0001214659-16-009907.txt : 20160229 0001214659-16-009907.hdr.sgml : 20160229 20160229162114 ACCESSION NUMBER: 0001214659-16-009907 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 49 CONFORMED PERIOD OF REPORT: 20151231 FILED AS OF DATE: 20160229 DATE AS OF CHANGE: 20160229 FILER: COMPANY DATA: COMPANY CONFORMED NAME: RIDGEWOOD ENERGY A-1 FUND LLC CENTRAL INDEX KEY: 0001457919 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 000000000 STATE OF INCORPORATION: DE FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-53895 FILM NUMBER: 161468044 BUSINESS ADDRESS: STREET 1: 14 PHILIPS PARKWAY CITY: MONTVALE STATE: NJ ZIP: 07645 BUSINESS PHONE: 201-447-9000 MAIL ADDRESS: STREET 1: 14 PHILIPS PARKWAY CITY: MONTVALE STATE: NJ ZIP: 07645 10-K 1 a121716010k.htm FOR THE FISCAL YEAR ENDED DECEMBER 31, 2015 a121716010k.htm
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, 2015
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. 000-53895

Ridgewood Energy A-1 Fund, LLC
(Exact name of registrant as specified in its charter)
 
Delaware
(State or other jurisdiction of
incorporation or organization)
  
01-0921132
(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.     Yes  x   No  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  x   No  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
(Do not check if a smaller reporting company)
  o
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 29, 2016 there are 207.7026 shares of LLC Membership Interest outstanding.
 
 
 
 
 
RIDGEWOOD ENERGY A-1 FUND, LLC
2015 ANNUAL REPORT ON FORM 10-K
 
     
PAGE
       
PART I
      
  2
  10
  10
  10
  11
  11
PART II
      
  12
  12
  12
  18
  18
  18
  18
  19
PART III
      
  19
  20
  20
  20
  21
PART IV
      
  22
       
    23
 
 
FORWARD-LOOKING STATEMENTS

Certain statements in this Annual Report on Form 10-K (“Annual Report”) and the documents Ridgewood Energy A-1 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, 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 February 3, 2009 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 March 2, 2009, 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 November 2012, 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 October 13, 2009. The Fund raised $41.1 million and, after payment of $6.7 million in offering fees, commissions and investment fees, the Fund had $34.5 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 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 were $0.4 million and $0.6 million, respectively.  Additionally, the Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions paid to the Manager for the years ended December 31, 2015 and 2014 were $13 thousand and $0.6 million, respectively.

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.  The Fund’s investments in oil and natural gas properties is complete and the balance of the Fund’s capital has been fully allocated to complete such projects 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 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, all 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 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 Committee’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 negotiated participation and joint operating 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

The 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 Office of Natural Resources Revenue (“ONRR”) depending on the lease.  Other than the ONRR royalties, the Fund does not have material royalty burdens other than as provided by the terms of the Fund’s credit agreement, which will require the Fund to pay royalties from the Beta Project to the lender. See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the credit agreement.

Deep Gas Royalty Relief
On January 26, 2004, the 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 $11.45 (estimated) per Million British Thermal Units (“mmbtu”), adjusted annually for inflation.  The Fund does not currently have any projects that qualify 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 project, the Liberty Project, which qualifies 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, 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
     1       0.02  
 
Acreage Data
The following table sets forth the Fund’s interests in developed and undeveloped oil and gas acreage as of December 31, 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
    
Undeveloped Acres
  
Gross
    
Net
    
Gross
    
Net
  
  5,760       115       6,124       122  

Information regarding the Fund’s current projects, all of which are located in the offshore waters of the Gulf of Mexico, is provided in the following table. The budget for each project is inclusive of estimated asset retirement obligations. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the heading “Liquidity Needs” for information regarding the funding of the Fund’s capital commitments.
 
 
         
Total Spent
    
Total
    
   
Working
    
through
    
Fund
    
Project
  
Interest
    
December 31, 2015
    
Budget
  
Status
         
(in thousands)
    
Non-producing Properties
                    
Beta Project
   2.0%     $ 12,258     $ 18,044  
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 $4.9 million for additional development costs and $0.9 million for asset retirement obligations.
Producing Properties
                        
Liberty Project
   2.0%     $ 3,004     $ 3,505  
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 $0.4 million for asset retirement obligations.
Fully Depleted Properties
                        
Alpha Project
   3.75%     $ 6,607     $ 7,470  
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 $0.9 million for asset retirement obligations.
Carrera Project
   2.0%     $ 3,244     $ 3,709  
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 $0.5 million for asset retirement obligations.
Sold Properties
                        
Raven Project
   25.0%     $ 11,452     $ 11,452  
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, entered into a purchase and sale agreement to sell its 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 25% working interest in the Raven Project and received $11.0 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.6 million, thereby resulting in a gain to the Fund of $10.4 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 2015, the Fund had three 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 project is near existing transportation infrastructure and pipelines.  The Fund 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 Beta Project to be marketed through Energy Upgrade, Inc.
 
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.  During the year ended December 31, 2015, decreases in commodity prices had an adverse effect on the Fund’s profitability and distributions.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Commodity Price Changes”, “Results of Operations – Overview” and “Results of Operations – Oil and Gas Revenue” for information regarding the impact of prices on the Fund’s oil and gas revenue.   In the past, the Fund has entered, and in the future, may continue to enter, into transactions, or derivative contracts, that fix the future prices or establish a price floor for portions of its oil or natural gas production. 
 
Seasonality

Generally, the Fund'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 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 LLOG Exploration Offshore, L.L.C. 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 its proportionate share of the anticipated cost of dismantling production platforms and facilities, plugging and abandoning the wells, and removing the platforms, facilities and wells in respect of the projects after the end of their useful lives, in accordance with applicable federal and state laws and regulations.  As of December 31, 2015, the Fund has $1.8 million invested in a salvage fund.  Upon commencement of production of the Beta Project, the Fund expects to contribute to the salvage fund a portion of the Beta Project’s operating income to fund its asset retirement obligations. Such contributions to the salvage fund will reduce the amount of cash distributions that would be made to investors by the Fund.  Any portion of the salvage fund that remains after the Fund has paid for all of its asset retirement obligations will be distributed to the shareholders and the Manager. There are no restrictions on withdrawals from the salvage fund.

Competition

Competition exists in the acquisition of oil and natural gas leases and in all sectors of the oil and natural gas exploration and production industry. The Fund, through its Manager, has competed with other companies for the acquisition of leases as well as percentage ownership interests in oil and natural gas working interests in the secondary market.  The Fund does not anticipate the acquisition of any additional ownership interests in oil and natural gas working interests as its capital has been fully allocated to current and past projects.

Employees

The Fund has no employees.  The Manager operates and manages the Fund.

Offices

The principal administrative office of both the Fund and the Manager is located at 14 Philips Parkway, Montvale, NJ 07645, and their phone number is 800-942-5550. The Manager leases additional office space at 1254 Enclave Parkway, Houston, TX 77077 and 125 Worth Avenue, Suite 318, Palm Beach, Florida, 33480.  In addition, the Manager maintains leases for other offices that are used for administrative purposes for the Fund and other funds managed by the Manager.

Regulation

Oil and natural gas exploration, development, production and transportation activities are subject to extensive federal and state laws and regulations. Regulations governing exploration and development activities require, among other things, the Fund’s operators to obtain permits to drill projects and to meet bonding, insurance and environmental requirements in order to drill, own or operate projects. In addition, the location of projects, the method of drilling and casing projects, the restoration of properties upon which projects are drilled, and the plugging and abandoning of projects are also subject to regulations.  The Fund owns projects that are located in the offshore waters of the Gulf of Mexico on the OCS. The Fund’s operations and activities are therefore governed by the OCSLA and certain other laws and regulations.
 
 
Outer Continental Shelf Lands Act

Under the OCSLA, the United States federal government has jurisdiction over oil and natural gas development on the OCS. As a result, the United States Secretary of the Interior is empowered to sell exploration, development and production leases of a defined submerged area of the OCS, or a block, through a competitive bidding process. Such activity is conducted by the BOEM, an agency of the United States Department of Interior (the “Department of Interior”). 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 adopted strict requirements for subsea drilling production equipment and has proposed new requirements to implement equipment reliability improvements, building upon enhanced industry standards for blowout preventers and blowout prevention technologies, and reforms in well design, well control, casing, cementing, real-time well monitoring and subsea containment.  These proposed requirements have not yet become final.  BSEE has also published a policy statement on safety culture with nine 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 and receives market prices from such sales. These sales are not currently subject to regulation by any federal or state agency. However, in order for the Fund to make such sales, it is dependent upon unaffiliated pipeline companies whose rates, terms and conditions of transport are subject to regulation by the Federal Energy Regulatory Commission.  Generally, depending on certain factors, pipelines can charge rates that are either market-based or cost-of-service. 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 $633.85 million (effective December 21, 2015 pursuant to the U.S. Coast Guard’s rulemaking adjusting liability limits for increases in Consumer Price Index), while the liability limit for a responsible party for offshore facilities, including any offshore pipeline, is equal to all removal costs plus up to $133.65 million in other damages for each incident. These liability limits may not apply if a spill is caused by a party’s gross negligence or willful misconduct, if the spill resulted from violation of a federal safety, construction or operating regulation, or if a party fails to report a spill or to cooperate fully in a clean-up.  Regulations under the OPA require owners and operators of rigs in United States waters to maintain certain levels of financial responsibility. The failure to comply with the OPA’s requirements may subject a responsible party to civil, criminal, or administrative enforcement actions. The Fund is not aware of any action or event that would subject us to liability under the OPA, and the Fund believes that 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, 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.

Under its LLC Agreement, the Fund has the authority to utilize derivative instruments to manage the price risk attributable to its oil and gas production.  Dodd-Frank mandates that many derivatives be executed in regulated markets and submitted for clearing to regulated clearinghouses.  Derivatives will be subject to minimum daily margin requirements set by the relevant clearinghouse and, potentially, by the SEC or the U.S. Commodity Futures Trading Commission (“CFTC”), and derivatives dealers may demand the unilateral ability to increase margin requirements beyond any regulatory or clearinghouse minimums.  In addition, as required by Dodd-Frank, 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 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, 2015 and 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.  The exploratory well in-progress at December 31, 2015 and 2014 is expected to produce both oil and natural gas, and is located in the offshore waters of the Gulf of Mexico.  During the years ended December 31, 2015 and 2014, the Fund had no drilling activity for developmental wells.  See Item 1. “Business” of this Annual Report under the heading “Properties” for more information about wells in-progress at December 31, 2015.

   
2015
    
2014
  
   
Gross
    
Net
    
Gross
    
Net
  
Exploratory wells:
                        
In-progress
     1       0.02       1       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, 2015 and 2014 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, 2015 and 2014, the Fund had proved undeveloped reserves related to the Beta Project totaling 0.3 million barrels of oil and 0.2 million mcf of natural gas, respectively.  The Beta project was determined to be a discovery in 2012.

During the year ended December 31, 2015, the Fund incurred costs to advance the development of proved undeveloped reserves of approximately $3.9 million, which related to the Beta Project.  The Beta Project is expected to commence production in third quarter 2016.  Information regarding estimated future development costs relating to the development of the Beta Project, which is contained in Item 1. “Business” of this Annual Report under the heading “Properties”, is incorporated herein by reference. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.

Production and Prices
The information regarding the Fund’s production of oil and natural gas, and certain price and cost information for the years ended December 31, 2015 and 2014 that is contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report under the headings “Results of Operations – Overview” and “Results of Operations – Operating Expenses” is incorporated herein by reference.

Delivery Commitments
As of December 31, 2015, 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 January 31, 2016, there were 631 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 Project, distributions have been impacted, and will be impacted in the future, by amounts reserved to provide for its ongoing development costs, debt service costs, and funding its estimated asset retirement obligations. There is no requirement to distribute available cash and, as such, available cash is distributed to the extent and at such times as the Manager believes is advisable. During the years ended December 31, 2015 and 2014, the Fund paid distributions totaling $0.1 million and $10.5 million, respectively.


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.

Commodity Price Changes
Changes in commodity prices may significantly affect liquidity and expected operating results.  Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable.  Significant declines in prices could result in non-cash charges to earnings due to impairment.

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 is volatile, and is likely to continue to be volatile in the future.  This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence. Therefore, it is impossible to predict the future price of oil and natural gas with any certainty.  Factors affecting market pricing for oil and natural gas include:

 
 
·
weather conditions;
 
·
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.
 
Critical Accounting Estimates
The discussion and analysis of the Fund’s financial condition and results of operations are based upon the Fund’s financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  In preparing these financial statements, the Fund is required to make certain estimates, judgments and assumptions. These estimates, judgments and assumptions affect the reported amounts of the Fund’s assets and liabilities, including the disclosure of contingent assets and liabilities, at the date of the financial statements and the reported amounts of its revenues and expenses during the periods presented.  The Fund evaluates these estimates and assumptions on an ongoing basis. The Fund bases its estimates and assumptions on historical experience and on various other factors that the Fund believes to be reasonable at the time the estimates and assumptions are made. However, future events and actual results may differ from these estimates and assumptions and such differences may have a material impact on the results of operations, financial position or cash flows.  See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for a discussion of the Fund’s significant accounting policies.  The following is a discussion of the accounting policies and estimates that management believes are most significant.

Accounting for 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.

Proved Reserves
Estimates of proved reserves are key components of the Fund’s most significant financial estimates involving its rate for recording depletion and amortization.  Annually, the Fund engages an independent petroleum engineer to perform a comprehensive study of the Fund’s proved properties to determine the quantities of reserves and the period over which such reserves will be recoverable. The Fund’s estimates of proved reserves are based on the quantities of oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions.  However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, rates of production and timing of development expenditures, including many factors beyond the Fund’s control.  The estimation process is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation, and judgment.  In addition, as a result of volatility and changing market conditions, commodity prices and future development costs will change from period to period, causing estimates of proved reserves and future net revenues to change.
 

Asset Retirement Obligations
Asset retirement obligations include costs to plug and abandon the Fund’s wells and to dismantle and relocate or dispose of the Fund’s production platforms and related structures and restoration costs of land and seabed.  The Fund develops estimates of these costs based upon the type of production structure, water depth, reservoir depth and characteristics, ongoing discussions with the wells’ operators and, at times, with information provided by third-party abandonment consultants specializing in the oil and gas industry.  Because these costs typically extend many years into the future, estimating these future costs is difficult and requires significant judgment that is subject to future revisions based upon numerous factors, 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 annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable.  Impairments of proved properties are determined by comparing estimated future net undiscounted cash flows from the property to the carrying value at the time of the review.  If the carrying value exceeds estimated future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using estimated future net discounted cash flows from the property.  The fair value determinations require considerable judgment and are sensitive to change.  Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment.  Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of net discounted future cash flows from proved oil and natural gas reserves could change in the near term.  Significant 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, even if only for a short period of time, it is possible that additional impairments of oil and gas properties will occur.

