing new technology tools. In addition, most technology providers do not recognize the widely dispersed, marginal operations of the stripper well industry as a major market.
Mechanical failures are the cause of nearly one quarter of the abnormal production declines seen in stripper gas wells. These mechanical failures are most commonly the result of corrosion, often exacerbated by the build up of corrosive brine in wellbores or its movement through production equipment. Marginal well operators must react to corrosion-sourced mechanical failures, but typically do not follow a proactive methodology for identifying problem areas and selecting the appropriate corrosion mitigation alternative before the failure takes place. As a result, opportunities for reducing failure rates and increasing production are missed.
Research suggests that 86 percent of failures in plunger lift systems are a result of corrosion damage brought on by produced brine. The inability to effectively deliver corrosion inhibitor to plunger lift wells leads to equipment failure, high operating costs, and premature abandonment.
Oil Stripper Well possible equipment used for the stripper well pumpin oil to the surface.
All Airwell stripper oil well equipment is available for purchase or hire, subject to availability and location. In some areas Airwell also offer a contract pumping service.
Contract Pumping Service
Airwell Oil & Gas can offer a complete contract pumping service.
For a daily hire fee they will provide the following services:
Supply of all pumping equipment
Installation of all pumping equipment
Maintenance of all pumping equipment
Monitoring and reporting of pumped fluids
For more information on a Airwell Oil & Gas contract pumping service please go to the contact us page.
Terms and Conditions Apply.
Features of the Airwell Oil & Gas Pump:
Optimizing Low Flow Wells
Even though Airwell Pumping Systems are capable of higher flows, they have traditionally received the most acclaim for their ability to pump wells with low flow rates. An Airwell Pumping System will optimize the well production by automatically adjusting its flow to match the production of the well, even down to zero flow rate. There is little risk of costly pumping downtime from damaged pump equipment in low flow pumping situations.
Centralised Power Supply Requirements For Multiple Pump Sites
With an Airwell Pumping System it is only necessary to have a power source available at one central location. From this point the energy (compressed air) is directed to the various wells using a high pressure air hose. A well location could be up to 2 miles (3.2 kilometres) from the power source. This means that every pump has a 24/7 power supply. This is especially important when optimizing low production wells.
High "Down Well" Reliability
An Airwell Pumping System has minimal moving parts and only quality materials have been used in their manufacture. This makes the patented Aiwell Oil & Gas pumps very reliable and reduces the pumping down time experienced by other sytems in the event of equipment breakdown. Much of the maintenance process is completed at surface level. This means that maintenance can be done efficiently and with less intereference to the well's productivity.
Remote System Monitoring
An Airwell Oil & Gas system will be monitored daily from one of their offices. Airwell Oil & Gas staff are able to monitor and provide clients with regular information on:
Total volumes of fluids pumped from individual wells
Current tanks levels
Percentage of oil / water split in tanks
All of this information can be emailed to a client in a daily or weekly report. Full tank alerts can also be provided.
Low Environmental Impact
The risk of oil leaks at the well head is greatly reduced with an Airwell Pumping System, as there is no sucker rod and stuffing box at the surface. This lessens the potential environment impact on a site. The use of multiple Airwell pumps from one centrally located air compressor also eliminates the need to supply power or run separate petrol engines to each well, as is currently required for existing pump jacks. In addition, an Airwell Pumping System is quieter and more visually appealing as it has no moving parts or petrol motors at the head of the well.
Airwell Oil & Gas are committed to providing long-term customer service and satisfaction by providing an affordable and reliable oil and gas pumping system to the Oil and Gas Industry.
Tech Specs:
Pumping Principal
The pumping systems developed by Airwell Oil & Gas utilise the Direct Gas Displacement Principle.
The Airwell Pumping system employs a displacement vessel pumping unit that is set down the well combined with a control unit at the surface. This control unit monitors the pumping unit in real time, allowing the pump to passively fill at the natural production rate of the well.
Once the control unit has sensed that the pumping unit is full of fluid the controller at the surface will pressurize the pump vessel with gas and displace its contents.
The control unit will then sense when the vessel is empty and release the pressure allowing the vessel to refill.
Maximum Heads Achievable
3,280 feet (1,000 meters) or 8,000 feet (2,438 meters)
Distance from Power
With the Airwell System it has been possible to run a large number of pumps up to 6.2 miles (10 kilometers) from one centrally located power source. Even though it is possible to run gas lines further, it is preferable that any wells are within a radius of 2 miles (3.2 Kilometres) from any particular power source.
Flow Rates
All Airwell Oil & Gas pumps are capable of pumping down to a flow rate of 0 BBLs / Day without risk of damage to the equipment.
(Standard)
The highest flow rates experienced with the standard pump to date was 130 BBLs / Day at a depth of 1,200 feet (365 meters). However the main market for this pump will be for wells producing under 50 BBLs / Day.
(High Flow)
This variant of the standard Airwell Oil & Gas technology,will allow this range of pumps to recover from zero to 500 barrels of fluid per day from depths in excess of 8,000 feet (2,438 meters).
Telemetry and Control
Airwell provide a full tange of telemetry and control products service for Pumping, Well and Associated Equipment.
6.4 Suppliers and Vendors
One out of every six barrels of crude oil produced in the United States comes from a stripper well, which is the common industry name for a marginal well whose production has slowed to 10 barrels a day or less.
The consortium is managed and administered by The Pennsylvania State University on behalf of DOE; the Office of Fossil Energy’s National Energy Technology Laboratory, better known as NETL, and the New York State Energy Research and Development Authority. Together they provide base funding and technical guidance to the program.
Once a well is plugged and abandoned, the oil and gas reserves left behind are “lost forever” since it is typically uneconomical to drill another well to recover these abandoned reserves. Every dollar of stripper oil and natural gas production creates roughly one dollar of economic activity and nearly 10 jobs result from every million dollars of marginal well oil and natural gas produced, DOE said in its press release.
Once a well is plugged oil is lost forever
A common misperception, DOE said in a description of the program on its website, is that oil left behind remains readily available for production when, say, oil prices rise again. In most instances, this is not the case, the agency said, “leaving our nation more dependent on foreign oil imports.”
Why wouldn’t the oil be readily available in the future?
Because when marginal fields are abandoned, the surface infrastructure—the pumps, piping, storage vessels and other processing equipment—is removed and the lease forfeited. Since much of this equipment was probably installed over many years, replacing it over a short period is “enormously expensive,” DOE said.
“Oil prices would have to stay at today's elevated record levels for many years before there would be sufficient economic justification to bring many marginal fields back into production,” so once abandoned the oil in the ground is “often lost forever” … because “the costs of re-drilling a plugged well may be as much as or more than drilling a new well.”
From 1998 through 2007, on average each year over 3 percent of marginal wells were plugged and abandoned, DOE said. In total, this is more than 124,000 marginal wells, representing a number equal to 25 percent of all operating oil wells in 2007.
Although the situation is less severe for natural gas, there is nonetheless a growing concern about the premature abandonment of gas stripper wells. (A stripper gas well is defined by the Interstate Oil and Gas Compact Commission, which represents the governors of oil and natural gas producing states, as one that produces 60 thousand cubic feet or less of gas per day.)
One consortium project by Vortex Flow has developed downhole tools that reduce pressure drop thereby reducing the gas flow needed to lift liquids up the wellbore, DOE said. This novel technology received the Platts 2004 Newcomer of the Year Award, one of the most prestigious award programs in the industry.
Consortium’s success led to extension
Nearly 100 projects have been funded since the initiation of the Stripper Well Consortium, which is made up of small domestic oil and natural gas producers, as well as service and supply companies, trade associations, industry consultants, technology entrepreneurs and academia.
Per DOE, “the successful development and commercialization of many of these projects provided the incentive for DOE to continue program funding,” when almost all other oil and gas research programs have been cut.
Some of the programs other successes include a pump that removes fluids (hydrocarbons and water) from a well more consistently than currently available systems; a “vortex flow unit” that works like a tornado, using natural gas that has already been produced to accelerate water velocity, reduce friction, and assist in lifting and removing fluids, resulting in increased production while reducing the amount of down-time due to water in gas gathering lines; a new hydraulic diaphragm submersible pump that continuously cleans wells which, among other things, reduces electric costs; a low-cost, real-time, down-hole wireless gauge that measures temperature and pressure, eliminating the need for cables, clamps and splices in the well, thus significantly lowering cost and time; and a technology that captures information at the wellhead and transmits it wirelessly to a control room at a remote location, allowing the operator to monitor hundreds of wells from a single location.
The SWC is an industry-driven consortium that is focused on the development, demonstration, and deployment of new technologies needed to improve the production performance of natural gas and petroleum stripper wells. SWC is comprised of natural gas and petroleum producers, service companies, industry consultants, universities, and industrial trade organizations. The Strategic Center for Natural Gas and the New York State Energy Research and Development Authority provide base funding and guidance to the consortium. By pooling financial and human resources, the SWC membership can economically develop technologies that will extend the life and production of the nation's stripper wells.
Organizational Structure
SWC is industry-driven and is tailored to meet the needs of its members. Active industrial participation and leadership is key to making the consortium a success. The SWC has a Constitution and Bylaws under which the consortium will be governed to operate. Each SWC member appoints one representative to a Technical Advisory Committee. The Technical Advisory Committee is responsible for steering the technical direction of the consortium and is responsible for electing a seven-member Executive Council. The Executive Council is responsible for selecting proposed research projects that will lead to improving natural gas/ petroleum production from stripper wells. The process of having industry develop, review, and select projects for funding will ensure that the consortium conducts research that is relevant and timely to the natural gas and petroleum industry.
Technology Development
Research will be conducted in three broad areas: reservoir remediation, wellbore clean-up, and surface system optimization. Research outside of these three areas may be considered pending approval of the program sponsors. Specific research projects will be developed by the membership using a standardized proposal template. Proposal submission is limited to full members of the consortium. Collaboration between full members is encouraged. Projects will be funded on an annual basis. Each proposal is required to provide a minimum of 30% cost share which is to be provided by the project participants. Cost share may be in the form of cash and/or in-kind support. The use of Federal funds for cost share is prohibited. Intellectual property provisions will follow Penn State's Cooperative Agreement with DOE.
Stripper Well Consortium aids America’s small Producers
The Stripper Well Consortium (SWC) is an industry-driven consortium focused on the development, demonstration and deployment of new technologies needed to improve the production performance of natural gas and petroleum stripper wells. The term stripper well denotes a well producing no more than 10 barrels of oil per day or 60,000 cubic feet of gas per day. One out of every six barrels of crude produced today comes from a stripper well. Over 85 percent of the total number of U.S. oil wells are now classified as stripper wells. Together, these nearly 400,000 wells produce around 800,000 barrels of oil per day or nearly 10 percent of lower-48 production. Many of these wells are marginally economic and at risk of being prematurely abandoned, leaving significant amounts of oil unrecovered. In addition, there are some 320,000 natural gas stripper wells in the U.S., accounting for over 1.7 trillion cubic feet of annual production, or 9 percent of the natural gas produced in the lower 48.
SWC Project 1:
Improved Pump-off Controls Help to Maximize Production
Beam pumped wells wrestle with subtle fluid level issues that can make production optimization challenging. If the fluid level in the wellbore is allowed to increase, the increased hydrostatic pressure on the producing reservoir can inhibit the inflow of formation fluids, thereby lowering production. If, on the other hand, beam pumped wells are “pumped off” (i.e., all the fluid is pumped from the wellbore), the pump and rods operate without liquid lubrication, leading to excessive wear on fluid seals and moving parts. This situation can also result in an unbalanced pumping system. Neither of these scenarios is desirable. In the ideal situation, the beam pumping unit would automatically shut off just before all the fluids had been pumped from the wellbore and then begin operation again when the fluid level in the wellbore reaches an optimal level. Until recently, this ideal has been approached through the use of trial-and-error manipulation of timers, with mixed degrees of success. Pre-Pump-Off Controls, a set of technologies developed by Oil Well Sentry, Inc. with support from the Stripper Well Consortium, promises to eliminate troublesome fluid level issues in beam pumped wells. The system works by monitoring each pump stroke for the normal level of fluid refilling the working barrel at the bottom of the well. When the normal level decreases because pump-off is approaching, the motor or engine stops the cycle in 2-3 pump strokes (Figure 1).
