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, subject to certain market conditions, no earlier than 2010, but expected no later than 2015, in order to maximize return to the partners of the Partnership. The term of the Partnership commenced on the effective date and continues until December 31, 2016, unless terminated sooner. 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. Between November 27, 2007 and June 30, 2010, the Partnership made three major property acquisitions with the capital raised by the Partnership. These three acquisitions are referred to in this Annual Report as the Slaughter Dean acquisition, the Azalea acquisition, and the Lett acquisition (See ITEM 2 - PROPERTIES). On all properties purchased, the Partnership planned 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 served as operator of the wells acquired in the Slaughter Dean acquisition prior to their sale during the second quarter of 2015. 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. The Partnership operates in only one industry segment, which is the exploration, development and production of oil, condensate, natural gas and natural gas liquids (“NGL’s”) in the United States.
While one of the original objectives of the Partnership was the sale of properties no later than 2015 in order to maximize return to the investor partners, Reef decided to delay any attempt to sell the properties acquired in the Azalea and Lett acquisitions as of December 31, 2014 as a result of the decline in crude oil prices that began during the third quarter of 2014. The Partnership was focused upon selling the properties acquired in the Slaughter Dean acquisition because they were operating at a deficit due to high operating and workover costs. The Partnership was successful in selling the Slaughter Dean acquisition properties during the second quarter of 2015.
However, as the decline in commodity prices continued into the third quarter of 2015, the Partnership saw its results of operations, financial position, and cash flows being severely adversely affected. The Partnership is not engaged in
commodity futures trading or hedging activities, and does not have significant cash reserves on hand, since cash flows are normally distributed on a regular basis to the investor partners. During the first two quarters of 2015 working capital was being drained because the Slaughter Dean acquisition properties were being operated at a deficit. During the third quarter of 2015, lease operating costs, production taxes, and general and administrative expenses of the remaining Azalea and Lett acquisition properties exceeded revenues. Without a recovery in commodity prices, Reef believes the Partnership must either borrow funds from Reef or sell properties to generate cash to cover the deficits. As Reef is unable to project when or if commodity prices will recover, a decision was made in October 2015 to begin marketing the remaining assets of the Partnership. Several property sales were consummated during the fourth quarter of 2015, and Reef expects to complete the divestiture of all of the Partnership’s oil and gas properties, wind up, and terminate the Partnership during 2016.
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, 2015, one marketer and one operator accounted for 44.3% and 18.2% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2014, the same marketer and operator accounted for 37.5% and 36.0% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2013, the same marketer and operator accounted for 38.0% and 32.6% of the Partnership’s crude oil and natural gas revenues, respectively. Nevertheless, 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. 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. Prior to August 2015, Reef maintained 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 public liability insurance no less than $10,000,000. As a result of the sale of all Partnership properties operated by RELP on behalf of the Partnership during the second quarter of 2015, as well as the cessation of drilling activities of the Partnership, the Partnership now maintains public liability insurance of $2,000,000 and umbrella liability insurance of $25,000,000 effective August 1, 2015.
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 are currently 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, if appropriate and necessary for the Partnership’s operations;
· 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 $1,000,000;
· Automobile public liability insurance with a limit of $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 vertically drilled land wells and $15,000,000 for horizontally drilled land wells; and
· Umbrella liability insurance (excess of the General liability, Employer’s liability and Automobile liability insurance) with a limit of $25,000,000.
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, limitations or prohibitions against hydraulic fracturing of wells, 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. Local, state, and national regulatory bodies are increasingly focused on greenhouse gas (“GHG”) emissions as contributing to climate change. The United States Environmental Protection Agency (“EPA”) has issued a ruling requiring annual reporting of GHG emissions, and it is possible that GHG emissions may be classified as pollutants regulated under the federal Clean Air Act.
In December 2015, the United States was a participant in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change held in Paris, France. The “Paris Agreement” adopted at that conference calls for nations to undertake efforts with respect to global temperatures and GHG emissions. If this agreement is ratified by the Congress of the United States, it will take effect in the year 2020.
While it is not possible at this time to predict how legislation or new regulations or treaties that may be adopted to address GHG emissions would impact the Partnership, any such future laws and regulations that require reporting of GHG’s or limit emissions of GHG’s from oil and gas operations could require expenditure of funds to reduce such emissions, or, by affecting the demand for refined petroleum products, could affect demand for oil and gas produced from Partnership wells.
Employees
The Partnership has no employees, and is managed by the managing general partner, Reef. RELP provides technical and administrative services necessary to the conduct of the Partnership’s business. 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 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 timing and sale of Partnership properties, 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. Should any one or more of these or other risks or uncertainties materialize or should any underlying assumptions prove incorrect, actual results are likely to vary materially from those described herein. All forward looking statements speak as of the filing date of this Annual Report. All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. Reef does not intend to update its forward-looking statements, except as otherwise required by applicable law. All subsequent written and oral forward-looking statements attributable to Reef or persons acting on its behalf are expressly qualified in their entirety by the applicable cautionary statements.
ITEM 1A.
ITEM 1A. RISK FACTORS
The Partnership is a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act, and as such, is not required to provide the information required under this Item.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Property Acquisition, Development Activities and Divestiture of Certain Properties
Slaughter Dean Acquisition
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. These wells were located in the Slaughter Field in Cochran County, Texas. Reef implemented a waterflood development plan on a portion of the Dean “B” Unit (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. While the waterflood development activity temporarily reduced the rate of decline in oil production, the desired increase in oil production rates did not materialize.
The Partnership sold all of the properties acquired in the Slaughter Dean acquisition during the second quarter of 2015. The Slaughter Dean acquisition properties were operated by RELP on behalf of the Partnership, and were the only RELP operated properties owned by the Partnership.
Azalea Acquisition
In January 2010, the Partnership acquired from RCWI, L.P. (“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 properties (the “Azalea Properties”) 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 largest property purchased in the Azalea acquisition was an interest in the Thums Long Beach Unit (“Thums Unit”), which is a long-lived waterflood project in the Wilmington Field, located underneath the Long Beach Harbor in southern California. Thums Long Beach derived its name from the property’s original shareholders, Texaco, Humble, Union, Mobil and Shell.