Results of Operations

The following table summarizes the Fund’s results of operations for the years ended December 31, 2015 and 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,
  
   
2015
    
2014
  
   
(in thousands)
  
Revenue
            
Oil and gas revenue
   $ 487     $ 3,045  
                 
Expenses
                
Depletion and amortization
     676       1,198  
Impairment of oil and gas properties
     -       646  
Management fees to affiliate
     380       632  
Operating expenses
     377       819  
General and administrative expenses
     142       142  
Total expenses
     1,575       3,437  
Gain on sale of oil and gas properties
     -       10,396  
(Loss) income from operations
     (1,088 )     10,004  
Interest income
     10       16  
Net (loss) income
     (1,078 )     10,020  
Other comprehensive (loss) income
                
Unrealized (loss) gain on marketable securities
     (1 )     7  
Total comprehensive (loss) income
   $ (1,079 )   $ 10,027  
 
 
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, 2015 and 2014.  Natural gas liquid (“NGL”) sales are included within gas sales.
 
 
   
Year ended December 31,
  
   
2015
    
2014
  
Number of wells producing
     1       3  
Total number of production days
     265       814  
Oil sales (in thousands of barrels)
     9       25  
Average oil price per barrel
   $ 50     $ 93  
Gas sales (in thousands of mcfs)
     24       133  
Average gas price per mcf
   $ 2.15     $ 4.87  

During the year ended December 31, 2015, production days and sales volumes were impacted by the Liberty Project, which was shut-in during fourth quarter 2015.  During the year ended December 31, 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.   Oil and gas revenue for the year ended December 31, 2015 was $0.5 million, a decrease of $2.6 million from the year ended December 31, 2014.  The decrease was attributable to decreased sales volume totaling $2.1 million coupled with decreased oil and gas prices totaling $0.5 million.   See “Overview” above for factors that impact the oil and gas revenue sales volume and rate variances.

Depletion and Amortization.  Depletion and amortization for the year ended December 31, 2015 was $0.7 million, a decrease of $0.5 million from the year ended December 31, 2014.  The decrease was attributable to decreases in production volumes totaling $0.9 million and the average depletion rate of $0.2 million, partially offset by adjustments to asset retirement obligations of $0.6 million, related to the Alpha and Carrera projects, fully depleted properties. 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 certain factors that impact the depletion and amortization volume and rate variances.  Depletion and amortization rates are also impacted by changes in reserve estimates provided annually by the Fund’s independent petroleum engineers.

Impairment of Oil and Gas Properties.  The Fund did not record an impairment of oil and gas properties during the year ended December 31, 2015.  During the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $0.6 million related to the Carrera Project, which was determined to be uneconomic relative to the remaining reserves and the well was fully impaired.
 
Management Fees to Affiliate. An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager.  

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,
  
   
2015
    
2014
  
   
(in thousands)
  
Lease operating expense
   $ 175     $ 592  
Insurance expense
     130       32  
Accretion expense
     83       20  
Workover expense and other
     (11 )     175  
    $ 377     $ 819  

Lease operating expense relates to the 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.  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 and insurance expense, was $24.14 per barrel of oil equivalent (“BOE”) during the year ended December 31, 2015 compared to $12.60 per BOE during the year ended December 31, 2014.  The increase in the average production cost is principally attributable to the impact of ongoing costs for the Alpha Project, which is no longer producing.  Accretion expense is related 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 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 $10.4 million related to the Raven Project. See Item 1. “Business” of this Annual Report under the heading “Properties” for additional information regarding the sale.

Interest Income.  Interest income is comprised of interest earned on cash and cash equivalents and salvage fund.

Unrealized (Loss) Gain on Marketable Securities.  The Fund has available-for-sale investments within its salvage fund in federal agency mortgage-backed securities.  Available-for-sale securities are carried in the financial statements at fair value and unrealized gains and losses related to the securities’ changes in fair value are recorded in other comprehensive income until realized.

Capital Resources and Liquidity

Operating Cash Flows
Cash flows used in operating activities for the year ended December 31, 2015 were $0.3 million, related to operating expenses of $0.4 million, management fees of $0.4 million and general and administrative expenses paid of $0.1 million, partially offset by revenue received of $0.6 million.

Cash flows provided by operating activities for the year ended December 31, 2014 were $2.0 million, related to revenue received of $3.9 million, partially offset by operating expenses of $1.1 million, management fees of $0.6 million and general and administrative expenses of $0.1 million.

Investing Cash Flows
Cash flows used in investing activities for the year ended December 31, 2015 were $4.3 million, related to capital expenditures for oil and gas properties.

Cash flows provided by investing activities for the year ended December 31, 2014 were $7.0 million, related to proceeds from the sale of the Raven Project of $11.0 million, partially offset by capital expenditures for oil and gas properties of $3.9 million.

Financing Cash Flows
Cash flows provided by financing activities for the year ended December 31, 2015 were $1.0 million, related to proceeds from long-term borrowings of $1.1 million, partially offset by manager and shareholder distributions of $0.1 million.

Cash flows used in financing activities for the year ended December 31, 2014 were $8.7 million, related to manager and shareholder distributions of $10.5 million, of which $7.2 million was related to the distribution of proceeds from the sale of the Raven Project, partially offset by proceeds from long-term borrowings of $1.8 million.

Estimated Capital Expenditures

The Fund has entered into multiple agreements for the acquisition, drilling and development of its oil and gas properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of December 31, 2015, the Fund had one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently expects to spend an additional $5.8 million, inclusive of asset retirement obligations, related to the development of this project, which the Fund anticipates will include a four-well development with related platform and pipeline infrastructure.  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, and in certain circumstances, through debt financing. 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, existing cash on-hand and borrowings.

As of December 31, 2015, the Fund’s estimated capital commitments related to its oil and gas properties were $7.6 million (which include asset retirement obligations for the Fund’s projects of $2.7 million and projected interest costs of $0.1 million for the Beta Project), of which $4.0 million is expected to be spent during the year ending December 31, 2016. These expected capital commitments exceed available working capital and salvage fund by $4.7 million at December 31, 2015.  The Fund has entered into a credit agreement to provide capital for the Beta Project.  See “Credit Agreement” below for additional information.
 
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 and borrowings 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 Project, distributions have been impacted, and will be impacted in the future, by amounts reserved to provide for its ongoing development costs, debt service costs, and funding its estimated asset retirement obligations.

Credit Agreement
In November 2012, the Fund entered into a credit agreement (the “Credit Agreement”) with Rahr Energy Investments LLC, as administrative agent and lender (and any other banks or financial institutions that may in the future become a party thereto), that provides for an aggregate loan commitment to the Fund of approximately $8.3 million to provide capital toward the funding of the Fund’s share of development costs on the Beta Project.  As of December 31, 2015 and 2014, the Fund had borrowed $2.9 million and $1.8 million, respectively, under the Credit Agreement. Principal and interest amounts are contracted to be repaid upon the onset of production of the Beta Project, which is expected in third quarter 2016, over a period not to extend beyond December 31, 2020.  The Fund expects operating income from the Beta Project will be sufficient to cover the principal and interest payments required under the Credit Agreement.  See Note 4 of “Notes to Financial Statements” – “Credit Agreement – Beta Project Financing” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information regarding the Credit Agreement.

The Credit Agreement contains customary negative covenants including covenants that limit the Fund’s ability to, among other things, grant liens, change the nature of its business, or merge into or consolidate with other persons. The events which constitute events of default are also customary for credit facilities of this nature and include payment defaults, breaches of representations, warrants and covenants, insolvency and change of control. Upon the occurrence of a default, in some cases following a notice and cure period, the Lenders under the Credit Agreement may accelerate the maturity of the Loan and require full and immediate repayment of all borrowings under the Credit Agreement. The Fund believes it is in compliance with all covenants under the Credit Agreement at December 31, 2015 and 2014.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at December 31, 2015 and 2014 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, 2015 and 2014, other than those discussed in “Estimated Capital Expenditures” and “Liquidity Needs – Credit Agreement” above.


Recent Accounting Pronouncements

See Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for a discussion of the Fund’s recent accounting pronouncements.


Not required.
 
 
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.
 

None.


Disclosure Controls and Procedures
Under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer of the Fund, management of the Fund and the Manager carried out an evaluation of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) as of December 31, 2015.  Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures are effective as of the end of the period covered by this report.

Management's Report on Internal Control over Financial Reporting
Management of the Fund is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rule 13a-15(f)).  The Fund’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management of the Fund, including its Chief Executive Officer and Chief Financial Officer, assessed the effectiveness of the Fund’s internal control over financial reporting as of December 31, 2015.  In making this assessment, management of the Fund used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal Control — Integrated Framework (2013). Based on their assessment using those criteria, management of the Fund concluded that, as of December 31, 2015, 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, 2015 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.



None.
 
PART III
 
 
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, 2015 are as follows:
 
Name, Age and Position with Registrant
 
Robert E. Swanson, 68
Chief Executive Officer
 
Kenneth W. Lang, 61
President and Chief Operating Officer
 
Kathleen P. McSherry, 50
Executive Vice President and Chief Financial Officer
 
Robert L. Gold, 57
Executive Vice President
 
Daniel V. Gulino, 55
Senior Vice President, General Counsel and Secretary

The officers in the above table have been officers of the Fund since February 3, 2009, 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 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 in 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, 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 207.7026 Shares outstanding as of 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 were $0.4 million and $0.6 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.   Distributions paid to the Manager for the years ended December 31, 2015 and 2014 were $13 thousand and $0.6 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, 2015 and 2014.
 
   
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
  
METHOD OF FILING
         
3.1
  
Certificate of Formation of Ridgewood Energy A-1 Fund, LLC dated February 3, 2009
  
Incorporated by reference to the Fund's Form 10 filed on February 18, 2010
         
3.2
  
Certificate of Amendment of Ridgewood Energy A-1 Fund, LLC dated February 24, 2009
  
Incorporated by reference to the Fund's Form 10 filed on February 18, 2010
         
3.3
  
Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy A-1  Fund, LLC dated March 2, 2009
  
Incorporated by reference to the Fund’s Form 10 files on February 18, 2010
         
10.1
  
Credit Agreement dated as of November 27, 2012 by and among Ridgewood Energy O Fund, LLC, Ridgewood Energy Q Fund, LLC, Ridgewood Energy S Fund, LLC, Ridgewood Energy T Fund, LLC, Ridgewood Energy V Fund, LLC, Ridgewood Energy W Fund, LLC, Ridgewood Energy A-1 Fund, LLC, Ridgewood Energy B-1 Fund, LLC, Rahr Energy Investments LLC, as Administrative Agent, and certain Lenders party thereto
  
Incorporated by reference to the Fund’s Form 8-K filed on December 3, 2012
         
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.
    
         
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 A-1 FUND, LLC
       
       
Date:  February 29, 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
     
/s/ ROBERT E. SWANSON
Chief Executive Officer
February 29, 2016
Robert E. Swanson
  (Principal Executive Officer)
  
     
     
/s/ KATHLEEN P. MCSHERRY
Executive Vice President and Chief Financial Officer
February 29, 2016
Kathleen P. McSherry
  (Principal Financial and Accounting Officer)
  
     
     
RIDGEWOOD ENERGY CORPORATION
    
     
BY:  /s/ ROBERT E. SWANSON
Chief Executive Officer of the Manager
February 29, 2016
Robert E. Swanson
    
 
 


 
To the Shareholders and Manager of Ridgewood Energy A-1 Fund, LLC:

We have audited the accompanying balance sheets of Ridgewood Energy A-1 Fund, LLC (the “Fund”) as of December 31, 2015 and 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. 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 A-1 Fund, LLC as of December 31, 2015 and 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.
 
/s/ Deloitte & Touche LLP


Parsippany, New Jersey
February 29, 2016

 
RIDGEWOOD ENERGY A-1 FUND, LLC
(in thousands, except share data)


   
December 31,
  
   
2015
    
2014
  
Assets
            
Current assets:
            
Cash and cash equivalents
   $ 1,444     $ 5,045  
Salvage fund
     474       -  
Production receivable
     7       98  
Other current assets
     -       21  
Total current assets
     1,925       5,164  
Salvage fund
     1,310       1,780  
Other assets
     244       366  
Oil and gas properties:
                
Proved properties
     15,754       14,697  
Less:  accumulated depletion and amortization
     (2,958 )     (6,318 )
Total oil and gas properties, net
     12,796       8,379  
Total assets
   $ 16,275     $ 15,689  
                 
Liabilities and Members' Capital
                
Current liabilities:
                
Due to operators
   $ 153     $ 914  
Accrued expenses
     215       33  
Asset retirement obligations
     474       -  
Total current liabilities
     842       947  
Long-term borrowings
     2,900       1,800  
Asset retirement obligations
     1,645       965  
Other liabilities
     127       48  
Total liabilities
     5,514       3,760  
Commitments and contingencies (Note 5)
                
Members' capital:
                
Manager:
                
Distributions
     (5,058 )     (5,045 )
Retained earnings
     5,097       5,152  
Manager's total
     39       107  
Shareholders:
                
Capital contributions (250 shares authorized;
                
207.7026 issued and outstanding)
     41,143       41,143  
Syndication costs
     (4,804 )     (4,804 )
Distributions
     (35,427 )     (35,351 )
Retained earnings
     9,807       10,830  
Shareholders' total
     10,719       11,818  
Accumulated other comprehensive income
     3       4  
Total members' capital
     10,761       11,929  
Total liabilities and members' capital
   $ 16,275     $ 15,689  

The accompanying notes are an integral part of these financial statements.


RIDGEWOOD ENERGY A-1 FUND, LLC
(in thousands, except per share data)


   
Year ended December 31,
  
   
2015
    
2014
  
Revenue
            
Oil and gas revenue
   $ 487     $ 3,045  
                 
Expenses
                
Depletion and amortization
     676       1,198  
Impairment of oil and gas properties
     -       646  
Management fees to affiliate (Note 3)
     380       632  
Operating expenses
     377       819  
General and administrative expenses
     142       142  
Total expenses
     1,575       3,437  
Gain on sale of oil and gas properties
     -       10,396  
(Loss) income from operations
     (1,088 )     10,004  
Interest income
     10       16  
Net (loss) income
     (1,078 )     10,020  
Other comprehensive (loss) income
                
Unrealized (loss) gain on marketable securities
     (1 )     7  
Total comprehensive (loss) income
   $ (1,079 )   $ 10,027  
                 
Manager Interest
                
Net (loss) income
   $ (55 )   $ 308  
                 
Shareholder Interest
                
Net (loss) income
   $ (1,023 )   $ 9,712  
Net (loss) income per share
   $ (4,928 )   $ 46,762  

The accompanying notes are an integral part of these financial statements.


