10-Q 1 o11717110q.htm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017
or
☐
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. 000-51924

Ridgewood Energy O Fund, LLC
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of
incorporation or organization)
76-0774429
(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)

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 ☒    No ☐

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 ☒     No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934.

Large accelerated filer
☐
Accelerated filer
☐
Non-accelerated filer
(Do not check if a smaller reporting company)
☐
Smaller reporting company
Emerging growth company
☒
☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Securities Exchange Act of 1934. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).  Yes ☐    No ☒

As of November 7, 2017 there were 870.6486 shares of LLC Membership Interest outstanding.
 
 
 
 
Table of Contents

 
PAGE
PART I - FINANCIAL INFORMATION
  
Item 1.
 1
    1
    2
    3
    4
Item 2.
 8
Item 3.
 14
Item 4.
 15
   
PART II - OTHER INFORMATION
  
Item 1.
 15
Item 1A.
 15
Item 2.
 15
Item 3.
 15
Item 4.
 15
Item 5.
 15
Item 6.
 15
     
  16


 
PART I – FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

RIDGEWOOD ENERGY O FUND, LLC
UNAUDITED CONDENSED BALANCE SHEETS
(in thousands, except share data)

      
September 30, 2017
    
December 31, 2016
  
Assets
            
Current assets:
            
Cash and cash equivalents
  
$
3,096
    
$
2,366
  
Salvage fund
    
528
      
-
  
Production receivable
    
1,100
      
1,198
  
Other current assets
    
189
      
234
  
Total current assets
    
4,913
      
3,798
  
Salvage fund
    
1,807
      
2,405
  
Investment in Delta House
    
119
      
119
  
Oil and gas properties:
                
Proved properties
    
69,052
      
64,348
  
Less:  accumulated depletion and amortization
    
(30,189
)
    
(22,242
)
Total oil and gas properties, net
    
38,863
      
42,106
  
Total assets
  
$
45,702
    
$
48,428
  
                 
Liabilities and Members' Capital
                
Current liabilities:
                
Due to operators
  
$
1,828
    
$
1,650
  
Accrued expenses
    
1,946
      
2,985
  
Current portion of long-term borrowings
    
10,428
      
6,424
  
Asset retirement obligations
    
528
      
-
  
Total current liabilities
    
14,730
      
11,059
  
Long-term borrowings
    
13,613
      
17,349
  
Asset retirement obligations
    
2,377
      
2,821
  
Other liabilities
    
100
      
100
  
Total liabilities
    
30,820
      
31,329
  
Commitments and contingencies (Note 4)
                
Members' capital:
                
Manager:
                
Distributions
    
(5,536
)
    
(5,536
)
Retained earnings
    
5,178
      
4,116
  
Manager's total
    
(358
)
    
(1,420
)
Shareholders:
                
Capital contributions (935 shares authorized;
                
   870.6486 issued and outstanding)
    
128,990
      
128,990
  
Syndication costs
    
(14,742
)
    
(14,742
)
Distributions
    
(33,548
)
    
(33,548
)
Accumulated deficit
    
(65,460
)
    
(62,181
)
Shareholders' total
    
15,240
      
18,519
  
Total members' capital
    
14,882
      
17,099
  
Total liabilities and members' capital
  
$
45,702
    
$
48,428
  

The accompanying notes are an integral part of these unaudited condensed financial statements.
 
 
RIDGEWOOD ENERGY O FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS
(in thousands, except per share data)

     
Three months ended September 30,
    
Nine months ended September 30,
  
   
2017
    
2016
    
2017
    
2016
  
Revenue
                        
Oil and gas revenue
  
$
3,699
    
$
1,777
    
$
11,350
    
$
4,154
  
Expenses
                                
Depletion and amortization
    
1,451
      
838
      
7,947
      
2,094
  
Impairment of oil and gas properties
    
-
      
-
      
-
      
13
  
Management fees to affiliate (Note 2)
    
316
      
233
      
947
      
932
  
Operating expenses
    
829
      
903
      
2,603
      
2,671
  
General and administrative expenses
    
43
      
40
      
183
      
112
  
Total expenses
    
2,639
      
2,014
      
11,680
      
5,822
  
Income (loss) from operations
    
1,060
      
(237
)
    
(330
)
    
(1,668
)
Other income (loss)
                                
Loss on investment in Delta House
    
-
      
(110
)
    
-
      
(110
)
Dividend income
    
7
      
58
      
19
      
181
  
Interest expense, net
    
(641
)
    
(583
)
    
(1,906
)
    
(580
)
Total other loss
    
(634
)
    
(635
)
    
(1,887
)
    
(509
)
Net income (loss)
  
$
426
    
$
(872
)
  
$
(2,217
)
  
$
(2,177
)
                                 
Manager Interest
                                
Net income
  
$
362
    
$
85
    
$
1,062
    
$
69
  
                                 
Shareholder Interest
                                
Net income (loss)
  
$
64
    
$
(957
)
  
