Information regarding the Fund’s current projects, all of which are located in the offshore waters of the Gulf of Mexico, is provided in the following table. The budget for each project is inclusive of estimated asset retirement obligations. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs” for information regarding the funding of the Fund’s capital commitments.
| | | | | | Total Spent | | | Total | | |
| | | Working | | | through | | | Fund | | |
| Project | | Interest | | | December 31, 2016 | | | Budget | | Status |
| | | | | | (in thousands) | | |
| Producing Properties | | | | | | | | | | |
| Diller Project | | | 0.88% | | | $ | 2,787 | | | $ | 3,938 | | The Diller Project is expected to include the development of two wells. Well #1 commenced production during third quarter 2015. Well #2 is expected to commence production in 2019. Well #1, which was shut-in in late-2016 due to well hydrate remediation work, resumed production in mid-January 2017. The Fund expects to spend $0.8 million for additional development costs and $0.4 million for asset retirement obligations. |
| Liberty Project | | | 5.0% | | | $ | 7,510 | | | $ | 8,612 | | The Liberty Project, a single-well project, commenced production in 2010. After various shut-ins in late-2015 and early-2016, due to third-party facilities' repair and maintenance activities, the well resumed production in early-May 2016. A smart recompletion is planned for 2018 with no costs to the Fund. The Fund expects to spend $1.1 million for asset retirement obligations. |
| Marmalard Project | | | 0.88% | | | $ | 5,597 | | | $ | 9,329 | | The Marmalard Project is expected to include the development of six wells. Wells #1, #2 and #3 commenced production during second quarter 2015. Well #4 commenced production during fourth quarter 2015. Additional wells are expected to commence production in 2019 and 2020. The Fund expects to spend $2.6 million for additional development costs and $1.1 million for asset retirement obligations. |
Sale of Investment in Delta House
| | | | | | Total Spent | | | Total | | |
| | | Working | | through | | | Fund | | |
| Project | | Interest | | December 31, 2015 | | | Budget | | Status |
| | | | | | (in thousands) | | |
| Producing Properties | | | | | | | | | | |
| Diller Project | | | 0.88 | % | | $ | 2,788 | | | $ | 3,937 | | The Diller Project is expected to include the development of two wells. Well #1 commenced production during third quarter 2015. Well #2 is expected to commence production in 2018. The Fund expects to spend $0.7 million for additional development costs and $0.4 million for asset retirement obligations. |
| | | | | | | | | | | | | | |
| Liberty Project | | | 5.0 | % | | $ | 7,510 | | | $ | 8,762 | | The Liberty Project, a single-well project, commenced production in 2010. The well has not produced since October 2015 due to a shut-in at the third-party natural gas processing plant that the Fund contracts, but does not own a working interest in. Production is expected to resume in March 2016. A recompletion is planned for 2017 at an estimated cost of $0.2 million. The Fund expects to spend $1.1 million for asset retirement obligations. |
| | | | | | | | | | | | | | |
| Marmalard Project | | | 0.88 | % | | $ | 5,629 | | | $ | 8,688 | | The Marmalard Project is expected to include the development of six wells. Wells #1, #2 and #3 commenced production during second quarter 2015. Well #4 commenced production during fourth quarter 2015. Additional wells are expected to commence production in 2020 and 2023. The Fund expects to spend $2.0 million for additional development costs and $1.1 million for asset retirement obligations. |
| Fully Depleted Properties | | | | | | | | | | | | | |
| Carrera Project | | | 5.0 | % | | $ | 8,111 | | | $ | 9,273 | | The Carrera Project, a single-well project, commenced production in 2011. The well reached the end of its productive life in fourth quarter 2014. The Fund expects to spend $1.2 million for asset retirement obligations. |
Marketing/Customers
The Manager, on behalf of the Fund, has engaged Energy Upgrade, Inc. to marketmarkets the Fund’s oil and natural gas.gas to third parties consistent with industry practice. During 2015, DH Sales and Transport, LLC (“DH S&T”), a wholly-owned subsidiary of the Manager, was formed to act as an aggregator to and as an accommodation for the Fund and other funds managed by the Manager to facilitate the transportation and sale of oil and natural gas produced from the Diller and Marmalard projects. During 2016, the Fund entered into a master agreement with DH S&T pursuant to which DH S&T is obligated to purchase from the Fund all of its interests in oil and natural gas produced from the Diller and Marmalard projects and sell such volumes to unrelated third party purchasers. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. Currently, and during 2015,2016, the Fund had threefour major customers in the public market. Because a ready market exists for oil and natural gas, the Fund does not believe that the loss of any individual customer would have a material adverse effect on its financial position or results of operations.
The Fund’s current producing projects are near existing transportation infrastructure and pipelines.
NaturalThe Fund’s natural gas and oil generally is sold in the spot marketto its customers at prevailing market prices, which fluctuate with demand as a result of related industry variables. Oil is generally sold one month at a time at prevailing market prices. Historically, the markets for, and prices of, oil and natural gas have been volatile, and they are likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence; therefore, it is impossible to predict the future price of oil and natural gas with any certainty. During the year ended December 31, 2015, decreases2016, fluctuations in commodity prices had an adverse effect on the Fund’s profitability and distributions. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Commodity Price Changes”, “Results of Operations – Overview” and “Results of Operations – Oil and Gas Revenue” for information regarding the impact of prices on the Fund’s oil and gas revenue. In the past, the Fund has entered, and in the future, may continue to enter, into transactions, or derivative contracts, that fix the future prices or establish a price floor for portions of its oil or natural gas production.
Seasonality
Generally, the Fund'sFund’s business operations are not subject to seasonal fluctuations in the demand for oil and natural gas that would result in more of the Fund'sFund’s oil and natural gas being sold, or likely to be sold, during one or more particular months or seasons. Once a project is producing, the operator of the project extracts oil and natural gas reserves throughout the year. Once extracted, oil and natural gas can be sold at any time during the year.
