Ridgewood Energy P Fund 10-Q 2007 Q3 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 September 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 000-51926

RIDGEWOOD ENERGY P FUND, LLC
(Exact name of registrant as specified in its charter)

Delaware	86-1133315
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	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.
Yesx     Noo

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).
Yeso Nox

As of November 2, 2007 there were 933.0600 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 September 30, 2007 and December 31, 2006	3
	Unaudited Condensed Statements of Operations and Other Comprehensive Loss for the three and nine months ended September 30, 2007 and 2006	4
	Unaudited Condensed Statements of Cash Flows for the nine months ended September 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	17
Item 4.	Controls and Procedures	17
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings	18
Item 1A.	Risk Factors	18
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	18
Item 3.	Defaults Upon Senior Securities	18
Item 4.	Submissions of Matters to a Vote of Security Holders	18
Item 5.	Other Information	18
Item 6.	Exhibits	19
	SIGNATURES	19

2

PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

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

	September 30, 2007			December 31, 2006
ASSETS
Current assets:
Cash and cash equivalents	$	21,221		$	23,667
Short-term investments in marketable securities		19,407			45,490
Production receivable		336			—
Other current assets		332			638
Total current assets		41,296			69,795
Salvage fund		1,098			1,060
Oil and gas properties:
Advances to operators for working interests and expenditures		1,438			—
Unproved properties		5,382			—
Proved properties		18,877			10,679
Less: accumulated depletion and amortization		(211	)		—
Total oil and gas properties		25,486			10,679
Total assets	$	67,880		$	81,534
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Due to operators	$	4,292		$	14,020
Accrued expenses payable		71			94
Due to affiliates (Note 5)		70			—
Total current liabilities		4,433			14,114
Asset retirement obligations		162			97
Total liabilities		4,595			14,211
Commitments and contingencies (Note 7)
Members’ capital:
Manager:
Accumulated deficit		(1,626	)		(1,340	)
Manager’s total		(1,626	)		(1,340	)
Shareholders:
Capital contributions (1,335 shares authorized; 933.0600 shares issued and outstanding)		138,344			138,344
Syndication costs		(15,898	)		(15,898	)
Accumulated deficit		(57,535	)		(53,783	)
Shareholders’ total		64,911			68,663
Total members’ capital		63,285			67,323
Total liabilities and members’ capital	$	67,880		$	81,534

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

3

RIDGEWOOD ENERGY P FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS AND OTHER COMPREHENSIVE LOSS
(in thousands, except share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Revenue
Oil and gas revenue	$	336		$	—		$	336		$	—
Expenses
Depletion and amortization		211			—			211			—
Dry-hole costs		30			916			3,755			29,952
Management fees to affiliate (Note 5)		537			865			1,615			2,594
Lease operating expenses		9			—			9			—
Other operating expenses		46			—			165			—
General and administrative expenses		188			108			532			331
Total expenses		1,021			1,889			6,287			32,877
Loss from operations		(685	)		(1,889	)		(5,951	)		(32,877	)
Other income
Interest income		529			1,063			1,913			3,040
Realized gain (loss) on short-term investments		—			2			—			(16	)
Net loss		(156	)		(824	)		(4,038	)		(29,853	)
Other comprehensive loss
Unrealized loss on marketable securities		—			—			—			(51	)
Total comprehensive loss	$	(156	)	$	(824	)	$	(4,038	)	$	(29,904	)
Manager Interest
Net loss	$	(55	)	$	(137	)	$	(286	)	$	(689	)
Shareholder Interest
Net loss	$	(101	)	$	(687	)	$	(3,752	)	$	(29,164	)
Net loss per share	$	(108	)	$	(736	)	$	(4,021	)	$	(31,257	)

