Ridgewood Energy Q Fund (RDWQS) 10-Q 2007 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2007
	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 Number 000-51927

RIDGEWOOD ENERGY Q FUND, LLC

(Exact name of registrant as specified in its charter)

Delaware	84-1689138
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1314 King Street, Wilmington, Delaware 19801

(Address of principal executive offices) (Zip code)

(302) 888-7444

(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    x   No   o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.  (Check one) :

Large accelerated filer   o Accelerated filer   o Non-accelerated filer   x

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

     As of August 1, 2007 there were 830.5577 shares of membership interest of the registrant outstanding.

	Table of Contents
		Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Unaudited Condensed Balance Sheets as of June 30, 2007 and December 31, 2006	3
	Unaudited Condensed Statements of Operations for the three and six months ended June 30, 2007 and 2006	4
	Unaudited Condensed Statements of Cash Flows for the three and six months ended June 30, 2007 and 2006	5
	Notes to Unaudited Condensed Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	15
Item 4.	Controls and Procedures	16
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	17
Item 1A.	Risk Factors	17
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	17
Item 3.	Defaults Upon Senior Securities	17
Item 4.	Submissions of Matters to a Vote of Security Holders	17
Item 5.	Other Information	17
Item 6.	Exhibits	17
	SIGNATURES	18

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PART I - FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS

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

	June 30, 2007			December 31, 2006
ASSETS
Current assets:
Cash and cash equivalents	$	45,348		$	49,055
Short-term investment in marketable securities		18,658			18,197
Production receivable		388			1,369
Other current assets		164			245
Total current assets		64,558			68,866
Salvage fund		1,058			1,042
Oil and gas properties:
Proved properties		28,360			18,506
Unproved properties		—			450
Less:  accumulated depletion and amortization		(7,068	)		(4,229	)
Total oil and gas properties, net		21,292			14,727
Total assets	$	86,908		$	84,635
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Due to operators	$	7,904		$	83
Accrued expenses payable		379			109
Total current liabilities		8,283			192
Asset retirement obligation		180			79
Total liabilities		8,463			271
Commitments and contingencies (Note 7)
Members’ capital:
Manager:
Distributions		(1,965	)		(925	)
Retained earnings		1,053			703
Manager’s total		(912	)		(222	)
Shareholders:
Capital contributions (1,335 shares authorized; 830.5577 issued and outstanding)		123,037			123,037
Syndication costs		(14,070	)		(14,070	)
Distributions		(11,130	)		(5,242	)
Accumulated deficit		(18,480	)		(19,139	)
Shareholders’ total		79,357			84,586
Total members’ capital		78,445			84,364
Total liabilities and members’ capital	$	86,908		$	84,635

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

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RIDGEWOOD ENERGY Q FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS
(in thousands, except share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
Revenue
Oil and gas revenue	$	1,375		$	936		$	4,617		$	936
Expenses
Dry-hole costs		(26	)		3,415			85			11,284
Depletion and amortization		822			144			2,839			144
Management fees to affiliate (Note 5)		653			769			1,308			1,539
Lease operating expense		209			—			411			—
Other operating expenses		1			—			115			—
General and administrative expenses		398			336			510			381
Total expenses		2,057			4,664			5,268			13,348
Loss from operations		(682	)		(3,728	)		(651	)		(12,412	)
Other income
Interest income		834			849			1,660			1,671
Net income (loss)	$	152		$	(2,879	)	$	1,009		$	(10,741	)
Manager Interest
Net income (loss)	$	20		$	(15	)	$	350		$	(239	)
Shareholder Interest
Net income (loss)	$	132		$	(2,864	)	$	659		$	(10,502	)
Net income (loss) per share	$	159		$	(3,448	)	$	793		$	(12,644	)