The Fund’s properties are located in the Gulf of Mexico; therefore, its operations and cash flows may be significantly impacted by hurricanes and other inclement weather. Such events may also have a detrimental impact on third-party pipelines and processing facilities, upon which the Fund relies to transport and process the oil and natural gas it produces. The National Hurricane Center defines hurricane season in the Gulf of Mexico as June through November. The Fund did not experience any significant damage, shut-ins, or production stoppages due to hurricane activity in 2015.2016.
OperatorOperators
The projects in which the Fund has invested are operated and controlled by unaffiliated third-party entities acting as operators. The operators are responsible for drilling, administration and production activities for leases jointly owned by working interest owners and act on behalf of all working interest owners under the terms of the applicable joint operating agreement. In certain circumstances, operators will enter into agreements with independent third-party subcontractors and suppliers to provide the various services required for operating leases. Currently, the Fund's properties are operated by LLOG Exploration Offshore, L.L.C.
Because the Fund does not operate any of the projects in which it has acquired a working interest, shareholders not only had to bear the risk that the Manager will be able to selectwould find suitable projects, but also that, once selected, have to bear the risk that such projects will be managed prudently, efficiently and fairly by the operators.
Insurance
The Manager has obtained what it believes to be adequate insurance for the funds that it manages to cover the risks associated with the Fund’sfunds’ passive investments, including those of the Fund. Although the Fund is not an operator, the Manager has, nonetheless, obtained hazard, property, general liability and other insurance in commercially reasonable amounts to cover its projects, as well as general liability, directors’ and officers’ liability and similar coverage for its business operations. However, there is no assurance that such insurance will be adequate to protect the Fund from material losses related to its projects. In addition, the Manager's pastManager’s practice has beenis to obtain insurance as a package that is intended to cover most, if not all, of the funds under its management. The Manager re-evaluates theits insurance coverage on an annual basis. While the Manager believes it has obtained adequate insurance in accordance with customary industry practices, the possibility exists, depending on the extent of the insurable incident, that insurance coverage may not be sufficient to cover all losses. In addition, depending on the extent, nature and payment of any claims to the Fund'sFund or to its affiliates, yearly insurance coverage limits may be exhausted and become insufficient to cover a claim made by the Fund in a given year.
Salvage Fund
The Fund deposits in a separate interest-bearing account, or salvage fund, cash to provide for its proportionate share of the anticipated cost of dismantling production platforms and facilities, plugging and abandoning the wells, and removing the platforms, facilities and wells in respect of the projects after the end of their useful lives, in accordance with applicable federal and state laws and regulations. As of December 31, 2015,2016, the Fund has $3.9$3.5 million invested in a salvage fund. On a monthly basis, the Fund expects to contribute to the salvage fund a portion of the operating income from the Diller and Marmalard projects to fund the asset retirement obligations of such projects. Such contributions to the salvage fund will reduce the amount of cash distributions that would be made to investors by the Fund. Any portion of the salvage fund that remains after the Fund has paid for all of its asset retirement obligations will be distributed to the shareholders and the Manager. There are no restrictions on withdrawals from the salvage fund.
Competition
Competition exists in the acquisition of oil and natural gas leases and in all sectors of the oil and natural gas exploration and production industry. The Fund, through its Manager, has competed with other companies for the acquisition of leases as well as percentage ownership interests in oil and natural gas working interests in the secondary market. The Fund does not anticipate the acquisition of any additional ownership interests in oil and natural gas working interests as its capital has been fully allocated to current and past projects.
Employees
The Fund has no employees. The Manager operates and manages the Fund.
Offices
The principal administrative office of both the Fund and the Manager is located at 14 Philips Parkway, Montvale, NJ 07645, and their phone number is 800-942-5550. The Manager leases additional office space at 1254 Enclave Parkway, Houston, TX 77077 and 125 Worth Avenue, Suite 318, Palm Beach, Florida, 33480. In addition, the Manager maintains leases for other offices that are used for administrative purposes for the Fund and other funds managed by the Manager.
Regulation
Oil and natural gas exploration, development, production and transportation activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other things, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled, and the plugging and abandoning of projects are also subject to regulations. The Fund owns projects that are located in the offshore waters of the Gulf of Mexico on the OCS. The Fund’s operations and activities are therefore governed by the OCSLA and certain other laws and regulations.
Outer Continental Shelf Lands Act
Under the OCSLA, the United States federal government has jurisdiction over oil and natural gas development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the BOEM, an agency of the United States Department of Interior (the “Department of Interior”).BOEM. Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement (the “BSEE”(“BSEE”) pursuant to regulations promulgated under the OCSLA. The OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. The BSEE regulates the design and operation of well control and other equipment at offshore production sites, implementation of safety and environmental management systems, and mandatory third-party compliance audits, among other requirements. BSEE has adopted strict requirements for subsea drilling production equipment and hashad proposed new requirements to implement equipment reliability improvements, building upon enhanced industry standards for blowout preventers and blowout prevention technologies, and reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment. These proposedIn April 2016, BSEE adopted a final rule establishing updated standards for blowout prevention systems and other well controls pertaining to offshore activities. The final rule became effective July 28, 2016; compliance with certain provisions of the final rule, however, are deferred as specified. The final rule imposes new requirements have not yet become final.relating to, among, other things, well design, well control, casing, cementing, real-time well monitoring and subsea containment. BSEE has also published a policy statement on safety culture with nine characteristics of a robust safety culture. The rule applies directly to operators as opposed to non-operators. However, the costs associated with compliance, which at this time cannot be determined or estimated, will likely increase the costs of operating in the Gulf of Mexico and such costs will be imposed upon all working interest owners, including the Fund. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities, delay or restriction of activities can result from either governmental or citizen prosecution.