Closely monitoring the fluid levels allows for a balance to be achieved between crude oil production time (pumping to pump-off) and the
number of pumping cycles. Typically, using the Well Sentry system allows for an increase in the number of cycles per day, with the pumping times tailored to actual well conditions. Although the pumping time per cycle may be decreased, net production can be significantly increased while energy consumption can be decreased by 30 percent.In addition to stroke-by-stroke fluid level monitoring, the technologies employ a meter that records the exact time of actual production in 6 minute increments. If the meter is checked and reset daily, the average daily pumping times can be compared and a “normal” production time determined for future operation. This reduces the need for physical observation of each well by the lease operator and eliminates guesswork as to how to adjust the system.
Several sensor packages are available in the Well Sentry line, each tailored to specific well parameters. The fluid level sensor measures the fluid level in the working barrel of the pump. The unit mounts on the bridle cables below the horse’s head (Figure 1) and stops the pump operation when the plunger fails to hit fluid high in the working barrel but contacts fluid near the bottom of the barrel.A second set of sensors are installed in the flowline coming off the wellhead and measure fluid volume for each stroke (Figure 2). The production cycle is ended when the average volume of the fluid pulse decreases. Each of the sensors is sized to match output pressure and volume. A third type of sensor monitors pressure of production fluids on each stroke against the backpressure valve on wells that produce associated gas. Back pressure valves are used to prevent gas from entering the pump and production tubing. The sensor terminates the production cycle when the back pressure valve fails to open as usual during a normal pump stroke due to less fluid being pumped. All sensors are accompanied by a control box containing a timer, shut down controls and monitoring units.The Pre-Pump Off controls have been configured to work with natural gas or gasoline powered engines as well as electric motor pump units. In all models, solar panels are being designed to replace batteries for operating the controls. Support from the SWC enabled Oil Well Sentry to refine the system and to develop and test additional sensors and controls. The system is currently commercially available.
6.5 Personnel Plan
Suppliers to the oil and gas (O&G) industry are experiencing a rare phenomenon in today’s economy: Growth.
The increase in shale oil and gas extraction projects has triggered spectacular growth in North American drilling projects, but with this growth comes transportation challenges as suppliers of pipe, chemicals, drilling equipment, water, sand, and other materials must move products to and from an expanding number of drilling sites, many of them in remote locations. All at a time when fuel costs are rising and transportation carrier capacity is shrinking.
A pump jack is a device used in oil production when the pressure inside a well is not sufficient to force oil to the surface. The pump jack is run to physically extract oil for use. Pump jacks were historically used on wells with low production levels, and can be seen dotting the landscape in many regions where oil wells have been dug. The distinctive appearance of the pump jack has become iconic and these devices are often used as symbols of the oil and gas industry, including on some company logos.
Known by names like “nodding donkey,” “grasshopper pump,” and “thirsty bird,” the pump jack consists of a long beam moved by an external power source. As the end of the beam rises and falls, the weighted end dips in and out of the well to extract oil. The other end is connected to a pulley system that is attached to the power source, providing continuous movement of the pump jack while it is turned on.
The same basic mechanics can also be seen in the design of some hand pumped wells, with a human being serving as the power source. Pump jacks can run on generators, as well as central power supplies. In large oil fields, pump jacks can be strung together along a power connection to access a central source of energy. Field workers maintain the devices, providing lubrication and replacing worn out parts.
These devices may not necessarily run full time. Production can be adjusted in response to changing oil prices and other factors, and in addition, some wells need to be allowed to rest to bring the levels of oil up high enough to reach with a pump. Typically, the pump jack extracts a solution of oil and saltwater, along with other impurities, and if a well is worked too hard, the level will fall below the reach of the pump. The ability to adjust production levels with a pump jack allows field workers to control how much oil is extracted, and when.
Once pulled out of the ground with a pump jack, the oil can be moved to containers for shipping and eventual treatment. In the treatment process the impurities will be removed and the oil will be graded and subjected to a series of refinery processes to produce different oil and gas products. The grade of the oil depends on a number of factors, with higher graded oils generally being more valuable.
6.6 General Operations
Finding the Oil
In order to pump oil, several geological elements must fall into place, including the right rocks, a well-formed reservoir and a trap. A trap keeps the oil from leaking away. Geologists study rocks on the surface, as well as beneath the ground. They send shockwaves into the ground and figure out how long it takes for them to bounce off rocks and return to the surface, otherwise known as collecting seismic data. Once they've collected enough seismic data of an area, they can make a three-dimensional map of what's underground and determine whether it's worth ior not t to drill.
The Parts
The most commonly seen oil pump is what's known as the nodding donkey. The big, ovular end that bobs up and down is commonly referred to as the horse's head. It's at the end of a long beam that sits upon a perpendicular beam, which is similar to a tall teeter-totter. On the other end of the beam are weights that are connected to a motor. Off the nose of the horse's head ia a rod that has a submersible pump on the end.
The Mechanics
The motor pulls the weights in a circular motion around a pulley, which tips the beam up and down. This allows gravity to do half the pulling work, making a 25 horsepower engine sufficient enough to move the entire pump. When the beam moves up, the other end moves down, forcing the horse's head to push the rod into the ground. The submersible pump at the end of the rod forces the oil into a tube that is connected to a tank. Then the oil is stored until it's sold or refined.
The Role of Stripper Wells in Meeting the Challenge:
What are stripper wells?
The United States has more oil and gas wells than any other country. As of December 31, 2003, there were more than 524,000 producing oil wells in the United States.That’s more than three times the combined total for the next three leaders: China, Canada and Russia. With just over 390,000 producing gas wells, the U.S. is the worldwide leader in that category as well. Unfortunately however, most of these wells produce relatively small volumes of oil and gas, often on an intermittent and marginally economic basis. Wells that
produce 10 barrels of oil or less per day, or 60 thousand cubic feet (Mcf) of gas or less, are commonly called “stripper”wells. The first use of this term is not recorded, but it follows from the idea that these wells are seen as stripping an underground reservoir of its last few barrels of oil or cubic feet of gas. The Interstate Oil and Gas Compact Commission (IOGCC), which reports the annual status of U.S. stripper wells, recorded 393,463 stripper oil wells producing an average of 2.18 barrels of oil per day, and 260,563 stripper gas wells producing an average of 15.5 Mcf per day, as of January 1, 2004.These totals amount to roughly 77 percent and 63 percent of the country’s total oil and gas well populations, respectively. The number of producing stripper wells changes depending on how many wells enter the ranks (by declining in production) and leave the ranks (by increasing production or being plugged and abandoned) of stripper wells each year. The United States’ stripper oil well population has been gradually declining over the past decade. Although a net of
about 8,000 aging oil wells drop to stripper status each year, roughly another 14,000 are plugged and abandoned, leaving a net reduction in the oil well total of about 6,000 wells per year. At the same time, a net of nearly 14,000 gas wells per year, on average, have dropped to stripper well status over the past decade (about 17,000 per year during 2000-2003). Roughly 3,800 stripper gas wells are plugged and abandoned in the U.S. each year on average, resulting in an average net increase in the stripper gas well population over the past decade of about 10,000 wells per year.
What is their contribution to current domestic supply?
Stripper oil production totaled 313,748,001 barrels in 2003, accounting for 28 percent of production from onshore wells in the lower-48 states; 15 percent of total domestic oil production. Although the top five stripper oil states (Texas,Oklahoma, California, Kansas, and Louisiana) account for about 80 percent of stripper oil and nearly 65 percent of stripper oil wells, stripper production contributes to tax revenues and economic growth in 28 states. Were it to represent the total annual production from any of the 105 nations that produce crude oil, the U.S. stripper well oil production total would place that country in the top third of producers, ahead of Oman, Egypt, Malaysia and Australia.
Introduction
Like prices of other commodities the price of crude oil experiences wide price swings in times of shortage or oversupply. The crude oil price cycle may extend over several years responding to changes in demand as well as OPEC and non-OPEC supply. We will discuss the impact of geopolitical events, supply demand and stocks as well as NYMEX trading and the economy.
Throughout much of the twentieth century, the price of U.S. petroleum was heavily regulated through production or price controls. In the post World War II era, U.S. oil prices at the wellhead averaged $28.52 per barrel adjusted for inflation to 2010 dollars. In the absence of price controls, the U.S. price would have tracked the world price averaging near $30.54. Over the same post war period, the median for the domestic and the adjusted world price of crude oil was $20.53 in 2010 prices. Adjusted for inflation, from 1947 to 2010 oil prices only exceeded $20.53 per barrel 50 percent of the time.
Until March 28, 2000 when OPEC adopted the $22-$28 price band for the OPEC basket of crude, real oil prices only exceeded $30.00 per barrel in response to war or conflict in the Middle East. With limited spare production capacity, OPEC abandoned its price band in 2005 and was powerless to stem a surge in oil prices, which was reminiscent of the late 1970s.
The price of petroleum as quoted in news in North America generally refers to the WTI Cushing Crude Oil Spot Price West Texas Intermediate (WTI), also known as Texas Light Sweet, is a type of crude oil used as a benchmark in oil pricing and the underlying commodity of New York Mercantile Exchange's oil futures contracts. WTI is a light crude oil, lighter than Brent Crude oil. It contains about 0.24% sulfur, rating it a sweet crude, sweeter than Brent. Its properties and production site make it ideal for being refined in the United States, mostly in the Midwest and Gulf Coast regions. WTI has an API gravity of around 39.6 (specific gravity approx. 0.827) per barrel (159 liters) of either WTI/light crude as traded on the New York Mercantile Exchange (NYMEX) for delivery at Cushing, Oklahoma, or of Brent as traded on the Intercontinental Exchange (ICE, into which the International Petroleum Exchange has been incorporated) for delivery at Sullom Voe. Cushing, Oklahoma, a major oil supply hub connecting oil suppliers to the Gulf Coast, has become the most significant trading hub for crude oil in North America.
The price of a barrel of oil is highly dependent on both its grade, determined by factors such as its specific gravity or API and its sulphur content, and its location. Other important benchmarks include Dubai, Tapis, and the OPEC basket. The Energy Information Administration (EIA) uses the imported refiner acquisition cost, the weighted average cost of all oil imported into the US, as its "world oil price".
The demand for oil is highly dependent on global macroeconomic conditions. According to the International Energy Agency, high oil prices generally have a large negative impact on the global economic growth. Peak oil is the period when the maximum rate of global petroleum extraction is reached, after which the rate of production enters terminal decline. It relates to a long term decline in the available supply of petroleum. This, combined with increasing demand, will significantly increase the worldwide prices of petroleum derived products. Most significant will be the availability and price of liquid fuel for transportation.
The US Department of Energy in the Hirsch report indicates that “The problems associated with world oil production peaking will not be temporary, and past “energy crisis” experience will provide relatively little guidance. The U.S. Energy Information Administration estimates that the United States will be the world's top producer of petroleum and natural gas hydrocarbons in 2013, surpassing Russia and Saudi Arabia. For the United States and Russia, total petroleum and natural gas hydrocarbon production, in energy content terms, is almost evenly split between petroleum and natural gas. Saudi Arabia, on the other hand, heavily favors petroleum.
5.3 Distribution Channels
SELLING THE OIL EXAMPLE: barges of oil as big as football fields for a living. He calls his route “the loop,” which starts with him guiding his boat and two empty 300-foot barges into the Port of Catoosa, outside Tulsa, Okla. Meredith steers toward a cluster of seven storage tanks brimming with crude that’s been trucked in from wells in Oklahoma and Kansas.
Moving 43,000 barrels of oil from the tanks into the barges is a 12-hour process, and one mistake can mean disaster. “You get 4,000 barrels going through that hose every hour, and you let something ass up. … Man, it makes a big mess,” Meredith says in his Florida drawl, his face deeply tanned from 19 years on a tugboat. At dawn the next day he’ll leave for Mobile, Ala. The route of winding rivers is more than 1,300 miles long and takes about a week.
