Tatonka Oil & Gas 8K Entry into a Material Definitive Agreement

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Item 1.01 Entry into a Material Definitive Agreement.

On August 8, 2006, New Pacific Ventures, Inc. (“NPV”) entered into a Share Exchange Agreement (the “Exchange Agreement”) with Tatonka Oil and Gas Company, Inc. (“Tatonka”) and LMA Hughes LLLP (the “Tatonka Shareholder”) whereby NPV, following the effectuation of a 4 for 1 forward stock split, issued 15,000,000 shares of its common stock to the Tatonka Shareholder in exchange for all of the issued and outstanding shares of Tatonka. As a result of the Exchange Agreement, Tatonka became a wholly-owned subsidiary of NPV.

On August 31, 2006, NPV held a meeting of its shareholders, at which time, the holders of a majority of the issued and outstanding shares of NPV approved the 4 for 1 forward stock split and the acquisition of Tatonka in exchange for 15,000,000 post forward stock split shares. The parties completed the exchange and satisfied all closing conditions as set forth in the Exchange Agreement on October 30, 2006.

Brian Hughes, the current President and CFO of Tatonka was appointed the President, CEO and a director of NPV. At closing, Gerry Jardine and Roy Brown resigned as directors. 10 days after the mailing of the information statement on Schedule 14F to the shareholders of NPV, Brent Petterson will resign as a director.

The parties claim an exemption under Rule 506 of Regulation D and Section 4(2) of the Securities Act of 1933, as amended, since, among other things, the transaction did not involve a public offering, the investors were accredited investors and/or qualified institutional buyers, the investors had access to information about the company and their investment, the investors took the securities for investment and not resale, and the Company took appropriate measures to restrict the transfer of the securities.

Item 2.01 Completion of Acquisition or Disposition of Assets.

DESCRIPTION OF TATONKA’S BUSINESS

Overview

Tatonka Oil and Gas Co., Inc. is an independent oil and gas company focused on the exploration and development of unconventional oil and gas resources. Currently, we plan to drill for and extract Methane gas from Coalbeds, known as Coalbed Methane (CBM), and to drill for and extract oil from fractured shales.

Our primary geographic focus is on the Rocky Mountain region, which has been subjectively described as "The Persian Gulf of Unconventional Oil and Gas Resources" because of the amount of gas contained in unconventional gas deposits, such as CBM, tight gas sands and fractured shales.

We believe that Coalbed Methane will become a significant source of competition to conventional natural gas. The potential resources of Coalbed Methane contained in the world’s coal deposits greatly exceed known conventional natural gas resources. In many areas, coalbeds contain three times more gas than found in the equivalent thicknesses of limestone or sandstone.

Tatonka commenced oil and gas operations on March 5, 2004 with the purchase of oil and gas leasehold interests in several properties. As part of its business model, Tatonka seeks to identify and acquire substantive acreage positions in these unconventional resource plays. Tatonka looks for areas that have significant retained or induced permeability.

Our business plan is focused on a strategy for maximizing our expertise in identifying and developing unconventional resources, primarily in the Rocky Mountain region. To date, execution of our business plan has largely focused on identifying prospective Coalbed Methane and fractured shale leases.

Successful Coalbed Methane drilling is dependant on the knowledge and experience of the management team. Brian Hughes is the Chief Executive officer of Tatonka. He has a BS in Engineering from West Point and an MS in Petroleum Engineering from the University of Texas. He has worked as a petroleum engineer for Shell, and as an independent consulting engineer for eighteen years. Mr. Hughes had central roles at Pennaco Energy, Ultra Petroleum and JM Huber Corp. Mr. Hughes has been involved in the acquisition of leases, exploration and production. He is an expert in Coalbed Methane and assembled our development and management team.

The three important concepts in defining economically viable Coalbed Methane acreage are coal thickness, the relationship between gas content and saturation, and permeability. Many of the basins in the Rocky Mountains are subjected to substantial compressive tectonic forces, which can be very detrimental to coal permeability. The foreland basins such as Powder River Basin of Wyoming have not seen significant compressive forces, except in limited areas. Other basins, such as the Sand Wash Basin of Colorado, have high permeability because of a large wrench fault systems. We have acquired approximately 15,000 net acres of undeveloped Coalbed Methane acreage in Northern Colorado’s Sand Wash Basin on which we have a 77% net revenue interest. This acreage is located in Moffat County, Colorado. In addition, we have acquired 7,500 net acres in Powder River Basin of Wyoming, on which we have a 77% net revenue interest.

The leases include the right to develop coal bed methane (CBM) from coals contained in the Williams Fork Formation of Cretaceous age. Other CBM operators in the areas adjacent to and within Tatonka’s Sand Wash Prospect include Pioneer Natural Resources USA, Inc. and CDX. According to Pioneer’s website, 22 wells in their Lay Creek project will be producing by the end of 2006, and another three pilot areas will be drilled and tested.

Thus far, our focus has been on technical and geological studies and preparation for test well drilling. We plan the operations for remainder of 2006 to be focused on the drilling of four to five test wells on the Sand Wash acreage to determine if there are commercial quantities that can be extracted. The completion of this task will require additional capital, which we currently do not have nor for do we have any commitments or agreements.

At the point that the test wells are complete, we will need additional capital to sufficiently expand drilling operations on our initial Sand Wash acreage to the Coalbed Methane seams not being exploited by the initial wells. Tatonka will undertake to maximize production from the initial wells while continuing to drill additional wells on new that is acquired.

Our goal is to discover and produce substantial commercial quantities of Coalbed Methane on the property. There is a pipeline in the region that we believe that can be engaged for transport. However, no assurances can be given that commercial quantities of CBM will be produced, if at all.

For the twelve months that follow, we expect to pursue oil and gas operations on some or all of our property, including the acquisition of additional acreage through leasing, farm-ins or option and participation in the drilling of oil and gas wells. We intend to continue to evaluate additional opportunities in areas where we feel there is potential for oil and gas reserves and production and may participate in areas other than those already identified, although we cannot assure that additional opportunities will be available, or if we participate in additional opportunities, that those opportunities will be successful.

The Coalbed Methane Industry

During the past two decades, Coalbed Methane has emerged as a viable source of natural gas compared to the late 1980s when no significant production outside of the still dominant San Juan Basin in New Mexico, and the Black Warrior Basin in Alabama. According to data from the U.S. Department of Energy’s Energy Information Administration, Coalbed Methane production totalled 1.72 trillion cubic feet in 2004, an increase of 7.5% over 2003. This production accounted for nearly 9% of the country’s total dry-gas output of 19.7 trillion cubic feet. Coalbed Methane production currently comes from fifteen basins located in the Rocky Mountain, Mid-Continent and Appalachian regions. One of the Coalbed Methane industry’s leading information specialists estimates that the number of producing wells nationwide (including those close to achieving production) is approaching 35,000. By comparison, more than 405,000 wells produce natural gas nationwide.

We believe the success of Coalbed Methane developments has been largely the result of improved drilling and completion techniques (including horizontal/lateral completions), better hydraulic fracture designs and significant cost reductions as a result of highly dependable gas content and Coalbed reservoir performance analysis. Also aiding this sector’s growth is the apparent shortage of quality domestic conventional exploration and development projects.

We also believe that a major reason propelling the growth in Coalbed Methane production is its relatively low finding and development costs. Coalbed Methane fields are often found where deeper conventional oil and gas reservoirs have already been developed. Therefore, considerable exploration-cost reducing geologic information is often readily available. This available geological information, combined with comparatively shallow depths of prospective Coalbed reservoirs, reduces finding and development costs.

According to the USGS in 2000, the US CBM resource is about 700 trillion cubic feet (tcf), of which they estimated about 100 tcf to be economic. The US consumes about 22 tcf per year, so CBM presents the equivalent of at least a 5 year supply to our country.

Coalbed Methane

Natural gas normally consists of 80% or more Methane with the balance comprising such hydrocarbons as butane, ethane and propane. In some cases it may contain minute quantities of hydrogen sulfide, referred to as sour gas. Coalbed Methane is, generally, a sweet gas consisting of 95% Methane and thus is normally of pipeline quality. Coalbed Methane is considered an unconventional natural gas resource because it does not rely on conventional trapping mechanisms, such as a fault or anticline, or stratigraphic traps. Instead Coalbed Methane is absorbed or attached to the molecular structure of the coals which is an efficient storage mechanism as Coalbed Methane coals can contain as much as seven times the amount of gas typically stored in a conventional natural gas reservoir such as sandstone or shale.

Coalbed Methane is kept within coal by pressure. To produce the gas the water in the Coalbed has to be removed, generally by using pumps. As pressure is reduced, the gas desorbs from the coal, flows to the well, and flows up the casing. At the wellhead, the flow rate is measured, and the gas is collected and compressed for transmission via pipelines to household, commercial and industrial users hundreds to thousands of miles away. As dewatering begins to lower the reservoir pressure, gas production occurs rapidly. If the target seam is under-saturated at a specific depth, significant water production must occur to reduce the reservoir pressure to allow gas production to commence. This process usually requires the drilling of adjacent wells and sometimes takes 6 to 36 months to complete. Coalbed Methane production typically has a low rate of production decline and an economic life typically of 10 to 20 years.