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

4

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

	Nine months ended September 30,
	2007			2006
Cash flows from operating activities
Net loss	$	(4,038	)	$	(29,853	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depletion and amortization		211			—
Dry-hole costs		3,755			29,953
Interest earned on marketable securities		(970	)		(2,197	)
Accretion expense		5			—
Changes in assets and liabilities:
Increase in production receivable		(336	)		—
Decrease (increase) in other current assets		306			(42	)
(Decrease) increase in accrued expenses payable		(14	)		6
Increase (decrease) in due to affiliates		70			(27	)
Net cash used in operating activities		(1,011	)		(2,160	)
Cash flows from investing activities
Advances to operators		(1,438	)		—
Capital expenditures for oil and gas properties		(27,012	)		(8,225	)
Salvage fund investments		(38	)		(33	)
Proceeds from the sale of marketable securities		50,553			89,070
Investment in marketable securities		(23,500	)		(48,087	)
Loss on the sale of marketable securities		—			18
Net cash (used in) provided by investing activities		(1,435	)		32,743
Cash flows from financing activities
Syndication costs paid		—			(2	)
Net cash used in financing activities		—			(2	)
Net (decrease) increase in cash and cash equivalents		(2,446	)		30,581
Cash and cash equivalents, beginning of period		23,667			5,532
Cash and cash equivalents, end of period	$	21,221		$	36,113
Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to dry-hole costs and proved properties	$	—		$	27,817

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

5

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

1. Organization and Purpose

The Ridgewood Energy P Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on March 21, 2005 and operates pursuant to a limited liability company agreement (“LLC Agreement”) dated as of May 16, 2005 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund. Although the date of formation is March 21, 2005, the Fund did not begin operations until May 16, 2005 when it began its private offering of shares.

The Fund was organized to acquire, drill, construct and develop oil and 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. As of September 2007, the Fund began earning revenue from its operations and has ceased to be in the exploratory stage. In prior periods, the Fund had been classified as an exploratory stage enterprise.

The Manager performs (or arranges for the performance of) the management, administrative and advisory 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 year ended December 31, 2006 included in the Fund’s Annual Report on 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.

Cash and Cash Equivalents

All highly liquid investments with maturities when purchased of three months or less are considered cash and cash equivalents. At times, bank deposits may be in excess of federally insured limits. At September 30, 2007 and December 31, 2006, bank balances, inclusive of salvage fund, exceeded federally insured limits by $15.0 million and $23.5 million, respectively. The Fund maintains bank deposits with accredited financial institutions.

6

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 that 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 fair value. Interest income is accrued as earned. At September 30, 2007, the fund had held-to-maturity investments totaling $20.5 million, inclusive of salvage fund, that mature in the first quarter 2008.

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.

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.

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 are depleted by the unit-of-production method.

As of September 30, 2007 and December 31, 2006, $4.3 million and $14.0 million, respectively, were recorded in due to operators related to the acquisition of oil and gas property. The balance at December 31, 2006 was paid during the first quarter of 2007.

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.

7

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 properties are expensed as dry-hole costs. The following table presents changes to the asset retirement obligations.

	For the nine months ended September 30, 2007			For the year ended December 31, 2006
	(in thousands)
Balance - Beginning of period	$	97		$	—
Liabilities incurred		484			767
Liabilities settled		(424	)		(670	)
Accretion expense		5			—
Balance - End of period	$	162		$	97

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.

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). At the time of transfer a production receivable is recorded.

The volume of oil and natural gas sold on the Fund’s behalf may differ from the volume of oil and natural gas to which 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, and a payable to other working interest owners for volumes oversold by the Fund. At September 30, 2007 and December 31, 2006, there were no material oil or natural gas balancing arrangements between the Fund and other working interest owners.

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 and nine months ended September 30, 2007 and 2006, no impairments have been 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. The Fund began production during the third quarter 2007 and has recorded depletion of $0.2 million for the three and nine months ended September 30, 2007.

Income Taxes

No provision is made for income taxes in the financial statements. The Fund is a limited liability corporation, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders.

8

Income and Expense Allocation

Profits and losses are allocated 85% to shareholders in proportion to their relative capital contributions and 15% to the Manager, except for interest income and certain expenses such as dry-hole costs, fiduciary fees, depletion and amortization, 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 accessing the reserves. Capitalized 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 for the periods ended September 30, 2007 and December 31, 2006. At September 30, 2007, the Fund had no capitalized exploratory well costs greater than one year.