“It’s a haul, man,” says Meredith. “You leave here and go back out the Arkansas River. Then you hit the Mississippi and take it down to New Orleans and into some industrial locks. Once you’re through those, you scoot across Mississippi Sound and on over to Mobile Bay and into the Mobile harbor.” Next stop is a storage facility in Mobile leased by Hunt Oil. Meredith says Hunt will take this domestic crude and mix it with lower-grade oil from Venezuela. He’ll then barge the blend up to Hunt’s refinery in Tuscaloosa, where it’ll be turned into gasoline, diesel fuel, jet fuel, and asphalt. Meredith then will head back to Catoosa and start all over again.
These are 24/7 days for oil production in the U.S. North Dakota now produces more oil than Alaska—and more than Ecuador, too. Geologists estimate that Oklahoma still has 80 percent of its reserves in the ground. The majority of this oil is of the highest quality: light, sweet crude that’s low in sulphur, lighter than water, and cheaper to refine into gasoline than the heavier sour (high in sulphur) crude from Venezuela and the Canadian tar sands. Goldman Sachs (GS) predicts that by 2017 the U.S. will be the world’s biggest oil producer.
All this oil needs to get stored somewhere, and the largest facility in the country is 60 miles west of Catoosa in the small town of Cushing (pop. 7,890). Each day some 900,000 oil futures and options contracts are traded on the New York Mercantile Exchange (CME). The oil at Cushing is what’s bought and sold. The town’s hundreds of storage tanks are the country’s biggest bank vault of oil. And it’s getting bigger. In September 2008 there were fewer than 15 million barrels of oil parked there. Today there are 44 million, 16 million more than in January. And that’s a problem. Oil is flowing into Cushing faster than it’s getting piped out.
The giant pool of crude stuck in the middle of the country has done strange things to the oil market. The light, sweet crude that Meredith transports is priced against the domestic benchmark West Texas Intermediate. It’s so plentiful right now that for the past year it has traded at an average $95 a barrel, $16 below the price of its international equivalent, Brent crude. At its peak last October, the spread—the price differential between WTI and Brent—was $27. That’s the biggest gap in the history of those two oil contracts, which for most of the last 20 years have moved within $1 of each other. What’s helped push down the price of WTI? The fact that it’s stuck in Cushing. Oil that can’t be moved to where it needs to go quickly drops in price. The result has been one of the biggest arbitrage opportunities in recent memory: Buy oil low in Cushing, and sell it high—just under the price of Brent—to refineries along the Gulf Coast. The trouble is getting it there. The race is on to get the oil out of Cushing. Pipeline companies are pushing to build new pipes and, in some cases, reversing the flow of existing ones. For 17 years, the 500-mile-long Seaway Pipeline pumped imported crude from the Gulf Coast into Cushing. In May it was reversed, and now Seaway pumps 150,000 barrels a day south to the refiners on the Gulf Coast. TransCanada (TRP), based in Calgary, is spending $2.3 billion to extend its Keystone Pipeline south of Cushing. (Its Keystone XL pipeline still awaits approval.) When completed next year, it’ll move 700,000 barrels a day.
Determining the Value of Your Producing Mineral Rights
In order to get an idea of what your oil or gas royalty stream is worth, one must look at a number of factors. Location, size of the land tract, depth restrictions, operating costs – all of these play into valuing royalties. The price of crude oil or natural gas, and the production decline rate are two of the more important variables. Of course estimation must be made several years into the future as to how these elements will fluctuate. When exchanging a cash payment now for an expected future cash flow stream, the time value of money also plays into the calculation. (A dollar in hand now is worth more than a dollar promised next year, because the dollar in hand can be used to earn interest over the course of the year). Also, mineral and royalty interests may qualify for use in Like-Kind Exchanges (1031 Exchanges) which can defer taxes. Under the Case Study section, you’ll find examples where oil and gas royalties have been exchanged for an immediate cash payment.
Shifting commodity prices are a given in the oil and gas industry, but sometimes the industry landscape changes in unexpected ways. In this interview with The Energy Report, Oppenheimer & Co. Managing Director and Senior Energy Analyst Fadel Gheit discusses the effect of Middle Eastern geopolitical issues on oil production, dissects the changing oil and gas production situation in the U.S. and explains how the shift in natural gas prices has turned the refinery business from the industry's perennial ugly duckling into a beautiful swan.
Oil and Gas Journal's semiannual Worldwide Construction Update shows an increase in refining construction activity compared with the previous edition of the update (OGJ, Nov.5, 2012, p. 48). Following are details from the latest survey, which is available on OGJ Online (see box). Refining In US refining news, CHS Inc., St. Paul, Minn., will boost refining capacity at the 85,000 b/d National Cooperative Refinery Association facility at McPherson, Kan., to 100,000 b/d by 2016 in a $327 million project (OGJ Online, Mar. 12, 2013). Completion will take place in phases during the second half of 2015 and the first months of 2016, with production expected in early 2016. The expansion will occur ... A Chinese oil company has purchased a cargo of North Sea oil, in a rare move into the European crude market that highlights the extent to which supply disruptions have left buyers scrambling to secure alternatives. ...U.S. refineries are expanding their diesel-production capacity, not so much for truckers in the U.S., but for drivers in places such as Mexico City and Santiago, Chile. Already running at their highest levels in six years, U.S. refineries are finding strong demand for diesel fuel, used widely in cars outside of the United States, and other distillates, like jet fuel.
Refiners have been pinched as crude oil prices rise, and the narrowing of the gap between U.S.-produced West Texas Intermediate and the international benchmark Brent crude, has taken away some of the advantage U.S. refiners had in the global marketplace. Exxon Mobil, for instance, pointed to refining margins for part of its surprisingly steep profit decline in the second quarter, and others, like Marathon and Valero, also blamed a contraction in refining margins for reduced profits. Refineries continued to operate at a high level of 90.9 percent of capacity, though off recent highs. Gasoline production rose slightly to 9.6 million barrels per day, and distillate fuel, mainly diesel production, increased to 4.9 million barrels per day.
North American crude oil markets are in a state of flux. The advent of new oil drilling techniques, has unlocked enormous quantities of crude oil previously thought unrecoverable. US crude oil production is expected to grow 60% from pre-recession levels by 2017. This has led industry commentators to project that the US will be able to produce enough crude oil to meet domestic demand by 2030, something that hasn’t occurred within the last 40 years. This astronomical growth in supply has overwhelmed traditional pipeline infrastructure, leading to bottlenecks. The inability to connect oil production to market has caused a supply-demand imbalance, leading to depressed oil prices in certain regions. The North American benchmark oil price, West Texas Intermediate (WTI), has traded at a discount as large as $30 to world oil prices, which trade at around $110/ barrel (bbl).
Refining in North America
Crude oil is transported from the oil wells to refineries by pipeline, railcar, or tanker. Pipelines are the primary and safest method of transportation in North America. There are two types of oil, light and heavy crude, both of which refineries can process. Light oils are refined into gasoline, while heavier crudes produce diesel and jet fuel. Not all refineries can process both types of oil, reconfiguring a refinery to process light from heavy and vice-versa requires billions in capital investment and years to complete, making this option unattractive.
Refineries are expensive to build, have long payback periods (20-30 years) and sell low-margin products. They make their money off of the difference between the crude oil input costs and the refined product sales price. This is called the “crack spread”. Unfortunately, the prices for both commodities are very volatile and do not always move together. Additionally, refineries built outside North America are far more cost effective due to lower overhead costs, cheaper labor, and more lenient environmental regulations. These factors, along with stringent environmental and emissions legislation in the US make it clear why few new refineries have been built in the US since the late 1970s.
5.4 Promotional Plan
Public Company Stock Promotion
Email Answers is an experienced, well managed marketing company that works with third party investors/owners who are interested in adding volume and increasing the price of a publicly traded companies stock. Whether you are a stock promoter or a third party investor looking for a stock investor email list, stock investors mailing list or a specialized, highly targeted marketing list, we have the capabilities to provide you with the most up to date and accurate stock investor lists that exist in the industry for your stock promotion campaigns.
With thousands of publicly traded companies in the financial world, it is almost impossible for small but growing companies to attract the attention of the investment world and that is where Email Answers can help.By focusing on timed press releases to the individual Small Cap, OTC, Pink Sheet and Nasdaq investors, our stock promotion programs work extremely well to get your current news into the investors hands in a timely and trustworthy manner.Email Answers has the data and expertise to meet all of your stock promotion needs.Our Stock Promotion Services Consist Of:Email Marketing ListsFull Creative Deployment ServicesNewsletter, Copyrighting and Creative DesignCampaign TrackingMaterial Development: Website, Corporate Packages, Brochures, etc.Direct Marketing ServicesData AcquisitionsNational & Wire Press Releases.
Starting a new business is hectic,
what with obtaining the funding, finding the right location, and leaping all the bureaucratic hurdles the various local, state, and federal governments put in your way. When you’re finally done with the set-up tasks, you may just want to rest on your laurels and take it easy for a while.
While investor sentiment toward stocks has been negatively influenced by the recent volatility in the financial markets, interest in IPO’s has remained steady.
The number of global IPO filings in 2010 is about 120 and indications are that there are many to follow. Of the companies that already have filed, a staggering 65% have come from Asia, with China leading the pack. So the uptick in filings year to date is a global phenomenon, which speaks in part to the resilience of the global economy.
The benefits of going public are fairly universal: greater and more inexpensive access to capital, enhanced opportunities to pursue mergers and acquisitions, increased liquidity for shareholders, a stronger corporate image and another tool to incentivize executives and employees. Here are ways to promote a new public company.
Communication Benefits:
Communication is the affection of every organization. Everything you do in the abode after-effects from communication.
When most people think about communication it is usually speaking that first springs to mind, however, being able to listen well is a large part of effective communication. A major benefit of good communication within the workplace is that it may very likely lead to an improvement in office morale.
Following are a few guidelines to help you become aware of how to take advantage of the benefits and avoid the obstacles.
Learn the 3 Rules:
If an affective media relations program can help you increasing the demand for company stock, then the newly public companies will learn quickly that the rules of the road are very complex, than while operating under the protection of private ownership. Media relation is vital if you know their rules. Come let’s see three basic rules.
Rule 1: Audience Changes
When a company lists its share on a public exchange; its key share holder extend far beyond media, customers, market researchers, business partners, and employees to include financial analysts, share holders, share holders interest groups, and government regulators.
Rule 2: Increase of Scrutiny
Public companies often comes under instance scrutiny and attacks in traditional as well as media such as the blogosphere, which can provide forums for watching investors and disgruntled employees. It also has potential to become hostile.
Rule 3: Avoid being too Strict
Quick period / speed rules strive to lower company awareness in the market just as media and public interact may be picking up, also cost of non compliance with quiet periods and numerous other restrictions may be devastating.
New Communications Approach
New public companies can avoid costly missteps by adopting a new communications approach that addresses all stakeholders and encompasses all pertinent communications disciplines.
Communications Teams for Help:
Communications team members need to function as strategic counselors to management teams and ambassadors to broader staff. They need to clearly understand and advocate the subtle differences between media activity that brings benefit and safety versus potentially risky and damaging during a quiet period – helping to maintain and build company awareness in the market while simultaneously abiding by new regulations.
Investor relations, corporate affairs, public affairs and crisis management must be equipped to manage and contain media reactions during turbulent times though the rapid dissemination of accurate, comprehensive information. It’s much easier for a company to keep its credibility than to rebuild it.
Social Media – a New Communication Approach
Social media as a group of Internet-based applications that build on the ideological and technological foundations of Web 2.0 and it allows the creation and exchange of user generated content. Social media is media for social interaction as a super-set beyond social communication. Enabled by ubiquitously accessible and scalable communication techniques, social media has substantially changed the way of organizations, communities, and individuals communication.
Social Media as practiced with tools like Facebook and Twitter creates an entirely new set of uncharted disclosure issues. On one hand, some companies simply restrict using social media for investor communications, despite the widespread popularity and advantages of these media in crisis situations.
