Item 1. Business
General
Southwest Royalties Institutional Income Fund VII-B, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on January 28, 1987. The offering of limited partnership interests in the Partnership began March 23, 1987, reached minimum capital requirements May 20, 1987, and concluded December 1, 1987. The Partnership has no subsidiaries. The Managing General Partner of the Partnership is Southwest Royalties, Inc. (the “Managing General Partner”), a Delaware corporation.
The Partnership has expended its capital and acquired interests in producing oil and gas properties. Since such acquisitions, the Partnership has produced and marketed the crude oil and natural gas produced from such properties. In most cases, the Partnership purchased royalty or overriding royalty interests and working interests in oil and gas properties that were converted into net profits interests or other non-operating interests. The Partnership purchased either all or part of the rights and obligations under various oil and gas leases.
During 2004, the Managing General Partner was acquired by Clayton Williams Energy, Inc. (“CWEI”), a Delaware corporation, and is now a wholly owned subsidiary of CWEI. CWEI is an oil and gas company based in Midland, Texas, and its common stock is traded on the Nasdaq Stock Market’s Global Market under the symbol “CWEI”. All of the directors and executive officers of the Managing General Partner are employees of CWEI. CWEI maintains an internet website at www.claytonwilliams.com from which public information about CWEI may be obtained.
The principal executive offices of the Partnership are located at 6 Desta Drive, Suite 6500, Midland, Texas, 79705. The Managing General Partner and its staff, together with certain independent consultants used on an "as needed" basis, perform various services on behalf of the Partnership, including the selection of oil and gas properties and the marketing of production from such properties. The Partnership has no employees.
Operations
The business objective of the Partnership is to maximize the production and related net cash flow from the properties it currently owns without engaging in the drilling of any development or exploratory wells except through farm-out arrangements. If additional drilling is necessary to fully develop a Partnership property, the Partnership will enter into a farm-out agreement with the Managing General Partner to assign a portion of the Partnership’s interest in the property to the Managing General Partner in exchange for retaining an interest in one or more new wells at no cost to the Partnership. The Managing General Partner obtains a fairness opinion from an unaffiliated petroleum engineer with respect to the terms of each farm-out agreement with the Partnership.
Principal Products and Markets
The Partnership has acquired and holds royalty, overriding royalty and net profit interests in oil and gas properties located in Texas, New Mexico, Oklahoma, Louisiana, Illinois and Arkansas. All activities of the Partnership are confined to the continental United States. During 2010, 86% of the Partnership’s revenues were derived from the sale of oil production and 14% were derived from gas production. All oil and gas produced from these properties is sold to unrelated third parties in the oil and gas business. The Partnership believes that the loss of any of its purchasers would not have a material adverse affect on its results of operations due to the availability of other purchasers.
The revenues generated from the Partnership's oil and gas activities are dependent upon the current market for oil and gas. The prices received by the Partnership for its oil and gas production depend upon numerous factors beyond the Partnership's control, including competition, economic, political and regulatory developments and competitive energy sources. The Partnership is unable to accurately predict future prices of oil and natural gas.
Competition
Because the Partnership has utilized all of its funds available for the acquisition of net profits or royalty interests in producing oil and gas properties, it is not subject to competition from other oil and gas property purchasers. See Item 2, Properties.
Factors that may adversely affect the Partnership include delays in completing arrangements for the sale of production, availability of a market for production, rising operating costs of producing oil and gas and complying with applicable water and air pollution control statutes, increasing costs and difficulties of transportation, and marketing of competitive fuels. Moreover, domestic oil and gas must compete with imported oil and gas and with coal, atomic energy, hydroelectric power and other forms of energy.
Regulation
Generally. The Partnership’s oil and gas production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. Because such rules and regulations are frequently amended or reinterpreted, the Partnership is unable to predict the future cost or impact of complying with such laws. Although the regulatory burden on the oil and gas industry increases the Partnership cost of doing business and, consequently, affects the Partnership’s profitability, these burdens generally do not affect the Partnership any differently or to any greater or lesser extent than they affect others in the Partnership’s industry with similar types, quantities and locations of production.
Regulations affecting production. All of the states in which the Partnership conducts business generally require permits for drilling operations, require drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the spacing, plugging and abandonment of such wells, restrictions on venting or flaring natural gas and requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil and natural gas the Partnership can produce from its wells and may limit the number of wells or the locations at which the Partnership can drill. Moreover, many states impose a production or severance tax with respect to the production and sale of oil and natural gas within their jurisdiction. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation of production, but there can be no assurance they will not do so in the future.
In the event the Partnership conducts operations on federal, state or Indian oil and natural gas leases, its operations may be required to comply with additional regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”) or other relevant federal or state agencies.
Regulations affecting sales. The sales prices of oil, natural gas liquids and natural gas are not presently regulated, but rather are set by the market. The Partnership cannot predict, however, whether new legislation to regulate the price of energy commodities might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.
The Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas the Partnership produces, as well as the revenues the Partnership receives for sales of such production. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. The Partnership does not believe that it will be affected by any such FERC action in a manner materially differently than other natural gas producers in the partnerships areas of operation.
The price the Partnership receives from the sale of oil and natural gas liquids is affected by the cost of transporting those products to market. Interstate transportation rates for oil, natural gas liquids and other products are regulated by the FERC. The FERC has established an indexing system for such transportation, which allows such pipelines to take an annual inflation-based rate increase. The Partnership is not able to predict with any certainty what effect, if any, these regulations will have on the Partnership, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.
Environmental Matters
The Partnership operations pertaining to oil and gas exploration, production and related activities are subject to numerous and constantly changing federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of certain permits prior to or in connection with the Partnership’s operations, restrict or prohibit the types, quantities and concentration of substances that the Partnership can release into the environment, restrict or prohibit activities that could impact wetlands, endangered or threatened species or other protected areas or natural resources, require some degree of remedial action to mitigate pollution from former operations, such as pit cleanups and plugging abandoned wells, and impose substantial liabilities for pollution resulting from its operations. Such laws and regulations may substantially increase the cost of the Partnership’s operations and may prevent or delay the commencement or continuation of a given project and thus generally could have a material adverse effect upon the Partnership’s capital expenditures, earnings, or competitive position. Violation of these laws and regulations could result in significant fines or penalties. The Partnership has experienced accidental spills, leaks and other discharges of contaminants at some of its properties, as have other similarly situated oil and gas companies, and some of the properties that the Partnership has acquired, operated or sold, or in which the Partnership may hold an interest but not operational control, may have past or ongoing contamination for which the Partnership may be held responsible. The Partnership’s environmental insurance coverage may not fully insure all of these risks. Although the costs of remedying such conditions may be significant, the Partnership does not believe these costs would have a material adverse impact on the Partnership’s financial condition and operations.