$
(3,279
)
  
$
(2,246
)
Net income (loss) per share
  
$
74
    
$
(1,100
)
  
$
(3,766
)
  
$
(2,580
)

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


 
RIDGEWOOD ENERGY O FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)

      
Nine months ended September 30,
  
   
2017
    
2016
  
             
Cash flows from operating activities
            
Net loss
  
$
(2,217
)
  
$
(2,177
)
Adjustments to reconcile net loss to net cash
                
provided by operating activities:
                
Depletion and amortization
    
7,947
      
2,094
  
Impairment of oil and gas properties
    
-
      
13
  
Accretion expense
    
78
      
-
  
Loss on investment in Delta House
    
-
      
110
  
Amortization of debt discounts and deferred financing costs
    
268
      
90
  
Changes in assets and liabilities:
                
Decrease (increase) in production receivable
    
98
      
(390
)
Decrease (increase) in other current assets
    
45
      
(179
)
Increase in due to operators
    
48
      
52
  
Increase in accrued expenses
    
872
      
535
  
Net cash provided by operating activities
    
7,139
      
148
  
                 
Cash flows from investing activities
                
Capital expenditures for oil and gas properties
    
(6,479
)
    
(3,781
)
Decrease (increase) in salvage fund
    
70
      
(342
)
Net cash used in investing activities
    
(6,409
)
    
(4,123
)
 
                
Cash flows from financing activities
    
-
      
-
  
                 
Net increase (decrease) in cash and cash equivalents
    
730
      
(3,975
)
Cash and cash equivalents, beginning of period
    
2,366
      
5,669
  
Cash and cash equivalents, end of period
  
$
3,096
    
$
1,694
  
                 
Supplemental disclosure of cash flow information
                
Cash paid for interest, net of amounts capitalized
  
$
771
    
$
-
  
                 
Supplemental disclosure of non-cash investing activities
                
Due to operators for accrued capital expenditures for
 oil and gas properties
  
$
1,168
    
$
634
  

The accompanying notes are an integral part of these unaudited condensed financial statements.
 
 
RIDGEWOOD ENERGY O FUND, LLC
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

1.
Organization and Summary of Significant Accounting Policies

Organization
The Ridgewood Energy O Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on December 21, 2004 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of February 16, 2005 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.  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, the preparation, review and dissemination of tax and other financial information and the management of the Fund’s investments in projects.  In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations.  The Manager also engages and manages contractual relations with unaffiliated custodians, depositories, accountants, attorneys, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 3 and 4.

Basis of Presentation
These unaudited interim condensed financial statements have been prepared by the Fund’s management in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and in the opinion of management, contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Fund’s financial position, results of operations and cash flows for the periods presented.  Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been omitted in these unaudited interim condensed financial statements.  The results of operations, financial position, and cash flows for the periods presented herein are not necessarily indicative of future financial results.  These unaudited interim condensed financial statements should be read in conjunction with the Fund’s December 31, 2016 financial statements and notes thereto included in the Fund’s Annual Report on Form 10-K (“2016 Annual Report”) filed with the Securities and Exchange Commission (“SEC”).  The year-end condensed balance sheet data was derived from audited financial statements for the year ended December 31, 2016, but does not include all annual disclosures required by GAAP.

Use of Estimates
The preparation of financial statements in accordance with 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, depletion and amortization, determination of proved reserves, impairment of long-lived assets and asset retirement obligations. Actual results may differ from those estimates.

Summary of Significant Accounting Policies
The Fund has provided discussion of significant accounting policies in Note 1 of “Notes to Financial Statements” – “Organization and Summary of Significant Accounting Policies” contained in Item 8. “Financial Statements and Supplementary Data” within its 2016 Annual Report. There have been no significant changes to the Fund’s significant accounting policies during the three and nine months ended September 30, 2017.

Investment in Delta House
The Fund has investments in Delta House Oil and Gas Lateral, LLC and Delta House FPS, LLC (collectively “Delta House”), legal entities that own interests in a deepwater floating production system operated by LLOG Exploration Company. The Fund accounts for its investment in Delta House using the cost method of accounting for investments as it does not have the ability to exercise significant influence over such investment.  Under the cost method, the Fund recognizes an investment in the equity of an investee at cost.   The Fund reviews its cost method investment for impairment at each reporting period and when an event or change in circumstances has occurred that may have a significant adverse effect on the fair value of the investment. Losses on cost method investments including impairments that are deemed to be other than temporary are classified as non-operating losses in the Fund’s statements of operations. During the three and nine months ended September 30, 2017, there were no such events or changes in circumstances that indicate that the Fund’s investment in Delta House is impaired.
 