RIDGEWOOD ENERGY A-1 FUND, LLC
(in thousands, except share data)
 
                     
Accumulated Other
        
                     
Comprehensive
        
   
# of Shares
    
Manager
    
Shareholders
    
(Loss) Income
    
Total
  
Balances, December 31, 2013
     207.7026     $ 364     $ 12,068     $ (3 )   $ 12,429  
Distributions
     -       (565 )     (9,962 )     -       (10,527 )
Net income
     -       308       9,712       -       10,020  
Other comprehensive income
     -       -       -       7       7  
Balances, December 31, 2014
     207.7026       107       11,818       4       11,929  
Distributions
     -       (13 )     (76 )     -       (89 )
Net loss
     -       (55 )     (1,023 )     -       (1,078 )
Other comprehensive loss
     -       -       -       (1 )     (1 )
Balances, December 31, 2015
     207.7026     $ 39     $ 10,719     $ 3     $ 10,761  

The accompanying notes are an integral part of these financial statements.
 

RIDGEWOOD ENERGY A-1 FUND, LLC
(in thousands)
 
   
Year ended December 31,
  
 
  
2015
    
2014
  
             
Cash flows from operating activities
            
Net (loss) income
   $ (1,078 )   $ 10,020  
Adjustments to reconcile net (loss) income to net cash
                
  (used in) provided by operating activities:
                
Depletion and amortization
     676       1,198  
Impairment of oil and gas properties
     -       646  
Gain on sale of oil and gas properties
     -       (10,396 )
Accretion expense
     83       19  
Changes in assets and liabilities:
                
Decrease in production receivable
     91       864  
Decrease in other current assets
     21       51  
Decrease in due to operators
     (124 )     (355 )
Increase (decrease) in accrued expenses
     37       (6 )
Net cash (used in) provided by operating activities
     (294 )     2,041  
                 
Cash flows from investing activities
                
Proceeds from sale of oil and gas properties
     -       10,978  
Capital expenditures for oil and gas properties
     (4,313 )     (3,927 )
Investments in salvage fund
     (5 )     (10 )
Net cash (used in) provided by investing activities
     (4,318 )     7,041  
                 
Cash flows from financing activities
                
Long-term borrowings
     1,100       1,800  
Distributions
     (89 )     (10,527 )
Net cash provided by (used in) financing activities
     1,011       (8,727 )
                 
Net (decrease) increase in cash and cash equivalents
     (3,601 )     355  
Cash and cash equivalents, beginning of year
     5,045       4,690  
Cash and cash equivalents, end of year
   $ 1,444     $ 5,045  
                 
Supplemental schedule of non-cash investing activities
                
Advances used for capital expenditures in oil and gas
properties reclassified to proved properties
   $ -     $ 68  
 
The accompanying notes are an integral part of these financial statements.
 
 
RIDGEWOOD ENERGY A-1 FUND, LLC

1.   Organization and Summary of Significant Accounting Policies

Organization
The Ridgewood Energy A-1 Fund, LLC (the "Fund"), a Delaware limited liability company, was formed on February 3, 2009 and operates pursuant to a limited liability company agreement (the “LLC Agreement") dated as of March 2, 2009 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, 4 and 5.

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 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority.  Cash and cash equivalents approximate fair value based on Level 1 inputs.  Mortgage-backed securities are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets.

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, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution.  At December 31, 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.  At December 31, 2015 and 2014, the Fund had investments in federal agency mortgage-backed securities as detailed in the following table, which are classified as available for sale.  Available-for-sale securities are carried in the financial statements at fair value.


         
Gross
        
   
Amortized
    
Unrealized
    
Fair
  
   
Cost
    
Gains
    
Value
  
   
(in thousands)
  
Government National Mortgage Association security (GNMA July 2041)
        
December 31, 2015
   $ 75     $ 3     $ 78  
December 31, 2014
   $ 84     $ 3     $ 87  
                         
Federal National Mortgage Association security (FNMA January 2042)
          
December 31, 2015
   $ -     $ -     $ -  
December 31, 2014
   $ 109     $ 1     $ 110  

The unrealized gains on the Fund's investments in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of those investments are guaranteed by an agency of the U.S. government.  Unrealized gains or losses on available-for-sale securities are reported in other comprehensive income until realized.  In July 2015, the Fund received all contractual principal and interest payments related to the FNMA January 2042 security and there was no realized gain or loss.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.  Interest earned on the account will become part of the salvage fund.  There are no restrictions on withdrawals from the salvage fund.

Debt Discounts and Deferred Financing Costs
Debt discounts and deferred financing costs include lender fees and other costs of acquiring debt (see Note 4. “Credit Agreement – Beta Project Financing”) such as the conveyance of override royalty interests related to the Beta Project.  These costs are deferred and amortized over the term of the debt period or until the redemption of the debt and are included on the balance sheet within “Other assets”.  At December 31, 2015 and 2014, $0.2 million and $0.4 million, respectively, of debt discounts and deferred financing costs were unamortized.  Amortization expense was $0.1 million for each of the years ended December 31, 2015 and 2014.  During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the balance sheet within “Oil and gas properties”.

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.  The costs of exploratory 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.  Interest costs related to the Credit Agreement (see Note 4. “Credit Agreement – Beta Project Financing”) are capitalized during the period of asset construction.  Annual lease rentals and exploration expenses are expensed as incurred.  All costs related to production activity and workover efforts are expensed as incurred.  Insurance expense related to operating wells of $32 thousand 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 and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.

At December 31, 2015 and 2014, amounts recorded in due to operators totaling $0.1 million and $0.8 million, respectively, related to capital expenditures for oil and gas properties.

Advances to Operators for Working Interests and Expenditures
The Fund may be required to advance its share of the estimated succeeding month’s 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 the costs are incurred, the advances are reclassified to 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, 2015 and 2014.
   
2015
    
2014
  
   
(in thousands)
  
Balance, beginning of year
   $ 965     $ 946  
Liabilities incurred
     404       -  
Accretion expense
     83       19  
Revisions in estimated cash flows
     667       -  
Balance, end of year
   $ 2,119     $ 965  

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 annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable.  Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review.  If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the 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.

Significant declines in oil and natural gas prices since fourth quarter 2014 have impacted the fair value of the Fund’s oil and gas properties.  During the year ended December 31, 2015, the Fund did not record an impairment of oil and gas properties.  During the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $0.6 million, relating to the Carrera Project, which was determined to be uneconomic relative to the remaining reserves and the well was fully impaired.  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.
 

Depletion and Amortization
Depletion 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.  During the year ended December 31, 2015, the Fund recorded $0.6 million of 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 2012 through 2014 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.  During the year ended December 31, 2014, the Fund made distributions of available cash from dispositions related to the sale of the Raven Project totaling $7.2 million. There were no such distributions during the year ended December 31, 2015.
 
Recent Accounting Pronouncements
In April 2015, the Financial Accounting Standards Board (“FASB”) issued accounting guidance related to the presentation of debt issuance costs in the balance sheet as a direct reduction from the carrying amount of the debt liability, consistent with debt discounts, rather than as an asset.  Amortization of debt issuance costs will continue to be reported as interest expense.  Debt issuance costs related to revolving credit arrangements, however, will continue to be presented as an asset and amortized ratably over the term of the arrangement.  In August 2015, the FASB issued accounting guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements which clarifies that companies may continue to present unamortized debt issuance costs associated with line of credit arrangements as an asset.  These pronouncements are effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, with early adoption permitted.  The Fund is currently evaluating the impact that the adoption of these pronouncements will have on its financial statements.
 
2.  Oil and Gas Properties

On January 17, 2014, the Fund, along with its affiliates, entered into a purchase and sale agreement to sell its 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 25% working interest in the Raven Project and received $11.0 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.6 million, thereby resulting in a gain to the Fund of $10.4 million, which was recognized during the year ended December 31, 2014.  There was no such amount recorded during the year ended December 31, 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 were $0.4 million and $0.6 million, respectively.
 
The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions from operations paid to the Manager for the years ended December 31, 2015 and 2014 were $13 thousand and $0.6 million, respectively.  In addition, the Manager is entitled to receive a 1% interest in cash distributions from dispositions.  Distributions from the sale of the Raven project paid to the Manager during the year ended December 31, 2014 were $0.1 million. There were no such distributions during the year ended December 31, 2015.
 
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.  Credit Agreement – Beta Project Financing

In November 2012, the Fund entered into a credit agreement (the “Credit Agreement”) with Rahr Energy Investments LLC, as Administrative Agent and Lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”) that provides for an aggregate loan commitment to the Fund of approximately $8.3 million (“Loan”), to provide capital toward the funding of the Fund’s share of development costs on the Beta Project. Except in cases of fraud and breach of certain representations, the Loan is non-recourse to the Fund’s other assets and secured solely by the Fund’s interests in the Beta Project. Certain other funds managed by Ridgewood (“Ridgewood Funds”, and when used with the Fund the “Ridgewood Participating Funds”) have also executed the Credit Agreement. Pursuant to the Credit Agreement, each Ridgewood Participating Fund has a separate loan commitment from the Lenders and amounts borrowed are not joint and several obligations. Each of the Ridgewood Participating Funds’ borrowings is secured solely by its separate interest in the Beta Project. Therefore, the Fund is liable for the repayment of its Loan and is not liable to the Lenders to repay any loan made to any other Ridgewood Fund. The Manager serves as the manager for each Ridgewood Participating Fund.

The Fund anticipates it will borrow approximately $8.3 million over the development period of the Beta Project. The Loan bears interest at 8% compounded annually and accrues only on Loan proceeds as they are drawn. Principal and interest will not be payable until such time that initial production has commenced for the Beta Project, which is currently expected in third quarter 2016.  At that time, if certain revenue production levels are met, principal and interest will be repaid at a monthly rate of 1.25% of the Fund’s total principal outstanding at the date the Beta Project commences production for the first seven months of production, and a monthly rate of 4.5% of the Fund’s total principal outstanding at the date the Beta Project commences production thereafter until the Loan is repaid in full, in no event later than December 31, 2020.  The Loan may be prepaid by the Fund without premium or penalty.  As of December 31, 2015 and 2014, the Fund had borrowings of $2.9 million and $1.8 million, respectively, under the Credit Agreement.  As of December 31, 2015 and 2014, interest costs of $0.3 million and $48 thousand, respectively, were capitalized and included on the balance sheet within “Oil and gas properties”.  Such amounts are accrued on the balance sheet within “Accrued expenses” and “Other liabilities” at December 31, 2015 and “Other liabilities” at December 31, 2014.

As additional consideration to the Lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interest in the Beta Project to the Lenders.  The Credit Agreement contains customary covenants, for which the Fund believes it was in compliance at December 31, 2015 and 2014.

5.   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.  As of December 31, 2015, the Fund had one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently anticipates such development will include a four-well development with related platform and pipeline infrastructure.
 

As of December 31, 2015, the Fund’s estimated capital commitments related to its oil and gas properties were $7.6 million (which include asset retirement obligations for the Fund’s projects of $2.7 million and projected interest costs of $0.1 million for the Beta Project), of which $4.0 million is expected to be spent during the year ending December 31, 2016. These expected capital commitments exceed available working capital and salvage fund by $4.7 million at December 31, 2015.  The Fund has entered into the Credit Agreement to provide capital for funding of the Beta Project.  See Note 4. “Credit Agreement – Beta Project Financing” for additional information.
 
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 and borrowings 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, 2015 and 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 A-1 Fund, LLC
Supplementary Financial Information

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,
  
   
2015
    
2014
  
   
(in thousands)
  
Proved properties
   $ 15,754     $ 14,697  
   Total oil and gas properties (a)
     15,754       14,697  
Accumulated depletion and amortization
     (2,958 )     (6,318 )
Oil and gas properties, net
   $ 12,796     $ 8,379  
 
 
 
(a)
Capitalized costs relating to oil and gas producing activities as of December 31, 2014 includes a reclassification that was 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 heading “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification.
 

Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
 
   
Year ended December 31,
  
   
2015
    
2014
  
   
(in thousands)
  
Exploration costs
   $ 4     $ (3 )
Development costs
     4,983       4,021  
    $ 4,987     $ 4,018  


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.
 
 
   
December 31, 2015
    
December 31, 2014
  
   
United States
  
   
Oil (BBLS)
    
NGL (BBLS)
    
Gas (MCF)
    
Oil (BBLS)
    
NGL (BBLS)
    
Gas (MCF)
  
                                     
Proved developed and undeveloped reserves:
                                    
Beginning of year
     306,783       11,395       371,865       355,412       171,648       6,378,017  
Sales of minerals in place (a)
     -       -       -       (40,214 )     (153,769 )     (5,873,539 )
Revisions of previous estimates (b)
     (6,217 )     (6,212 )     (40,625 )     16,383       2,140       (19,471 )
Production
     (8,655 )     (1,219 )     (20,019 )     (24,798 )     (8,624 )     (113,142 )
End of year
     291,911       3,964       311,221       306,783       11,395       371,865  
                                                 
Proved developed reserves:
                                                
Beginning of year
     27,798       11,395       162,625       46,097       41,475       1,182,852  
End of year
     14,355       3,964       103,054       27,798       11,395       162,625  
                                                 
Proved undeveloped reserves:
                                                
Beginning of year
     278,985       -       209,240       309,315       130,173       5,195,165  
End of year (c)
     277,556       -       208,167       278,985       -       209,240  
 
 
(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 5 thousand barrels and 36 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 24 thousand barrels and 0.1 million barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.9 million mcf and 5.0 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.  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 15 thousand barrels of oil, 1 thousand barrels of NGL’s, and 18 thousand mcf's of gas, related to the Carrera Project, which are included in the above table as of December 31, 2014, were not recovered. Revisions of previous estimates during the year ended December 31, 2014 were attributable to well performance.

 
(c)
At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project.