The Partnership believes that it is in substantial compliance with current applicable environmental laws and regulations, and the cost of compliance with such laws and regulations has not been material and is not expected to be material during 2011. The Partnership does not believe that it will be required to incur any material capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in the interpretations thereof could have a significant impact on the Partnership’s operations, as well as the oil and gas industry in general. For instance, any changes in environmental laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal or clean-up requirements could have a material adverse impact on the Partnership’s operations.
Hazardous Substances. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons 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 neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Partnership is able to control directly the operation of only those wells with respect to which the Partnership acts as operator. Notwithstanding its lack of direct control over wells operated by others, the failure of an operator of a property owned by the Partnership to comply with applicable environmental regulations may, in certain circumstances, be attributed to the Partnership. The Partnership is not aware of any liabilities for which it may be held responsible that would materially and adversely affect the Partnership.
Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid wastes. RCRA specifically excludes drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the U.S. Environmental Protection Agency (“EPA”) or state agencies as solid wastes. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, the Partnership does not believe that its costs in this regard are materially more burdensome than those for similarly situated companies.
Air Emissions. The Federal Clean Air Act and comparable state laws and regulations impose restrictions on emissions of air pollutants from various industrial sources, including compressor stations and natural gas processing facilities, and also impose various monitoring and reporting requirements. Such laws and regulations may require that the Partnership obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limits, or utilize specific emission control technologies to limit emissions. The Partnership’s failure to comply with these requirements could subject the Partnership to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Capital expenditures for air pollution equipment may be required in connection with maintaining or obtaining operating permits and approvals relating to air emissions at facilities owned or operated by the Partnership. The Partnership does not believe that its operations will be materially adversely affected by any such requirements.
Water Discharges. The Federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In addition, the United States Oil Pollution Act of 1990 (“OPA”) and similar legislation enacted in Texas, Louisiana and other coastal states impose oil spill prevention and control requirements and significantly expand liability for damages resulting from oil spills. OPA imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil spill response and removal costs and a variety of public and private damages.
Global Warming and Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require the Partnership to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas the Partnership produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on the partnership’s business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the partnership’s financial condition and results of operations.
OSHA and Other Laws and Regulation. The Partnership is subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that the Partnership organize and/or disclose information about hazardous materials used or produced in its operations. The Partnership believes that it is in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
Claims are sometimes made or threatened against companies engaged in oil and gas exploration, production and related activities by owners of surface estates, adjoining properties or others alleging damages resulting from environmental contamination and other incidents of operations. Limited partners should be aware that the assessment of liability associated with environmental liabilities is not always correlated to the value of a particular project. Accordingly, liability associated with the environment under local, state, or federal regulations, particularly clean-ups under CERCLA, can exceed the value of the Partnership’s investment in the associated site.
Partnership Employees
The Partnership has no employees; however the Managing General Partner and CWEI have a staff of geologists, engineers, accountants, landmen and clerical staff who engage in Partnership activities and operations and perform additional services for the Partnership as needed. In addition, the Partnership engages independent consultants such as petroleum engineers and geologists as needed.
Item 1A.
Item 1A. Risk Factors
There are many factors that affect the Partnership’s business, some of which are beyond the Partnership’s control. The Partnership’s business, financial condition and results of operations could be materially adversely affected by any of these risks. The risks described below are not the only ones facing the Partnership. Additional risks not presently known to the Partnership or that the Partnership currently deems immaterial individually or in the aggregate may also impair the Partnership’s business operations.
The Partnership may not be able to replace production with new reserves.
In general, the volume of production from an oil and gas property declines as reserves related to that property are depleted. The decline rates depend upon reservoir characteristics. Historically, the Partnership’s oil and gas properties have had steep rates of decline and short estimated productive lives. The implied life of the Partnership’s proved reserves at December 31, 2010 is approximately 10.1 years, based on 2010 production levels. The Partnership is not allowed to engage in exploratory or development drilling of oil and gas wells.
Volatility of oil and gas prices significantly affects the Partnership’s cash flow and ability to produce oil and gas economically.
Historically, the markets for oil and gas have been volatile, and the Partnership believes that they are likely to continue to be volatile. Significant changes in oil and gas prices may result from relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and other factors that are beyond the Partnership’s control. The Partnership cannot predict, with any degree of certainty, future oil and natural gas prices. Changes in oil and natural gas prices significantly affect the Partnership’s revenues, operating results, profitability and the value of the Partnership’s oil and gas reserves. Those prices also affect the amount of cash flow available for distribution to partners and the amount of oil and natural gas that the Partnership can produce economically.
Changes in oil and gas prices impact both the Partnership’s estimated future net revenue and the estimated quantity of proved reserves. Price increases may permit additional quantities of reserves to be produced economically, and price decreases may render uneconomic the production of reserves previously classified as proved. Thus, the Partnership may experience material increases and decreases in reserve quantities solely as a result of price changes and not as a result of well performance.
The Partnership’s proved reserves are estimates and depend on many assumptions. Any material inaccuracies in these assumptions could cause the quantity and value of the partnership’s oil and gas reserves, and the Partnership’s revenue, profitability, and cash flow, to be materially different from the Partnership’s estimates.
The estimated proved reserve information is based upon reserve reports prepared by independent engineers. The accuracy of proved reserves estimates and estimated future net revenues from such reserves is a function of the quality of available geological, geophysical, engineering and economic data and is subject to various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, and other matters. Although the Partnership believes that the Partnership’s estimated proved reserves represent reserves that the Partnership is reasonably certain to recover, actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates used to determine proved reserves. Any significant variance could materially affect the estimated quantities and value of the Partnership’s oil and gas reserves, which in turn could adversely affect the Partnership’s cash flow and results of operations. In addition, the Partnership may adjust estimates of proved reserves to reflect production history, results of development, prevailing oil and gas prices and other factors, many of which are beyond the Partnership’s control. Downward adjustments to the Partnership’s estimated proved reserves could require the Partnership to write down the carrying value of the Partnership’s oil and gas properties, which would reduce the Partnership’s earnings and partners' equity.
The present value of proved reserves will not necessarily equal the current fair market value of the Partnership’s estimated oil and gas reserves. In accordance with the reserve reporting requirements of the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value.
The Partnership may not be insured against all of the operating hazards to which the Partnership’s business is exposed.
The Partnership’s operations are subject to the usual hazards incident to the production of oil and gas, such as windstorms, lightning strikes, blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, severe weather and pollution and other environmental risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations which could result in substantial loss. The Partnership maintains insurance against some, but not all, of the risks described above. Such insurance may not be adequate to cover losses or liabilities. Also, the Partnership cannot be assured of the continued availability of insurance at premium levels that justify its purchase.