On the other hand, companies may opt toward transparency and provide information in direct opposition to fair and equal disclosure requirements.
Employee Education
The employee communications discipline can take the form of a program aimed at educating employees on behavioral changes and expectations within a newly public company. For example, once a company goes public, employees have no right to material information before other shareholders.
Employees are an especially important group. Experience has proven that employees are more motivated when they clearly understand company actions and decisions and have a sense of personal stake in the outcome.
Despite the desire for transparency, an advice to the clients is—that corporate legal and IR teams must get involved in social media to protect the company from violating disclosure requirements. The risks simply don’t outweigh the benefits.
So what do public relations agencies do?
PR agencies, as opposed to advertising agencies, promote companies or individuals via editorial coverage. This is known as “earned” or “free” media — stories appearing on websites, newspapers, magazines and TV programs — as compared to “paid media” or advertisements.
PR agencies and advertising agencies share the same goals: promoting clients and making them seem as successful, honest, important, exciting or relevant as possible. But the paths to creating awareness are vastly different. Most people understand advertising is paid for by the client and should be viewed with skepticism. Articles or TV appearances in respected publications have the advantage of third-party validation and are generally viewed more favorably.
Ideas Given To Us To Use:
When you build name recognition, your laboratory pops into your dentist-client's mind first. In this tight economy, consider using downtime to develop your public relations (PR) strategy, thereby increasing your exposure while reinforcing trust, loyalty and respect in your relationships.
While PR initiatives are often no- or low-cost, they do require a commitment of time to develop your message and broadcast it regularly through the press, your own media and community involvement. And although success may be hard to quantify in accounting terms, studies show companies that cut back on their investment in PR activities often have a simultaneous decrease in sales.
The two questions to ask when developing a PR plan are: "What information will benefit our clients?" and "How can we broadcast it?"
Following are some ideas for jumpstarting your foray into public relations:
Be Delivered—Through the Newspaper
Is there a hot dental issue in the general media? Call your local paper's health editor and offer to answer any questions he may have.
Send a letter to the editor offering the dental laboratory perspective on concerns about lead in restorations, offshore outsourcing or other issues.
Send a press release to the local newspaper when you have a noteworthy business development, such as opening a new denture department, a 10-year anniversary in business, or hiring new managers. Or, if your employees pitch in for a day at a local charity, send their picture to the paper.
These mentions are the little reminders that keep your name on the tip of many tongues not just of the general public, but also the editors when they're looking for an expert source. More importantly, it validates your credibility to be featured by a third party rather than in your own promotional pieces.
Be Seen as an Expert
Speak before civic organizations and senior groups on relevant patient-education topics, such as restorative options and how healthy smiles affect self esteem and overall health and contribute to helping victims of domestic violence, bulimia or drug abuse get back on their feet.
Offer to speak on these topics on locally produced cable and talk radio as well as at health and wellness fairs.
Be Your Own Media
Develop an e-newsletter for dentists. Use it to call attention to time-saving opportunities on your website, such as customized prescription forms, delivery schedules, impression-taking tips, practice management strategies, and requests for tool and equipment loans if you offer them.
Provide patient education materials for your dentist-clients such as brochures or information sheets on metal-free options, nightguards, understanding the process of try-ins and provisional cases for denture patients.
Be a Part of the Community
As a member of the local business community, you need to network and be involved. Being seen in the community makes it harder for dentists to outsource if they understand that it hurts your business and employees who are, in turn, customers in their local businesses. It may also smooth the way if you need to face your neighbors or the zoning board to expand your facility.
Team up with a dentist and a local nonprofit organization to donate your services to those in need.
Sponsor a work day for your employees to assist a community group or family in need through organizations like the United Way or Habitat for Humanity.
Sponsor a local youth sports team and be amazed by the visability your lab's name will have on the backs of 12 Little Leaguers.
Take out a small ad in your local symphony or chamber music series program book to show that you support organizations that your dentist-clients value (doctors and dentists make up a dedicated demographic that support arts organizations).
What is Investor Relations?
Investor relations is the term used to describe the ongoing activity of companies communicating with the investment community. While the communication that quoted companies undertake is a mix of regulatory and voluntary activities, investor relations
is essentially the part of stock market life that sees companies interacting with existing shareholders, potential investors, analysts and journalists. For many quoted companies, the dialogue will begin in the pre-IPO phase, when the company is profiling itself to what is often a new set of potential investors. Once on market, the communication continues with shareholders and financial market commentators, as well as with other potential investors.Fundamentally, the remit of investor relations is not only to create an awareness and understanding of your company amongst the investment community, it is also to help quoted companies gain access to capital and achieve liquidity in, and fair valuation for their shares. The ability to raise capital and the ease with which
that capital is raised are often seen as key measures as to how successful a company’s investor relations efforts are. Entering into a dialogue and developing relationships with the investment community over time so that its participants become cognisant with the company and its investment proposition is generally seen as a worthwhile exercise when trying to achieve efficient, cost-effective access to capital.
Liquidity:
One of the outcomes quoted companies aim for from their investor relations activities is to attract liquidity – frequency of trading in their shares. Profiling and explaining the company to the investment community on a continual basis can assist in creatinggreater awareness of a company. Depending on the availability of shares, this can then assist a company in attracting pools of buyers and sellers and the potential for higher frequency in the trading of its shares.
5.5 Feedback
Getting Customer Feedback Right
Most companies devote a lot of energy to listening to the “voice of the customer,” but few of them are very happy with the outcome of the effort. Managers have experimented with a wide array of techniques, all useful for some purposes—but all with drawbacks. Elaborate satisfaction surveys that involve proprietary research models can be expensive to conduct and slow to yield findings. Once delivered, their findings can be difficult to convert into practical actions. The results also may be imprecise: Our research shows that most customers who end up defecting to another business have declared themselves “satisfied” or “very satisfied” in such surveys not long before jumping ship. The practice of sending executives out to spend time in the field can generate fresh insights, but few management teams sustain such efforts—and even if they do, they often struggle to convert those insights into prescriptions that frontline employees can follow. Bringing in “power customers”—heavy spenders who tend to be deeply committed to the company—to talk about their experiences can shine a spotlight on critical issues. But frontline employees can’t easily learn about their own behaviors from those customers or develop remedies for the problems they raise.
A growing number of companies have developed effective customer feedback programs that head off those challenges right from the start. Instead of building elaborate, centralized customer research mechanisms, these firms begin their feedback loop at the front line. Employees working there receive evaluations of their performance from the people best able to render an appraisal—the customers they just served. The employees then follow up with willing customers in one-on-one conversations. The objective is to understand in detail what the customers value and what the front line can do to deliver it better. Over time, companies compile the data into a baseline of the customer experience, which they draw upon to make process and policy refinements.
A Five-Point Customer Feedback Checklist we need to follow:
1. Have you reached a consensus on your business’s five most critical “moments of truth” with customers?
2. Do employees and managers get customer feedback routinely, on a daily or weekly basis?
3. Do you let customers know the impact their feedback had on improving your processes?
4. Do you know what percentage of detractors your operations now convert into promoters through service recovery processes?
5. Can you put a dollar value on turning a detractor into a promoter?
The strongest feedback loops do more than just connect customers, the front line, and a few decision makers in management, however; they keep the customer front and center across the entire organization. A number of tactics, such as hiring “mystery shoppers” to test customer service or arranging periodic forums between employees and customers, help strengthen this organization-wide focus. One approach that we believe works well across a range of industries is the Net Promoter Score (NPS), which one of the authors of this article, Fred Reichheld, created seven years ago.
6. Operating Plan
We aspire to be an independent oil and gas company in North America and to provide our shareholders with returns over the long-term. To achieve this, we strive to optimize our capital investments to maximize growth in cash flows, earnings, production and establish reserves. We will do this by:
1.Generating cash flow,
2.Securing financing to acquire our planned acquisitions,
3.Exercising capital discipline,
4.Ensuring financial strength, and
5.Investing in oil and gas properties with strong full-cycle margins.
The Company plans to acquire producing or near producing oil and gas properties that will provide cash flow and an upside for future development. Such activities are concentrated in North America onshore, primarily in the United States. We are currently scouting and evaluating properties in Texas, Oklahoma, Pennsylvania, Kansas and in Canada. There is no assurance that we will be successful in raising the necessary funds to acquire any of producing oil and gas properties.
The implementation of our business plan will require significant capital. We do not have this capital and as a result, we will require additional financing to acquire and develop our leasehold obligations. We may use debt or equity to fund our ongoing operations. There can be no assurance that any financing will be available, and if available, will be on terms and conditions acceptable to the Company. If we rely on equity financing, our shareholders will experience significant dilution. If we rely on debt financing, we may not be able to satisfy our debt obligations.
The Company plans to acquire producing or near producing leaseholds that will provide cash flow and an upside for future development. However, it is unlikely that we will be able to exploit these leaseholds without a significant capital infusion.
The Company may acquire the leaseholds in consideration for cash or shares of the company or a combination of cash and shares of the Company and may include an Overriding Royalty. Typical Overriding Royalty’s range from 2.5% to as much as 25% depending upon the current production on the leaseholds and the potential for Oil and Gas production.
A typical leasehold grants the Company the exclusive right to explore the land (“Property”) covered by the Oil and Gas Lease by geophysical and other methods, and to operate same for and produce there from all naturally-occurring oil, gas, casing-head gas or gasoline, gas condensate and/or all other liquid or gaseous hydrocarbons and other marketable or non-marketable substances produced therewith ("Oil and Gas"); and the exclusive right to inject gas, water, brine and other fluids into subsurface strata; and rights of way and easements for laying pipelines, telephone, telegraph and power lines, and the right to erect or install power stations, compressor stations, roadways, storage tanks or other storage facilities, separators and any fixtures and other structures thereon for producing, treating, processing, maintaining, storing and caring for the oil and gas; and oil and gas from other properties and any and all other rights and privileges necessary, incident to, or convenient for the economical operation of the Property and other lands for the production of Oil and Gas, and the injecting of gas, water, brine and other fluids into subsurface strata.
The Company may, at any time and from time-to-time pool all or part of the Property with other properties to create one or more drilling units. The production of Oil or Gas from such a pooled unit is generally treated as though the production occurred from a well on the Property, except the Lessor shall be entitled to royalty only on its pro-rata share of such production.
It is intended that the leasehold also include all lands and interests of the Lessor, which are contiguous to or in the vicinity of the Property.
Usually the leasehold will remain in force for a term of one year from the date executed and for as long thereafter as Oil and/or Gas is produced from the Property, or as long as operations for drilling are continued or as long as operations are continued for injection of gas, water, brine and other fluids into subsurface strata.
When a well is worked over or offset well drilled, an access road is constructed to the well site or upgraded. This results in surface damages that the surface owner is compensated for the loss of property. Timber may also be cut down during construction, the Company may cut and stack the timber at a location convenient for the surface owner to sell or a value may be assessed on the timber and the surface owner compensated.
Depending upon jurisdiction of the leasehold, the state can force a "pooling" of the oil and gas interests of a landowner with the interests of other landowners where the size or condition of lands does not allow the neighbor to find a drill site while respecting distance limits from property lines. A mineral owner has five options in the context of forced pooling. They can:
1.Lease their mineral interest.
2.Sell their mineral interest.
3.Participate materially in the development of the gas field.
4.Be a non-consenting owner.
5.Protest forced pooling
A rework well or producing well requires maintenance by a company representative sometimes referred to as a “pumper” to insure the well(s) produce at their capacity and to monitor production. As per the terms of the lease, a gate may be installed by the well Operator to prohibit access to the Property by unauthorized personnel. The gate is typically locked and a key may be provided to the landowner. The well may require periodic maintenance by a service rig during the life of the well. Surface equipment includes a wellhead, gas meter, storage tank (for oil wells), separator, and pipeline. Lease is held-by-production during the life of the well(s).
Risks Related to Our Business:
We ceased generating revenue.
We have had limited revenues since inception. We will, in all likelihood, sustain operating expenses without corresponding revenues. This may result in our incurring a net operating loss that will increase unless we consummate an acquisition of an oil and gas producing properties that are profitable. We cannot assure you that we can identify any oil and gas properties that will be profitable at the time of its acquisition by the Company or ever.
