ITEM 1. BUSINESS
Introduction
Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) is a limited partnership formed under the laws of the state of Texas on November 27, 2007. The Partnership was formed to purchase working interests in oil and gas properties with the purposes of (i) growing the value of properties through the development of proved undeveloped reserves, (ii) generating revenue from the production of crude oil and natural gas, (iii) distributing cash to the partners of the Partnership, and (iv) selling the properties no later than 2015, in order to maximize return to the partners of the Partnership. Reef Oil & Gas Partners, L.P. (“Reef”) is the managing general partner of the Partnership. Terms used in this Annual Report such as “we,” “us” or “our” refer to Reef.
The Partnership sought to purchase working interests in oil and gas properties with both proved producing reserves and proved undeveloped reserves. During the period from November 27, 2007 through the period ended June 30, 2010, the Partnership made three major property acquisitions with the capital raised by the Partnership. These three acquisitions are referred to as the Slaughter Dean acquisition, the Azalea acquisition, and the Lett acquisition. On all properties purchased, the Partnership plans to produce existing proved reserves and develop any proved undeveloped reserves, but not to engage in exploratory drilling for unproved reserves. Drilling locations with unproved reserves, if any, may be farmed out or sold to third parties or other partnerships formed by Reef.
In instances where the percentage ownership of the Partnership in a property is large enough, Reef Exploration, L.P., an affiliate of Reef (“RELP”), serves as the property’s operator. RELP currently serves as operator of the wells acquired in the Slaughter Dean acquisition. All wells included in the Azalea and Lett acquisitions are operated by third parties not affiliated with the Partnership, Reef, or any other Reef affiliate. Other partnerships managed by Reef also own working interests in some of the properties acquired in the Azalea and Lett acquisitions.
Property Acquisition, Development, and Divestiture
Slaughter Dean Acquisition
The Slaughter Dean acquisition consisted of the purchase of a working interest in a producing oil property with approximately 70 wells producing or capable of producing crude oil at the time of the Partnership’s acquisition in January 2008. These wells are located in the Slaughter Field in Cochran County, Texas. Though the wells acquired in the Slaughter Dean acquisition had existing production, the acquisition was made primarily for the purpose of developing the field’s reserves by performing a waterflood development project in a portion of the field. The Slaughter Dean acquisition consisted of approximately 70 wells and 6,700 acres and produces crude oil and natural gas from the San Andres formation at depths from 5,000 to 5,500 feet. The major portions of the Slaughter Dean
field were previously unitized for waterflood operations. During the period from 2008 through 2010, RELP, on behalf of the Partnership and other working interest owners, performed additional waterflood developmental work within the Slaughter Dean field in an attempt to increase the ultimate recovery of crude oil and natural gas from the field. The Slaughter Dean acquisition is divided into two units and one non-unitized lease known as (i) the Dean Unit, (ii) the Dean “B” Unit, and (iii) the Dean “K” lease, respectively. Waterflood developmental activity was focused in the Dean “B” Unit. Several existing productive wells were converted into water injection wells, unit spacing was changed from 40 acres per well to 20 acres per well, and new production and injection wells were drilled within the new unit spacing. Some inactive water injection wells and marginal producing wells were also converted to water injection wells. New injection pumps were installed which enabled the unit to approximately triple its water injection capacity to over 6,000 barrels of water per day, in an attempt to pressurize the reservoir via water fill-up. The development work was performed during 2008 and 2009, and the additional injection capacity was added during the first quarter of 2010.
The actual results of the additional developmental work did not produce the desired production of additional oil. The waterflood activities described above temporarily reduced the rate of decline in oil production, but did not increase crude oil production as desired. Although significant crude oil reserves may remain in the reservoir, the effort to increase the waterflood response was determined to be unlikely to be effective in materially increasing the recovery of those reserves, based upon the results during 2010. The Partnership re-evaluated its reserves associated with the development and enhancement of waterflood operations based on data obtained from the operations of the Slaughter Dean waterflood to determine what quantities of crude oil and natural gas reserves the Partnership could reasonably expect to recover from this reservoir under current economic and operating conditions. Based upon this analysis, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean waterflood of $53,166,873 as of December 31, 2010.
RELP has continued to monitor the waterflood operations and daily production of total fluids (oil and water) during 2011, 2012 and 2013, but no further developmental activities were performed during those years. Although the total water injection on a daily basis exceeds the fluids being removed from the reservoir, no noticeable increase in pressure or fluid production has been observed. During 2012, RELP ran injection profile logs on five of the current water injection wells hoping they might aid in determining if there is any work that might be performed on the injection wells to try and improve the waterflood pattern performance; however, the results of this work were inconclusive. While alternative configurations may improve waterflood results, the Partnership does not possess the capital required to implement a re-configuration of the waterflood. RELP continues to monitor waterflood operations and continues to operate the Slaughter Dean Project without any changes.
Azalea Acquisition
During January 2010, the Partnership acquired from RCWI, an affiliate of the Partnership, at cost, 61% of the working interests initially acquired by RCWI from Azalea Properties, Ltd. RCWI also assigned portions of the acquired working interests to other affiliates of RCWI and the Partnership on the same terms. The Azalea acquisition included working interests in more than 400 properties, including more than 1,400 wells, located in Texas, California, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado, and Arkansas, and also included undrilled infill and offset acreage on certain properties. The acquired working interests are all minority non-operated interests. The properties are operated by more than 100 different operators, none of which are affiliates of the Partnership or Reef.
The Partnership has participated as a working interest owner in the drilling of additional developmental wells on some of the properties purchased, and during 2010 sold interests in certain acquired properties to other Reef affiliates when it was determined that additional drilling activities on such properties was not considered developmental. Additional property sales subsequent to 2010 are summarized below.
Lett Acquisition
During June 2010, the Partnership acquired from RCWI, at cost, working interests acquired by RCWI from Lett Oil & Gas, L.P. The Lett acquisition consisted of working interests in the Thums Long Beach Unit, a producing oil and gas property with approximately 870 producing wells and 485 injection wells. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. The
acquired working interests are all minority non-operated interests. The Thums Long Beach Unit is operated by a third party which is not an affiliate of the Partnership or Reef.
Sales of Interests - Thums Long Beach Unit
In January 2011, the Partnership sold a portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P., a Reef affiliate. In June 2011, the Partnership sold an additional portion of its interests in the Thums Long Beach Unit to the same affiliate. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. These interests were initially acquired as part of the Lett Acquisition, and were sold primarily in order for the Partnership to pay down its debt obligations under the Partnership’s credit agreement. The Partnership received $350,000 in cash in exchange for the interests sold in January and $2,650,000 for the interests sold in June. The Partnership recorded no gain or loss associated with these transactions.
Sales of Interests - Covington Prospect
In September 2012, the Partnership sold leasehold interests related to a three well drilling program in the Covington Prospect in Ward County, Texas proposed by a third party operator, to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate (“Reef 2012-A”). The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and the Partnership would have needed to retain cash flow from producing properties and forego distributions to partners for several months in order to fund this drilling project. The leasehold acreage sold also included one productive working interest well and twelve productive royalty interest wells that currently produce oil and gas from different geologic zones than the zone to be tested in the three proposed wells. The Partnership recorded $138,973 as accounts receivable from affiliates at September 30, 2012 related to this transaction. During 2012, Reef 2012-A paid $93,451 to the Partnership in connection with this sale, and the Partnership had a receivable of $45,522 at December 31, 2012. The purchase and sale agreement called for the Partnership to receive an amount equal to the value of the first drilled well, based upon a 12 percent per year discount factor (“PV12%”) from a third party engineering report prepared at year-end 2012 in accordance with SEC regulations. This report was received during 2013 and the sales price was adjusted from $138,973 to $201,573. The Partnership received the $45,522 account receivable, plus an additional payment of $62,600 from Reef 2012-A in 2013. The Partnership recorded no gain or loss related to this sales transaction.
Sales of Interests - Carter County, Oklahoma
The Partnership sold its interest in two wells acquired as a part of the Azalea acquisition during the fourth quarter of 2013. The Partnership owned working interests of less than 2% in each well. The operator of these two properties received an offer from a third party interested in drilling new wells to a deeper horizon than the current wells. The operator notified the working interest partners of the offer, and the Partnership agreed to include the interests owned by the Partnership in the sale. The Partnership received approximately $191,000 for its interest in the two wells. The estimated discounted future net cash flows included in the Partnership’s 2012 reserve report for these two wells was less than $2,000. The Partnership utilized $170,000 of the proceeds to prepay principal under its existing credit agreement. The Partnership recorded no gain or loss related to this sales transaction.
Major Customers
The Partnership sells crude oil and natural gas on credit terms to refiners, pipelines, marketers, and other users of petroleum commodities. Revenues are received directly from these parties or, in certain circumstances, paid to the operator of the property who disburses to the Partnership its percentage share of the revenues. During the year ended December 31, 2013, one marketer and one operator accounted for 38.0% and 32.8% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2012, one marketer and one operator accounted for 34.6% and 26.8% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2011, one marketer and one operator accounted for 34.9% and 29.4% of the Partnership’s crude oil and natural gas revenues, respectively. Due to the competitive nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.
Insurance
The Partnership is a named insured under blowout, pollution, public liability and workmen’s compensation insurance policies obtained by RELP. Such insurance, however, may not be sufficient to cover all liabilities of the Partnership. Each unit held by general partners represents a joint and several liability for unforeseen events including, without limitation, blowouts, lost circulation, and stuck drill pipe that may result in unanticipated additional liability materially in excess of a general partner’s initial investment in the Partnership.
RELP has obtained various insurance policies, as described below, and intends to maintain such policies subject to its analysis of their premium costs, coverage and other factors. In the exercise of its fiduciary duty as managing general partner, Reef has obtained insurance on behalf of the Partnership to provide the Partnership with such coverage as Reef believes is sufficient to protect the investor partners against the foreseeable risks of drilling and production. Reef reviews the Partnership’s insurance coverage prior to commencing drilling operations and periodically evaluates the sufficiency of insurance. Reef has obtained and maintained, and will continue to maintain, umbrella liability insurance coverage for the Partnership equal to the lesser of at least $50,000,000 or twice the capitalization of the Partnership, and in no event will the Partnership maintain public liability insurance of less than $10,000,000. Subject to the foregoing, Reef may, in its sole discretion, increase or decrease the policy limits and types of insurance from time to time as it deems appropriate under the circumstances, which may vary materially.
Reef and RELP are the beneficiaries under each policy and pay the premiums for each policy. The Partnership is a named insured under all insurance policies carried by RELP. Insurance premiums are broken down on a well-by-well basis and billed through an inter-company charge to the Partnership, as well as other Reef-sponsored partnerships, based upon the premiums charged by the insurance carrier for the specific wells in which the Partnership owns a working interest. Should a claim arise related to a property owned by the Partnership, the Partnership will be reimbursed for any amounts payable under such insurance coverage through a credit to the inter-company account balance. The inter-company balance between RELP and the Partnership is settled on at least a quarterly basis. However, in the event of a large insurance reimbursement being payable to the Partnership, the inter-company balance would be settled earlier, within a reasonable time after receipt of the insurance proceeds.
The Partnership reimburses RELP for its share of the insurance premium. The following types and amounts of insurance have been maintained:
· Workmen’s compensation insurance in full compliance with the laws of the State of Texas, and which will be obtained for any other jurisdictions where the Partnership may conduct its business in the future;
· General liability insurance, including bodily injury liability and property damage liability insurance, with a combined single limit of $1,000,000;
· Employer’s liability insurance with a limit of not less than $1,000,000;
· Automobile public liability insurance with a limit of not less than $1,000,000 per occurrence, covering all automobile equipment;
· Energy exploration and development liability (including well control, environmental and pollution liability) insurance coverage with limits of not less than $5,000,000 for land wells and $10,000,000 for wet wells; and
· Umbrella liability insurance (excess of the General liability, Employer’s liability and Automobile liability insurance) with a limit of not less than $50,000,000.
Reef will notify all non-Reef general partners of the Partnership at least 30 days prior to any material change in the amount of the Partnership’s insurance coverage. Within this 30-day period, non-Reef general partners have the right to convert their units into units of limited partnership interest by giving Reef written notice. Non-Reef general partners will have limited liability as a limited partner for any Partnership operations conducted after their conversion date, effective upon the filing of an amendment to the Certificate of Limited Partnership of the Partnership. At any time during this 30-day period, upon receipt of the required written notice from the non-Reef
general partner of his intent to convert, Reef will amend the partnership agreement and will file the amendment with the State of Texas prior to the effective date of the change in insurance coverage. This amendment to the partnership agreement will effectuate the conversion of the interest of the former non-Reef general partner to that of a limited partner. Effecting conversion is subject to the express requirement that the conversion will not cause a termination of the partnership for federal income tax purposes. However, even after an election of conversion, a non-Reef general partner will continue to have unlimited liability regarding partnership activities while he was a non-Reef general partner.