The principal sources of Coalbed Methane are either biogenic, producing a dry gas which is generated from bacteria in organic matter, typically at depths less than 1,000 feet, or thermogenic, which is a deeper wet gas formed when organic matter is broken down by temperature and pressure.

The three main factors that determine whether or not gas can be economically recovered from Coalbeds are: (1) the relationship between the gas saturation and the content of the coals; (2) the permeability or flow characteristics of the coals; and (3) the thickness of the coalbeds. Gas content is measured in terms of standard cubic feet per ton and varies widely from 430 standard cubic feet per ton in the deep (2,000 to 3,500 feet) San Juan, New Mexico thermogenic coals, and only 60 standard cubic feet per ton for the shallow (300 to 700 feet deep) Powder River, Wyoming biogenic coals. Relatively high permeability, which can affect the ability of gas to easily travel to the borehole, is an important factor for the success of Coalbed Methane wells, but is not absolutely required. The thickness of coalbeds from which Coalbed Methane is economically produced varies from as little as a few feet in some areas of the gas-rich (300 standard cubic feet) Raton Basin to as much as 75 net feet of coalbed thickness at the relatively gas-poor Powder River.

No special technology is needed for CBM extraction. The Powder River basin in Wyoming started using water well technology; in other basins, modified conventional oil and gas technologies were used. The most significant technology used was specialized pump controllers, which allows the operator to monitor production rates and pressures, allowing diagnosis of problems and optimization of production. In some of the deeper Coalbed Methane basins hydraulic fracturing and to a limited degree cavity completions are used to complete the wells.

The price natural gas has to be for feasible economic extraction of CBM depends upon the cost structure of the basin. For the Powder River basin in 2000, it was about $2 per thousand cubic feet (mcf) break even cost. Now, the break-even cost is likely closer to $4/mcf. Factors to be considered include drilling costs, services, and costs to collect and transport the CBM. On this basis, we estimate that the break-even cost in the Sand Wash it was about $2 per thousand cubic feet (mcf).

THE NATURAL GAS INDUSTRY

The Rise of Natural Gas

Little more than a half-century ago, drillers seeking valuable crude oil bemoaned the discovery of natural gas, despite it being the most efficient and cleanest burning fossil fuel. Given the lack of transportation infrastructure at the time, wells had to be capped or the gas flared. As the U.S. economy expanded after World War II, the development of a vast interstate transmission system facilitated widespread consumption of natural gas in homes and business establishments. By 1970, natural gas consumption, on a heat-equivalent basis, had risen to three-fourths that of oil. But in the following decade, consumption lagged because of competitive inroads made by coal and nuclear power.

The demand for natural gas rose sharply in the 1980’s, when consumers and businesses began to find more uses for it. After years as a low-value commodity, natural gas ascended into the spotlight as demand for the fuel to fire power plants, heat homes and serve as a chemical feedstock outstripped the petroleum industry's ability to tap new reserves. In the 1990’s, the popularity of natural gas as an economic and environmentally benign fossil fuel made it the fuel of choice for power generation.

By the year 2000, the U.S. economy was thriving, fueled by cheap energy. To meet the growing need for electricity, U.S. utilities ordered 180,000 Megawatts of gas-fired power plants to be installed by 2005. This was, by far, the largest amount of power generation capacity ever installed in such a short period. As a result, the U.S. electricity supply margins and its economy became dependent on natural gas availability and price. Today, any new electricity capacity brought on line is generated by natural gas, rather than oil, coal, water or nuclear. This has prompted the National Petroleum Council to predict that electricity generation will be responsible for 47% of the increase in natural gas consumption between 1998 and 2010.

U.S. Dependency

The United States currently depends on natural gas for approximately 23% of its total primary energy requirements. But with its commitment to the use of natural gas, particularly in the electricity sector, the U.S. now finds itself with a supply shortage at a time of increased demand.

From 1990 through 2003, natural gas consumption in the United States increased by 14%. In 2004, natural gas demand was expected to increase by 1.1% due to increasing economic growth, the continuing rise in electricity demand, and below-average hydroelectric power levels in the Pacific Northwest. Demand growth in 2005 is expected to be flat as natural gas end-use prices remain high. Still, consumption is expected to increase at an average rate of 1.8% per year to 35 trillion cubic feet (Tcf) per year in 2025, from 22 Tcf in 2003 - a 50% increase over the next two decades.

The demand for natural gas is further influenced by the crude oil market. Although crude oil and natural gas are two separate commodities, their prices have historically been correlated at irregular intervals. Strong oil prices generally keep natural gas prices elevated because fuel oil is a possible substitute for natural gas. As the price of crude oil increases, some industries switch to natural gas. This is particularly true in the electricity sector.

The Supply Shortage

Presently, the United States relies on three sources for its natural gas. Domestic production accounts for 80% of supply. Imports from Canada, mainly the western provinces of Alberta, British Columbia and Saskatchewan provide an additional 17%. Imports of liquefied natural gas make up the remainder.

According to the Macro Energy Outlook 2006 a report produced by Simmons & Company, a recognized authority in the energy industry, domestic natural gas production was expected to decrease from 51.2 billion cubic feet per day (Bcfd) to 49.1 Bcfd in 2005, a decrease of 4%. This same report indicates that domestic production is expected to continue to decline over the next several years resulting in a production rate of 45.3 Bcfd by 2010, a decrease of 8% from 2005 levels. According to the report, high natural gas prices resulted in strong natural gas-directed drilling activity during 2005, however, an uncharacteristically harsh hurricane season in the U.S. Gulf Coast caused significant damage to production infrastructure in that area and had a large negative impact on natural gas production. Production is expected to continue to fall through 2010 despite high levels of industry activity. As indicated in Simmons & Company’s Macro Energy Outlook 2006, issued January 18, 2006, “While we expect domestic drilling activity to increase by 15% in 2006, we do not expect the rig fleet to grow rapidly enough to maintain current production levels.”

According to the Energy Information Administration’s Annual Energy Outlook 2006, despite rising new natural gas well completions, high drilling rates are expected to only modestly improve U.S. domestic production levels to 21.2 Tcf by 2025. Many of the wells that have produced abundant quantities of natural gas since the 1980s and 1990s are in terminal decline, yielding rapidly diminishing returns. These waning reserves have not become readily apparent because the natural gas industry has been bringing new fields online in a frantic effort to keep production levels from dropping too rapidly. Unfortunately, newer plays tend to be smaller and are produced (and depleted) quickly in the effort to maintain overall production levels. Whereas the first year depletion rate of a typical new natural gas well drilled in 1997 was21%, in 2005 the rate was 30%, meaning that new wells are soon depleted and must be replaced. Since nearly half of the U.S. natural gas supply is coming from wells that have been drilled in the past five years, this declining trend is likely to continue.

Canadian Gas Declining

Historically, the United States has looked to Canada for approximately 15% of its natural gas supply. But Canada faces many of the same supply challenges as the United States. While Canadian demand for gas is growing, Canadian producers are also struggling with declining output from mature fields. With gas imports from Canada expected to remain flat at 9.9 Bcfd between 2005 and 2006, and expected to fall to 9.4 Bcfd by 2010, it is unlikely that the U.S. can look to Canada to soften the supply gap anytime soon.

Commodity Price Volatility

Oil and natural gas prices are volatile and subject to a number of external factors. Prices are cyclical and fluctuate as a result of shifts in the balance between supply and demand for oil and natural gas, world and North American market forces, conflicts in Middle Eastern countries, inventory and storage levels, OPEC policy, weather patterns and other factors. OPEC supply curtailment, tensions in the middle east, increased demand in China and low North American crude stocks have kept crude oil prices high. Natural gas prices are greatly influenced by market forces in North America since the primary source of supply is contained within the continent. Market forces include the industry's ability to find new production and reserves to offset declining production, economic factors influencing industrial demand, weather patterns affecting heating demand and the price of oil for fuel switching.

Seasonality

The exploration for oil and natural gas reserves depends on access to areas where operations are to be conducted. Seasonal weather variations, including freeze-up and break-up affect access in certain circumstances. Natural gas is used principally as a heating fuel and for power generation. Accordingly, seasonal variations in weather patterns affect the demand for natural gas. Depending on prevailing conditions, the prices received for sales of natural gas are generally higher in winter than summer months, while prices are generally higher in summer than spring and fall months.

Competition

Coalbed Methane in the United States is produced by several major exploration and production companies and by numerous independents. The majors include BP American and Conoco-Phillips in the San Juan basin and, to a lesser extent, Chevron USA in the Black Warrior Basin. A number of large and mid-size independents, including Anadarko Petroleum Corporation, Devon Energy Corporation, Dominion Resources, Inc., El Paso Corporation, EnCana Corporation, Energen Corporation, Equitable Resources, Inc., Fidelity Exploration & Production Company, GeoMet Inc., J.M. Huber Corporation, Lance Oil & Gas Corporation, Penn Virginia Corporation, Pennaco Energy Inc., Pioneer Natural Resources Company, The Williams Companies, Inc., XTO Energy Inc. and Yates Petroleum Corporation, have established production in one or more basins.