BOEM Draft GuidanceNotice to Lessees on Supplemental Bonding
On September 22, 2015,July 14, 2016, the BOEM issued draft guidance (“Draft Guidance”) describing revised supplemental bonding procedures directed at oil and natural gas exploration and production companies operating on the OCS. The Draft Guidance describes procedures and criteria for determining operators’ ability to carry out its financial obligations for decommissioning of wells, platforms, pipelines and other facilities situated on the OCS. Among other things, the Draft Guidance proposes to eliminate the “waiver” exemption currently allowed by BOEM, whereby certain operators on the OCS with a large net worth and meeting certain other criteria have the option of being exempted from posting bonds or other acceptable assurances for such operator’s decommissioning obligations by self-insuring for those liabilities. Instead, the BOEM has proposed one set of self-insurance criteria for independent exploration and production companies, and another set for companies within the “integrated” exploration and production sector. It is unclear what the actual thresholds will be for self-insurability. The proposed criteria identify performance, leverage, and liquidity factors. BOEM used existing data to calculate what those numbers look like for companies in the top and bottom quartiles. But there does not appear to be any clear direction that “a company must meet this minimum number” in order to qualify for self-insurance. In addition, the BOEM has stated that it will no longer consider the combined financial strength and reliability of co-lessees when determining a lessee’s decommissioning liability such that smaller non-operators, such as the Fund, will no longer be able to rely on the waiver exemption of a co-lessee. Once the Draft Guidance is finalized, the BOEM will issue these supplemental bonding changes in a revised Notice to Lessees (“NTL”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the OCS (“Lessees”). Generally, the new NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees, (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance. The new rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in replacementcertain circumstances. The Fund, as well as other industry participants, are working with the BOEM, its operators and working interest partners to determine and agree upon the correct level of an existingdecommissioning obligations to which they may be liable and the manner in which such obligations will be secured. The impact of the NTL, onif enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM satisfaction using one or more of the enumerated methods for doing so. Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, that was made effective on August 28, 2008. The BOEM has delayed issuing any final NTL on these issues. We anticipate that a new NTL incorporating somefund escrow accounts or allobtain letters of the Draft Guidance will be issued by early 2016. credit.
Sales and Transportation of Oil and Natural Gas
The Fund, directly or indirectly through affiliated entities, sells its proportionate share of oil and natural gas to the market through a marketer and receives market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for the Fund to make such sales, it is dependent upon unaffiliated pipeline companies whose rates, terms and conditions of transport are subject to regulation by the Federal Energy Regulatory Commission. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service.cost-of-service-based. In some circumstances, rates can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge the Fund, although regulated, are beyond the Fund’s control. Nevertheless, such rates would apply uniformly to all transporters on that pipeline and, as a result, management does not anticipate that the impact to the Fund of any changes in such rates, terms or conditions would be materially different than the impact upon other oil or natural gas producers and marketers.
Environmental Matters and Regulation
The Fund’s operations are subject to pervasive environmental laws and regulations governing the discharge of materials into the air and water, the handling and managing of waste materials, and the protection of aquatic species and habitats. However, although it shares the liability along with its other working interest owners for any environmental damage,While most of the activities to which these federal, state and local environmental laws and regulations apply are conducted by the operatoroperators on the Fund’s behalf. Nevertheless,behalf, the Fund shares the liability along with its other working interest owners for any environmental damage. The environmental laws and regulations to which its operations are subject may require the Fund, or the operator, to acquire permits to commence drilling operations, restrict or prohibit the release of certain materials or substances into the environment, impose the installation of certain environmental control devices, require certain remedial measures to prevent pollution and other discharges such as the plugging of abandoned projects and, finally, impose in some instances severe penalties, fines and liabilities for the environmental damage that may be caused by the Fund’s projects.
Some of the environmental laws that apply to oil and natural gas exploration and production are described below:
The Oil Pollution Act. The Oil Pollution Act of 1990, as amended (the “OPA”), amends Section 311 of the Federal Water Pollution Control Act of 1972, as amended (the “Clean Water Act”) and was enacted in response to the numerous tanker spills, including the Exxon Valdez spill, that occurred in the 1980s. Among other things, the OPA clarifies the federal response authority to, and increases penalties for, such spills. OPA imposes strict, joint and several liabilities on “responsible parties” for damages, including natural resource damages, resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility and the lessee or permit holder of the area in which an offshore facility is located. The OPA establishes a liability limit for onshore facilities and deepwater ports of $633.85 million, (effective December 21, 2015 pursuant to the U.S. Coast Guard’s rulemaking adjusting liability limits for increases in Consumer Price Index), while the liability limit for a responsible party for offshore facilities, including any offshore pipeline, is equal to all removal costs plus up to $133.65 million in other damages for each incident. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up. Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. The Fund is not aware of any action or event that would subject us to liability under the OPA, and the Fund believes that complianceOPA. Compliance with the OPA’s financial assurance and other operating requirements has not had, and the Fund believes will not in the future have, a material impact on itsthe Fund’s operations or financial condition.
Clean Water Act. Generally, the Clean Water Act imposes liability for the unauthorized discharge of pollutants, including petroleum products, into the surface and coastal U.S. waters, except in strict conformance with discharge permits issued by the federal, or state, if applicable, agency. Regulations governing water discharges also impose other requirements, such as the obligation to prepare spill response plans. The Fund’s operators are responsible for compliance with the Clean Water Act, although the Fund may be liable for any failure of the operator to do so.
Federal Clean Air Act. The Federal Clean Air Act of 1970, as amended (the “Clean Air Act”), restricts the emission of certain air pollutants. Prior to constructing new facilities, permits may be required before work can commence and existing facilities may be required to incur additional capital costs to add equipment to ensure and maintain compliance. As a result, the Fund’s operations may be required to incur additional costs to comply with the Clean Air Act.