Competition
There are a large number of oil and gas companies in the United States. Competition is strong among persons and entities involved in the acquisition of oil and gas properties, as well as the exploration for and production of crude oil and natural gas. Reef expects the Partnership to encounter strong competition at every phase of business. The Partnership competes with entities having financial resources and staffs substantially larger than those available to it.
The national supply of natural gas is widely diversified, with no one entity controlling over 5% of supply. As a result of deregulation of the natural gas industry enacted by Congress and the Federal Energy Regulatory Commission (“FERC”), natural gas prices are generally determined by competitive market forces. Prices of crude oil, condensate and natural gas liquids are not currently regulated and are generally determined by competitive market forces.
Markets
The marketing of crude oil and natural gas produced by the Partnership is affected by a number of factors that are beyond the Partnership’s control and whose exact effect cannot be accurately predicted. These factors include:
· the amount of crude oil and natural gas imports;
· the availability, proximity and cost of adequate pipeline and other transportation facilities;
· the success of efforts to market competitive fuels, such as coal and nuclear energy and the growth and/or success of alternative energy sources such as wind and solar power;
· the effect of United States and state regulation of production, refining, transportation and sales;
· other matters affecting the availability of a ready market, such as fluctuating supply and demand; and
· general economic conditions in the United States and around the world.
The supply and demand balance of crude oil and natural gas in world markets has caused significant variations in the prices of these products over recent years. The North American Free Trade Agreement eliminated trade and investment barriers between the United States, Canada, and Mexico, resulting in increased foreign competition for domestic natural gas production. New pipeline projects recently approved by, or presently pending before, FERC, as well as nondiscriminatory access requirements could further substantially increase the availability of natural gas imports to certain U.S. markets. Such imports could have an adverse effect on both the price and volume of natural gas sales from Partnership wells.
Members of the Organization of Petroleum Exporting Countries (“OPEC”) establish prices and production quotas for petroleum products from time to time with the intent of affecting the global supply of crude oil and maintaining, reducing, or increasing certain price levels. Reef is unable to predict what effect, if any, such actions will have on both the price and volume of crude oil produced and sold from the Partnership’s wells.
In several initiatives, FERC has required pipeline transportation companies to develop electronic communication and to provide standardized access via the Internet to information concerning capacity and prices on a nationwide basis, so as to create a national market. Parallel developments toward an electronic marketplace for electric power, mandated by FERC, are serving to create multi-national markets for energy products generally. These systems will allow rapid consummation of natural gas transactions. Although this system may initially lower prices due to increased competition, it is anticipated to expand natural gas markets and to improve their reliability.
Governmental Regulation
The Partnership’s operations will be affected from time to time in varying degrees by domestic and foreign political developments, and by federal and state laws and regulations.
Production. In most areas of operations within the United States the production of crude oil and natural gas is regulated by state agencies that set allowable rates of production and otherwise control the conduct of oil and gas operations. Among the ways that states control production is through regulations that establish the spacing of wells, or in some instances limit the number of days in a given month that a well is permitted to produce oil and gas.
Operators of oil and gas properties are required to have a number of permits to operate oil and gas properties, including operator permits and permits to dispose of salt water. RELP possesses all material requisite permits required by the states and other local authorities in areas where it operates Partnership properties. In addition, under federal law, operators of oil and gas properties are required to possess certain certificates and permits such as hazardous materials certificates, which RELP has obtained.
Environmental Matters. The Partnership’s drilling and production operations are also subject to environmental protection regulations established by federal, state, and local agencies that may necessitate significant capital outlays that, in turn, would materially affect the financial position and business operations of the Partnership. These regulations, enacted to protect against waste, conserve natural resources and prevent pollution, could necessitate spending funds on environmental protection measures, rather than on drilling operations. If any penalties or prohibitions were imposed on the Partnership for violating such regulations, the Partnership’s operations could be adversely affected.
Natural Gas Transportation and Pricing. FERC regulates the rates for interstate transportation of natural gas as well as the terms for access to natural gas pipeline capacity. Pursuant to the Wellhead Decontrol Act of 1989, however, FERC may not regulate the price of natural gas. Such deregulated natural gas production may be sold at market prices determined by supply and demand, Btu content, pressure, location of wells, and other factors. Reef anticipates that all of the natural gas produced by the Partnership’s wells will be considered price-decontrolled natural gas and that the Partnership’s natural gas will be sold at fair market value. However, while sales by producers of natural gas can currently be made at unregulated market prices, Congress could reenact price controls in the future.
Proposed Regulation. Various legislative proposals are being considered in Congress and in the legislatures of various states, which, if enacted, may significantly and adversely affect the petroleum and natural gas industries. Such proposals involve, among other things, the imposition of price controls on all categories of natural gas production, the imposition of land use controls, such as prohibiting drilling activities on certain federal and state lands in protected areas, as well as other measures. At the present time, it is impossible to predict what proposals, if any, will actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals will have on the Partnership’s operations. No prediction can be made as to what additional legislation may be proposed, if any, affecting the competitive status of an oil and gas producer, restricting the prices at which a producer may sell its oil and/or gas, or the market demand for oil and/or gas, nor can it be predicted which proposals, including those presently under consideration, if any, might be enacted, nor when any such proposals, if enacted, might become effective.
Climate Change Legislation and Greenhouse Gas Regulation. The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005 (the “Protocol”). Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol. However, the U.S. Congress is considering proposed legislation directed at reducing greenhouse gas emissions. In addition, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The natural gas and oil industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact the operations on wells by the Partnership. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact the Partnership’s business.
Employees
The Partnership has no employees, and is managed by the managing general partner, Reef. RELP employs a staff including geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership’s operations. The Partnership reimburses RELP for technical and administrative services at cost. See “Item 11. Executive Compensation.”
CAUTIONARY INFORMATION ABOUT FORWARD LOOKING STATEMENTS
This Annual Report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These forward looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements; other than statements of historical fact, regarding strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward looking statements. You should exercise extreme caution with respect to all forward-looking statements made in this Annual Report. Specifically, the following statements are forward-looking:
· statements regarding the Partnership’s overall strategy for acquiring and disposing of oil and gas properties;
· statements regarding the Partnership’s plans to develop the Slaughter Dean field, including the enhancement of production of existing wells through waterflood operations;
· statements regarding the state of the oil and gas industry and the opportunity to profit within the oil and gas industry, our competition, pricing, level of production, or the regulations that may affect the Partnership;
· statements regarding the plans and objectives of Reef for future operations, including, without limitation, the uses of Partnership funds and the size and nature of the costs the Partnership expect to incur and people and services the Partnership may employ;
· statements regarding the timing of distributions
· any statements using the words “anticipate,” “believe,” “estimate,” “expect” and similar such phrases or words; and
· any statements of other than historical fact.
Reef believes that it is important to communicate its future expectations to our investors. Forward-looking statements reflect the current view of management with respect to future events and are subject to numerous risks, uncertainties and assumptions, including, without limitation, the factors listed in Item 1A
ITEM 1A. RISK FACTORS
Our business activities are subject to certain risks and hazards, including the risks discussed below. If any of these events should occur, it could materially and adversely affect our business, financial condition, cash flow, or results of operations. The risks below are not the only risks we face. We may experience additional risks and uncertainties
not currently known to us or, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flow, and results of operations. Consequently, you should not consider this list to be a complete statement of all of our potential risks or uncertainties.
Oil and gas well drilling is a speculative activity involving numerous risks and substantial and uncertain costs which could adversely affect the Partnership.
Drilling for oil and gas involves numerous risks, including the risk that no commercially productive crude oil and/or natural gas reserves will be discovered. There can be no assurance that wells drilled by the Partnership will be productive or recover all or any portion of the investment in such wells. Drilling and completion costs are substantial and uncertain, and drilling operations may be curtailed, delayed, or cancelled due to a variety of factors beyond our control, including shortages or delays in the availability of drilling rigs and crews, unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, and compliance with environmental and other governmental regulations. Our drilling activities may not be successful and, if unsuccessful, will have an adverse effect on the Partnership’s results of operations and cash flow available for distribution to the partners.
Oil and gas investments are risky.
Although the Partnership will not engage in any exploratory drilling, the acquisition, development and operation of oil and gas properties is not an exact science and involves a high degree of risk. The risks of acquiring and
operating producing properties are generally less than those associated with the drilling of wells. Developmental drilling may result in dry holes or wells that do not produce crude oil or natural gas in sufficient quantities to make them commercially profitable to complete. The producing properties acquired by the Partnership may not produce sufficient quantities of crude oil or natural gas to enable an investor partner to obtain any certain projected rate of return on his or her investment, and it is possible that investor partners may lose money.
We are subject to substantial environmental hazards and operating risks that may adversely affect the results of operations.
There are numerous natural hazards involved in the drilling and operation of oil and gas wells, including unexpected or unusual formations, pressures, blowouts involving possible damages to property and third parties, surface damages, bodily injuries, damage to and loss of equipment, reservoir damage and loss of reserves, pollution, releases of toxic gas and other environmental hazards and risks. There are also hazards involved in the transportation of crude oil and natural gas from Partnership wells to market. Such hazards include pipeline leakage and risks associated with the spilling of oil transported by rail or barge instead of pipeline, both of which could result in liabilities associated with environmental cleanup. The Partnership could suffer substantial losses as a result of any of these risks. The Partnership is not fully insured against all risks inherent to the oil and gas business. Uninsured liabilities would reduce the funds available to the Partnership, may result in the loss of Partnership properties and may create liability for the general partners. Although the Partnership maintains insurance coverage in amounts Reef deems appropriate, it is possible that insurance coverage may be insufficient. In that case Partnership assets may have to be sold to pay personal injury and property damage claims and the cost of controlling blowouts or replacing damaged equipment rather than for drilling activities. In the event the Partnership incurs uninsured losses or liabilities, the Partnership’s funds available for Partnership purposes may be substantially reduced or lost completely, and investor general partners may be jointly and severally liable for such amounts.
Crude oil and natural gas prices are volatile, and fluctuate due to a number of factors outside of our control.
The financial condition, results of operations, and the carrying value of our oil and gas properties depend primarily upon the prices received for our crude oil and natural gas production. Crude oil and natural gas prices historically have been volatile and likely will continue to be volatile given current geopolitical conditions. Cash flow from operations is highly dependent upon the sales prices received from crude oil and natural gas production. The prices for crude oil and natural gas are subject to a variety of factors beyond our control. These factors include:
· the domestic and foreign supply of crude oil and natural gas; consumer demand for crude oil and natural gas, and market expectations regarding supply and demand;
· the ability of the members of OPEC to agree to and maintain crude oil price and production controls;
· domestic government regulations and taxes;
· the price and availability of foreign exports and alternative fuel sources;
· weather conditions, including hurricanes and tropical storms in and around the Gulf of Mexico;
· political conditions in crude oil and natural gas producing regions, including the Middle East, Nigeria, and Venezuela; and
· domestic and worldwide economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict price movements. Also, crude oil and natural gas prices do not necessarily move in tandem. Declines in crude oil and natural gas prices would not only reduce revenues and cash flow available for distributions to partners, but could reduce the amount of crude oil and natural gas that can be economically produced from successful wells drilled by the Partnership, and, therefore, have an adverse effect upon financial condition, results of operations, crude oil and natural gas reserves, and the carrying value of the Partnership’s oil and gas properties. Approximately 78.3% of the Partnership’s estimated proved reserves at December 31, 2013 were crude oil reserves, and, as a result, financial results are more sensitive to fluctuations in crude oil prices.
The Partnership, while not prohibited from engaging in commodity trading or hedging activities in an effort to reduce exposure to short-term fluctuations in the price of crude oil and natural gas, has no hedges in place at
December 31, 2013. Accordingly, the Partnership is at risk for the volatility in crude oil and natural gas prices, and the level of commodity prices has a significant impact upon the Partnership’s results of operations.
A global economic downturn could have a material adverse impact on our financial position, results of operations and cash flows.