The Partnership’s business depends on oil and natural gas transportation facilities, most of which are owned by others.
The marketability of the Partnership’s oil and natural gas production depends in large part on the availability, proximity and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells. Although the Partnership has some contractual control over the transportation of the Partnership’s product, material changes in these business relationships could materially affect the Partnership’s operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, maintenance and repair and general economic conditions could adversely affect the Partnership’s ability to produce, gather and transport oil and natural gas.
A terrorist attack or armed conflict could harm the Partnership’s business by decreasing the Partnership’s revenues and increasing the Partnership’s costs.
Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States may adversely affect the United States and global economies and could prevent the Partnership from meeting the Partnership’s financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for the Partnership’s services and causing a reduction in the Partnership’s revenue. Oil and natural gas related facilities could be direct targets of terrorist attacks, and the Partnership’s operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and natural gas production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
The Partnership’s industry is highly competitive.
The oil and gas industry as a whole competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect the Partnership’s revenue.
The market for the Partnership’s oil, gas and natural gas liquids production depends on factors beyond the Partnership’s control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.
Compliance with environmental and other government regulations could be costly and could negatively impact production.
The Partnership’s oil and gas production and related operations are subject to extensive rules and regulations promulgated by federal, state and local agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Partnership’s cost of doing business and affects the Partnership’s profitability. Because such rules and regulations are frequently amended or reinterpreted, the Partnership is unable to predict the future cost or impact of complying with such laws.
All of the states in which the Partnership operates generally require reports concerning operations and impose other requirements relating to the production of oil and gas. Such states also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. The statutes and regulations of certain states also limit the rate at which oil and gas can be produced from the Partnership’s properties.
FERC regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas the Partnership produces, as well as the revenues the Partnership receives for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance the Partnership’s ability to market and transport the Partnership’s gas, although it may also subject the Partnership to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances.
The Partnership’s sales of oil and natural gas liquids are not presently regulated and are made at market prices. The price the Partnership receives from the sale of those products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. The Partnership is not able to predict with any certainty what effect, if any, these regulations will have on the Partnership, but, other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids.
Under the EP Act 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While the Partnership’s natural gas operations have not been regulated by FERC under the NGA, FERC has adopted regulations that may subject certain of the Partnership otherwise non-FERC jurisdictional entities to FERC annual reporting and daily scheduled flow and capacity posting requirements, as described more fully in Item 1 above. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject the Partnership to civil penalty liability.
The Partnership’s oil and gas production and related activities are subject to extensive environmental regulations, and to laws that can give rise to substantial liabilities from environmental contamination.
The Partnership’s operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which the Partnership has an ownership interest but no operational control, properties the Partnership formerly owned or operated and sites where the Partnership’s wastes have been treated or disposed of, as well as at properties that the Partnership currently own or operate. Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that the Partnership could be held responsible for more than the Partnership’s share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.
The Partnership has incurred expenses in connection with environmental compliance, and the Partnership anticipates that the Partnership will continue to do so in the future. Failure to comply with extensive applicable environmental laws and regulations could result in significant civil or criminal penalties and remediation costs. Some of the Partnership’s properties, including properties in which the Partnership has an ownership interest but no operating control, may be affected by environmental contamination that may require investigation or remediation. In addition, claims are sometimes made or threatened against companies engaged in oil and gas production by owners of surface estates, adjoining properties or others alleging damage resulting from environmental contamination and other incidents of operation, and such claims have been asserted against the Partnership. Compliance with, and liabilities for remediation under, these laws and regulations, and liabilities concerning contamination or hazardous materials, may adversely affect the Partnership’s business, financial condition and results of operations.
Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil and natural gas that the Partnership produces.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA recently adopted two sets of rules regulating greenhouse gas emissions under the Clean Air Act, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulates emissions of greenhouse gases from certain large stationary sources, effective January 2, 2011. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing, or requiring state environmental agencies to implement, the rules. The EPA has also adopted rules requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010, as well as certain onshore oil and natural gas production facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
In addition, the United States Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases could require the Partnership to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas the Partnership produced. Consequently, legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse effect on the Partnership’s business, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Partnership’s financial condition and results of operations.
Item 1B.
Item 1B. Unresolved Staff Comments
Not applicable.
Item 2.
Item 2. Properties
As of December 31, 2010, the Partnership possessed an interest in oil and gas properties located in Logan County, Arkansas; Crawford and White Counties of Illinois, Cameron Parish of Louisiana; Eddy and Lea Counties of New Mexico; Alfalfa, Bryan, Caddo, Garvin, Hughes, Leflore, Logan, McClain, Marshall, Seminole and Stephens Counties of Oklahoma; Andrews, Crane, Dawson, Ector, Fisher, Gaines, Goliad, Gray, Gregg, Hale, Howard, Hutchinson, Leon, Loving, Midland, Mitchell, Moore, Pecos, Rusk, Scurry, Stonewall, Upton, Ward, Wichita and Winkler Counties of Texas. These properties consist of various interests in approximately 2,437 wells and units.
Reserves
Rule Changes Applicable to Reserve Estimates and Disclosures.
In 2009, the SEC issued its final rule on the modernization of oil and gas reporting, and the Financial Accounting Standards Board (“FASB”) adopted conforming changes to Accounting Standards Codification (“ASC”) Topic 932, “Extractive Industries”, to align the FASB’s reserves requirements with those of the SEC. The final rule is now in effect for companies with fiscal years ending on or after December 31, 2009. As it affects the Partnership’s reserve estimates and disclosures, the final rule:
·
amends the definition of proved reserves to require the use of average commodity prices based upon the prior 12 month period rather than year-end prices;
·
expands the type of technologies available to establish reserve estimates and categories;
·
modifies certain definitions used in estimating proved reserves;
·
permits disclosure of probable and possible reserves; and
·
permits disclosure of reserves based on different price and cost criteria, such as futures prices or management forecasts.
See “Glossary of Terms” for current definitions of terms related to oil and gas reserves.
The following table sets forth certain information as of December 31, 2010 with respect to the Partnership’s estimated proved oil and gas reserves pursuant to SEC guidelines and standardized measure of discounted future net cash flows.
The following table sets forth certain information as of December 31, 2010 regarding the Partnership’s proved oil and gas reserves for certain significant fields.
The estimates of proved reserves at December 31, 2010 and the standardized measure of discounted future net cash flows were derived from a report prepared by Ryder Scott Company, L.P., petroleum consultants. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.
The commodity prices used to estimate proved reserves and their related PV-10 Value at December 31, 2010 were based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period from January 2010 through December 2010. These benchmark average prices were further adjusted for quality, energy content, transportation fees and other price differentials specific to our properties, resulting in an average adjusted price of $74.35 per barrel of oil and $6.68 per Mcf of natural gas over the remaining life of our proved reserves. Operating costs were not escalated.