Unless we secure additional working capital, the Company can only continue as a going concern for twelve months.
Unless we secure equity, debt financing or Joint Venture partners, of which there can be no assurance, or identify a profitable acquisition candidate, we will not be able to continue any operations for longer than twelve months. We based this estimate on that majority of our operating costs are for salaries of the officers and directors of the Company, which are being accrued. Our negative cash flow is for our auditors, attorneys, transfer agent, EDGAR filer and travel expenses. We have sufficient cash to cover auditors, attorneys, transfer agent, EDGAR filer and limited travel expenses for the next twelve months. After such time, the Company would be forced to cease operations. We will require significant working capital to continue our current development program. There can be no assurance that we will be able to secure additional funding to meet our objectives or if we are able to identify funding sources, that the funding will be available on terms acceptable to the Company. Should this occur, we will have to significantly reduce our development programs, which will limit our ability to secure additional equity participation in acquisitions of oil and gas leases or in various joint ventures.
There may be insufficient oil and gas reserves to develop any of our properties and our estimates may be inaccurate.
There is no certainty that any expenditures made in the development/exploration of any properties will result in discoveries of commercially recoverable quantities of oil or gas. Most development/exploration projects do not result in the discovery of commercially extractable deposits of oil or gas and no assurance can be given that any particular level of recovery will in fact be realized or that any identified leasehold interest will ever qualify as a commercially developed. Estimates of reserves, deposits, and production costs can also be affected by such factors as environmental regulations and requirements, weather, unexpected or unknown results when we re-enter a well, environmental factors, unforeseen technical difficulties, unusual or unexpected geological formations, and work interruptions.
Short term factors relating to reserves, such as the need for orderly development of the wells may also have an adverse effect on our development/exploration, drilling and on the results of operations. There can be no assurance the production of insignificant amounts of oil can be duplicated in a larger exploration program. Material changes in estimated reserves, development/drilling costs may affect the economic viability of any project.
We have no proven reserves.
All of our leasehold interests are without known bodies (reserves) of commercial oil or gas. Development of these properties will follow only upon obtaining satisfactory development/exploration results. The long-term profitability of the Company’s operations will be in part directly related to the cost and success of its development/exploration and development programs. Oil and gas development/exploration and development are highly speculative businesses, involving a high degree of risk. Few properties, which are explored, are ultimately developed into producing oil and gas fields. There is no assurance that our development/exploration and development activities will result in any discoveries of commercial quantities of oil and gas. There is also no assurance that, even if commercial quantities of oil or gas are discovered, a well can be brought into commercial production. Production/discovery of oil and gas is dependent upon a number of factors, not the least of which is the technical skillof the development/exploration personnel involved. The commercial viability of a well is also dependent upon a number of factors, many of which are beyond the Company’s control, such as worldwide economy, the price of oil and gas, government regulations, including regulations relating to royalties, allowable production, and environmental protection.
We face fluctuating oil and prices.
The price of oil and gas has experienced significant price movements over short periods of time and is affected by numerous factors beyond our control, including international economic and political trends, expectations of inflation, currency exchange fluctuations (including, the U.S. dollar relative to other currencies) interest rates, global or regional consumption patterns, speculative activities and increases in production due to improved exploration and d production methods. The supply of and demand for oil and gas are affected by various factors, including political events, economic conditions and production costs in major producing regions.
Drilling operations are hazardous, raise environmental concerns and raise insurance risks.
Drilling operations are by their nature subject to a variety of risks, such as, flooding, environmental hazards, the discharge of toxic chemicals and other hazards. Such occurrences may delay development or production, increase production costs, or result in a liability. We may not be able to insure fully or at all against such risks, due to political or other reasons, or we may decide not to take out insurance against such risks as a result of high premiums or other reasons. We intend to conduct our business in a way that safeguards public health and the environment and in compliance with applicable laws and regulations. Environmental hazards may exist on properties in which we hold an interest which are unknown to us and may have been caused by prior owners. Changes to drilling laws and regulations could require additional capital expenditures and increase operating and/or reclamation costs. Although we are unable to predict what additional legislation, if any, might be proposed or enacted, additional regulatory requirements could render certain operations uneconomic.
Our estimates of resources are subject to uncertainty. The cost of employing this technology maybe cost prohibitive or the cost may exceed the benefit.
Under current SEC standards, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field-tested and have demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
In order to establish reasonable certainty with respect to our leases, we would have to employ technologies that have been demonstrated to yield results with consistency and repeatability. The technical data used in the estimation of proved reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Generally, oil and gas reserves are estimated using, as appropriate, one or more of these available methods: production decline curve analysis, analogy to similar reservoirs or volumetric calculations. Reserves attributable to producing wells with sufficient production history are estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations are estimated using performance from analogous wells in the surrounding area and technical data to assess the reservoir continuity. In some instances, particularly in connection with exploratory discoveries, analogous performance data is not available, requiring us to rely primarily on volumetric calculations to determine reserve quantities. Volumetric calculations are primarily based on data derived from geologic-based seismic interpretation, open-hole logs, and completion flow data. When using production decline curve analysis or analogy to estimate proved reserves, they would be limited to estimates to the quantities of oil and gas derived through volumetric calculations.
The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering, and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves and future cash flows are based on various assumptions and are inherently imprecise. Even though these estimates may be reasonable and logical, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which the oil and natural gas industry in general are subject.
The oil and gas industry is highly competitive and the success and future growth of our business depend upon our ability to remain competitive in identifying and developing properties with sufficient reserves for economic exploitation.
The oil and gas industry is highly competitive and fragmented with limited barriers to entry, especially at the exploratory stages. We compete in national, regional, and local markets with large multi-national corporations and against start-up operators hoping to identify an oil or gas property. Some of our competitors have significantly greater financial resources than we do. This puts us at a competitive disadvantage if we choose to further exploit development opportunities.
The loss of key members of our senior management team could adversely affect the execution of our business strategy and
our financial results.
We believe that the successful execution of our business strategy and our ability to move beyond the exploratory stages depends on the continued employment of key members of our senior management team. If any members of our senior management team become unable or unwilling to continue in their present positions, our financial results and our business could be materially adversely affected.
Risks Related to Our Stockholders and Shares of Common Stock
We have a large number of authorized but unissued shares of our common stock.
We have a large number of authorized but unissued shares of common stock, which our management may issue without further stockholder approval, thereby causing dilution of your holdings of our common stock. Our management will continue to have broad discretion to issue shares of our common stock in a range of transactions, including capital-raising transactions, mergers, acquisitions and in other transactions, without obtaining stockholder approval, unless stockholder approval is required. If our management determines to issue shares of our common stock from the large pool of authorized but unissued shares for any purpose in the future, your ownership position would be diluted without your further ability to vote on that transaction.
Shares of our common stock may continue to be subject to price volatility and illiquidity because our shares may continue to be thinly traded and may never become eligible for trading on a national securities exchange.
While we may at some point be able to meet the requirements necessary for our common stock to be listed on a national securities exchange, we cannot assure you that we will ever achieve a listing of our common stock on a national securities exchange. Our shares are currently only eligible for quotation on the Over-The-Counter Bulletin Board, which is not an exchange. Initial listing on a national securities exchange is subject to a variety of requirements, including minimum trading price and minimum public “float” requirements, and could also be affected by the general skepticism of such markets concerning companies that are the result of mergers with inactive publicly-held companies. There are also continuing eligibility requirements for companies listed on public trading markets. If we are unable to satisfy the initial or continuing eligibility requirements of any such market, then our stock may not be listed or could be delisted. This could result in a lower trading price for our common stock and may limit your ability to sell your shares, any of which could result in you losing some or all of your investments.
The market valuation of our business may fluctuate due to factors beyond our control and the value of your investment may fluctuate correspondingly.
The market valuation of emerging growth companies, such as us, frequently fluctuate due to factors unrelated to the past or present operating performance of such companies. Our market valuation may fluctuate significantly in response to a number of factors, many of which are beyond our control, including:
i.changes in securities analysts’ estimates of our financial performance, although there are currently no analysts covering our stock;
ii.fluctuations in stock market prices and volumes, particularly among securities of emerging growth companies;
iii.changes in market valuations of similar companies;
iv.announcements by us or our competitors of significant contracts, new technologies, acquisitions, commercial relationships, joint ventures or capital commitments;
v.variations in our quarterly operating results;
vi.fluctuations in related commodities prices; and
vii.additions or departures of key personnel.
As a result, the value of your investment in us may fluctuate.
Investors should not look to dividends as a source of income.
In the interest of reinvesting initial profits back into our business, we do not intend to pay cash dividends in the foreseeable future. Consequently, any economic return will initially be derived, if at all, from appreciation in the fair market value of our stock, and not as a result of dividend payments.
We expect to issue more shares in an equity financing, which will result in substantial dilution..
Our Articles of Incorporation authorize the Company to issue 900,000,000 shares of common stock. Any equity financing effected by the Company may result in the issuance of additional securities without stockholder approval and may result in substantial dilution in the percentage of our common stock held by our then existing stockholders. Moreover, our common stock issued in any equity financing transaction may be valued on an arbitrary or non-arm’s-length basis by our management, resulting in an additional reduction in the percentage of common stock held by our then existing stockholders. Our board of directors has the power to issue any or all of such authorized but unissued shares without stockholder approval. To the extent that additional shares of common stock or preferred stock are issued in connection with a business combination or otherwise, dilution to the interests of our stockholders will occur and the rights of the holders of common stock might be materially adversely affected.
The Selling Stockholder (anyone whom buys shares from our company treasury) and any of its pledgees, donees, assignees and other successors-in-interest may, from time to time sell any or all of their shares of common stock on any stock exchange, market or trading facility on which the shares are traded or in private transactions. These sales may be at fixed or negotiated prices. The Selling Stockholder may use any one or more of the following methods when selling shares:
·ordinary brokerage transactions and transactions in which the broker-dealer solicits the purchaser;
·block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion
of the block as principal
·facilitate the transaction
·purchases by a broker-dealer as principal and resale by the broker-dealer for its account
·an exchange distribution in accordance with the rules of the applicable exchange
·privately negotiated transactions
·broker-dealers may agree with the Selling Stockholder to sell a specified number of such shares at a stipulated price per share
·through the writing of options on the shares
·a combination of any such methods of sale
·any other method permitted pursuant to applicable law
The Selling Stockholder shall have the sole and absolute discretion not to accept any purchase offer or make any sale of shares if it deems the purchase price to be unsatisfactory at any particular time.
The Selling Stockholder may also sell the shares directly to market makers acting as principals and/or broker-dealers acting as agents for themselves or their customers. Such broker-dealers may receive compensation in the form of discounts, concessions or commissions from the Selling Stockholder and/or the purchasers of shares for whom such broker-dealers may act as agents or to whom they sell as principal or both, which compensation as to a particular broker-dealer might be in excess of customary commissions. Market makers and block purchasers purchasing the shares will do so for their own account and at their own risk. It is possible that the Selling Stockholder will attempt to sell shares of common stock in block transactions to market makers or other purchasers at a price per share which may be below the then existing market price. We cannot assure that all or any of the shares offered in this prospectus will be issued to, or sold by, the Selling Stockholder. The Selling Stockholder and any broker-dealers or agents, upon completing the sale of any of the shares offered in this prospectus, may be deemed to be "underwriters" as that term is defined under the Securities Act, the Exchange Act and the rules and regulations of such acts. In such event, any commissions received by such broker-dealers or agents and any profit on the resale of the shares purchased by them may be deemed to be underwriting commissions or discounts
under the Securities Act.
We are required to pay all fees and expenses incident to the registration of the shares. The Selling Stockholder, alternatively, may sell all or any part of the shares offered in this prospectus through an underwriter. The Selling Stockholder has not entered into any agreement with a prospective underwriter and there is no assurance that any such agreement will be entered into.