During the fourth quarter of 2015, the Partnership sold its working interest in the Thums Unit that it had acquired in the Azalea Properties acquisition, and during the third and fourth quarters made eight additional sales of various wells from the Azalea acquisition properties.
Lett Acquisition
In June 2010, the Partnership acquired from RCWI, at cost, certain working interests (the “Lett Properties”) acquired by RCWI from Lett Oil & Gas, L.P. The Lett Properties consisted of additional working interests in the Thums Unit. The acquired working interests are all minority non-operated interests. The Thums Unit is operated by a third party not affiliated with the Partnership or Reef.
During the fourth quarter of 2015, the Partnership sold its working interest in the Thums Unit that it had acquired in the Lett Properties acquisition.
Properties Owned at December 31, 2015
The sales during 2015 of the Slaughter Dean acquisition properties, the working interests in the Thums Unit that were acquired in connection with the Azalea Acquisition and Lett Acquisition, and other properties acquired in the Azalea Acquisition represented 87.3% of the Partnership’s oil reserves and 25.1% of the Partnership’s natural gas reserves based upon reserve quantities stated in the Partnership’s December 31, 2014 reserve report. At December 31, 2015 the Partnership owns working interests in more than 600 wells acquired in the Azalea Acquisition, located in Texas, New Mexico, Louisiana, Oklahoma, North Dakota, Mississippi, Alabama, Kansas, Montana, Colorado and Arkansas.
Property Sales
The Partnership sold the Slaughter Dean acquisition properties during the second quarter of 2015 to Red Sea 2012, Inc. for a purchase price of $700,000, less fees paid of $5,765, subject to certain revenue and cost adjustments retroactive to the effective sale date of December 1, 2014. In accordance with the full cost methodology, the Partnership recorded a gain on sale totaling $1,673,100 related to this sale. During the fourth quarter of 2015, the Partnership wrote off the account receivable totaling $181,610 it had recorded related to the certain revenue and cost adjustments retroactive to the effective date of sale of December 1, 2014 as a bad debt expense, as RELP has been unsuccessful in recovering these funds from the purchaser.
During the second quarter of 2015, the Partnership sold its working interest in a well drilled upon acreage acquired as a part of the Azalea acquisition for a purchase price of $84,332. In accordance with the full cost method of accounting, the Partnership did not record any gain or loss associated with this sale.
During the fourth quarter of 2015, the Partnership and Reef Oil & Gas Income and Development Fund II, L.P., an affiliate of the Partnership, sold their interest in the Thums Unit to the operator, California Resources Long Beach Inc. for a purchase price totaling $1,000,000. Sales proceeds allocated to the interest owned by the Partnership were $940,371. In accordance with the full cost methodology, the Partnership recorded a loss on sale totaling $2,405,410 related to this sale.
During the third and fourth quarters of 2015, the Partnership consummated eight property sales involving properties acquired as a part of its Azalea acquisition in 2010. Collectively, the Partnership received sales proceeds totaling
$47,483 for these eight property sales. In accordance with the full cost method of accounting, the Partnership did not record any gain or loss associated with these eight sales transactions.
During the second quarter of 2014, the Partnership sold its interest in several oil and gas wells acquired as a part of the Azalea acquisition for approximately $135,000. The estimated discounted future cash flows included in the Partnership’s 2013 reserve report for these wells was less than $45,000. The operator of the properties notified the Partnership of their intent to form a waterflood unit to be implemented in three phases. The cost of the initial phase, net to the working interest owned by the Partnership, was approximately $351,500, and would have required the Partnership to pay these capital costs, plus costs associated with Phases 2 and 3, from current cash flows instead of distributing those cash flows to investors. In accordance with the full cost method of accounting, the Partnership did not record any gain or loss related to this transaction.
The Partnership does not expect to purchase interests in any additional properties, nor does it expect to participate in the drilling of any new wells, should proposals from operators to drill additional wells on the infill and offset acreage acquired in connection with the Azalea acquisition be received.
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. 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 reserve information presented below is based upon estimates of net proved reserves that were prepared by the senior reservoir engineer for RELP as of December 31, 2015, and by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2014 and 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, 2015, 2014, and 2013 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, 2015, 2014, and 2013 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, 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, 2015, 2014, and 2013, the Partnership recognized property impairment costs of proved properties totaling $5,432,366, $1,841,274, and $0, respectively.
During 2014, gas reserve estimates on the Dean B Unit were adjusted downward by approximately 60,000 Mcf, due to an increase in the decline rate of natural gas production form the lease, and adjustments to various Azalea Properties totaled approximately 96,000 Mcf. During 2015, the oil and gas reserves sold by the Partnership, as
measured by the proved reserves shown in the 2014 reserve report, totaled 459,910 Bbl and 164,990 Mcf. The additional reductions in reserve volumes are primarily attributable to lower commodity prices during 2015.
Qualifications of Technical Persons and Internal Controls Over the Reserves Estimation Process
The Partnership used Mr. Jerald Sluder, RELP’s Senior Reservoir Engineer to prepare its December 31, 2015 estimates of net proved crude oil and natural gas reserves.
The Partnership used an independent petroleum engineering firm, Forrest A. Garb & Associates, Inc., (“FGA”) of Dallas, Texas, to prepare its December 31, 2014 and 2013 estimates of net proved crude oil and natural gas reserves. FGA estimated reserves for all of our properties as of December 31, 2014 and 2013. 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.
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 petroleum engineer. 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 were prepared by Jerald Sluder, RELP’s Senior Reservoir Engineer, and by FGA. Our technical staff and members of our accounting department met regularly with Mr. Sluder and 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, was 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 twenty-one 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 certain Azalea Properties is held in the name of the Partnership. Under the purchase agreement with RCWI relating to the Azalea acquisition, title to certain 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
Units and Holders
As of March 30, 2016, the Partnership had one managing general partner, 818 non-Reef general partners, and 671 non-Reef limited partners. Reef holds a total of 9.2197 general partner units and 1.0500 limited partner units, and the non-Reef partners hold 490.2327 general partner units and 395.4672 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.
Investor 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.