Other Information Concerning our Proved Reserves
The accuracy of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and PV-10 Value are based on various assumptions and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.
Since January 1, 2010, we have not filed an estimate of our net proved oil and gas reserves with any federal authority or agency other than the SEC.
Item 3.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Partnership is a party.
Item 4.
Item 4. (Removed and Reserved)
Part II
Item 5.
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Limited partnership interests, or units, in the Partnership were initially offered and sold for a price of $500. Limited partner units are not traded on any exchange and there is no public or organized trading market for them.
Number of Limited Partner Interest Holders
As of December 31, 2010, there were 532 holders of limited partner units in the Partnership.
Distributions
Pursuant to Article IV, Section 4.01 of the Partnership's Certificate and Agreement of Limited Partnership "Net Cash Flow" is distributed to the partners on a quarterly basis. "Net Cash Flow" is defined as "the cash generated by the Partnership's investments in producing oil and gas properties, less (i) General and Administrative Costs, (ii) Operating Costs, and (iii) any reserves necessary to meet current and anticipated needs of the Partnership, as determined in the sole discretion of the Managing General Partner." During 2010, distributions were made totaling $827,017, with $744,196 ($49.61 per unit) distributed to the limited partners and $82,821 to the general partner.
Issuer Purchases of Equity Securities
After completion of the Partnership's first full fiscal year of operations and each year thereafter, the Managing General Partner has offered to purchase each limited partner's interest in the Partnership in accordance with the obligations set forth in the partnership agreement. The pricing mechanism used to calculate the repurchase is based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the Managing General Partner. However, the Managing General Partner's obligation to purchase limited partner units under the partnership agreement is limited to an annual expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners. The following table sets forth certain information regarding purchases of limited partnership units by the Managing General Partner during the year ended December 31, 2010.
Item 6.
Item 6. Selected Financial Data
The following selected financial data for the years ended December 31, 2010, 2009, 2008, 2007 and 2006 should be read in conjunction with the financial statements included in Item 8:
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
General
The Partnership was formed to acquire royalty and net profits interests in producing oil and gas properties, to produce and market crude oil and natural gas produced from such properties and to distribute the net proceeds from operations to the limited and general partners. Net revenues from producing oil and gas properties are not reinvested in other revenue producing assets except to the extent that production facilities and wells are improved or reworked or where methods are employed to improve or enable more efficient recovery of oil and gas reserves. The economic life of the Partnership thus depends on the period over which the Partnership’s oil and gas reserves are economically recoverable.
Increases or decreases in Partnership revenues and, therefore, distributions to partners will depend primarily on changes in the prices received for production, changes in volumes of production sold, increases and decreases in production costs, enhanced recovery projects, offset drilling activities pursuant to farm-out arrangements, sales of properties, and the depletion of wells. Since wells deplete over time, production can generally be expected to decline from year to year.
Production costs and general and administrative costs usually decrease with production declines; however, these costs may not decrease proportionately to production volumes or revenues. Net income available for distribution to the partners is therefore expected to decline in later years based on these factors.
Critical Accounting Policies
The Partnership follows the full cost method of accounting for its oil and gas properties. The full cost method subjects companies to quarterly calculations of a “ceiling”, or limitation on the amount of properties that can be capitalized on the balance sheet. If the Partnership’s capitalized costs are in excess of the calculated ceiling, the excess must be written off as an expense.
The Partnership’s discounted present value of its proved oil and natural gas reserves is a major component of the ceiling calculation, and represents the component that requires the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. The Partnership’s reserve estimates are prepared by outside consultants.
The passage of time provides more qualitative information regarding estimates of reserves, and revisions are made to prior estimates to reflect updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. If future significant revisions are necessary that reduce previously estimated reserve quantities, it could result in a full cost property writedown. In addition to the impact of these estimates of proved reserves on calculation of the ceiling, estimates of proved reserves are also a significant component of the calculation of depletion, depreciation, and amortization (“DD&A”).
While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of the reserves do not require judgment. Current SEC financial accounting and reporting standards require that pricing parameters be the arithmetic average of the first-day-of-the-month price for the 12-month period preceding the effective date of the reserve report. The ceiling calculation dictates that those prices be held constant. Because the ceiling calculation dictates that prices and costs are held constant indefinitely, the resulting value is not indicative of the true fair value of the reserves. Oil and natural gas prices have historically been cyclical and can be either substantially higher or lower than the Partnership’s long-term price forecast that is a barometer for true fair value.
Supplemental Information
The following unaudited information is intended to supplement the financial statements included in this Form 10-K with data that is not readily available from those statements.
Operating Results
The following discussion compares our results for the year ended December 31, 2010 to the two previous years. All references to 2010, 2009 and 2008 within this section refer to the respective annual periods.
Revenues
Oil and gas prices increased compared to the previous year. Comparing 2010 to 2009, oil and gas sales increased $292,953, of which price variances accounted for a $330,281 increase and production variances accounted for a $37,328 decrease. Comparing 2009 to 2008, oil and gas sales decreased $1,213,446, of which price variances accounted for a $802,398 decrease and production variances accounted for a $411,048 decrease.
Production in 2010 (on a BOE basis) was 5% lower than 2009 and 21% lower than 2008. Our oil production was less than 1% higher in 2010 than 2009. Our gas production was 19% lower in 2010 than 2009 due primarily to production decline on one property.
In 2010, our realized oil price was 32% higher than 2009 and 23% lower than 2008, while our realized gas price was 22% higher than 2009 and 31% lower than 2008. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.
Oil and gas production costs on a BOE basis increased from $14.65 per BOE in 2009 and $15.63 per BOE in 2008 to $18.07 per BOE in 2010. The increase in oil and gas production costs per BOE in 2010 was primarily due to surface repairs on a property.
Expenses
Depletion on a BOE basis increased 4% from 2009 and increased 11% from 2008. Comparing 2010 to 2009, depletion expense decreased $622, of which rate variances accounted for a $1,370 increase and production variances accounted for a $1,992 decrease. Comparing 2009 to 2008, depletion expense decreased $4,619, of which rate variances accounted for a $2,524 increase and production variances accounted for a $7,143 decrease.
Accretion expense remained unchanged compared to 2010 and 2009.
General and administrative (“G&A”) expenses were 1% lower in 2010 than 2009 and 1% lower than 2008.