Other new entrants to Coalbed Methane continue to acquire prospective acreage and to conduct test drilling. By virtue of their strategic property holdings, affiliates of several of the country’s largest coal mining companies also have become active in Coalbed Methane, such as Consol Energy Inc., Jim Walter Resources, Inc., Peabody Energy Corporation, USX Corporation and Westmoreland Coal Company.

A number of smaller independents, many of whom originally began with conventional oil and gas production and operating a small number of wells, have found profitable niches in Coalbed Methane. These smaller independents represent the vast majority of initial exploration and development of Coalbed Methane projects. They then find themselves acquired by larger companies. It is very labor intensive, and the overhead of large companies make Coalbed Methane not viable. Small independent CBM producers might drill 1,000 wells in one year, which is about the number wells that Shell drills in a year.

It wasn't until the mid '90s that the industry expanded significantly outside of San Juan and Black Warrior basins. It can therefore be described as a young industry. Further, Coalbed Methane is a resource that is hard to export, it has to be used in the country where it is found. There is no association of CBM producers. However, the oil and gas industry has several associations in the Rockies, such as Petroleum Association of Wyoming, Colorado Oil and Gas Association, and IPAMS, which do include CBM as well as other producers.

Governmental Regulation

Our operations are or will be subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells; maintaining bonding requirements in order to drill or operate wells; implementing spill prevention plans; submitting notification and receiving permits relating to the presence, use and release of certain materials incidental to oil and gas operations; and regulating the location of wells, the method of drilling and casing wells, the use, transportation, storage and disposal of fluids and materials used in connection with drilling and production activities, surface usage and the restoration of properties upon which wells have been drilled, the plugging and abandoning of wells and the transporting of production. Our operations are or will be also subject to various conservation matters, including the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in a unit, and the unitization or pooling of oil and gas properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally limit the venting or flaring of gas, and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas we may be able to produce from our wells and to limit the number of wells or the locations at which we may be able to drill.

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the oil and gas industry. We plan to develop internal procedures and policies to ensure that our operations are conducted in full and substantial environmental regulatory compliance.

Failure to comply with any laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive an effect on our operations than on other similar companies in the energy industry. We do not anticipate any material capital expenditures to comply with federal and state environmental requirements.

From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. There are currently no regulatory or tax incentives for CBM. The industry was kick-started by section 29 of the tax code in the late '80s and early '90s, but today the markets understand CBM well enough for no government incentives to be required. There are many regulatory disincentives, such as the time and effort needed to obtain drilling and water discharge permits. This slows down a company’s ability to develop CBM, and in places prevents development due to the economic impact of the regulations.

Further, the industry does face hurdles set forth by the Bureau of Land Management’s bureaucracy and by the environmental bureaucracies in the Federal and State governments. Just in the ways companies are challenged in gaining permits to produce the wells.

Environmental Regulation

Operations on properties in which we have an interest are subject to extensive federal, state and local environmental laws that regulate the discharge or disposal of materials or substances into the environment and otherwise are intended to protect the environment. Numerous governmental agencies issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial administrative, civil and criminal penalties and in some cases injunctive relief for failure to comply.

Some laws, rules and regulations relating to the protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination. These laws render a person or company liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills in certain states, consequential damages without regard to negligence or fault. Other laws, rules and regulations may require the rate of oil and gas production to be below the economically optimal rate or may even prohibit exploration or production activities in environmentally sensitive areas. In addition, state laws often require some form of remedial action, such as closure of inactive pits and plugging of abandoned wells, to prevent pollution from former or suspended operations.

Legislation has been proposed in the past and continues to be evaluated in Congress from time to time that would reclassify certain oil and gas exploration and production wastes as “hazardous wastes.” This reclassification would make these wastes subject to much more stringent storage, treatment, disposal and clean-up requirements, which could have a significant adverse impact on operating costs. Initiatives to further regulate the disposal of oil and gas wastes are also proposed in certain states from time to time and may include initiatives at the county, municipal and local government levels. These various initiatives could have a similar adverse impact on operating costs.

The regulatory burden of environmental laws and regulations increases our cost and risk of doing business and consequently affects our profitability. The federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes liability, without regard to fault, on certain classes of persons with respect to the release of a “hazardous substance” into the environment. These persons include the current or prior owner or operator of the disposal site or sites where the release occurred and companies that transported, disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for the federal or state government to pursue such claims.

It is also not uncommon for neighboring landowners and other third parties to file claims for personal injury or property or natural resource damages allegedly caused by the hazardous substances released into the environment. Under CERCLA, certain oil and gas materials and products are, by definition, excluded from the term “hazardous substances.” Similarly, under the federal Resource, Conservation and Recovery Act, or RCRA, which governs the generation, treatment, storage and disposal of “solid wastes” and “hazardous wastes,” certain oil and gas materials and wastes are exempt from the definition of “hazardous wastes.” This exemption continues to be subject to judicial interpretation and increasingly stringent state interpretation. During the normal course of operations on properties in which we have an interest, exempt and non-exempt wastes, including hazardous wastes, that are subject to RCRA and comparable state statutes and implementing regulations are generated or have been generated in the past. The federal Environmental Protection Agency and various state agencies continue to promulgate regulations that limit the disposal and permitting options for certain hazardous and non-hazardous wastes.

We plan to establish guidelines and management systems to ensure compliance with environmental laws, rules and regulations. The existence of these controls cannot, however, guarantee total compliance with environmental laws, rules and regulations.

We believe that the operator of the properties in which we have an interest is in substantial compliance with applicable laws, rules and regulations relating to the control of air emissions at all facilities on those properties. Although we will maintain insurance against some, but not all, of the risks described above, including insuring the costs of clean-up operations, public liability and physical damage, there is no assurance that our insurance will be adequate to cover all such costs, that the insurance will continue to be available in the future or that the insurance will be available at premium levels that justify our purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and operations. Compliance with environmental requirements, including financial assurance requirements and the costs associated with the cleanup of any spill, could have a material adverse effect on our capital expenditures, earnings or competitive position. We do believe, however, that our operators are in substantial compliance with current applicable environmental laws and regulations. Nevertheless, changes in environmental laws have the potential to adversely affect operations. At this time, we have no plans to make any material capital expenditures for environmental control facilities.

Compared to developing coal for heating or electricity in the US, CBM has a smaller environmental ‘footprint’. This includes the amount of surface disturbance and air emissions. Overseas, a modest Coalbed Methane well in Africa produces fuel equivalent to 300,000 trees. As a result, in such places, Coalbed Methane when developed, will contribute to reduction in deforestation.

Employees

As of October 26, 2006, we had seven full-time, at will employees. We plan to enter into employment agreements shortly with our employees. We consider our relations with our employees to be good.

Description of Property

We maintain our principal office at 1515 Arapahoe Street, Tower 1, 10^th floor, Denver, Colorado. Our telephone number at that office is (720) 261-1491. Our current office space consists of approximately 1,500 square feet. The lease runs until August 31, 2007 at a cost of $8,000 per month. We believe that our current office space and facilities are sufficient to meet our present needs and do not anticipate any difficulty securing alternative or additional space, as needed, on terms acceptable to us.

Legal Proceedings

From time to time, the Company may become involved in various lawsuits and legal proceedings, which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters may arise from time to time that may harm its business. Tatonka is currently not aware of any such legal proceedings or claims that it believes will have, individually or in the aggregate, a material adverse affect on its business, financial condition or operating results.

RISK FACTORS

We Have a History Of Losses Which May Continue, Which May Negatively Impact Our Ability to Achieve Our Business Objectives.

We incurred net losses of $43,262 and $24,008 for the year ended December 31, 2005 and for the period from March 5, 2004 (date of inception) to December 31, 2004, respectively. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the establishment of a business enterprise. There can be no assurance that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether we will be able to continue expansion of our revenue. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on us.

Our Independent Auditors Have Expressed Substantial Doubt About Our Ability to Continue As a Going Concern, Which May Hinder Our Ability to Obtain Future Financing.

In their report dated June 30, 2006, our independent auditors stated that our financial statements were prepared assuming that we would continue as a going concern. Our ability to continue as a going concern is an issue raised as a result of recurring losses from operations. We continue to experience net operating losses. Our ability to continue as a going concern is subject to our ability to generate a profit and/or obtain necessary funding from outside sources, including obtaining additional funding from the sale of our securities, increasing sales or obtaining loans and grants from various financial institutions where possible. Our continued net operating losses increase the difficulty in meeting such goals and there can be no assurances that such methods will prove successful.

We Have a Limited Operating History and if We are not Successful in Continuing to Grow Our Business, Then We may have to Scale Back or Even Cease Our Ongoing Business Operations.

We have no history of revenues from operations. We have yet to generate positive earnings and there can be no assurance that we will ever operate profitably. Our company has a limited operating history and must be considered in the exploration stage. Our success is significantly dependent on a successful drilling, completion and production program. Our operations will be subject to all the risks inherent in the establishment of a developing enterprise and the uncertainties arising from the absence of a significant operating history. We may be unable to locate recoverable reserves or operate on a profitable basis. We are in the exploration stage and potential investors should be aware of the difficulties normally encountered by enterprises in the exploration stage. If our business plan is not successful, and we are not able to operate profitably, investors may lose some or all of their investment in our company.