Distributions
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 initially distributed 11% to Reef and 89% to investor partners. Effective October 1, 2013, Reef purchased 0.60 units of limited partner interest from one of the Partnership’s investor partners. As such, effective October 1, 2013, Reef received 11.06% and investor partners received 88.94% of total cash distributions. During 2015, Reef purchased 0.45 units of limited partner interest and 0.25 units of general partner interest from investor partners. As such, effective September 1, 2015 Reef receives 11.13% and investor partners receive 88.87% of total cash distributions. Total cash distributions paid during 2015, 2014, and 2013 were $17,654, $170,871, and $682,835, respectively.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The Partnership is a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act, and as such, is not required to provide the information required under this Item.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to 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.
Going Concern
Management is currently pursuing the sale of all Partnership assets with the intent to wind up and terminate the Partnership during 2016. As a result, the Partnership is not expected to continue as a going concern. The financial statements included with this Annual Report do not include any adjustments that might result from the outcome of this uncertainty.
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 reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership 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.
Oil and Gas Properties
The Partnership follows the full cost method of accounting for oil and gas properties. 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 thousand cubic feet (“Mcf”) of natural gas to 1 barrel (“Bbl”) of crude oil. 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. During 2015, the Partnership recorded gain or loss in connection with two of its property sales. During the second quarter of 2015, the Partnership recognized a gain of $1,673,100 in connection with the sale of the Slaughter Dean acquisition properties in Cochran County, Texas. During the fourth quarter of 2015, the Partnership recognized a loss of $2,405,410 in connection with the sale of its interest in the Thums Unit located in the Wilmington Field underneath the Long Beach Harbor in southern California.
In applying the full cost method, the Partnership performs 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 lower of unamortized cost or the cost ceiling, which is defined as the sum of the estimated future net revenues from the Partnership’s 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, 2015, 2014, and 2013, the Partnership recognized property impairment costs of proved properties totaling $5,432,366, $1,841,274, and $0, respectively.
Unproved property consists of undrilled infill and offset acreage acquired in connection with the Azalea acquisition in 2010. Investments in unproved property are not subject to depletion until they are either impaired or developed. Unproved property is assessed for impairment quarterly as of the balance sheet date. In determining whether an
unproved property is impaired, the Partnership considers numerous factors including, but not limited to, the following items: intent to drill; remaining primary lease term; drilling results and activity in the immediate area of the property; the holding period of the property, geological and geophysical evaluation and current market conditions. To the extent that the assessment indicates a property is impaired, the impairment amount is re-classed from unproved property to the proved property full cost pool and subjected to depletion and the quarterly full cost ceiling test. After considering the holding period of the Azalea acquisition unproved properties as well as current market conditions at December 31, 2014, the Partnership impaired all of its remaining unproved property totaling $361,865 during the fourth quarter of 2014. This amount was re-classed from unproved property to the proved property full cost pool and subjected to depletion and the full cost ceiling test at December 31, 2014. During the year ended December 31, 2013, the Partnership recognized no impairment of unproved property.
Estimates of Proved Oil and Gas Reserves
The estimates of the Partnership’s proved reserves at December 31, 2015, 2014, and 2013 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 the senior reservoir engineer for RELP at December 31, 2015, and by FGA, an independent petroleum engineering firm, at December 31, 2014 and 2013.
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 future net income. A decline in estimated proved reserves and future cash flows, whether caused by declining commodity prices or downward adjustments to the rate of production from Partnership wells, 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.
The following table summarizes the Partnership’s asset retirement obligation for the years ended December 31, 2015 and 2014.
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. Any significant over or under balanced gas positions are disclosed in the financial statements. As of December 31, 2015, 2014 and 2013, the Partnership had no material gas imbalance positions.
Recent Accounting Developments - Revenue Recognition
The following recently issued accounting pronouncement has been adopted or may impact the Partnership in future periods:
The Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) in May 2014 which provides accounting guidance for all revenues arising from contracts to provide goods or services to customers. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following five steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract(s); (5) recognize revenue when (or as) the entity satisfies a performance obligation. The requirements from the new ASU will supersede prior revenue recognition requirements and most prior industry-specific guidance throughout the FASB’s ASC, and will be effective for all interim and annual periods beginning after December 15, 2017. The Partnership is still considering the method of adoption but does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flow.
Outlook
The oil and gas industry began experiencing decreases in and sustained depression of commodity prices during the third quarter of 2014, and these decreases continued throughout 2015 and into the first quarter of 2016. The severely depressed commodity prices are believed to be driven by a global supply/demand imbalance for crude oil and an oversupply of natural gas in the United States. Commodity prices are the most significant factor impacting the revenues, profitability, operating cash flows, and working capital of the Partnership. Reef is unable to predict what changes may occur in commodity prices, when such changes may occur, and for what period of time such changes may be effective. Reef believes that both crude oil and natural gas prices will remain volatile for the foreseeable future.
The depressed level of commodity prices over the past five quarters has had a significant adverse effect upon the financial position, cash flows, and results of operations of the Partnership. The profitability of properties owned by the Partnership has deteriorated, and the Partnership has recorded significant proved property impairment expense totaling $1,841,274 during the fourth quarter of 2014 and $5,432,366 during 2015 as oil and gas reserves have been rendered uneconomic to produce in the current pricing environment.
During the first half of 2015, the Partnership’s Slaughter Dean acquisition properties operated at a deficit prior to being sold, and during the third quarter oil and gas revenues from the Partnership’s remaining oil and gas properties, while exceeding direct lease operating costs and production taxes, were unable to cover direct lease operating costs, production taxes, and general and administrative costs.
As a result of this continued depressed commodity price environment, Reef made a decision in October 2015 to begin marketing the remaining oil and gas properties owned by the Partnership, with a goal to complete the divestiture of all properties, wind up and terminate the Partnership during 2016.
Overview
Reef Oil & Gas Income and Development Fund III, L.P. is a Texas limited partnership formed in 2007. The primary stated objectives of the Partnership were 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, subject to certain market conditions, no earlier than 2010, but expected 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 the three groups of properties purchased by the Partnership (see ITEM 2 - Properties), the Partnership has produced existing proved reserves and worked to develop proved undeveloped reserves, but has not engaged in exploratory drilling for unproved reserves on leasehold acreage purchased by the Partnership deemed to contain unproved drilling locations. Drilling locations with unproved reserves, if any, have been farmed out or sold to third parties or other partnerships formed by Reef. Prior to the fourth quarter of 2015, the Partnership evaluated, 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 agreed to participate or declined to participate in such additional drilling based upon its evaluations of such proposals. When the Partnership decided to participate in such developmental drilling, funds to drill were taken from current net cash flows that otherwise would have been available for distributions to investors.