The oil and gas industry is cyclical and tends to reflect general economic conditions. The United States and other countries around the world experienced an economic downturn in 2008 and 2009 which had an adverse impact on demand and pricing for crude oil and natural gas. Another downturn similar to that experienced in 2008 and 2009 could lead to a similar negative impact on crude oil and natural gas prices or reduced demand for crude oil and natural gas that could have a significant impact on the Partnership’s operating cash flows and profitability. Declines in crude oil and natural gas prices may also impact the value of our crude oil and natural gas reserves, which could result in future impairment charges to reduce the carrying value of the Partnership’s oil and gas properties.
We cannot control activities on non-operated properties.
The Partnership has limited ability to exercise influence over and control the risks associated with operations on properties not operated by RELP. The Azalea acquisition properties and the Lett acquisition properties are all operated by third party operators. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements, or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. The success and timing of drilling and development activities on properties operated by others depends upon a number of factors outside of our control, including the operator’s
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timing and amount of capital expenditures;
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expertise and financial resources;
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inclusion of other participants in drilling wells; and
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the use of technology.
In addition, the Partnership could be held liable for the joint interest obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of the other working interest owners. Full development of leases and prospects may be jeopardized in the event other working interest owners cannot pay their share of drilling and completion costs.
The Partnership may become liable for joint activities of other working interest owners.
The Partnership holds title to its interests in oil and gas properties in its own name, and it is anticipated that the Partnership will hold any additional interests in properties it may purchase in the future in its own name. Additionally, the Partnership is and will continue to be a joint working interest owner with other parties. It has not been clearly established whether joint working interest owners have several liability or joint and several liability with respect to obligations relating to the working interest. Although the operating agreements relating to properties ordinarily specify that the liabilities of joint working interest owners will be several, if the Partnership and other working interest owners are determined to have joint and several liability, the Partnership could be responsible for the obligations of these other parties relating to the entire working interest. The Partnership was advised that Davric, Corporation, who is unrelated to Reef and owns a 7% working interest in the Dean Unit and the Dean “B” Unit in the Slaughter Dean Project, was unable to pay $538,443 of its share of costs incurred subsequent to February 28, 2009. Pursuant to the Davric Operating Agreement, the Partnership assumed the 7% working interest of Davric and Davric is now a non-consenting working interest owner. The unpaid costs have been recorded as property additions and operating costs on the books of the Partnership, and the Partnership will retain the Davric 7% working interest until the net revenues related to this interest exceed the unpaid costs, plus penalties ranging from 300% to 450% of the amount in default.
Crude oil and natural gas reserve data are estimates based upon assumptions that may be inaccurate and existing economic and operating conditions that may differ from future economic and operating conditions.
Securities and Exchange Commission (“SEC”) rules require the Partnership to present annual estimates of reserves using the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-
month period and year end costs. Future prices and costs may be materially higher or lower than these prices and costs, which would impact the estimate of reserves and future cash flows.
Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.
You should not assume the present value of future net cash flows referred to in this Annual Report to be the current market value of our estimated crude oil and natural gas reserves. The estimated discounted future net cash flows from our proved reserves as of December 31, 2013 are based upon the preceding 12-month un-weighted arithmetic average of the first-day-of-the-month prices and year end costs. Actual current prices, as well as future prices and costs, may be materially higher or lower. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates.
The Partnership Agreement limits Reef’s liability to each partner and the Partnership and requires the Partnership to indemnify Reef against certain losses.
Reef will have no liability to the Partnership or to any partner for any loss suffered by the Partnership, and will be indemnified by the Partnership against loss sustained by it in connection with the Partnership if:
1. Reef determines in good faith that its action was in the best interest of the Partnership;
2. Reef was acting on behalf of or performing services for the Partnership; and
3. Reef’s action did not constitute negligence or misconduct by Reef.
The production and producing life of Partnership wells is uncertain. Production will decline.
It is not possible to predict the life and production of any well. The actual lives could differ significantly from those anticipated. Sufficient crude oil or natural gas may not be produced for investor partners to receive a profit or even to recover their initial investment. In addition, production from the Partnership’s oil and gas wells, if any, will decline over time, and does not indicate any consistent level of future production. This production decline may be rapid and irregular when compared to a property’s initial production.
Extreme weather conditions may adversely affect production operations and partner distributions.
Some oil and gas wells acquired in the Azalea acquisition are located in coastal regions of Louisiana and Texas. This area is susceptible to extreme weather conditions, especially those associated with hurricanes. In the event of a hurricane and related storm activity, such as windstorms, storm surges, floods and tornados, Partnership operations in the region may be adversely affected. The occurrence of a hurricane or other extreme weather may harm or delay the Partnership’s operations or distribution of revenues, if any.
Our dependence on third parties for the processing and transportation of crude oil and natural gas may adversely affect the Partnership’s revenues and distributions.
We rely on third parties to process and transport crude oil and natural gas produced by the Partnership’s successful wells. In the event a third party upon whom we rely is unable to provide transportation or processing services, and another third party is unavailable to provide such services, then the Partnership may have to temporarily shut-in successful wells, and revenues to the Partnership and distributions to investor partners may be delayed.
We face strong competition within the energy industry.
The oil and gas industry is highly competitive. Competition is encountered in all aspects of Partnership operations, including the requisition of drilling and service contractors. Many of our competitors are larger, well-established companies with substantially larger operating staffs and greater capital resources than those of the Partnership, Reef and its affiliates. We may not be able to conduct our operations successfully, obtain drilling and service contractors, consummate transactions, and obtain technical, managerial and other professional personnel in this highly competitive environment. Specifically, larger competitors may be able to pay more for competent personnel than the Partnership, Reef and its affiliates. In addition, such competitors may be able to expend greater resources on the existing and changing technologies that will be increasingly important to success. Such competitors may also be in a better position to secure drilling and oilfield services, as well as equipment, more timely or on more favorable terms. Finally, oil and gas producers are increasingly facing competition from providers of non-fossil energy, and government policy may favor those competitors in the future.
The Partnership may incur liability for liens against its subcontractors.
Although Reef will try to determine the financial condition of nonaffiliated subcontractors, if subcontractors fail to timely pay for materials and services, the properties of the Partnership could be subject to materialmen’s and workmen’s liens. In that event, the Partnership could incur excess costs in discharging the liens.
The effect of borrowing and other financing may negatively impact partnership distributions.
Net proceeds from the sale of units in the Partnership were used for the Slaughter Dean acquisition and the execution of the waterflood development work plan, including drilling new oil wells on the Dean “B” Unit and providing necessary production equipment and facilities to service such oil and gas wells. Net proceeds from the sale of units in the Partnership were also used in connection with the Azalea acquisition in January 2010. However, the Partnership borrowed $5,000,000 from a bank in connection with the Lett acquisition in June 2010. As of December 31, 2013, the outstanding balance of these borrowings was $690,000. Although there are no plans at this time to do so, certain costs of operations may also be financed through partnership borrowings and through utilization of partnership revenues obtained from production, the sale of producing or non-producing reserves, the sale of net profits interests or other operating or non-operating interests in properties, or other methods of financing. If these methods of financing should prove to be unavailable or insufficient to maintain the desired level of operations for the Partnership, operations could be continued through farmout arrangements with third parties (including affiliated partnerships) or the sale of net profits interests or other operated or non-operating interests in properties. This could result in the Partnership giving up a substantial interest in crude oil and natural gas reserves. If the Partnership sells net profits interests in properties, the Partnership will incur costs that it cannot recover from the holders of the net profits interests, except from future revenues, if any, relating to such properties. The effect of borrowing or other financing could be to increase funds available to the Partnership, but also could be to reduce cash available for distributions to the extent cash is used to repay borrowings, or to reduce reserves if properties are farmed out or interests in the properties are sold.
Government regulation may adversely impact the Partnership’s profitability.
The oil and gas business is subject to extensive governmental regulation under which, among other things, rates of production from partnership wells may be fixed and the prices for natural gas produced from the Partnership wells may be limited. Governmental regulation also may limit or otherwise affect the market for the Partnership’s crude oil and natural gas production, if any, and the price that may be paid for that production. Governmental regulations relating to environmental matters could also affect the Partnership’s operations by increasing the costs of operations or by requiring the modification of operations in certain areas. State and federal governmental regulation of the oil and gas industry is in a potentially fluid situation and could change dramatically as a result of many outside factors, including a shift in the philosophy of the governmental environmental policies, continued increases in the price of crude oil and national security concerns. The nature and extent of various regulations, the nature of other political developments, and their overall effect upon the Partnership are not predictable. Investment in the Partnership involves a high degree of risk and is suitable only for investors of substantial financial means who have no need for liquidity in their investments.
Fluctuations in drilling costs over recent periods may impact the profitability of each Partnership well and the number of wells the Partnership may drill.
There has been significant volatility in recent periods in the costs associated with the drilling of oil and gas wells. Specifically, the costs of the use of drilling rigs and their personnel, steel for pipelines, mud and fuel have risen and fallen in recent periods. Future increases could result in limiting the number of wells the Partnership may drill as well as the profitability of each well once completed.
Delays in the transfer of title to the Partnership could place the Partnership at risk.
Titles to the Partnership’s interest in the leases for the Slaughter Dean field and the Thums Long Beach Unit are held in the name of the Partnership. Under the RCWI Agreement, title to the Azalea acquisition properties is held temporarily in the name of RCWI. When the Partnership acquires additional properties, title to those properties may be held temporarily in Reef’s name or in the name of one or more of Reef’s affiliates as nominee for the Partnership in order to facilitate the acquisition of properties by the Partnership and for other valid purposes. When this is the case, the Partnership runs the risk that the transfer of title could be set aside in the event of the bankruptcy of the party holding title. In this event, title to the leases and the wells would revert to the creditors or trustee, and the Partnership would either recover nothing or only the amount paid for the leases and the cost of drilling the wells. Assigning the leases to the Partnership after the wells are drilled and completed, however, will not affect the availability of the tax deductions for intangible drilling costs since the Partnership will have an economic interest in the wells under the drilling and operating agreement before the wells are drilled. See “ITEM 2. PROPERTIES - Title to Properties.”
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Drilling, Waterflood Development Activities and Productive Wells
The Slaughter Dean acquisition included approximately 70 wells producing or capable of producing crude oil at the time of the Partnership’s acquisition in January 2008. Reef implemented a waterflood development plan on a portion of the Dean “B” Unit during 2008 and 2009, and upgraded water injection facilities during 2010. The Partnership spent a significant portion of its capital on the Slaughter Dean waterflood project.
The drilling of new water injection wells and the conversion of a number of old already-producing oil wells to water injection wells was intended to increase the productivity of the project as a whole. The gradual filling of the productive formation via this enhancement of waterflooding was designed to loosen and force out additional oil, thereby increasing the ultimate recovery of crude oil in the Dean “B” Unit.
While the waterflood development activity temporarily reduced the rate of decline in oil production, the desired increase in oil production rates did not materialize. As a result, as of December 31, 2010 the Partnership determined that the waterflood development work was unlikely to be effective in materially increasing the recoverable crude oil reserves that may remain in the reservoir. Based upon this analysis, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean waterflood development project of $53,166,873 as of December 31, 2010.
RELP has continued to monitor the waterflood operations and daily production of total fluids (oil and water) during 2011, 2012 and 2013, but no further developmental activities were performed during those years. Although the total water injection on a daily basis exceeds the fluids being removed from the reservoir, no noticeable increase in pressure or fluid production has been observed. During 2012, RELP ran injection profile logs on five of the current water injection wells hoping they might aid in determining if there is any work that might be performed on the injection wells to try and improve the waterflood pattern performance; however, the results of this work were inconclusive. While alternative configurations may improve waterflood results, the Partnership does not possess the capital required to implement a re-configuration of the waterflood. RELP continues to monitor waterflood
operations and continues to operate the Slaughter Dean Project without any changes.
The Partnership also owns non-operated minority working interests in properties acquired in the Azalea and Lett acquisitions, which consist of over 400 properties and more than 1,400 wells located in twelve states, which were acquired in two separate purchases completed during 2010. The largest property purchased in the Azalea acquisition is an interest in the Thums Long Beach Unit, which is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. Thums Long Beach has produced more than 930 BOE from the Wilmington Field, and it is estimated it has in excess of 200 million barrels of oil equivalent remaining to be produced using current costs and pricing as of December 31, 2013. Thums Long Beach derived its name from the property’s original shareholders, Texaco, Humble, Union, Mobil and Shell. The only property acquired in the Lett acquisition was an additional interest in the Thums Long Beach Unit.