Because We Are Small and Do Not Have Much Capital, We May Have to Limit our Exploration Activity Which May Result in a Loss of Your Investment.

Because we are small and do not have much capital, we must limit our exploration activity. As such we may not be able to complete an exploration program that is as thorough as we would like. In that event, existing reserves may go undiscovered. Without finding reserves, we cannot generate revenues and you will lose your investment.

If We Are Unable to Retain the Services of Mr. Brian Hughes or If We Are Unable to Successfully Recruit Qualified Managerial and Field Personnel Having Experience in Oil and Gas Exploration, We May Not Be Able to Continue Our Operations.

Our success depends to a significant extent upon the continued services of Mr. Brian Hughes, our Chief Executive Officer, President, and a director. Loss of the services of Mr. Hughes could have a material adverse effect on our growth, revenues, and prospective business. In order to successfully implement and manage our business plan, we will be dependent upon, among other things, successfully recruiting qualified managerial and field personnel having experience in the oil and gas exploration business. Competition for qualified individuals is intense. There can be no assurance that we will be able to find, attract and retain existing employees or that we will be able to find, attract and retain qualified personnel on acceptable terms.

As Our Properties are in the Exploration Stage, There Can be no Assurance That We Will Establish Commercial Discoveries on Our Properties.

Exploration for economic reserves of oil and gas is subject to a number of risk factors. Few properties that are explored are ultimately developed into producing oil and/or gas wells. Our properties are in the exploration stage only and are without proven reserves of oil and gas. We may not establish commercial discoveries on any of our properties.

The Potential Profitability of Oil and Gas Ventures Depends Upon Factors Beyond the Control of Our Company.

The potential profitability of oil and gas properties is dependent upon many factors beyond our control. For instance, world prices and markets for oil and gas are unpredictable, highly volatile, potentially subject to governmental fixing, pegging, controls, or any combination of these and other factors, and respond to changes in domestic, international, political, social, and economic environments. Additionally, due to worldwide economic uncertainty, the availability and cost of funds for production and other expenses have become increasingly difficult, if not impossible, to project. These changes and events may materially affect our financial performance.

Adverse weather conditions can also hinder drilling operations. A productive well may become uneconomic in the event no water or other deleterious substances are encountered which impair or prevent the production of oil and/or gas from the well. In addition, production from any well may be uneconomic if it is not impregnated with water or other deleterious substances. The marketability of oil and gas which may be acquired or discovered will be affected by numerous factors beyond our control. These factors include the proximity and capacity of oil and gas pipelines and processing equipment, market fluctuations of prices, taxes, royalties, land tenure, allowable production and environmental protection. These factors cannot be accurately predicted and the combination of these factors may result in our company not receiving an adequate return on invested capital.

Competition In The Oil And Gas Industry Is Highly Competitive And There Is No Assurance That We Will Be Successful In Acquiring New Leases.

The oil and gas industry is intensely competitive. We compete with numerous individuals and companies, including many major oil and gas companies, which have substantially greater technical, financial and operational resources and staffs. Accordingly, there is a high degree of competition for desirable oil and gas leases, suitable properties for drilling operations and necessary drilling equipment, as well as for access to funds. We cannot predict if the necessary funds can be raised or that any projected work will be completed.

The Marketability of Natural Resources Will be Affected by Numerous Factors Beyond Our Control Which May Result in Us not Receiving an Adequate Return on Invested Capital to be Profitable or Viable.

The marketability of natural resources which may be acquired or discovered by us will be affected by numerous factors beyond our control. These factors include market fluctuations in oil and gas pricing and demand, the proximity and capacity of natural resource markets and processing equipment, governmental regulations, land tenure, land use, regulation concerning the importing and exporting of oil and gas and environmental protection regulations. The exact effect of these factors cannot be accurately predicted, but the combination of these factors may result in us not receiving an adequate return on invested capital to be profitable or viable.

Oil and Gas Operations are Subject to Comprehensive Regulation Which May Cause Substantial Delays or Require Capital Outlays in Excess of Those Anticipated Causing an Adverse Effect on Our Company.

Oil and gas operations are subject to federal, state, and local laws relating to the protection of the environment, including laws regulating removal of natural resources from the ground and the discharge of materials into the environment. Oil and gas operations are also subject to federal, state, and local laws and regulations which seek to maintain health and safety standards by regulating the design and use of drilling methods and equipment. Various permits from government bodies are required for drilling operations to be conducted; no assurance can be given that such permits will be received. Environmental standards imposed by federal, state or local authorities may be changed and any such changes may have material adverse effects on our activities. Moreover, compliance with such laws may cause substantial delays or require capital outlays in excess of those anticipated, thus causing an adverse effect on us. Additionally, we may be subject to liability for pollution or other environmental damages which it may elect not to insure against due to prohibitive premium costs and other reasons. To date we have not been required to spend any material amount on compliance with environmental regulations. However, we may be required to do so in future and this may affect our ability to expand or maintain our operations.

Exploration Activities are Subject to Certain Environmental Regulations Which May Prevent or Delay the Commencement or Continuance of Our Operations.

In general, our exploration activities are subject to certain federal, state and local laws and regulations relating to environmental quality and pollution control. Such laws and regulations increase the costs of these activities and may prevent or delay the commencement or continuance of a given operation. Compliance with these laws and regulations has not had a material effect on our operations or financial condition to date. Specifically, we are subject to legislation regarding emissions into the environment, water discharges and storage and disposition of hazardous wastes. In addition, legislation has been enacted which requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities. However, such laws and regulations are frequently changed and we are unable to predict the ultimate cost of compliance. Generally, environmental requirements do not appear to affect us any differently or to any greater or lesser extent than other companies in the industry.

We believe that our operations comply, in all material respects, with all applicable environmental regulations. Our operating partners maintain insurance coverage customary to the industry; however, we are not fully insured against all possible environmental risks.

Exploratory Drilling Involves Many Risks and We May Become Liable for Pollution or Other Liabilities Which May Have an Adverse Effect on Our Financial Position.

Drilling operations generally involve a high degree of risk. Hazards such as unusual or unexpected geological formations, power outages, labor disruptions, blow-outs, sour gas leakage, fire, inability to obtain suitable or adequate machinery, equipment or labor, and other risks are involved. We may become subject to liability for pollution or hazards against which we cannot adequately insure or which we may elect not to insure. Incurring any such liability may have a material adverse effect on our financial position and operations.

Any Change to Government Regulation/Administrative Practices May Have a Negative Impact on Our Ability to Operate and Our Profitability.

The laws, regulations, policies or current administrative practices of any government body, organization or regulatory agency in the United States or any other jurisdiction, may be changed, applied or interpreted in a manner which will fundamentally alter the ability of our company to carry on our business.

The actions, policies or regulations, or changes thereto, of any government body or regulatory agency, or other special interest groups, may have a detrimental effect on us. Any or all of these situations may have a negative impact on our ability to operate and/or our profitably.

MANAGEMENT’S DISCUSSION AND ANALYSIS

Forward Looking Statements

Some of the statements contained in this Form 8-K that are not historical facts are "forward-looking statements" which can be identified by the use of terminology such as "estimates," "projects," "plans," "believes," "expects," "anticipates," "intends," or the negative or other variations, or by discussions of strategy that involve risks and uncertainties. We urge you to be cautious of the forward-looking statements, that such statements, which are contained in this Form 8-K, reflect our current beliefs with respect to future events and involve known and unknown risks, uncertainties and other factors affecting our operations, market growth, services, products and licenses. No assurances can be given regarding the achievement of future results, as actual results may differ materially as a result of the risks we face, and actual events may differ from the assumptions underlying the statements that have been made regarding anticipated events. Factors that may cause actual results, our performance or achievements, or industry results, to differ materially from those contemplated by such forward-looking statements include without limitation:

·	Our ability to attract and retain management, and to integrate and maintain technical information and management information systems;

·	Our ability to raise capital when needed and on acceptable terms and conditions;

·	The intensity of competition; and

·	General economic conditions.

All written and oral forward-looking statements made in connection with this Form 8-K that are attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. Given the uncertainties that surround such statements, you are cautioned not to place undue reliance on such forward-looking statements.

Overview

Tatonka commenced oil and gas operations on March 5, 2004 with the purchase of oil and gas leasehold interests in several properties. As part of its business model, the company seeks to identify acquire substantive acreage positions in these unconventional resource plays. The company looks for areas that have significant retained or induced permeability.

Our business plan is focused on a strategy for maximizing the long-term development of our drilling and exploration projects in the Rocky Mountain region. To date, execution of our business plan has largely focused on identifying prospective Coalbed Methane and to a lesser degree, fractured shale leases.

Brian Hughes is the Chief Executive Officer. He has worked as a petroleum engineer for Shell, and as an independent consulting engineer for eighteen years. Mr. Hughes has been involved in the acquisition of leases, exploration and production. He has substantial experience with Methane and assembled our development and management team. We have seven fulltime employees working on geology, exploration, production, production technology and corporate finance. Our team’s industry experience base totals more than 120 years.

Operations Plans

We have acquired approximately than 15,000 net acres of undeveloped Coalbed Methane (CBM) acreage in Northern Colorado’s Sandwash River Basin on which we have a 77% net revenue interest. The Sand Wash project has an estimated CBM resource of 1.4 tcf, with other resource potential. In addition, we have acquired 7,500 net acres in Powder River Basin of Wyoming, on which we have a 77% net revenue interest, which is a pure exploration play.

Thus far, our focus has been on technical and geological study and preparation for test well drilling. We plan the operations for remainder of 2006 to be focused on the drilling of four to five test wells on the Sandwash acreage to prove out the resources. The completion of this task will require additional capital beyond what we currently have on hand.

At the point that the test wells are complete, we plan to seek additional investment capital to sufficiently expand drilling operations on our initial Sandwash acreage to the Coalbed Methane seams not being exploited by the initial wells. Tatonka will undertake to maximize production from the initial wells while continuing to drill additional wells on new acreage that is acquired.

For the next twelve months that follow, we expect to pursue oil and gas operations on some or all of our property, including the acquisition of additional acreage through leasing, farm-ins or option and participation agreements in the drilling of oil and gas wells. We intend to continue to evaluate additional opportunities in areas where we feel there is potential for oil and gas reserves and production and may participate in areas other than those already identified, although we cannot assure that additional opportunities will be available, or if we participate in additional opportunities, that those opportunities will be successful.

Gas wells have production rates that naturally decline over time, and that decline must be replaced to maintain or increase total gas production. The US consumes about 22 tcf per year, and this is expected to grow to 25 tcf per year within 10 years.

Decline rates depend on the type of gas reservoir; for CBM reservoirs, this can be 7% to 25% per year. In other words, CBM well production rates can be expected to halve every 3 to 10 years, and we have to drill 7% to 25% more wells annually just to keep up with declines from existing wells.

Our current cash position is not sufficient to fund our cash requirements during the next twelve months, including operations and capital expenditures. We intend to seek joint ventures or obtain equity and/or debt financing to support our current and proposed oil and gas operations and capital expenditures. We cannot assure that continued funding will be available.

Our future financial results will depend primarily on (1) our ability to discover or produce commercial quantities of oil and gas; (2) the market price for oil and gas; (3) our ability to continue to source and screen potential projects; and (4) our ability to fully implement our exploration and development program with respect to these and other matters. We cannot assure that we will be successful in any of these activities or that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production

We have not entered into commodity swap arrangements or hedging transactions. Although we have no current plans to do so, we may enter into commodity swap and/or hedging transactions in the future in conjunction with oil and gas production. We have no off-balance sheet arrangements.

Liquidity and Capital Resources

Net of fees at the close of the recent equity private placement we had $4,500,000 in available cash. As stated in the purchase and sale agreement, there were advances from a director of Tatonka of which a maximum of $650,000 is to be repaid on the closing of the acquisition of Tatonka, these expenses represented oil and gas leases, leasehold improvements, geological surveys and equipment development purchased by a director of Tatonka prior and subsequent to the date of the offering memorandum. There is also approximately another $285,000 in expenses incurred by the director of Tatonka in the period leading up to the close of the New Pacific transaction that is also to be reimbursed. Adjusting for these cash expenditures, we have approximately $3,565,000 in available cash.

We plan to continue to provide for our capital needs by issuing equity securities. The included Pro-Forma financial statements do not include any adjustments to the amount and classification of assets and liabilities that may be necessary should we be unable to continue as a going concern.

We will require additional financing in order to complete our stated plan of operations for the next twelve months. We believe that we will require additional financing to carry out our intended objectives during the next twelve months. There can be no assurance, however, that such financing will be available or, if it is available, that we will be able to structure such financing on terms acceptable to us and that it will be sufficient to fund our cash requirements until we can reach a level of profitable operations and positive cash flows. If we are unable to obtain the financing necessary to support our operations, we may be unable to continue as a going concern. We currently have no firm commitments for any additional capital.

The trading price of our shares of common stock and the downturn in the United States stock and debt markets could make it more difficult to obtain financing through the issuance of equity or debt securities. Even if we are able to raise the funds required, it is possible that we could incur unexpected costs and expenses, fail to collect significant amounts owed to us, or experience unexpected cash requirements that would force us to seek alternative financing. Further, if we issue additional equity or debt securities, stockholders may experience additional dilution or the new equity securities may have rights, preferences or privileges senior to those of existing holders of our shares of common stock. If additional financing is not available or is not available on acceptable terms, we will have to curtail our operations.

Summary of Significant Accounting Policies

Our consolidated financial statements have been prepared on a going concern basis. Our ability to continue as a going concern is dependent upon our ability to generate profitable operations in the future and/or to obtain the necessary financing to meet our obligations and repay our liabilities arising from normal business operations when they come due. The outcome of these matters cannot be predicted with any certainty at this time.

The financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the United States of America. Because a precise determination of many assets and liabilities is dependent upon future events, the preparation of financial statements for a period necessarily involves the use of estimates which have been made using careful judgment. Actual results may vary from these estimates.

The financial statements have, in management’s opinion been properly prepared within the framework of the significant accounting policies summarized below:

Accounting Estimates

The preparation of the consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Management makes its best estimate of the ultimate outcome for these items based on the historical trends and other information available when the consolidated financial statements are prepared. Changes in the estimates are recognized in accordance with the accounting rules for the estimate, which is typically in the period when new information becomes available to management. Actual results could differ from those estimates and assumptions.

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Company considers all investment purchased with a maturity of three months or less to be cash equivalents.

Exploration Stage Company

The Company complies with Financial Accounting Standards Board Statement No. 7 and Securities and Exchange Commission Act Guide 7 for its characterization of the Company as exploration stage.

Oil and Gas Properties

The Company follows the full cost method of accounting for oil and gas operations whereby all costs of exploring for and developing oil and gas reserves are initially capitalized on a country-by-country (cost centre) basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling and overhead charges directly related to acquisition and exploration activities. Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves. Petroleum products and reserves are converted to a common unit of measure, using 6 MCF of natural gas to one barrel of oil.

Costs of acquiring and evaluating unproved properties are initially excluded from depletion calculations. These unevaluated properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

Future net cash flows from proved reserves using period-end, non-escalated prices and costs, are discounted to present value and compared to the carrying value of oil and gas properties.

Proceeds from a sale of petroleum and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would alter the rate of depletion by more than 20%. Royalties paid net of any tax credits received are netted with oil and gas sales.

Asset Retirement Obligations

The Corporation recognizes the fair value of a liability for an asset retirement obligation in the year in which it is incurred when a reasonable estimate of fair value can be made. The carrying amount of the related long-lived asset is increased by the same amount as the liability.

Changes in the liability for an asset retirement obligation due to the passage of time will be measured by applying an interest method of allocation. The amount will be recognized as an increase in the liability and an accretion expense in the statement of operations. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or a decrease in the carrying amount of the liability for an asset retirement obligation and the related asset retirement cost capitalized as part of the carrying amount of the related long-lived asset. At December 31, 2005 and 2004, the fair value of the oil and gas property’s site restoration costs is insignificant.

Long-Lived Assets Impairment

Our long-term assets are reviewed when changes in circumstances require as to whether their carrying value has become impaired, pursuant to guidance established in SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Management considers assets to be impaired if the carrying value exceeds the future projected cash flows from the related operations, undiscounted and without interest charges. If impairment is deemed to exist, the assets will be written down to fair value, and a loss is recorded as the difference between the carrying value and the fair value. Fair values are determined based on the quoted market values, discounted cash flows or internal and external appraisal, as applicable. Assets to be disposed of are carried at the lower of carrying value or estimated net realizable value.

Income Taxes

We have adopted SFAS No. 109, “Accounting for Income Taxes”, going forward, which requires us to recognize deferred tax liabilities and assets for the expected future tax consequences of events that have been recognized in our consolidated financial statements or tax returns using the liability method. Under this method, deferred tax liabilities and assets are determined based on the temporary differences between the consolidated financial statements and tax bases of assets and liabilities using enacted tax rates in effect in the years in which the differences are expected to reverse.

Financial Instruments

The carrying value of cash and accounts payable and accrued liabilities approximates their fair value because of the short maturity of these instruments. It is management’s opinion that the Company is not exposed to significant interest, currency or credit risks arising from these financial instruments.

Stock-based Compensation

We have adopted SFAS No. 123 “Accounting for Stock Based Compensation” as amended by SFAS No. 148 "Accounting for Stock-based Compensation - Transition and Disclosure”. We will recognize stock-based compensation expense using a fair value based method. New Pacific did have a stock option plan in place that we intend to modify as needed.

Accounting for Derivative Instruments and Hedging Activities

We have adopted SFAS No. 133 “Accounting for Derivative and Hedging Activities”, which requires companies to recognize all derivative contracts as either assets or liabilities in the balance sheet and to measure them at fair value. If certain conditions are met, a derivative may be specifically designated as a hedge, the objective of which is to match the timing of gain and loss recognition on the hedging derivative with the recognition of (i) the changes in the fair value of the hedged asset or liability that are attributable to the hedged risk or (ii) the earnings effect of the hedged forecasted transaction. For a derivative not designated as a hedging instrument, the gain or loss is recognized in income in the period of change. We have not entered into derivative contracts either to hedge existing risks or for speculative purposes, but we plan to use derivative contracts in the future solely for hedging prices on production.

MANAGEMENT

Executive Officers and Directors

Below are the names and certain information regarding the Company’s executive officers and directors following the acquisition of Tatonka.

Name	Age	Position
Brian Hughes	51	President, Chief Executive Officer, Secretary and Director

Officers are elected annually by the Board of Directors (subject to the terms of any employment agreement), at its annual meeting, to hold such office until an officer’s successor has been duly appointed and qualified, unless an officer sooner dies, resigns or is removed by the Board.

Background of Executive Officers and Directors

Brian Hughes. Mr. Hughes became President/CEO/Director / Secretary-Treasurer, with the closing of the transaction between New Pacific and Tatonka. Mr. Hughes studied at West Point from 1973 to 1977 and graduated with a BSc in Engineering. Mr. Hughes studied at the University of Texas from 1983 to 1985 and graduated with an MSc in Petroleum Engineering at the University of Texas. From 2000 until now, Mr. Hughes has been an independent oil and gas investor. Mr. Hughes prior employment history included three years as a Petroleum Engineer at Shell before embarking on a career as an independent petroleum engineer for eighteen years. Mr. Hughes had central roles at Pennaco Energy, Ultra Petroleum and The JM Huber Corp. His prior gas projects have achieved a combined market capitalization exceeding $8 Billion, producing more than 500 MMCFPD and generating more than $3 million per day in revenue.

Executive Compensation

The following table sets forth all compensation paid in respect of the Company’s Chief Executive Officer and those individuals who received compensation in excess of $100,000 per year (collectively, the "Named Executive Officers") for our last three completed fiscal years.

SUMMARY COMPENSATION TABLE
					Long-Term Compensation
		Annual Compensation			Awards		Payouts
Name and Principal Position	Fiscal Year	Annual Salary ($)	Annual Bonus ($)	Other Annual Compensation ($)	Restricted Stock Awards ($)	Securities Underlying Options/SARs (#)	LTIP Payouts ($)	All Other Compensation ($)

Brian Hughes, CEO	2005	0	0	0	0	0	0	0
	2004	0	0	0	0	0	0	0
	2003	0	0	0	0	0	0	0

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

LMA Hughes LLLP provided $650,000 in advances to the Company, which were repaid upon the closing of a private placement in October 2006. These advances were for oil and gas leases, leasehold improvements, geological surveys and equipment development purchased for Tatonka. Brian Hughes, our CEO, is the President of Hughes Ventures, which is the general partner of LMA Hughes LLLP. Mr. Hughes, his ex-wife and three minor children are the limited partners of LMA Hughes LLLP.

LMA Hughes LLLP holds overriding royalties on the difference between the 77% net revenue interest purchased by New Pacific and the original leases purchased by the partnership. We do not anticipate granting such overrides on acreage that is acquired going forward.

None of the other Directors or other Officers of the Company, nor any proposed nominee for election as a Director of the Company, nor any person who beneficially owns, directly or indirectly, shares carrying more than 10% of the voting rights attached to all outstanding shares of the Company, nor any promoter of the Company, nor any relative or spouse of any of the foregoing persons has any material interest, direct or indirect, in any transaction since the incorporation date of or in any presently proposed transaction which, in either case, has or will materially affect the Company. The Company has not entered into transactions with any member of the immediate families of the foregoing persons, nor is any such transaction proposed.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth certain information, as of October 26, 2006 with respect to the beneficial ownership of the outstanding common stock by (i) any holder of more than five (5%) percent; (ii) each of the Company’s executive officers and directors; and (iii) the Company’s directors and executive officers as a group. Except as otherwise indicated, each of the stockholders listed below has sole voting and investment power over the shares beneficially owned.

Name of Beneficial Owner (1)	Common Stock Beneficially Owned	Percentage of Common Stock (2)
Brian Hughes (3)	15,000,000	27.27%
Brent Petterson	2,000,000	3.64%
All officers and directors as a group (2 persons)	17,000,000	30.91%
LMA Hughes LLLP (3)	15,000,000	27.27%

(1)	Except as otherwise indicated, the address of each beneficial owner is c/o Tatonka Oil and Gas Company, Inc. 1515 Arapahoe Street, Tower 1, 10^th floor, Denver, Colorado 80202.

(2)

Applicable percentage ownership is based on 55,000,000 shares of common stock outstanding as of October 26, 2006, together with securities exercisable or convertible into shares of common stock within 60 days of October 26, 2006 for each stockholder. Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and generally includes voting or investment power with respect to securities. Shares of common stock that are currently exercisable or exercisable within 60 days of October 26, 2006 are deemed to be beneficially owned by the person holding such securities for the purpose of computing the percentage of ownership of such person, but are not treated as outstanding for the purpose of computing the percentage ownership of any other person.

(3)	Mr. Hughes is the President of Hughes Ventures, which is the general partner of LMA Hughes LLLP and has voting and investment control of the shares owned by LMA Hughes LLLP.

·	No Director, executive officer, affiliate or any owner of record or beneficial owner of more than 5% of any class of voting securities of the Company is a party adverse to the Company or has a material interest adverse to the Company.

DESCRIPTION OF SECURITIES

The Company’s authorized capital stock consists of 100,000,000 shares of common stock at a par value of $0.001 per share and 25,000,000 shares of preferred stock at a par value of $0.001 per share. As of October 26, 2006, there were 55,000,000 shares of the Company’s common stock issued and outstanding that are held by approximately 52 stockholders of record and no shares of preferred stock issued and outstanding.

Holders of the Company’s common stock are entitled to one vote for each share on all matters submitted to a stockholder vote. Holders of common stock do not have cumulative voting rights. Therefore, holders of a majority of the shares of common stock voting for the election of directors can elect all of the directors. Holders of the Company’s common stock representing a majority of the voting power of the Company’s capital stock issued, outstanding and entitled to vote, represented in person or by proxy, are necessary to constitute a quorum at any meeting of stockholders. A vote by the holders of a majority of the Company’s outstanding shares is required to effectuate certain fundamental corporate changes such as liquidation, merger or an amendment to the Company’s articles of incorporation.

Holders of the Company’s common stock are entitled to share in all dividends that the board of directors, in its discretion, declares from legally available funds. In the event of a liquidation, dissolution or winding up, each outstanding share entitles its holder to participate pro rata in all assets that remain after payment of liabilities and after providing for each class of stock, if any, having preference over the common stock. The Company’s common stock has no pre-emptive rights, no conversion rights and there are no redemption provisions applicable to the Company’s common stock.

MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The Company’s common stock is traded on the OTC Bulletin Board, referred to herein as the OTCBB, under the symbol “NPFC” Prior to September 18, 2006, the Company’s stock traded under the symbol “NPFV.” The Company’s common stock was first eligible for quotation on the OTCBB April 13, 2005. To date, there has not been any market activity in the Company’s common stock.

Dividends

On September 18, 2005, the Company declared a 4 for 1 forward stock split. The Company has never declared or paid any cash dividends on its common stock. The Company currently intends to retain future earnings, if any, to finance the expansion of its business. As a result, the Company does not anticipate paying any cash dividends in the foreseeable future.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table shows information with respect to each equity compensation plan under which the Company’s common stock is authorized for issuance as of the fiscal year ended December 31, 2005.

EQUITY COMPENSATION PLAN INFORMATION

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)
	(a)	(b)	(c)
Equity compensation plans approved by security holders	-0-	-0-	-0-

Equity compensation plans not approved by security holders	-0-	-0-	-0-

Total	-0-	-0-	-0-

INDEMNIFICATION OF DIRECTORS AND OFFICERS

The Company’s directors and executive officers are indemnified as provided by the Colorado Business Corporation Act and the Company’s Articles of Incorporation and Bylaws. These provisions state that the Company’s directors may cause the Company to indemnify a director or former director against all costs, charges and expenses, including an amount paid to settle an action or satisfy a judgment, actually and reasonably incurred by him as a result of him acting as a director. The indemnification of costs can include an amount paid to settle an action or satisfy a judgment. Such indemnification is at the discretion of the Company’s board of directors and is subject to the Securities and Exchange Commission’s policy regarding indemnification.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, or otherwise, the Company has been advised that in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable.

Item 3.02 Unregistered Sales of Equity Securities.

On October 30, 2006, the Company closed a private placement, in which it issued 10 million shares of common stock to 21 accredited investors, at a purchase price of $0.50 per share. This issuance of common stock is exempt from the registration requirements under Rule 506 of Regulation D and Rule 4(2) of the Securities Act of 1933, as amended.

Pursuant to a Share Exchange Agreement dated August 3, 2006, the Company issued 15,000,000 shares of common stock to Brian Hughes. This issuance of common stock is exempt from the registration requirements under Rule 4(2) of the Securities Act of 1933, as amended.