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

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

	For the six months ended June 30,
	2007			2006
Cash flows from operating activities
Net income (loss)	$	1,009		$	(10,741	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depletion and amortization		2,839			144
Dry-hole costs		85			11,284
Accretion expense		2			—
Interest earned on marketable securities		(691	)		(719	)
Changes in assets and liabilities:
Decrease (increase) in production receivable		981			(936	)
Decrease in other current assets		81			239
Increase in due to operator		10			—
Increase in accrued expenses payable		270			32
Decrease in due to affiliates		—			(1,570	)
Net cash provided by (used in) operating activities		4,586			(2,267	)
Cash flows from investing activities
Capital expenditures for oil and gas properties		(1,579	)		(8,131	)
Salvage fund investments		(16	)		(1,017	)
Proceeds from maturity of marketable securities		18,455			—
Investment in marketable securities		(18,225	)		(34,999	)
Net cash used in investing activities		(1,365	)		(44,147	)
Cash flows from financing activities
Collection of subscriptions receivable		—			2,964
Distributions		(6,928	)		—
Syndication costs paid		—			(4,113	)
Net cash used in financing activities		(6,928	)		(1,149	)
Net decrease in cash and cash equivalents		(3,707	)		(47,563	)
Cash and cash equivalents, beginning of period		49,055			86,240
Cash and cash equivalents, end of period	$	45,348		$	38,677
Supplemental schedule of disclosures of cash flow information
Advances used for capital expenditures in oil and gas properties reclassified to dry-hole costs, unproved and proved properties	$	—		$	11,787

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

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RIDGEWOOD ENERGY Q FUND, LLC
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

1.   Organization and Purpose

The Ridgewood Energy Q Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 16, 2005 and operates pursuant to a limited liability company agreement (“Agreement”) dated as of September 6, 2005 by and among Ridgewood Energy Corporation (the “Manager”), and the shareholders of the Fund.  Although the date of formation is August 16, 2005, the Fund did not begin operations until September 6, 2005 when it began its private offering of shares. 

The Fund was organized to acquire, drill, construct and develop natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.  The Fund has devoted most of its efforts to raising capital and oil and natural gas exploration activities. 

The Manager performs (or arranges for the performance of) the management 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 outside custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required (Notes 2, 5 and 7).

2.   Summary of Significant Accounting Policies

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 annual financial statements and the notes thereto for the period ended December 31, 2006 included in the Fund’s Annual Report on Form 10-K (“Form 10-K”) filed with the Securities and Exchange Commission (“SEC”).

Use of Estimates
The preparation of financial statements in conformity 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 revenues and expenses during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to amounts advanced to and billed by operators, determination of proved reserves, impairments and environmental liabilities.  Actual results may differ from those estimates.

Advances to Operators for Working Interests and Expenditures
The Fund’s acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Fund’s right, title and interest.  The Fund is required to advance its share of estimated cash expenditures for the succeeding month’s operation. The Fund accounts for such payments as advances to operators for working interests and expenditures.  As drilling costs are incurred, the advances are transferred to unproved properties. 

Oil and Natural Gas Properties
Investments in oil and natural gas properties are operated by unaffiliated entities (“Operators”) who 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 relating to the wells are advanced and billed by Operators through authorization for expenditures.

6

The successful efforts method of accounting for oil and natural gas producing activities is followed. Acquisition costs are capitalized when incurred.  Other oil and natural gas exploration costs, excluding the costs of drilling exploratory wells, are charged to expense as incurred.  The costs of drilling exploratory wells are capitalized pending the determination of whether the wells have discovered proved commercial reserves.  If proved commercial reserves have not been found, exploratory drilling costs are expensed to dry-hole expense.   Costs to develop proved reserves, including the costs of all development wells and related facilities and equipment used in the production of crude oil and natural gas, are capitalized.  Expenditures for ongoing repairs and maintenance of producing properties are expensed as incurred. 

Upon the sale or retirement of a proved property (i.e. a producing well), the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss is recognized.  On the sale or retirement of an unproved property, gain or loss on the sale is recognized.   Currently, it is not the Manager’s intention to sell any of the Fund’s property interests. 

Capitalized acquisition costs of producing oil and natural gas properties after recognizing estimated salvage values are depleted by the unit-of-production method.  At the time of transfer a production receivable is recorded. 

As of June 30, 2007 and December 31, 2006 $7.8 million and $0.1 million was recorded in due to operators, respectively, related to the acquisition of oil and gas property and for drilling costs.  The balance at December 31, 2006 was paid in the first quarter of 2007.