In October 2015, Reef made a decision to market the remaining assets of the Partnership as a result of continuing depressed commodity prices. The Partnership does not expect to purchase interests in any additional properties, nor does it expect to participate in the drilling of any new wells, should proposals from operators to drill additional wells on the infill and offset acreage acquired in connection with the Azalea acquisition be received.
The Partnership expended all of the capital it raised on the Slaughter Dean, Azalea, and Lett acquisitions described in Item 2 - Properties, and upon developmental drilling opportunities on infill and offset acreage acquired in connection with the Azalea acquisition. Upon exhausting the capital raised by the Partnership, additional development drilling opportunities were funded using current net cash flows that otherwise would have been available for distribution to investors.
During 2015, the Partnership sold its interest in approximately 87.3% of its total oil reserves and 25.1% of its total gas reserves, as measured by the December 31, 2014 reserve report. The Thums Unit and the Slaughter Dean acquisition properties represented 65.2% and 21.7% of total December 31, 2014 oil reserves, respectively, and 2.3% and 12.6% of total December 31, 2014 gas reserves, respectively. As a result of these sales, Partnership oil and gas production subsequent to December 31, 2015 is expected to significantly decline.
The Partnership currently has no hedges in place, and therefore is subject to commodity price risk. While oil and gas sales revenues began declining during the third quarter of 2014, the full impact of the decline in prices was not felt until the last quarter of 2014 and beyond. The significant declines in prices for oil and gas have had a material effect on the Partnership’s financial condition, results of operations, cash flows, and quantities of reserves that are economically recoverable. The decline in commodity prices led to a decrease in proved reserves considered to be economically recoverable, resulting in impairment expense of proved properties totaling $1,841,274 during the fourth quarter of 2014 and $5,432,366 during 2015. The Partnership expects to recognize additional impairment of proved properties during the first quarter of 2016, since the quarterly reserves are calculated using the preceding 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices held constant and discounted at 10%, and it is expected that this average will decline from the average used to prepare the December 31, 2015 reserve estimates. If oil and gas prices remain depressed for a significant period of time, the Partnership may not be able to achieve its objective of selling Partnership properties on terms that provide a favorable return to investors.
Liquidity and Capital Resources
Capital Contributions
The Partnership was funded with initial capital contributions totaling $89,410,519 from both non-Reef partners and Reef. Non-Reef partners purchased 490.9827 units of general partner interest and 397.0172 units of limited partner interest for $88,648,094, 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. Reef contributed $762,425 for the purchase of 8.9697 units of general partner interest at a price of $85,000 per unit, which is net of the 15% management fee paid by non-Reef investors. The 15% management fee used to pay organization and offering costs, including sales commissions, totaled $13,168,094, leaving capital contributions of $76,242,425 available for Partnership activities. As of December 31, 2015, the Partnership had expended $81,369,543 on property acquisition and development costs. Expenditures in excess of available capital were financed through debt or property sales, or have been recovered from cash flows by reducing Partnership distributions.
Credit Agreement
On June 30, 2010, the Partnership and TCB entered into a Credit Agreement with a $5,000,000 borrowing base, and a related promissory note and security agreement for purposes of funding a property acquisition. The per annum interest rate was 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. The obligations of TCB to the Partnership under the Credit Agreement were to expire on June 30, 2015, at which point the promissory note was to mature, and any unpaid principal and interest would have become due and payable. The Credit Agreement was a reducing revolving credit facility, and was subject to semi-annual redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans.
The Partnership had the right to prepay promissory note principal and accrued interest thereon in whole or in part at any time without premium or penalty. During 2014, the Partnership made various pre-payments of principal on the promissory note, utilizing proceeds from property sales and current cash flows. The Partnership completed repayment of the promissory note balance during December 2014 and terminated the Credit Agreement with TCB on December 31, 2014.
The Partnership paid TCB certain facility fees and engineering fees in connection with prior year redeterminations of the borrowing base. The fees paid in connection with these prior borrowing base redeterminations were capitalized by the Partnership as Deferred Financing Fees and amortized over the term of the Credit Agreement.
Capital Expenditures
As of December 31, 2015, the Partnership had expended $81,369,543 on property acquisition and development costs. Expenditures in excess of available capital were financed through debt or property sales, or have been recovered from cash flows by reducing Partnership distributions. Expenditures in excess of available Partnership capital, which totaled $76,242,425, have been financed through debt or property sales, or have been recovered from cash flows by reducing Partnership distributions.
The Partnership had working capital of $1,640,865 at December 31, 2015, primarily as a result of property sales made during 2015. The Partnership distributed approximately $500,000 of property sales proceeds to investors during January 2016, but has maintained the remaining working capital to cover any deficits prior to its divestiture of all remaining properties during 2016. Subsequent to expending the initial available Partnership capital contributions on property acquisitions and development, the Partnership working capital consists primarily of cash flows from productive properties, which have been utilized to pay cash distributions to investors. Sources of future funding consist of cash on hand, cash flow from operations, if any, and cash received from the sale of the Partnership’s remaining properties. The Partnership has entered into three separate sales transactions subsequent to December 31, 2015 which have generated approximately $100,000 in sales proceeds to the Partnership. The Partnership may not be able to sell properties at the values desired in order to achieve its objective of selling Partnership properties on terms that provide a favorable return to investors.
Results of Operations
Year Ended December 31, 2015 compared to Year Ended December 31, 2014
The Partnership had a net loss of $7,296,413 for the year ended December 31, 2015, compared to a net loss of $2,493,870 for the year ended December 31, 2014. The increased loss is primarily the result of an increase in impairment of proved properties during the year ended December 31, 2015 as a result of continuing decreases in commodity prices. In addition, the Partnership incurred a net loss of $732,310 from property sales and saw its net revenues less lease operating expenses decrease from $1,625,594 in 2014 to $254,897 in 2015.