 
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
   $ 14,095     $ 29,128  
Future production costs
     (2,086 )     (2,566 )
Future development costs
     (7,029 )     (8,854 )
Future net cash flows
     4,980       17,708  
10% annual discount for estimated timing of cash flows
     (1,605 )     (5,381 )
Standardized measure of discounted future estimated net cash flows
   $ 3,375     $ 12,327  


Table V - Changes in the Standardized Measure for Discounted Future Net 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
   $ (9,551 )   $ (2,638 )
Sales and transfers of oil and gas produced during the period (a)
     (183 )     (2,421 )
Net change due to purchases and sales of minerals in place (b)
     -       (12,530 )
Changes in estimated future development costs
     1,825       4,227  
Net change due to revisions in quantities estimates
     (449 )     743  
Accretion of discount
     1,233       2,407  
Other (a)
     (1,827 )     (1,530 )
Aggregate change in the standardized measure of discounted future net cash
flows for the year
   $ (8,952 )   $ (11,742 )
 
 
(a)
Changes in the standardized 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 “Notes to Financial Statements” – “Organization and 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)
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 $12.5 million.
 
 
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.
 
 
F-15
 EX-31.1 2 ex31_1.htm EXHIBIT 31.1 ex31_1.htm
Exhibit 31.1
CERTIFICATION

I, Robert E. Swanson, certify that:

 
1.
I have reviewed this Annual Report on Form 10-K of Ridgewood Energy A-1 Fund, LLC;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f))  for the registrant and have:

(a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.  The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 
Dated:
February 29, 2016
  
       
 
/s/
ROBERT E. SWANSON
  
 
Name:
Robert E. Swanson
  
       
 
Title:
Chief Executive Officer
  
   
(Principal Executive Officer)
  
 
 
 
 
 EX-31.2 3 ex31_2.htm EXHIBIT 31.2 ex31_2.htm
Exhibit 31.2
CERTIFICATION

I, Kathleen P. McSherry, certify that:

1.      I have reviewed this Annual Report on Form 10-K of Ridgewood Energy A-1 Fund, LLC;

 
2.
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 
3.
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 
4.
The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f))  for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 
5.
The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 
Dated:
February 29, 2016
  
       
 
/s/
KATHLEEN P. MCSHERRY
  
 
Name:
Kathleen P. McSherry
  
       
 
Title:
Executive Vice President and Chief Financial Officer
  
   
(Principal Financial and Accounting Officer)
  
 
 
 
 EX-32 4 ex32.htm EXHIBIT 32 ex32.htm
Exhibit 32


CERTIFICATIONS PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with this Annual Report on Form 10-K of the Ridgewood Energy A-1 Fund, LLC (the “Fund”) for the fiscal year ended December 31, 2015, as filed with the Securities and Exchange Commission on the date hereof, (the “Report”), each of the undersigned officers of the Fund hereby certifies, pursuant to 18 U.S.C. (section) 1350, as adopted pursuant to (section) 906 of the Sarbanes-Oxley Act of 2002, that to the best of their knowledge:

 
(1)
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 
(2)
The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Fund.


Dated:
February 29, 2016
      
     
/s/
ROBERT E. SWANSON
     
Name:
Robert E. Swanson
     
Title:
Chief Executive Officer
       
(Principal Executive Officer)
         
Dated:
February 29, 2016
      
     
/s/
KATHLEEN P. MCSHERRY
     
Name:
Kathleen P. McSherry
     
Title:
Executive Vice President and Chief Financial Officer
       
(Principal Financial and Accounting Officer)
         
         

A signed original of this written statement or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement has been provided to the Fund and will be retained by the Fund and furnished to the Securities and Exchange Commission or its staff upon request. The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of this report or as a separate disclosure document.
 
 
 







 
 EX-99.1 5 ex99_1.htm EXHIBIT 99.1 ex99_1.htm
Exhibit 99.1
 
   
 
February 12, 2016


Mr. W. Kent Webb
Ridgewood Energy Corporation
1254 Enclave Parkway, Suite 600
Houston, Texas 77077

Dear Mr. Webb:
 
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2015, to the Ridgewood Energy A-1 Fund, LLC (Ridgewood A-1 Fund) interest in certain oil and gas properties located in federal waters in the Gulf of Mexico.  We completed our evaluation on or about the date of this letter.  It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Ridgewood A-1 Fund.  The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas.  Definitions are presented immediately following this letter.  This report has been prepared for Ridgewood A-1 Fund's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Ridgewood A-1 Fund interest in these properties, as of December 31, 2015, to be:

   
Net Reserves
    
Future Net Revenue(1) (M$)
  
   
Oil
    
NGL
    
Gas
          
Present Worth
  
Category
  
(MBBL)
    
(MBBL)
    
(MMCF)
    
Total
    
at 10%
  
                               
Proved Developed Producing
     0.0       0.0       0.0       -1,327.6       -1,263.0  
Proved Developed Non-Producing
     14.4       4.0       103.1       -38.0       89.6  
Proved Undeveloped
     277.6       0.0       208.2       6,345.9       4,548.4  
                                         
Total Proved
     291.9       4.0       311.2       4,980.3       3,375.0  

Totals may not add because of rounding.

(1)
Future net revenue is after deducting estimated abandonment costs.

The oil volumes shown include crude oil and condensate.  Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons.  Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves.  As requested, probable and possible reserves that exist for these properties have not been included.  This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.  Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status.  The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Ridgewood A-1 Fund's share of the gross (100 percent) revenue from the properties prior to any deductions.  Future net revenue is after deductions for Ridgewood A-1 Fund's share of capital costs, abandonment costs, and operating expenses but before consideration of any income taxes.  The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money.  Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.
 
 
 
 
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2015.  For oil and NGL volumes, the average Light Louisiana Sweet spot price of $54.02 per barrel is adjusted by field for quality, transportation fees, and market differentials.  For gas volumes, the average Henry Hub spot price of $2.587 per MMBTU is adjusted by field for energy content, transportation fees, and market differentials.  All prices are held constant throughout the lives of the properties.  The average adjusted product prices weighted by production over the remaining lives of the properties are $45.34 per barrel of oil, $11.34 per barrel of NGL, and $2.615 per MCF of gas.

Operating costs used in this report are based on operating expense records of Ridgewood Energy Corporation (Ridgewood) and our knowledge of similar offshore operations.  These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels.  Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs and include contractual production handling agreement fees.  Since all properties are nonoperated, no headquarters general and administrative overhead expenses of Ridgewood or Ridgewood A-1 Fund are included.  Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Ridgewood and are based on authorizations for expenditure and actual costs from recent activity.  Capital costs are included as required for workovers, new well completions, new development wells, and production equipment.  Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable.  Abandonment costs used in this report are Ridgewood's estimates of the costs to abandon the wells, platforms, and production facilities, net of any salvage value.  Capital costs and abandonment costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities.  We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Ridgewood A-1 Fund interest.  Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Ridgewood A-1 Fund receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities.  Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves.  Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance.  In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Ridgewood, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance.  If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts.  Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.
 
 
 
 

 
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests.  The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards).  We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Ridgewood, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate.  Supporting work data are on file in our office.  We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned.  The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.  Lee E. George, a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 1997 and has over 15 years of prior industry experience.  Shane M. Howell, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2005 and has over 7 years of prior industry experience.  We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.
 
  Sincerely,
   
 
NETHERLAND, SEWELL & ASSOCIATES, INC.
 
Texas Registered Engineering Firm F-2699
   
   
   
/s/ C.H. (Scott) Rees III
  By:
 
   
C.H. (Scott) Rees III, P.E.
   
Chairman and Chief Executive Officer
   

 
 
/s/ Lee E. George
  
/s/ Shane M. Howell
By:   By:   
   
Lee E. George, P.E. 95018
  
Shane M. Howell, P.G. 11276
 
Vice President
  
Vice President
       
       
Date Signed:  February 12, 2016
Date Signed:  February 12, 2016
 
 
LEG:KNE
 
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients.  The digital document is intended to be substantively the same as the original signed document maintained by NSAI.  The digital document is subject to the parameters, limitations, and conditions stated in the original document.  In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.
 
 
 
 

 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a).  Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties.  Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir.  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery.  When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

 
(i)
Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
 
(ii)
Same environment of deposition;
 
(iii)
Similar geological structure; and
 
(iv)
Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen.  Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis.  In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate.  Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate.  The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves.  Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
 
(ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
 
Supplemental definitions from the 2007 Petroleum Resources Management System:
 
Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.  Improved recovery reserves are considered producing only after the improved recovery project is in operation.
 
Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.  Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons.  Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production.  In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
 
(7) Development costs.  Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.  More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 
(i)
Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.
 
(ii)
Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
 
 
Definitions - Page 1 of 6
 

 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
 
(iii)
Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
 
(iv)
Provide improved recovery systems.

(8) Development project.  A development project is the means by which petroleum resources are brought to the status of economically producible.  As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible.  The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.  The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR).  Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs.  Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.  Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property.  Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

 
(i)
Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies.  Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.
 
(ii)
Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.
 
(iii)
Dry hole contributions and bottom hole contributions.
 
(iv)
Costs of drilling and equipping exploratory wells.
 
(v)
Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well.  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.  Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well.  An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.  There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both.  Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field.  The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

 
(i)
Oil and gas producing activities include:

 
(A)
The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;
 
(B)
The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;
 
(C)
The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
 
(1)
Lifting the oil and gas to the surface; and
 
(2)
Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
 
 
Definitions - Page 2 of 6
 

 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
 
(D)
Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank.  If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

 
a.
The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and
 
b.
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

 
(ii)
Oil and gas producing activities do not include:

 
(A)
Transporting, refining, or marketing oil and gas;
 
(B)
Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;
 
(C)
Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or
 
(D)
Production of geothermal steam.

(17) Possible reserves.  Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 
(i)
When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.  When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
 
(ii)
Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain.  Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
 
(iii)
Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.
 
(iv)
The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.
 
(v)
Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir.  Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
 
(vi)
Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology.  Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 
(i)
When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves.  When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
 
 
Definitions - Page 3 of 6
 

 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
 
(ii)
Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion.  Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.
 
(iii)
Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.
 
(iv)
See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

 
(i)
Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.  They become part of the cost of oil and gas produced.  Examples of production costs (sometimes called lifting costs) are:

 
(A)
Costs of labor to operate the wells and related equipment and facilities.
 
(B)
Repairs and maintenance.
 
(C)
Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.
 
(D)
Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
 
(E)
Severance taxes.

 
(ii)
Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities.  To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate.  Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.  The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 
(i)
The area of the reservoir considered as proved includes:

 
(A)
The area identified by drilling and limited by fluid contacts, if any, and
 
(B)
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
 
(iii)
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
 
(iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 
(A)
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
 
 
Definitions - Page 4 of 6
 

 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
 
(B)
The project has been approved for development by all necessary parties and entities, including governmental entities.

 
(v)
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined.  The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties.  Properties with proved reserves.

(24) Reasonable certainty.  If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered.  If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.  A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves.  Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.  In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible.  Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
 
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
 
932-235-50-30  A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

 
a.
Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
 
b.
Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.
 
932-235-50-31  All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
 
 
a.
Future cash inflows.  These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves.  Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.
 
b.
Future development and production costs.  These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.  If estimated development expenditures are significant, they shall be presented separately from estimated production costs.
 
c.
Future income tax expenses.  These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved.  The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
 
d.
Future net cash flows.  These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.
 
 
 
Definitions - Page 5 of 6
 

 
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
 
 
e.
Discount.  This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.
 
f.
Standardized measure of discounted future net cash flows.  This amount is the future net cash flows less the computed discount.
 
(27) Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources.  Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations.  A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable.  Resources include both discovered and undiscovered accumulations.

(29) Service well.  A well drilled or completed for the purpose of supporting production in an existing field.  Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well.  A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition.  Such wells customarily are drilled without the intent of being completed for hydrocarbon production.  The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration.  Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves.  Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 
(i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
 
(ii)
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
 
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
 
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.
 
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

 
Ÿ
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);
 
Ÿ
The company's historical record at completing development of comparable long-term projects;
 
Ÿ
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;
 
Ÿ
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and
 
Ÿ
The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).
 
 
(iii)
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties.  Properties with no proved reserves.
 