Revenue Recognition and Production Receivable
Oil and natural gas sales are recognized when delivery is made by the Operator to the purchaser and title is transferred (i.e., production has been delivered to a pipeline or transport vehicle). 

The volume of oil and natural gas sold on the Fund’s behalf may differ from the volume of oil and natural gas the Fund is entitled.  The Fund will account for such oil and natural gas production imbalances by the entitlements method.  Under the entitlements method, the Fund will recognize a receivable from other working interest owners for volumes oversold by other working interest owners.  For volumes oversold by the Fund, a payable to other working interest owners will be recorded.  At June 30, 2007 and December 31, 2006, there were no material oil or natural gas balancing arrangements between the Fund and other working interest owners.

Syndication Costs
Direct costs associated with offering the Fund’s shares including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and outside brokers are reflected as a reduction of shareholders’ capital.

Asset Retirement Obligations
For oil and natural 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 recorded.  Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.

	June 30, 2007		December 31, 2006
	(in thousands)
Balance - Beginning of period	$	79	$	—
Liabilities incurred		99		192
Liabilities settled		—		(115	)
Accretion expense		2		2
Balance - End of period	$	180	$	79

7

Impairment of Long-Lived Assets
In accordance with the provisions of Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment of Long-Lived Assets”, long-lived assets, such as oil and natural gas properties, are evaluated when events or changes in circumstances indicate the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is made by comparing the carrying values of long-lived assets to the estimated future undiscounted cash flows attributable to the asset. The impairment loss recognized is the excess of the carrying value over the future discounted cash flows attributable to the asset or the estimated fair value of the asset.  For the three months and six months ended June 30, 2007 and 2006, no impairments were recorded.

Depletion and Amortization
Depletion and amortization of the cost of proved oil and natural gas properties are calculated using the units of production method.  Proved developed reserves are used as the base for depleting the cost of successful exploratory drilling and development costs.  The sum of proved developed and proved undeveloped reserves is used as the base for depleting (or amortizing) leasehold acquisition costs, the costs to acquire proved properties and platform and pipeline costs. 

Income Taxes
No provision is made for income taxes in the financial statements.  Because the Fund is a limited liability corporation (“LLC”), the income or losses are passed through and included in the tax returns of the individual shareholders.

Cash and Cash Equivalents
All highly liquid investments with maturities when purchased of three months or less are considered as cash and cash equivalents.  At times, bank deposits may be in excess of federally insured limits.  At June 30, 2007 and December 31, 2006, bank balances, inclusive of salvage fund, exceeded federally insured limits by approximately $27.2 million and $30.9 million, respectively. The Fund maintains bank deposits with accredited financial institutions to mitigate such risk.

Salvage Fund
The Fund deposits in a separate interest-bearing account, or a salvage fund, money to provide for dismantling production platforms and facilities, plugging and abandoning the wells and removing the platforms, facilities and wells after their useful lives, in accordance with applicable federal and state laws and regulations.

Interest earned on the account will become part of the salvage fund; there are no legal restrictions on the withdrawal from the salvage fund.

Short-term Investments in Marketable Securities
At times the Fund may purchase short-term investments comprised of US Treasury Notes with maturities greater than three months and as such are considered held-to-maturity investments.  Held-to-maturity securities are those investments that the Fund has the ability and intent to hold until maturity.  Held-to-maturity investments are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximate market value.  Interest income is accrued as earned.   Held-to-maturity investments at June 30, 2007 of $18.7 million matured in July 2007.

Income and Expense Allocation
Profits and losses are to be allocated 85% to shareholders in proportion to their relative capital contributions and 15% to the Manager, except for items of expense, loss, deduction and credit that are attributable to the expenditure of shareholders’ capital contributions, which are allocated 99% to shareholders and 1% to the Manager.

3.   Unproved Properties - Capitalized Exploratory Well Costs

Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves.  Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves.  Capitalization costs are expensed as dry-hole costs in the event that reserves are not found or are not in sufficient quantities to complete the well and develop the field. The following table reflects the net changes in unproved properties at June 30, 2007 and December 31, 2006.  At June 30, 2007, the Fund had no capitalized exploratory well costs greater than one year.  Main Pass 30 Well #2 was reclassified to a proved property at June 30, 2007.