Other Environmental Laws. In addition to the above, the Fund’s operations may be subject to the Resource Conservation and Recovery Act of 1976,as amended, which regulates the generation, transportation, treatment, storage, disposal and cleanup of certain hazardous wastes, as well as the Comprehensive Environmental Response, Compensation, and Liability Act of 1980,as amended, which imposes joint and several liability without regard to fault or legality of conduct on classes of persons who are considered responsible for the release of a hazardous substance into the environment.
The above represents a brief outline of significant environmental laws that may apply to the Fund’s operations. The Fund believes that its operators are in compliance with each of these environmental laws and the regulations promulgated thereunder. The Fund does not believe that its environmental, health and safety risks are materially different from those of comparable companies in the United States in the offshore oil and gas industry. However, there are no assurances that the environmental regulations described above will not result in curtailment of production orproduction; material increases in the costs of production, development or exploration,exploration; enforcement actions or other penalties as a result of any non-compliance with any such regulations; or otherwise have a material adverse effect on the Fund’s operating results and cash flows.
Dodd-Frank Act. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market and, in addition, requires certain additional SEC reporting requirements.
On February 3, 2017, the “Presidential Executive Order on Core Principles for Regulating the United States Financial System” (the “Order”) was issued to review the Dodd-Frank Act. The Fund cannot predict at this time what regulations or portions of the law, if any, will be changed as a result of the Order.
Under its LLC Agreement, the Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production. Dodd-Frank Act mandates that many derivatives be executed in regulated markets and submitted for clearing to regulated clearinghouses. Derivatives will be subject to minimum daily margin requirements set by the relevant clearinghouse and, potentially, by the SEC or the U.S. Commodity Futures Trading Commission (“CFTC”), and derivatives dealers may demand the unilateral ability to increase margin requirements beyond any regulatory or clearinghouse minimums. In addition, as required by Dodd-Frank Act, the CFTC has set “speculative position limits” (limits(which are limits imposed on the maximum net long or net short speculative positions that a person may hold or control with respect to futures or options contracts traded on the U.S. commodities exchange) with respect to most energy contracts. These requirements under Dodd-Frank Act could significantly increase the cost of any derivatives transactions of the Fund (including through requirements to post collateral, which could adversely affect the Fund’s liquidity), materially alter the terms of derivatives transactions and make it more difficult for the Fund to enter into customized transactions, cause the Fund to liquidate certain positions it may hold, reduce the ability of the Fund to protect against price volatility and other risks by making certain hedging strategies impossible or so costly that they are not economical to implement, and increase the Fund’s exposure to less creditworthy counterparties. If as a result of the legislation and regulations, the Fund alters any hedging program that may be in effect from time to time, the Fund’s operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Fund’s performance. The Fund is not currently, and has not been during 20152016, or 2014,at any time since 2012, a party to any derivative instruments or hedging programs.
Dodd-Frank Act also required the SEC to issue rules requiring resource extraction issuers to disclose annually information relating to certain payments made by the issuer to the U.S. federal government or a foreign government for the purpose of the commercial development of oil, natural gas or minerals. Rules issued by the SEC in 2012 were subsequently vacated in federal court in 2013. In December 2015,On June 27, 2016, the SEC proposed newadopted resource extraction rules. When any finalissuer payment disclosure rules are issued, the Fund will evaluate any impactpursuant to Section 1504 of the Dodd-Frank Act that will require resource extraction companies to publicly file with the SEC information about the type and total amount of payments made to a foreign government or to the U.S. federal government for each project related to the development of crude oil, natural gas or minerals, and the type and total amount of payments made to each government. However, on February 14, 2017, a bill passed by the United States Congress was signed eliminating the SEC resource extraction issuer payment disclosure rules. The SEC will have one year to issue replacement rules on its business.to implement Section 1504 of the Dodd-Frank Act.
Not required.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
The information regarding the Fund’s properties that is contained in Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties,” is incorporated herein by reference.
Drilling Activity
The following table sets forth the Fund’s drilling activity forduring the years ended December 31, 20152016 and 2014.2015. Gross wells are the total number of wells in which the Fund has an interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells, which produce both oil and natural gas, and are located in the offshore waters of the Gulf of Mexico.
| | | 2015 | | | 2014 | | | 2016 | | | 2015 | |
| | | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | |
| Exploratory wells: | | | | | | | | | | | | | | | | | | | | | | | | |
| Productive | | 2 | | | 0.02 | | | - | | | - | | | | - | | | | - | | | | 2 | | | | 0.02 | |
| In-progress | | | - | | | | - | | | | 2 | | | | 0.02 | | |
| Exploratory well total | | | 2 | | | | 0.02 | | | | 2 | | | | 0.02 | | | | - | | | | - | | | | 2 | | | | 0.02 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Development wells: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Productive | | 3 | | | 0.03 | | | - | | | - | | | | - | | | | - | | | | 3 | | | | 0.03 | |
| In-progress | | | - | | | | - | | | | 2 | | | | 0.02 | | |
| Development well total | | | 3 | | | | 0.03 | | | | 2 | | | | 0.02 | | | | - | | | | - | | | | 3 | | | | 0.03 | |
Unaudited Oil and Gas Reserve Quantities
The preparation of the Fund’s oil and gas reserve estimates are completed in accordance with the Fund’s internal control procedures over reserve estimation. The Fund’s management controls over proved reserve estimation include: 1) verification of input data that is provided to an independent petroleum engineering firm; 2) engagement of well-qualified and independent reservoir engineers for preparation of reserve reports annually in accordance with SEC reserve estimation guidelines; and 3) a review of the reserve estimates by the Manager.
The Manager’s primary technical person in charge of overseeing the Fund’s reserve estimates has a B.S. degree in Petroleum Engineering and is a member of the Society of Petroleum Engineers, the Association of American Drilling Engineers and the American Petroleum Institute. With over twenty-fivethirty years of industry experience, he is currently responsible for reserve reporting, engineering and economic evaluation of exploration and development opportunities, and the oversight of drilling and production operations.