Definitions - Page 6 of 6
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padding-bottom: 2px; font-family: 'times new roman'; font-size: 10pt; white-space: nowrap; padding-right: 5px; padding-left: 5px;" nowrap="nowrap">&#160;</td> <td style="padding-bottom: 2px; font-family: 'times new roman'; font-size: 10pt; white-space: nowrap; padding-right: 5px; padding-left: 5px;" align="left">&#160;</td> <td style="text-align: left; font-family: 'times new roman'; font-size: 10pt; border-bottom: #000000 1pt solid !important; white-space: nowrap; padding-right: 5px; padding-left: 5px;">&#160;</td> <td style="text-align: right; font-family: 'times new roman'; border-bottom: #000000 1pt solid !important; vertical-align: bottom; white-space: nowrap;"><font style="display: inline; font-family: times new roman; font-size: 10pt;"><font>41,475</font></font></td> <td style="text-align: left; padding-bottom: 2px; font-family: 'times new roman'; font-size: 10pt; white-space: nowrap; padding-right: 5px; padding-left: 5px;" nowrap="nowrap">&#160;</td> <td style="padding-bottom: 2px; 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See Note 1 of “Notes to Financial Statements” – “Organization and 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. 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 $12.5 million. Capitalized costs relating to oil and gas producing activities as of December 31, 2014 includes a reclassification that was 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 heading “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification. 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 5 thousand barrels and 36 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 24 thousand barrels and 0.1 million barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.9 million mcf and 5.0 million mcf, respectively. Revisions of previous estimates during the year ended December 31, 2015 were attributable to the Carrera Project and to well performance. 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 15 thousand barrels of oil, 1 thousand barrels of NGL's, and 18 thousand mcf's of gas, related to the Carrera Project, which are included in the above table as of December 31, 2014, were not recovered. Revisions of previous estimates during the year ended December 31, 2014 were attributable to well performance. At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project. 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Advances Used For Capital Expenditures In Oil And Gas Properties Reclassified To Proved Properties Unproved Properties Or Dry Hole Costs Advances used for capital expenditures in oil and gas properties reclassified to proved properties The annual rate for distributions paid to the Fund Manager as a percentage of capital contributions, net of cumulative dry-hole costs incurred. Annual Management Fee Percentage Rate Annual management fee percentage rate Carrying value of oil and gas property at date of sale. Carrying Value Of Oil And Gas Property Sold Carrying value of oil and gas properties at date of sale Monthly repayment rate of total principal outstanding for the first seven months of production for a specified project if certain revenue production levels are not met. Debt Instrument Repayment Rate Revenue Contingency First Seven Months Of Production Credit agreement, contingency repayment rate, first seven months of production Monthly repayment rate of total principal outstanding after the first seven months of production for a specified project if certain revenue production levels are not met. Debt Instrument Repayment Rate Revenue Contingency Thereafter Credit agreement, contingency repayment rate, after first seven months of production Distributions of available cash from dispositions made during the period related to the sale of oil and gas properties. Distributions Of Available Cash From Dispositions Related To Sale Of Oil And Gas Property Distributions related to Raven Project Distributions Paid During Period. Distributions Paid During Period Distributions Distributions [Policy Text Block] Distributions [Policy Text Block] Distributions Document and Entity Information [Abstract] Document And Entity Information [Abstract] Amendment Flag Amendment Flag Federal National Mortgage Association Securities Maturing January Two Thousand Forty Two [Member] Federal National Mortgage Association Securities Maturing January Two Thousand Forty Two [Member] FNMA January 2042 [Member] Fund Manager [Member] Fund Manager [Member] The working interest owned, expressed as a percentage, that an entity has in a particular well(s). Gas And Oil Working Interest Percentage Working interest percentage Government National Mortgage Association Securities Maturing July Two Thousand Forty One [Member] Government National Mortgage Association Securities Maturing July Two Thousand Forty One [Member] GNMA July 2041 [Member] Income And Expense Allocation [Policy Text Block] Income And Expense Allocation [Policy Text Block] Income and Expense Allocation LLC Membership Interest, Shares Authorized Llc Membership Interest Shares Authorized Shares authorized Llc Membership Interest, Shares Issued Llc Membership Interest Shares Issued Shares issued Llc Membership Interest, Shares Outstanding Llc Membership Interest Shares Outstanding Balances, shares Balances, shares Shares outstanding Long-Term Purchase Commitment Amount Expected To Be Incurred In Next Twelve Months. Long Term Purchase Commitment Amount Expected To Be Incurred In Next Twelve Months Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months The minimum amount the entity agreed to spend under the long-term purchase commitment that is in excess of available working capital. Long Term Purchase Commitment Amount In Excess Of Working Capital Commitments for the drilling and development of investment properties in excess of working capital The fees paid to the Manager of the Fund for the management of the Fund. Management Fees To Affiliate Management fees to affiliate (Note 3) Annual management fees paid to Fund Manager Distributions to the Manager of the Fund. Manager Distributions Distributions Manager Interest In Net Income Loss Abstract Manager Interest The cumulative earnings (or deficit) for the Manager of the Fund. Manager Retained Earnings Accumulated Deficit Retained earnings Current Fiscal Year End Date Current Fiscal Year End Date The total amount of equity attributable to the Manager of the Fund. Managers Capital Manager's total The maximum cash balance that is insured by the FDIC, per financial institution. Maximum Cash Balance Federally Insured Per Financial Institution Maximum cash balance federally insured per financial institution Manager's interest in net income (loss). Net Income Loss Manager Interest Net (loss) income The net income (loss) per share attributable to the shareholders. Net Income Loss Per Share Shareholder Interest Net (loss) income per share Shareholders' interest in net income (loss). Net Income Loss Shareholder Interest Net (loss) income The percentage of available cash from dispositions allocated to the Fund manager until the shareholders have received total distributions equal to their capital contributions. Percentage Of Available Cash From Dispositions Allocated To Fund Manager Percentage of available cash from dispositions allocated to fund manager The percentage of available cash from dispositions allocated to the Fund manager after shareholders have received distributions equal to their capital contributions. Percentage Of Available Cash From Dispositions Allocated To Fund Manager After Distributions Have Equaled Capital Contributions Percentage of available cash from dispositions allocated to fund manager after distributions have equaled capital contributions The percentage of available cash from dispositions allocated to shareholders until the shareholders have received total distributions equal to their capital contributions. Percentage Of Available Cash From Dispositions Allocated To Shareholders Percentage of available cash from dispositions allocated to shareholders The percentage of available cash from dispositions allocated to shareholders after shareholders have received distributions equal to their capital contributions. Percentage Of Available Cash From Dispositions Allocated To Shareholders After Distributions Have Equaled Capital Contributions Percentage of available cash from dispositions allocated to shareholders after distributions have equaled capital contributions The percentage of cash from operations allocated to the Fund manager. Percentage Of Cash From Operations Allocated To Fund Manager Percentage of cash from operations allocated to fund manager The percentage of cash from operations allocated to shareholders. Percentage Of Cash From Operations Allocated To Shareholders Percentage of cash from operations allocated to shareholders Document Period End Date Document Period End Date Percentage of total distributions allocated to Fund Manager. Percentage Of Total Distributions Allocated To Fund Manager Percentage of total distributions allocated to Fund Manager The cash inflow or outflow relating to salvage fund. Proceeds From Investments In Salvage Fund Net Investments in salvage fund Raven Project [Member] Raven Project [Member] The total cash consideration for the purchase and sale agreement of the oil and gas properties. Sale Of Oil And Gas Properties Cash Consideration Cash consideration Salvage Fund, Noncurrent. Salvage Fund Noncurrent Salvage fund Salvage Fund [Policy Text Block] Salvage Fund [Policy Text Block] Salvage Fund The total amount of equity attributable to the shareholders of the Fund. Shareholders Capital Shareholders' total The amount of capital raised from selling shares. Shareholders Capital Contributions Capital contributions (250 shares authorized; 207.7026 issued and outstanding) Distributions to shareholders. Shareholders Distributions Distributions Shareholders Interest In Net Income Loss Abstract Shareholder Interest The cumulative earnings (or deficit) for the shareholders of the Fund. Shareholders Retained Earnings Accumulated Deficit Retained earnings 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. Shareholders Syndication Costs Syndication costs Syndication Costs [Policy Text Block] Syndication Costs [Policy Text Block] Syndication Costs Value of capitalized expenditures for oil and gas properties owed to operators. Value Of Capital Expenditures For Oil And Gas Properties Owed To Operators Value of capital expenditures for oil and gas properties owed to operators Commitments for asset retirement obligations included in estimated capital commitments. Commitments For Asset Retirement Obligations Included In Estimated Capital Commitments Commitments for asset retirement obligations included in estimated capital commitments Commitments for projected interest costs included in estimated capital commitments. Commitments For Projected Interest Costs Included In Estimated Capital Commitments Commitments for projected interest costs included in estimated capital commitments Salvage Fund, Current. Salvage Fund Current Salvage fund Tabular disclosure of the changes in the standardized measure for discounted future net cash flows. Changes In Standardized Measure For Discounted Cash Flows [Table Text Block] Schedule of Changes in the Standardized Measure for Discounted Cash Flows The amount of discounted cash flows relating to oil and gas properties. Discounted Cash Flows Relating To Oil And Gas Properties Discounted cash flows Shareholder of the Fund Fund Shareholders [Member] Shareholders [Member] InformationAboutOilAndGasProducingActivitiesAbstract Information About Oil And Gas Producing Activities [Abstract] Proved Developed Reserves [Abstract] Proved Developed Reserves Abstract Proved developed reserves: Proved Undeveloped Reserves [Abstract] Proved Undeveloped Reserves Abstract Proved undeveloped reserves: Shares of LLC Interest [Member]. Shares Of Llc Interest [Member] # of Shares [Member] The entire disclosure for supplemental oil and gas activity information. Supplemental Oil And Gas Disclosures [Text Block] Information about Oil and Gas Producing Activities Total costs incurred in oil and gas property acquisitions, exploration and development. Total Costs Incurred In Oil And Gas Property Acquisition Exploration And Development Total costs Amount of increase/decrease in standardized measure of discounted future net cash flow as a result of purchases and sales of minerals in place. Net Change Due To Purchases And Sales Of Minerals In Place Net change due to purchases and sales of minerals in place Reserves that were not recovered. Reserves Not Recovered Reserves not recovered Carrera Project [Member] Carrera Project [Member] The reclassification amount during the period from equipment and facilities in progress to proved properties for oil and gas entities. Reclassification Of Equipment And Facilities In Progress To Proved Properties Reclassification of equipment and facilities in progress Entity Well-known Seasoned Issuer Entity Well-known Seasoned Issuer Entity Voluntary Filers Entity Voluntary Filers Entity Current Reporting Status Entity Current Reporting Status Entity Filer Category Entity Filer Category Entity Public Float Entity Public Float Entity Registrant Name Entity Registrant Name Entity Central Index Key Entity Central Index Key Entity Common Stock, Shares Outstanding Entity Units Outstanding Document Fiscal Year Focus Document Fiscal Year Focus Document Fiscal Period Focus Document Fiscal Period Focus Document Type Document Type Accounts Payable, Current Due to operators Accounts Receivable, Net, Current Production receivable Accretion of Discount Accretion of discount Accrued expenses Accrued Liabilities, Current AOCI Attributable to Parent [Member] Accumulated Other Comprehensive (Loss) Income [Member] Accumulated other comprehensive income Accumulated Other Comprehensive Income (Loss), Net of Tax Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities: Adjustments to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities [Abstract] Amortization of Financing Costs Amortization of financing costs Asset Retirement Obligations Asset Retirement Obligations, Policy [Policy Text Block] Accretion expense Asset Retirement Obligation, Accretion Expense Asset retirement obligations Asset Retirement Obligations, Noncurrent Balance, beginning of period Balance, end of period Asset Retirement Obligation, Revision of Estimate Revisions in estimated cash flows Asset Retirement Obligation Balance, beginning of period Balance, end of period Asset Retirement Obligation, Current Asset retirement obligations Asset Retirement Obligation, Liabilities Incurred Liabilities incurred Assets Assets [Abstract] Assets Total assets Assets, Current Total current assets Assets, Current [Abstract] Current assets: Available-for-sale Securities Fair Value Amortized Cost Available-for-sale Securities, Amortized Cost Basis Available-for-sale Securities, Gross Unrealized Gain Gross Unrealized Gains Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block] Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities Project [Axis] Cash and Cash Equivalents Cash and Cash Equivalents, Policy [Policy Text Block] Cash and cash equivalents Cash and Cash Equivalents, at Carrying Value Cash and cash equivalents, beginning of year Cash and cash equivalents, end of year Cash and Cash Equivalents, Period Increase (Decrease) Net (decrease) increase in cash and cash equivalents Commitments and Contingencies Commitments and contingencies (Note 5) Commitments and Contingencies Commitments and Contingencies Disclosure [Text Block] Commitments and Contingencies [Abstract] Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block] Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development Costs Incurred, Development Costs Development costs Costs Incurred, Exploration Costs Exploration costs Oil and Gas Properties [Abstract] Crude Oil and NGL [Member] NGL (BBLS) [Member] Credit Agreement - Beta Project Financing [Abstract] Credit Agreement - Beta Project Financing Debt Disclosure [Text Block] Debt Instrument, Unamortized Discount Unamortized debt discounts and deferred financing costs Credit agreement, maturity date Debt Instrument, Maturity Date Credit agreement, interest rate Debt Instrument, Interest Rate, Stated Percentage Debt Discounts and Deferred Financing Costs Debt, Policy [Policy Text Block] Depletion Depletion Fair Value Measurement, Policy [Policy Text Block] Fair Value Measurements Full Cost or Successful Efforts, Policy [Policy Text Block] Oil and Gas Properties 10% annual discount for estimated timing of cash flows Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Ten Percent Annual Discount for Estimated Timing of Cash Flows Future development costs Future development costs Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Development Costs Future net cash flows Future net cash flows Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Production Costs Future production costs Future production costs Future cash inflows Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Cash Inflows Gain on sale of oil and gas properties Gain (Loss) on Disposition of Oil and Gas Property Gain on sale of oil and gas properties General and Administrative Expense General and administrative expenses Impaired Long-Lived Assets Held and Used, Asset Name [Domain] Impaired Long-Lived Assets Held and Used [Line Items] Impaired Long-Lived Assets Held and Used by Type [Axis] Impairment of Long-Lived Assets Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block] Impairment of Oil and Gas Properties Impairment of oil and gas properties STATEMENTS OF OPERATIONS AND COMPREHENSIVE (LOSS) INCOME [Abstract] Income Tax, Policy [Policy Text Block] Income Taxes Decrease in production receivable Increase (Decrease) in Accounts Receivable Decrease in due to operators Increase (Decrease) in Accounts Payable Decrease in other current assets Increase (Decrease) in Other Current Assets Increase (decrease) in accrued expenses Increase (Decrease) in Accrued Liabilities Changes in assets and liabilities: Increase (Decrease) in Operating Capital [Abstract] Changes in Estimated Future Development Costs Changes in estimated future development costs Proved Developed and Undeveloped Reserves [Abstract] Proved developed and undeveloped reserves: Capitalized interest Interest Costs Capitalized Interest income Investment Income, Interest Liabilities, Current Total current liabilities Current liabilities: Liabilities, Current [Abstract] Liabilities Total liabilities Liabilities and Equity [Abstract] Liabilities and Members' Capital Liabilities and Equity Total liabilities and members' capital Credit agreement, maximum borrowing capacity Line of Credit Facility, Maximum Borrowing Capacity Long-term borrowings Long-term Debt Long-term borrowings Long-term Debt, Excluding Current Maturities Commitments for the drilling and development of investment properties Long-term Purchase Commitment, Amount Major Types of Debt and Equity Securities [Domain] Major Types of Debt and Equity Securities [Axis] Gas (MCF) [Member] Natural Gas [Member] Cash flows from financing activities Net Cash Provided by (Used in) Financing Activities [Abstract] Net cash (used in) provided by investing activities Net Cash Provided by (Used in) Investing Activities, Continuing Operations Net cash (used in) provided by operating activities Net Cash Provided by (Used in) Operating Activities, Continuing Operations Net (loss) income Net (loss) income Net (loss) income Net Income (Loss) Attributable to Parent Cash flows from investing activities Net Cash Provided by (Used in) Investing Activities [Abstract] Cash flows from operating activities Net Cash Provided by (Used in) Operating Activities [Abstract] Net cash provided by (used in) financing activities Net Cash Provided by (Used in) Financing Activities, Continuing Operations Net change in sales and transfer prices and in production costs related to future production Net Increase (Decrease) in Sales and Transfer Prices and Production Costs New Accounting Pronouncements, Policy [Policy Text Block] Recent Accounting Pronouncements Oil and Gas Revenue Oil and gas revenue Oil and Gas Exploration and Production Industries Disclosures [Text Block] Oil and Gas Properties Oil and Gas Property, Successful Effort Method, Gross Total oil and gas properties Oil (BBLS) [Member] Oil [Member] Oil and Gas Property, Successful Effort Method, Net Total oil and gas properties, net Accumulated depletion and amortization Less: accumulated depletion and amortization Less: accumulated depletion and amortization Oil and Gas Property, Successful Effort Method, Accumulated Depreciation, Depletion and Amortization Expenses Operating Expenses [Abstract] Operating Expenses Total expenses (Loss) income from operations Operating Income (Loss) Operating Costs and Expenses Operating expenses Organization and Summary of Significant Accounting Policies [Abstract] Organization and Summary of Significant Accounting Policies Organization, Consolidation, Basis of Presentation, Business Description and Accounting Policies [Text Block] Other Comprehensive Income (Loss), Net of Tax Total comprehensive (loss) income Other assets Other Assets, Noncurrent Other comprehensive (loss) income Other Comprehensive Income (Loss), Net of Tax [Abstract] Other Assets, Current Other current assets Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Net of Tax Unrealized (loss) gain on marketable securities Other comprehensive income (loss) Other liabilities Other Liabilities, Noncurrent Partner Capital Components [Domain] Partner Capital Components [Axis] Members' capital: Partners' Capital [Abstract] Capital expenditures for oil and gas properties Payments to Acquire Oil and Gas Property Distributions Payments of Capital Distribution Reclassification, Policy [Policy Text Block] Reclassifications Prior Period Reclassification Adjustment Reclassification of general and administrative expenses Long-term borrowings Proceeds from Issuance of Long-term Debt Proceeds from sale of oil and gas properties Proceeds from Sale of Oil and Gas Property and Equipment Project [Domain] Oil and gas properties: Property, Plant and Equipment, Net [Abstract] Depletion and Amortization Property, Plant and Equipment, Policy [Policy Text Block] Beginning of year End of year Proved developed reserves Proved Developed Reserves (Volume) Production Proved Developed and Undeveloped Reserves, Production Proved Oil and Gas Property, Successful Effort Method Proved properties Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table] Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table] Beginning of year End of year Proved Developed and Undeveloped Reserves, Net Proved Developed and Undeveloped Reserves, Sales of Minerals in Place Sales of minerals in place Beginning of year End of year Proved Undeveloped Reserve (Volume) Proved undeveloped reserves Proved Developed and Undeveloped Reserves, Revisions of Previous Estimates Revisions of previous estimates Related Parties Related Party Transactions Disclosure [Text Block] Related Party Transaction [Line Items] Related Party [Axis] Related Party [Domain] Related Parties [Abstract] Reserve Quantities [Line Items] Reserve Quantities [Line Items] Petroleum Reserves [Axis] Reserve 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Document and Entity Information - USD ($)
 12 Months Ended
Dec. 31, 2015
Feb. 29, 2016
Document And Entity Information [Abstract]    
Document Type 10-K  
Amendment Flag false  
Document Period End Date Dec. 31, 2015  
Entity Registrant Name RIDGEWOOD ENERGY A-1 FUND LLC  
Entity Central Index Key 0001457919  
Current Fiscal Year End Date --12-31  
Document Fiscal Period Focus FY  
Document Fiscal Year Focus 2015  
Entity Filer Category Smaller Reporting Company  
Entity Units Outstanding   207.7026
Entity Current Reporting Status Yes  
Entity Well-known Seasoned Issuer No  
Entity Voluntary Filers No  
Entity Public Float $ 0  
XML 18 R2.htm IDEA: XBRL DOCUMENT v3.3.1.900
BALANCE SHEETS - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Current assets:    
Cash and cash equivalents $ 1,444 $ 5,045
Salvage fund 474
Production receivable $ 7 $ 98
Other current assets 21
Total current assets $ 1,925 5,164
Salvage fund 1,310 1,780
Other assets 244 366
Oil and gas properties:    
Proved properties 15,754 14,697
Less: accumulated depletion and amortization (2,958) (6,318)
Total oil and gas properties, net 12,796 8,379
Total assets 16,275 15,689
Current liabilities:    
Due to operators 153 914
Accrued expenses 215 $ 33
Asset retirement obligations 474
Total current liabilities 842 $ 947
Long-term borrowings 2,900 1,800
Asset retirement obligations 1,645 965
Other liabilities 127 48
Total liabilities $ 5,514 $ 3,760
Commitments and contingencies (Note 5)
Members' capital:    
Distributions $ (5,058) $ (5,045)
Retained earnings 5,097 5,152
Manager's total 39 107
Capital contributions (250 shares authorized; 207.7026 issued and outstanding) 41,143 41,143
Syndication costs (4,804) (4,804)
Distributions (35,427) (35,351)
Retained earnings 9,807 10,830
Shareholders' total 10,719 11,818
Accumulated other comprehensive income 3 4
Total members' capital 10,761 11,929
Total liabilities and members' capital $ 16,275 $ 15,689
XML 19 R3.htm IDEA: XBRL DOCUMENT v3.3.1.900
BALANCE SHEETS (Parenthetical) - shares
Dec. 31, 2015
Dec. 31, 2014
BALANCE SHEETS [Abstract]    
Shares authorized 250 250
Shares issued 207.7026 207.7026
Shares outstanding 207.7026 207.7026
XML 20 R4.htm IDEA: XBRL DOCUMENT v3.3.1.900
STATEMENTS OF OPERATIONS AND COMPREHENSIVE (LOSS) INCOME - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Revenue    
Oil and gas revenue $ 487 $ 3,045
Expenses    
Depletion and amortization $ 676 1,198
Impairment of oil and gas properties 646
Management fees to affiliate (Note 3) $ 380 632
Operating expenses 377 819
General and administrative expenses 142 142
Total expenses $ 1,575 3,437
Gain on sale of oil and gas properties 10,396
(Loss) income from operations $ (1,088) 10,004
Interest income 10 16
Net (loss) income (1,078) 10,020
Other comprehensive (loss) income    
Unrealized (loss) gain on marketable securities (1) 7
Total comprehensive (loss) income (1,079) 10,027
Manager Interest    
Net (loss) income (55) 308
Shareholder Interest    
Net (loss) income $ (1,023) $ 9,712
Net (loss) income per share $ (4,928) $ 46,762
XML 21 R5.htm IDEA: XBRL DOCUMENT v3.3.1.900
STATEMENTS OF CHANGES IN MEMBERS' CAPITAL - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Balances $ 11,929 $ 12,429
Balances, shares 207.7026  
Distributions $ (89) (10,527)
Net (loss) income (1,078) 10,020
Other comprehensive income (loss) (1) 7
Balances $ 10,761 $ 11,929
Balances, shares 207.7026 207.7026
# of Shares [Member]    
Balances, shares 207.7026 207.7026
Distributions
Net (loss) income
Other comprehensive income (loss)
Balances, shares 207.7026 207.7026
Fund Manager [Member]    
Balances $ 107 $ 364
Distributions (13) (565)
Net (loss) income $ (55) $ 308
Other comprehensive income (loss)
Balances $ 39 $ 107
Shareholders [Member]    
Balances 11,818 12,068
Distributions (76) (9,962)
Net (loss) income $ (1,023) $ 9,712
Other comprehensive income (loss)
Balances $ 10,719 $ 11,818
Accumulated Other Comprehensive (Loss) Income [Member]    
Balances $ 4 $ (3)
Distributions
Net (loss) income
Other comprehensive income (loss) $ (1) $ 7
Balances $ 3 $ 4
XML 22 R6.htm IDEA: XBRL DOCUMENT v3.3.1.900
STATEMENTS OF CASH FLOWS - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Cash flows from operating activities    
Net (loss) income $ (1,078) $ 10,020
Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities:    
Depletion and amortization $ 676 1,198
Impairment of oil and gas properties 646
Gain on sale of oil and gas properties (10,396)
Accretion expense $ 83 19
Changes in assets and liabilities:    
Decrease in production receivable 91 864
Decrease in other current assets 21 51
Decrease in due to operators (124) (355)
Increase (decrease) in accrued expenses 37 (6)
Net cash (used in) provided by operating activities $ (294) 2,041
Cash flows from investing activities    
Proceeds from sale of oil and gas properties 10,978
Capital expenditures for oil and gas properties $ (4,313) (3,927)
Investments in salvage fund (5) (10)
Net cash (used in) provided by investing activities (4,318) 7,041
Cash flows from financing activities    
Long-term borrowings 1,100 1,800
Distributions (89) (10,527)
Net cash provided by (used in) financing activities 1,011 (8,727)
Net (decrease) increase in cash and cash equivalents (3,601) 355
Cash and cash equivalents, beginning of year 5,045 4,690
Cash and cash equivalents, end of year $ 1,444 5,045
Supplemental schedule of non-cash investing activities    
Advances used for capital expenditures in oil and gas properties reclassified to proved properties $ 68
XML 23 R7.htm IDEA: XBRL DOCUMENT v3.3.1.900
Organization and Summary of Significant Accounting Policies
 12 Months Ended
Dec. 31, 2015
Organization and Summary of Significant Accounting Policies [Abstract]  
Organization and Summary of Significant Accounting Policies
1.   Organization and Summary of Significant Accounting Policies