8

	June 30, 2007			December 31, 2006
	(in thousands)
Balance - Beginning of the period	$	450		$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		9,241			18,956
Reclassifications to proved properties based on the determination of proved reserves		(9,691	)		(18,506	)
Capitalized exploratory well costs charged to dry-hole costs		—			—
Balance - End of the period	$	—		$	450

Dry-hole costs are detailed in the table below for the three and six months ended June 30, 2007 and 2006.

	Three months ended June 30,					Six months ended June 30,
	2007			2006		2007		2006
	(in thousands)
Main Pass 221	$	(26	)	$	3,415	$	85	$	11,284

4.   Distributions

Distributions to shareholders are allocated in proportion to the number of shares held.

The Manager will determine whether available cash from operations, as defined in the Fund’s LLC Agreement, is to be distributed.  Such distribution will be allocated 85% to the shareholders and 15% to the Manager, as defined in the Fund’s LLC Agreement. 

Available cash from dispositions, as defined in the Fund’s 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. 

The shareholders received distributions of $2.5 million and $5.9 million for the three and six months ended June 30, 2007, respectively.  The Manager received distributions of $0.4 million and $1.0 million for the three and six months ended June 30, 2007, respectively.  There were no distributions paid during the three and six months ended June 30, 2006. 

5.   Related Parties

A management agreement provides that the Manager render management, administrative and advisory services. For such services, the Manager receives an annual management fee, payable monthly, of 2.5% of total capital contributions. Effective January 1, 2007, the Manager has changed its policy regarding the annual management fee.  Under the new policy, the management fee is equal to 2.5% of the total shareholder capital contributions, net of cumulative dry-hole costs incurred by the Fund. 

From time to time, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.  At June 30, 2007 and December 31, 2006, no such amounts were outstanding. 

None of the compensation to be received by the Manager has been derived as a result of arm’s length negotiations.

9

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.

6.   Fair Value of Financial Instruments

At June 30, 2007 and December 31, 2006, the carrying value of cash and cash equivalents, short-term investments and the salvage fund approximate fair value. 

7.   Commitment and Contingencies

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 the Operators 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 natural 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 June 30, 2007 and December 31, 2006, there were no known environmental contingencies that required the Fund to record a liability.

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 which is not insured or not fully insured could have an adverse impact upon earnings and financial position.

10

ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Cautionary Statement Regarding Forward-Looking Statements

This Quarterly Report on Form 10-Q, including all documents incorporated by reference, includes “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”) and the Private Securities Litigation Reform Act of 1995, and the “safe harbor” provisions thereof. These forward-looking statements are usually accompanied by the words “anticipates,” “believes,” “plan,” “seek,” “expects,” “intends,” “estimates,” “projects,” “will likely result,” “future” and similar terms and expressions or variations thereof.  The forward-looking statements in this Quarterly Report on Form 10-Q reflect the Fund’s current views with respect to future events and financial performance.  These forward-looking statements are subject to certain risks and uncertainties, including, among other things, the high-risk nature of natural gas exploratory operations, the fact that the Fund’s drilling activities are managed by third parties, the volatility of natural gas prices and extraction, and those other risks and uncertainties discussed in the Fund’s 2006 Annual Report on Form 10-K filed with the Securities and Exchange Commission that could cause actual results to differ materially from historical results or those anticipated.  Readers are urged to carefully consider all such factors. 

In light of these risks and uncertainties, there can be no assurance that the forward-looking information contained in this Quarterly Report on Form 10-Q will in fact occur or prove to be accurate.  Readers should not place undue reliance on the forward-looking statements contained herein, which speak only as of the date of this filing.  The Fund undertakes no obligation to publicly revise these forward-looking statements to reflect events or circumstances that may arise after today.  All subsequent written or oral forward-looking statements attributable to the Fund or persons acting on its behalf are expressly qualified in their entirety by this section.