The Fund’s reserve estimates atas of December 31, 20152016 and 20142015 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent petroleum engineering firm. The information regarding the qualifications of the petroleum engineer is included within the report from NSAI, which is filed as Exhibit 99.1 to this Annual Report, and is incorporated herein by reference.
Proved Reserves. Proved oil and gas reserves are estimated quantities of oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. The information regarding the Fund’s proved reserves, which is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Critical Accounting Estimates – Proved Reserves”, is incorporated herein by reference. The information regarding the Fund’s unaudited net quantities of proved developed and undeveloped reserves, which is contained in Table III in the “Supplementary Financial Information – Information about Oil and Gas Producing Activities – Unaudited” included in Item 8. “Financial Statements and Supplementary Data” of this Annual Report, is incorporated herein by reference.
Proved Undeveloped Reserves. AtAs of December 31, 2016, the Fund had proved undeveloped reserves related to the Marmalard Project totaling 0.1 million barrels of oil, 0.1 million barrels of natural gas liquid (“NGL”) and 0.5 million mcf of natural gas. As of December 31, 2015, the Fund had proved undeveloped reserves related to the Marmalard Project totaling 0.2 million barrels of oil, 45 thousand barrels of natural gas liquid (“NGL”)NGL and 0.4 million mcf of natural gas. AtThe Marmalard Project was determined to be a discovery in 2012 and commenced production during 2015.
During the year ended December 31, 2014,2016, the Fund haddid not incur capital expenditures to advance the development of the proved undeveloped reserves related to the Marmalard and Diller projects totaling 0.5 million barrels of oil and 1.2 million mcf of natural gas. The Diller and Marmalard projects were determined to be discoveries in 2012.
During the year ended December 31, 2015, the Fund incurred costs to advance the development of its proved undeveloped reserves of approximately $2.9 million, which related to the Diller and Marmalard projects. During 2015, the Diller and Marmalard projects commenced production.Project. The Fund currently expects to develop the proved undeveloped reserves relating to the Marmalard Project over the next several years. Information regarding estimated future development costs relating to the Marmalard Project, which is contained in Item 1. “Business” of this Annual Report under the heading “Properties”, is incorporated herein by reference. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.
Production and Prices
The information regarding the Fund’s production of oil and natural gas, and certain price and cost information forduring the years ended December 31, 20152016 and 20142015 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations – Overview” and “Results of Operations – Operating Expenses” is incorporated herein by reference.
Delivery Commitments
As of December 31, 2015,2016, the Fund had no delivery obligations or delivery commitments under any existing contracts.
ITEM 3. LEGAL PROCEEDINGS
None.
ITEM 4. MINE SAFETY DISCLOSURES
None.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
There is currently no established public trading market for the Shares. As of January 31, 2016,2017, there were 1,3231,331 shareholders of record of the Fund.
Distributions are made in accordance with the provisions of the LLC Agreement. At various times throughout the year, the Manager determines whether there is sufficient available cash, as defined in the LLC Agreement, for distribution to shareholders. Due to the significant capital required to developfor the ongoing development of the Diller and Marmalard projects, distributions have been impacted, and willmay be impacted in the future, by amounts reserved to provide for their ongoing development costs and funding of their estimated asset retirement obligations. There is no requirement to distribute available cash and, as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. During the years ended December 31, 20152016 and 2014,2015, the Fund paid distributions totaling $0.6$0.9 million and $2.4$0.6 million, respectively.
ITEM 6. SELECTED FINANCIAL DATA
Not required.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Overview of the Fund’s Business
The Fund was organized primarily to acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of exploratory or development oil and natural gas projects. However, the Fund is not required to make distributionsDistributions to shareholders except as providedare made in accordance with the Fund’s LLC Agreement. The Fund does not expect in the LLC Agreement.future to investigate or invest in any additional projects other than those in which it currently has a working interest. The Fund’s remaining capital has been fully allocated to complete such projects.
The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. The Fund does not currently, nor is there any plan to, operate any project in which the Fund participates. The Manager enters into operating agreements with third-party operators for the management of all exploration, development and producing operations, as appropriate. See Item 1. “Business” of this Annual Report under the headings “Project Information” and “Properties” for more information regarding the projects of the Fund.
Commodity Price Changes
Changes in commodity prices may significantly affect liquidity and expected operating results. Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in non-cash charges to earnings due to impairment.
SinceDuring fourth quarter 2014, there has beenwas a significant decline in oil and natural gas prices.commodity prices, which continued into mid-year 2016 when oil and gas commodity prices began to show improvement. The Fund plans for price cyclicality in its planning and believes it is well positioned to withstand such price volatility. The Fund continues to conserve cash to complete the ongoing development of the Diller and Marmalard projects. See “Results of Operations” under this Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report for more information on the average oil and natural gas prices received by the Fund during the years ended December 31, 20152016 and 20142015 and the effect of such decreased average prices on the Fund’s results of operations. If oil and natural gas prices continue to decline, even if only for a short period of time, the Fund’s results of operations and liquidity will continue to be adversely impacted.
Market pricing for oil and natural gas is volatile, and is likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence. Therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Factors affecting market pricing for oil and natural gas include:
| · | economic conditions, including demand for petroleum-based products; |
| · | actions by OPEC, the Organization of Petroleum Exporting Countries; |
| · | political instability in the Middle East and other major oil and gas producing regions; |
| · | governmental regulations, both domestic and foreign; |
| · | domestic and foreign tax policy; |
| · | the pace adopted by foreign governments for the exploration, development, and production of their national reserves; |
| · | the supply and price of foreign imports of oil and gas; |
| · | the cost of exploring for, producing and delivering oil and gas; |
| · | the discovery rate of new oil and gas reserves; |
| · | the rate of decline of existing and new oil and gas reserves; |
| · | available pipeline and other oil and gas transportation capacity; |
| · | the ability of oil and gas companies to raise capital; |
| · | the overall supply and demand for oil and gas; and |
| · | the price and availability of alternate fuel sources. |
Critical Accounting Estimates
The discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of its revenues and expenses during the periods presented. The Fund evaluates these estimates and assumptions on an ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and actual results may differ from these estimates and assumptions and such differences may have a material impact on the results of operations, financial position or cash flows. See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for a discussion of the Fund’s significant accounting policies. The following is a discussion of the accounting policies and estimates that management believes are most significant.