Organization
The Ridgewood Energy A-1 Fund, LLC (the "Fund"), a Delaware limited liability company, was formed on February 3, 2009 and operates pursuant to a limited liability company agreement (the “LLC Agreement") dated as of March 2, 2009 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, 4 and 5.

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 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority.  Cash and cash equivalents approximate fair value based on Level 1 inputs.  Mortgage-backed securities are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets.

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, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution.  At December 31, 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.  At December 31, 2015 and 2014, the Fund had investments in federal agency mortgage-backed securities as detailed in the following table, which are classified as available for sale.  Available-for-sale securities are carried in the financial statements at fair value.

     Gross
        
Amortized
Unrealized
    
Fair
  
Cost
Gains
    
Value
  
(in thousands)
Government National Mortgage Association security (GNMA July 2041)
        
December 31, 2015
   $ 75     $ 3     $ 78  
December 31, 2014
   $ 84     $ 3     $ 87  
                         
Federal National Mortgage Association security (FNMA January 2042)
          
December 31, 2015
   $ -     $ -     $ -  
December 31, 2014
   $ 109     $ 1     $ 110  

The unrealized gains on the Fund's investments in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of those investments are guaranteed by an agency of the U.S. government.  Unrealized gains or losses on available-for-sale securities are reported in other comprehensive income until realized.  In July 2015, the Fund received all contractual principal and interest payments related to the FNMA January 2042 security and there was no realized gain or loss.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.  Interest earned on the account will become part of the salvage fund.  There are no restrictions on withdrawals from the salvage fund.

Debt Discounts and Deferred Financing Costs
Debt discounts and deferred financing costs include lender fees and other costs of acquiring debt (see Note 4. “Credit Agreement – Beta Project Financing”) such as the conveyance of override royalty interests related to the Beta Project.  These costs are deferred and amortized over the term of the debt period or until the redemption of the debt and are included on the balance sheet within “Other assets”.  At December 31, 2015 and 2014, $0.2 million and $0.4 million, respectively, of debt discounts and deferred financing costs were unamortized.  Amortization expense was $0.1 million for each of the years ended December 31, 2015 and 2014.  During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the balance sheet within “Oil and gas properties”.

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.  The costs of exploratory 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.  Interest costs related to the Credit Agreement (see Note 4. “Credit Agreement – Beta Project Financing”) are capitalized during the period of asset construction.  Annual lease rentals and exploration expenses are expensed as incurred.  All costs related to production activity and workover efforts are expensed as incurred.  Insurance expense related to operating wells of $32 thousand 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 and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.

At December 31, 2015 and 2014, amounts recorded in due to operators totaling $0.1 million and $0.8 million, respectively, related to capital expenditures for oil and gas properties.

Advances to Operators for Working Interests and Expenditures
The Fund may be required to advance its share of the estimated succeeding month's 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 the costs are incurred, the advances are reclassified to 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, 2015 and 2014.
2015
    
2014
  
(in thousands)
  
Balance, beginning of year
 $ 965     $ 946  
Liabilities incurred
   404       -  
Accretion expense
     83       19  
Revisions in estimated cash flows
     667       -  
Balance, end of year
   $ 2,119     $ 965  

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 annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable.  Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review.  If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the 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.

Significant declines in oil and natural gas prices since fourth quarter 2014 have impacted the fair value of the Fund's oil and gas properties.  During the year ended December 31, 2015, the Fund did not record an impairment of oil and gas properties.  During the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $0.6 million, relating to the Carrera Project, which was determined to be uneconomic relative to the remaining reserves and the well was fully impaired.  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.

Depletion and Amortization
Depletion 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.  During the year ended December 31, 2015, the Fund recorded $0.6 million of 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 2012 through 2014 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.  During the year ended December 31, 2014, the Fund made distributions of available cash from dispositions related to the sale of the Raven Project totaling $7.2 million. There were no such distributions during the year ended December 31, 2015.
 
Recent Accounting Pronouncements
In April 2015, the Financial Accounting Standards Board (“FASB”) issued accounting guidance related to the presentation of debt issuance costs in the balance sheet as a direct reduction from the carrying amount of the debt liability, consistent with debt discounts, rather than as an asset.  Amortization of debt issuance costs will continue to be reported as interest expense.  Debt issuance costs related to revolving credit arrangements, however, will continue to be presented as an asset and amortized ratably over the term of the arrangement.  In August 2015, the FASB issued accounting guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements which clarifies that companies may continue to present unamortized debt issuance costs associated with line of credit arrangements as an asset.  These pronouncements are effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, with early adoption permitted.  The Fund is currently evaluating the impact that the adoption of these pronouncements will have on its financial statements.
XML 24 R8.htm IDEA: XBRL DOCUMENT v3.3.1.900
Oil and Gas Properties
 12 Months Ended
Dec. 31, 2015
Oil and Gas Properties [Abstract]  
Oil and Gas Properties
2.  Oil and Gas Properties

On January 17, 2014, the Fund, along with its affiliates, entered into a purchase and sale agreement to sell its 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 25% working interest in the Raven Project and received $11.0 million in cash proceeds from the sale. The net carrying value for the Raven Project on the date of the sale was $0.6 million, thereby resulting in a gain to the Fund of $10.4 million, which was recognized during the year ended December 31, 2014.  There was no such amount recorded during the year ended December 31, 2015.
XML 25 R9.htm IDEA: XBRL DOCUMENT v3.3.1.900
Related Parties
 12 Months Ended
Dec. 31, 2015
Related Parties [Abstract]  
Related Parties
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 were $0.4 million and $0.6 million, respectively.
 
The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund.  Distributions from operations paid to the Manager for the years ended December 31, 2015 and 2014 were $13 thousand and $0.6 million, respectively.  In addition, the Manager is entitled to receive a 1% interest in cash distributions from dispositions.  Distributions from the sale of the Raven project paid to the Manager during the year ended December 31, 2014 were $0.1 million. There were no such distributions during the year ended December 31, 2015.
 