Critical Accounting Policies and Estimates

The following discussion and analysis of the Fund’s financial condition and operating results is based on its financial statements.  The preparation of this Quarterly Report on Form 10-Q requires the Fund to make estimates and assumptions that affect the reported amount of assets and liabilities, disclosure of contingent assets and liabilities at the date of the Fund’s financial statements, and the reported amount of revenue and expenses during the reporting period. Actual results may differ from those estimates and assumptions.  See “Notes to Unaudited Condensed Financial Statements” in Part I of this Quarterly Report on Form 10-Q for a presentation of the Fund’s significant accounting principles.  No changes have been made to the Fund’s critical accounting policies and estimates disclosed in its 2006 Annual Report on Form 10-K.

Overview of the Fund’s Business

The Fund is an independent oil and natural gas producer.  The Fund’s primary investment objective is to generate cash flow for distribution to the Fund’s shareholders through participation in oil and natural gas exploration and development projects in the Gulf of Mexico.  

The Manager performs certain duties on the Fund’s behalf including the evaluation of potential projects for investment and ongoing administrative and advisory services associated with these projects. 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 is paid an annual management fee (2.5% of capital contributions, net of cumulative dry-hole costs), payable monthly, for ongoing administrative and management duties as well as reimbursement of expenses. The Manager also participates in distributions.

Business Update

As of June 30, 2007 the Fund owned working interests in two offshore blocks and has participated in the drilling of three wells, one of which was determined to be a dry-hole in 2006. 

11

Main Pass 30
The Fund acquired a 45% working interest from the operator, Chevron U.S.A., Inc. (“Chevron”).  This project has a five well potential between 12,000 and 12,500 feet. 

The first well in the Main Pass 30 project (“Main Pass 30 well #1”) was put in production in June 2006 and is utilizing an existing Chevron production platform and pipeline. In return for the use of this infrastructure, the Fund pays 15 cents per one thousand cubic feet (“MCF”) as a processing fee for production.   During the second quarter 2007, Main Pass 30 well #1 experienced lower volumes than expected, particularly of oil production, due to a minor mechanical issue, which is expected to be remedied after Main Pass 30 well #2 is placed in production during the third quarter of 2007. 

The Main Pass 30 well #2 project began drilling in May 2007 and was determined to be a commercial discovery during the second quarter of 2007 and expenditures totaling $9.7 million were reclassified to proved property at June 30, 2007.  Completion efforts are ongoing and production is expected to commence in August 2007.

The current production platform equipment has the capacity to process natural gas from the first two wells.  After the third well is drilled and ready for production, a pipeline upgrade will be necessary.  The estimated budget for Main Pass 30 wells 3 – 5 is $45.2 million, which includes $3.2 million for this upgrade.

Results of Operations

The following review of operations for the three and six months ended June 30, 2007 and 2006 should be read in conjunction with the Fund’s financial statements and the notes thereto.  The following table summarizes the Fund’s results of operations (in thousands, except share data):

	Three months ended June 30,						Six months ended June 30,
	2007			2006			2007			2006
Revenue
Oil and gas revenues	$	1,375		$	936		$	4,617		$	936
Expenses
Dry-hole costs		(26	)		3,415			85			11,284
Depletion and amortization		822			144			2,839			144
Management fees to affiliate		653			769			1,308			1,539
Lease operating expense		209			—			411			—
Other operating expense		1			—			115			—
General and administrative expenses		398			336			510			381
Total expenses		2,057			4,664			5,268			13,348
Loss from operations		(682	)		(3,728	)		(651	)		(12,412	)
Other income
Interest income		834			849			1,660			1,671
Net income (loss)	$	152		$	(2,879	)	$	1,009		$	(10,741	)

Operating Revenues.  Oil and gas revenues for the three months ended June 30, 2007 were $1.4 million, a $0.4 million increase from the three months ended June 30, 2006.  For the six months ended June 30, 2007, the Fund earned revenues of $4.6 million, a $3.7 million increase from the six months ended June 30, 2006.

The Fund’s producing well, Main Pass 30 well #1, was placed in production in June 2006, producing approximately 4 thousand barrels of oil for the three and six months ended June 30, 2006.   During the three and six months ended June 30, 2007, Main Pass 30 well #1 produced approximately 1 thousand barrels and 4 thousand barrels of oil, respectively.  The decrease in oil volumes for the three and six month periods is attributable to a minor mechanical issue which is expected to be resolved once the Main Pass 30 well #2 begins production.    Oil prices approximated $64 and $57 per barrel during the three and six months ended June 30, 2007, respectively.  During the three and six months ended June 30, 2006, oil prices averaged $68 per barrel.