During the year ended December 31, 2015, the Partnership recognized impairment expense of $5,432,366. The impairment was the result of falling commodity prices throughout 2015, which decreased estimated future cash flows from Partnership properties and rendered some properties uneconomic to produce. During 2014, the Partnership recognized impairment expense of $1,841,274, all of which was incurred in the fourth quarter.
Partnership revenues totaled $4,234,581 and lease operating expenses totaled $2,608,987 for the year ended December 31, 2014, for a margin of $1,625,594. During the year ended 2015, Partnership revenues totaled $1,557,050 and lease operating expenses totaled $1,302,153, for a margin of $254,897. The 63.2% decrease in oil and gas revenues during 2015 was primarily attributable to the decrease in oil and gas sales prices during 2015. The average sales price for crude oil decreased by 45.1%, to an average price of $43.83 per Bbl for the year ended December 31, 2015 compared to an average price of $81.01 for the year ended December 31, 2014. Oil sales volumes also decreased during the year ended December 31, 2015 compared to the year ended December 31, 2014 by 15,518 Bbl, or approximately 32.6%. Oil sales volumes from the Partnership’s Slaughter Dean acquisition properties, which were sold during the second quarter of 2015, accounted for 12,430 Bbl of the 15,518 Bbl drop in sales volumes.
The Partnership has not and is currently not engaged in commodity futures trading, hedging activities, or derivative financial instrument transactions for trading or other speculative purposes. The Partnership sells substantially all 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.
Lease operating expenses decreased from $2,608,987 for the year ended December 31, 2014 to $1,302,153 for the year ended December 31, 2015, a decrease of $1,306,834, or 50.1%. Lease operating expenses from the Partnership’s Slaughter Dean acquisition properties, which were sold during the second quarter of 2015, declined from $1,628,357 during 2014 to $455,869 during the first six months of 2015, a decrease of $1,172,488, or 89.7% of the total decrease in lease operating expenses. The Slaughter Dean acquisition properties incurred high workover expenditures of $390,078 in 2014. During the first six months of 2015, the Partnership deferred workover costs by shutting in wells with mechanical failures, thus delaying workover costs. Lease operating expenses on the Thums Unit also decreased from $471,329 in 2014 to $390,591 in 2015. During the first six months of 2014 the Partnership experienced higher lease operating costs on the Thums Unit in connection with certain projects being performed by the lease operator.
General and administrative costs during the year ended December 31, 2015 decreased to $506,622 as compared to $635,685 incurred during the year ended December 31, 2014. The allocation of RELP’s overhead to the Partnership is a significant portion of general and administrative expenses. 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. The administrative overhead charged to the Partnership decreased from $431,793 during the year ended December 31, 2014 to $279,085 during the year ended December 31, 2015. This decrease was primarily incurred during the second half of 2015, as the sale of the Slaughter Dean acquisition properties reduced this Partnership’s activity levels compared to the activity levels of other Reef partnerships.
The Partnership incurred a loss on sale of oil and gas properties totaling $732,310 during 2015, compared to $0 during 2014. Under the full cost method of accounting, no gain or loss on disposition of oil and gas properties is recorded unless such disposition significantly alters the relationship between capitalized costs and proved reserves.
Because of the significant reduction in commodity prices during 2015, the property write-offs related to the Partnership’s two major sales were considered to materially affect this relationship, and as such, the partnership recorded gain/loss. During 2014 no gain/loss was required to be recorded in connection with the Partnership’s sale of properties.
Year Ended December 31, 2014 compared to Year Ended December 31, 2013
The Partnership had a net loss of $2,493,870 for the year ended December 31, 2014, compared to net income of $421,300 for the year ended December 31, 2013. The primary change in operating results is primarily due to impairment of proved properties during the year ended December 31, 2014. In addition, decreases in average sales prices for crude oil and increases in lease operating expenses contributed to the loss for the year ended December 31, 2014 as compared to the year ended December 31, 2013.
During the year ended December 31, 2014, the Partnership recognized impairment expense of $1,841,274. The impairment was primarily related to a change in the per barrel price received by the Partnership for oil production from the Thums Unit wells, which account for approximately 38.1% of the Partnerships total oil revenues. The per- barrel price received by the Partnership dropped from a premium of approximately $8 over current spot prices to a premium of approximately $2 over spot prices. This change in pricing reduced the future estimated net revenues expected from the property and led to a ceiling test write down.
Partnership revenues totaled $4,234,581 for the year ended December 31, 2014 compared to $5,112,482 for the comparable period in 2013, a decrease of 17.2% due primarily to decreases in oil sales prices. Overall, oil and gas sales volumes decreased during the year ended December 31, 2014 compared to the year ended December 31, 2013 by approximately 7.8% on a BOE basis, a result of natural declining production from existing wells. In addition, the average sales price for crude oil decreased by 10.3%, to an average price of $81.01 per Bbl for the year ended December 31, 2014 compared to an average price of $90.27 for the year ended December 31, 2013. The majority of the 2014 price decline occurred during the fourth quarter, with the fourth quarter 2014 average oil price dropping to $61.32 per barrel from $86.68 received during the third quarter. While the overall decrease in 2014 revenues year to year was 17.2%, fourth quarter revenues dropped to $743,402 from third quarter revenues of $1,182,939, a decline of 37.2%. The average sales price for natural gas increased by 6.4%, to an average price of $4.14 per MCF for the year ended December 31, 2014 compared to an average price of $3.89 for the year ended December 31, 2013. However, gas revenues account for less than 10% of total Partnership oil and gas sales revenues.
The Partnership has not and is currently not engaged in commodity futures trading, hedging activities, or derivative financial instrument transactions for trading or other speculative purposes. The Partnership sells substantially all 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. Prices for crude oil have continued to decline throughout the first quarter of 2015.
Lease operating expenses increased from $2,327,209 for the year ended December 31, 2013 to $2,608,987 for the year ended December 31, 2014, due primarily to increased workover expenses on the Slaughter Dean acquisition properties. Total workover costs included in lease operating expenses, most of which are incurred on the Partnership’s Slaughter Dean acquisition properties, increased from $212,715 in 2013 to $390,078 in 2014. As workover costs are primarily a function of repairing mechanical well failures, workover costs can vary from year to year. Production tax expense decreased in conjunction with the decrease in revenues, from $298,815 for the year ended December 31, 2013 to $252,144 for the year ended December 31, 2014.