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.
XML 26 R10.htm IDEA: XBRL DOCUMENT v3.3.1.900
Credit Agreement - Beta Project Financing
 12 Months Ended
Dec. 31, 2015
Credit Agreement - Beta Project Financing [Abstract]  
Credit Agreement - Beta Project Financing
4.  Credit Agreement – Beta Project Financing

In November 2012, the Fund entered into a credit agreement (the “Credit Agreement”) with Rahr Energy Investments LLC, as Administrative Agent and Lender (and any other banks or financial institutions that may in the future become a party thereto, collectively “Lenders”) that provides for an aggregate loan commitment to the Fund of approximately $8.3 million (“Loan”), to provide capital toward the funding of the Fund's share of development costs on the Beta Project. Except in cases of fraud and breach of certain representations, the Loan is non-recourse to the Fund's other assets and secured solely by the Fund's interests in the Beta Project. Certain other funds managed by Ridgewood (“Ridgewood Funds”, and when used with the Fund the “Ridgewood Participating Funds”) have also executed the Credit Agreement. Pursuant to the Credit Agreement, each Ridgewood Participating Fund has a separate loan commitment from the Lenders and amounts borrowed are not joint and several obligations. Each of the Ridgewood Participating Funds' borrowings is secured solely by its separate interest in the Beta Project. Therefore, the Fund is liable for the repayment of its Loan and is not liable to the Lenders to repay any loan made to any other Ridgewood Fund. The Manager serves as the manager for each Ridgewood Participating Fund.

The Fund anticipates it will borrow approximately $8.3 million over the development period of the Beta Project. The Loan bears interest at 8% compounded annually and accrues only on Loan proceeds as they are drawn. Principal and interest will not be payable until such time that initial production has commenced for the Beta Project, which is currently expected in third quarter 2016.  At that time, if certain revenue production levels are met, principal and interest will be repaid at a monthly rate of 1.25% of the Fund's total principal outstanding at the date the Beta Project commences production for the first seven months of production, and a monthly rate of 4.5% of the Fund's total principal outstanding at the date the Beta Project commences production thereafter until the Loan is repaid in full, in no event later than December 31, 2020.  The Loan may be prepaid by the Fund without premium or penalty.  As of December 31, 2015 and 2014, the Fund had borrowings of $2.9 million and $1.8 million, respectively, under the Credit Agreement.  As of December 31, 2015 and 2014, interest costs of $0.3 million and $48 thousand, respectively, were capitalized and included on the balance sheet within “Oil and gas properties”.  Such amounts are accrued on the balance sheet within “Accrued expenses” and “Other liabilities” at December 31, 2015 and “Other liabilities” at December 31, 2014.

As additional consideration to the Lenders, the Fund has agreed to convey an overriding royalty interest (“ORRI”) in its working interest in the Beta Project to the Lenders.  The Credit Agreement contains customary covenants, for which the Fund believes it was in compliance at December 31, 2015 and 2014.
XML 27 R11.htm IDEA: XBRL DOCUMENT v3.3.1.900
Commitments and Contingencies
 12 Months Ended
Dec. 31, 2015
Commitments and Contingencies [Abstract]  
Commitments and Contingencies
5.   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.  As of December 31, 2015, the Fund had one non-producing property, the Beta Project, for which additional development costs must be incurred in order to commence production. The Fund currently anticipates such development will include a four-well development with related platform and pipeline infrastructure.

As of December 31, 2015, the Fund's estimated capital commitments related to its oil and gas properties were $7.6 million (which include asset retirement obligations for the Fund's projects of $2.7 million and projected interest costs of $0.1 million for the Beta Project), of which $4.0 million is expected to be spent during the year ending December 31, 2016. These expected capital commitments exceed available working capital and salvage fund by $4.7 million at December 31, 2015.  The Fund has entered into the Credit Agreement to provide capital for funding of the Beta Project.  See Note 4. “Credit Agreement – Beta Project Financing” for additional information.
 
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 and borrowings 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, 2015 and 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.
XML 28 R12.htm IDEA: XBRL DOCUMENT v3.3.1.900
Information about Oil and Gas Producing Activities
 12 Months Ended
Dec. 31, 2015
Information About Oil And Gas Producing Activities [Abstract]  
Information about Oil and Gas Producing Activities
Ridgewood Energy A-1 Fund, LLC
Supplementary Financial Information
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,
  
   
2015
    
2014
  
   
(in thousands)
  
Proved properties
   $ 15,754     $ 14,697  
   Total oil and gas properties (a)
     15,754       14,697  
Accumulated depletion and amortization
     (2,958 )     (6,318 )
Oil and gas properties, net
   $ 12,796     $ 8,379  
 
 
 
(a)
Capitalized costs relating to oil and gas producing activities as of December 31, 2014 includes a reclassification that was 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 heading “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification.



Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
 
Year ended December 31,
2015
  
2014
  
(in thousands)
Exploration costs
 $ 4     $ (3 )
Development costs
     4,983       4,021  
    $ 4,987     $ 4,018  




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.
 
 
December 31, 2015
December 31, 2014
  
United States
Oil (BBLS)
NGL (BBLS)
    
Gas (MCF)
    
Oil (BBLS)
    
NGL (BBLS)
    
Gas (MCF)
  
                         
Proved developed and undeveloped reserves:
                                    
Beginning of year
     306,783       11,395       371,865       355,412       171,648       6,378,017  
Sales of minerals in place (a)
     -       -       -       (40,214 )     (153,769 )     (5,873,539 )
Revisions of previous estimates (b)
     (6,217 )     (6,212 )     (40,625 )     16,383       2,140       (19,471 )
Production
     (8,655 )     (1,219 )     (20,019 )     (24,798 )     (8,624 )     (113,142 )
End of year
     291,911       3,964       311,221       306,783       11,395       371,865  
                                                 
Proved developed reserves:
                                                
Beginning of year
     27,798       11,395       162,625       46,097       41,475       1,182,852  
End of year
     14,355       3,964       103,054       27,798       11,395       162,625  
                                                 
Proved undeveloped reserves:
                                                
Beginning of year
     278,985       -       209,240       309,315       130,173       5,195,165  
End of year (c)
     277,556       -       208,167       278,985       -       209,240  
 
 
(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 5 thousand barrels and 36 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 24 thousand barrels and 0.1 million barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.9 million mcf and 5.0 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.  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 15 thousand barrels of oil, 1 thousand barrels of NGL's, and 18 thousand mcf's of gas, related to the Carrera Project, which are included in the above table as of December 31, 2014, were not recovered. Revisions of previous estimates during the year ended December 31, 2014 were attributable to well performance.


 
(c)
At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project.

 

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
 $ 14,095     $ 29,128  
Future production costs
     (2,086 )     (2,566 )
Future development costs
     (7,029 )     (8,854 )
Future net cash flows
     4,980       17,708  
10% annual discount for estimated timing of cash flows
     (1,605 )     (5,381 )
Standardized measure of discounted future estimated net cash flows
   $ 3,375     $ 12,327  




Table V - Changes in the Standardized Measure for Discounted Future Net 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
 $ (9,551 )   $ (2,638 )
Sales and transfers of oil and gas produced during the period (a)
     (183 )     (2,421 )
Net change due to purchases and sales of minerals in place (b)
     -       (12,530 )
Changes in estimated future development costs
     1,825       4,227  
Net change due to revisions in quantities estimates
     (449 )     743  
Accretion of discount
     1,233       2,407  
Other (a)
     (1,827 )     (1,530 )
Aggregate change in the standardized measure of discounted future net cash
flows for the year
   $ (8,952 )   $ (11,742 )
 
 
(a)
Changes in the standardized 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 “Notes to Financial Statements” – “Organization and 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)
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 $12.5 million.

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.
XML 29 R13.htm IDEA: XBRL DOCUMENT v3.3.1.900
Organization and Summary of Significant Accounting Policies (Policy)
 12 Months Ended
Dec. 31, 2015
Organization and Summary of Significant Accounting Policies [Abstract]  
Use of Estimates
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
Reclassifications
The Fund's financial statements for prior periods include reclassifications that were made to conform to the current-year presentation.
Fair Value Measurements
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 inputs are unobservable inputs and include situations where there is little, if any, market activity for the instrument; hence, these inputs have the lowest priority.  Cash and cash equivalents approximate fair value based on Level 1 inputs.  Mortgage-backed securities are recorded based on Level 2 inputs, as such instruments trade in over-the-counter markets.
Cash and Cash Equivalents
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, deposits may be in excess of federally insured limits, which are $250 thousand per insured financial institution.  At December 31, 2015, the Fund's bank balances were maintained in uninsured bank accounts at Wells Fargo Bank, N.A.
Salvage Fund
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.  At December 31, 2015 and 2014, the Fund had investments in federal agency mortgage-backed securities as detailed in the following table, which are classified as available for sale.  Available-for-sale securities are carried in the financial statements at fair value.

     Gross
        
Amortized
Unrealized
    
Fair
  
Cost
Gains
    
Value
  
(in thousands)
Government National Mortgage Association security (GNMA July 2041)
        
December 31, 2015
   $ 75     $ 3     $ 78  
December 31, 2014
   $ 84     $ 3     $ 87  
                         
Federal National Mortgage Association security (FNMA January 2042)
          
December 31, 2015
   $ -     $ -     $ -  
December 31, 2014
   $ 109     $ 1     $ 110  

The unrealized gains on the Fund's investments in federal agency mortgage-backed securities were the result of fluctuations in market interest rates. The contractual cash flows of those investments are guaranteed by an agency of the U.S. government.  Unrealized gains or losses on available-for-sale securities are reported in other comprehensive income until realized.  In July 2015, the Fund received all contractual principal and interest payments related to the FNMA January 2042 security and there was no realized gain or loss.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.  Interest earned on the account will become part of the salvage fund.  There are no restrictions on withdrawals from the salvage fund.
Debt Discounts and Deferred Financing Costs
Debt Discounts and Deferred Financing Costs
Debt discounts and deferred financing costs include lender fees and other costs of acquiring debt (see Note 4. “Credit Agreement – Beta Project Financing”) such as the conveyance of override royalty interests related to the Beta Project.  These costs are deferred and amortized over the term of the debt period or until the redemption of the debt and are included on the balance sheet within “Other assets”.  At December 31, 2015 and 2014, $0.2 million and $0.4 million, respectively, of debt discounts and deferred financing costs were unamortized.  Amortization expense was $0.1 million for each of the years ended December 31, 2015 and 2014.  During the period of asset construction, amortization expense, as a component of interest, is capitalized and included on the balance sheet within “Oil and gas properties”.
Oil and Gas Properties
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.  The costs of exploratory 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.  Interest costs related to the Credit Agreement (see Note 4. “Credit Agreement – Beta Project Financing”) are capitalized during the period of asset construction.  Annual lease rentals and exploration expenses are expensed as incurred.  All costs related to production activity and workover efforts are expensed as incurred.  Insurance expense related to operating wells of $32 thousand 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 and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.

At December 31, 2015 and 2014, amounts recorded in due to operators totaling $0.1 million and $0.8 million, respectively, related to capital expenditures for oil and gas properties.
Advances to Operators for Working Interests and Expenditures
Advances to Operators for Working Interests and Expenditures
The Fund may be required to advance its share of the estimated succeeding month's 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 the costs are incurred, the advances are reclassified to proved properties.
Asset Retirement Obligations
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, 2015 and 2014.
2015
    
2014
  
(in thousands)
  
Balance, beginning of year
 $ 965     $ 946  
Liabilities incurred
   404       -  
Accretion expense
     83       19  
Revisions in estimated cash flows
     667       -  
Balance, end of year
   $ 2,119     $ 965  

As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.
Syndication Costs
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
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
Impairment of Long-Lived Assets
The Fund reviews the value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable.  Impairments are determined by comparing estimated future net undiscounted cash flows to the carrying value at the time of the review.  If the carrying value exceeds the estimated future net undiscounted cash flows, the carrying value of the asset is written down to fair value, which is determined using estimated future net discounted cash flows from the 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.

Significant declines in oil and natural gas prices since fourth quarter 2014 have impacted the fair value of the Fund's oil and gas properties.  During the year ended December 31, 2015, the Fund did not record an impairment of oil and gas properties.  During the year ended December 31, 2014, the Fund recorded an impairment of oil and gas properties of $0.6 million, relating to the Carrera Project, which was determined to be uneconomic relative to the remaining reserves and the well was fully impaired.  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.
Depletion and Amortization
Depletion and Amortization
Depletion 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.  During the year ended December 31, 2015, the Fund recorded $0.6 million of depletion expense related to adjustments to asset retirement obligations for fully depleted properties.
Income Taxes
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 2012 through 2014 tax returns remain open for examination by tax authorities.
Income and Expense Allocation
Income and Expense Allocation
Profits and losses are allocated to shareholders and the Manager in accordance with the LLC Agreement.
Distributions
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.  During the year ended December 31, 2014, the Fund made distributions of available cash from dispositions related to the sale of the Raven Project totaling $7.2 million. There were no such distributions during the year ended December 31, 2015.
Recent Accounting Pronouncements
Recent Accounting Pronouncements
In April 2015, the Financial Accounting Standards Board (“FASB”) issued accounting guidance related to the presentation of debt issuance costs in the balance sheet as a direct reduction from the carrying amount of the debt liability, consistent with debt discounts, rather than as an asset.  Amortization of debt issuance costs will continue to be reported as interest expense.  Debt issuance costs related to revolving credit arrangements, however, will continue to be presented as an asset and amortized ratably over the term of the arrangement.  In August 2015, the FASB issued accounting guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements which clarifies that companies may continue to present unamortized debt issuance costs associated with line of credit arrangements as an asset.  These pronouncements are effective for fiscal years, and interim periods within those years, beginning after December 15, 2015, with early adoption permitted.  The Fund is currently evaluating the impact that the adoption of these pronouncements will have on its financial statements.
XML 30 R14.htm IDEA: XBRL DOCUMENT v3.3.1.900
Organization and Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2015
Organization and Summary of Significant Accounting Policies [Abstract]  
Summary of Available-For-Sale Securities

     Gross
        
Amortized
Unrealized
    
Fair
  
Cost
Gains
    
Value
  
(in thousands)
Government National Mortgage Association security (GNMA July 2041)
        
December 31, 2015
   $ 75     $ 3     $ 78  
December 31, 2014
   $ 84     $ 3     $ 87  
                         
Federal National Mortgage Association security (FNMA January 2042)
          
December 31, 2015
   $ -     $ -     $ -  
December 31, 2014
   $ 109     $ 1     $ 110  
Schedule of Changes in Asset Retirement Obligations
2015
    
2014
  
(in thousands)
  
Balance, beginning of year
 $ 965     $ 946  
Liabilities incurred
   404       -  
Accretion expense
     83       19  
Revisions in estimated cash flows
     667       -  
Balance, end of year
   $ 2,119     $ 965  
XML 31 R15.htm IDEA: XBRL DOCUMENT v3.3.1.900
Information about Oil and Gas Producing Activities (Tables)
 12 Months Ended
Dec. 31, 2015
Information About Oil And Gas Producing Activities [Abstract]  
Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities
Table I - Capitalized Costs Relating to Oil and Gas Producing Activities
 
   
December 31,
  
   
2015
    
2014
  
   
(in thousands)
  
Proved properties
   $ 15,754     $ 14,697  
   Total oil and gas properties (a)
     15,754       14,697  
Accumulated depletion and amortization
     (2,958 )     (6,318 )
Oil and gas properties, net
   $ 12,796     $ 8,379  
 
 
 
(a)
Capitalized costs relating to oil and gas producing activities as of December 31, 2014 includes a reclassification that was 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 heading “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification.
Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
Table II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development
 
Year ended December 31,
2015
  
2014
  
(in thousands)
Exploration costs
 $ 4     $ (3 )
Development costs
     4,983       4,021  
    $ 4,987     $ 4,018  

Schedule of 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.
 