	For the nine months ended September 30, 2007		For the year ended December 31, 2006
	(in thousands)
Balance - Beginning of the period	$	—	$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		5,382		10,582
Reclassifications to proved properties based on the determination of proved reserves		—		(10,582	)
Capitalized exploratory well costs charged to dry-hole costs		—		—
Balance - End of the period	$	5,382	$	—

Dry-hole costs are detailed in the table below.

	For the three months ended September 30,					For the nine months ended September 30,
Lease Block	2007			2006		2007			2006
	(in thousands)
Green Canyon 246	$	(3	)	$	—	$	1,831		$	—
South Timbalier 135/136		(4	)		—		1,684			—
West Cameron 109		(16	)		—		230			—
South Marsh 231		4			30		(80	)		8,454
West Cameron 265		49			886		90			21,498
	$	30		$	916	$	3,755		$	29,952

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 Agreement, is to be distributed. Such distributions will be allocated 85% to the shareholders and 15% to the Manager, as defined in the Fund’s Agreement.

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

There have been no distributions made by the Fund.

9

5. Related Parties

The LLC Agreement provides that the Manager render management, administrative and advisory services. For such services, the Manager originally received an annual management fee, payable monthly, of 2.5% of total capital contributions. Effective January 1, 2007, the Manager 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. Management fees for the three months ended September 30, 2007 and 2006 were $0.5 million and $0.9 million, respectively. For the nine months ended September 30, 2007 and 2006, management fees were $1.6 million and $2.6 million, respectively.

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 September 30, 2007, the Fund owed the Manager $70 thousand, which is included in due to affiliates. At December 31, 2006, there were no such amounts outstanding.

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

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

6. Fair Value of Financial Instruments

As of September 30, 2007 and December 31, 2006, the carrying value of cash and cash equivalents, short-term investments in marketable securities and salvage fund approximates fair value.

7. Commitments 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 September 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, 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. The forward-looking statements in this Quarterly Report on Form 10-Q reflect Ridgewood Energy P Fund, LLC’s (the “Fund”) 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 its 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 policies. No changes have been made to the Fund’s critical accounting policies and estimates since the filing of the 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.

Ridgewood Energy Corporation (the “Manager”) performs certain duties on the Fund’s behalf including the evaluation of potential projects for investment and ongoing management, administrative and advisory services associated with these projects. For these services, the Manager receives an annual management fee (2.5% of capital contributions, net of cumulative dry-hole costs), payable monthly. 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 (“Operators”) for the management of all exploration, development and producing operations, as appropriate. The Manager also participates in distributions.

Business Update

The Fund owns working interests and has participated in the drilling of ten wells, five of which were determined to be dry-holes, three that have resulted in discoveries and two that are currently drilling.

11

Currently Drilling

Walker Ridge 155

In the third quarter 2007, the Fund paid $0.7 million as consideration for a 1% allocation of the Manager’s interest in the Walker Ridge 155 project. Anadarko Petroleum Corporation (“Anadarko”) is the operator of the project. Drilling for Walker Ridge 155, a deep-water project, began in mid-August 2007 and is expected to be completed late in the fourth quarter of 2007. Through September 30, 2007, the Fund has spent $0.7 million related to this property, for which the total estimated budget is $14.4 million.

Mississippi Canyon 489/490

In the third quarter 2007, the Fund acquired an 8.3% working interest in the exploratory project Mississippi Canyon 489/490 from LLOG Exploration Offshore, Inc. (“LLOG”). LLOG is the operator of the project. Drilling began in September 2007. Through September 30, 2007, the Fund has spent $2.3 million related to this property, for which the total estimated budget is $7.0 million.