General and administrative costs during the year ended December 31, 2014 decreased to $635,685 as compared to $736,429 incurred during the year ended December 31, 2013. The allocation of RELP’s overhead to the Partnership is a significant portion of general and administrative expenses. 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. The administrative overhead charged to the Partnership decreased from $489,183 during the year ended December 31, 2013 to $431,793 during the year ended December 31, 2014. In addition, professional services incurred during the year decreased from $229,122 for the year ended December 31, 2013 to $184,476 for the year ended December 31, 2014. Professional services include legal
fees, audit fees, engineering fees for reserve reports and other analysis, and fees for preparation of SEC filings and XBRL services. During 2013, the Partnership incurred one time fees associated with XBRL services to set up the initial detailed XBRL tagging of its financial statements and footnotes. These decreases were offset by a slight increase in geology and geophysical charges incurred related to resolving ownership issues and various other issues related to the individual properties.
Off-Balance Sheet Arrangements
The Partnership does not participate in transactions that generate relationships with unconsolidated entities or financial partnerships, such as entities often referred to as structure finance or special purpose entities (SPEs), which would have been established for the purpose of facilitating off-balance sheet arrangements or other contractually narrow or limited purposes. As of December 31, 2015, 2014 and 2013, the Partnership was not involved in any unconsolidated SPE transactions or any other off-balance sheet arrangements.
Contractual Obligations Table
* In September 2006, 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 acquisition properties only. The amounts payable to William R. Dixon under the aforementioned agreement are not fixed and determinable amounts, and will vary based upon sales revenues from the Slaughter Dean acquisition properties. During the years ended December 31, 2015, 2014, and 2013, William R. Dixon received $4,216, $19,379, and $17,147, respectively, related to this overriding royalty interest. The Partnership sold its interest in the Slaughter Dean acquisition properties during the second quarter of 2015, and the liability for payment of this overriding royalty interest was transferred to the purchaser of the Slaughter Dean acquisition properties upon consummation of the sale.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Partnership is a “smaller reporting company” as defined by Rule 12b-2 of the Exchange Act, and as such, is not required to provide the information required under this Item.
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, 2015.
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 Over Financial Reporting
There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended December 31, 2015 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. (referred to herein as Reef). Reef Exploration, L.P. (referred to herein as RELP), an affiliate of Reef, provides technical and administrative services necessary to the conduct of the Partnership’s business. RELP employs a staff including geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership’s operations.
Reef Oil & Gas Partners, L.P. and Reef Exploration, L.P.
The Manager, officers and key personnel of the managing general partner (Reef) and RELP, 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.
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 Partnership units to brokers for their own accounts, who were permitted to buy Partnership units at a price net of the commission that they would normally earn on sales of such 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. Prior to October 1, 2013, 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, Reef purchased 0.60 units of limited partner interest from one of the Partnership’s investor partners. As such, effective October 1, 2013 Reef received 11.06% and investor partners received 88.94% of total cash distributions. During 2015, Reef purchased 0.45 units of limited partner interest and 0.25 units of general partner interest from the Partnership’s investor partners. As such, effective September 1, 2015, Reef receives 11.13% and investor partners receive 88.87% of total cash distributions. During the years ended December 31, 2015, 2014 and 2013, Reef received $1,965, $18,899, and $75,254, respectively, in cash distributions related to its Partnership interest.
RELP is entitled to receive drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership for wells operated by RELP. RELP served as the operator of the Slaughter Dean acquisition properties until their sale during the second quarter of 2015. RELP also is also entitled to receive 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, tangible costs of drilling and completing the well, costs of storage and other surface facilities, and the 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. During the years ended December 31, 2015, 2014, and 2013, RELP received $13,564, $21,201, and $25,602, 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, 2015, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $82,922 and $2,672, respectively. During the year ended December 31, 2014, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $96,804 and $1,130, respectively. 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.
RELP allocates its general and administrative expenses as overhead to all of the partnerships to which it provides services, and this allocation is a significant portion of the Partnership’s general and administrative expenses. The allocation of RELP’s overhead to the partnerships to which it provides services 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, 2015, 2014, and 2013, the administrative overhead charged by RELP to the Partnership totaled $279,085, $431,793, and $489,183, respectively. The administrative overhead charged by RELP is included in general and administrative expense in the accompanying 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, 2015 and 2014, RELP owed the Partnership $135,851 and $183,078, 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, 2015 concerning the managing general partner and 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. As of December 31, 2015 there were a total of 896.9696 Partnership units outstanding, including 499.9524 units of general partner interest outstanding and 397.0172 units of limited partner interest outstanding.
(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. As of December 31, 2015, Reef has also purchased 1.05 units of limited partner interest from investor partners, representing 0.117% of outstanding investor partner units, and 0.25 units of general partner interest, representing 0.028% of outstanding investor partner units. Michael J. Mauceli has control of Reef’s voting and investment powers. 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.”
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
In each of the last two fiscal years, 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. As such, no pre-approval policies or procedures for engagement of principal accountants have been established.
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 Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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,
March 30, 2016
Michael J. Mauceli
L.P., the Managing General Partner of the Partnership
(Principal Executive Officer)
/s/ Daniel C. Sibley
Chief Financial Officer and General Counsel of
March 30, 2016
Daniel C. Sibley
Reef Exploration, L.P.
(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
lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 10-Q, dated May 15, 2013.
10.22
Purchase and Sale Agreement dated May 27, 2015, by and between Reef Oil & Gas Income and Development Fund III, L.P. and Red Sea 2012, Inc. (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K, dated June 3, 2015).
10.23
Offer to Purchase Oil, Gas and Mineral Interest Wilmington Oil Field, Long Beach Unit, dated December 2, 2015 and Acceptance of Offer to Purchase, signed December 16, 2015, by and between Reef Oil & Gas Income and Development Fund II, L.P., Reef Oil & Gas Income and Development Fund III, L.P. and California Resources Long Beach Inc. (incorporated by reference to Exhibit 10.1 of the Partnership’s Current Report on Form 8-K, dated December 22, 2015).