Item 5.01 Changes in Control of Registrant.

See Item 2.01.

Item 5.02 Departure of Directors or Principal Officers; Election of Directors; Appointment of Principal Officers.

See Item 1.01.

Item 5.06 Change in Shell Company Status.

See Item 2.01

Item 9.01 Financial Statements and Exhibits.

(a) Financial statements of business acquired.

Audited Financial Statements of Tatonka Oil and Gas Company, Inc. for the fiscal years ended December 31, 2005 and 2004 and unaudited financial statements for the three and six month period ended June 30, 2006.

(b) Pro forma financial information.

Not applicable.

Consolidated unaudited pro forma financial statements December 31, 2005 and July 31, 2006.

(d) Exhibits

Exhibit Number		Description
10.1		Agreement of Share Exchange and Purchase of Sale, by and among New Pacific Ventures, Inc., Tatonka Oil and Gas Company, Inc. and the shareholder of Tatonka Oil and Gas Company, Inc., previously filed as an exhibit to the quarterly report on Form 10-QSB, filed by New Pacific Ventures, Inc. on September 15, 2006 and incorporated herein by reference.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	NEW PACIFIC VENTURES, INC.

Dated: November 2, 2006	By:	/s/ BRIAN HUGHES
		Name: Brian Hughes
		Title: Chief Executive Officer

TATONKA OIL AND GAS COMPANY, INC.

Index to Financial Statements

	Page
Report of Independent Registered Certified Public Accounting Firm	F-2
Balance Sheets as of December 31, 2005 and 2004	F-3
Statement of Operations for the fiscal years ended December 31, 2005 and 2004 and for the period March 5, 2004 (date of inception) through December 31, 2005	F-4
Statements of Members Equity for the period March 5, 2004 (date of inception) through December 31, 2005	F-5
Statement of Cash Flows for the fiscal year ended December 31, 2005 and for the periods March 5, 2004 (date of inception) through December 31, 2004 and March 5, 2004 (date of inception) through December 31, 2005	F-6
Notes to Financial Statements	F-7 ~ F-10
Pro Forma financial information (Unaudited)	F-11 ~ 15

F-1

INDEPENDENT AUDITOR’S REPORT

To the MANAGING MEMBER

TATONKA OIL AND GAS COMPANY, LLC

We have audited the accompanying balance sheets of TATONKA OIL AND GAS COMPANY, LLC (an Exploration Stage Company) as of December 31, 2005 and 2004, and the related statements of income, members’ equity, and cash flows for the year ended December 31, 2005, and for the period from March 5, 2004 to December 31, 2004, and for the period from March 5, 2004 (inception) through December 31, 2005. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, based on our audits, the financial statements referred to above present fairly, in all material respects, the financial position of TATONKA OIL AND GAS COMPANY, LLC (an Exploration Stage Company) as of December 31, 2005 and 2004, and the results of its operations and its cash flows for the period from March 5, 2004 (inception) to December 31, 2004 and for the period from March 5, 2004 (inception) to December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has suffered recurring losses from operations and has a net capital deficiency. These items raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ De Leon & Company, P.A.

Pembroke Pines, Florida

June 30, 2006

F-2

TATONKA OIL AND GAS COMPANY, LLC

(An Exploration Stage Company)

BALANCE SHEETS

December 31, 2005 and 2004

(Stated in US Dollars)

ASSETS	2005			2004

Current
Cash	$	48,423		$	183,992
Escrow deposits		27,243			-
Total Current Assets		75,666			183,992

Deposits and other assets		272,757			-
Oil and gas properties - Notes 3 and 5		195,829			100,000

Total Assets	$	544,252		$	283,992

LIABILITIES AND MEMBERS’ EQUITY

LIABILITIES
Current
Accounts payable and accrued liabilities	$	9,522		$	6,000
Total Current Liabilities		9,522			6,000

Commitments - Note 3

MEMBERS’ EQUITY
Members’ equity -Note 5		602,000			302,000
Deficit accumulated during the exploration stage		(67,270	)		(24,008	)
Total Members’ Equity		534,730			277,992

Total Liabilities and Members' Equity	$	544,252		$	283,992

See Accompanying Notes

F-3

TATONKA OIL AND GAS COMPANY, LLC

(An Exploration Stage Company)

STATEMENTS OF OPERATIONS

For the year ended December 31, 2005 and for the period from March 5, 2004 to December 31, 2004

and for the period from March 5, 2004 (Date of Inception) to December 31, 2005

(Stated in US Dollars)

							March 5, 2004
				From			(Date of
				March 5, 2004			Inception) to
	December 31,			To December 31,			December 31,
		2005			2004			2005

Revenue	$	-		$	-		$	-

Expenses		43,262			24,008			67,270

Net loss for the period	$	(43,262	)	$	(24,008	)	$	(67,270	)

See Accompanying Notes

F-4

TATONKA OIL AND GAS COMPANY, LLC

(An Exploration Stage Company)

STATEMENTS OF MEMBERS’ EQUITY

For the Period from March 5, 2004 (Date of Inception) to December 31, 2005

(Stated in US Dollars)

			Deficit Accumulated
	Members’		During
	Equity		Exploration Stage			Total
3/1/04 Contribution by Member	$100,000					100,000

6/1/04 Contribution by Member	3,000					3,000

6/19/04 Contribution by Member	450,000					450,000

10/19-12/19/04 Distributions	(251,000)					(251,000)

Net loss for the period 3/5/04 to 12/31/04			(24,008		)	(24,008		)
Balance December 31, 2004		302,000		(24,008	)		277,992

11/21/05 Contribution by Member		300,000					300,000

Net loss for the year				(43,262	)		(43,262	)
Balance December 31, 2005	$	602,000	$	(67,270	)	$	534,730

See Accompanying Notes

F-5

TATONKA OIL AND GAS COMPANY, LLC

(An Exploration Stage Company)

STATEMENTS OF CASH FLOWS

For the year ended December 31, 2005 and for the period from March 5, 2004 (Date of Inception) to December 31, 2004 and for the period from March 5, 2004 (Date of Inception) to December 31, 2005

(Stated in US Dollars)


	December 31,	March 5, 2004 (Date of Inception) to December 31,	March 5, 2004 (Date of Inception) to December 31,
	2005	2004	2005

Operating Activities

Net loss for the period

(43,262

)

(24,008

)

(67,270

)

Change in non-cash working capital balance related to operations:
Increase in escrow deposits	(27,243		)	-			(27,243		)
Increase in other assets	(272,557		)				(272,557		)
Accounts payable and accrued liabilities	3,522						9,522
Cash used in operating activities	(339,740		)	(18,008		)	(357,748		)

Investing Activity
Acquisition of oil and gas properties		(95,829	)		(100,000	)		(195,829	)

Cash used in investing activity		(95,829	)		(100,000	)		(195,829	)

Financing Activity
Members’ equity contributions		300,000			302,000			602,000

Cash provided by financing activity		300,000			302,000			602,000

Increase (decrease) in cash during the period		(135,569	)		183,992			48,423

Cash, beginning of the period		183,992			-			-

Cash, end of the period	$	48,423		$	183,992		$	48,423

See Accompanying Notes

F-6

Note 1 Nature of Operations

The Company is in the exploration stage and is in the process of acquiring and exploring oil and gas properties located in the U.S.A. The recoverability of amounts shown for oil and gas properties are dependent upon the discovery of economically recoverable reserves, confirmation of the Company’s interest in the properties, the ability of the Company to obtain necessary financing to complete the development and upon future profitable production or proceeds from the disposition thereof.

The Company was incorporated in the State of Colorado on March 5, 2004, as a Limited Liability Company (“LLC”) and is a single member LLC.

At December 31, 2005, the Company has working capital of $66,144, but has incurred losses since inception totalling $67,270 and has yet to achieve profitable operations. The Company’s ability to continue as a going concern is dependent on raising additional capital to fund future operations and ultimately to attain profitable operations (See Note 5). Accordingly, these factors raise substantial doubt as to the Company’s ability to continue as a going concern. These financial statements do not give affect to adjustments that would be necessary to the carrying values and classification of assets and liabilities should the Company be unable to continue as a going concern. Management plans to continue to provide for its capital needs during the year ended December 31, 2006 by the development of its properties, by issuing equity securities or by pursuing alternative financing, however, there is no assurances that management’s plans will be attained..

Note 2 Summary of Significant Accounting Policies

The financial statements have, in management’s opinion been properly prepared within the framework of the significant accounting policies summarized below:

Cash and Cash Equivalents

For purposes of the statement of cash flows, the Company considers all investment purchased with a maturity of three months or less to be cash equivalents. At December 31, 2005 and 2004 the Company had uninsured demand deposits in banks in the amount of $0 and $83,992, respectively.

F-7

TATONKA OIL AND GAS COMPANY, LLC

(An Exploration Stage Company)

NOTES TO THE FINANCIAL STATEMENTS

December 31, 2005 and 2004

(Stated in US Dollars)

Note 2 Summary of Significant Accounting Policies - (cont’d)

Escrow Deposits and Other Assets

On November 21, 2005 the Company escrowed $300,000 for the purchase of leases with Elm Ridge Exploration Company (“EREC”). EREC acquired leases for the Company in 2006 expending $272,757 in acquisition costs. The balance of $27,243 is being held in the escrow account subject to refund to the Company. The $27,243 is being accounted for as a current asset “escrow deposit”, while the acquisition cost are classified as “deposits and other assets”, in the non-current section of the balance sheet.