Successful Wells

West Cameron 593

In July 2006, the Fund acquired a 43.28% working interest in the exploratory project West Cameron 593 from Newfield Exploration Company (“Newfield”), the operator. On August 15, 2006, the Fund started drilling West Cameron 593, a 12,849 foot single well project in approximately 257 feet of water offshore Louisiana. West Cameron 593 was deemed successful in mid-September 2006. In August 2007, Newfield sold its interest in this property to McMoRan Exploration Co. (“McMoRan”). At that time, McMoRan assumed Newfield’s responsibilities as the operator of this property. In September 2007, the well was completed and production began. The total cost of this property was $14.1 million.

Eugene Island 346/347

In March 2007, the Fund acquired a 10% working interest in the exploratory project Eugene Island 346/347 from Newfield, the operator. In June 2007, the well was deemed successful In August 2007, Newfield sold its interest in this property to McMoRan. At that time, McMoRan assumed Newfield’s responsibilities as the operator of this property. Completion is ongoing and production is expected in the second quarter 2008. Through September 30, 2007, the Fund has spent $3.8 million related to this property, for which the total estimated budget is $6.5 million.

Eugene Island 354

In May 2007, the Fund acquired a 33% working interest in the exploratory project Eugene Island 354 from the operator, Devon Energy Production Company, L.P. (“Devon”). In June 2007, the well was deemed successful and classified as a proved property at June 30, 2007. Completion efforts have concluded and production is scheduled to begin during the fourth quarter 2007. Through September 30, 2007, the Fund has spent $4.6 million related to this property, for which the total estimated budget is $4.8 million.

Dry Hole Wells

South Timbalier 135/136

On January 24, 2007, the Fund was informed by its operator, Chevron U.S.A., Inc. (“Chevron”), that the exploratory well being drilled by Chevron in the South Timbalier 135/136 lease block did not have commercially productive quantities of either oil or natural gas and has therefore been deemed an unsuccessful well or dry hole. The Fund owns a 10% working interest in South Timbalier 135/136. Through September 30, 2007, dry-hole costs related to South Timbalier 135/136, including plug and abandonment expenses, incurred by the Fund totaled $6.9 million.

Green Canyon 246

In July 2006, the Fund acquired a 5% working interest in the exploratory project Green Canyon 246 from Marathon Oil Company (“Marathon”), the operator from acquisition date until December 28, 2006. In December 2006, oil was discovered in one reservoir of the well, however, a side-track operation would have to be performed to determine the commercial viability of the well. Marathon elected not to participate in the side-track and forfeited its 40% interest. Woodside Energy (USA) Inc. (“Woodside”) and the Fund elected to proceed, taking over, on a pro-rated basis, Marathon’s 40% interest. The Fund increased its ownership to 8.3%, and Woodside took over the project as operator. Upon completion of the side-track, on January 24, 2007, the Fund was informed that the exploratory well being drilled did not have commercially productive quantities of either oil or natural gas and had therefore been deemed an unsuccessful well or dry hole. Through September 30, 2007, dry-hole costs related to Green Canyon 246, including plug and abandonment expenses, incurred by the Fund totaled $6.7 million.

12

Results of Operations

The following review of operations for the three and nine months ended September 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.

	Three months endedSeptember 30,						Nine months ended September 30,
	2007			2006			2007			2006
		(in thousands)
Revenue
Oil and gas revenue	$	336		$	—		$	336		$	—
Expenses
Depletion and amortization		211			—			211			—
Dry-hole costs		30			916			3,755			29,952
Management fees to affiliate		537			865			1,615			2,594
Lease operating expense		9			—			9			—
Other operating expenses		46			—			165			—
General and administrative expenses		188			108			532			331
Total expenses		1,021			1,889			6,287			32,877
Loss from operations		(685	)		(1,889	)		(5,951	)		(32,877	)
Other income
Interest income		529			1,063			1,913			3,040
Realized gain (loss) on short-term investments		—			2			—			(16	)
Net loss		(156	)		(824	)		(4,038	)		(29,853	)
Other comprehensive loss
Unrealized loss on marketable securities		—			—			—			(51	)
Total comprehensive loss	$	(156	)	$	(824	)	$	(4,038	)	$	(29,904	)

Oil and Gas Revenue. The Fund’s first successful well, West Cameron 593, began production in September 2007. Prior to this time, the Fund had no revenues and was classified as an exploratory stage enterprise. The Fund is no longer an exploratory stage enterprise. Production for two additional wells, Eugene Island 354 and Eugene Island 346/347 is scheduled to begin in fourth quarter 2007 and second quarter 2008, respectively, upon successful completion efforts.