31.1
*
Certification of Principal Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2
*
Certification of Principal Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1
*
Certification of Principal Executive Officer pursuant to 18 U.S.C. §1350.
32.2
*
Certification of Principal Financial Officer pursuant to 18 U.S.C. §1350.
101.INS
*
XBRL Instance Document.
101.SCH
*
XBRL Taxonomy Extension Schema Document.
101.CAL
*
XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB
*
XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE
*
XBRL Taxonomy Extension Presentation Linkbase Document.
101.DEF
*
XBRL Taxonomy Extension Definitions Linkbase Document.
* Filed herewith
Reef Oil & Gas Income and Development Fund III, L.P.
Financial Statements
Years Ended December 31, 2015, 2014, and 2013
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
The 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, 2015 and 2014 and the related statements of operations, partnership equity, and cash flows for each of the three years in the period ended December 31, 2015. 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.
The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern. As discussed in Note 1 to the financial statements, the Partnership, when formed, was projected to have a limited life through December 2016, unless terminated sooner. Management is currently pursuing the sale of all Partnership assets with the intent to wind up and terminate the Partnership during 2016, as specified in the Partnership’s governing documents at its inception. In accordance with generally accepted accounting principles for a limited life entity, the Partnership has not applied the liquidation basis of accounting to these financial statements.
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, 2015 and 2014, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/S/ BDO USA, LLP
Dallas, Texas
March 30, 2016
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 Flow
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 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, subject to certain market conditions, no earlier than 2010, but expected no later than 2015, in order to maximize return to the partners of the Partnership. The term of the Partnership commenced on the effective date and continues until December 31, 2016, unless terminated sooner. 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 initially distributed 11% to Reef and 89% to investor partners. Effective October 1, 2013, Reef purchased 0.60 units of limited partner interest from one of the Partnership’s investor partners. As such, effective October 1, 2013 Reef received 11.06% and investor partners received 88.94% of total cash distributions. During 2015, Reef purchased 0.45 units of limited partner interest and 0.25 units of general partner interest from investor partners. As such, effective September 1, 2015 Reef receives 11.13% and investor partners receive 88.87% of total cash distributions.
The Partnership operates in only one industry segment, which is the exploration, development and production of oil, condensate, natural gas and natural gas liquids (“NGL’s”) in the United States.
Going Concern
The accompanying financial statements have been prepared assuming that the Partnership will continue as a going concern.
During 2015, the Partnership sold its interest in the Slaughter Dean acquisition properties, which were operating at a deficit as a result of the decline in commodity prices that began during the third quarter of 2014. As Reef is unable to project when or if commodity prices will recover, in October 2015 Reef made a decision to begin marketing the remainder of the Partnership’s oil and gas properties. Several property sales were consummated during the fourth quarter of 2015, and Reef is currently pursuing the divestiture of all of the Partnership’s oil and gas properties with the intent to wind up and terminate the Partnership during 2016. Therefore, the Partnership is not expected to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements (continued)
2. Summary of Significant 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 reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership 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 purchase date to be cash equivalents. Cash and cash equivalents consist of demand deposits 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 oil and gas properties. 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 thousand cubic feet (“Mcf”) of natural gas to 1 barrel (“Bbl”) of crude oil. 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. During 2015, the Partnership recorded gain or loss in connection with two of its property sales. During the second quarter of 2015, the Partnership recognized a gain of $1,673,100 in connection with the sale of the Slaughter Dean acquisition properties in Cochran County, Texas (the “Slaughter Dean Properties”). During the fourth quarter of 2015, the Partnership recognized a loss of $2,405,410 in connection with the sale of its interest in the Thums Long Beach Unit (“Thums Unit”) located in the Wilmington Field underneath the Long Beach Harbor in southern California.
In applying the full cost method, the Partnership performs 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 lower of unamortized cost or the cost ceiling, which is defined as the sum of the estimated future net revenues from the Partnership’s proved reserves using prices that are the preceding 12-month un-weighted arithmetic average of the first-day-of-the-month
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements (continued)
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, 2015, 2014, and 2013, the Partnership recognized property impairment costs of proved properties totaling $5,432,366, $1,841,274, and $0, respectively.
Estimates of Proved Oil and Gas Reserves
The estimates of the Partnership’s proved reserves at December 31, 2015, 2014, and 2013 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 the senior reservoir engineer for Reef Exploration, L.P. (“RELP”), an affiliate of the Partnership and Reef, at December 31, 2015, and by an independent petroleum engineering firm at December 31, 2014 and 2013.
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 future net income. A decline in estimated proved reserves and future cash flows, whether caused by declining commodity prices or downward adjustments to the rate of production from Partnership wells, 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 regulators enact new well restoration requirements. The Partnership recognizes accretion expense in connection with the discounted liability over the remaining life of the well.
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements (continued)
The following table summarizes the Partnership’s asset retirement obligation for the years ended December 31, 2015 and 2014.
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, 2015, 2014, and 2013.
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, 2015, the tax basis of the Partnership’s assets exceeds the financial reporting basis of the assets by approximately $16.7 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
Accounting Standards Codification (“ASC”) section 740 provides guidance on accounting for uncertainty in income taxes. ASC 740 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. ASC 740 also provides guidance on de-recognition, classification, interest and penalties, accounting in interim periods, and disclosure.
Under ASC 740, 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, 2015 and 2014. The Partnership is subject to examination of income tax filings in the U.S. and various state jurisdictions for the years ended December 31, 2015, 2014, and 2013. The Partnership has not been subjected to any audits by the Internal Revenue Service for these periods.
Fair Value of Financial Instruments
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements (continued)
The estimated fair value of cash and cash equivalents, accounts receivable from affiliates, accounts payable and accrued liabilities approximates their carrying value due to their short-term nature.
Recent Accounting Developments - Revenue Recognition
The following recently issued accounting pronouncement has been adopted or may impact the Partnership in future periods:
The Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) in May 2014 which provides accounting guidance for all revenues arising from contracts to provide goods or services to customers. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. To achieve this core principle, an entity should apply the following five steps: (1) identify the contract(s) with the customer; (2) identify the performance obligations in the contract(s); (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract(s); (5) recognize revenue when (or as) the entity satisfies a performance obligation. The requirements from the new ASU will supersede prior revenue recognition requirements and most prior industry-specific guidance throughout the FASB’s ASC, and will be effective for all interim and annual periods beginning after December 15, 2017. The Partnership is still considering the method of adoption but does not expect the adoption of this guidance to materially impact its operating results, financial position or cash flow.