Accounting for Acquisition, Exploration Development and AcquisitionDevelopment Costs
Exploration,Acquisition, exploration and development and acquisition costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs, are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. Annual lease rentals and exploration expenses are expensed as incurred.
Proved Reserves
Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depletion and amortization. Annually, the Fund engages an independent petroleum engineer to perform a comprehensive study of the Fund’s proved properties to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Fund’s control. The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment. In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues to change.
Asset Retirement Obligations
Asset retirement obligations include costs to plug and abandon the Fund’s wells and to dismantle and relocate or dispose of the Fund’s production platforms and related structures and restoration costs of land and seabed. The Fund develops estimates of these costs based upon the type of production structure, water depth, reservoir depth and characteristics, ongoing discussions with the wells’ operators and, at times, with information provided by third-party abandonment consultants specializing in the oil and gas industry. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires significant judgment that is subject to future revisions based upon numerous factors such as the timing of settlements, the credit-adjusted risk-free rates used and inflation rates, including changing technology and the political and regulatory environment. Estimates are reviewed on a bi-annual basis, or more frequently if an event occurs that would dictate a change in assumptions or estimates.
Impairment of Long-Lived Assets
The Fund reviews the carrying value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of proved properties are determined by comparing estimated future net undiscounted cash flows from the property to the carrying value at the time of the review. If the carrying value exceeds estimated future net undiscounted cash flows, the carrying value of the propertyasset is written down to fair value, which is determined using estimated future net discounted cash flows from the property.asset. The fair value determinations require considerable judgment and are sensitive to change. Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of net discounted future cash flows from proved oil and natural gas reserves could change in the near term.
Significant declinesand consistent fluctuations in oil and natural gas prices since fourth quarter 2014 have resulted in impairmentsimpacted the fair value of the Fund’s oil and gas properties. If oil and natural gas prices continue to decline, even if only for a short period of time, it is possible that additional impairments of oil and gas properties will occur.
Results of Operations
The following table summarizes the Fund’s results of operations forduring the years ended December 31, 20152016 and 2014,2015, and should be read in conjunction with the Fund’s financial statements and the notes thereto included within Item 8. “Financial Statements and Supplementary Data” in this Annual Report.
| | | Year ended December 31, | |
| | | 2016 | | | 2015 | |
| | | (in thousands) | |
| Revenue | | | | | | |
| Oil and gas revenue | | $ | 5,045 | | | $ | 3,512 | |
| Expenses | | | | | | | | |
| Depletion and amortization | | | 2,017 | | | | 1,833 | |
| Management fees to affiliate | | | 1,083 | | | | 1,082 | |
| Operating expenses | | | 2,819 | | | | 1,951 | |
| General and administrative expenses | | | 154 | | | | 152 | |
| Total expenses | | | 6,073 | | | | 5,018 | |
| Loss from operations | | | (1,028 | ) | | | (1,506 | ) |
| Other (loss) income | | | | | | | | |
| Loss on investment in Delta House | | | (114 | ) | | | - | |
| Dividend income | | | 191 | | | | 75 | |
| Interest income | | | 9 | | | | 11 | |
| Total other income | | | 86 | | | | 86 | |
| Net loss | | $ | (942 | ) | | $ | (1,420 | ) |
| | | Year ended December 31, | |
| | | 2015 | | | 2014 | |
| | | (in thousands) | |
| Revenue | | | | | | |
| Oil and gas revenue | | $ | 3,512 | | | $ | 5,246 | |
| Expenses | | | | | | | | |
| Depletion and amortization | | | 1,833 | | | | 1,321 | |
| Impairment of oil and gas properties | | | - | | | | 1,615 | |
| Management fees to affiliate | | | 1,082 | | | | 1,287 | |
| Operating expenses | | | 2,018 | | | | 1,156 | |
| Workover expense | | | (67 | ) | | | 401 | |
| General and administrative expenses | | | 152 | | | | 157 | |
| Total expenses | | | 5,018 | | | | 5,937 | |
| Loss from operations | | | (1,506 | ) | | | (691 | ) |
| Other income | | | | | | | | |
| Dividend income | | | 75 | | | | - | |
| Interest income | | | 11 | | | | 15 | |
| Total other income | | | 86 | | | | 15 | |
| Net loss | | $ | (1,420 | ) | | $ | (676 | ) |
Overview. The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the years ended December 31, 20152016 and 2014.2015. NGL sales are included within gas sales.
| | | Year ended December 31, | |
| | | 2016 | | | 2015 | |
| Number of wells producing | | | 6 | | | | 6 | |
| Total number of production days | | | 1,779 | | | | 1,064 | |
| Oil sales (in thousands of barrels) | | | 106 | | | | 66 | |
| Average oil price per barrel | | $ | 41 | | | $ | 47 | |
| Gas sales (in thousands of mcfs) | | | 251 | | | | 171 | |
| Average gas price per mcf | | $ | 2.36 | | | $ | 2.43 | |
| | | Year ended December 31, | |
| | | 2015 | | | 2014 | |
| Number of wells producing | | | 6 | | | | 2 | |
| Total number of production days | | | 1,064 | | | | 563 | |
| Oil sales (in thousands of barrels) | | | 66 | | | | 51 | |
| Average oil price per barrel | | $ | 47 | | | $ | 91 | |
| Gas sales (in thousands of mcfs) | | | 171 | | | | 131 | |
| Average gas price per mcf | | $ | 2.43 | | | $ | 4.52 | |
During the year ended December 31, 2015, production days and sales volumes were impacted by the commencement of production of four wellsThe increases noted in the above table were primarily related to the Marmalard Project and one well in the Diller Project,projects, which commenced production during 2015, partially offset by the Liberty Project, which washad been shut-in during fourth quarter 2015. During the year ended December 31, 2014, the Carrera Project reached the endearly part of its productive life.2016. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.