 
As of September 30, 2016, the Fund invested a total of $0.6 million in Delta House and had received and recorded dividends totaling $0.3 million. During third quarter 2016, the Fund received an offer from a third party for the purchase of approximately 74% of its investment for $0.3 million in cash. The transaction closed pursuant to a unit purchase agreement with D-Day Offshore Holdings, LLC dated October 31, 2016. Certain other funds managed by the Manager were also parties to this unit purchase agreement. The Fund adjusted the carrying value of its investment in Delta House in third quarter 2016 to fair value, which was determined based on the third party sale and recorded a loss on investment during the three and nine months ended September 30, 2016 of $0.1 million. The loss was included on the Fund’s statement of operations within “Loss on investment in Delta House”. There was no such amount recorded during the three and nine months ended September 30, 2017.  Inputs used to estimate fair value of the investment in Delta House are categorized as Level 3 in the fair value hierarchy.

Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. Upon the determination that a property is either proved or dry, a retirement obligation is incurred. The Fund recognizes the fair value of a liability for an asset retirement obligation in the period incurred.  Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.  At least bi-annually, or more frequently if an event occurs that would dictate a change in assumptions or estimates underlying the obligations, the Fund reassesses its asset retirement obligations to determine whether any revisions to the obligations are necessary.  The Fund maintains a salvage fund to provide for the funding of asset retirement obligations.

Impairment of Long-Lived Assets
The Fund reviews the carrying value of its oil and gas properties annually and when management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable.  Impairments 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 future net discounted cash flows from proved oil and natural gas reserves could change in the near term.

Fluctuations in oil and natural gas prices may impact the fair value of the Fund’s oil and gas properties. There were no impairments of oil and gas properties during the three and nine months ended September 30, 2017 and during the three months ended September 30, 2016.  During the nine months ended September 30, 2016, the Fund recorded impairments of oil and gas properties of $13 thousand, which represented the carrying value of Eugene Island 346/347.  The impairment was primarily attributable to declines in future oil and natural gas prices.  If oil and natural gas prices decline, even if only for a short period of time, it is possible that additional impairments of oil and gas properties will occur.
 
Recent Accounting Pronouncements
In January 2016, the Financial Accounting Standards Board (“FASB”) issued accounting guidance that requires, among other things, companies to measure investments in other entities, except those accounted for under the equity method, at fair value and recognize any changes in fair value in net income unless an election is made to record the investment at cost, less impairment and plus or minus subsequent adjustments for observable price changes with change in basis reported in current earnings. This pronouncement is effective for the Fund in the first quarter of 2018. Early adoption is not permitted. The Fund does not expect the accounting guidance will have a material impact on its financial statements upon adoption.

In May 2014, the FASB issued accounting guidance on revenue recognition, which provides for a single five-step model to be applied to all revenue contracts with customers. In July 2015, the FASB issued a deferral of the effective date of the guidance to 2018, with early adoption permitted in 2017. In March 2016, the FASB issued accounting guidance, which clarifies the implementation guidance on principal versus agent considerations in the new revenue recognition standard. In April 2016, the FASB issued guidance on identifying performance obligations and licensing and in May 2016, the FASB issued final amendments which provided narrow scope improvements and practical expedients related to the implementation of the guidance.  The accounting guidance may be applied either retrospectively or through the use of a modified-retrospective method. The Fund has substantially completed the evaluation of the accounting guidance and currently expects the adoption of the accounting guidance will not have a material impact on the Fund’s financial statements. Under the new accounting guidance, the revenue associated with the Fund’s existing contracts will be recognized in the period that control of the related commodity is transferred to the customer, which is generally consistent with its current revenue recognition model.  The Fund will adopt the new accounting guidance using the modified retrospective method at the date of adoption, which is January 1, 2018.  Although the Fund has not identified changes to its revenue recognition that would result in a material cumulative effect adjustment to retained earnings on January 1, 2018, the Fund expects the adoption of the accounting guidance will result in enhanced disclosures related to revenue recognition policies, the Fund’s performance obligations and significant judgments used in applying the new revenue recognition accounting guidance.
 

 
2.
Related Parties

Pursuant to the terms of the LLC Agreement, the Manager is entitled to 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.  In addition, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion. Such fee may be temporarily waived to accommodate the Fund’s short-term capital commitments.  Management fees during the three and nine months ended September 30, 2017 were $0.3 million and $0.9 million, respectively. Management fees during the three and nine months ended September 30, 2016 were $0.2 million and $0.9 million, respectively.

The Manager is also entitled to receive a 15% interest in cash distributions from operations made by the Fund.  The Fund did not pay distributions during the three and nine months ended September 30, 2017 and 2016.

In 2016, the Fund entered into master agreements with Beta Sales and Transport, LLC and DH Sales and Transport, LLC, wholly owned subsidiaries of the Manager, to facilitate the transportation and sale of oil and natural gas produced from the Beta, Diller and Marmalard projects. The Fund has provided discussion of these agreements in Note 2 of “Notes to Financial Statements” – “Related Parties” contained in Item 8. “Financial Statements and Supplementary Data” within its 2016 Annual Report.

At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.

The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects, which are also owned by other entities that are likewise managed by the Manager.