Texas Margin Taxes
In May 2006, the State of Texas adopted House Bill 3, which modified the state’s franchise tax structure, replacing the previous tax based on capital or earned surplus with a margin tax (the “Texas Margin Tax”) effective with franchise tax reports filed on or after January 1, 2008. The Texas margin Tax is computed by applying the applicable tax rate (1% for the Partnership’s business) to the profit margin, which is generally determined by total revenue less either cost of goods sold or compensation as applicable. However the Partnership believes, based on its interpretation, that the Texas Margin Tax does not apply to the Partnership since substantially all of its income is derived from a net profits interest.
Liquidity and Capital Resources
Partnership distributions during the year ended December 31, 2010 were $827,017, of which $744,196 was distributed to the limited partners and $82,821 to the general partner. Cumulative cash distributions of $19,681,011 have been made to the general and limited partners as of December 31, 2010. As of December 31, 2010, $17,727,406 or $1,181.83 per limited partner unit has been distributed to the limited partners, representing 236% of contributed capital.
Our primary source of cash from operating activities is our oil and gas sales, net of production costs. Cash flow provided by operating activities for 2010 was 46% higher than for 2009 due to the combined effects of several drivers. The effect of a 26% increase in oil and gas sales, driven primarily by higher oil and gas prices, was partially offset by an increase in production costs. Our only use in financing activities is the distribution to partners which was 44% higher than 2009.
As of December 31, 2010, the Partnership had approximately $318,000 in working capital. The Managing General Partner knows of no unusual contractual commitments. Although the Partnership held many long-lived properties at inception, because of the restrictions on property development imposed by the partnership agreement, the Partnership cannot develop its non-producing properties, if any. Without continued development, the producing reserves continue to deplete. Accordingly, as the Partnership’s properties have matured and depleted, the net cash flows from operations for the Partnership have steadily declined, except in periods of substantially increased commodity pricing. Maintenance of properties and administrative expenses for the Partnership are increasing relative to production. As the properties continue to deplete, maintenance of properties and administrative costs as a percentage of production are expected to continue to increase.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
The Partnership financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, trading activities in commodities future markets, weather conditions, the price and availability of alternative fuels, and overall economic conditions, both foreign and domestic. The Partnership cannot predict future oil and gas prices with any degree of certainty. Sustained weakness in oil and gas prices may adversely affect our financial condition, results of operations and cash distributions to partners.
The Partnership is not a party to any derivative or embedded derivative instruments.
Item 8.
Item 8. Financial Statements and Supplementary Data
Page
Report of Independent Registered Public Accounting Firm
Balance Sheets
Statements of Operations
Statements of Changes in Partners' Equity (Deficit)
Statements of Cash Flows
Notes to Financial Statements
Report of Independent Registered Public Accounting Firm
The Partners
Southwest Royalties Institutional Income Fund VII-B, L.P.
(A Delaware Limited Partnership)
We have audited the accompanying balance sheets of Southwest Royalties Institutional Income Fund VII-B, L.P. (the Partnership) as of December 31, 2010 and 2009, and the related statements of operations, changes in partner’s equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2010. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the 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 Partnership 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 Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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, the financial statements referred to above present fairly, in all material respects, the financial position of Southwest Royalties Institutional Income Fund VII-B, L.P. as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010 in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Dallas, Texas
March 29, 2011
Southwest Royalties Institutional Income Fund VII-B, L.P.
Balance Sheets
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund VII-B, L.P.
Statements of Operations
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund VII-B, L.P.
Statements of Changes in Partners' Equity (Deficit)
Years ended December 31, 2010, 2009 and 2008
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund VII-B, L.P.
Statements of Cash Flows
The accompanying notes are an integral
part of these financial statements.
Southwest Royalties Institutional Income Fund VII-B, L.P.
Notes to Financial Statements
1.
Organization
Southwest Royalties Institutional Income Fund VII-B, L.P. was organized under the laws of the state of Delaware on January 28, 1987, for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc., a wholly owned subsidiary of Clayton Williams Energy, Inc., serves as the Managing General Partner.
Revenues, costs and expenses are allocated as follows:
(1)
All organization costs in excess of 3% of initial capital contributions will be paid by the Managing General Partner and will be treated as a capital contribution. The Partnership paid the Managing General Partner an amount equal to 3% of initial capital contributions for such organization costs.
(2)
Administrative costs in any year, which exceed 2% of capital contributions shall be paid by the Managing General Partner and will be treated as a capital contribution.
2.
Summary of Significant Accounting Policies
Oil and Gas Properties
The Partnership uses the full cost method of accounting for its oil and gas producing activities. Accordingly, all costs associated with acquisition, exploration, and development of oil and gas reserves are capitalized. Depletion is provided using the unit-of production method based upon estimates of proved oil and gas reserves. The amortizable base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage value. All of the Partnership’s oil and gas properties are located within the United States. Gain or loss on the sale of oil and gas properties is not recognized unless significant oil and gas reserves are sold.
Should the net capitalized costs exceed the estimated present value of oil and gas reserves, discounted at 10%, such excess costs would be charged to current expense. As of December 31, 2010, 2009 and 2008, the net capitalized costs did not exceed the estimated present value of oil and gas reserves.
The Partnership's interest in oil and gas properties consists of net profits interests in proved properties located within the continental United States. A net profits interest is created when the owner of a working interest in a property enters into an arrangement providing that the net profits interest owner will receive a stated percentage of the net profit from the property. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.
Southwest Royalties Institutional Income Fund VII-B, L.P.
Notes to Financial Statements
2.
Summary of Significant Accounting Policies - continued
The Partnership recognizes income from its net profits interest in oil and gas property on an accrual basis, while the quarterly cash distributions of the net profits interest are based on a calculation of actual cash received from oil and gas sales, net of expenses incurred during that quarterly period. If the net profits interest calculation results in expenses incurred exceeding the oil and gas income received during a quarter, no cash distribution is due to the Partnership's net profits interest until the deficit is recovered from future net profits. The Partnership accrues a quarterly loss on its net profits interest provided there is a cumulative net amount due for accrued revenue as of the balance sheet date. As of December 31, 2010, there were no timing differences which resulted in a deficit net profit interest.
Estimates and Uncertainties
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership’s depletion calculation and full-cost ceiling test for oil and gas properties uses oil and gas reserves estimates, which are inherently imprecise. Actual results could differ from those estimates.
Syndication Costs
Syndication costs are accounted for as a reduction of partnership equity.
Environmental Costs
The Partnership is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Costs, which improve a property as compared with the condition of the property when originally constructed or acquired and costs, which prevent future environmental contamination are capitalized. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated.
Revenue Recognition
The Partnership recognizes oil and gas sales when delivery to the purchaser has occurred and title has transferred. This occurs when production has been delivered to a pipeline or transport vehicle.
Gas Balancing
The Partnership utilizes the sales method of accounting for gas-balancing arrangements. Under this method the Partnership recognizes sales revenue on all gas sold. As of December 31, 2010 and 2009, the Partnership was under produced by 3,263 mcf of gas.
Income Taxes
No provision for income taxes is reflected in these financial statements, since the tax effects of the Partnership's income or loss are passed through to the individual partners.
Cash and Cash Equivalents
For purposes of the statement of cash flows, the Partnership considers all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. The Partnership maintains its cash at one financial institution.
Number of Limited Partner Units
As of December 31, 2010, 2009 and 2008, there were 15,000 limited partner units outstanding held by 532, 551 and 558 partners, respectively.
Southwest Royalties Institutional Income Fund VII-B, L.P.
Notes to Financial Statements
2.
Summary of Significant Accounting Policies - continued
Concentrations of Credit Risk
The Partnership is subject to credit risk for amounts due from its customers. Although a substantial portion of its debtors’ ability to pay is dependent upon the oil and gas industry, credit risk is minimized due to a large customer base. All partnership revenues are received by the Managing General Partner and subsequently remitted to the partnership and all expenses are paid by the Managing General Partner and subsequently reimbursed by the Partnership.
Fair Value of Financial Instruments
The carrying amount of cash and accounts receivable approximates fair value due to the short maturity of these instruments.
Net Income per limited partnership unit
The net income per limited partnership unit is calculated by using the number of outstanding limited partnership units.
3. Abandonment Obligations
The Partnership follows the provisions of ASC topic 410-20, formerly SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”). ASC topic 410-20 requires the Partnership to recognize a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost associated with the abandonment obligations, along with any estimated salvage value, is included in the computation of depreciation, depletion and amortization.
Our asset retirement obligation is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.
Changes in abandonment obligations for 2010 and 2009 are as follows:
Southwest Royalties Institutional Income Fund VII-B, L.P.
Notes to Financial Statements
4.
Commitments and Contingent Liabilities
After completion of the Partnership's first full fiscal year of operations and each year thereafter, the Managing General Partner has offered and will continue to offer to purchase each limited partner's interest in the Partnership. The pricing mechanism used to calculate the repurchase is based on tangible assets of the Partnership, plus the present value of the future net revenues of proved oil and gas properties, minus liabilities with a risk factor discount of up to one-third which may be implemented in the sole discretion of the Managing General Partner. However, the Managing General Partner's obligation to purchase limited partner units is limited to an annual expenditure of an amount not in excess of 10% of the total limited partner units initially subscribed for by limited partners.
The Partnership is subject to various federal, state and local environmental laws and regulations, which establish standards and requirements for protection of the environment. The Partnership cannot predict the future impact of such standards and requirements, which are subject to change and can have retroactive effectiveness. The Partnership continues to monitor the status of these laws and regulations.
As of December 31, 2010, the Partnership has not been fined, cited or notified of any environmental violations and management is not aware of any unasserted violations, which would have a material adverse effect upon capital the Partnership’s financial condition and operations. However, the Managing General Partner does recognize by the very nature of its business, material costs could be incurred in the near term to bring the Partnership into total compliance. The amount of such future expenditures is not determinable due to several factors, including the unknown magnitude of possible contaminations, the unknown timing and extent of the corrective actions which may be required, the determination of the Partnership's liability in proportion to other responsible parties and the extent to which such expenditures are recoverable from insurance or indemnifications from prior owners of the Partnership's properties.
In May 2006, the State of Texas adopted House Bill 3, which modified the state’s franchise tax structure, replacing the previous tax based on capital or earned surplus with a margin tax (the “Texas Margin Tax”) effective with franchise tax reports filed on or after January 1, 2008. The Texas margin Tax is computed by applying the applicable tax rate (1% for the Partnership’s business) to the profit margin, which is generally determined by total revenue less either cost of goods sold or compensation as applicable. However the Partnership believes, based on its interpretation, that the Texas Margin Tax does not apply to the Partnership since substantially all of its income is derived from a net profits interest.
5.
Related Party Transactions
A significant portion of the oil and gas properties in which the Partnership has an interest are purchased from and operated by the Managing General Partner. As provided for in the operating agreement for each respective oil and gas property in which the Partnership has an interest, the operator is paid an amount for administrative overhead attributable to operating such properties, with such amounts payable to Southwest Royalties, Inc. as operator approximating $27,900, $33,400 and $21,200 for the years ended December 31, 2010, 2009 and 2008, respectively. The amounts for administrative overhead attributable to operating the partnership properties has been deducted from gross oil and gas revenues in the determination of net profit interest. In addition, the Managing General Partner and certain officers and employees of the Managing General Partner may have an interest in some of the properties that the Partnership also participates.
Southwest Royalties, Inc., the Managing General Partner, was paid $108,000 during each of 2010, 2009 and 2008 as an administrative fee for indirect general and administrative overhead expenses. The administrative fees are included in general and administrative expense on the statement of operations.
Southwest Royalties Institutional Income Fund VII-B, L.P.
Notes to Financial Statements
5.
Related Party Transactions - continued
Receivables from Southwest Royalties, Inc., the Managing General Partner, of approximately $192,900 and $176,300 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2010 and 2009, respectively.
6.
Oil and Gas Reserves Information (unaudited)
The estimates of proved oil and gas reserves utilized in the preparation of the financial statements were prepared by independent petroleum engineers. Such estimates are in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board. All of the Partnership's reserves are located in the United States. For information about the Partnership’s results of operations from oil and gas producing activities, see the accompanying statements of operations.
In 2009, the SEC issued its final rule on the modernization of oil and gas reporting, and the Financial Accounting Standards Board (“FASB”) adopted conforming changes to Accounting Standards Codification (“ASC”) Topic 932, “Extractive Industries”, to align the FASB’s reserves requirements with those of the SEC. The final rule is now in effect for companies with fiscal years ending on or after December 31, 2009. As it affects our reserve estimates and disclosures, the final rule:
·
amends the definition of proved reserves to require the use of average commodity prices based upon the prior 12-month period rather than year-end prices;
·
expands the type of technologies available to establish reserve estimates and categories;
·
modifies certain definitions used in estimating proved reserves;
·
permits disclosure of probable and possible reserves; and
·
permits disclosure of reserves based on different price and cost criteria, such as futures prices or management forecasts.
We emphasize that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. In addition, a portion of our proved reserves are classified as proved developed nonproducing and proved undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced.
The Partnership's interest in proved oil and gas reserves is as follows:
Southwest Royalties Institutional Income Fund VII-B, L.P.
Notes to Financial Statements
6.