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Natural gas production for the three and six months ended June 30, 2006 was 130 thousand million cubic feet (“mcf”). Natural gas production for the three and six months ended June 30, 2007 was approximately 170 thousand mcf and 567 thousand mcf, respectively.  The aforementioned volumes represent increases that are attributable to three and six months of production during 2007 compared to one month of production during 2006.    During the three and six months ended June 30, 2007, natural gas prices were approximately $7.99 and $7.71 per mcf, respectively, compared to average prices for the three and six months ended June 30, 2006 of $6.56. 

Operating and Other Expenses

Depletion and Amortization.  Depletion and amortization for the three months ended June 30, 2007 was $0.8 million, an increase of $0.7 million from the three months ended June 30, 2006.   During the six months ended June 30, 2007, depletion and amortization was $2.8 million, a $2.7 million increase from the six months ended June 30, 2006.  The increases in depletion and amortization resulted from increased production.  Depletion and amortization was lower as production did not commence until June 2006. 

Dry-hole Costs.  Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well. The following table summarizes dry-hole costs inclusive of plug and abandonment costs for the three and six months ended June 30, 2007 and 2006. 

	Three months ended June 30,					Six months ended June 30,
	2007			2006		2007		2006
	(in thousands)
Main Pass 221	$	(26	)	$	3,415	$	85	$	11,284

Management Fees. The Manager receives an annual management fee, payable monthly, to cover expenses associated with overhead incurred by the Manager for its ongoing management, administrative and advisory services.  Such overhead expenses include but are not limited to rent, payroll and benefits for employees of the Manager, and other administrative costs.  Commencing in January 1, 2007, the management fee, payable monthly, was reduced by 2.5% of the cumulative dry-hole expenses incurred by the Fund, resulting in a decrease of $0.1 million and $0.2 million, respectively, for the three and six months ended June 30, 2007. 

Lease Operating Expenses.  Lease operating expenses represent the costs of operating and maintaining wells and related facilities. For the three and six months ended June 30, 2007, lease operating expenses were $0.2 million and $0.4 million, respectively.  The increases over the 2006 periods were attributable to the onset of production in June 2006. 

Other Operating Expenses.  The following table summarizes other operating expenses for the three and six months ended June 30, 2007 and 2006.

	Three months ended June 30,				Six months ended June 30,
	2007		2006		2007		2006
	(in thousands)
Geological costs	$	—	$	—	$	113	$	—
Accretion expense		1		—		2		—
	$	1	$	—	$	115	$	—

Geological costs for the six months ended June 30, 2007 relate to the Main Pass 30 A-15 platform.

General and Administrative Expenses.  Accounting, legal, fiduciary fees and insurance expenses represent costs specifically identifiable or allocable to the Fund. Accounting and legal fees represent annual audit and tax preparation fees, quarterly reviews and filing fees of the Fund.   Insurance expense represents premiums related to well control insurance and production insurance.   Insurance expense increased during the 2007 periods due to increased drilling activities in 2007 compared to 2006.

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The following table summarizes general and administrative expenses for the three and six months ended June 30, 2007 and 2006.

	Three months ended June 30,				Six months ended June 30,
	2007		2006		2007		2006
	(in thousands)
Accounting and legal fees	$	59	$	73	$	124	$	92
Insurance		317		231		345		247
Trust fees		21		32		40		42
Other expenses		1		—		1		—
	$	398	$	336	$	510	$	381

Interest Income.  Interest income represents interest earned on money market accounts and short-term US Treasury Notes.  Interest income for the three months and six months ended June 30, 2007 was consistent with the corresponding 2006 periods.  Increased interest rates during the six months ended June 30, 2007 principally offset the decrease in average outstanding balances earning interest.