Exploration Stage Company

The Company complies with Financial Accounting Standards Board Statement No. 7 and Securities and Exchange Commission Act Guide 7 for its characterization of the Company as exploration stage.

Oil and Gas Properties

Costs capitalized, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves. Petroleum products and reserves are converted to a common unit of measure, using 6 MCF of natural gas to one barrel of oil.

Future net cash flows from proved reserves using period-end, non-escalated prices and costs, are discounted to present value and compared to the carrying value of oil and gas properties.

F-8

TATONKA OIL AND GAS COMPANY, LLC

(An Exploration Stage Company)

NOTES TO THE FINANCIAL STATEMENTS

December 31, 2005 and 2004

(Stated in US Dollars)

Note 2 Summary of Significant Accounting Policies - (cont’d)

Asset Retirement Obligations

Income Taxes

The Company is not a taxpaying entity for federal income tax purposes, and thus no income tax expense has been recorded in the statements.

Financial Instruments

Note 3 Oil and Gas Properties

The Company has acquired leases in unproved oil and gas properties located in Colorado and Wyoming, USA. Under the terms of the lease agreements the Company is required to pay its share of royalties and other obligations.

The Company expended $100,000 in 2004 and $95,829 in 2005 for a total of $195,829 at December 31, 2005 to acquire leases of unproved properties. There has been no funds expensed in 2004 or 2005 for exploratory activities.

The Company has contracted to acquire lease properties in Wyoming and Colorado. Pursuant to such contracts the Company is obligated to provide $1,751,784 to acquire such leases. This amount does not contemplate funds needed for exploration.

F-9

TATONKA OIL AND GAS COMPANY, LLC

(An Exploration Stage Company)

NOTES TO THE FINANCIAL STATEMENTS

December 31, 2005 and 2004

(Stated in US Dollars)

Note 4 Income Taxes

The Company is not a taxpaying entity for federal income tax purposes, and thus no income tax expense has been recorded in the statements. Income of the Company is taxed to the members in their respective returns.

Note 5

Subsequent Events

Subsequent to December 31, 2005, the Company:

Received cash totaling $1,580,000 from the member of the Company.

Acquired additional leases in unproved oil and gas properties located in Colorado, USA, for a cost of $850,000.

Committed to acquire leases in unproved oil and gas properties located in Wyoming, USA for a cost of $901,784.

F-10

TATONKA OIL AND GAS COMPANY, LLC

(An Exploration Stage Company)

NOTES TO THE FINANCIAL STATEMENTS

December 31, 2005 and 2004

(Stated in US Dollars)

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION

New Pacific Ventures, Inc. acquired all of the capital stock of Tatonka Oil and Gas Company, Inc. (formerly Tatonka Oil and Gas Company, LLC.) The acquisition was consummated as of October 16, 2006, pursuant to a Stock Purchase Agreement.

The aggregate consideration for the acquisition was the issuance of 15,000,000 common shares of New Pacific Ventures, Inc.

The unaudited pro forma statements of operations of New Pacific Ventures, Inc. for the year ended October 31, 2005 and the nine months ended July 31, 2006, give effect to (i) the Stock Purchase Agreement by applying the purchase method of accounting, (ii) certain adjustments that are directly attributable to the Stock Purchase Agreement, and (iii) the sale of 10,000,000 Common Shares of New Pacific Ventures, Inc. at $0.50 per share as if the transaction was consummated as of October 31, 2004.

The unaudited pro forma consolidated balance sheet as of July 31, 2006, is presented as if the Stock Purchase Agreement and sale of all of the Common Shares had occurred on July 31, 2006.

The fair value of the net assets acquired has been estimated pending completion of a valuation by an independent appraiser.

These unaudited pro forma condensed financial statements are presented for illustrative purposes only and are not necessarily indicative of the operating results or the financial position that would have been achieved had the Stock Purchase Agreement been consummated as of the dates indicated or of the results that may be obtained in the future.

F-11

NEW PACIFIC VENTURES, INC.

(An Exploration Stage Company)

PRO FORMA CONSOLIDATED BALANCE SHEET

July 31, 2006

(Unaudited)

		Historical
					Tatonka
		New Pacific			Oil & Gas			Pro Forma
		Ventures, Inc.			Company, Inc.			Adjustments			Pro Forma
ASSETS
Current assets
Cash	$	1,250,274		$	85,243		$	3,750,000(2	)	$	3,750,517
								(400,000)(2	)
								(935,000)(4	)

Oil and gas properties		-			1,898,317			7,992,862(3	)		9,891,179

Total assets	$	1,250,274		$	1,983,560					$	13,641,696

LIABILITIES

Current liabilities
Accounts payable	$	67,075		$	9,522					$	76,597

								1,250,000(2	)
Advances payable		1,250,000			2,466,900			935,000(4	)		1,531,900

Total liabilities		1,317,075			2,476,422						1,608,497

STOCKHOLDERS’ EQUITY (DEFICIENCY)

Common stock		9,000			100			(27,000)(1	)
								(10,000)(2	)
								100(3	)
								(15,000)(3	)
								6,000(5	)		55,000

Additional paid-in capital		-			-			27,000(1	)
								400,000(2	)
								(4,990,000)(2	)
								(7,485,000)(3	)
								(6,000)(5	)		12,054,000

Deficit accumulated during the exploration stage		(75,801	)		(492,962	)		(492,962)(3	)		(75,801	)

Total stockholders’ equity (deficiency)		(66,801	)		(492,862	)					12,033,199

Total liabilities and stockholders’ equity	$	1,250,274		$	1,983,560					$	13,641,696

See Notes To The Unaudited Pro Forma Consolidated Financial Statements

F-12

NEW PACIFIC VENTURES, INC.

(An Exploration Stage Company)

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

October 31, 2005

(Unaudited)

		Historical
					Tatonka
		New Pacific			Oil & Gas	Pro Forma
		Ventures, Inc.			Company, Inc.	Adjustments		Pro Forma


Revenue	$	74		$	-		$	74

Expenses		23,696			43,262			66,950

Net loss	$	(23,622	)	$	(43,262	)	$	(66,876	)

Basic and diluted loss per common share	$	(0.00	)				$	(0.00	)

Basic and diluted weighted average number of common shares outstanding		9,000,000						55,000,000

See Notes To The Unaudited Pro Forma Consolidated Financial Statements

F-13

NEW PACIFIC VENTURES, INC.

(An Exploration Stage Company)

PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

Nine months ended July 31, 2006

(Unaudited)

	Historical
				Tatonka
	New Pacific			Oil & Gas			Pro Forma
	Ventures, Inc.			Company, Inc.			Adjustments	Pro Forma

Revenue	$	23		$	-			$	23

Expenses		7,556			425,692				433,225

Net loss	$	(7,529	)	$	(425,692	)		$	(433,202	)

Basic and diluted loss per common share	$	(0.00	)					$	(0.00	)

Basic and diluted weighted average number of common shares outstanding		9,000,000							55,000,000

See Notes To The Unaudited Pro Forma Consolidated Financial Statements

F-14

NEW PACIFIC VENTURES, INC.

NOTES TO THE UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

October 31, 2005 and July 31, 2006

Note 1

The Company completed a forward split of its common stock on a four new shares for one old share basis.

Note 2

The Company completed an offering of 10,000,000 post split common shares at $0.50 per share for total proceeds of $5,000,000. Share issuance costs of $400,000 were incurred in respect to the offering.

Note 3

The aggregate consideration for the acquisition of 100% of Tatonka Oil and Gas Company, Inc. (“Tatonka”) was 15,000,000 post split of the Company’s common stock for $0.50 per share.

The pro forma financial statements have been prepared on the basis of assumptions relating to the allocation of the consideration paid to the acquired assets and liabilities of Tatonka, based on management’s best estimates.

The purchase price was allocated as follows:

Current assets	$	85,243
Oil and gas properties		9,606,179
Current liabilities		(2,191,422	)

Total purchase price	$	7,500,000

Note 4

Advances payable of $935,000 were repaid on the closing of the acquisition of Tatonka, which represent oil and gas leases and expenditures incurred by the director of Tatonka subsequent to the date of the offering memorandum.

Note 5

Directors of the Company cancelled 6,000,000 post split common shares on the closing of the acquisition of Tatonka.

Note 6 Pro-forma common stock outstanding is made up as follows:

	Number of
	Shares

New Pacific Ventures, Inc. - October 31, 2005		9,000,000
Forward split - 4 new shares for 1 old share		27,000,000
Cancellation of common stock by directors		(6,000,000	)

		30,000,000
Offering memorandum - at $0.50		10,000,000
Issuance of common stock on acquisition of Tatonka		15,000,000

Total		55,000,000

Tatonka Oil & Gas (TTKA) Inactive 8-KEntry into a Material Definitive Agreement