Oil and Gas Reserves Information (unaudited) - continued
Net revisions of 25,000 BOE in 2010, consisted of approximately 30,000 BOE of upward revisions attributable to the effects of higher product prices on the estimated quantities of proved reserves, net of downward revisions of approximately 3,000 BOE attributable to well performance primarily from properties in the Amacker-Tippett field of West Texas and 2,000 BOE of downward revisions of proved undeveloped reserves. Net revisions of 26,000 BOE in 2009, consisted of approximately 19,000 BOE of upward revisions attributable to the effects of higher product prices on the estimated quantities of proved reserves, net of downward revisions of approximately 41,000 BOE attributable to well performance primarily from properties in the Hendrick field of West Texas and 4,000 BOE of downward revisions of proved undeveloped reserves.
Oil price adjustments were made in the individual evaluations to reflect oil quality, gathering and transportation costs. The standardized measure as of December 31, 2010, 2009 and 2008 reflects an average oil price of $74.35, $56.46 and $42.47 per barrel. Average prices for December 31, 2010 and December 31, 2009 were based on the 12-month unweighted arithmetic average for the first-day-of-the-month price for the period from January 2010 through December 2010 and January 2009 through December 2009.
Gas price adjustments were made in the individual evaluations to reflect BTU content, gathering and transportation costs and gas processing and shrinkage. The standardized measure as of December 31, 2010, 2009 and 2008 reflects an average natural gas price of $6.68, $3.91 and $6.82 per Mcf. Average prices for December 31, 2010 and December 31, 2009 were based on the 12-month unweighted arithmetic average for the first-day-of-the-month price for the period from January 2010 through December 2010 and January 2009 through December 2009.
The evaluation of oil and gas properties is not an exact science and inevitably involves a significant degree of uncertainty, particularly with respect to the quantity of oil or gas that any given property is capable of producing. Estimates of oil and gas reserves are based on available geological and engineering data, the extent and quality of which may vary in each case and, in certain instances, may prove to be inaccurate. Consequently, properties may be depleted more rapidly than the geological and engineering data have indicated.
Unanticipated depletion, if it occurs, will result in lower reserves than previously estimated; thus an ultimately lower return for the Partnership. Basic changes in past reserve estimates occur annually. As new data is gathered during the subsequent year, the engineer must revise his earlier estimates. A year of new information, which is pertinent to the estimation of future recoverable volumes, is available during the subsequent year evaluation. In applying industry standards and procedures, the new data may cause the previous estimates to be revised. This revision may increase or decrease the earlier estimated volumes.
The Partnership has reserves, which are classified as proved developed and proved undeveloped. All of the proved reserves are included in the engineering reports, which evaluate the Partnership's present reserves.
Because the Partnership does not engage in drilling activities, the development of proved undeveloped reserves is conducted pursuant to farm-out arrangements with the Managing General Partner or unrelated third parties. Generally, the Partnership retains a carried interest such as an overriding royalty interest under the terms of a farm-out.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves at December 31, 2010, 2009 and 2008 is presented below:
Southwest Royalties Institutional Income Fund VII-B, L.P.
Notes to Financial Statements
6.
Oil and Gas Reserves Information (unaudited) - continued
Changes in the standardized measure of discounted future net cash flows relating to proved reserves for the years ended December 31, 2010, 2009 and 2008 are as follows:
7.
Selected Quarterly Financial Results - (unaudited)
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None
Item 9A.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
The Managing General Partner has established disclosure controls and procedures that are adequate to provide reasonable assurance that management of the Managing General Partner will be able to collect, process and disclose both financial and non-financial information, on a timely basis, in the Partnership’s reports to the SEC. Disclosure controls and procedures include all processes necessary to ensure that material information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and is accumulated and communicated to management of the Managing General Partner, including our chief executive and chief financial officers, to allow timely decisions regarding required disclosures.
With respect to these disclosure controls and procedures:
·
management of the Managing General Partner has evaluated the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report;
·
this evaluation was conducted under the supervision and with the participation of management of the Managing General Partner, including the chief executive and chief financial officers of the Managing General Partner; and
·
it is the conclusion of chief executive and chief financial officers of the Managing General Partner that these disclosure controls and procedures are effective in ensuring that information that is required to be disclosed by the Partnership in reports filed or submitted with the SEC is recorded, processed, summarized and reported within the time periods specified in the rules and forms established by the SEC.
Internal Control Over Financial Reporting
Management designed our internal control over financial reporting to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:
·
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
·
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our Board of Directors; and
·
provide reasonable assurance regarding prevention or timely detection of any unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Changes in Internal Control Over Financial Reporting
There has not been any change in the Partnership’s internal control over financial reporting that occurred during the year ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, its internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on this assessment, management has concluded that, as of December 31, 2010, our internal control over financial reporting is effective based on those criteria.
Item 9B.
Item 9B. Other Information
None.
Part III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Management of the Partnership is provided by Southwest Royalties, Inc., as Managing General Partner. Since the Managing General Partner is a wholly owned subsidiary of CWEI, the directors of the Managing General Partner are elected by management of CWEI. Each director the Managing General Partner serves for a term of one year. Following is certain information concerning each of the directors and executive officers of the Managing General Partner.
CLAYTON W. WILLIAMS, age 79, is Chairman of the Board and a director of the Managing General Partner, having served in this capacity since May 2004. Mr. Williams also serves as Chairman of the Board, President, Chief Executive Officer and a director of CWEI.
MEL G. RIGGS, age 56, is President of the Managing General Partner, having served in this capacity since February 2011. Prior to that, Mr. Riggs had served as Vice President of the Managing General Partner since May 2004. Mr. Riggs has also served as Director of the Managing General Partner since May 2004. Mr. Riggs has served as Executive Vice President and Chief Operating Officer of CWEI since December 2010. Prior to that, Mr. Riggs had served as Senior Vice President, Chief Financial Officer and Treasurer since September 1991. Mr. Riggs has been a Director of CWEI since May 1994.
MICHAEL L. POLLARD, is age 60, Senior Vice President and Treasurer of the Managing General Partner, having served in this capacity since February 2011. Mr. Pollard has also served as Senior Vice President- Finance, Chief Financial Officer and Treasurer of CWEI since December 2010. Prior to that, Mr. Pollard served as Vice President - Accounting of CWEI since 2003.
RANDY HOWARD, age 55, is Vice President of the Managing General Partner, having served in this capacity since March 2006.
ROBERT C. LYON, age 74, is Vice President of the Managing General Partner, having served in this capacity since May 2004. Mr. Lyon also serves as Vice President - Gas Gathering and Marketing of CWEI.
T. MARK TISDALE, age 54, is Vice President of the Managing General Partner, having served in this capacity since May 2004. Mr. Tisdale also serves as Vice President and General Counsel of CWEI.