Oil and Gas Revenue. TheGenerally, the Fund generally sells oil, gas and NGLs under two types of agreements, which are common in the oil and gas industry. Both types of agreements may include transportation charges. One type of agreement isIn a netback agreement, under which the Fund sells oil and gas at the wellhead and receives a price, net of transportation expense incurred by the purchaser. In this case,purchaser, and the Fund records revenue at the net price received fromreceived. In the purchaser. The second type of agreement, is one whereby the Fund pays transportation expense directly. In that case,directly, and transportation expense is included within operating expense in the statements of operations.
Oil and gas revenue forduring the year ended December 31, 20152016 was $3.5$5.0 million, a decreasean increase of $1.7$1.5 million from the year ended December 31, 2014.2015. The decreaseincrease was attributable to increased sales volume totaling $2.1 million, partially offset by decreased oil and gas prices totaling $3.2 million, partially offset by increased sales volume totaling $1.5$0.6 million.
See “Overview” above for factors that impact the oil and gas revenue sales volume and rate variances.
Depletion and Amortization. Depletion and amortization forduring the year ended December 31, 20152016 was $1.8$2.0 million, an increase of $0.5$0.2 million from the year ended December 31, 2014.2015. The increase was attributable to adjustments to asset retirement obligations of $0.4 million, primarily related to the Carrera Project, a fully depleted property, coupled with an increase in production volumes totaling $0.4$0.8 million, partially offset by adjustments to asset retirement obligations related to fully depleted properties totaling $0.4 million, which were recorded in second quarter 2015, and a decrease in the average depletion rate totaling $0.3$0.2 million. The decrease in the average depletion rate was primarily attributable to the Carrera Project, which had higher cost reservesDepletion and did not produce in 2015. The average depletion rate was alsoamortization rates were impacted by the onset of the production of the Diller Project, which has higher cost reserves andchanges in reserve estimates provided annually by the onset of production of the Marmalard Project, which has lower cost reserves. Fund’s independent petroleum engineers.
See “Overview” above for certain factors that impact the depletion and amortization volume and rate variances. Depletion and amortization rates are also impacted by changes in reserve estimates provided annually by the Fund’s independent petroleum engineers.
Impairment of Oil and Gas Properties. During the year ended December 31, 2015, the Fund did not record an impairment of oil and gas properties. During the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $1.6 million related to the Carrera Project, which was determined to be uneconomic relative to the remaining reserves and the well was fully impaired.
Management Fees to Affiliate. An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager. Such fee may be temporarily waived by the Manager to accommodate the Fund’s short-term capital commitments.
Operating Expenses. Operating expenses represent costs specifically identifiable or allocable to the Fund’s wells, as detailed in the following table.
| | | Year ended December 31, | |
| | | 2016 | | | 2015 | |
| | | (in thousands) | |
| Lease operating expense | | $ | 2,268 | | | $ | 1,625 | |
| Transportation expense | | | 322 | | | | 153 | |
| Workover expense | | | 121 | | | | (67 | ) |
| Accretion expense | | | 64 | | | | 140 | |
| Insurance expense | | | 56 | | | | 121 | |
| Other | | | (12 | ) | | | (21 | ) |
| | | $ | 2,819 | | | $ | 1,951 | |
| | | Year ended December 31, | |
| | | 2015 | | | 2014 | |
| | | (in thousands) | |
| Lease operating expense | | $ | 1,625 | | | $ | 993 | |
| Transportation expense | | | 153 | | | | - | |
| Accretion expense | | | 140 | | | | 39 | |
| Insurance expense | | | 121 | | | | 83 | |
| Dry-hole and other | | | (21 | ) | | | 41 | |
| | | $ | 2,018 | | | $ | 1,156 | |
15
Lease operating expense and transportation expense relates to the Fund’s producing properties. Workover expense represents costs to restore or stimulate production of existing reserves. During the year ended December 31, 2016, workover expense relates to the Diller and Marmalard projects. Accretion expense related to the asset retirement obligations established for the Fund’s proved properties. Insurance expense represents premiums related to producing well and control of well insurance,the Fund’s properties, which variesvary depending upon the number of wells producing or drilling. Insurance expense related to operating wells has been reclassified from “General and administrative expenses” in prior year to “Operating expenses” to correct prior period presentation.
The average production cost, which includes lease operating expense, transportation expense and insurance expense, was $20.13$17.87 per barrel of oil equivalent (“BOE”) during the year ended December 31, 2015,2016 compared to $13.65$20.13 per BOE during the year ended December 31, 2014.2015. The increase is principallydecrease was primarily attributable to the impactMarmalard Project, which had higher cost per BOE in 2015 as a result of costs associated with the commencementproject’s onset of production coupled with lower lease operating expense for the Marmalard and Diller projects. Accretion expense relates to the asset retirement obligations established for the Fund’s proved properties. Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs.Liberty Project.
Workover Expense. Workover expense represents costs to restore or stimulate production of existing reserves. During the years ended December 31, 2015 and 2014, credits to workover expense of $0.1 million and workover expense of $0.4 million, respectively, principally related to the Carrera Project.
General and Administrative Expenses. General and administrative expenses represent costs specifically identifiable or allocable to the Fund, such as accounting and professional fees and directors’ and officers’ liability insurance expense.expenses.
Loss on Investment in Delta House. During the year ended December 31, 2016, the Fund recognized a loss on investment of $0.1 million related to its investment in Delta House. There were no such amounts recorded during the year ended December 31, 2015. See Note 1 of “Notes to Financial Statements” - “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Investment in Delta House.
Dividend Income. Dividend income is related to the Fund’s investment in Delta House. See Note 1 of “Notes to Financial Statements” - “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Investment in Delta House.
Interest Income. Interest income is comprised of interest earned on cash and cash equivalents and salvage fund.
Capital Resources and Liquidity
Operating Cash Flows
Cash flows provided by operating activities forduring the year ended December 31, 2016 were $0.5 million, related to revenue received of $4.9 million and dividend income received of $0.2 million, partially offset by operating expenses of $2.9 million, management fees of $1.1 million, the settlement of an asset retirement obligation of $0.5 million and general and administrative expenses of $0.1 million.
Cash flows provided by operating activities during the year ended December 31, 2015 were $0.5 million, related to revenue received of $3.4 million and dividend income received of $0.1 million, partially offset by operating expenses of $1.9 million and management fees of $1.1 million.
Investing Cash Flows
Cash flows provided by operatinginvesting activities forduring the year ended December 31, 20142016 were $2.5$0.8 million, primarily related to revenue received of $5.3 million, partially offset by management fees of $1.3 million, operating expenses of $0.9 million, workover expensenet proceeds from salvage fund of $0.4 million and general and administrative expensescoupled with proceeds from the sale of $0.2investment in Delta House of $0.3 million.
Investing Cash Flows
Cash flows used in investing activities forduring the year ended December 31, 2015 were $5.6 million, related to capital expenditures for oil and gas properties and investment in Delta House of $3.2 million and investments in the salvage fund of $2.4 million. See Note 1 of “Notes to Financial Statements” - “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Investment in Delta House.
Cash flows used in investing activities for the year ended December 31, 2014 were $2.3 million, related to capital expenditures for oil and gas properties and investment in Delta House of $2.1 million, inclusive of advances, and investments in the salvage fund of $0.2 million.
Financing Cash Flows
Cash flows used in financing activities forduring the year ended December 31, 2016 were $0.9 million, related to manager and shareholder distributions.
Cash flows used in financing activities during the year ended December 31, 2015 were $0.6 million, related to manager and shareholder distributions.
Cash flows used in financing activities for the year ended December 31, 2014 were $2.4 million related to manager and shareholder distributions.16
Estimated Capital Expenditures
The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of December 31, 2015, the Fund had two properties, the Diller and Marmalard projects, for which additional development costs must be incurred. The Fund currently expects to spend an additional $4.2 million (which includes asset retirement obligations) related to the development of these projects, which the Fund anticipates will include the development of eight wells, two in the Diller Project and six in the Marmalard Project, with related platform and pipeline infrastructure. During 2015, one well in the Diller Project and four wells in the Marmalard Project commenced production. See Item 1. “Business” of this Annual Report under the heading “Properties” for additional information. Seeand “Liquidity Needs” below for additional information.
Capital expenditures for oil and gas properties have been funded with the capital raised by the Fund in its private placement offering. The number of projects in which the Fund could invest was limited, and each unsuccessful project the Fund experienced exhausted its capital and reduced its ability to generate revenue.
Liquidity Needs
The Fund’s primary short-term liquidity needs are to fund its operations and capital expenditures for its oil and gas properties. Such needs are funded utilizing operating income and existing cash on-hand.
As of December 31, 2015,2016, the Fund’s estimated capital commitments related to its oil and gas properties were $6.7$6.6 million (which include asset retirement obligations for the Fund’s projects of $3.8$3.2 million), of which $1.2$0.6 million is expected to be spent during the year ending December 31, 2016.
2017. Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, as well as ongoing operations. Reserve estimates are projections based on engineering data that cannot be measured with precision, require substantial judgment, and are subject to frequent revision.
The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. However, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Such fee may be temporarily waived to accommodate the Fund’s short-term capital commitments.
Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion. Due to the significant capital required to developfor the ongoing development of the Diller and Marmalard projects, distributions have been impacted, and willmay be impacted in the future, by amounts reserved to provide for their ongoing development costs and funding their estimated asset retirement obligations.
Off-Balance Sheet Arrangements
The Fund had no off-balance sheet arrangements atas of December 31, 20152016 and 20142015 and does not anticipate the use of such arrangements in the future.
Contractual Obligations
The Fund enters into participation and joint operating agreements with operators. On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities. The Fund does not negotiate such contracts. No contractual obligations exist atas of December 31, 20152016 and 2014,2015, other than those discussed in “Estimated Capital Expenditures” above.
Recent Accounting Pronouncements
See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for a discussion of the Fund’s recent accounting pronouncements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not required.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
All financial statements meeting the requirements of Regulation S-X and the supplementary financial information required by Item 302 of Regulation S-K are included in the financial statements listed in Item 15. “Exhibits and Financial Statement Schedules” and filed as part of this report.
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, 2015.2016. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.
Management's Report on Internal Control over Financial Reporting
Management of the Fund is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)). The Fund’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2015.2016. In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal Control — Integrated Framework (2013). Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2015,2016, the Fund’s internal control over financial reporting is effective.
This Annual Report does not include an attestation report of the Fund’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Fund’s registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Fund to provide only management’s report in this Annual Report.
Changes in Internal Control over Financial Reporting
The Chief Executive Officer and Chief Financial Officer of the Fund have concluded that there have not been any changes in the Fund’s internal control over financial reporting during the quarter ended December 31, 20152016 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The Fund has engaged Ridgewood Energy as the Manager. The Manager has very broad authority, including the authority to appoint the executive officers of the Fund. Executive officers of the Fund and their ages atas of December 31, 20152016 are as follows:
Name, Age and Position with Registrant |
| |
Robert E. Swanson, 6869 Chief Executive Officer |
| |
Kenneth W. Lang, 6162 President and Chief Operating Officer |
| |
Kathleen P. McSherry, 5051 Executive Vice President and Chief Financial Officer |
| |
Robert L. Gold, 5758 Executive Vice President |
| |
Daniel V. Gulino, 5556 Senior Vice President, General Counsel and Secretary |