In January 2011, the Partnership sold a portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P., a Reef affiliate. In June 2011, the Partnership sold an additional portion of its interests in the Thums Long Beach Unit to the same affiliate. These interests were sold primarily in order for the Partnership to pay down its debt obligations under the Partnership’s credit agreement. The Partnership received $350,000 in cash in exchange for the interests sold in January and $2,650,000 for the interests sold in June. The Partnership recorded no gain or loss associated with this transaction.
In September 2012, the Partnership sold leasehold interests related to a three well drilling program in the Covington Prospect in Ward County, Texas proposed by a third party operator, to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate (“Reef 2012-A”). The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and the Partnership would have needed to retain cash flow from producing properties and forego distributions to partners for several months in order to fund this drilling project. The leasehold acreage sold also included one productive working interest well and twelve productive royalty interest wells that currently produce oil and gas from different geologic zones than the zone to be tested in the three proposed wells. The Partnership recorded $138,973 as accounts receivable from affiliates at September 30, 2012 related to this transaction. During 2012, Reef 2012-A paid $93,451 to the Partnership in connection with this sale, and the Partnership had a receivable of $45,522 at December 31, 2012. The purchase and sale agreement called for the Partnership to receive an amount equal to the value of the first drilled well, based upon a 12 percent per year discount factor (“PV12%”) from a third party engineering report prepared at year-end 2012 in accordance with SEC regulations. This report was received during 2013 and the sales price was adjusted from $138,973 to $201,573. The Partnership received the $45,522 account receivable, plus an additional payment of $62,600 from Reef 2012-A in 2013. The Partnership recorded no gain or loss related to this sales transaction.
The Partnership sold its interest in two wells acquired as a part of the Azalea acquisition during the fourth quarter of 2013. The Partnership owned working interests of less than 2% in each well. The operator of these two properties received an offer from a third party interested in drilling new wells to a deeper horizon than the current wells. The operator notified the working interest partners of the offer, and the Partnership agreed to include the interests owned by the Partnership in the sale. The Partnership received approximately $191,000 for its interest in the two wells. The estimated discounted future net cash flows included in the Partnership’s 2012 reserve report for these two wells was less than $2,000. The Partnership utilized $170,000 of the proceeds to prepay principal under its existing credit agreement. The Partnership recorded no gain or loss related to this sales transaction.
The Partnership does not expect to purchase interests in any additional properties. The Partnership evaluates, on a case by case basis, proposals from operators to drill additional wells on the infill and offset acreage acquired in connection with the Azalea acquisition, and agrees to participate or declines to participate in such additional drilling based upon its evaluations of such proposals. Should the Partnership receive proposals for new wells that are classified as exploratory wells, the Partnership may sell the acreage, along with any currently productive wells on the lease, to other Partnerships affiliated with Reef and RELP.
Proved Crude Oil and Natural Gas Reserves
Estimates of the Partnership’s proved reserves are prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and year end
costs. The reserve information presented below is based upon estimates of net proved reserves that were prepared by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2013. All of the Partnership’s reserves are located in the United States.
The estimated net proved crude oil and natural gas reserves at December 31, 2013, 2012, and 2011 are summarized below. Proved crude oil and natural gas reserves discussed in this section include only the amounts which the Partnership can estimate with reasonable certainty to be economically producible in future years from known oil and gas reservoirs under existing economic conditions, operating methods, and government regulations. Proved reserves include only quantities that the Partnership expects to recover commercially using current prices, costs, existing regulatory practices, and technology. Therefore, any changes in future prices, costs, regulations, technology or other unforeseen factors could materially increase or decrease the proved reserve estimates.
The standardized measure of discounted future net cash flows as of December 31, 2013, 2012, and 2011 is computed by applying the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period, costs, and legislated tax rates and a discount factor of 10% to net proved reserves. The standardized measure of discounted future net cash flows does not purport to present the fair value of our crude oil and natural gas reserves.
During the years ended December 31, 2013, 2012, and 2011, the Partnership recorded no property impairment costs of proved properties.
During 2013, the rate of decline in production from the wells in the Slaughter Dean field increased, and, as a result, reserve estimates were adjusted downward. Estimated proved reserves related to the Partnership’s working interest in the Slaughter Dean wells at December 31, 2013 were estimated to be approximately 113,000 Bbl, compared to approximately 332,000 Bbl at December 31, 2012.
Qualifications of Technical Persons and Internal Controls Over the Reserves Estimation Process
The Partnership used an independent petroleum engineering firm, Forrest A. Garb & Associates, Inc., (“FGA”) of Dallas, Texas, to prepare its December 31, 2013, 2012, and 2011 estimates of net proved crude oil and natural gas reserves. FGA estimated reserves for all of our properties as of December 31, 2013, 2012 and 2011. The technical personnel responsible for preparing the reserve estimates at FGA meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. FGA is an independent firm of petroleum engineers and geologists. They do not own an interest in any of our properties, and are not employed on a contingent fee basis. FGA’s report was developed utilizing state reporting records and published production data purchased from third parties, and data provided by Reef. Their reserve summary, which contains further discussions of the reserve estimates and evaluations, as well as the qualifications of FGA’s technical personnel responsible for overseeing their estimates and evaluations, is included as Exhibit 99.1 to this Annual Report.
Reef’s policies and practices regarding internal controls over the recording of reserves are structured to objectively and accurately estimate oil and gas reserve quantities and present values in compliance with SEC regulations and US Generally Accepted Accounting Principles (“GAAP”).
Reef maintains a staff of technical personnel who are well versed in the engineering evaluation computer programs and technology used and who provide well and production data to our independent petroleum engineering firm, FGA. Our accounting department accumulates historical production and pricing data and lease operating expenses
for our wells, as well as the percentage interest owned by the Partnership, which is reviewed by our technical staff. Reserve estimates are prepared by FGA. Our technical staff and members of our accounting department meet regularly with FGA’s representatives to review properties and discuss methods and assumptions used in the preparation of their estimates. Mr. Jerald Sluder, Senior Reservoir Engineer for RELP, is primarily responsible for overseeing the preparation of reserve estimates by FGA. Mr. Sluder has a B.S. in Petroleum Engineering, is a Registered Professional Engineer in the State of Texas and has over nineteen years of industry experience in oil and gas operations. Mr. Sluder is an active member of the Society of Petroleum Engineers and of the Petroleum Engineers Club of Dallas. Any significant reserve changes are approved by Mr. Daniel C. Sibley, Chief Financial Officer and General Counsel of RELP, and Mr. Michael J. Mauceli, Chief Executive Officer of RELP.
Title to Properties
Title to the Partnership’s interest in the leases for the Slaughter Dean wells, the Thums Long Beach Unit, and certain Azalea acquisition properties is held in the name of the Partnership. Under the RCWI Agreement, title to properties is temporarily held in the name of RCWI. Upon acquiring properties, title to properties may be held temporarily in Reef’s name or in the name of one or more of Reef’s affiliates as nominee for the Partnership in order to facilitate the acquisition of properties by the Partnership and for other valid purposes. Otherwise, record title to the Partnership properties will be held in the name of the Partnership.
The Partnership believes that the title to its oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to exceptions which, in the opinion of the Partnership, will not be so material as to detract substantially from the use or value of such properties. The Partnership’s properties are subject, in one degree or another, to one or more of the following: royalties and other burdens created by the Partnership or its predecessors in title; a variety of contractual obligations arising under operating agreements, production sales contracts and other agreements that may affect the properties or their titles; liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; pooling, unitization and commoditization agreements, declarations and orders; and easements, restrictions, rights-of-way and other matters that commonly affect property. To the extent that such burdens and obligations affect the Partnership’s rights to production revenues, they will be taken into account in calculating the Partnership’s new revenue interests and in estimating the quantity and value of the Partnership’s reserves. The Partnership believes that the burdens and obligations affecting its properties will be conventional in the industry for properties of their kind.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
There are no material legal proceedings pending, on appeal or concluded to which the Partnership is a party, or to which any of its assets is subject.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
As of December 31, 2013, the Partnership had one managing general partner, 813 non-Reef general partners, and 666 non-Reef limited partners. Reef holds a total of 8.9697 general partner units and 0.6000 limited partner units, and the non-Reef partners hold 490.9827 general partner units and 396.4172 limited partner units. No established trading market exists for the units, and there is no unit repurchase program available to investor partners under the terms of the Partnership Agreement.
Cash which, in the sole judgment of the managing general partner, is not required to meet the Partnership’s obligations is available for distribution to the partners at least quarterly in accordance with the Partnership
Agreement. The Partnership has made cash distributions to the partners of crude oil and natural gas sales revenues, less operating, general and administrative, and other costs since January 2008. Cash distributions were distributed 11% to Reef and 89% to investor partners. During 2013, Reef purchased 0.60 units of limited partner interest from one of the investor partners (representing 0.067% of investor partner units.). Thus, effective October 1, 2013 Reef also holds 0.067% of the 89% interest in the Partnership (0.060%) represented by the investor partner units, and receives 0.060% of the distributions paid to investor partners. The Partnership’s credit agreement contains certain restrictions on distributions, including the absence of default as defined by the credit agreement, the maintenance of a minimum cash balance, and a maximum amount to be distributed based on certain other calculations described in the credit agreement. Cash distributions paid during 2013, 2012, and 2011 were $682,835, $655,321, and $867,371, respectively.
Investor limited partner interests are transferable, subject to certain restrictions contained in the Partnership Agreement; however, no assignee of a unit in the Partnership can become a substituted partner without the written consent of both the transferor and Reef.
Use of Proceeds
Units of limited and general partner interests in the Partnership were offered at $100,000 each (with a minimum investment of ¼ unit at $25,000) to accredited investors in a private placement pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated thereunder, with a maximum offering amount of $90,000,000 (900 units). Reef Securities, Inc., an affiliate of Reef, served as the dealer manager for the private placement. An amount equal to 15% of the proceeds realized from the sale of interests to investors was paid to Reef as a management fee. Reef paid all organization and offering costs of the Partnership, including sales commissions, from this amount. The remaining 85% of the proceeds has been expended on the Slaughter Dean, Azalea, and Lett acquisitions, the waterflood development project at Slaughter Dean and drilling of developmental wells upon acreage purchased in connection with the Azalea acquisition, and payment of additional fees owed to Reef as a result of such activities. On June 12, 2008, the offering of units of general and limited partner interests in the Partnership was closed. A total of $88,648,094 was raised by the Partnership, net of adjustments for sales to brokers for their own accounts, who were permitted to buy Units at a price net of the commission that they would normally earn on sales of Units, of which $48,984,933 were sold to accredited investors as units of general partner interest and $39,663,161 were sold to accredited investors as units of limited partner interest. As managing general partner, Reef contributed $762,425 (approximately one percent 1%) of the total contributions of the non-Reef general partners and limited partners) to the Partnership in exchange for 8.9697 units of general partner interest, resulting in a total capitalization of the Partnership of $89,410,519 before payment of the 15% management fee used by Reef to pay organization and offering costs.
All units except those purchased by Reef paid a 15% ($13,320,000, less $151,906 of unpaid net asset values) management fee to Reef to pay for Partnership organization and offering costs, including sales commissions. These costs totaled $13,168,094, leaving capital contributions of $76,242,425 available for Partnership oil and gas operations. As of December 31, 2013, the Partnership had expended $57,328,179 on acquisition and development of the Slaughter Dean wells, $16,270,856 on the acquisition and development of the Azalea properties, and $6,901,254 on the acquisition and development of the Lett properties, prior to sales of the Partnership’s interests or portions of its interests in certain properties. The Partnership has no current plans to purchase additional oil and gas properties.
Expenditures in excess of available capital have been financed through debt or property sales, or have been recovered from cash flows by reducing Partnership distributions.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data. The selected financial data presented below has been derived from the audited financial statements of the Partnership.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion will assist you in understanding the Partnership’s financial position, liquidity, and results of operations. The information should be read in conjunction with the audited financial statements and notes to financial statements contained herein. The discussion contains historical and forward-looking information.
For a discussion of risk factors that could impact the Partnership’s financial results, please see Item 1A of this Annual Report.
Critical Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the amounts reported in the financial statements and accompanying notes. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates and assumptions under different conditions. The more significant areas requiring the use of management’s estimates and judgments relate to the estimation of proved crude oil and natural gas reserves, the use of these crude oil and natural gas reserves in calculating depletion, depreciation, and amortization, the use of the estimates of future net revenues in computing ceiling test limitations, and estimates of future abandonment obligations used in recording asset retirement obligations.
Management is also required to select among alternative acceptable accounting policies. See Note 2 to the financial statements for a complete list of significant accounting policies.
Oil and Gas Properties
The Partnership follows the full cost method of accounting for its oil and gas activities. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method using estimated proved reserves. For these purposes, proved natural gas reserves are converted to barrels of oil equivalent (“BOE”) at a rate of 6 Mcf to 1 Bbl. Under the full cost method of accounting, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.
In applying the full cost method, the Partnership is required to perform a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the sum of the estimated future net revenues from proved reserves using prices that are the preceding 12-month un-weighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, if any. If capitalized costs exceed the ceiling, an impairment loss is recognized for the amount by which the capitalized costs exceed the ceiling, and is shown as a reduction of oil and gas properties and as property impairment expense on the Partnership’s statements of operations. During the years ended December 31, 2013, 2012, and 2011, the Partnership recognized no property impairment expense of proved properties.
Unproved property consists of undrilled infill and offset acreage acquired in connection with the purchase of the Azalea properties. Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date. The assessment includes consideration of the following factors, among others: intent to drill; remaining primary lease term; drilling results and activity in the immediate area of the property; the holding period of the property; and geological and geophysical evaluation. To the extent that the assessment indicates a property is impaired, the amount of impairment is added to the capitalized costs of oil and gas properties which are subject to the quarterly ceiling test. During the years ended December 31, 2013, 2012, and 2011, the Partnership recognized no property impairment expense of unproved properties.
The Partnership expects that all of its unproved property costs at December 31, 2013 will be drilled and transferred to proved property cost within 10 years of acquisition. All unproved property cost not being amortized as of December 31, 2013 was incurred during the year ended December 31, 2010.
Estimates of Proved Oil and Gas Reserves
The estimate of the Partnership’s proved reserves at December 31, 2013 was prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and year end costs. Future prices and costs may be materially higher or lower than these prices and costs, which would impact the estimate of reserves and future cash flows. The Partnership’s proved reserve information included in this report was based upon evaluations prepared by FGA, an independent petroleum engineering firm.
Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.
Reserves and their relation to estimated future net cash flows impact the Partnership’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. If proved reserve estimates decline, the rate at which depletion expense is recorded increases, reducing net income. A decline in estimated proved reserves and future cash flows also reduces the capitalized cost ceiling and may result in increased impairment expense.
Asset Retirement Obligation
The Partnership has recognized an estimated liability for future plugging and abandonment costs. A liability for the estimated fair value of the future plugging and abandonment costs is recorded with a corresponding increase in the full cost pool at the time a new well is drilled or acquired. Depreciation expense associated with estimated plugging and abandonment costs is recognized in accordance with the full cost methodology.
The Partnership estimates a liability for plugging and abandonment costs based on historical experience and estimated well life. The liability is discounted using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs or well useful lives, or if federal or state regulators enact new well restoration requirements. The Partnership recognizes accretion expense in connection with the discounted liability over the remaining life of the well.
During 2011, the Partnership plugged and abandoned seven wells located in the Slaughter Dean Field. The costs associated with the plugging operation exceeded the Partnership’s recorded asset retirement obligation, and approximately $62,000 of plugging and abandonment cost was recorded as lease operating expenses on the 2011 statement of operations. The Partnership determined that its estimated asset retirement obligation for the Slaughter Dean wells (approximately 145 wells) was understated, and, in that regard, the Partnership increased the basis of the Slaughter Dean wells by $860,878 and recorded additional asset retirement obligation of this amount as a change in estimate.
During 2012, the Partnership plugged and abandoned three wells located in the Slaughter Dean Field. Approximately $27,362 of plugging and abandonment costs related to these three wells were applied against the Partnership’s asset retirement obligation shown on the accompanying balance sheet, and approximately $88,000 was recorded as lease operating expenses on the 2012 statement of operations. The Partnership received lower bids for providing plugging services from two other third party vendors; however, those vendors could not schedule the services prior to the regulatory deadlines imposed by the state. Based upon the bids received from the other two vendors, the Partnership did not revise its estimated asset retirement liability for the other wells in the Slaughter Dean Field.
The following table summarizes the Partnership’s asset retirement obligation for the periods ended December 31, 2013 and 2012.
Recognition of Revenue
The Partnership has entered into sales contracts for disposition of its share of crude oil and natural gas production from productive wells. Revenue is recognized based upon the Partnership’s share of metered volumes delivered to those purchasers each month. Any significant over or under balanced gas positions are disclosed in the financial statements. As of December 31, 2013, 2012 and 2011, the Partnership had no material gas imbalance positions.
Overview
Reef Oil & Gas Income and Development Fund III, L.P. is a Texas limited partnership. The primary objectives of the Partnership are to purchase working interests in oil and gas properties with the purposes of (i) growing the value of properties through the development of proved undeveloped reserves, (ii) generating revenue from the production of crude oil and natural gas, (iii) distributing cash to the partners of the Partnership, and (iv) selling the properties no later than 2015, in order to maximize return to the partners of the Partnership. Reef is the managing general partner of the Partnership.
On properties purchased by the Partnership, the Partnership plans to produce existing proved reserves and develop any proved undeveloped reserves, but will not engage in exploratory drilling for unproved reserves, should acreage purchased by the Partnership be deemed to contain unproved drilling locations. Drilling locations with unproved reserves, if any, may be farmed out or sold to third parties or other partnerships formed by Reef. In 2010, after expending funds on a major waterflood development project located on the Dean “B” Unit, a portion of the Partnership’s Slaughter Dean acquisition, the Partnership recognized an impairment of its unproved properties in the Slaughter Dean waterflood of $53,166,873. The Partnership evaluates, on a case by case basis, proposals from operators to drill additional wells on the infill and offset acreage acquired in connection with the Azalea acquisition, and agrees to participate or declines to participate in such additional drilling based upon its evaluations of such proposals. Should the Partnership decide to participate in such developmental drilling, funds to drill are taken from current net cash flows available for distributions to investors. The Partnership does not expect to purchase interests in any additional properties.
The Partnership owns interests in over 1,500 wells located in twelve states. The management of the operations and other business of the Partnership is the responsibility of Reef. RELP, an affiliate of Reef, serves as operator of the Partnership’s Slaughter Dean wells. All properties associated with the Azalea and Lett acquisitions are operated by third party operators not affiliated with Reef or any of Reef’s affiliates. The Partnership does not operate in any other industry segment.
The Partnership has borrowed funds from a bank in connection with the Lett acquisition, and is subject to the interest rate risk inherent in borrowing activities. The Partnership currently has no hedges in place, and therefore is subject to commodity price risk. See “Item 7A
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Interest Rate Risk
The Partnership Agreement allows borrowings from banks or other financial sources of up to 30% of the aggregate capital contributions to the Partnership with the consent of the Investor Partners. At December 31, 2013, the Partnership had $690,000 of outstanding debt under the Credit Agreement. Interest is calculated under the terms of the agreement based on the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of 5%, payable monthly. A 1.0% increase in interest rates during the year ended December 31, 2013 would have increased interest expense by approximately $10,150. The Partnership does not currently intend to enter into any derivative arrangements to protect against fluctuations in interest rates applicable to its outstanding indebtedness.
Commodity Price Risk
As of December 31, 2013, the Partnership does not expect to engage in commodity futures trading or hedging activities or enter into derivative financial instrument transactions for trading or other speculative purposes. The Partnership sells a vast majority of its production from successful oil and gas wells on a month-to-month basis at current spot market prices. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.
Assuming the production levels the Partnership attained during the year ended December 31, 2013, a 10% change in the price received for crude oil would have had an approximate $475,000 impact on the Partnership’s oil revenues, and a 10% change in the price received for the natural gas would have had an approximate $36,000 impact on the Partnership’s natural gas revenues.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The report of our independent registered public accounting firm, and the Partnership’s financial statements, related notes, and supplementary data are presented beginning on page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As the managing general partner of the Partnership, Reef maintains a system of controls and procedures designed to provide reasonable assurance as to the reliability of the financial statements and other disclosures included in this Annual Report, as well as to safeguard assets from unauthorized use or disposition. The Partnership, under the supervision and with participation of its management, including the principal executive officer and principal financial and accounting officer of the Partnership’s managing general partner, Reef Oil & Gas Partners, L.P., evaluated the effectiveness of its “disclosure controls and procedures” as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this Annual Report. Based on that evaluation, the principal executive officer and principal financial and accounting officer of our managing general partner have concluded that the Partnership’s disclosure controls and
procedures are effective to ensure that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in Securities and Exchange Commission rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial and accounting officer of our managing general partner, as appropriate to allow timely decisions regarding financial disclosure.
Management Report on Internal Control Over Financial Reporting
Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Our management conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation under the framework in Internal Control - Integrated Framework (1992), management of the Partnership concluded that the Partnership’s internal control over financial reporting was effective as of December 31, 2013.
This annual report does not include an attestation report of the Partnership’s independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Partnership’s registered public accounting firm pursuant to rules of the SEC that permit the Partnership to provide only management’s report in this annual report.
Changes in Internal Controls
There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
The Partnership has no directors or executive officers. Its managing general partner is Reef Oil & Gas Partners, L.P.
Reef Oil & Gas Partners, L.P. and Reef Exploration, L.P.
The Manager, officers and key personnel of the managing general partner, their ages, current positions with the managing general partner and/or RELP, and certain additional information are set forth below.
Michael J. Mauceli is the Manager and a member of Reef Oil & Gas Partners, GP, LLC, which is the general partner of Reef, as well as the Chief Executive Officer of RELP. Mr. Mauceli has been the principal executive officer of Reef since its formation in February 1999. He has served in this position with RELP since January 2006 and has served in this position with its predecessor entity, OREI, Inc. (“OREI”) since 1987. Mr. Mauceli attended the University of Mississippi where he majored in business management and marketing as well as the University of
Houston where he received his Commercial Real Estate License. He entered the oil and gas business in 1976 when he joined Tenneco Oil & Gas Company. Mr. Mauceli moved to Dallas in 1979, where he was independently employed by several exploration and development firms in planning exploration and marketing feasibility of privately sponsored drilling programs.
Daniel C. Sibley became Chief Financial Officer of RELP in March 2010 and General Counsel of RELP in January 2009. He previously served as Chief Financial Officer of Reef from December 1999 until his appointment to General Counsel of RELP. He also served as Chief Financial Officer for RELP from January 2006 until his appointment to General Counsel of RELP, and had served in this same position with RELP’s predecessor entity, OREI, since 1998. Mr. Sibley was employed as a Certified Public Accountant with Grant Thornton from 1977 to 1980. From 1980 to 1994, he was involved in the private practice of law. He received a B.B.A. in accounting from the University of North Texas in 1973, a law degree (J.D.) from the University of Texas in 1977, and a Master of Laws-Taxation degree (Ll.M) from Southern Methodist University in 1984. Mr. Sibley became a certified public accountant in 1977, but no longer maintains that license. He is an active member of the Texas Bar Association.
David M. Tierney, the Chief Financial Reporting Officer and Treasurer of RELP, has been employed by RELP since January 2006 and was previously with its predecessor entity, OREI, Inc., since March 2001. Mr. Tierney became Chief Financial Reporting Officer of RELP in March 2010 and Treasurer of RELP in May 2009. Prior to that, Mr. Tierney served as Chief Accounting Officer - Public Partnerships of RELP starting in July 2008. From 2001 to 2008, Mr. Tierney was the Controller of the Reef Global Energy Ventures and Reef Global Energy Ventures II partnerships. Mr. Tierney received a Bachelor’s degree from Davidson College in 1974, a Masters of Business Administration from Tulane University in 1976, and is a Texas Certified Public Accountant. Mr. Tierney has worked in public accounting, and has worked in the oil and gas industry since 1979. From 1992 through 2000 he served as controller/treasurer of an independent oil and gas exploration company.
Audit Committee and Nominating Committee
Because the Partnership has no directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.
Code of Ethics
Because the Partnership has no employees, it does not have a code of ethics. Employees of the Partnership’s managing general partner, Reef, must comply with Reef’s Code of Ethics, a copy of which will be provided to Investor Partners, without charge, upon request made to Reef Oil & Gas Partners, L.P., 1901 N. Central Expressway, Suite 300, Richardson, Texas 75080, Attention: Daniel C. Sibley.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
The following table summarizes the items of compensation to be received by Reef and its affiliates from the Partnership:
Reef received a payment equal to 15% ($13,320,000, less $151,906 of the unpaid net asset values) of the Partnership’s subscriptions, as adjusted for sale of Units to brokers for their own accounts, who were permitted to buy Units at a price net of the commission that they would normally earn on sales of Units. From this payment, Reef paid organization and offering costs of the Partnership, including commissions. Because the organization and offering costs were less than 15% of the aggregate subscriptions to the Partnership, Reef kept the difference ($5,688,668) as a one-time management fee.
Reef purchased 1% of the Partnership units, and received an additional 10% general partner interest as compensation for forming the Partnership. This 10% interest is “carried” by the Investor Partners and Reef pays no drilling or completion expenses for this interest. Cash distributions to partners of the net cash flow from crude oil and natural gas sales revenues, less operating, general and administrative, and other costs were distributed 11% to Reef and 89% to investor partners. Effective October 1, 2013, as a result of Reef’s purchase of 0.60 units of limited partner interest from an investor, Reef receives 0.067% of the 89% interest in the Partnership (0.060%) represented by the investor partner units. During the years ended December 31, 2013, 2012 and 2011, Reef received $75,112, $72,085, and $107,464, respectively, in cash distributions related to its 11% interest, and received $142 during the year ended December 31, 2013 related to its units of limited partner interest.
In addition, when RELP, serves as operator of a Partnership well, then RELP, receives drilling compensation in an amount equal to 15% of the total well costs paid from the funds of the Partnership. RELP currently serves as the operator of the Slaughter Dean wells. As a result, such drilling compensation payable to RELP may amount to approximately 9% of total partnership subscriptions, depending on the level of developmental operations conducted by RELP. Total well costs include all drilling and equipment costs, including intangible well costs, tangible costs of drilling and completing the well, costs of storage and other surface facilities, and the tangible costs of gathering pipelines necessary to connect the well to the nearest appropriate sales point or delivery point. In addition, total well costs also include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for a well or any other activity incident to the operations of a well, excluding ordinary well operating costs after completion. Total well costs do not include costs relating to lease acquisitions for purposes of calculating drilling compensation. RELP also receives drilling compensation in an amount equal to 5% of the total well costs paid by the Partnership for non-operated wells. During the years ended December 31, 2013, 2012, and 2011, RELP received $25,602, $39,856, and $54,005, respectively, in drilling compensation. Drilling compensation payments are included in oil and gas properties in the financial statements.
Additionally, Reef and its affiliates are reimbursed for direct costs and all documented out-of-pocket expenses incurred
on behalf of the Partnership. During the year ended December 31, 2013, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $102,762 and $1,551, respectively. During the year ended December 31, 2012, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $171,800 and $1,302, respectively. During the year ended December 31, 2011, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $342,271 and $2,818, respectively.
Prior to January 1, 2012, RELP received an administrative fee to cover all general and administrative costs in an amount equal to 1/12th of 1% of all capital raised payable monthly, totaling $74,740 per month. During the first quarter of 2012, Reef reduced the amount of the monthly administrative fee charged to the Partnership by changing the calculation of the fee from the fixed monthly amount referenced above to a variable monthly amount calculated in accordance with the standard RELP overhead allocation method used to charge overhead to other affiliated partnerships. The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. During the years ended December 31, 2013, 2012, and 2011, RELP received administrative fees totaling $489,183, $567,424, and $896,880, respectively. Administrative fees are included in general and administrative expense in the financial statements. RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or by third parties, but excluding direct costs and operating costs.
RELP processes joint interest billings and revenues on behalf of the Partnership. At December 31, 2013 and 2012, RELP owed the Partnership $509,271 and $633,900, respectively, for net revenues processed in excess of net joint interest and technical and administrative service charges. The cash associated with net revenues processed by RELP is normally received by RELP from oil and gas purchasers 30-60 days after the end of the month.
Compensation Committee
Because the Partnership has no directors, it does not have a compensation committee.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The following table sets forth information as of December 31, 2013 concerning all persons known by Reef to own beneficially more than 5% of the interests in the Partnership. Unless expressly indicated otherwise, each partner exercises sole voting and investment power with respect to the units beneficially owned.
(1) Reef Oil & Gas Partners, L.P.’s address is 1901 N. Central Expressway, Suite 300, Richardson, Texas 75080.
Reef, as managing general partner, received a 10% general partner interest in the Partnership as compensation for forming the Partnership. This interest is not represented by Partnership units. Reef also acquired a 1% general partner interest as a result of purchasing 1% of total Partnership units (8.9697 units). The units purchased by investor partners represent an 89% interest in the Partnership. Effective October 1, 2013, Reef purchased 0.60 units of limited partner interest from an investor partner, representing .067% of outstanding investor partner units. Michael J. Mauceli has voting and investment powers over Reef. There are no arrangements whereby Reef has the
right to acquire additional units within sixty days from options, warrants, rights, conversion privileges, or similar obligations.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The Partnership is managed by a managing general partner and does not have directors. Reef is the managing general partner of the Partnership. Along with its affiliates, Reef has entered into agreements with, and received compensation from, the Partnership for services it performs for the Partnership. See “Item 11 - Executive Compensation.”
In January 2011, the Partnership sold a portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P., a Reef affiliate. In June 2011, the Partnership sold an additional portion of its interests in the Thums Long Beach Unit to the same affiliate. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. The Partnership received $350,000 in cash in exchange for the interests sold in January and $2,650,000 for the interests sold in June. The Partnership recorded no gain or loss associated with this transaction.
In September 2012, the Partnership sold leasehold interests related to a three well drilling program proposed by a third party operator to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate (“purchaser”). The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and the Partnership would have needed to retain cash flow from producing properties and forego distributions to partners for several months in order to fund this drilling project. The leasehold acreage sold also included one productive working interest well and twelve productive royalty interest wells that currently produce oil and gas from different geologic zones than the zone to be tested in the three new drilled wells. The Partnership recorded $138,973 as accounts receivable from affiliates at September 30, 2012 related to this transaction. During 2012, Reef 2012-A paid $93,451 to the Partnership in connection with this sale, and the Partnership had a receivable of $45,522 at December 31, 2012. The purchase and sale agreement called for the Partnership to receive an amount equal to the value of the first drilled well, based upon a 12 percent per year discount factor (“PV12%”) from a third party engineering report prepared at year-end 2012 in accordance with SEC regulations. This report was received during 2013 and the sales price was adjusted from $138,973 to $201,573. The Partnership received the $45,522 account receivable, plus an additional payment of $62,600 from Reef 2012-A in 2013. The Partnership recorded no gain or loss related to this transaction.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
The Partnership incurred professional audit and tax fees from its principal accountant BDO USA, LLP, as disclosed in the table below:
As indicated in Item 10 above, the Partnership does not have any directors or an audit committee.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
1. Financial Statements
Report of Independent Registered Public Accounting Firm
Balance Sheets
Statements of Operations
Statements of Partnership Equity
Statements of Cash Flows
Notes to Financial Statements
2. Financial Statement Schedules
None
3. Exhibits
A list of the exhibits filed or furnished with this Annual Report (or incorporated by reference to exhibits previously filed or furnished by us) is provided in the Exhibit Index in this Annual Report. Those exhibits incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. Otherwise, the exhibits are filed herewith.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Michael J. Mauceli
Manager and Member of Reef Oil & Gas Partners, GP, LLC, the general partner of Reef Oil & Gas Partners, L.P., the Managing General Partner of the
March 31, 2014
Michael J. Mauceli
Partnership
(Principal Executive Officer)
/s/ Daniel C. Sibley
Chief Financial Officer and General Counsel of Reef Exploration, L.P.
March 31, 2014
Daniel C. Sibley
(Principal Financial and Accounting Officer)
EXHIBIT INDEX
The following documents are incorporated by reference in response to Item 15 (b).
Exhibit
Number
Description
3.1
Certificate of Formation of Reef Oil & Gas Income and Development Fund III, L.P. dated November 27, 2007(incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
4.1
Second Amendment and Restated Agreement of Limited Partnership of Reef Oil & Gas Income and Development Fund III, L.P., dated June 4, 2008 (incorporated by reference to Exhibit 4.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.1
Operating Agreement dated January 7, 2008, by and among Reef Exploration, L.P., Reef Oil & Gas Income and Development Fund III, L.P. and Davric Corporation (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.2
Operating Agreement dated May 1, 2008, by and among Reef Exploration, L.P., Reef Oil & Gas Income and Development Fund III, L.P. and Davric Corporation (incorporated by reference to Exhibit 10.2 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.3
Purchase and Sale Agreement dated January 7, 2008 by and among Sierra-Dean Production Company L.P., Reef Oil & Gas Income and Development Fund III, L.P., Reef Exploration L.P. and SPI Operations LLC, as amended on January 8, 2008 (incorporated by reference to Exhibit 10.3 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.4
Assignment, dated May 1, 2008, by and between Davric Corporation and Reef Oil & Gas Income and Development Fund III, L.P. (incorporated by reference to Exhibit 10.4 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.5
Crude Oil Contract, dated March 13, 2008, by and between Reef Exploration, L.P. and Occidental Energy Marketing, Inc., as amended by Amendment No. 1, dated June 24, 2008, by and between Reef Exploration, L.P. and Occidental Energy Marketing, Inc. (incorporated by reference to Exhibit 10.5 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.6
Consulting Agreement, dated September 1, 2006, by between Reef Exploration, L.P. and William R. Dixon (incorporated by reference to Exhibit 10.6 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.7
Casinghead Gas Sales Contract, dated January 1, 1978, by and between Amoco Production Company and Amoco Production Company (incorporated by reference to Exhibit 10.7 to the Partnership’s Registration Statement on Form 10, dated October 2, 2009).
10.8
Purchase and Sale Agreement, dated January 19, 2010, by and between Azalea Properties Ltd. And RCWI, LP. (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).
10.9
Purchase and Sale Agreement, dated January 19, 2010, by and between RCWI, L.P., and Reef Oil & Gas Income and Development Fund III, L.P. (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).
10.10
Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Post Closing PUDs (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).
10.11
Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Post Closing Properties/Title Defect Notice (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).
10.12
Side Letter Agreement, dated January 19, 2010 between RCWI, L.P. and Azalea Properties Ltd. Regarding Third Party Consents (incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, dated January 22, 2010).
10.13
Purchase and Sale Agreement by and between Lett Oil & Gas, L.P., as seller and RCWI, L.P., as buyer dated as of June 23, 2010 (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).
10.14
Assignment, Conveyance and Bill of Sale between Lett Oil & Gas, L.P. (“Assignor”) and Reef Oil & Gas Income and Development Fund III, L.P. (“Assignee”) executed June 30, 2010 and dated effective June 1, 2010 (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).
10.15
$50,000,000 Credit Agreement dated June 30, 2010 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.3 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).
10.16
Form of Security Agreement (General) dated June 30, 2010 by Reef Oil & Gas Income and Development Fund III, L.P., in favor of Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.4 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).
10.17
Promissory Note in the principal amount of up to $50,000,000 dated June 30, 2010 payable to Texas Capital Bank, N.A. (incorporated by reference to Exhibit 10.5 to the Partnership’s Current Report on Form 8-K, dated July 9, 2010).
10.18
Purchase and Sale Agreement, effective June 1, 2011, between the Partnership and Reef 2010 -A Income Fund, L.P. (incorporated by reference to Exhibit 10.2 to the Partnership’s Current Report on Form 8-K, dated June 24, 2011).
10.19
First Amendment to the Credit Agreement dated May 20, 2011 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated May 20, 2011).
10.20
Second Amendment to the Credit Agreement dated June 30, 2011 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K, dated June 24, 2011).
10.21
Third Amendment to the Credit Agreement dated April 30, 2013 between Reef Oil & Gas Income and Development Fund III, L.P., as borrower and Texas Capital Bank, N.A., as
* Filed herewith
Reef Oil & Gas Income and Development Fund III, L.P.
Financial Statements
Years Ended December 31, 2013, 2012, and 2011
Contents
Report of Independent Registered Public Accounting Firm
Audited Financial Statements
Balance sheets
Statements of operations
Statements of partnership equity
Statements of cash flows
Notes to financial statements
Report of Independent Registered Public Accounting Firm
Partners
Reef Oil & Gas Income and Development Fund III, L.P.
Richardson, TX
We have audited the accompanying balance sheets of Reef Oil & Gas Income and Development Fund III, L.P. (“the Partnership”) as of December 31, 2013 and 2012 and the related statements of operations, partnership equity, and cash flows for each of the three years in the period ended December 31, 2013. 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 audits 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 audits 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 also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Reef Oil & Gas Income and Development Fund III, L.P. at December 31, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America.
Reef Oil & Gas Partners Income and Development Fund III, L.P.
Balance Sheets
See accompanying notes to financial statements.
Reef Oil & Gas Partners Income and Development Fund III, L.P.
Statements of Operations
See accompanying notes to financial statements.
Reef Oil & Gas Partners Income and Development Fund III, L.P.
Statements of Partnership Equity
See accompanying notes to financial statements.
Reef Oil & Gas Partners Income and Development Fund III, L.P.
Statements of Cash Flows
See accompanying notes to financial statements.
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements
1. Organization and Basis of Presentation
Reef Oil & Gas Income and Development Fund III, L.P. (the “Partnership”) is a limited partnership formed under the laws of Texas on November 27, 2007. The Partnership was formed to purchase working interests in oil and gas properties with the purposes of (i) growing the value of properties through the development of proved undeveloped reserves, (ii) generating revenue from the production of crude oil and natural gas, (iii) distributing cash to the partners of the Partnership, and (iv) selling the properties no later than 2015, in order to maximize return to the partners of the Partnership. Reef Oil & Gas Partners, L.P. (“Reef”) is the managing general partner of the Partnership.
Units of limited and general partner interests in the Partnership were offered at $100,000 each (with a minimum investment of ¼ unit at $25,000 each) to accredited investors in a private placement pursuant to Section 4(2) of the Securities Act of 1933 and Regulation D promulgated there under, with a maximum offering amount of $90,000,000 (900 units). On June 12, 2008, the offering of units of limited and general partner interests in the Partnership was closed, with interests aggregating to $88,648,094 being sold to accredited investors, of which $48,984,933 were sold to accredited investors as units of general partner interest and $39,663,161 were sold to accredited investors as units of limited partner interest. As managing general partner, Reef contributed $762,425 (approximately one percent 1%) of the total contributions of the non-Reef general partners and limited partners) to the Partnership in exchange for 8.9697 units of general partner interest, resulting in a total capitalization of the Partnership of $89,410,519 before organization and offering costs.
Reef, as managing general partner, received a 10% general partner interest in the Partnership as compensation for forming the Partnership. This 10% interest is not represented by Partnership units. Reef also acquired a 1% general partner interest as a result of purchasing 1% of total Partnership units (8.9697 units). The purchase price paid by Reef for the units it purchased was net of the 15% management fee paid by investors. The units purchased by investor partners represented an 89% interest in the Partnership.
Under the terms of the partnership agreement, certain income and expense items are allocated differently between the managing general partner and the investor partners. Allocations of income and expense to the managing general partner and investor partners are made quarterly based upon the number and type of partnership units held at the end of the quarter.
Cash distributions to partners of the net cash flow from crude oil and natural gas sales, less operating, general and administrative, and other costs were distributed 11% to Reef and 89% to investor partners. During 2013, Reef purchased 0.60 units of limited partner interest from one of the investor partners (representing 0.067% of investor partner units). Thus, effective October 1, 2013 Reef also holds 0.067% of the 89% interest in the Partnership (0.060%) represented by the investor partner units, and receives 0.060% of the distributions paid to investor partners. At December 31, 2013, Reef has a total interest in the Partnership of 11.06%.
2. Summary of Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and judgments that affect the amounts reported in the financial statements and accompanying notes. The Partnership bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results could differ from these estimates and assumptions under different conditions. The more significant areas requiring the use of management’s estimates and judgments relate to the estimation of proved crude oil and natural gas reserves, the use of these crude oil and natural gas reserves in calculating depletion, depreciation, and amortization, the use of the estimates of future net revenues in computing ceiling test limitations, and estimates of future abandonment obligations used in recording asset retirement obligations.
Cash and Cash Equivalents
The Partnership considers all highly liquid investments with maturity dates of no more than three months from the
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Notes to Financial Statements (continued)
purchase date to be cash equivalents. Cash and cash equivalents consist of demand deposits and money market investments invested with a major national bank, which at times may exceed federally insured limits. The Partnership has not experienced any losses in such accounts, and does not expect any loss from this exposure. The carrying value of the Partnership’s cash equivalents approximates fair value.
Risks and Uncertainties
Historically, the oil and gas market has experienced significant price fluctuations. Prices are impacted by local weather, supply in the area, availability and price of competitive fuels, seasonal variations in local demand, limited transportation capacity to other regions, and the worldwide supply and demand for crude oil.
The Partnership has not engaged in commodity futures trading or hedging activities and has not entered into derivative financial instrument transactions for trading or other speculative purposes. Accordingly, the Partnership is at risk for the volatility in commodity prices inherent in the oil and gas industry, and the level of commodity prices has a significant impact on the Partnership’s results of operations.
Oil and Gas Properties
The Partnership follows the full cost method of accounting for its oil and gas activities. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method using estimated proved reserves. For these purposes, proved natural gas reserves are converted to barrels of oil equivalent (“BOE”) at a rate of 6 Mcf to 1 Bbl. Under the full cost method of accounting, sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless such disposition would significantly alter the relationship between capitalized costs and proved reserves.
In applying the full cost method, the Partnership is required to perform a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the sum of the estimated future net revenues from proved reserves using prices that are the preceding 12-month un-weighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, if any. If capitalized costs exceed the ceiling, an impairment loss is recognized for the amount by which the capitalized costs exceed the ceiling, and is shown as a reduction of oil and gas properties and as property impairment expense on the Partnership’s statements of operations. During the years ended December 31, 2013, 2012, and 2011, the Partnership recognized no property impairment expense of proved properties.
Unproved property consists of undrilled infill and offset acreage acquired in connection with the purchase of the Azalea Properties. Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date. The assessment includes consideration of the following factors, among others: intent to drill; remaining primary lease term; drilling results and activity in the immediate area of the property; the holding period of the property; and geological and geophysical evaluation. To the extent that the assessment indicates a property is impaired, the amount of impairment is added to the capitalized costs of oil and gas properties which are subject to the quarterly ceiling test. During the years ended December 31, 2013, 2012, and 2011, the Partnership recognized no property impairment of unproved properties.
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Notes to Financial Statements (continued)
The Partnership excludes from amortization the cost of unproved properties. The Partnership expects that all unproved property costs incurred will be transferred to proved property cost within 10 years of their acquisition. The following schedule shows, by the year in which they were incurred, the amount of all unproved property cost not currently being amortized as of December 31, 2013.
Estimates of Proved Oil and Gas Reserves
The estimates of the Partnership’s proved reserves at December 31, 2013, 2012, and 2011 have been prepared and presented in accordance with SEC rules and accounting standards which require SEC reporting entities to prepare their reserve estimates using pricing based upon the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and year end costs. Future prices and costs may be materially higher or lower than these prices and costs, which would impact the estimate of reserves and future cash flows. The Partnership’s proved reserve information included in this report was based upon evaluations prepared by independent petroleum engineers.
Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.
Reserves and their relation to estimated future net cash flows impact the Partnership’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. If proved reserve estimates decline, the rate at which depletion expense is recorded increases, reducing net income. A decline in estimated proved reserves and future cash flows also reduces the capitalized cost ceiling and may result in increased impairment expense.
Restoration, Removal, and Environmental Liabilities
The Partnership is subject to extensive Federal, state and local environmental laws and regulations. These laws 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 substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.
Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or reliably determinable.
The Partnership has recognized an estimated liability for future plugging and abandonment costs. A liability for the estimated fair value of the future plugging and abandonment costs is recorded with a corresponding increase in the full cost pool at the time a new well is drilled or acquired. Depreciation expense associated with estimated plugging and abandonment costs is recognized in accordance with the full cost methodology.
The Partnership estimates a liability for plugging and abandonment costs based on historical experience and estimated well life. The liability is discounted using the credit-adjusted risk-free rate. Revisions to the liability could occur due to changes in well plugging and abandonment costs or well useful lives, or if federal or state
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Notes to Financial Statements (continued)
regulators enact new well restoration requirements. The Partnership recognizes accretion expense in connection with the discounted liability over the remaining life of the well.
The following table summarizes the Partnership’s asset retirement obligation for the periods ended December 31, 2013 and 2012.
Recognition of Revenue
The Partnership has entered into sales contracts for disposition of its share of crude oil and natural gas production from productive wells. Revenue is recognized based upon the Partnership’s share of metered volumes delivered to its purchasers each month. The Partnership had no material gas imbalances at December 31, 2013, 2012, and 2011.
Income Taxes
The Partnership’s net income or loss flows directly through to its partners, who are responsible for the payment of Federal taxes on their respective share of any income or loss. Therefore, there is no provision for federal income taxes in the accompanying financial statements.
As of December 31, 2013, the tax basis of the Partnership’s assets exceeds the financial reporting basis of the assets by approximately $20.1 million, primarily due to the difference between property impairment costs deducted for financial reporting purposes and intangible drilling costs deducted for income tax purposes.
Accounting for Uncertainty in Income Taxes
The Financial Accounting Standards Board (“FASB”) provides guidance on accounting for uncertainty in income taxes. This guidance is intended to clarify the accounting for uncertainty in income taxes recognized in a company’s financial statements and prescribes the recognition and measurement of a tax position taken or expected to be taken in a tax return. It also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure.
Under this guidance, evaluation of a tax position is a two-step process. The first step is to determine whether it is more-likely-than-not that a tax position will be sustained upon examination, including the resolution of any related appeals or litigation based on the technical merits of that position. The second step is to measure a tax position that meets the more-likely-than-not threshold to determine the amount of benefit to be recognized in the financial statements. A tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement.
Tax positions that previously failed to meet the more-likely-than-not recognition threshold should be recognized in the first subsequent period in which the threshold is met. Previously recognized tax positions that no longer meet the more-likely-than-not criteria should be de-recognized in the first subsequent reporting period in which the threshold is no longer met. Penalties and interest are classified as income tax expense.
Based on the Partnership’s assessment, there are no material uncertain tax positions as of December 31, 2013 and 2012. The Partnership is subject to examination of income tax filings in the U.S. and various state jurisdictions for the years ended December 31, 2013 and 2012. The Partnership has not been subjected to any audits by the Internal Revenue Service for these periods.
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Notes to Financial Statements (continued)
Fair Value of Financial Instruments
The estimated fair values for financial instruments have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable, accounts receivable from affiliates, and accounts payable approximates their carrying value due to their short-term nature. The fair market value of the Partnership’s long-term debt approximates the carrying value at December 31, 2013 and 2012, as it is subject to short-term floating interest rates that approximate the rates available to the Partnership for those periods, and is classified as Level 2 within the fair value hierarchy.
Comprehensive Income
Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Partnership has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the consolidated statements of operations equals comprehensive income.
3. Long-Term Debt
On June 30, 2010, the Partnership and Texas Capital Bank, N.A. (“TCB”) entered into a Credit Agreement (the “Credit Agreement”) with a $5,000,000 borrowing base, and a related promissory note and security agreement for purposes of funding an acquisition. The per annum interest rate is equal to the U.S. prime rate as published by the Wall Street Journal’s “Monday Rates” plus 0.5%, with a minimum interest rate of 5%, payable monthly. At December 31, 2013, the interest rate was 5.0%. The obligations of TCB to the Partnership under the Credit Agreement expire on June 30, 2015, at which point the promissory note matures, and any unpaid principal and interest becomes due and payable. The Credit Agreement is a reducing revolving credit facility, and is subject to semi-annual redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans. At December 31, 2013, the borrowing base and the current outstanding loan balance are $690,000, and the borrowing base reduces at a rate of $30,000 per month. Therefore, the Partnership has recognized $360,000 of the note payable balance due as a current liability on the accompanying balance sheet. The Partnership has no plans to request any additional borrowing or changes to the borrowing base, and does not expect to extend the term of the loan beyond its current expiration date of June 30, 2015. The principal and accrued interest thereon may generally be prepaid by the Partnership in whole or in part at any time and without premium or penalty.
The Partnership has paid TCB certain facility fees and engineering fees in connection with prior year redeterminations of the borrowing base. The Partnership is obligated to pay additional facility fees upon each determination of an increase in the borrowing base, and additional engineering fees if TCB’s internal engineers perform an engineering review of the collateral, or the actual fees and expenses of any third-party engineers retained by TCB to prepare an engineering report, payable at the time of a redetermination of the borrowing base. The Partnership has no plans to request a redetermination of the borrowing base. The fees paid in connection with prior borrowing base redeterminations have been capitalized by the Partnership as Deferred Financing Fees on the accompanying balance sheets, and are being amortized over the remaining term of the Credit Agreement.
The Credit Agreement is guaranteed by two Reef affiliated entities. Borrowings under the Credit Agreement are secured by a first priority lien on no less than 90% of the oil and gas properties utilized in determining the borrowing base, based on the net present value of the crude oil and natural gas to be produced from the oil and gas properties calculated using a discount rate of nine percent (9.00%) per annum.