3.
Credit Agreement – Beta Project Financing

As of September 30, 2017 and December 31, 2016, the Fund had borrowings of $24.1 million under the credit agreement. The loan bears interest at 8% compounded annually.  Principal and interest are repaid at the lesser of the Monthly Fixed Amount or the Debt Service Cap amount, as defined in the credit agreement, 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, 2016, in accordance with the terms of the credit agreement, there are no additional borrowings available to the Fund. On September 15, 2017, the Fund and other participating funds managed by the Manager, entered into the second amendment to the credit agreement (“Second Amendment”). The Second Amendment principally amended the definition of net revenues, which is the basis for the calculation of the Debt Service Cap amount.

Unamortized debt discounts and deferred financing costs of $0.1 million as of September 30, 2017 and $0.4 million as of December 31, 2016 are presented as a reduction of “Long-term borrowings” on the balance sheets.  Amortization expense during the three and nine months ended September 30, 2017 of $0.1 million and $0.3 million, respectively, and amortization expense during the three months ended September 30, 2016 of $0.1 million were expensed and included on the statements of operations within “Interest expense, net”. Amortization expense during the nine months ended September 30, 2016 of $0.2 million was capitalized and included on the balance sheet within “Oil and gas properties”.
 
As of September 30, 2017 and December 31, 2016, accrued interest costs of $1.9 million and $2.9 million, respectively, were included on the balance sheets within “Accrued expenses”. Interest costs incurred during the three and nine months ended September 30, 2017 of $0.6 million and $1.6 million, respectively, and interest costs incurred during the three months ended September 30, 2016 of $0.5 million were expensed and included on the statements of operations within “Interest expense, net”. Interest costs incurred during the nine months ended September 30, 2016 of $1.0 million were capitalized and included on the balance sheet within “Oil and gas properties”. During the nine months ended September 30, 2017, the Fund made payments on the loan of $1.9 million, which related to capitalized interest costs.
 
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. Such ORRI will not accrue or become payable to the lenders until after the loan is repaid in full. The credit agreement contains customary covenants, with which the Fund was in compliance as of September 30, 2017 and December 31, 2016.

4.
Commitments and Contingencies

Capital Commitments
As of September 30, 2017, the Fund’s estimated capital commitments related to its oil and gas properties were $12.5 million (which include asset retirement obligations for the Fund’s projects of $5.9 million), of which $3.4 million is expected to be spent during the next twelve months primarily related to the additional development costs for the Beta Project.  Additionally, current liabilities exceed current assets as of September 30, 2017.  Future results of operations and cash flows are dependent on the continued successful development and the related production of oil and gas revenues from the Beta Project.
 
 
Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, borrowing repayments and 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 commitments, the Manager will temporarily waive all or a portion of the management fee as well as provide short-term financing to accommodate the Fund’s short-term commitments if needed.

Environmental and Governmental Regulations
Many aspects of the oil and gas industry are subject to federal, state and local environmental laws and regulations. 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. 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. As of September 30, 2017 and December 31, 2016, there were no known environmental contingencies that required adjustment to, or disclosure in, the Fund’s financial statements.

Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. 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. 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.

BOEM Notice to Lessees on Supplemental Bonding
On July 14, 2016, the Bureau of Ocean Energy Management (“BOEM”) issued a Notice to Lessees (“NTL”) that discontinued and materially replaced existing policies and procedures regarding financial security (i.e. supplemental bonding) for decommissioning obligations of lessees of federal oil and gas leases and owners of pipeline rights-of-way, rights-of use and easements on the Outer Continental Shelf (“Lessees”).  Generally, the new NTL (i) ended the practice of excusing Lessees from providing such additional security where co-lessees had sufficient financial strength to meet such decommissioning obligations, (ii) established new criteria for determining financial strength and additional security requirements of such Lessees,  (iii) provided acceptable forms of such additional security and (iv) replaced the waiver system with one of self-insurance.  The new rule became effective as of September 12, 2016; however on January 6, 2017, the BOEM announced that it was suspending the implementation timeline for six months in certain circumstances.  On June 22, 2017, the BOEM announced that the implementation timeline extension will remain in effect pending the completion of its review of the new NTL. The Fund, as well as other industry participants, are working with the BOEM, its operators and working interest partners to determine and agree upon the correct level of decommissioning obligations to which they may be liable and the manner in which such obligations will be secured.  The impact of the NTL, if enforced without change or amendment, may require the Fund to fully secure all of its potential abandonment liabilities to the BOEM’s satisfaction using one or more of the enumerated methods for doing so.  Potentially this could increase costs to the Fund if the Fund is required to obtain additional supplemental bonding, fund escrow accounts or obtain letters of credit.

Insurance Coverage
The Fund is subject to all risks inherent in the oil and natural gas business. 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.  Depending on the extent, nature and payment of claims made by the Fund or other funds managed by the Manager, yearly insurance coverage may be exhausted and become insufficient to cover a claim by the Fund in a given year.
 