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 a property acquisition. The per annum interest rate was 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. The obligations of TCB to the Partnership under the Credit Agreement were to expire on June 30, 2015, at which point the promissory note was to mature, and any unpaid principal and interest would have become due and payable. The Credit Agreement was a reducing revolving credit facility, and was subject to semi-annual redetermination of the borrowing base in accordance with the TCB’s customary practices for oil and gas loans.
The Partnership had the right to prepay principal and accrued interest thereon in whole or in part at any time without premium or penalty. During 2014, the Partnership made various pre-payments of principal on the promissory note, utilizing proceeds from property sales and current cash flows. The Partnership completed repayment of the promissory note balance during December 2014 and terminated the Credit Agreement with TCB on December 31, 2014.
The Partnership paid TCB certain facility fees and engineering fees in connection with prior year redeterminations of the borrowing base. The fees paid in connection with these prior borrowing base redeterminations were capitalized by the Partnership as Deferred Financing Fees and amortized over the term of the Credit Agreement.
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. Prior to October 1, 2013, cash distributions to partners of the net cash flow from
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements (continued)
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, Reef purchased 0.60 units of limited partner interest from one of the Partnership’s investor partners. As such, effective October 1, 2013 Reef received 11.06% and investor partners received 88.94% of total cash distributions. During 2015, Reef purchased 0.45 units of limited partner interest and 0.25 units of general partner interest from investor partners. As such, effective September 1, 2015 Reef receives 11.13% and investor partners receive 88.87% of total cash distributions.
During the years ended December 31, 2015, 2014 and 2013, Reef received $1,965, $18,899, and $75,254, respectively, in cash distributions related to its Partnership interest. From funds generated by its carried interest and management fee, Reef pays to specific FINRA-licensed broker-dealers on a quarterly basis a fee in an 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 fee is recorded as a commission expense by Reef.
RELP is entitled to receive drilling compensation in an amount equal to 15% of the total well costs paid by the Partnership for wells operated by RELP. RELP served as the operator of the Partnership’s Slaughter Dean acquisition properties until their sale during the second quarter of 2015. RELP is also entitled to receive 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, tangible costs of drilling and completing the well, costs of storage and other surface facilities, and the 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. During the years ended December 31, 2015, 2014 and 2013, RELP received $13,564, $21,201, and $25,602, 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, 2015, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $82,922 and $2,672, respectively. During the year ended December 31, 2014, Reef and its affiliates received total reimbursements for direct costs and other documented out-of-pocket expenses of $96,804 and $1,130, respectively. 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.
RELP allocates its general and administrative expenses as overhead to all of the partnerships to which it provides services, and this allocation is a significant portion of the Partnership’s general and administrative expenses. The allocation of RELP’s overhead to the partnerships to which it provides services 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, 2015, 2014, and 2013, the administrative overhead charged by RELP to the Partnership totaled $279,085, $431,793, and $489,183, respectively. The administrative overhead charged by RELP is included in general and administrative expense in the accompanying 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, 2015 and 2014, RELP owed the Partnership $135,851 and $183,078, 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. At September 30, 2015, RELP also owed the Partnership $181,610 associated with the sale of the Partnership’s Slaughter Dean Properties. The amount represented post-closing purchase price adjustments due from the purchaser of the Slaughter Dean Properties. RELP has been unsuccessful in collecting this balance due, and as of December 31, 2015 this amount was re-classified as a bad debt expense on the books of the Partnership.
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements (continued)
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, 2015, one marketer and one operator accounted for 44.3% and 18.2% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2014, the same marketer and operator accounted for 37.5% and 36.0% of the Partnership’s crude oil and natural gas revenues, respectively. During the year ended December 31, 2013, the same marketer and operator accounted for 38.0% and 32.8% 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 Properties. During the years ended December 31, 2015, 2014, and 2013, William R. Dixon received $4,216, $19,379, and $17,147, respectively, related to this overriding royalty interest. The Partnership sold its interest in the Slaughter Dean Properties during the second quarter of 2015, and the liability for payment of this overriding royalty interest was transferred to the purchaser of the Slaughter Dean Properties.
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, 2015, 2014 and 2013 is detailed below:
For the year ended December 31, 2015
For the year ended December 31, 2014
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements (continued)
For the year ended December 31, 2013
8. Subsequent Event
During the first quarter of 2016, two investor partners owning 0.50 units of general partner interest and 0.50 units of limited partner interest have abandoned their interests in the Partnership. As such, the Partnership has reduced the total number of general partner and limited partner units outstanding effective January 1, 2016 to reflect these abandonments.
We have evaluated subsequent events and determined that no subsequent events have occurred that would require recognition in the financial statements or disclosure in the notes thereto other than as discussed in the accompanying notes.
9. 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 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, 2015, 2014, and 2013.
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements (continued)
Results of Operations
The following table sets forth the results of operations from oil and gas producing activities for the years ended December 31, 2015, 2014 and 2013
BOE = Barrels of Oil Equivalent (6 MCF equals 1 BOE)
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 Jerald Sluder, the Senior Reservoir Engineer for RELP, as of December 31, 2015, and by the independent petroleum engineering firm Forrest A. Garb & Associates, Inc. as of December 31, 2014, and 2013. 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, 2015 and 2014, all of the Partnership’s reserves are classified as proved developed reserves. 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.
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.
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements (continued)
The following information table sets forth changes in estimated net proved developed crude oil and natural gas reserves for the years ended December 31, 2015, 2014 and 2013.
(1) Oil includes both oil and natural gas liquids
(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, 2015, 2014, and 2013, calculations were made using average prices of $50.19, $93.63, and $96.90 per barrel of crude oil, respectively, and $2.63, $4.22, and $3.67 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.
Reef Oil & Gas Income and Development Fund III, L.P.
Notes to Financial Statements (continued)
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, 2015, 2014 and 2013 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: