UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20142015
or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____ to _____
Commission File No. 000-53584
| Ridgewood Energy Y Fund, LLC |
| (Exact name of registrant as specified in its charter) |
| Delaware | | 26-2417032 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| 14 Philips Parkway, Montvale, NJ 07645 |
| (Address of principal executive offices) (Zip code) |
| |
| (800) 942-5550 |
| (Registrant’s telephone number, including area code) |
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Shares of LLC Membership Interest
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes o No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesdays.Yes xNo o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes xNo o
Indicate by check mark if the disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | o | Accelerated filer | o |
Non-accelerated filer | o (Do not check if a smaller reporting company) | Smaller reporting company | x | |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).Yes o No x
There is no market for the shares of LLC Membership Interest in the Fund. As of February 24, 201526, 2016 there are 492.3709 shares of LLC Membership Interest outstanding.
RIDGEWOOD ENERGY Y FUND, LLC
20142015 ANNUAL REPORT ON FORM 10-K
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| PART II | | | |
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| PART III | | | |
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FORWARD-LOOKING STATEMENTS
Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy Y Fund, LLC (the “Fund”) has incorporated by reference into this Annual Report, other than purely historical information, including estimates, projections and statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the US Private Securities Litigation Reform Act of 1995 that are based on current expectations and assumptions and are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. You are therefore cautioned against relying on any such forward-looking statements. Forward-looking statements can generally be identified by words such as “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “will likely result,” and similar expressions and references to future periods. Examples of events that could cause actual results to differ materially from historical results or those anticipated include weather conditions, such as hurricanes, changes in market conditions affecting the pricing and production of oil and natural gas, the cost and availability of equipment, and changes in governmental regulations.regulations, as well as other risks and uncertainties discussed in this Annual Report in Item 1. “Business” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. Examples of forward-looking statements made herein include statements regarding projects, investments, insurance, capital expenditures and liquidity. Forward-looking statements made in this document speak only as of the date on which they are made. The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.
PART I
Overview
The Fund is a Delaware limited liability company (“LLC”) formed on March 25, 2008 to primarily acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.
The Fund initiated its private placement offering on May 1, 2008, selling whole and fractional shares of membership interests (“Shares”), consisting of Limited Liability Shares of Membership Interests (“Limited Liability Shares”) and Investor GP Shares of Membership Interests (“Investor GP Shares”), primarily at $200 thousand per whole Share. The Limited Liability Shares and the Investor GP Shares constitute a single class of securities as defined in Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). In January 2014, pursuant to the LLC Agreement, Ridgewood Energy Corporation, as manager of the Fund converted all then outstanding Investor GP Shares to Limited Liability Shares. There is no public market for the Shares and one is not likely to develop. In addition, the Shares are subject to material restrictions on transfer and resale and cannot be transferred or resold except in accordance with the Fund’s limited liability company agreement (the “LLC Agreement”) and applicable federal and state securities laws. The private placement offering was terminated on November 7, 2008. The Fund raised $97.8 million and after payment of $16.1 million in offering fees, commissions and investment fees, the Fund had $81.7 million for investments and operating expenses.
Manager
Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) was founded in 1982. The Manager has direct and exclusive control over the management of the Fund’s operations. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. Historically when the Fund had sought project investment, the Manager located potential projects, conducted due diligence, and negotiated the investment transactions with respect to those projects. Additional information regarding the Manager is available through its website at www.ridgewoodenergy.com. No information on such website shall be deemed to be included or incorporated by reference into this Form 10-K.Annual Report.
As compensation for its services, the Manager is entitled to an annual management fee, payable monthly, equal to 2.5% of the total capital contributions made by the Fund’s shareholders, net of cumulative dry-hole and related well costs incurred by the Fund. The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. Management fees for the years ended December 31, 2015 and 2014 and 2013 were $1.7$1.2 million and $1.8$1.7 million, respectively. Additionally, the Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. The Fund did not pay distributions for the year ended December 31, 2015. Distributions paid to the Manager for the yearsyear ended December 31, 2014 and 2013 were $0.3 million and $0.9 million, respectively.million.
In addition to the management fee, the Fund is required to pay all other expenses it may incur, including insurance premiums, expenses of preparing and printing periodic reports for shareholders and the Securities Exchange Commission (“SEC”), commission fees, taxes, third-party legal, accounting and consulting fees, litigation expenses and other expenses. The Fund is required to reimburse the Manager for all such expenses paid on its behalf.
Business Strategy
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. Distributions are funded from cash flow from operations, and the frequency and amount are within the Manager’s discretion subject to available cash from operations, reserve requirements and Fund operations. The Fund has invested in the drilling and development of both shallow and deepwater oil and natural gas projects in the U.S. offshore waters of Texas, Louisiana, and Alabama in the Gulf of Mexico, in partnership with exploration and production companies. At December 31, 2014, theThe Fund’s participation in investments in oil and natural gas properties had been completely identified and contractedis complete and the balance of the Fund’s capital has been fully allocated to complete such projects and since that time, the Fund has not investigated or invested in, and does not expect in the future to investigate or invest in, any additional projects, other than those in which the Fund currently has a working interest.
The Fund has invested its capital with operators through working interest joint ventures with such operators and in some cases, other energy companies that also own or acquire working interests in the projects. A working interest is an undivided fractional interest in a lease block acquired from the U.S. government or from an operator that has acquired the working interest. A working interest includes the right to drill, produce and conduct operating activities and share in any resulting oil and natural gas production. Operators will generally retain 25% to 50% interests in multiple drilling projects, rather than 100% interests in a few projects, in order to share risk, obtain independent technical validation and stretch exploration budgets that are split across numerous regions of the world.
Investment Committee
Ridgewood Energy maintains an investment committee consisting of five members, whichall of whom are employees of the Manager (the “Investment Committee”). The Investment Committee provides operational, financial, scientific and technical oil and gas expertise to the Fund (the “Investment Committee”).and generally approves investments and other matters for the Fund. Two members of the Investment Committee are based out of the Manager’s Montvale, New Jersey office and three members are based out of the Manager’s Houston, Texas office. Currently, the Investment CommitteeCommittee’s activities surrounding the Fund are principally related to the development and operation of properties for which it already has a working interest.
Participation and Joint Operating Agreements
On behalf of the Fund, and with respect to the Fund’s projects, Ridgewood Energy negotiatesnegotiated participation and joint operating agreements with the goal of achieving the best possible economics and governance rights for the Fund in connection with acquiring the interest.agreements. Under the joint operating agreement, proposals and decisions with respect to a project and related activities are generally made based on percentage ownership approvals and although an operator’s percentage ownership may constitute a majority ownership, operators generally seek consensus relating to project decisions. As a result, Ridgewood Energy and other non-operating partners generally retain the right to make proposals and influence decisions involving certain operational matters associated with a project. This approval discretion and the operator’s desire to execute the project efficiently and expeditiously can function to limit the operator’s inclination to act on its own, or against the interests of the participants in the project.
Project Information
ExistingThe Fund’s existing projects are located in the waters of the Gulf of Mexico, offshore Louisiana, on the Outer Continental Shelf (“OCS”). The Outer Continental Shelf Lands Act (“OCSLA”), which was enacted in 1953, governs certain activities with respect to working interests and the exploration of oil and natural gas in the OCS. See further discussion under the heading “Regulation” in this Item 1. “Business” of this Annual Report.
Leases in the OCS are generally issued for a primary lease term of 5, 8 or 10 years, depending on the water depth of the lease block. During a primary lease term, except in limited circumstances, lessees are not subject to any particular requirements to conduct exploratory or development activities. However, once a lessee drills a well and begins production, the lease term is extended for the duration of commercial production.
The lessee of a particular block, for the term of the lease, has the right to drill and develop exploratory wells and conduct other activities throughout the block. If the initial well on the block is successful, a lessee, or third-party operator for a project, may conduct additional geological studies and may determine to drill additional exploratory or development wells. If a development well is to be drilled in the block, each lessee owning working interests in the block must be offered the opportunity to participate in, and cover the costs of, the development well up to that particular lessee’s working interest ownership percentage.
Royalty Payments
Generally, working interests in an offshore oil and natural gas lease under the OCSLA pay a 12.5%, 16.67% or 18.75% royalty to the BureauOffice of Ocean Energy ManagementNatural Resources Revenue (“BOEM”ONRR”) depending on the lease. Other than BOEMthe ONRR royalties, the Fund does not have material royalty burdens.
Deep Gas Royalty Relief
On January 26, 2004, the BOEM Bureau of Ocean Energy Management (“BOEM”) promulgated a rule providing incentives for companies to increase deep natural gas production in the Gulf of Mexico (the "Royalty Relief Rule"). The Royalty Relief Rule does not extend to deep waters of the Gulf of Mexico off the Outer Continental Shelf nor does it apply if the price of natural gas exceeds $11.35$11.45 (estimated) per Million British Thermal Units (“mmbtu”), adjusted annually for inflation. The Fund currently has three leases,one project, the Cobalt Liberty and Carrera projects,Project, which qualifyqualifies for royalty relief under the Royalty Relief Rule.
Deepwater Royalty Relief
In addition to the Royalty Relief Rule, the Deep Water Royalty Relief Act of 1995 (the “Deepwater Relief Act”) was enacted to promote exploration and production of oil and natural gas in the deepwater of the Gulf of Mexico and relieves eligible leases from paying royalties to the U.S. Government on certain defined amounts of deepwater production. The Deepwater Relief Act expired in the year 2000 but was extended for qualified leases by the BOEM to promote continued interest in deepwater. The Deepwater Royalty Relief Act does not apply to oil if the prices of oil exceed certain thresholds (currently estimated to be between $36.83 per barrel and $47.83 per barrel), adjusted annually for inflation. The Deepwater Royalty Relief Act does not apply to natural gas if the prices of natural gas exceed certain thresholds (currently estimated to be between $4.60 per mmbtu and $7.97 per mmbtu) adjusted annually for inflation. The Fund currently has one lease,three projects, the Liberty, Project,Diller and Marmalard projects, which qualifiesqualify for royalty relief under the Deepwater Relief Act.
Properties
Productive Wells
The following table sets forth the number of productive oil and natural gas wells in which the Fund owned an interest as of December 31, 2014.2015. Productive wells are producing wells and wells mechanically capable of production. Gross wells are the total number of wells in which the Fund owns a working interest. Net wells are the sum of the Fund’s fractional working interests owned in the gross wells. All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.
| | | Total Productive Wells | |
| | | Gross | | | Net | |
| Oil and natural gas | | | 3 | | | | 0.18 | |
| | | Total Productive Wells | |
| | | Gross | | | Net | |
| Oil and natural gas | | | 7 | | | | 0.19 | |
During January 2015, the Fund determined that the Carrera Project, one of the productive wells included in the table above, was no longer mechanically capable of producing.
Acreage Data
The following table sets forth the Fund’s interests in developed and undeveloped oil and gas acreage as of December 31, 2014.2015. Gross acres are the total number of acres in which the Fund owns a working interest. Net acres are the sum of the fractional working interests owned in gross acres. Ownership interests generally take the form of working interests in oil and gas leases that have varying terms. All of the wells are located in the offshore waters of the Gulf of Mexico and are operated by third-party operators.
| Developed Acres | Developed Acres | | | Undeveloped Acres | Developed Acres | | | Undeveloped Acres | |
| Gross | Gross | | | Net | | | Gross | | | Net | | Net | | | Gross | | | Net | |
| | 16,520 | | | | 946 | | | | 34,924 | | | | 375 | |
| 28,040 | | | | 924 | | | | 17,644 | | | | 222 | |
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 Spent | | | Total | | |
| | | Working | | | through | | | Total Fund | | | | Working | | | through | | | Fund | | |
| Project | | Interest | | | December 31, 2014 | | | Budget | | Status | | Interest | | | December 31, 2015 | | | Budget | | Status |
| | | | | | (in thousands) | | | | | | | (in thousands) | | |
| Equipment and Facilities | | | | | | | | | | | |
| Delta House Project | | 0.06% | | | $ | 313 | | | $ | 529 | | Floating production facility to service several wells, including the Diller and Marmalard wells, which is expected to be placed in service in second quarter 2015. | |
| Non-producing Properties | | | | | | | | | | | | | | | | | | | | | | |
| Beta Project | | 2.0% | | | $ | 8,169 | | | $ | 15,996 | | Well deemed to be a discovery in 2012. Completion efforts are ongoing and production is expected to commence in 2016. | | 2.0% | | | $ | 11,853 | | | $ | 17,517 | | The Beta Project is expected to include the development of four wells. Well #1 is expected to commence production in third quarter 2016. Well #2 is expected to commence production in fourth quarter 2016. Wells #3 and #4 are expected to commence production in 2017. The Fund expects to spend $4.8 million for additional development costs and $0.9 million for asset retirement obligations. |
| | | | | | | | | | | | | | |
| Producing Properties | | | | | | | | | | | | | |
| Cobalt Project | | | 12.0% | | | $ | 5,683 | | | $ | 5,991 | | The Cobalt Project, a single-well project, commenced production in 2009. Recompletions are planned for 2016, 2017 and 2019 at an estimated total cost of $0.1 million. The Fund expects to spend $0.2 million for asset retirement obligations. |
| | | | | | | | | | | | | | |
| Diller Project | | 0.88% | | | $ | 2,298 | | | $ | 3,711 | | Well deemed to be a discovery in 2012. Completion efforts are ongoing and production is expected to commence in third quarter 2015. | | 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 | | | 3.0% | | | $ | 4,506 | | | $ | 5,257 | | 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 $0.1 million. The Fund expects to spend $0.7 million for asset retirement obligations. |
| Marmalard Project | | 0.88% | | | $ | 3,235 | | | $ | 7,923 | | Wells #1 and #2 were deemed to be discoveries in 2012 and 2013, respectively. Well #3 began drilling in December 2014. Completion efforts are ongoing and production is expected to commence in second quarter 2015. | | 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. |
| Producing Properties | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| Fully Depleted Properties | | | | | | | | | | | | | |
| Alpha Project | | | 7.5% | | | $ | 13,214 | | | $ | 14,940 | | The Alpha Project, a single-well project, commenced production in 2012. The well reached the end of its productive life in fourth quarter 2014.The Fund expects to spend $1.7 million for asset retirement obligations. |
| Carrera Project | | 3.0% | | | $ | 4,875 | | | $ | 5,265 | | Production commenced in 2011. Well was periodically shut-in during 2014. On January 2, 2015, the well experienced mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that the estimated costs to bring the well back on production were not economic relative to the remaining reserves. Accordingly, the Fund has fully impaired the net book value of the well as of December 31, 2014. | | 3.0% | | | $ | 4,867 | | | $ | 5,564 | | 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 $0.7 million for asset retirement obligations. |
| Cobalt Project | | 12.0% | | | $ | 5,683 | | | $ | 6,055 | | Production commenced in 2009. Recompletions are planned for third quarter 2015 and fourth quarter 2016. | |
| Liberty Project | | 3.0% | | | $ | 4,512 | | | $ | 4,932 | | Production commenced in 2010. Well is currently producing, however, was shut-in periodically during 2014 due to maintenance activities. Recompletion is planned for 2016. | |
| Fully Depleted | | | | | | | | | | | | | |
| Alpha Project | | 7.5% | | | $ | 13,213 | | | $ | 14,188 | | Production commenced in 2012. Well reached the end of it productive life in fourth quarter 2014. | |
| Sold Properties | | | | | | | | | | | | | | | | | | | | | | | | |
| Raven Project well #1 & #2 | | 6.25% | | | $ | 2,863 | | | $ | 2,863 | | In January 2014, the Fund sold its interest in the Raven Project. See "Raven Sale" below for additional information. | |
| Raven Project | | | 6.25% | | | $ | 2,863 | | | $ | 2,863 | | In January 2014, the Fund sold its interest in the Raven Project. See "Raven Sale" below for additional information. |
Raven Sale
On January 17, 2014, the Fund, along with its affiliates, Ridgewood Energy Gulf of Mexico Oil and Gas Fund, L.P., Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy P Fund, LLC, and Ridgewood Energy W Fund, LLC, (when used with the Fund the “Ridgewood Funds”) entered into a purchase and sale agreement to sell the Ridgewood Funds’ interestsits interest in the Raven Project, located in the state waters of Louisiana, to Castex Energy Partners, L.P. for cash consideration totaling $21.7 million. The closing of the sale transaction occurred on January 30, 2014.
The Fund had a 6.25% working interest in the Raven Project and received $2.7 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.1 million, thereby resulting in a gain to the Fund of $2.6 million, which was recognized during the year ended December 31, 2014. There was no such amount recorded during the year ended December 31, 2015.
Marketing/Customers
The Manager, on behalf of the Fund, has engaged Energy Upgrade, Inc. to market the Fund’s oil and natural gas. The number of customers purchasing the Fund’s oil and natural gas may vary from time to time. Currently, and during 2014,2015, the Fund had twothree 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. The Manager believes thatFund has one non-producing property, the Beta Project, for which it is participating in the financing of platform and pipeline infrastructure. The Fund expects oil and natural gas from the Fund’s non-producing projects will have accessBeta Project to pipeline transportation and will be marketed through Energy Upgrade, Inc. The Fund is participating in the financing of both platform and pipeline infrastructure for its non-producing projects.
Natural gas is sold in the spot market at prevailing 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. LowDuring the year ended December 31, 2015, decreases in commodity prices could havehad an adverse effect on the Fund’s future profitability.profitability and distributions. Historically,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'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'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 2014.2015.
Operator
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 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 Apache Deepwater LLC, Deep Gulf Energy LP, LLOG Exploration Offshore, L.L.C., W&T Offshore, Inc. and Walter Oil & Gas Corporation.
Because the Fund does not operate any of the projects in which it has acquired a working interest, shareholders not only bear the risk that the Manager will be able to select suitable projects, but also that, once selected, 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’s 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 past practice has been 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 the 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 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's affiliates, yearly insurance 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 the Fund’sits 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, 2014,2015, the Fund has deposited $2.0$2.6 million from capital contributions and reinvested interest intoinvested in a salvage fund. AsOn a resultmonthly basis, the Fund expects to contribute to the salvage fund a portion of the significant capital required and number of wells anticipated foroperating income from the Beta, Diller and Marmalard projects, any furtherand upon commencement of production, the Beta Project, 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 athe salvage fund that remains after the Fund payshas paid for all of its share of the actual salvage costasset retirement obligations will be distributed to the shareholders and the Manager. There are no legal restrictions on the withdrawal or use ofwithdrawals from the salvage fund.
Competition
Strong competitionCompetition 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 also owns additional office space at 79 Turtle Point, Tuxedo Park, NY, 10987.125 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”). Federal offshore leases are managed both by the BOEM and the Bureau of Safety and Environmental Enforcement (the “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 proposed stricteradopted strict requirements for subsea drilling production equipment and has indicated that there will be an additional, separate rulemakingproposed new requirements to govern the design, performance and maintenance ofimplement equipment reliability improvements, building upon enhanced industry standards for blowout preventers but that rule hasand blowout prevention technologies, and reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment. These proposed requirements have not yet been published.become final. BSEE has also published a draftpolicy statement of policy on safety culture with nine proposed characteristics of a robust safety culture. 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 Guidance on Supplemental Bonding
On September 22, 2015, 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”) in replacement of an existing NTL on 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 some or all of the Draft Guidance will be issued by early 2016.
Sales and Transportation of Oil and Natural Gas
The Fund sells its proportionate share of oil and natural gas to the market through a marketer or a joint operating agreement 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 ("FERC"). The rates, terms and conditions are regulated by FERC pursuant to a variety of statutes, including the OCSLA, the Natural Gas Act of 1938, The Natural Gas Policy Act of 1978 and the Energy Policy Acts of 1992 and 2005.Commission. Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service. 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, most of the activities to which these federal, state and local environmental laws and regulations apply are conducted by the operator on the Fund’s behalf. Nevertheless, 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 $350$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 $75$133.65 million in other damages.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 compliance with the OPA’s financial assurance and other operating requirements will not have a material impact on its 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, 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 or material increases in the costs of production, development or exploration, or otherwise have a material adverse effect on the Fund’s operating results and cash flows.
Dodd-Frank Act. The Dodd-Frank Act, signed into law in July 2010, 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.
TheUnder 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 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 CFTC,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, the CFTC has set “speculative position limits” (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 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 the Fund alters any hedging program 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 2015 or 2014, a party to any derivative instruments or hedging programs.
Dodd-Frank 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, the SEC proposed new resource extraction rules. When any final rules are issued, the Fund will evaluate any impact of the rules on its business.
Not required.
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 for the years ended December 31, 20142015 and 2013.2014. 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, in-progress at December 31, 2014 and 2013 are expected towhich produce both oil and natural gas, and are located in the offshore waters of the Gulf of Mexico. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information about wells in-progress at December 31, 2014.2015.
| | | 2014 | | | 2013 | | | 2015 | | | 2014 | |
| | | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | | | Gross | | | Net | |
| Exploratory wells: | | | | | | | | | | | | | | | | | | | | | | | | |
| Productive | | | | 2 | | | | 0.02 | | | | - | | | | - | |
| In-progress | | | 3 | | | | 0.04 | | | | 3 | | | | 0.04 | | | | 1 | | | | 0.02 | | | | 3 | | | | 0.04 | |
| Exploratory well total | | | | 3 | | | | 0.04 | | | | 3 | | | | 0.04 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Development wells: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Productive | | | | 3 | | | | 0.03 | | | | - | | | | - | |
| In-progress | | | 2 | | | | 0.02 | | | | 1 | | | | 0.01 | | | | - | | | | - | | | | 2 | | | | 0.02 | |
| Development well total | | | | 3 | | | | 0.03 | | | | 2 | | | | 0.02 | |
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-five 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 at December 31, 20142015 and 20132014 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. At December 31, 2014,2015, the Fund had approximately 756 thousand barrels and 1.4 million mcf of proved undeveloped oil and natural gas reserves respectively, related to the Beta Diller and Marmalard projects. At December 31, 2013, the Fund had approximately 751projects totaling 0.5 million barrels of oil, 45 thousand barrels and 2.8 million mcf of proved undeveloped oil and natural gas reserves (inclusive of natural gas liquid (“NGL”) reserves), respectively. Suchand 0.7 million mcf of natural gas. At December 31, 2014, the Fund had proved undeveloped reserves are related to the Beta, Marmalard and Diller projects totaling 0.8 million barrels of oil and 1.4 million mcf of natural gas. The Beta, Diller and Marmalard projects which were determined to be discoveries in 2012, and the Raven Project.2012.
On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which included proved developed and undeveloped oil reserves of approximately 1 thousand barrels and 9 thousand barrels, respectively, and proved developed and undeveloped gas reserves, inclusive of NGL reserves, of approximately 0.3 million mcf and 1.4 million mcf, respectively.
During the year ended December 31, 2014,2015, the Fund incurred costs to advance the development of its proved undeveloped reserves of approximately $6.1$6.6 million, which related to the Beta, Diller and Marmalard projects. During 2015, the Diller and Marmalard projects commenced production. The Beta Project is expected to commence production in third quarter 2016. 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 development of the Fund’s non-producing properties,Beta and Marmalard projects, 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 for the years ended December 31, 20142015 and 20132014 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, 2014,2015, the Fund had no delivery obligations or delivery commitments under any existing contracts.
None.
None.
PART II
There is currently no established public trading market for the Shares. As of the date of this filing,January 31, 2016, there were 1,3881,409 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 develop the Beta, Diller and Marmalard projects, distributions have been impacted, and will 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. DuringThe Fund did not pay distributions during the yearsyear ended December 31, 2015. During the year ended December 31, 2014, and 2013, the Fund paid distributions totaling $2.1 million and $6.0 million, respectively.million.
Not required.
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 distributions to shareholders except as provided in the LLC Agreement.
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.
RevenuesCommodity 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 subjectcommercially recoverable. Significant declines in prices could result in non-cash charges to marketearnings due to impairment.
Since fourth quarter 2014, there has been a significant decline in oil and natural gas prices. 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, 2015 and 2014 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 which has beenis 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 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 availability of alternate fuel sources. |
Changes in commodity prices may significantly affect liquidity and expected operating results. Price changes will directly affect revenues. 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.
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 conformityaccordance 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 Exploration, Development and Acquisition Costs
Exploration, 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. Costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.”
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, and ongoing discussions with the wells’ operators.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, 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 value of its oil and gas properties wheneverannually 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 net bookcarrying value at the time of the review. If the net bookcarrying value exceeds theestimated future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using estimated future net discounted future cash flows from the property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred. 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 net cash flows from proved oil and natural gas reserves could change in the near term. Significant declines in oil and natural gas prices since fourth quarter 2014 have resulted in impairments of oil and gas properties. If oil and natural gas prices continue to decline, significantly, even if only for a short period of time, it is possible that write-downsadditional impairments of oil and gas properties couldwill occur.
Results of Operations
The following table summarizes the Fund’s results of operations for the years ended December 31, 20142015 and 2013,2014, 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, | | | Year ended December 31, | |
| | | 2014 | | | 2013 | | | 2015 | | | 2014 | |
| | | (in thousands) | | | (in thousands) | |
| Revenue | | | | | | | | | | | | |
| Oil and gas revenue | | $ | 5,189 | | | $ | 9,648 | | | $ | 3,193 | | | $ | 5,189 | |
| | | | | | | | | | |
| Expenses | | | | | | | | | | | | | | | | |
| Depletion, depreciation and amortization | | | 2,328 | | | | 3,415 | | |
| Dry-hole costs | | | - | | | | (220 | ) | |
| Depletion and amortization | | | | 2,487 | | | | 2,328 | |
| Impairment of oil and gas properties | | | 969 | | | | 1,212 | | | | 342 | | | | 969 | |
| Management fees to affiliate | | | 1,680 | | | | 1,750 | | | | 1,218 | | | | 1,680 | |
| Operating expenses | | | 1,375 | | | | 2,274 | | | | 2,205 | | | | 1,466 | |
| General and administrative expenses | | | 251 | | | | 346 | | | | 158 | | | | 160 | |
| Total expenses | | | 6,603 | | | | 8,777 | | | | 6,410 | | | | 6,603 | |
| Gain on sale of oil and gas properties | | | 2,599 | | | | - | | | | - | | | | 2,599 | |
| Income from operations | | | 1,185 | | | | 871 | | |
| (Loss) income from operations | | | | (3,217 | ) | | | 1,185 | |
| Other income | | | | | | | | | |
| Dividend income | | | | 75 | | | | - | |
| Interest income | | | 15 | | | | 19 | | | | 8 | | | | 15 | |
| Net income | | $ | 1,200 | | | $ | 890 | | |
| Total other income | | | | 83 | | | | 15 | |
| Net (loss) income | | | $ | (3,134 | ) | | $ | 1,200 | |
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, 20142015 and 2013.2014. NGL sales are included within gas sales.
| | | Year ended December 31, | | | Year ended December 31, | |
| | | 2014 | | | 2013 | | | 2015 | | | 2014 | |
| Number of wells producing | | | 4 | | | | 6 | | | | 7 | | | | 4 | |
| Total number of production days | | | 1,178 | | | | 1,685 | | | | 1,425 | | | | 1,178 | |
| Oil sales (in thousands of barrels) | | | 41 | | | | 55 | | | | 58 | | | | 41 | |
| Average oil price per barrel | | $ | 94 | | | $ | 106 | | | $ | 47 | | | $ | 94 | |
| Gas sales (in thousands of mcfs) | | | 280 | | | | 1,006 | | | | 179 | | | | 280 | |
| Average gas price per mcf | | $ | 4.81 | | | $ | 4.09 | | | $ | 2.42 | | | $ | 4.81 | |
The decreases inDuring the number of wells producing,year ended December 31, 2015, production days and sales volumes were primarily attributable toimpacted by the Ravencommencement of production of four wells in the Marmalard Project which was soldand one well in January 2014, the AlphaDiller Project, which was determined to be fully depleted during fourth quarter 2014 andpartially offset by the CarreraLiberty Project, which was shut-in periodically throughout 2014 due to ongoing mechanical issues and various repair and maintenance activities.during fourth quarter 2015. During January 2015, the Fund determined that the Carrera Project was no longer mechanically capable of producing and has determined that the well was fully impaired atyear ended December 31, 2014. 2014, the Alpha and Carrera projects reached the end of their productive lives. See Item 1. “Business” of this Annual Report under the heading “Properties” for more information.
Oil and Gas Revenue. 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 is 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, the Fund records revenue at the net price received from the purchaser. The second type of agreement is one whereby the Fund pays transportation expense directly. In that case, transportation expense is included within operating expense in the statements of operations.
Oil and gas revenue for the year ended December 31, 20142015 was $5.2$3.2 million, a decrease of $4.5$2.0 million from the year ended December 31, 2013.2014. The decrease was attributable to decreased oil and gas prices totaling $3.2 million, partially offset by increased sales volume totaling $4.2 million, of which $2.0 million related to the sale of the Raven Project, coupled with the impact of the change in average prices totaling $0.3$1.2 million. See “Overview” above for additional information.factors that impact the oil and gas revenue sales volume and rate variances.
Depletion Depreciation and Amortization. Depletion depreciation and amortization for the year ended December 31, 20142015 was $2.3$2.5 million, a decreasean increase of $1.1$0.2 million from the year ended December 31, 2013.2014. The decrease resulted from a decrease in production volumes totaling $2.1 million, partially offset by an increase in average depletion rates totaling $1.0 million. The increase in average depletion rates was attributable to the reductionadjustments to asset retirement obligations of lower cost reserves related to the sale of the Raven Project coupled with a decrease in reserve estimates$1.0 million, related to the Alpha Project.and Carrera projects, fully depleted properties, partially offset by a decrease in the average depletion rate totaling $0.9 million. The decrease in the average depletion rate was primarily attributable to the Alpha and Carrera projects, which had higher cost reserves and did not produce in 2015. See “Overview” above for additional information.
Dry-hole Costs. Dry-hole costscertain factors that impact the depletion and amortization volume and rate variances. Depletion and amortization rates are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gasalso impacted by changes in sufficient quantities to justify completion ofreserve estimates provided annually by the well. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. During the year ended December 31, 2014, the Fund did not record dry-hole costs. During the year ended December 31, 2013, the Fund recorded credits to dry-hole costs of $0.2 million, which related to wells that were determined to be dry holes in prior years.Fund’s independent petroleum engineers.
Impairment of Oil and Gas Properties. During Januarythe year ended December 31, 2015, the Carrera Project was shut-in due to ongoing mechanical issuesFund recorded an impairment of oil and gas properties of $0.3 million related to a blockagethe Cobalt Project, which was attributable to both declines in future oil and gas prices and revisions to reserve estimates as provided by the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves and the well was fully impaired. Accordingly, duringFund’s independent petroleum engineers. During the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $1.0 million representing the remaining net book value at the date of impairment. During the year ended December 31, 2013, the Fund recorded an impairment of oil and gas properties of $1.2 million related to the CobaltCarrera Project, which was attributabledetermined to both declines in future oilbe uneconomic relative to the remaining reserves and gas prices and an increase in estimated asset retirement costs.the well was fully impaired.
Management Fees to Affiliate. Management fees for the years ended December 31, 2014 and 2013 were $1.7 million and $1.8 million, respectively. 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.
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, | |
| | | 2014 | | | 2013 | |
| | | (in thousands) | |
| Lease operating expense | | $ | 1,066 | | | $ | 1,778 | |
| Workover expense | | | 243 | | | | 441 | |
| Accretion expense | | | 48 | | | | 25 | |
| Geological costs | | | 18 | | | | 30 | |
| | | $ | 1,375 | | | $ | 2,274 | |
Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”. The average production cost was $12.21 per barrel of oil equivalent (“BOE”) during the year ended December 31, 2014 compared to $7.69 per BOE during the year ended December 31, 2013. Workover expense represents costs to restore or stimulate production of existing reserves. Accretion expense related to the asset retirement obligations established for the Fund’s proved properties. Geological costs represent costs incurred to obtain seismic data, surveys, and lease rentals.
General| | | Year ended December 31, | |
| | | 2015 | | | 2014 | |
| | | (in thousands) | |
| Lease operating expense | | $ | 1,703 | | | $ | 1,066 | |
| Insurance expense | | | 196 | | | | 91 | |
| Accretion expense | | | 170 | | | | 48 | |
| Transportation expense | | | 153 | | | | - | |
| Workover expense and other | | | (17 | ) | | | 261 | |
| | | $ | 2,205 | | | $ | 1,466 | |
Lease operating expense and Administrative Expenses.General and administrative expenses represent costs specifically identifiable or allocabletransportation expense relates to the Fund, as detailed in the following table.
| | | Year ended December 31, | |
| | | 2014 | | | 2013 | |
| | | (in thousands) | |
| Accounting and professional fees | | $ | 124 | | | $ | 115 | |
| Insurance expense | | | 123 | | | | 212 | |
| Trust fees and other | | | 4 | | | | 19 | |
| | | $ | 251 | | | $ | 346 | |
Accounting and professional fees represent expenses for audits, quarterly reviews, tax preparation, reserve data engineering and reporting, and administration of filings.Fund’s producing properties. Insurance expense represents premiums related to producing well and control of well insurance, which varies depending upon the number of wells producing or drilling,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 $23.30 per barrel of oil equivalent (“BOE”) during the year ended December 31, 2015, compared to $12.21 per BOE during the year ended December 31, 2014. The increase is principally attributable to the impact of costs associated with the commencement of production for the Marmalard and Diller projects. Accretion expense relates to the asset retirement obligations established for the Fund’s proved properties. Workover expense represents costs to restore or stimulate production of existing reserves.
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. Trust fees represent bank fees associated with the management of the Fund’s cash accounts.insurance expense.
Gain on Sale of Oil and Gas Properties. The Fund did not record a gain on sale of oil and gas properties during the year ended December 31, 2015. During the year ended December 31, 2014, the Fund recorded a gain on sale of oil and gas properties of $2.6 million related to the Raven Project. See Item 1. “Business”��Business” of this Annual Report under the heading “Properties” for additional information regarding the sale. There were no such amounts recorded during
Dividend Income. Dividend income is related to the year ended December 31, 2013.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 and held-to-maturity investments.fund.
Capital Resources and Liquidity
Operating Cash Flows
Cash flows used in operating activities for the year ended December 31, 2015 were $0.2 million, related to operating expenses of $2.0 million, management fees of $1.2 million and general and administrative expenses of $0.1 million, partially offset by revenue received of $3.0 million and dividend income received of $0.1 million.
Cash flows provided by operating activities for the year ended December 31, 2014 were $2.5 million, primarily related to revenue received of $5.6 million, partially offset by management fees of $1.7 million, operating expenses paid of $1.3 million, and general and administrative expenses paid of $0.2 million.
Investing Cash Flows
Cash flows provided by operatingused in investing activities for the year ended December 31, 20132015 were $6.3$8.0 million, primarily related to revenue receivedcapital expenditures for oil and gas properties and investment in Delta House of $10.6 million, partially offset by operating expenses paid of $2.2 million, management fees of $1.8$7.5 million and generalinvestments in the salvage fund of $0.5 million. See Note 1 of “Notes to Financial Statements” - “Organization and administrative expenses paidSummary of $0.3 million.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.
Investing Cash Flows
Cash flows used in investing activities for the year ended December 31, 2014 were $4.0 million, related to capital expenditures for oil and gas properties and investment in Delta House of $5.9 million, inclusive of advances, and investments in the salvage fund of $0.8 million, partially offset by proceeds from the sale of the Raven Project of $2.7 million.
Financing Cash Flows
There were no cash flows used in investingfrom financing activities for the year ended December 31, 2013 were $3.0 million, primarily related to investments in U.S. Treasury securities of $7.5 million, capital expenditures for oil and gas properties of $2.9 million, inclusive of advances, and investments in the salvage fund of $0.1 million, partially offset by the proceeds from the maturity of investments in U.S. Treasury securities of $7.5 million.2015.
Financing Cash Flows
Cash flows used in financing activities for the year ended December 31, 2014 were $2.1 million, related to manager and shareholder distributions.
Cash flows used in financing activities for the year ended December 31, 2013 were $6.0 million, related to manager and shareholder distributions.
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, 2014,2015, the Fund has several non-producinghad three properties, the Beta, Diller and Marmalard projects, for which additional development costs must be incurred in order to commence production.incurred. The Fund currently expects to spend an additional $14.1$9.9 million (which includes asset retirement obligations) related to the development of these projects, which the Fund anticipates will include the development of twelve wells, four in the Beta Project, and eighttwo in the Diller Project and six in the Marmalard projects,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. See “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, which may be all the capital it will obtain.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 and income earned therefrom.on-hand.
As of December 31, 2014,2015, the Fund’s estimated capital commitments related to its oil and gas properties were $16.3$13.4 million (which include asset retirement obligations for the Fund’s projects of $4.4$5.6 million), of which $6.3$4.2 million is expected to be spent during the year ending December 31, 2015.2016. These expected capital commitments exceed available working capital and salvage fund by $5.6$9.5 million at December 31, 2014.2015.
Based upon its current cash position, and its current reserve estimates and its current development plan of the Beta Project, 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. However, if cash flow from operations is not sufficient to meet the Fund’s capital requirements, the Manager will take action, which may include adjusting its management fee temporarily to accommodate the Fund’s short-term capital requirements.
The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year.
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 develop the Beta, Diller and Marmalard projects, distributions have been impacted, and will 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 at December 31, 20142015 and 20132014 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 at December 31, 20142015 and 20132014, other than those discussed in “Estimated Capital Expenditures” above.
Recent Accounting Pronouncements
The Fund has consideredSee 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 and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.pronouncements.
Not required.
| 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, Financial Statement Schedules” and filed as part of this report.
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, 2014.2015. 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, 2014.2015. 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, 2014,2015, 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, 20142015 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.
None.
None.
PART III
| 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 at December 31, 20142015 are as follows:
Name, Age and Position with Registrant |
| |
Robert E. Swanson, 6768 Chief Executive Officer |
| |
Kenneth W. Lang, 6061 President and Chief Operating Officer |
| |
Kathleen P. McSherry, 4950 Executive Vice President and Chief Financial Officer |
| |
Robert L. Gold, 5657 Executive Vice President |
| |
Daniel V. Gulino, 5455 Senior Vice President, General Counsel and Secretary |
The officers in the above table have been officers of the Fund since March 25, 2008, the date of inception of the Fund, with the exception of Mr. Lang, who has been an officer of the Fund since June 2009. The officers are employed by and paid exclusively by the Manager. Set forth below is certain biographical information regarding the executive officers of Ridgewood Energy and the Fund:
Robert E. Swanson has served as the Chairman, Chief Executive Officer, and controlling shareholder of Ridgewood Energy since its inception and is the Chairman of the Investment Committee. Mr. Swanson is also the Chairman of Ridgewood Capital Management, LLC and Ridgewood Private Equity Partners, LLC, and President of Ridgewood Securities Corporation, affiliates of Ridgewood Energy. Mr. Swanson is an inactive member of the New York and New Jersey State Bars. He is a graduate of Amherst College and Fordham University Law School.
Kenneth W. Lang has served as the President and Chief Operating Officer of Ridgewood Energy since June 2009 and is a member of the Investment Committee. Prior to joining the Fund, Mr. Lang was with BP for twenty-four years, ultimately serving for his last two years with BP as Senior Vice President for BP’s Gulf of Mexico business and a member of the Board of Directors for BP America, Inc. Prior to that, Mr. Lang was Vice President – Production for BP. After twenty-four years of service to BP, Mr. Lang retired and devoted fifteen months of personal time to pursue and explore other interests. Mr. Lang is a graduate of the University of Houston.
Kathleen P. McSherry has served as the Executive Vice President and Chief Financial Officer of Ridgewood Energy since 2001. Ms. McSherry holds a Bachelor of Science degree in Accounting.Accounting from Kean University.
Robert L. Gold has served as a senior officer of Ridgewood Energy since 1987 and is a member of the Investment Committee. Mr. Gold has also served as the President and Chief Executive Officer of Ridgewood Capital since its inception in 1998. Mr. Gold is a member of the New York State Bar. Mr. Gold is a graduate of Colgate University and New York University School of Law.
Daniel V. Gulino is Senior Vice President - Legal Affairs and Secretary for Ridgewood Energy and has served as counselin that capacity for Ridgewood Energy since 2003. Mr. Gulino also serves as Senior Vice President of Legal Affairs of Ridgewood Capital Management, LLC and Ridgewood Private Equity Partners, LLC and Senior Vice President & General Counsel of Ridgewood Securities Corporation. Mr. Gulino is a member of the New Jersey State and Pennsylvania State Bars. Mr. Gulino is a graduate of Fairleigh Dickinson University and Rutgers School of Law.
Board of Directors and Board Committees
The Fund does not have its own board of directors or any board committees. The Fund relies upon the Manager to provide recommendations regarding dispositions and financial disclosure. Officers of the Fund are not compensated by the Fund, and all compensation matters are addressed by the Manager, as described in Item 11. “Executive Compensation” of this Annual Report. Because the Fund does not maintain a board of directors and because officers of the Fund are compensated by the Manager, the Manager believes that it is appropriate for the Fund to not have a nominating or compensation committee.
Code of Ethics
The Manager has adopted a code of ethics for all employees, including the Manager’s principal executive officer and principal financial and accounting officer. If any amendments are made to the code of ethics or the Manager grants any waiver, including any implicit waiver, from a provision of the code that applies to the Manager’s executive officers or principal financial and accounting officer, the Fund will disclose the nature of such amendment or waiver on the Manager’s website or in a current report on Form 8-K. Copies of the code of ethics are available, without charge, on the Manager’s website at www.ridgewoodenergy.com and in print upon written request to the business address of the Manager at 14 Philips Parkway, Montvale, New Jersey 07645, ATTN: General Counsel.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act, as amended, requires the Fund’s executive officers and directors, and persons who own more than 10% of a registered class of the Fund’s equity securities, to file reports of ownership and changes in ownership with the SEC. Based on a review of the copies of reports furnished or otherwise available to the Fund, the Fund believes that during the year ended December 31, 2014,2015, all filing requirements applicable to its officers, directors and 10% beneficial owners were met on a timely basis.
The executive officers of the Fund do not receive compensation from the Fund. The Manager and its affiliates compensate the officers without additional payments by the Fund. See Item 13. “Certain Relationships and Related Transactions, and Director Independence” of this Annual Report for more information regarding Manager compensation and payments to affiliated entities.
Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Percentage of beneficial ownership is based on 492.3709 Shares outstanding as of the date of this filing.January 31, 2016. No officer of the Manager or the Fund owns any of the Shares and no person owns more than 5% of the Shares.
Pursuant to the terms of the LLC Agreement, the Manager renders management, administrative and advisory services to the Fund. For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. Management fees for the years ended December 31, 2015 and 2014 and 2013 were $1.7$1.2 million and $1.8$1.7 million, respectively.
The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. The Fund did not pay distributions for year ended December 31, 2015. Distributions paid to the Manager for the yearsyear ended December 31, 2014 and 2013 were $0.3 million and $0.90.3 million, respectively..
At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.
None of the amounts paid to the Manager have been derived as a result of arm’s length negotiations.
The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager.
Profits and losses are allocated in accordance with the LLC Agreement. In general, profits and losses in any year are allocated 85% to shareholders and 15% to the Manager. The primary exception to this treatment is that all items of expense, loss, deduction and credit attributable to the expenditure of shareholders’ capital contributions are allocated 99% to shareholders and 1% to the Manager.
The following table presents fees for services rendered by Deloitte & Touche LLP for the years ended December 31, 20142015 and 2013.2014.
| | | Year ended December 31, | |
| | | 2014 | | | 2013 | |
| | | (in thousands) | |
Audit fees (1) | | $ | 85 | | | $ | 85 | |
| | | Year ended December 31, | |
| | | 2015 | | | 2014 | |
| | | (in thousands) | |
Audit fees (1) | | $ | 88 | | | $ | 85 | |
| (1) | Fees for audit of annual financial statements, reviews of the related quarterly financial statements, and reviews of documents filed with the SEC. |
PART IV
(a) (1) Financial Statements
See “Index to Financial Statements” set forth on page F-1.
(a) (2) Financial Statement Schedules
None.
(a) (3)
EXHIBIT NUMBER | TITLE OF EXHIBIT
| | TITLE OF EXHIBIT | | METHOD OF FILING |
| | | | |
| 3.1 | | Certificate of Formation of Ridgewood Energy Y Fund, LLC dated March 25, 2008 | | Incorporated by reference to the Fund's Form 10 filed on February 17, 2009 |
| | | | | |
| 3.2 | | Amended Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy Y Fund, LLC dated April 13, 2011 | | Incorporated by reference to the Fund's Form 10Q filed on April 28, 2011 |
| | | | | |
| 31.1 | | Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a) | | Filed herewith |
| | | | | |
| 31.2 | | Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a) | | Filed herewith |
| | | | | |
| 32 | | Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund | | Filed herewith |
| | | | | |
| 99.1 | | Report of Netherland, Sewell & Associates, Inc. | | Filed herewith |
| | | | | |
| 101.INS | | XBRL Instance Document | | Filed herewith |
| | | | | |
| 101.SCH | | XBRL Taxonomy Extension Schema | | Filed herewith |
| | | | | |
| 101.CAL | | XBRL Taxonomy Extension Calculation Linkbase | | Filed herewith |
| | | | | |
| 101.DEF | | XBRL Taxonomy Extension Definition Linkbase Document | | Filed herewith |
| | | | | |
| 101.LAB | | XBRL Taxonomy Extension Label Linkbase | | Filed herewith |
| | | | | |
| 101.PRE | | XBRL Taxonomy Extension Presentation Linkbase | | Filed herewith |
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.
| | RIDGEWOOD ENERGY Y FUND, LLC | |
| | | | |
| | | | |
Date: February 24, 201526, 2016 | By: | /s/ ROBERT E. SWANSON | |
| | | Robert E. Swanson | |
| | Chief Executive Officer | |
| | (Principal Executive Officer) | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Signature | Capacity | Date |
| | | February 24, 2015
|
| /s/ ROBERT E. SWANSON | Chief Executive Officer (Principal Executive Officer)
| February 26, 2016 |
| Robert E. Swanson | (Principal Executive Officer) | |
| | | |
| | | |
| /s/ KATHLEEN P. MCSHERRY | Executive Vice President and Chief Financial Officer | February 26, 2016 |
| Kathleen P. McSherry | (Principal Financial and Accounting Officer) | February 24, 2015 |
Kathleen P. McSherry | |
| | | |
| RIDGEWOOD ENERGY CORPORATION | | |
| | | |
| BY: /s/ ROBERT E. SWANSON | Chief Executive Officer of the Manager | February 24, 201526, 2016 |
| Robert E. Swanson | | |
| INDEX TO FINANCIAL STATEMENTS | PAGE |
| | |
| F-2 |
| F-3 |
| F-4 |
| F-5 |
| F-6 |
| F-7 |
| F-12 |
To the Shareholders and Manager of Ridgewood Energy Y Fund, LLC:
We have audited the accompanying balance sheets of Ridgewood Energy Y Fund, LLC (the “Fund”) as of December 31, 20142015 and 2013,2014, and the related statements of operations, changes in members’ capital, and cash flows for the years then ended. These financial statements are the responsibility of the Fund’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Fund 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 Fund’s internal control over financial reporting. Accordingly, we express no such opinion.opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Ridgewood Energy Y Fund, LLC as of December 31, 20142015 and 2013,2014, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Emphasis of Matter
As discussed in Note 4 to the financial statements, the Fund’s estimated capital commitments are $13.4 million, of which $4.2 million is expected to be spent during the year ending December 31, 2016. Based upon its current cash position, its current reserve estimates and its current development plan of the Beta Project, 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. However, if cash flow from operations is not sufficient to meet the Fund’s capital requirements, the Manager will take action, which may include adjusting its management fee temporarily to accommodate the Fund’s short-term capital requirements. Our opinion is not modified with respect to this matter.
/s/ Deloitte & Touche LLP
Parsippany, New Jersey
February 24, 201526, 2016
RIDGEWOOD ENERGY Y FUND, LLC
(in thousands, except share data)
| | | December 31, | | | December 31, | |
| | | 2014 | | | 2013 | | | 2015 | | | 2014 | |
| Assets | | | | | | | | | | | | |
| Current assets: | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 9,712 | | | $ | 13,330 | | | $ | 1,462 | | | $ | 9,712 | |
| Salvage fund | | | | 711 | | | | - | |
| Production receivable | | | 158 | | | | 617 | | | | 363 | | | | 158 | |
| Asset held for sale | | | - | | | | 317 | | |
| Other current assets | | | 36 | | | | 99 | | | | - | | | | 36 | |
| Total current assets | | | 9,906 | | | | 14,363 | | | | 2,536 | | | | 9,906 | |
| Salvage fund | | | 2,021 | | | | 1,216 | | | | 1,850 | | | | 2,021 | |
| Other assets | | | 30 | | | | 89 | | | | - | | | | 30 | |
| Investment in Delta House | | | | 572 | | | | 318 | |
| Oil and gas properties: | | | | | | | | | | | | | | | | |
| Advances to operators for working interests and expenditures | | | 589 | | | | 101 | | | | - | | | | 589 | |
| Proved properties | | | 24,408 | | | | 35,998 | | | | 31,872 | | | | 29,289 | |
| Equipment and facilities - in progress | | | 5,199 | | | | 2,119 | | |
| Less: accumulated depletion, depreciation and amortization | | | (14,678 | ) | | | (25,527 | ) | |
| Less: accumulated depletion and amortization | | | | (11,272 | ) | | | (14,678 | ) |
| Total oil and gas properties, net | | | 15,518 | | | | 12,691 | | | | 20,600 | | | | 15,200 | |
| Total assets | | $ | 27,475 | | | $ | 28,359 | | | $ | 25,558 | | | $ | 27,475 | |
| | | | | | | | | | | | | | | | | |
| Liabilities And Members' Capital | | | | | | | | | | | | | | | | |
| Current liabilities: | | | | | | | | | | | | | | | | |
| Due to operators | | $ | 1,157 | | | $ | 1,039 | | | $ | 487 | | | $ | 1,157 | |
| Accrued expenses | | | 44 | | | | 42 | | | | 92 | | | | 44 | |
| Liability held for sale | | | - | | | | 171 | | |
| Asset retirement obligations | | | | 711 | | | | - | |
| Total current liabilities | | | 1,201 | | | | 1,252 | | | | 1,290 | | | | 1,201 | |
| Asset retirement obligations | | | 2,154 | | | | 2,087 | | | | 3,282 | | | | 2,154 | |
| Total liabilities | | | 3,355 | | | | 3,339 | | | | 4,572 | | | | 3,355 | |
| | | | | | | | | | |
| Commitments and contingencies (Note 4) | | | | | | | | | | | | | | | | |
| | | | | | | | | | |
| Members' capital: | | | | | | | | | | | | | | | | |
| Manager: | | | | | | | | | | | | | | | | |
| Distributions | | | (4,153 | ) | | | (3,838 | ) | | | (4,153 | ) | | | (4,153 | ) |
| Retained earnings | | | 3,352 | | | | 3,067 | | | | 3,304 | | | | 3,352 | |
| Manager's total | | | (801 | ) | | | (771 | ) | | | (849 | ) | | | (801 | ) |
| | | | | | | | | | |
| Shareholders: | | | | | | | | | | | | | | | | |
| Capital contributions (500 shares authorized; | | | | | | | | | | | | | | | | |
| 492.3709 issued and outstanding) | | | 97,818 | | | | 97,818 | | | | 97,818 | | | | 97,818 | |
| Syndication costs | | | (11,668 | ) | | | (11,668 | ) | | | (11,668 | ) | | | (11,668 | ) |
| Distributions | | | (25,174 | ) | | | (23,389 | ) | | | (25,174 | ) | | | (25,174 | ) |
| Accumulated deficit | | | (36,055 | ) | | | (36,970 | ) | | | (39,141 | ) | | | (36,055 | ) |
| Shareholders' total | | | 24,921 | | | | 25,791 | | | | 21,835 | | | | 24,921 | |
| Total members' capital | | | 24,120 | | | | 25,020 | | | | 20,986 | | | | 24,120 | |
| Total liabilities and members' capital | | $ | 27,475 | | | $ | 28,359 | | | $ | 25,558 | | | $ | 27,475 | |
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY Y FUND, LLC
(in thousands, except per share data)
| | | Year ended December 31, | | | Year ended December 31, | |