Capital Resources and Liquidity

Operating Cash Flows
Cash flows provided by operating activities for the six months ended June 30, 2007 were $4.6 million, primarily related to production revenue receipts of $5.6 million, interest income received of $1.0 million, and favorable working capital of $0.3 million, partially offset by management fees of $1.3 million, lease operating expenses of $0.4 million, and general and administrative and other operating expenses of $0.6 million.

Cash flows used in operating activities for the six months ended June 30, 2006 were $2.3 million, primarily related to management fees of $1.5 million and general and administrative expenses of $0.4 million, and payments to the Manager of $1.6 million for investment fees, partially offset by interest income received of $1.2 million.

Investing Cash Flows
Cash flows used in investing activities for the six months ended June 30, 2007 were $1.4 million, primarily related to investment in US Treasury Notes of $18.2 million and capital expenditures for oil and gas properties of $1.6 million, partially offset by proceeds from the maturity of US Treasury Notes of $18.4 million.

Cash flows used in investing activities for the six months ended June 30, 2006 were $44.1 million, primarily related to investment in marketable securities of $35.0 million, funding of the salvage fund of $1.0 million and capital expenditures for oil and gas properties of $8.1 million.

Financing Cash Flows
Cash flows used in financing activities for the six months ended June 30, 2007 were $6.9 million related to distributions to the Manager and the shareholders.

Cash flows used in financing activities for the six months ended June 30, 2006 were $1.1 million related to $4.1 million of syndication costs payments offset by the collection of $3.0 million in subscriptions receivable.

Estimated Capital Expenditures

The Fund has entered into multiple offshore operating agreements for the drilling and development of its investment properties.  The estimated capital expenditures associated with these agreements can vary depending on the stage of development on a property-by-property basis.  As of June 30, 2007, such estimated capital expenditures totaled approximately $51.0 million, all of which is expected to be paid out of unspent cash within the following twelve months. 

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The table below presents exploration and development capital expenditures for currently drilling projects as well as estimated budgeted amounts for the next twelve months.  Remaining unspent cash will be reallocated to one or more new unspecified projects.

Estimated Capital Expenditures
As of June 30, 2007

	Spent Through June 30, 2007		To be Spent Next 12 Months
	(in thousands)
Main Pass 30	$	18,495	$	—
Main Pass 30 Well #2		9,224		5,818
Main Pass Wells 3-5		—		45,172
	$	27,719	$	50,990

Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its 2007 operations, including management fees and capital expenditures, with existing cash on-hand and income earned from its short-term investments and cash and cash equivalents.  The Manager is entitled to receive an annual management fee from the Fund regardless of whether the Fund is profitable in that year. The annual fee, payable monthly, was originally equal to 2.5% of total capital contributed by shareholders.  Effective January 1, 2007, the Manager changed its policy regarding the annual management fee.  Commencing in January 2007, the management fee payable is equal to 2.5% of the total shareholder capital contributions, net of cumulative dry-hole expenses incurred by the Fund. 

Distributions, if any, 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 capital raised by the Fund in its private placement is more than likely all the capital it will be able to obtain for investments in projects. The number of projects in which the Fund can invest will naturally be limited and each unsuccessful project the Fund experiences, if any, will not only reduce its ability to generate revenue, but also exhaust its limited supply of capital. Typically, the Manager seeks an investment portfolio that combines high and low risk exploratory projects. 

When the Manager makes a decision for participation in a particular project, it assumes that the well will be successful and allocates enough capital to budget for the completion of that well and the additional development wells that are anticipated to be drilled. If the exploratory well is deemed a dry-hole or if it is un-economical, the capital allocated to the completion of that well and to the development of additional wells is then reallocated to a new project or used to make additional investments.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements as of June 30, 2007 and December 31, 2006 and does not anticipate the use of such arrangements in the future.

Contractual Obligations

The Fund enters into 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 discuss or negotiate any such contracts.  No contractual obligations exist at June 30, 2007 and December 31, 2006.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Projects drilled may not have commercially productive oil and natural gas reservoirs. In such an event, the Fund’s revenue, future results of operations and financial condition would be adversely impacted.