 
ITEM 2.          MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Statement Regarding Forward-Looking Statements

Certain statements in this Quarterly Report on Form 10-Q (“Quarterly Report”) and the documents Ridgewood Energy O Fund, LLC (the “Fund”) has incorporated by reference into this Quarterly Report, other than purely historical information, including estimates, projections, 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 U.S. 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 and other conditions affecting the pricing, production and demand of oil and natural gas, the cost and availability of equipment, and changes in domestic and foreign governmental regulations.  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.

Critical Accounting Policies and Estimates

There were no changes to the Fund’s critical accounting policies and estimates from those disclosed in its Annual Report on Form 10-K for the year ended December 31, 2016.

Overview of the Fund’s Business

The Fund was organized primarily to 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’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of oil and natural gas projects. Distributions to shareholders are made in accordance with the Fund’s limited liability company agreement (the “LLC Agreement”).

Ridgewood Energy Corporation (the “Manager”) is the Manager, and as such, 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 the Fund’s operations.  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 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.  The Manager also participates in distributions.

Commodity Price Changes

Changes in commodity prices may significantly affect liquidity and expected operating results.  Declines 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.

Oil and natural gas commodity prices have been subject to significant fluctuations during the past several years. The Fund anticipates price cyclicality in its planning and believes it is well positioned to withstand price volatility. Despite operating in a sustained lower commodity price environment, the Fund continued to advance the development of the Beta Project, which commenced production during the second half of 2016. The Fund has suspended distributions and continues to conserve cash to provide for the continued development of the Beta Project.  See “Results of Operations” under this Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report for more information on the average oil and natural gas prices received by the Fund during the three and nine months ended September 30, 2017 and 2016 and the effect of such average prices on the Fund’s results of operations.  If oil and natural gas commodity prices decline, even if only for a short period of time, the Fund’s results of operations and liquidity will 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 supply and price of foreign oil and gas;
·
the cost of exploring for, producing and delivering oil and gas;
·
the discovery rate of new oil and gas reserves;
·
the rate of decline of existing and new oil and gas reserves;
·
available pipeline and other oil and gas transportation capacity;
·
the ability of oil and gas companies to raise capital;
·
the overall supply and demand for oil and gas; and
·
the price and availability of alternate fuel sources.
 
Business Update
 
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.  See “Liquidity Needs” under this Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report for information regarding the funding of the Fund’s capital commitments.
 
 
                            
           
Total Spent
    
Total
    
    
Working
    
through
    
Fund
    
Project
  
Interest
    
September 30, 2017
    
Budget
  
Status
           
(in thousands)
    
Producing Properties
                         
Beta Project
    
5.0%
    
$
42,605
    
$
48,555
  
The Beta Project is expected to include the development of five wells.  Wells #1 and #2 commenced production during third quarter 2016 and fourth quarter 2016, respectively.  Wells #3 and #4 commenced production during second  quarter 2017 and  third quarter 2017, respectively. Well #5 began drilling in third quarter 2017 and is expected to commence production in first quarter 2018. The Fund expects to spend $3.6 million for additional development costs and $2.3 million for asset retirement obligations.
Cobalt Project
    
4.0%
    
$
1,894
    
$
1,985
  
The Cobalt Project, a single-well project, commenced production in 2009.  Recompletions are planned for 2018 at estimated total costs of $36 thousand.  The Fund expects to spend $0.1 million for asset retirement obligations.
Diller Project
    
0.88%
    
$
2,770
    
$
3,865
  
The Diller Project is expected to include the development of two wells.  Well #1 commenced production in 2015.  Well #2 is expected to commence production in 2019. Well #1, which  was shut-in in late-2016 due to well hydrate remediation work, resumed production in mid-January 2017. The Fund expects to spend $0.7 million for additional development costs and $0.4 million for asset retirement obligations.
Eugene Island 346/347
    
5.0%
    
$
4,197
    
$
4,501
  
Eugene Island 346/347 consists of two wells, which commenced production in 2008. Both wells are producing at nominal rates and nearing the end of their productive lives.  The Fund expects to spend $0.3 million for asset retirement obligations.
Liberty Project
    
5.0%
    
$
5,578
    
$
6,680
  
The Liberty Project, a single-well project, commenced production in 2010.  After various shut-ins in late-2015 and early-2016, due to third-party facilities' repair and maintenance activities, the well resumed production in early-May 2016.  The well was shut-in again in late-June 2017 due to gas dehydration unit work, resuming production in late-September 2017. The operator is currently flowing the well's current zone together with the behind-pipe zone at no cost to the Fund.  The Fund expects to spend $1.1 million for asset retirement obligations.
Marmalard Project
    
0.88%
    
$
5,552
    
$
8,753
  
The Marmalard Project is expected to include the development of six wells.  Four wells commenced production in 2015.  Additional wells are expected to commence production in 2019 and 2020.  The Fund expects to spend $2.1 million for additional development costs and $1.1 million for asset retirement obligations.
South Pelto 9
    
16.67%
    
$
5,026
    
$
5,233
  
South Pelto 9, a single-well project, commenced production in 2007.  After various shut-ins in late-2015 and early-2016, due to third-party facilities' repair and maintenance activities,  the well resumed production in late-April 2016. The well, which was shut-in again during the majority of second and third quarter of 2017 due to third-party facilities' repair and maintenance, is producing at nominal rates. The Fund expects to spend $0.2 million for asset retirement obligations.
 
 
Results of Operations

The following table summarizes the Fund’s results of operations during the three and nine months ended September 30, 2017 and 2016, and should be read in conjunction with the Fund’s financial statements and notes thereto included within Item 1.  “Financial Statements” in Part I of this Quarterly Report.

     
Three months ended September 30,
    
Nine months ended September 30,
  
   
2017
    
2016
    
2017
    
2016
  
     
(in thousands)
  
Revenue
                        
Oil and gas revenue
  
$
3,699
    
$
1,777
    
$
11,350
    
$
4,154
  
Expenses
                                
Depletion and amortization
    
1,451
      
838
      
7,947
      
2,094
  
Impairment of oil and gas properties
    
-
      
-
      
-
      
13
  
Management fees to affiliate
    
316
      
233
      
947
      
932
  
Operating expenses
    
829
      
903
      
2,603
      
2,671
  
General and administrative expenses
    
43
      
40
      
183
      
112
  
Total expenses
    
2,639
      
2,014
      
11,680
      
5,822
  
Income (loss) from operations
    
1,060
      
(237
)
    
(330
)
    
(1,668
)
Other income (loss)
                                
Loss on investment in Delta House
    
-
      
(110
)
    
-
      
(110
)
Dividend income
    
7
      
58
      
19
      
181
  
Interest expense, net
    
(641
)
    
(583
)
    
(1,906
)
    
(580
)
Total other loss
    
(634
)
    
(635
)
    
(1,887
)
    
(509
)
Net income (loss)
  
$
426
    
$
(872
)
  
$
(2,217
)
  
$
(2,177
)

Overview.  The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the three and nine months ended September 30, 2017 and 2016.  Natural gas liquid (“NGL”) sales are included within gas sales.

   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2017
    
2016
    
2017
    
2016
  
Number of wells producing
    
13
      
11
      
14
      
11
  
Total number of production days
    
923
      
752
      
2,688
      
2,048
  
Oil sales (in thousands of barrels)
    
72
      
36
      
220
      
90
  
Average oil price per barrel
  
$
45
    
$
42
    
$
46
    
$
39
  
Gas sales (in thousands of mcfs)
    
125
      
97
      
398
      
267
  
Average gas price per mcf
  
$
3.50
    
$
2.64
    
$
3.29
    
$
2.27
  
 
The increases in the above table were primarily related to the commencement of production of four wells in the Beta Project, two wells during the second half of 2016 and two wells during 2017, coupled with the Diller Project, which was shut-in in late 2016.   In addition, the increases in gas sales were also attributable to the Marmalard Project, which did not produce NGLs during third quarter 2016 due to third-party facilities’ repair and maintenance activities. These increases were partially offset by the Liberty Project, which was shut-in during the majority of third quarter 2017, and South Pelto 9, which was shut-in during the majority of second and third quarter of 2017.  See additional discussion in “Business Update” section above.

Oil and Gas Revenue. Generally, the Fund sells oil, gas and NGLs under two types of agreements, which are common in the oil and gas industry. In a netback agreement, the Fund receives a price, net of transportation expense incurred by the purchaser, and the Fund records revenue at the net price received. In the second type of agreement, the Fund pays transportation expense directly, and transportation expense is included within operating expenses in the statements of operations.

Oil and gas revenue during the three months ended September 30, 2017 was $3.7 million, an increase of $1.9 million from the three months ended September 30, 2016. The increase was attributable to increased sales volume totaling $1.6 million coupled with increased oil and gas prices totaling $0.3 million.

Oil and gas revenue during the nine months ended September 30, 2017 was $11.4 million, an increase of $7.2 million from the nine months ended September 30, 2016. The increase was attributable to increased sales volume totaling $5.4 million coupled with increased oil and gas prices totaling $1.8 million.
 
 
See “Overview” above for factors that impact the oil and gas revenue volume and rate variances.

Depletion and Amortization.  Depletion and amortization during the three months ended September 30, 2017 was $1.5 million, an increase of $0.6 million from the three months ended September 30, 2016.  The increase was primarily attributable to an increase in production volumes.
 
Depletion and amortization during the nine months ended September 30, 2017 was $7.9 million, an increase of $5.9 million from the nine months ended September 30, 2016.  The increase was attributable to an increase in the average depletion rate totaling $3.5 million coupled with an increase in production volumes totaling $2.4 million. The increase in the average depletion rate was primarily attributable to the onset of production of the Beta Project, partially offset by the lower cost of reserves from the Diller and Marmalard projects.
 
See “Overview” above for certain factors that impact the depletion and amortization volume and rate variances.  Depletion and amortization rates may also be 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 any impairments of oil and gas properties during the three and nine months ended September 30, 2017 and during the three months ended September 30, 2016.  During the nine months ended September 30, 2016, the Fund recorded impairments of oil and gas properties of $13 thousand, related to Eugene Island 346/347, which was primarily attributable to declines in future oil and gas prices.

Management Fees to Affiliate.  An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager. Such fee may be temporarily waived by the Manager to accommodate the Fund’s short-term capital commitments.
 
Operating Expenses.  Operating expenses represent costs specifically identifiable or allocable to the Fund’s wells, as detailed in the following table.
 
   
Three months ended September 30,
    
Nine months ended September 30,
  
   
2017
    
2016
    
2017
    
2016
  
   
(in thousands)
  
Lease operating expense
  
$
553
    
$
648
    
$
1,709
    
$
2,152
  
Transportation and processing expense
    
128
      
83
      
379
      
252
  
Insurance expense
    
116
      
141
      
288
      
195
  
Workover expense
    
(5
)
    
14
      
117
      
41
  
Accretion expense
    
26
      
-
      
78
      
-
  
Other
    
11
      
17
      
32
      
31
  
   
$
829
    
$
903
    
$
2,603
    
$
2,671
  
 
Lease operating expense and transportation and processing expense relates to the Fund’s producing properties.  Insurance expense represents premiums related to the Fund’s properties, which vary depending upon the number of wells producing or drilling. Workover expense, which represents costs to restore or stimulate production of existing reserves, primarily relates to the Beta, Diller and Marmalard projects. Accretion expense relates to the asset retirement obligations established for the Fund’s proved properties.
 
The average production cost, which includes lease operating expense, transportation and processing expense and insurance expense, was $8.62 per barrel of oil equivalent (“BOE”) and $8.31 per BOE during the three and nine months ended September 30, 2017, respectively, compared to $16.86 per BOE and $19.36 per BOE during the three and nine months ended September 30, 2016, respectively.  The decreases were primarily attributable to the Beta, Diller and Marmalard projects, which had lower cost per BOE in 2017.  These decreases were partially offset by ongoing costs for South Pelto 9, which produced at nominal rates during the second and third quarters of 2017.
 
The Beta Project, which commenced production in third quarter 2016, has lower cost per BOE as compared to other projects due to the processing of production through its standalone facility. The production costs per BOE may decline over time as throughput increases from the project or other projects expected to tie-in to the facility.  The Diller and Marmalard projects had lower cost per BOE as a result of a reduction in production handling fees from $15.50 per BOE to $4.50 per BOE effective December 2016. The production handling fees for the Diller and Marmalard projects decline over time as certain production hurdles are met in accordance with their production handling agreement relating to the Delta House production facility.

General and Administrative Expenses.  General and administrative expenses represent costs specifically identifiable or allocable to the Fund, such as accounting and professional fees and insurance expenses.
 
 
Loss on Investment in Delta House. During the three and nine months ended September 30, 2016, the Fund recognized a loss on investment of $0.1 million related to its investment in Delta House.  See Note 1 of “Notes to Unaudited Condensed Financial Statements” - “Organization and Summary of Significant Accounting Policies” contained in Item 1. “Financial Statements” within Part I of this Quarterly Report for more information regarding the Investment in Delta House. There were no such amounts recorded during the three and nine months ended September 30, 2017.
 
Dividend Income.  Dividend income is related to the Fund’s investment in Delta House.
 
Interest Expense, Net.  Interest expense, net is comprised of interest expense and amortization of debt discounts and deferred financing costs related to the Fund’s long-term borrowings (see “Liquidity Needs” below for additional information), and interest income earned on cash and cash equivalents and salvage fund.

Capital Resources and Liquidity

Operating Cash Flows
Cash flows provided by operating activities during the nine months ended September 30, 2017 were $7.1 million, related to revenue received of $11.4 million, partially offset by operating expenses of $3.2 million, management fees of $0.9 million and general and administrative expenses of $0.2 million.

Cash flows provided by operating activities during the nine months ended September 30, 2016 were $0.1 million, related to revenue received of $3.8 million and dividend income received of $0.2 million, partially offset by operating expenses of $2.8 million, management fees of $0.9 million and general and administrative expenses of $0.1 million.

Investing Cash Flows
Cash flows used in investing activities during the nine months ended September 30, 2017 were $6.4 million, primarily related to capital expenditures for oil and gas properties.

Cash flows used in investing activities during the nine months ended September 30, 2016 were $4.1 million, related to capital expenditures for oil and gas properties of $3.8 million and investments in salvage fund of $0.3 million.

Financing Cash Flows
There were no cash flows from financing activities during the nine months ended September 30, 2017 and 2016.

Estimated Capital Expenditures

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.  See “Business Update” under this Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Quarterly Report for information regarding the Fund’s current projects. 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 Fund’s remaining capital has been fully allocated to complete its projects. As a result, the Fund will not invest in any new projects and will limit its investment activities, if any, to those projects in which it currently has a working interest.

Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its operations, capital expenditures for its oil and gas properties and borrowing repayments.  Such needs are funded utilizing operating income and existing cash on-hand.

As of September 30, 2017, the Fund’s estimated capital commitments related to its oil and gas properties were $12.5 million (which include asset retirement obligations for the Fund’s projects of $5.9 million), of which $3.4 million is expected to be spent during the next twelve months primarily related to the additional development costs for the Beta Project. Additionally, current liabilities exceed current assets as of September 30, 2017.  Future results of operations and cash flows are dependent on the continued successful development and the related production of oil and gas revenues from the Beta Project. Based upon its current cash position and its current reserve estimates, the Fund expects cash flow from operations to be sufficient to cover its commitments, borrowing repayments, 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 commitments, the Manager will temporarily waive all or a portion of the management fee as well as provide short-term financing to accommodate the Fund’s short-term commitments if needed.
 
 
The Manager is entitled to an annual management fee from the Fund regardless of the Fund’s profitability in that year. However, pursuant to the terms of the LLC Agreement, the Manager is also permitted to waive the management fee at its own discretion.

Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion.  Due to the significant capital required to develop the Beta, Diller and Marmalard projects, distributions have been impacted, and may be impacted in the future, by amounts reserved to provide for their ongoing development costs, debt service costs, and funding their estimated asset retirement obligations.

Credit Agreement
In November 2012, the Fund entered into a credit agreement (as amended on September 30, 2016 and September 15, 2017, the “Credit Agreement”) to provide capital toward the funding of the Fund’s share of development costs on the Beta Project.  As of September 30, 2017 and December 31, 2016, the Fund had borrowed $24.1 million under the Credit Agreement. As of December 31, 2016, in accordance with the terms of the Credit Agreement, there are no additional borrowings available to the Fund.

The loan bears interest at 8% compounded annually. Monthly principal and interest payments are the lesser of the Monthly Fixed Amount or the Debt Service Cap amount, as defined in the Credit Agreement, until the loan is repaid in full, in no event later than December 31, 2020. The Fund expects operating income from the Beta Project to be sufficient to cover the principal and interest payments required under the Credit Agreement. The loan may be prepaid by the Fund without premium or penalty.

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 Fund’s share of the lender’s aggregate ORRI is directly proportionate to its level of borrowing as a percentage of total borrowings of all the other participating funds managed by the Manager. Such ORRI will not accrue or become payable to the lenders until after the loan is repaid in full.

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 as of September 30, 2017 and December 31, 2016.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements as of September 30, 2017 and December 31, 2016 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 as of September 30, 2017 and December 31, 2016, other than those discussed in “Estimated Capital Expenditures” and “Liquidity Needs – Credit Agreement” above.

Recent Accounting Pronouncements

See Note 1 of “Notes to Unaudited Condensed Financial Statements” - “Organization and Summary of Significant Accounting Policies” contained in Item 1. “Financial Statements” within Part I of this Quarterly Report for a discussion of recent accounting pronouncements.

ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.
 
 
ITEM 4.
CONTROLS AND PROCEDURES

In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Fund’s management, including its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Fund’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures were effective as of September 30, 2017.

There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended September 30, 2017 that has materially affected, or is reasonably likely to materially affect, the Fund’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1.
LEGAL PROCEEDINGS

None.

ITEM 1A.
RISK FACTORS

Not required.

ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3.
DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.
MINE SAFETY DISCLOSURES

None.

ITEM 5.
OTHER INFORMATION

None.

ITEM 6.
EXHIBITS
 
EXHIBIT
NUMBER
TITLE OF EXHIBIT
  
METHOD OF FILING
       
31.1
  
Filed herewith
       
31.2
  
Filed herewith
       
32
  
Filed herewith
       
10.3
  
Filed herewith
 
 
101.INS
XBRL Instance Document
Filed herewith
     
101.SCH
XBRL Taxonomy Extension Schema
Filed herewith
     
101.CAL
XBRL Taxonomy Extension Calculation Linkbase
Filed herewith
     
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document
Filed herewith
     
101.LAB
XBRL Taxonomy Extension Label Linkbase
Filed herewith
     
101.PRE
XBRL Taxonomy Extension Presentation Linkbase
Filed herewith
 

 SIGNATURES

Pursuant to the requirements 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 O FUND, LLC
 
Dated:
November 7, 2017
By:
/s/
    
ROBERT E. SWANSON
     
Name:
    
Robert E. Swanson
     
Title:
    
Chief Executive Officer
           
(Principal Executive Officer)
             
             
Dated:
November 7, 2017
By:
/s/
    
KATHLEEN P. MCSHERRY
     
Name:
    
Kathleen P. McSherry
     
Title:
    
Executive Vice President and Chief Financial Officer
           
(Principal Financial and Accounting Officer)
 
 
16