| | | 2014 | | | 2013 | | | 2015 | | | 2014 | |
| Revenue | | | | | | | | | | | | |
| Oil and gas revenue | | $ | 5,189 | | | $ | 9,648 | | | $ | 3,193 | | | $ | 5,189 | |
| | | | | | | | | | |
| Expenses | | | | | | | | | | | | | | | | |
| Depletion, depreciation and amortization | | | 2,328 | | | | 3,415 | | |
| Dry-hole costs | | | - | | | | (220 | ) | |
| Depletion and amortization | | | | 2,487 | | | | 2,328 | |
| Impairment of oil and gas properties | | | 969 | | | | 1,212 | | | | 342 | | | | 969 | |
| Management fees to affiliate (Note 3) | | | 1,680 | | | | 1,750 | | | | 1,218 | | | | 1,680 | |
| Operating expenses | | | 1,375 | | | | 2,274 | | | | 2,205 | | | | 1,466 | |
| General and administrative expenses | | | 251 | | | | 346 | | | | 158 | | | | 160 | |
| Total expenses | | | 6,603 | | | | 8,777 | | | | 6,410 | | | | 6,603 | |
| Gain on sale of oil and gas properties | | | 2,599 | | | | - | | | | - | | | | 2,599 | |
| Income from operations | | | 1,185 | | | | 871 | | |
| (Loss) income from operations | | | | (3,217 | ) | | | 1,185 | |
| Other income | | | | | | | | | |
| Dividend income | | | | 75 | | | | - | |
| Interest income | | | 15 | | | | 19 | | | | 8 | | | | 15 | |
| Net income | | $ | 1,200 | | | $ | 890 | | |
| Total other income | | | | 83 | | | | 15 | |
| Net (loss) income | | | $ | (3,134 | ) | | $ | 1,200 | |
| | | | | | | | | | | | | | | | | |
| Manager Interest | | | | | | | | | | | | | | | | |
| Net income | | $ | 285 | | | $ | 758 | | |
| Net (loss) income | | | $ | (48 | ) | | $ | 285 | |
| | | | | | | | | | | | | | | | | |
| Shareholder Interest | | | | | | | | | | | | | | | | |
| Net income | | $ | 915 | | | $ | 132 | | |
| Net income per share | | $ | 1,858 | | | $ | 268 | | |
| Net (loss) income | | | $ | (3,086 | ) | | $ | 915 | |
| Net (loss) income per share | | | $ | (6,268 | ) | | $ | 1,858 | |
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY Y FUND, LLC
(in thousands, except share data)
| | | # of Shares | | | Manager | | | Shareholders | | | Total | | | # of Shares | | | Manager | | | Shareholders | | | Total | |
| Balances, December 31, 2012 | | | 492.3709 | | | $ | (624 | ) | | $ | 30,786 | | | $ | 30,162 | | |
| Distributions | | | - | | | | (905 | ) | | | (5,127 | ) | | | (6,032 | ) | |
| Net income | | | - | | | | 758 | | | | 132 | | | | 890 | | |
| Balances, December 31, 2013 | | | 492.3709 | | | | (771 | ) | | | 25,791 | | | | 25,020 | | | | 492.3709 | | | $ | (771 | ) | | $ | 25,791 | | | $ | 25,020 | |
| Distributions | | | - | | | | (315 | ) | | | (1,785 | ) | | | (2,100 | ) | | | - | | | | (315 | ) | | | (1,785 | ) | | | (2,100 | ) |
| Net income | | | - | | | | 285 | | | | 915 | | | | 1,200 | | | | - | | | | 285 | | | | 915 | | | | 1,200 | |
| Balances, December 31, 2014 | | | 492.3709 | | | $ | (801 | ) | | $ | 24,921 | | | $ | 24,120 | | | | 492.3709 | | | | (801 | ) | | | 24,921 | | | | 24,120 | |
| Net loss | | | | - | | | | (48 | ) | | | (3,086 | ) | | | (3,134 | ) |
| Balances, December 31, 2015 | | | | 492.3709 | | | $ | (849 | ) | | $ | 21,835 | | | $ | 20,986 | |
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY Y FUND, LLC
(in thousands)
| | | Year ended December 31, | | | Year ended December 31, | |
| | | 2014 | | | 2013 | | | 2015 | | | 2014 | |
| | | | | | | | | | | | | |
| Cash flows from operating activities | | | | | | | | | | | | |
| Net income | | $ | 1,200 | | | $ | 890 | | |
| Adjustments to reconcile net income to net cash | | | | | | | | | |
| provided by operating activities: | | | | | | | | | |
| Depletion, depreciation and amortization | | | 2,328 | | | | 3,415 | | |
| Dry-hole costs | | | - | | | | (220 | ) | |
Net (loss) income | | | $ | (3,134 | ) | | $ | 1,200 | |
| Adjustments to reconcile net (loss) income to net cash | | | | | | | | | |
| (used in) provided by operating activities: | | | | | | | | | |
| Depletion and amortization | | | | 2,487 | | | | 2,328 | |
| Impairment of oil and gas properties | | | 969 | | | | 1,212 | | | | 342 | | | | 969 | |
| Gain on sale of oil and gas properties | | | (2,599 | ) | | | - | | | | - | | | | (2,599 | ) |
| Accretion expense | | | 48 | | | | 25 | | | | 170 | | | | 48 | |
| Changes in assets and liabilities: | | | | | | | | | | | | | | | | |
| Decrease in production receivable | | | 459 | | | | 929 | | |
| (Increase) decrease in production receivable | | | | (205 | ) | | | 459 | |
| Decrease in other current assets | | | 63 | | | | 56 | | | | 36 | | | | 63 | |
| Increase in due to operators | | | 21 | | | | 3 | | | | 49 | | | | 21 | |
| Increase in accrued expenses | | | 2 | | | | - | | | | 48 | | | | 2 | |
| Net cash provided by operating activities | | | 2,491 | | | | 6,310 | | |
| Net cash (used in) provided by operating activities | | | | (207 | ) | | | 2,491 | |
| | | | | | | | | | | | | | | | | |
| Cash flows from investing activities | | | | | | | | | | | | | | | | |
| Proceeds from sale of oil and gas properties | | | 2,745 | | | | - | | | | - | | | | 2,745 | |
| Payments to operators for working interests | | | | | | | | | | | | | | | | |
| and expenditures | | | (589 | ) | | | (101 | ) | | | - | | | | (589 | ) |
| Capital expenditures for oil and gas properties | | | (5,360 | ) | | | (2,783 | ) | | | | | | | | |
| Investments in marketable securities | | | - | | | | (7,499 | ) | |
| Proceeds from maturity of investments | | | - | | | | 7,500 | | |
| and investment in Delta House | | | | (7,503 | ) | | | (5,360 | ) |
| Investments in salvage fund | | | (805 | ) | | | (81 | ) | | | (540 | ) | | | (805 | ) |
| Net cash used in investing activities | | | (4,009 | ) | | | (2,964 | ) | | | (8,043 | ) | | | (4,009 | ) |
| | | | | | | | | | | | | | | | | |
| Cash flows from financing activities | | | | | | | | | | | | | | | | |
| Distributions | | | (2,100 | ) | | | (6,032 | ) | | | - | | | | (2,100 | ) |
| Net cash used in financing activities | | | (2,100 | ) | | | (6,032 | ) | | | - | | | | (2,100 | ) |
| | | | | | | | | | | | | | | | | |
| Net decrease in cash and cash equivalents | | | (3,618 | ) | | | (2,686 | ) | | | (8,250 | ) | | | (3,618 | ) |
| Cash and cash equivalents, beginning of year | | | 13,330 | | | | 16,016 | | | | 9,712 | | | | 13,330 | |
| Cash and cash equivalents, end of year | | $ | 9,712 | | | $ | 13,330 | | | $ | 1,462 | | | $ | 9,712 | |
| | | | | | | | | | | | | | | | | |
| Supplemental schedule of non-cash investing activities | | | | | | | | | | | | | | | | |
Advances used for capital expenditures in oil and gas properties reclassified to proved properties | | $ | 101 | | | $ | - | | | $ | 589 | | | $ | 101 | |
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY Y FUND, LLC
1. Organization and Summary of Significant Accounting Policies
Organization
The Ridgewood Energy Y Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on March 25, 2008 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of May 1, 2008 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The Fund was organized to primarily 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 Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project investments, the Manager locates potential projects, conducts due diligence, and negotiates and completes the transactions in which the investments are made. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 3 and 4.
Use of Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to the fair value of financial instruments, property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.
Reclassifications
The Fund’s financial statements for prior periods include reclassifications that were made to conform to the current-year presentation.
Fair Value Measurements
The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consists of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuationsinputs are derived fromunobservable inputs that are significant and unobservable;include situations where there is little, if any, market activity for the instrument; hence, these valuationsinputs have the lowest priority. Cash and cash equivalents approximate fair value based on Level 1 inputs.
Cash and Cash Equivalents
All highly liquid investments with maturities, when purchased, of three months or less, are considered cash and cash equivalents. At times, depositsdeposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution. At December 31, 2014,2015, the Fund’s bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.
Salvage Fund
The Fund deposits in a separate interest-bearing account, or salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives in accordance with applicable federal and state laws and regulations. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.
Investment in Delta House
The Fund has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by LLOG Exploration Company. The Fund accounts for its investment in Delta House using the cost method of accounting for investments as it does not have the ability to exercise significant influence over such investment. Under the cost method, the Fund recognizes an investment in the equity of an investee at cost. The Fund recognizes as income dividends received that are distributed from net accumulated earnings of the investee since the date of acquisition by the Fund. Dividends received in excess of earnings subsequent to the date of investment are considered a return of investment and are recorded as reductions of cost of the investment. The fair value of this investment is not estimated because there are no identified events or changes in circumstances that may have a significant adverse effect on the fair value of the investment.
The aggregate prior year balance of the Fund’s investment in Delta House was classified as “Equipment and facilities – in progress” within “Oil and gas properties” in the Fund’s December 31, 2014 balance sheet. Such amount has been corrected to reclassify these investments in the Fund’s December 31, 2014 balance sheet as “Investment in Delta House”. The reclassification had no impact on the Fund’s statement of operations or statement of cash flows for the year ended December 31, 2014.
Oil and Gas Properties
The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators.
Exploration, 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. CostsThe costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.” Exploratory costsexploratory wells are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory costs are expensed as dry-hole costs. At times, the Fund receives adjustments to certain wells from their respective operators upon review and audit of the wells’ costs. During the year ended December 31, 2014, the Fund did not record dry-hole costs. During the year ended December 31, 2013, the Fund recorded credits to dry-hole costs of $0.2 million, which related to wells that were determined to be dry holes in prior years. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity, transportation expense and workover efforts are expensed as incurred. Insurance expense related to operating wells of $0.1 million has been reclassified from “General and administrative expenses” in the Fund’s statement of operations for the fiscal year ended December 31, 2014 to “Operating expenses” to correct prior period presentation.
The aggregate prior year balance of $4.9 million, representing the Fund’s investment in equipment and facilities related to the Beta Project, was classified as “Equipment and facilities – in progress” within “Oil and gas properties” in the Fund’s December 31, 2014 balance sheet. Such amount has been reclassified in the Fund’s December 31, 2014 balance sheet as “Proved properties” within “Oil and gas properties” to conform to the current year presentation. The reclassification had no impact on the Fund’s statement of operations or cash flows for the year ended December 31, 2014.
Once a well has been determined to be fully depleted or upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion depreciation and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.
At December 31, 20142015 and 2013,2014, amounts recorded in due to operators totaling $0.8$0.1 million and $0.7$0.8 million, respectively, related to capital expenditures for oil and gas properties.
Advances to Operators for Working Interests and Expenditures
The Fund’s acquisition of a working interest in an oil and gas property requires it to make a payment to the seller for the Fund’s rights, title and interest. The Fund may be required to advance its share of the estimated cash expenditures for the succeeding month’s operation.expenditures to the operator for its oil and gas properties. The Fund accounts for such payments as advances to operators for working interests and expenditures. As drillingthe costs are incurred, the advances are reclassified to unproved or proved properties.
Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. The following table presents changes in asset retirement obligations for the years ended December 31, 20142015 and 2013.2014.
| | | 2014 | | | 2013 | |
| | | (in thousands) | |
| Balance, beginning of year | | $ | 2,087 | | | $ | 1,254 | |
| Liabilities incurred | | | 19 | | | | 79 | |
| Liabilities settled/relieved | | | - | | | | (171 | ) |
| Accretion expense | | | 48 | | | | 25 | |
| Revisions in estimated cash flows | | | - | | | | 900 | |
| Balance, end of year | | $ | 2,154 | | | $ | 2,087 | |
At December 31, 2013, the Fund’s balance sheet reflects the reclassification of the Raven Project’s asset retirement obligation from “Asset retirement obligation” to “Liability held for sale”. On January 17, 2014, the Fund entered into an agreement to sell its interest in the Raven Project to a third party.| | | 2015 | | | 2014 | |
| | | (in thousands) | |
| Balance, beginning of year | | $ | 2,154 | | | $ | 2,087 | |
| Liabilities incurred | | | 441 | | | | 19 | |
| Accretion expense | | | 170 | | | | 48 | |
| Revisions in estimated cash flows | | | 1,228 | | | | - | |
| Balance, end of year | | $ | 3,993 | | | $ | 2,154 | |
As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.
Syndication Costs
Syndication costs are direct costs incurred by the Fund in connection with the offering of the Fund’s shares, including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and unaffiliated broker-dealers, which are reflected on the Fund’s balance sheet as a reduction of shareholders’ capital.
Revenue Recognition and Imbalances
Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. The Fund uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Fund’s recorded liability, if any, would be reflected in other liabilities. No receivables are recorded for those wells where the Fund has taken less than its share of production.
Impairment of Long-Lived Assets
The Fund reviews the value of its oil and gas properties wheneverannually 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 to the net bookcarrying value at the time of the review. If the net bookcarrying value exceeds the 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 future cash flows from the property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment in value has occurred.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 discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If
Significant declines in oil and natural gas prices decline significantly, even if only for a short periodsince fourth quarter 2014 have impacted the fair value of time, it is possible that write-downs ofthe Fund’s oil and gas properties could occur.
properties. During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves and the well was fully impaired. Accordingly, during the year ended December 31, 2014,2015, the Fund recorded an impairment of oil and gas properties of $1.0 million, representing the remaining net book value of the well at the date of impairment. During the year ended December 31, 2013, the Fund recorded an impairment of oil and gas properties of $1.2$0.3 million related to the Cobalt Project, which was attributable to both declines in future oil and gas prices and an increase in estimated asset retirement costs. Duringrevisions to reserve estimates as provided by the year ended December 31, 2013, theFund’s independent petroleum engineers. The fair value of the impaired property at the date of impairment was $0.9$0.1 million. Such amount was determined based on Level 3 inputs, which included projected income from reserves utilizing forward price curves, net of anticipated costs, discounted. If oil and natural gas prices continue to decline, even if only for a short period of time, it is possible that the additional impairments of oil and gas properties will occur. During the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $1.0 million, relating to the Carrera Project, which was determined to be uneconomic relative to the remaining reserves and the well was fully impaired.
Depletion Depreciation and Amortization
Depletion depreciation and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs. In certain circumstances, equipment and facilities costs are depreciated overDuring the estimated useful lifeyear ended December 31, 2015, the Fund recorded $1.0 million of the asset.depletion expense related to adjustments to asset retirement obligations for fully depleted properties.
Income Taxes
No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders. The Fund files U.S. Federal and State tax returns and the 20102012 through 20132014 tax returns remain open for examination by tax authorities.
Income and Expense Allocation
Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement.
Distributions
Distributions to shareholders are allocated in proportion to the number of shares held. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement.
Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions. After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.
Recent Accounting Pronouncements
In January 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-01 that requires, among other things, companies to measure investments in other entities, except those accounted for under the equity method, at fair value and recognize any changes in fair value in net income. This pronouncement is effective for fiscal years beginning after December 15, 2017 and interim periods within those fiscal years, with early adoption not permitted. The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effectis currently evaluating the impact of this guidance on the Fund’sits financial statements.
2. Oil and Gas Properties
On January 17, 2014, the Fund, along with its affiliates, Ridgewood Energy Gulf of Mexico Oil and Gas Fund, L.P., Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy P Fund, LLC, and Ridgewood Energy W Fund, LLC, (when used with the Fund the “Ridgewood Funds”) entered into a purchase and sale agreement to sell the Ridgewood Funds’ interestsits interest in the Raven Project, located in the state waters of Louisiana, to Castex Energy Partners, L.P. for cash consideration totaling $21.7 million. The closing of the sale transaction occurred on January 30, 2014.
The Fund had a 6.25% working interest in the Raven Project and received $2.7 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.1 million, thereby resulting in a gain to the Fund of $2.6 million, which was recognized during the year ended December 31, 2014. There was no such amount recorded during the year ended December 31, 2013.
At December 31, 2013, the Fund’s balance sheet reflected the Raven Project’s cost and accumulated depletion classified as “Asset held for sale”, which totaled $0.3 million, and the Raven Project’s asset retirement obligation classified as “Liability held for sale”, which totaled $0.2 million. Such asset was monetized and obligation was relieved upon the closing of the Raven Project’s sale.2015.
3. Related Parties
Pursuant to the terms of the LLC Agreement, the Manager renders management, administrative and advisory services to the Fund. For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. Management fees for the years ended December 31, 2015 and 2014 and 2013 were $1.7$1.2 million and $1.8$1.7 million, respectively.
The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. The Fund did not pay distributions for the year ended December 31, 2015. Distributions paid to the Manager for the yearsyear ended December 31, 2014 and 2013 were $0.3 million and $0.9 million, respectively.0.3 million.
At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.
None of the amounts paid to the Manager have been derived as a result of arm’s length negotiations.
The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager.
4. Commitments and Contingencies
Capital Commitments
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. Currently,As of December 31, 2015, the Fund has several non-producinghad three properties, the Beta, Diller and Marmalard projects, for which additional development costs must be incurred in order to commence production.incurred. The Fund currently expects to spend an additional $9.9 million (which includes asset retirement obligations) related to the development of these projects, which the Fund anticipates such development will include the development of twelve wells, four in the Beta Project, and eighttwo in the Diller Project and six in the Marmalard projects,Project, with related platform and pipeline infrastructure. During 2015, one well in the Diller Project and four wells in the Marmalard Project commenced production.
As of December 31, 2014,2015, the Fund’s estimated capital commitments related to its oil and gas properties were $16.3$13.4 million (which include asset retirement obligations for the Fund’s projects of $4.4$5.6 million), of which $6.3$4.2 million is expected to be spent during the year ending December 31, 2015.2016. These expected capital commitments exceed available working capital and salvage fund by $5.6$9.5 million at December 31, 2014.2015.
Based upon its current cash position, and its current reserve estimates and its current development plan of the Beta Project, 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. However, if cash flow from operations is not sufficient to meet the Fund’s capital requirements, the Manager will take action, which may include adjusting its management fee temporarily to accommodate the Fund’s short-term capital requirements.
Environmental Considerations
The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. At December 31, 20142015 and 2013,2014, there were no known environmental contingencies that required the Fund to record a liability.
During the past several years, the United States Congress, as well as certain regulatory agencies with jurisdiction over the Fund’s business, have considered or proposed legislation or regulation relating to the upstream oil and gas industry both onshore and offshore. If any such proposals were to be enacted or adopted they could potentially materially impact the Fund’s operations. It is not possible at this time to predict whether such legislation or regulation, if proposed, will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact the Fund’s business. Any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows.
Insurance Coverage
The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have a material adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the funds managed by the Manager. Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund.
Ridgewood Energy Y Fund, LLC
Information about Oil and Gas Producing Activities – Unaudited
In accordance with the Financial Accounting Standards Board guidance on disclosures of oil and gas producing activities, this section provides supplementary information on oil and gas exploration and producing activities of the Fund. The Fund is engaged solely in oil and gas activities, all of which are located in the United States offshore waters of Louisiana in the Gulf of Mexico.
| Table I - Capitalized Costs Relating to Oil and Gas Producing Activities | |
| | | December 31, | | | December 31, | |
| | | 2014 | | | 2013 | | | 2015 | | | 2014 | |
| | | (in thousands) | | | (in thousands) | |
| Advances to operators for working interests and expenditures | | $ | 589 | | | $ | 101 | | | $ | - | | | $ | 589 | |
| Proved properties | | | 24,408 | | | | 35,998 | | | | 31,872 | | | | 29,289 | |
| Equipment and facilities - in progress | | | 5,199 | | | | 2,119 | | |
| Total oil and gas properties | | | 30,196 | | | | 38,218 | | |
| Accumulated depletion, depreciation and amortization | | | (14,678 | ) | | | (25,527 | ) | |
| Total oil and gas properties (a) | | | | 31,872 | | | | 29,878 | |
| Accumulated depletion and amortization | | | | (11,272 | ) | | | (14,678 | ) |
| Oil and gas properties, net | | $ | 15,518 | | | $ | 12,691 | | | $ | 20,600 | | | $ | 15,200 | |
| (a) | Capitalized costs relating to oil and gas producing activities as of December 31, 2014 includes reclassifications that were made to conform to the current year presentation. See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” under the headings “Investment in Delta House” and “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassifications. |
| Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development | |
| | | Year ended December 31, | | | Year ended December 31, | |
| | | | 2014 | | | | 2013 | | | 2015 | | | 2014 | |
| | | (in thousands) | | | (in thousands) | |
| Exploration costs | | $ | (3 | ) | | $ | (163 | ) | | $ | 8 | | | $ | (3 | ) |
| Development costs | | | 6,144 | | | | 4,350 | | | | 8,243 | | | | 6,144 | |
| | | $ | 6,141 | | | $ | 4,187 | | | $ | 8,251 | | | $ | 6,141 | |
Table III - Reserve Quantity Information
| Table III - Reserve Quantity Information |
|
| Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2015 and 2014. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available. |
Oil and gas reserves of the Fund have been estimated by independent petroleum engineers, Netherland, Sewell & Associates, Inc. at December 31, 2014 and 2013. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules. Due to inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.
| | | December 31, 2014 | | | December 31, 2013 | | | December 31, 2015 | | | December 31, 2014 | |
| | | United States | | | United States | |
| | | Oil (BBLS) | | | NGL (BBLS) | | | Gas (MCF) | | | Oil (BBLS) | | | NGL (BBLS) | | | Gas (MCF) | | | Oil (BBLS) | | | NGL (BBLS) | | | Gas (MCF) | | | Oil (BBLS) | | | NGL (BBLS) | | | Gas (MCF) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved developed and undeveloped reserves: | Proved developed and undeveloped reserves: | | | | | | | | | | | | | | | | | Proved developed and undeveloped reserves: | | | | | | | | | | | | | | | | |
| Beginning of year | | | 820,565 | | | | 69,645 | | | | 3,423,908 | | | | 579,699 | | | | - | | | | 3,422,158 | | | | 800,545 | | | | 18,130 | | | | 1,749,182 | | | | 820,565 | | | | 69,645 | | | | 3,423,908 | |
| Extensions and discoveries | | | - | | | | - | | | | - | | | | 258,453 | | | | - | | | | 548,978 | | |
Sales of minerals in place (a) | | | (10,053 | ) | | | (38,442 | ) | | | (1,468,385 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (10,053 | ) | | | (38,442 | ) | | | (1,468,385 | ) |
Revisions of previous estimates (b) | | | 30,575 | | | | 3,208 | | | | 3,197 | | | | 36,724 | | | | 98,280 | | | | 221,435 | | | | 104,438 | | | | 95,691 | | | | (275,731 | ) | | | 30,575 | | | | 3,208 | | | | 3,197 | |
| Production | | | (40,542 | ) | | | (16,281 | ) | | | (209,538 | ) | | | (54,311 | ) | | | (28,635 | ) | | | (768,663 | ) | | | (58,300 | ) | | | (9,331 | ) | | | (130,644 | ) | | | (40,542 | ) | | | (16,281 | ) | | | (209,538 | ) |
End of year (c) | | | 800,545 | | | | 18,130 | | | | 1,749,182 | | | | 820,565 | | | | 69,645 | | | | 3,423,908 | | |
| End of year | | | | 846,683 | | | | 104,490 | | | | 1,342,807 | | | | 800,545 | | | | 18,130 | | | | 1,749,182 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved developed reserves: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Beginning of year | | | 69,521 | | | | 37,102 | | | | 859,508 | | | | 155,719 | | | | - | | | | 1,877,427 | | | | 44,939 | | | | 18,130 | | | | 367,710 | | | | 69,521 | | | | 37,102 | | | | 859,508 | |
| End of year | | | 44,939 | | | | 18,130 | | | | 367,710 | | | | 69,521 | | | | 37,102 | | | | 859,508 | | | | 360,467 | | | | 59,347 | | | | 685,300 | | | | 44,939 | | | | 18,130 | | | | 367,710 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Proved undeveloped reserves: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Beginning of year | | | 751,044 | | | | 32,543 | | | | 2,564,400 | | | | 423,980 | | | | - | | | | 1,544,731 | | | | 755,606 | | | | - | | | | 1,381,472 | | | | 751,044 | | | | 32,543 | | | | 2,564,400 | |
End of year (d) | | | 755,606 | | | | - | | | | 1,381,472 | | | | 751,044 | | | | 32,543 | | | | 2,564,400 | | |
End of year (c) | | | | 486,216 | | | | 45,143 | | | | 657,507 | | | | 755,606 | | | | - | | | | 1,381,472 | |
| | (a) | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which at December 31, 2013, included proved developed and undeveloped oil reserves of approximately 1 thousand barrels and 9 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 6 thousand barrels and 33 thousand barrels, respectively and proved developed and undeveloped gas reserves of approximately 0.2 million mcf and 1.2 million mcf, respectively. |
| | (b) | Revisions of previous estimates during the year ended December 31, 2015 were attributable to the Carrera Project and to well performance. |
| (c) | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, approximately 22 thousand barrels of oil, 2 thousand barrels of NGL’s, and 27 thousand mcf's of gas, related to the Carrera Project, which arewere included in the above table areas of December 31, 2014, were not expectedrecovered. Revisions of previous estimates during the year ended December 31, 2014 were attributable to be recovered.well performance. |
| | (d)(c) | At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project. Such decreases were offset by slight increases in the Beta, Diller and Marmalard reserves. |
| Table IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves |
|
| Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions. |
| | | December 31, | |
| | | 2015 | | | 2014 | |
| | | (in thousands) | |
| Future cash inflows | | $ | 44,707 | | | $ | 80,772 | |
| Future production costs | | | (13,036 | ) | | | (14,785 | ) |
| Future development costs | | | (13,220 | ) | | | (14,825 | ) |
| Future net cash flows | | | 18,451 | | | | 51,162 | |
| 10% annual discount for estimated timing of cash flows | | | (5,831 | ) | | | (18,227 | ) |
| Standardized measure of discounted future net cash flows | | $ | 12,620 | | | $ | 32,935 | |
| Table V - Changes in the Standardized Measure for Discounted Cash Flows |
|
| The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs. |
| | | Year ended December 31, | |
| | | 2015 | | | 2014 | |
| | | (in thousands) | |
Net change in sales and transfer prices and in production costs related to future production | | $ | (23,928 | ) | | $ | (1,995 | ) |
| Sales and transfers of oil and gas produced during the period (a) | | | (1,141 | ) | | | (4,032 | ) |
Net change due to purchases and sales of minerals in place (b) | | | - | | | | (3,132 | ) |
| Changes in estimated future development costs | | | 1,605 | | | | 5,499 | |
| Net change due to revisions in quantities estimates | | | 2,842 | | | | 1,325 | |
| Accretion of discount | | | 3,293 | | | | 3,278 | |
| Other (a) | | | (2,986 | ) | | | (792 | ) |
| Aggregate change in the standardized measure of discounted future net cash flows for the year | | $ | (20,315 | ) | | $ | 151 | |
Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and gas reserves. Future cash inflows were determined based on average first-of-the-month pricing for the prior twelve month period. Future production and development costs are derived based on current costs assuming continuation of existing economic conditions.
| | | | | | | |
| | | December 31, | |
| | | 2014 | | | 2013 | |
| | | (in thousands) | |
| Future cash inflows | | $ | 80,772 | | | $ | 99,815 | |
| Future production costs | | | (14,785 | ) | | | (21,152 | ) |
| Future development costs | | | (14,825 | ) | | | (22,186 | ) |
| Future ad valorem taxes | | | - | | | | (150 | ) |
Future net cash flows (a) (b) | | | 51,162 | | | | 56,327 | |
| 10% annual discount for estimated timing of cash flows | | | (18,227 | ) | | | (23,543 | ) |
Standardized measure of discounted future net cash flows (a) (b) | | $ | 32,935 | | | $ | 32,784 | |
| | (a) | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interestsChanges in the Raven Project to a third party, which, at December 31, 2013, included undiscounted andstandardized measure for discounted cash flows for the year ended December 31, 2014 includes an insurance expense reclassification that was made to conform to the current year presentation. See Note 1 of approximately $4.3 million“Notes to Financial Statements” – “Organization and $3.1 million, respectively.Summary of Significant Accounting Policies” under the heading and “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification. |
| | (b) | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. As a result, undiscounted and discounted cash flows at December 31, 2014 of approximately $1.0 million related to the Carrera Project are not expected to be realized. |
Table V - Changes in the Standardized Measure for Discounted Cash Flows
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.
| | | | | | | |
| | | Year ended December 31, | |
| | | 2014 | | | 2013 | |
| | | (in thousands) | |
Net change in sales and transfer prices and in production costs related to future production | | $ | (1,995 | ) | | $ | (104 | ) |
| Sales and transfers of oil and gas produced during the period | | | (4,123 | ) | | | (7,939 | ) |
| Net change due to extensions, discoveries, and improved recovery | | | - | | | | 5,342 | |
Net change due to purchases and sales of minerals in place (a) | | | (3,132 | ) | | | - | |
| Changes in estimated future development costs | | | 5,499 | | | | 272 | |
| Net change due to revisions in quantities estimates | | | 1,325 | | | | 5,378 | |
| Accretion of discount | | | 3,278 | | | | 2,918 | |
| Other | | | (701 | ) | | | (2,267 | ) |
Aggregate change in the standardized measure of discounted future net cash flows for the year (b) | | $ | 151 | | | $ | 3,600 | |
| (a) | On January 17, 2014, the Fund entered into an agreement to sell its leasehold interests in the Raven Project to a third party, which at December 31, 2013, included discounted cash flows of approximately $3.1 million. |
| (b) | During January 2015, the Carrera Project was shut-in due to ongoing mechanical issues related to a blockage in the flowline. Upon evaluation, it was determined that estimated costs to bring the well back on production were not economic relative to the remaining reserves. See additional information in Tables III and IV. |
It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves as the computations are based on a number of estimates. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitation inherent therein.