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The Fund does not have or use, any derivative instruments nor does it have any plans to enter into such derivative arrangements. The Fund will generally invest cash in high-quality credit instruments consisting primarily of money market funds, bankers’ acceptance notes and government agency securities with maturities of six months or less. The Fund does not expect any material loss from cash equivalents and therefore believes its potential interest rate exposure is not material. The Fund has no plan to conduct any international activities and therefore believes it is not subject to foreign currency risk.

The principal market risks to which the Fund is exposed that may adversely impact the Fund’s results of operations and financial position are changes in oil and natural gas prices.

Low commodity prices could have an adverse affect on the Fund’s future profitability and, in such an event the Fund may be required by accounting rules to write down the carrying value of the Fund’s projects.  Revenue to the Fund will be sensitive to changes in price to be received for oil and natural gas production. Prevailing market prices fluctuate in response to many factors that are outside of the Fund’s control such as the supply and demand for oil and natural gas. Availability of alternative fuels as well as seasonal risks such as hurricanes can also impact the supply and demand.

High oil and natural gas prices have resulted in a strong demand for and a tight supply of drilling rigs necessary to drill new projects. The increased cost in daily rig rates could have a negative impact on the return to shareholders in the Fund. The shortage of drilling rigs could delay the application of capital to such projects and thus delay revenue from operations.

ITEM 4.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures
The Fund maintains “disclosure controls and procedures”, as such term is defined under Securities and Exchange Act of 1934 (“Exchange Act”) Rule 13a-15(e), that are designed to ensure that information required to be disclosed in the Fund’s Exchange Act reports is recorded, processed, summarized and reported within the same time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to its management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, the Fund’s management recognized that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and its management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. The Fund has carried out an evaluation, as of June 30, 2007, under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Fund’s disclosure controls and procedures.  Based upon their evaluation and subject to the foregoing, such procedures were effective.

Because the Fund is not an “Accelerated Filer” as defined in Rule 12b-2 of the Exchange Act, the Fund is not presently required to file Management’s annual report on internal control over financial reporting and the Attestation report of the registered public accounting firm required by Item 308(a) and (b) of Regulation S-K promulgated under the Securities Act.  Under current rules, because the Fund is neither a “large accelerated filer” nor an “accelerated filer”, the Fund is not required to provide management’s report on internal control over financial reporting until the Fund files its annual report for 2007 and compliance with the auditor’s attestation report requirement is not required until the Fund files its annual report for 2008.  The Fund currently expects to comply with these requirements at such time as the Fund is required to do so.

Changes in Internal Controls over Financial Reporting

The Fund continually reviews its disclosure controls and procedures and makes changes as necessary, to ensure the quality of its financial reporting.  There were no changes in the Fund’s  internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that occurred during the quarter ended June 30, 2007 that have materially affected, or are reasonably likely to materially affect, the Fund’s  internal control over financial reporting.

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PART II.  OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

There have been no changes to the legal proceedings disclosed in the Fund’s most recent Annual Report on Form 10-K.

ITEM 1A. RISK FACTORS

For information regarding factors that could affect the Fund’s results of operations, financial condition and liquidity, see risk factors discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations”  in Item 7 of the Fund’s 2006 Annual Report on Form 10-K.  There have been no material changes from the risk factors previously disclosed in the Fund’s most recent Annual Report on Form 10-K.

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

None.

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSIONS OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

EXHIBIT NUMBER	TITLE OF EXHIBIT
31.1	Certification of Robert E. Swanson, Chief Executive Officer, pursuant to Securities Exchange Act Rule 13a-14(a).
31.2	Certification of Kathleen P. McSherry, Chief Financial Officer, pursuant to Securities Exchange Act Rule 13a-14(a).
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 Company and Kathleen P. McSherry, Chief Financial Officer of the Company.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: August 1, 2007	RIDGEWOOD ENERGY Q FUND, LLC
	By:	/s/ ROBERT E. SWANSON
	Name:	Robert E. Swanson
	Title:	President and Chief Executive Officer
		(Principal Executive Officer)
Dated: August 1, 2007
	By:	/s/ KATHLEEN P. MCSHERRY
	Name:	Kathleen P. McSherry
	Title:	Senior Vice President and Chief Financial Officer
		(Principal Financial and Accounting Officer)

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