The Selling Stockholder may pledge its shares to its brokers under the margin provisions of customer agreements. If the Selling Stockholder defaults on a margin loan, the broker may, from time to time, offer and sell the pledged shares. The Selling Stockholder and any other persons participating in the sale or distribution of the shares will be subject to applicable provisions of the Exchange Act, and the rules and regulations under such act, including, without limitation, Regulation M. These provisions may restrict certain activities of, and limit the timing of purchases and sales of any of the shares by, the Selling Stockholder or any other such person. The Selling Stockholder is not permitted to engage in short sales of common stock. Furthermore, under Regulation M, persons engaged in a distribution of securities are prohibited from simultaneously engaging in market making and certain other activities with respect to such securities for a specified period of time prior to the commencement of such distributions, subject to specified exceptions or exemptions. All of these limitations may affect the marketability of the shares.
6.1 Location
Company Operations
The Company is engaged primarily in the acquisition of producing or near producing oil and gas properties and the development of these oil and gas properties. The Company plans to acquire producing or near producing oil and gas properties that will provide cash flow and an upside for future development. Such activities are concentrated in North America onshore, primarily in the United States. We are currently scouting and evaluating properties in Texas, Oklahoma, Pennsylvania, Kansas and as well in Canada.
The Company may acquire the leaseholds in consideration for cash or shares of the company or a combination of cash and shares of the Company and may include an Overriding Royalty. Typical Overriding Royalty’s range from 2.5% to as much as 25% depending upon the current production on the leaseholds and the potential for Oil and Gas production. The Company may, at any time and from time-to-time pool all or part of the Property with other properties to create one or more drilling units. The production of Oil or Gas from such a pooled unit is generally treated as though the production occurred from a well on the Property, except the Lessor shall be entitled to royalty only on its pro-rata share of such production. Usually the leasehold will remain in force for a term of one year from the date executed and for as long thereafter as Oil and/or Gas is produced from the Property, or as long as operations for drilling are continued or as long as operations are continued for injection of gas, water, brine and other fluids into subsurface strata.
THE NOW CORPORATION AGREES TO REWORK 147 WELLS:
A rework well or producing well requires maintenance by a company representative sometimes referred to as a “pumper” to insure the well(s) produce at their capacity and to monitor production. As per the terms of the lease, a gate may be installed by the well Operator to prohibit access to the Property by unauthorized personnel. The gate is typically locked and a key may be provided to the landowner. The well may require periodic maintenance by a service rig during the life of the well. Surface equipment includes a wellhead, gas meter, storage tank (for oil wells), separator, and pipeline. Lease is held-by-production during the life of the well(s). When the well is no longer considered productive, the Company is required to plug the well under the direction of the Division of Oil and Gas inspector for the State. This involves placing cement plugs at various depths to isolate producing intervals, protect fresh water aquifers and coal seams. The site is reclaimed and vegetation is established to prevent erosion from the well site. After all wells on a lease are plugged, the lease is terminated and returned to the mineral owner.
After completion and testing of a workover well or an offset well, the well is put into production. As in the case of oil, the oil is pumped into a 100 BBL or 200 BBL tank(s). The pumper inspects the well on a daily or regular routine basis and monitors the production of oil. As the tank(s) nears capacity, the pumper will make arrangements for pickup of the oil for delivery to the Purchaser. The cost of hauling the oil to the refinery varies by distance from the well to the refinery and can range from $3 to $6 per BBL. The cost of the freight charge is borne by the Company. Oil collected or shipped during the month is paid by the Purchaser in the following month. The price paid for the produced oil is based on the average monthly market price.
Conflicts of Interest:
Management is not required to commit their full time to our affairs and, accordingly, such persons may have conflicts of interest in allocating management time among various business activities. Our affiliates, officers, and directors may engage in other business activities similar and dissimilar to those we are engaged in. To the extent that management engages in such other activities, they will have possible conflicts of interest in diverting opportunities to other companies, entities, or persons with which they are or may be associated or have an interest, rather than diverting such opportunities to us. As no policy has been established for the resolution of such a conflict, we could be adversely affected should management choose to place their other business interests before ours. No assurance can be given that such potential conflicts of interest will not cause us to lose potential opportunities. Management may become aware of investment and business opportunities, which may be appropriate for presentation to us as well as the other entities with which they are affiliated. Management may have conflicts of interest in determining which entity a particular business opportunity should be presented. Accordingly, as a result of multiple business affiliations, management may have similar legal obligations relating to presenting certain business opportunities to multiple entities. In addition, conflicts of interest may arise in connection with evaluations of a particular business opportunity by the board of directors with respect to the foregoing criteria. There can be no assurances that any of the foregoing conflicts will be resolved in our favor. We may consider Business Combinations with entities owned or controlled by persons other than those persons described above. There can be no assurances that any of the foregoing conflicts will be resolved in our favor.
Forward-Looking Statements:
Certain statements, other than purely historical information, including estimates, projections, statements relating to our business plans, objectives, and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act and Section 21E of the Exchange Act. These forward-looking statements generally are identified by the words “believes,” “project,” “expects,” “anticipates,” “estimates,” “intends,” “strategy,” “plan,” “may,” “will,” “would,” “will be,” “will continue,” “will likely result,” and similar expressions. We intend such forward-looking statements to be covered by the safe-harbor provisions for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995, and are including this statement for purposes of complying with those safe-harbor provisions. Forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties, which may cause actual results to differ materially from the forward-looking statements. Our ability to predict results or the actual effect of future plans or strategies is inherently uncertain. Factors which could have a material adverse effect on our operations and future prospects on a consolidated basis include, but are not limited to: changes in economic conditions, legislative/regulatory changes, availability of capital, interest rates, competition, and generally accepted accounting principles. These risks and uncertainties should also be considered in evaluating forward-looking statements and undue reliance should not be placed on such statements. We undertake no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Further information concerning our business, including additional factors that could materially affect our financial results, is included herein.
Our primary financial resource is our base of our unproven oil and gas leases. Our ability to fund our capital expenditure program is dependent upon the availability of capital resource financing. In the next fiscal year, we plan on spending approximately $1.4 MILLION DOLLARS in new capital investments for a 147well offset drilling program including exercising our option for an additional 40 oil and gas wells. However our actual expenditures may vary significantly from this estimate if our plans for to obtain financing changes during the year. Factors such as changes in operating margins due to changes in the price of oil and gas and the availability of capital resources could increase or decrease our ultimate level of expenditures during the next fiscal year.
Governmental Regulations:
The oil and natural gas industry is subject to various types of regulation throughout the world. Laws, rules, regulations, and other policy implementations affecting the oil and natural gas industry have been pervasive and are under constant review for amendment or expansion. Pursuant to public policy changes, numerous government agencies have issued extensive laws and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas exploration, production and marketing and midstream activities. These laws and regulations increase the cost of doing business and, consequently, affect profitability. Because public policy changes affecting the oil and natural gas industry are commonplace and because existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. However, we do not expect that any of these laws and regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size and financial strength.
WHY PENNSYLVANIA FOR LOCATION:
The Pennsylvania oil rush was a boom in petroleum production which occurred in northwestern Pennsylvania from 1859 to the early 1870s. It was the first oil boom in the United States.
The oil rush began in Titusville, Pennsylvania, in the Oil Creek Valley when Colonel Edwin L. Drake struck "rock oil" there. Titusville and other towns on the shores of Oil Creek expanded rapidly as oil wells and refineries shot up across the region. Oil quickly became one of the most valuable commodities in the United States and railroads expanded into Western Pennsylvania to ship petroleum to the rest of the country.
By the mid-1870s, the oil industry was well established, and the "rush" to drill wells and control production was over. Pennsylvania oil production peaked in 1891, and was later surpassed by western states such as Texas and California, but some oil industry remains in Pennsylvania.
Pennsylvania is one of four states looking to capture some of the excess profits enjoyed by the nation’s major oil companies. It is no wonder. In 2006, Exxon Mobil made $39.5 billion in profit on $365 billion in revenue. In contrast, Wal-Mart, the nation’s number two company, earned $11.3 billion, just one-third of Exxon’s profits, on revenues of $345 billion. As citizens have struggled to pay the rising cost of gasoline in the past five years, the profits of major oil companies increased by 344%. The strong world demand for oil, coupled with increased concentration and reduced competition in the industry, will likely result in high oil company profit levels for the foreseeable future.
Even when oil companies have record profits, however, Pennsylvania’s porous corporate tax system currently makes it possible for large corporations, like Exxon Mobil, Chevron, and ConocoPhillips, to shelter billions of dollars of income from taxation. Using transfer pricing and other “paper profit” minimizing techniques, oil companies have the ability to shift profits to low-tax states and nations, reducing their Pennsylvania tax liability
There's a lot of reasons, apparently, why New York should perhaps follow Pennsylvania's lead and lift its self-imposed moratorium. Here are some of them:
Pennsylvania counties with hydrofractured gas wells have performed better across economic indicators than those that have no wells.
The more wells a county contains, the better it performed.
Between 2007 and 2011, per-capita income rose by 19 percent in Pennsylvania counties with more than 200 wells, by 14 percent in counties with between 20 and 200 wells, and by 12 percent in counties with fewer than 20 wells.
In counties without any hydrofractured wells, income went up by only 8 percent.
Counties with the lowest per-capita incomes experienced the most rapid growth.
Counties with more than 200 wells added jobs at a 7 percent annual rate over the same time period.
Where there was no drilling, or only a few wells, the number of county jobs shrank by 3 percent.
Pennsylvania and the entire Appalachian basin in general are referred to as a “mature basin” because there has been more than 100 year of active drilling. So far, drilling activity has occurred primarily within thetop 3,000 to 5,000 feet in a basin that contains up to 30,000 feet of sediments. Some gas fields are producing from depths of 8,000 to 9,000 feet.
Exploration is ongoing for natural gas at depths upwards of 10,000 feet. More oil and gas are being discovered each year, and additional supplies are waiting to be discovered in the future.THE FUTURE OF OIL AND GAS, What have we taken and what’s left?
Since Drake’s discovery of oil in 1859, Pennsylvania oil fields haveproduced more than 1.4 billion barrels of crude oil. That’s more thanenough oil to fill 6.5 million swimming pools 20 feet in diameter and 4 feet deep. Natural gas production has exceeded 1.07 trillion cubic feet, Pennsylvania crude oil is so highly valued because the waxy, sweet paraffinic oils make high quality lubricating oils and greases.
6.2 Facility
When an oilman’s gamble pays off with a producing oil well, much remains to be done before the oil can make it to market. In 1859, “Colonel” Edwin Drake used a common water well hand pump to retrieve oil from 69.5 feet. It wasn’t long before necessity and ingenuity ombined to find something more efficient.
Oil wells will run dry, but advances in technologies can put off the inevitable. Even with the best technologies, more than half of the oil can remain trapped. The evolution of oil production is reflected in thousands of marginally producing oil and natural gas wells quietly reaching for often stubborn reserves. Low-volume “stripper” wells produce no more than 15 barrels a day.
The average stripper well produces only about 2.2 barrels per day. However, according to the Independent Petroleum Association of America (IPAA), these wells comprise 84 percent of domestic oil wells and produce over 20 percent of all domestic oil – an amount roughly equal to imports
Walking Beam Compressors:
Oil Well DiagramOil wells that use pumping units to artificially lift oil from the well are also wells that generally produce natural gas in addition to oil.When the ground oil-formation releases oil into the well bore, the formation also releases natural gas into the casing annulus. The annulus is the volumetric space between the inside diameter of the casing and the outside diameter of the tubing that is located within the casing. The tubing is thestring of pipe through which the sucker-rod string operates the down-hole oil pump attached to the bottom of the tubing-string (see pic, click to enlarge). The down-hole pump forces the oil up through the tubing to the well-head, and then into the flow line away from the well-head.The oil formation pressure moves oil from the formation into the well-bore, specifically into the casing annulus at the location of the down-hole pump.
As oil is released from the formation into the well bore, gas is also released from the oil formation. This released gas will fill the annulus all the way up to the surface casing-head. When the casing-head gas pressure becomes equal to or exceeds the flow line pressure, the gas leaves the casing-head and enters the same flow line as does the well-head oil.
The accumulated gas in the casing annulus exerts a back-pressure on the down-hole oil formation. This down-hole back pressure (hydrostatic pressure) acts on the oil formation in a manner to prevent or restrict free flow of oil and gas from the formation.When the hydrostatic pressure created by the casing gas is reduced, flow of oil and gas from the formation increases, and thus production of oil and gas increases.
For more than one hundred years, various means of “well head compression” have been used to reduce the hydrostatic pressure by removing the casing gas. Well Head Compression refers to the removal of casing-head gas, and the compression of that gas into the higher pressure flow line. Many types of conventional compressors have been used over the years in attempts to successfully and reliably reduce hydrostatic pressure through removal of casing-head gas. Most of the past attempts were forced-lubrication units that required considerable maintenance, adjustments, and attention. And they were prone to continual failures for lack of adequate and practical technology.
Walking beam compressors, while in use now for years have often been saddled with maintenance and other performace issues that make them a risky investment. In recent years, new technology and operating strategies have been developed that easily overcome previous detriments to walking beam compressors. This fact, coupled with the spiraling price of crude oil and gas make these compressors not only financially viable, but quite profitable to use.
One particular walking beam compressor, the Oil Flow Compressor (OFC) was developed in the period since 1992 using state-of-the-art materials, seals, and engineering technology. The result is the world’s unique walking beam gas compressor. It’s powered by the force of the walking beam of a typical pumping unit. Power requirement for the OFC is approximately 3 to 7 horsepower. Both maintenance free and adjustment free, replacement of seals is typically required, at minor cost, about every eight (8) months of continuous operation.
As the primary oil reserves have played out in the old Trenton Oil field in the Midwest U.S., and other regions, small independent oil producing companies in the U.S. have difficulty producing oil using the traditional technology of pump jacks, down hole steel rods, steel tubing, and cups.
Shallow stripper well production is generally uneconomic for several reasons:
• the low oil output of stripper wells (<10 barrels a day) provides less funding to pay labor costs for normal pump-jack maintenance
• pump jack equipment experiences significant wear-and-tear, leading to low reliability and significant downtime for repairs
• the corrosive chemical environment (including salt water and acids) of the shallow wells destroys the equipment Even though a well may still be producing small quantities of oil, the well is capped because the cost to operate such wells has proven to be non-productive.
Starting in 1997, Energy, Inc. began development of a new oil pumping system. Called Airlift, the new pump featured off-the-shelf PVC construction and virtually no moving parts. It relied on pressurized air to force oil through a series of stages until reaching the surface. The design of the unit has solved the problems facing traditional pump-jack equipment, namely reliability and corrosion. As added benefits, the design was safer, environmentally friendly, and required less maintenance. Potentially, the Airlift unit would allow thousands of old abandoned stripper wells to become economically feasible again due to low operating costs.The first version of the Airlift, later referred to as Gen 1, was tested from 1997 to 2000 in a few stripper wells. These earlier tests of the first version indicated the concept was sound, hence the current DOE grant was received in 2000 to take the technology to the next stage of success.
6.3 Operating Equipment
Fundamentally, there are three challenges small producers face in keeping their stripper wells on line. The first is basic economics, the second is basic physics, and the third is access to technology. Because stripper wells operate close to the edge of profitability, if oil and gas prices fall, the value of the oil or gas produced each day can quickly drop below the average daily cost of operating the wells. These costs include maintaining and operating pumps, transporting the produced oil or gas for sale, safe disposal of produced water, salaries, insurance, taxes and of course the royalties paid to the owners of the mineral rights.
Any technology or new operating practice that can help to lower the cost of operating a stripper well directly influences the limit of profitability and the time that well can be kept producing.
Physics controls how fast the oil, gas and water flow into the wellbore from the reservoir, and how difficult it can be to lift the fluids to the surface. Keeping stripper gas wells clear of water so that gas can flow more freely into the wellbore is a major challenge. Remediating wellbore damage so that oil and gas can both flow at higher rates is another. Optimizing the downhole and surface production equipment so that a stripper well produces the maximum amount of oil and gas for the minimum amount of power cost is yet another challenge.
Reducing costs and overcoming the physics of production both rely on technology. Unfortunately, most stripper well producers have neither the dollars nor the manpower to invest in developing new technology tools. In addition, most technology providers do not recognize the widely dispersed, marginal operations of the stripper well industry as a major market.
Mechanical failures are the cause of nearly one quarter of the abnormal production declines seen in stripper gas wells. These mechanical failures are most commonly the result of corrosion, often exacerbated by the build up of corrosive brine in wellbores or its movement through production equipment. Marginal well operators must react to corrosion-sourced mechanical failures, but typically do not follow a proactive methodology for identifying problem areas and selecting the appropriate corrosion mitigation alternative before the failure takes place. As a result, opportunities for reducing failure rates and increasing production are missed.
Research suggests that 86 percent of failures in plunger lift systems are a result of corrosion damage brought on by produced brine. The inability to effectively deliver corrosion inhibitor to plunger lift wells leads to equipment failure, high operating costs, and premature abandonment.
Oil Stripper Well possible equipment used for the stripper well pumpin oil to the surface.
All Airwell stripper oil well equipment is available for purchase or hire, subject to availability and location. In some areas Airwell also offer a contract pumping service.
Contract Pumping Service
Airwell Oil & Gas can offer a complete contract pumping service.
For a daily hire fee they will provide the following services:
Supply of all pumping equipment
Installation of all pumping equipment
Maintenance of all pumping equipment
Monitoring and reporting of pumped fluids
For more information on a Airwell Oil & Gas contract pumping service please go to the contact us page.
Terms and Conditions Apply.
Features of the Airwell Oil & Gas Pump:
Optimizing Low Flow Wells
Even though Airwell Pumping Systems are capable of higher flows, they have traditionally received the most acclaim for their ability to pump wells with low flow rates. An Airwell Pumping System will optimize the well production by automatically adjusting its flow to match the production of the well, even down to zero flow rate. There is little risk of costly pumping downtime from damaged pump equipment in low flow pumping situations.
Centralised Power Supply Requirements For Multiple Pump Sites
With an Airwell Pumping System it is only necessary to have a power source available at one central location. From this point the energy (compressed air) is directed to the various wells using a high pressure air hose. A well location could be up to 2 miles (3.2 kilometres) from the power source. This means that every pump has a 24/7 power supply. This is especially important when optimizing low production wells.
High "Down Well" Reliability
An Airwell Pumping System has minimal moving parts and only quality materials have been used in their manufacture. This makes the patented Aiwell Oil & Gas pumps very reliable and reduces the pumping down time experienced by other sytems in the event of equipment breakdown. Much of the maintenance process is completed at surface level. This means that maintenance can be done efficiently and with less intereference to the well's productivity.
Remote System Monitoring
An Airwell Oil & Gas system will be monitored daily from one of their offices. Airwell Oil & Gas staff are able to monitor and provide clients with regular information on:
Total volumes of fluids pumped from individual wells
Current tanks levels
Percentage of oil / water split in tanks
All of this information can be emailed to a client in a daily or weekly report. Full tank alerts can also be provided.
Low Environmental Impact
The risk of oil leaks at the well head is greatly reduced with an Airwell Pumping System, as there is no sucker rod and stuffing box at the surface. This lessens the potential environment impact on a site. The use of multiple Airwell pumps from one centrally located air compressor also eliminates the need to supply power or run separate petrol engines to each well, as is currently required for existing pump jacks. In addition, an Airwell Pumping System is quieter and more visually appealing as it has no moving parts or petrol motors at the head of the well.
Airwell Oil & Gas are committed to providing long-term customer service and satisfaction by providing an affordable and reliable oil and gas pumping system to the Oil and Gas Industry.
Tech Specs:
Pumping Principal
The pumping systems developed by Airwell Oil & Gas utilise the Direct Gas Displacement Principle.
The Airwell Pumping system employs a displacement vessel pumping unit that is set down the well combined with a control unit at the surface. This control unit monitors the pumping unit in real time, allowing the pump to passively fill at the natural production rate of the well.
Once the control unit has sensed that the pumping unit is full of fluid the controller at the surface will pressurize the pump vessel with gas and displace its contents.
The control unit will then sense when the vessel is empty and release the pressure allowing the vessel to refill.
Maximum Heads Achievable
3,280 feet (1,000 meters) or 8,000 feet (2,438 meters)
Distance from Power
With the Airwell System it has been possible to run a large number of pumps up to 6.2 miles (10 kilometers) from one centrally located power source. Even though it is possible to run gas lines further, it is preferable that any wells are within a radius of 2 miles (3.2 Kilometres) from any particular power source.
Flow Rates
All Airwell Oil & Gas pumps are capable of pumping down to a flow rate of 0 BBLs / Day without risk of damage to the equipment.
(Standard)
The highest flow rates experienced with the standard pump to date was 130 BBLs / Day at a depth of 1,200 feet (365 meters). However the main market for this pump will be for wells producing under 50 BBLs / Day.
(High Flow)
This variant of the standard Airwell Oil & Gas technology,will allow this range of pumps to recover from zero to 500 barrels of fluid per day from depths in excess of 8,000 feet (2,438 meters).
Telemetry and Control
Airwell provide a full tange of telemetry and control products service for Pumping, Well and Associated Equipment.
6.4 Suppliers and Vendors
One out of every six barrels of crude oil produced in the United States comes from a stripper well, which is the common industry name for a marginal well whose production has slowed to 10 barrels a day or less.
The consortium is managed and administered by The Pennsylvania State University on behalf of DOE; the Office of Fossil Energy’s National Energy Technology Laboratory, better known as NETL, and the New York State Energy Research and Development Authority. Together they provide base funding and technical guidance to the program.
Once a well is plugged and abandoned, the oil and gas reserves left behind are “lost forever” since it is typically uneconomical to drill another well to recover these abandoned reserves. Every dollar of stripper oil and natural gas production creates roughly one dollar of economic activity and nearly 10 jobs result from every million dollars of marginal well oil and natural gas produced, DOE said in its press release.
Once a well is plugged oil is lost forever
A common misperception, DOE said in a description of the program on its website, is that oil left behind remains readily available for production when, say, oil prices rise again. In most instances, this is not the case, the agency said, “leaving our nation more dependent on foreign oil imports.”
Why wouldn’t the oil be readily available in the future?
Because when marginal fields are abandoned, the surface infrastructure—the pumps, piping, storage vessels and other processing equipment—is removed and the lease forfeited. Since much of this equipment was probably installed over many years, replacing it over a short period is “enormously expensive,” DOE said.
“Oil prices would have to stay at today's elevated record levels for many years before there would be sufficient economic justification to bring many marginal fields back into production,” so once abandoned the oil in the ground is “often lost forever” … because “the costs of re-drilling a plugged well may be as much as or more than drilling a new well.”
From 1998 through 2007, on average each year over 3 percent of marginal wells were plugged and abandoned, DOE said. In total, this is more than 124,000 marginal wells, representing a number equal to 25 percent of all operating oil wells in 2007.
Although the situation is less severe for natural gas, there is nonetheless a growing concern about the premature abandonment of gas stripper wells. (A stripper gas well is defined by the Interstate Oil and Gas Compact Commission, which represents the governors of oil and natural gas producing states, as one that produces 60 thousand cubic feet or less of gas per day.)
One consortium project by Vortex Flow has developed downhole tools that reduce pressure drop thereby reducing the gas flow needed to lift liquids up the wellbore, DOE said. This novel technology received the Platts 2004 Newcomer of the Year Award, one of the most prestigious award programs in the industry.
Consortium’s success led to extension
Nearly 100 projects have been funded since the initiation of the Stripper Well Consortium, which is made up of small domestic oil and natural gas producers, as well as service and supply companies, trade associations, industry consultants, technology entrepreneurs and academia.
Per DOE, “the successful development and commercialization of many of these projects provided the incentive for DOE to continue program funding,” when almost all other oil and gas research programs have been cut.