 
December 31, 2015
December 31, 2014
  
United States
Oil (BBLS)
NGL (BBLS)
    
Gas (MCF)
    
Oil (BBLS)
    
NGL (BBLS)
    
Gas (MCF)
  
                         
Proved developed and undeveloped reserves:
                                    
Beginning of year
     306,783       11,395       371,865       355,412       171,648       6,378,017  
Sales of minerals in place (a)
     -       -       -       (40,214 )     (153,769 )     (5,873,539 )
Revisions of previous estimates (b)
     (6,217 )     (6,212 )     (40,625 )     16,383       2,140       (19,471 )
Production
     (8,655 )     (1,219 )     (20,019 )     (24,798 )     (8,624 )     (113,142 )
End of year
     291,911       3,964       311,221       306,783       11,395       371,865  
                                                 
Proved developed reserves:
                                                
Beginning of year
     27,798       11,395       162,625       46,097       41,475       1,182,852  
End of year
     14,355       3,964       103,054       27,798       11,395       162,625  
                                                 
Proved undeveloped reserves:
                                                
Beginning of year
     278,985       -       209,240       309,315       130,173       5,195,165  
End of year (c)
     277,556       -       208,167       278,985       -       209,240  
 
 
(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 5 thousand barrels and 36 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 24 thousand barrels and 0.1 million barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.9 million mcf and 5.0 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.  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 15 thousand barrels of oil, 1 thousand barrels of NGL's, and 18 thousand mcf's of gas, related to the Carrera Project, which are included in the above table as of December 31, 2014, were not recovered. Revisions of previous estimates during the year ended December 31, 2014 were attributable to well performance.


 
(c)
At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project.
Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas 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
 $ 14,095     $ 29,128  
Future production costs
     (2,086 )     (2,566 )
Future development costs
     (7,029 )     (8,854 )
Future net cash flows
     4,980       17,708  
10% annual discount for estimated timing of cash flows
     (1,605 )     (5,381 )
Standardized measure of discounted future estimated net cash flows
   $ 3,375     $ 12,327  

Schedule of Changes in the Standardized Measure for Discounted Cash Flows
Table V - Changes in the Standardized Measure for Discounted Future Net 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
 $ (9,551 )   $ (2,638 )
Sales and transfers of oil and gas produced during the period (a)
     (183 )     (2,421 )
Net change due to purchases and sales of minerals in place (b)
     -       (12,530 )
Changes in estimated future development costs
     1,825       4,227  
Net change due to revisions in quantities estimates
     (449 )     743  
Accretion of discount
     1,233       2,407  
Other (a)
     (1,827 )     (1,530 )
Aggregate change in the standardized measure of discounted future net cash
flows for the year
   $ (8,952 )   $ (11,742 )
 
 
(a)
Changes in the standardized 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 “Notes to Financial Statements” – “Organization and 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)
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 $12.5 million.
XML 32 R16.htm IDEA: XBRL DOCUMENT v3.3.1.900
Organization and Summary of Significant Accounting Policies (Narrative) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Organization and Summary of Significant Accounting Policies [Abstract]    
Maximum cash balance federally insured per financial institution $ 250  
Unamortized debt discounts and deferred financing costs 200 $ 400
Amortization of financing costs 100 100
Reclassification of general and administrative expenses 32  
Reclassification of equipment and facilities in progress 4,900  
Value of capital expenditures for oil and gas properties owed to operators $ 100 800
Impaired Long-Lived Assets Held and Used [Line Items]    
Impairment of oil and gas properties 646
Depletion $ 600  
Percentage of cash from operations allocated to shareholders 85.00%  
Percentage of cash from operations allocated to fund manager 15.00%  
Percentage of available cash from dispositions allocated to shareholders 99.00%  
Percentage of available cash from dispositions allocated to fund manager 1.00%  
Percentage of available cash from dispositions allocated to shareholders after distributions have equaled capital contributions 85.00%  
Percentage of available cash from dispositions allocated to fund manager after distributions have equaled capital contributions 15.00%  
Distributions related to Raven Project   7,200
Carrera Project [Member]    
Impaired Long-Lived Assets Held and Used [Line Items]    
Impairment of oil and gas properties   $ 600
XML 33 R17.htm IDEA: XBRL DOCUMENT v3.3.1.900
Organization and Summary of Significant Accounting Policies (Schedule of Available-For-Sale Securities) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
GNMA July 2041 [Member]    
Schedule of Available-for-sale Securities [Line Items]    
Amortized Cost $ 75 $ 84
Gross Unrealized Gains 3 3
Fair Value $ 78 87
FNMA January 2042 [Member]    
Schedule of Available-for-sale Securities [Line Items]    
Amortized Cost 109
Gross Unrealized Gains 1
Fair Value $ 110
XML 34 R18.htm IDEA: XBRL DOCUMENT v3.3.1.900
Organization and Summary of Significant Accounting Policies (Schedule of Changes in Asset Retirement Obligations) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Organization and Summary of Significant Accounting Policies [Abstract]    
Balance, beginning of period $ 965 $ 946
Liabilities incurred 404
Accretion expense 83 $ 19
Revisions in estimated cash flows 667
Balance, end of period $ 2,119 $ 965
XML 35 R19.htm IDEA: XBRL DOCUMENT v3.3.1.900
Oil and Gas Properties (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Oil and Gas Properties [Abstract]    
Cash consideration   $ 21,700
Working interest percentage   25.00%
Proceeds from sale of oil and gas properties $ 10,978
Carrying value of oil and gas properties at date of sale   600
Gain on sale of oil and gas properties $ 10,396
XML 36 R20.htm IDEA: XBRL DOCUMENT v3.3.1.900
Related Parties (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Related Party Transaction [Line Items]    
Annual management fee percentage rate 2.50%  
Annual management fees paid to Fund Manager $ 380 $ 632
Percentage of total distributions allocated to Fund Manager 15.00%  
Distributions $ (89) (10,527)
Fund Manager [Member]    
Related Party Transaction [Line Items]    
Distributions $ 13 600
Fund Manager [Member] | Raven Project [Member]    
Related Party Transaction [Line Items]    
Percentage of total distributions allocated to Fund Manager 1.00%  
Distributions   $ 100
XML 37 R21.htm IDEA: XBRL DOCUMENT v3.3.1.900
Credit Agreement - Beta Project Financing (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Credit Agreement - Beta Project Financing [Abstract]    
Credit agreement, maximum borrowing capacity $ 8,300  
Credit agreement, interest rate 8.00%  
Credit agreement, contingency repayment rate, first seven months of production 1.25%  
Credit agreement, contingency repayment rate, after first seven months of production 4.50%  
Credit agreement, maturity date Dec. 31, 2020  
Long-term borrowings $ 2,900 $ 1,800
Capitalized interest $ 300 $ 48
XML 38 R22.htm IDEA: XBRL DOCUMENT v3.3.1.900
Commitments and Contingencies (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2015
USD ($)
Commitments and Contingencies [Abstract]  
Commitments for the drilling and development of investment properties $ 7.6
Commitments for asset retirement obligations included in estimated capital commitments 2.7
Commitments for projected interest costs included in estimated capital commitments 0.1
Commitments for the drilling and development of investment properties expected to be incurred in the next 12 months 4.0
Commitments for the drilling and development of investment properties in excess of working capital $ 4.7
XML 39 R23.htm IDEA: XBRL DOCUMENT v3.3.1.900
Information about Oil and Gas Producing Activities (Schedule of Capitalized Costs Relating to Oil and Gas Producing Activities) (Details) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Information About Oil And Gas Producing Activities [Abstract]    
Proved properties $ 15,754 $ 14,697
Total oil and gas properties [1] 15,754 14,697
Accumulated depletion and amortization (2,958) (6,318)
Total oil and gas properties, net $ 12,796 $ 8,379
[1] Capitalized costs relating to oil and gas producing activities as of December 31, 2014 includes a reclassification that was 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 heading “Oil and Gas Properties” contained in Item 8. “Financial Statements and Supplementary Data” within this Annual Report for more information on the reclassification.
XML 40 R24.htm IDEA: XBRL DOCUMENT v3.3.1.900
Information about Oil and Gas Producing Activities (Schedule of Costs Incurred in Oil and Gas Property Acquisition, Exploration, and Development) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Information About Oil And Gas Producing Activities [Abstract]    
Exploration costs $ 4 $ (3)
Development costs 4,983 4,021
Total costs $ 4,987 $ 4,018
XML 41 R25.htm IDEA: XBRL DOCUMENT v3.3.1.900
Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Details)
 12 Months Ended
Dec. 31, 2015
bbl
Mcf
Dec. 31, 2014
bbl
Mcf
Oil (BBLS) [Member]    
Proved developed and undeveloped reserves:    
Beginning of year 306,783 355,412
Sales of minerals in place [1] (40,214)
Revisions of previous estimates [2] (6,217) 16,383
Production (8,655) (24,798)
End of year 291,911 306,783
Proved developed reserves:    
Beginning of year 27,798 46,097
End of year 14,355 27,798
Proved undeveloped reserves:    
Beginning of year 278,985 [3] 309,315
End of year [3] 277,556 278,985
NGL (BBLS) [Member]    
Proved developed and undeveloped reserves:    
Beginning of year 11,395 171,648
Sales of minerals in place [1] (153,769)
Revisions of previous estimates [2] (6,212) 2,140
Production (1,219) (8,624)
End of year 3,964 11,395
Proved developed reserves:    
Beginning of year 11,395 41,475
End of year 3,964 11,395
Proved undeveloped reserves:    
Beginning of year [3] 130,173
End of year [3]
Gas (MCF) [Member]    
Proved developed and undeveloped reserves:    
Beginning of year | Mcf 371,865 6,378,017
Sales of minerals in place | Mcf [1] (5,873,539)
Revisions of previous estimates | Mcf [2] (40,625) (19,471)
Production | Mcf (20,019) (113,142)
End of year | Mcf 311,221 371,865
Proved developed reserves:    
Beginning of year | Mcf 162,625 1,182,852
End of year | Mcf 103,054 162,625
Proved undeveloped reserves:    
Beginning of year | Mcf 209,240 [3] 5,195,165
End of year | Mcf [3] 208,167 209,240
[1] 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 5 thousand barrels and 36 thousand barrels, respectively, proved developed and undeveloped NGL reserves of approximately 24 thousand barrels and 0.1 million barrels, respectively, and proved developed and undeveloped gas reserves of approximately 0.9 million mcf and 5.0 million mcf, respectively.
[2] Revisions of previous estimates during the year ended December 31, 2015 were attributable to the Carrera Project and to well performance. 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 15 thousand barrels of oil, 1 thousand barrels of NGL's, and 18 thousand mcf's of gas, related to the Carrera Project, which are included in the above table as of December 31, 2014, were not recovered. Revisions of previous estimates during the year ended December 31, 2014 were attributable to well performance.
[3] At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project.
XML 42 R26.htm IDEA: XBRL DOCUMENT v3.3.1.900
Information about Oil and Gas Producing Activities (Schedule of Reserve Quantity Information) (Parenthetical) (Details)
Dec. 31, 2015
bbl
Mcf
Jan. 31, 2015
bbl
Mcf
Dec. 31, 2014
bbl
Mcf
Jan. 17, 2014
bbl
Mcf
Dec. 31, 2013
bbl
Mcf
Oil (BBLS) [Member]          
Reserve Quantities [Line Items]          
Proved developed reserves 14,355   27,798 5,000 46,097
Proved undeveloped reserves 277,556 [1]   278,985 [1] 36,000 309,315
Reserves not recovered   15,000      
NGL (BBLS) [Member]          
Reserve Quantities [Line Items]          
Proved developed reserves 3,964   11,395 24,000 41,475
Proved undeveloped reserves [1]   [1] 100,000 130,173
Reserves not recovered   1,000      
Gas (MCF) [Member]          
Reserve Quantities [Line Items]          
Proved developed reserves | Mcf 103,054   162,625 900,000 1,182,852
Proved undeveloped reserves | Mcf 208,167 [1]   209,240 [1] 5,000,000 5,195,165
Reserves not recovered | Mcf   18,000      
[1] At December 31, 2014, the decreases in proved undeveloped reserves were principally due to the sale of the Raven Project.
XML 43 R27.htm IDEA: XBRL DOCUMENT v3.3.1.900
Information about Oil and Gas Producing Activities (Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves) (Details) - USD ($)
$ in Thousands
Dec. 31, 2015
Dec. 31, 2014
Information About Oil And Gas Producing Activities [Abstract]    
Future cash inflows $ 14,095 $ 29,128
Future production costs (2,086) (2,566)
Future development costs (7,029) (8,854)
Future net cash flows 4,980 17,708
10% annual discount for estimated timing of cash flows (1,605) (5,381)
Standardized measure of discounted future estimated net cash flows $ 3,375 $ 12,327
XML 44 R28.htm IDEA: XBRL DOCUMENT v3.3.1.900
Information about Oil and Gas Producing Activities (Schedule of Changes in the Standardized Measure for Discounted Cash Flows) (Details) - USD ($)
$ in Thousands
 12 Months Ended
Dec. 31, 2015
Dec. 31, 2014
Dec. 31, 2013
Information About Oil And Gas Producing Activities [Abstract]      
Net change in sales and transfer prices and in production costs related to future production $ (9,551) $ (2,638)  
Sales and transfers of oil and gas produced during the period [1] $ (183) (2,421)  
Net change due to purchases and sales of minerals in place [2] (12,530)  
Changes in estimated future development costs $ 1,825 4,227  
Net change due to revisions in quantities estimates (449) 743  
Accretion of discount 1,233 2,407  
Other [1] (1,827) (1,530)  
Aggregate change in the standardized measure of discounted future net cash flows for the year $ (8,952) $ (11,742)  
Discounted cash flows     $ 12,500
[1] Changes in the standardized 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 “Notes to Financial Statements” – “Organization and 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.
[2] 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 $12.5 million.
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