Financial Code of Ethics
As a wholly owned subsidiary of CWEI, the Managing General Partner is subject to the Financial Code of Ethics adopted by CWEI. The Financial Code of Ethics contains the ethical principles by which our Chief Executive Officer, Chief Financial Officer, Vice President - Accounting or Chief Accounting Officer and other senior financial officers (collectively, the “Senior Officers”) are expected to conduct themselves when carrying out their duties and responsibilities. Senior Officers must also comply with the Company’s other ethics policies, including any amendments or supplements thereto, including the Company’s Code of Conduct and Ethics. The Financial Code of Ethics is designed to deter wrongdoing and to promote, among other things: honest and ethical conduct, ethical handling of actual or apparent conflicts of interest; full, fair, accurate and timely disclosure in filings with the SEC and in other public disclosures; compliance with applicable law; and prompt internal reporting of violations of the Financial Code of Ethics.
The Financial Code of Ethics is available on our website at www.claytonwilliams.com under “Investor Relations /Governance/Documentation.” We will provide the Financial Code of Ethics in print, free of charge, to partners who request it. Any waiver of the Financial Code of Ethics with respect to executive officers or directors may be made only by the Board or a Board committee and will be promptly disclosed to partners on our website, as will any amendments to the Financial Code of Ethics.
Item 11.
Item 11. Executive Compensation
The Partnership does not employ any directors, executive officers or employees. The Managing General Partner receives an administrative fee for the management of the Partnership. The Managing General Partner received $108,000 during each of 2010, 2009 and 2008, as an annual administrative fee. The executive officers of the Managing General Partner do not receive any form of compensation, from the Partnership; instead, their compensation is paid solely by CWEI. The executive officers, however, may occasionally perform administrative duties for the Partnership but receive no additional compensation for this work.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
There are no limited partners who own of record, or are known by the Managing General Partner to beneficially own, more than five percent of the Partnership's limited partnership interests, other than the Managing General Partner.
Through repurchase offers to the limited partners, the Managing General Partner owns 6,509.5 limited partner units, a 39.1% limited partner interest. The Managing General Partner's total percentage interest ownership in the Partnership is 49.1%.
No officer or director of the Managing General Partner directly owns units in the Partnership. CWEI is considered to be a beneficial owner of the limited partner units acquired by the Managing General Partner by virtue of its ownership of the Managing General Partner. Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and includes voting or investment power with respect to the limited partner units.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
In 2010, the Managing General Partner received $108,000 as an administrative fee. This amount is part of the general and administrative expenses incurred by the Partnership.
In some instances, the Managing General Partner and its affiliates may be working interest owners in an oil and gas property in which the Partnership also has a net profits interest. Certain properties in which the Partnership has an interest are operated by the Managing General Partner, who was paid approximately $27,900 for administrative overhead attributable to operating such properties during 2010.
The terms of the above transactions are similar to ones that would have been obtained through arm’s length negotiations with unaffiliated third parties.
Item 14.
Item 14. Principal Accounting Fees and Services
The following table presents fees for professional audit services rendered by KPMG LLP for the audit of the Partnership’s annual financial statements for the years ended December 31, 2010 and 2009 and fees billed for other services rendered by KPMG during those periods.
For the Year Ended December 31,
Audit Fees
$
19,034
$
17,163
Audit Related Fees
-
-
Tax Fees
-
-
All Other Fees
-
-
TOTAL
$
19,034
$
17,163
The Audit Committee of CWEI reviewed and approved, in advance, all audit and non-audit services provided by KPMG LLP.
Part IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
(a)
(1)
Financial Statements:
Included in Part II of this report
Report of Independent Registered Public Accounting Firm
Balance Sheets
Statements of Operations
Statements of Changes in Partners' Equity (Deficit)
Statements of Cash Flows
Notes to Financial Statements
(2)
Schedules required by Article 12 of Regulation S-X are either omitted because they are not applicable or because the required information is shown in the financial statements or the notes thereto.
(3)
Exhibits:
(a)
Certificate of Limited Partnership of Southwest Royalties Institutional Income Fund VII-B, L.P., dated January 28, 1987. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1988.)
(b)
Agreement of Limited Partnership of Southwest Royalties Institutional Income Fund VII-B, L.P. dated May 20, 1987. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1988.)
(c)
Certificate of Amendment of Limited Partnership of Southwest Royalties Institutional Income Fund VII-B, L.P., dated July 21, 1987. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1988.)
31.1
Rule 13a-14(a)/15d-14(a) Certification
31.2
Rule 13a-14(a)/15d-14(a) Certification
32.1
Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
Glossary of Oil and Gas Terms
The following are abbreviations and definitions of terms commonly used in the oil and gas industry that are used in this filing. All volumes of natural gas referred to herein are stated at the legal pressure base to the state or area where the reserves exit and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.
Bbl. One barrel, or 42 U.S. gallons of liquid volume.
BOE. Means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or natural gas liquid.
Developmental well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Completion . The installation of permanent equipment for the production of oil or gas.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Farm-out arrangement. An agreement whereby the owner of a leasehold or working interest agrees to assign his interest in certain specific acreage to an assignee, retaining some interest, such as an overriding royalty interest, subject to the drilling of one (1) or more wells or other specified performance by the assignee.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Mcf. One thousand cubic feet.
Natural gas liquids . Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.
Net Profits Interest. An agreement whereby the owner receives a specified percentage of the defined net profits from a producing property in exchange for consideration paid. The net profits interest owner will not otherwise participate in additional costs and expenses of the property.
Oil. Crude oil, condensate and natural gas liquids.
Overriding royalty interest. Interests that are carved out of a working interest, and their duration is limited by the term of the lease under which they are created.
Present value of proved reserves (“PV-10”). The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with Securities and Exchange Commission guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, (ii) nonproperty related expenses such as general and administrative expenses, debt service and future income tax expense, or (iii) depreciation, depletion and amortization.
Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.
Proved Area. The part of a property to which proved reserves have been specifically attributed.
Proved developed oil and gas reserves. Proved oil and gas reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved properties. Properties with proved reserves.
Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including government entities.
Proved undeveloped reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
Standardized measure of discounted future net cash flows. Present value of proved reserves, as adjusted to give effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment, and (ii) estimated future income taxes.
Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.
Workover. Operations on a producing well to restore or increase production.
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Partnership has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Southwest Royalties Institutional Income Fund
VII-B, L.P., a Delaware limited partnership
By:
Southwest Royalties, Inc., Managing
General Partner
By:
/ s/ Mel G. Riggs
Mel G. Riggs
President and Chief Executive Officer
Date:
March 29, 2011
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
/s/ Clayton W Williams
/s/ Mel G. Riggs
Clayton W. Williams, Chairman of the Board
Mel G. Riggs, President, Chief Executive
and a Director
Officer and a Director
Date: March 29, 2011
Date: March 29, 2011
/s/ Michael L. Pollard
Michael L. Pollard, Senior Vice President
and Chief Financial Officer
Date: March 29, 2011