On April 30, 2013, the Partnership entered into the Third Amendment to the Credit Agreement (“Third Amendment”), with TCB. The Third Amendment extended the final maturity date of the Credit Agreement and the obligations thereunder from June 30, 2013 to June 30, 2015. During May 2013, the Partnership paid TCB fees of $13,150 in connection with the Third Amendment. These fees, as well as attorney fees paid in connection with the Third Amendment, have been capitalized as Deferred Financing Fees on the accompanying balance sheet and are being amortized over the remaining term of the Credit Agreement.
The Credit Agreement contains various covenants, including among others:
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Notes to Financial Statements (continued)
· restrictions on liens;
· restrictions on incurring other indebtedness without the lenders’ consent;
· restrictions on distributions and other restricted payments;
· maintenance of a current ratio as of the end of each fiscal quarter of not less than 1.0 to 1.0, as adjusted; and
· maintenance of an interest coverage ratio of cash flow to fixed charges as of the end of each fiscal quarter, to be at least 3.0 to 1.0.
All outstanding amounts owed under the Credit Agreement become due and payable upon the occurrence of certain usual and customary events of default, including among others:
· failure to make payments under the Credit Agreement;
· non-performance of covenants and obligations continuing beyond any applicable grace period; and
· the occurrence of a “Change in Control” (as defined in the Credit Agreement).
At December 31, 2013, the Partnership was not in compliance with a requirement of the Credit Agreement to deposit all Partnership revenues directly into a Partnership bank account maintained at the lender. A waiver of this requirement has been obtained.
4. Transactions with Affiliates
Reef purchased 1% of the Partnership units, and received an additional 10% general partner interest as compensation for forming the Partnership. This 10% interest is “carried” by the Investor Partners and Reef pays no drilling or completion expenses for this interest. Cash distributions to partners of the net cash flow from crude oil and natural gas sales revenues, less operating, general and administrative, and other costs were distributed 11% to Reef and 89% to investor partners. In addition, effective October 1, 2013, as a result of Reef’s purchase of 0.60 units of limited partner interest from an investor, Reef receives 0.067% of the 89% interest in the Partnership (0.060%) represented by the investor partner units. During the years ended December 31, 2013, 2012 and 2011, Reef received $75,112, $72,085, and $107,464, respectively, in cash distributions related to its 11% interest, and received $142 during the year ended December 31, 2013 related to its units of limited partner interest. From funds generated by its carried interest and management fee, Reef paid to specific FINRA-licensed broker-dealers a monthly fee in the amount equal to the maximum of the economic equivalent of a 3% carried interest in the Partnership as additional compensation for the sale of units. This was recorded as a commission expense by Reef.
Reef Exploration, L.P. (“RELP”), an affiliate of Reef, the managing general partner of the Partnership, receives drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership for wells operated by RELP. RELP also receives drilling compensation in an amount equal to 5% of the total well costs paid by the Partnership for non-operated wells. Total well costs include all drilling and equipment costs, including intangible development costs, surface facilities, and costs of pipelines necessary to connect the well to the nearest delivery point. In addition, total well costs also include the costs of all developmental activities on a well, such as reworking, working over, deepening, sidetracking, fracturing a producing well, installing pipeline for a well or any other activity incident to the operations of a well, excluding ordinary well operating costs after completion. Total well costs do not include costs relating to lease acquisitions. During the years ended December 31, 2013, 2012 and 2011, RELP received $25,602, $39,856, and $54,005, respectively, in drilling compensation. Drilling compensation payments are included in oil and gas properties in the financial statements.
Additionally, Reef and its affiliates are reimbursed for direct costs and all documented out-of-pocket expenses incurred on behalf of the Partnership. During the year ended December 31, 2013, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $102,762 and $1,551, respectively.
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Notes to Financial Statements (continued)
During the year ended December 31, 2012, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $171,800 and $1,302, respectively. During the year ended December 31, 2011, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $342,271 and $2,818, respectively.
Prior to January 1, 2012, RELP received an administrative fee to cover all general and administrative costs in an amount equal to 1/12th of 1% of all capital raised payable monthly, totaling $74,740 per month. During the first quarter of 2012, Reef reduced the amount of the monthly administrative fee charged to the Partnership by changing the calculation of the fee from the fixed monthly amount referenced above to a variable monthly amount calculated in accordance with the standard RELP overhead allocation method used to charge overhead to other affiliated partnerships. The allocation of RELP’s overhead to partnerships is based upon several factors, including the level of drilling activity, revenues, and capital and operating expenditures of each partnership compared to the total levels of all partnerships. During the years ended December 31, 2013, 2012, and 2011, RELP received administrative fees totaling $489,183, $567,424, and $896,880, respectively. Administrative fees are included in general and administrative expense in the accompanying condensed statements of operations. RELP’s general and administrative costs include all customary and routine expenses, accounting, office rent, telephone, secretarial, salaries and other incidental expenses incurred by RELP or its affiliates that are necessary to the conduct of the Partnership’s business, whether generated by RELP, its affiliates or by third parties, but excluding direct costs and operating costs.
RELP processes joint interest billings and revenues on behalf of the Partnership. At December 31, 2013 and 2012, RELP owed the Partnership $509,271 and $633,900, respectively, for net revenues processed in excess of net joint interest and technical and administrative service charges. The cash associated with net revenues processed by RELP is normally received by RELP from oil and gas purchasers 30-60 days after the end of the month.
In January 2011, the Partnership sold a portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P., a Reef affiliate. The Thums Long Beach Unit is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. The Partnership received $350,000 in cash in exchange for these interests. In June 2011, the Partnership sold an additional portion of its interests in the Thums Long Beach Unit to Reef Oil & Gas 2010-A Income Fund, L.P. The Partnership received $2,650,000 in cash in exchange for these additional interests. These sales transactions reduced the full cost pool of capitalized oil and gas properties. The Partnership recorded no gain or loss associated with these transactions.
In September 2012, the Partnership sold leasehold interests related to a three well drilling program proposed by a third party operator to Reef 2012-A Private Drilling Fund, L.P., a Reef affiliate (“purchaser”). The estimated drilling cost of the three proposed wells to the Partnership was in excess of $450,000, and the Partnership would have needed to retain cash flow from producing properties and forego distributions to partners for several months in order to fund this drilling project. The leasehold acreage sold also included one productive working interest well and twelve productive royalty interest wells that currently produce oil and gas from different geologic zones than the zone to be tested in the three new drilled wells. The Partnership recorded $138,973 as accounts receivable from affiliates at September 30, 2012 related to this transaction. During 2012, Reef 2012-A paid $93,451 to the Partnership in connection with this sale, and the Partnership had a receivable of $45,522 at December 31, 2012. The purchase and sale agreement called for the Partnership to receive an amount equal to the value of the first drilled well, based upon a 12 percent per year discount factor (“PV12%”) from a third party engineering report prepared at year-end 2012 in accordance with SEC regulations. This report was received during 2013 and the sales price was adjusted from $138,973 to $201,573. The Partnership received the $45,522 account receivable, plus an additional payment of $62,600 from Reef 2012-A in 2013. The Partnership recorded no gain or loss related to this transaction.
5. Major Customers
The Partnership sells crude oil and natural gas on credit terms to refiners, pipelines, marketers, and other users of petroleum commodities. Revenues are received directly from these parties or, in certain circumstances, paid to the operator of the property who disburses to the Partnership its percentage share of the revenues. During the year ended December 31, 2013, one marketer and one operator accounted for 38.0% and 32.8% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2012, one marketer and one operator accounted for 34.6% and 26.8% of the Partnership’s
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Notes to Financial Statements (continued)
crude oil and natural gas revenues, respectively. During the year ended December 31, 2011, one marketer and one operator accounted for 34.9% and 29.4% of the Partnership’s crude oil and natural gas revenues, respectively. Due to the competitive nature of the market for purchase of crude oil and natural gas, the Partnership does not believe that the loss of any particular purchaser would have a material adverse impact on the Partnership.
6. Commitments and Contingencies
The Partnership is not currently involved in any legal proceedings.
The Partnership entered into a consulting agreement with William R. Dixon d/b/a DXN Associates whereby the Partnership agreed to assign a one percent (1%) overriding royalty interest, proportionately reduced to the Partnership’s working interest, to William R. Dixon in exchange for Dixon’s agreement to “review and evaluate exploration, exploitation, and development drilling opportunities.” This overriding royalty interest burdens the Partnership’s working interest in the Slaughter Dean wells. During the years ended December 31, 2013, 2012, and 2011, William R. Dixon received $17,147, $23,819, and $21,914, respectively, related to this overriding royalty interest.
7. Partnership Equity
Information regarding the number of units outstanding and the net income (loss) per type of Partnership unit for the years ended December 31, 2013, 2012 and 2011 is detailed below:
For the year ended December 31, 2013
For the year ended December 31, 2012
For the year ended December 31, 2011
8. Supplemental Information on Oil & Natural Gas Exploration and Production Activities (unaudited)
Capitalized Costs
The following table presents the Partnership’s aggregate capitalized costs relating to oil and gas activities at the end
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Notes to Financial Statements (continued)
of the periods indicated:
Costs Incurred
The following table sets forth the costs incurred in oil and gas exploration and development activities during the years ended December 31, 2013, 2012, and 2011.
Results of Operations
The following table sets forth the other results of operations from oil and gas producing activities for the years ended December 31, 2013, 2012 and 2011
BOE = Barrels of Oil Equivalent (6 MCF equals 1 BOE)
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Notes to Financial Statements (continued)
Crude Oil and Natural Gas Reserves
Net Proved Reserve Summary
The reserve information presented below is based upon estimates of net proved oil and gas reserves that were prepared by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2013, 2012 and 2011. All of the Partnership’s reserves are located in the United States.
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 in future years from known reservoirs under existing economic conditions, operating methods and governmental regulations (i.e. prices and costs as of the date the estimate is made). The project to extract the hydrocarbons must have commenced or the interest owner must be reasonably certain that it will commence within a reasonable period of time. At December 31, 2013, 99.83% of the Partnership’s proved reserves are classified as proved developed reserves, and 0.17% are classified as proved undeveloped reserves. At December 31, 2013, future development costs were estimated to be approximately $23,970 in connection with the Partnership’s proved developed non-producing and proved undeveloped reserves. At December 31, 2012 and 2011, all of the Partnership’s reserves were classified as proved developed reserves.
Reservoir engineering, which is the process of estimating quantities of crude oil and natural gas reserves, is complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering, and economic data for each reservoir. These estimates are dependent upon many variables, and changes occur as knowledge of these variables evolves. Therefore, these estimates are inherently imprecise, and are subject to considerable upward or downward adjustments. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and such variances could be material. In addition, reserve estimates for properties which have not yet been drilled, or properties with a limited production history may be less reliable than estimates for properties with longer production histories.
The following information table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, 2013, 2012 and 2011.
(1) Oil includes both oil and natural gas liquids
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Notes to Financial Statements (continued)
(2) BOE (barrels of oil equivalent) is calculated by converting 6 MCF of natural gas to 1 BBL of oil. A BBL (barrel) of oil is one stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.
Standardized Measure of Discounted Future Net Cash Flows
Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Partnership believes such information is essential for a proper understanding and assessment of the data presented.
For the years ended December 31, 2013, 2012, and 2011, calculations were made using average prices of $96.90, $94.68, and $95.84 per barrel of crude oil, respectively, and $3.67, $2.76, and $4.15 per MCF of natural gas, respectively. Prices and costs are held constant for the life of the wells; however, prices are adjusted by well in accordance with sales contracts, energy content quality, transportation, compression and gathering fees, and regional price differentials.
These assumptions used to compute the standardized measure are those prescribed by the FASB and the SEC, and do not necessarily reflect Reef’s expectations of the Partnership’s actual net cash flow to be derived from those reserves, nor the present worth of the properties. Further, actual future net cash flows will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas, and changes in governmental regulations and tax rates. Sales prices of both crude oil and natural gas have fluctuated significantly in recent years. Reef, as managing general partner, does not rely upon the following information in making investment and operating decisions for the Partnership.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.
A 10% annual discount rate is used to reflect the timing of the future net cash flows relating to proved reserves.
The standardized measure of discounted future net cash flows as of December 31, 2013, 2012 and 2011 were as follows:
Changes in the Standardized Measure of Discounted Future Net Cash flows Relating to Proved Crude Oil and Natural Gas Reserves were as follows for the years indicated:
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Notes to Financial Statements (continued)