Some of the programs other successes include a pump that removes fluids (hydrocarbons and water) from a well more consistently than currently available systems; a “vortex flow unit” that works like a tornado, using natural gas that has already been produced to accelerate water velocity, reduce friction, and assist in lifting and removing fluids, resulting in increased production while reducing the amount of down-time due to water in gas gathering lines; a new hydraulic diaphragm submersible pump that continuously cleans wells which, among other things, reduces electric costs; a low-cost, real-time, down-hole wireless gauge that measures temperature and pressure, eliminating the need for cables, clamps and splices in the well, thus significantly lowering cost and time; and a technology that captures information at the wellhead and transmits it wirelessly to a control room at a remote location, allowing the operator to monitor hundreds of wells from a single location.
The SWC is an industry-driven consortium that is focused on the development, demonstration, and deployment of new technologies needed to improve the production performance of natural gas and petroleum stripper wells. SWC is comprised of natural gas and petroleum producers, service companies, industry consultants, universities, and industrial trade organizations. The Strategic Center for Natural Gas and the New York State Energy Research and Development Authority provide base funding and guidance to the consortium. By pooling financial and human resources, the SWC membership can economically develop technologies that will extend the life and production of the nation's stripper wells.
Organizational Structure
SWC is industry-driven and is tailored to meet the needs of its members. Active industrial participation and leadership is key to making the consortium a success. The SWC has a Constitution and Bylaws under which the consortium will be governed to operate. Each SWC member appoints one representative to a Technical Advisory Committee. The Technical Advisory Committee is responsible for steering the technical direction of the consortium and is responsible for electing a seven-member Executive Council. The Executive Council is responsible for selecting proposed research projects that will lead to improving natural gas/ petroleum production from stripper wells. The process of having industry develop, review, and select projects for funding will ensure that the consortium conducts research that is relevant and timely to the natural gas and petroleum industry.
Technology Development
Research will be conducted in three broad areas: reservoir remediation, wellbore clean-up, and surface system optimization. Research outside of these three areas may be considered pending approval of the program sponsors. Specific research projects will be developed by the membership using a standardized proposal template. Proposal submission is limited to full members of the consortium. Collaboration between full members is encouraged. Projects will be funded on an annual basis. Each proposal is required to provide a minimum of 30% cost share which is to be provided by the project participants. Cost share may be in the form of cash and/or in-kind support. The use of Federal funds for cost share is prohibited. Intellectual property provisions will follow Penn State's Cooperative Agreement with DOE.
Stripper Well Consortium aids America’s small Producers
The Stripper Well Consortium (SWC) is an industry-driven consortium focused on the development, demonstration and deployment of new technologies needed to improve the production performance of natural gas and petroleum stripper wells. The term stripper well denotes a well producing no more than 10 barrels of oil per day or 60,000 cubic feet of gas per day. One out of every six barrels of crude produced today comes from a stripper well. Over 85 percent of the total number of U.S. oil wells are now classified as stripper wells. Together, these nearly 400,000 wells produce around 800,000 barrels of oil per day or nearly 10 percent of lower-48 production. Many of these wells are marginally economic and at risk of being prematurely abandoned, leaving significant amounts of oil unrecovered. In addition, there are some 320,000 natural gas stripper wells in the U.S., accounting for over 1.7 trillion cubic feet of annual production, or 9 percent of the natural gas produced in the lower 48.
SWC Project 1:
Improved Pump-off Controls Help to Maximize Production
Beam pumped wells wrestle with subtle fluid level issues that can make production optimization challenging. If the fluid level in the wellbore is allowed to increase, the increased hydrostatic pressure on the producing reservoir can inhibit the inflow of formation fluids, thereby lowering production. If, on the other hand, beam pumped wells are “pumped off” (i.e., all the fluid is pumped from the wellbore), the pump and rods operate without liquid lubrication, leading to excessive wear on fluid seals and moving parts. This situation can also result in an unbalanced pumping system. Neither of these scenarios is desirable. In the ideal situation, the beam pumping unit would automatically shut off just before all the fluids had been pumped from the wellbore and then begin operation again when the fluid level in the wellbore reaches an optimal level. Until recently, this ideal has been approached through the use of trial-and-error manipulation of timers, with mixed degrees of success. Pre-Pump-Off Controls, a set of technologies developed by Oil Well Sentry, Inc. with support from the Stripper Well Consortium, promises to eliminate troublesome fluid level issues in beam pumped wells. The system works by monitoring each pump stroke for the normal level of fluid refilling the working barrel at the bottom of the well. When the normal level decreases because pump-off is approaching, the motor or engine stops the cycle in 2-3 pump strokes (Figure 1).
Closely monitoring the fluid levels allows for a balance to be achieved between crude oil production time (pumping to pump-off) and the
number of pumping cycles. Typically, using the Well Sentry system allows for an increase in the number of cycles per day, with the pumping times tailored to actual well conditions. Although the pumping time per cycle may be decreased, net production can be significantly increased while energy consumption can be decreased by 30 percent.In addition to stroke-by-stroke fluid level monitoring, the technologies employ a meter that records the exact time of actual production in 6 minute increments. If the meter is checked and reset daily, the average daily pumping times can be compared and a “normal” production time determined for future operation. This reduces the need for physical observation of each well by the lease operator and eliminates guesswork as to how to adjust the system.
Several sensor packages are available in the Well Sentry line, each tailored to specific well parameters. The fluid level sensor measures the fluid level in the working barrel of the pump. The unit mounts on the bridle cables below the horse’s head (Figure 1) and stops the pump operation when the plunger fails to hit fluid high in the working barrel but contacts fluid near the bottom of the barrel.A second set of sensors are installed in the flowline coming off the wellhead and measure fluid volume for each stroke (Figure 2). The production cycle is ended when the average volume of the fluid pulse decreases. Each of the sensors is sized to match output pressure and volume. A third type of sensor monitors pressure of production fluids on each stroke against the backpressure valve on wells that produce associated gas. Back pressure valves are used to prevent gas from entering the pump and production tubing. The sensor terminates the production cycle when the back pressure valve fails to open as usual during a normal pump stroke due to less fluid being pumped. All sensors are accompanied by a control box containing a timer, shut down controls and monitoring units.The Pre-Pump Off controls have been configured to work with natural gas or gasoline powered engines as well as electric motor pump units. In all models, solar panels are being designed to replace batteries for operating the controls. Support from the SWC enabled Oil Well Sentry to refine the system and to develop and test additional sensors and controls. The system is currently commercially available.
6.5 Personnel Plan
Suppliers to the oil and gas (O&G) industry are experiencing a rare phenomenon in today’s economy: Growth.
The increase in shale oil and gas extraction projects has triggered spectacular growth in North American drilling projects, but with this growth comes transportation challenges as suppliers of pipe, chemicals, drilling equipment, water, sand, and other materials must move products to and from an expanding number of drilling sites, many of them in remote locations. All at a time when fuel costs are rising and transportation carrier capacity is shrinking.
A pump jack is a device used in oil production when the pressure inside a well is not sufficient to force oil to the surface. The pump jack is run to physically extract oil for use. Pump jacks were historically used on wells with low production levels, and can be seen dotting the landscape in many regions where oil wells have been dug. The distinctive appearance of the pump jack has become iconic and these devices are often used as symbols of the oil and gas industry, including on some company logos.
Known by names like “nodding donkey,” “grasshopper pump,” and “thirsty bird,” the pump jack consists of a long beam moved by an external power source. As the end of the beam rises and falls, the weighted end dips in and out of the well to extract oil. The other end is connected to a pulley system that is attached to the power source, providing continuous movement of the pump jack while it is turned on.
The same basic mechanics can also be seen in the design of some hand pumped wells, with a human being serving as the power source. Pump jacks can run on generators, as well as central power supplies. In large oil fields, pump jacks can be strung together along a power connection to access a central source of energy. Field workers maintain the devices, providing lubrication and replacing worn out parts.
These devices may not necessarily run full time. Production can be adjusted in response to changing oil prices and other factors, and in addition, some wells need to be allowed to rest to bring the levels of oil up high enough to reach with a pump. Typically, the pump jack extracts a solution of oil and saltwater, along with other impurities, and if a well is worked too hard, the level will fall below the reach of the pump. The ability to adjust production levels with a pump jack allows field workers to control how much oil is extracted, and when.
Once pulled out of the ground with a pump jack, the oil can be moved to containers for shipping and eventual treatment. In the treatment process the impurities will be removed and the oil will be graded and subjected to a series of refinery processes to produce different oil and gas products. The grade of the oil depends on a number of factors, with higher graded oils generally being more valuable.
6.6 General Operations
Finding the Oil
In order to pump oil, several geological elements must fall into place, including the right rocks, a well-formed reservoir and a trap. A trap keeps the oil from leaking away. Geologists study rocks on the surface, as well as beneath the ground. They send shockwaves into the ground and figure out how long it takes for them to bounce off rocks and return to the surface, otherwise known as collecting seismic data. Once they've collected enough seismic data of an area, they can make a three-dimensional map of what's underground and determine whether it's worth ior not t to drill.
The Parts
The most commonly seen oil pump is what's known as the nodding donkey. The big, ovular end that bobs up and down is commonly referred to as the horse's head. It's at the end of a long beam that sits upon a perpendicular beam, which is similar to a tall teeter-totter. On the other end of the beam are weights that are connected to a motor. Off the nose of the horse's head ia a rod that has a submersible pump on the end.
The Mechanics
The motor pulls the weights in a circular motion around a pulley, which tips the beam up and down. This allows gravity to do half the pulling work, making a 25 horsepower engine sufficient enough to move the entire pump. When the beam moves up, the other end moves down, forcing the horse's head to push the rod into the ground. The submersible pump at the end of the rod forces the oil into a tube that is connected to a tank. Then the oil is stored until it's sold or refined.
The Role of Stripper Wells in Meeting the Challenge:
What are stripper wells?
The United States has more oil and gas wells than any other country. As of December 31, 2003, there were more than 524,000 producing oil wells in the United States.That’s more than three times the combined total for the next three leaders: China, Canada and Russia. With just over 390,000 producing gas wells, the U.S. is the worldwide leader in that category as well. Unfortunately however, most of these wells produce relatively small volumes of oil and gas, often on an intermittent and marginally economic basis. Wells that
produce 10 barrels of oil or less per day, or 60 thousand cubic feet (Mcf) of gas or less, are commonly called “stripper”wells. The first use of this term is not recorded, but it follows from the idea that these wells are seen as stripping an underground reservoir of its last few barrels of oil or cubic feet of gas. The Interstate Oil and Gas Compact Commission (IOGCC), which reports the annual status of U.S. stripper wells, recorded 393,463 stripper oil wells producing an average of 2.18 barrels of oil per day, and 260,563 stripper gas wells producing an average of 15.5 Mcf per day, as of January 1, 2004.These totals amount to roughly 77 percent and 63 percent of the country’s total oil and gas well populations, respectively. The number of producing stripper wells changes depending on how many wells enter the ranks (by declining in production) and leave the ranks (by increasing production or being plugged and abandoned) of stripper wells each year. The United States’ stripper oil well population has been gradually declining over the past decade. Although a net of
about 8,000 aging oil wells drop to stripper status each year, roughly another 14,000 are plugged and abandoned, leaving a net reduction in the oil well total of about 6,000 wells per year. At the same time, a net of nearly 14,000 gas wells per year, on average, have dropped to stripper well status over the past decade (about 17,000 per year during 2000-2003). Roughly 3,800 stripper gas wells are plugged and abandoned in the U.S. each year on average, resulting in an average net increase in the stripper gas well population over the past decade of about 10,000 wells per year.
What is their contribution to current domestic supply?
Stripper oil production totaled 313,748,001 barrels in 2003, accounting for 28 percent of production from onshore wells in the lower-48 states; 15 percent of total domestic oil production. Although the top five stripper oil states (Texas,Oklahoma, California, Kansas, and Louisiana) account for about 80 percent of stripper oil and nearly 65 percent of stripper oil wells, stripper production contributes to tax revenues and economic growth in 28 states. Were it to represent the total annual production from any of the 105 nations that produce crude oil, the U.S. stripper well oil production total would place that country in the top third of producers, ahead of Oman, Egypt, Malaysia and Australia.