During the three and nine months ended September 30, 2007, revenues were $0.3 million. Oil prices averaged approximately $79 per barrel and gas prices averaged approximately $5.95 per mcf. West Cameron 593 produced and sold approximately 2,200 barrels of oil and 28 thousand mcf of gas.

Operating and Other Expenses

Depletion and Amortization. For the three and nine months ended September 30, 2007, depletion and amortization was $0.2 million. The Fund’s first producing well, West Cameron 593, was placed in service in September 2007. Prior to that time, the Fund did not have production and therefore did not have depletion or amortization expense.

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. During the three months ended September 30, 2007, certain wells received credits from their respective operators upon review and audit of the wells’ costs.

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	For the three months ended September 30,					For the nine months ended September 30,
Lease Block	2007			2006		2007			2006
	(in thousands)
Green Canyon 246	$	(3	)	$	—	$	1,831		$	—
South Timbalier 135/136		(4	)		—		1,684			—
West Cameron 109		(16	)		—		230			—
South Marsh 231		4			30		(80	)		8,454
West Cameron 265		49			886		90			21,498
	$	30		$	916	$	3,755		$	29,952

Management Fees. The Manager receives an annual management fee of 2.5% of total capital contributions, 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 was reduced by 2.5% of the cumulative dry-hole expenses incurred by the Fund, resulting in a decrease of $0.3 million and $1.0 million, for the three and nine month periods ended September 30, 2007, respectively. Management fees for the three months ended September 30, 2007 and 2006 were $0.5 million and $0.9 million, respectively. Management fees for the nine months ended September 30, 2007 and 2006 were $1.6 million and $2.6 million, respectively.

Lease Operating Expense. For the three and nine months ended September 30, 2007, lease operating expense was $9 thousand related to the onset of production for the Fund’s first producing well, West Cameron 593, which was placed in service in September 2007. Prior to that time, the Fund did not have production and therefore did not have lease operating expense.

Other Operating Expense. Other operating expenses for the three and nine months ended September 30, 2007 were $46 thousand and $165 thousand, respectively. For the three months ended September 30, 2007, geological costs totaling $44 thousand were incurred related to Mississippi Canyon 490 and Eugene Island 346/347. For the nine months ended September 30, 2007, geological costs of $115 thousand, $35 thousand, and $10 thousand were incurred related to Eugene Island 354, Mississippi Canyon 490, and Eugene Island 346/347, respectively. Accretion expense for the three and nine months ended September 30, 2007 was $2 thousand and $5 thousand, respectively, for the Fund’s proven properties, West Cameron 593 and Eugene Island 354. There were no other operating expenses for the three and nine month periods ended September 30, 2006.

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, which increased due to the onset of production for West Cameron 593 as well as the increase in drilling activities.

The following table summarizes general and administrative expenses.

	For the three months ended September 30,				For the nine months ended September 30,
	2007		2006		2007		2006
	(in thousands)
Accounting and legal fees	$	62	$	40	$	159	$	136
Insurance		109		18		307		57
Trust fees		17		50		65		137
Other		—		—		1		1
	$	188	$	108	$	532	$	331

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Interest Income. Interest income represents interest earned on money market accounts and short-term US Treasury Notes. For the three months ended September 30, 2007, interest income was $0.5 million, a $0.5 million decrease from the three months ended September 30, 2006. For the nine months ended September 30, 2007, interest income was $1.9 million, a $1.1 million decrease from the nine months ended September 30, 2006. Decreases in average outstanding balances earning interest due to property expenditures during the three and nine months ended September 30, 2007 were partially offset by an increase in average interest rates.

Other Comprehensive Loss. Other comprehensive loss is comprised solely of the unrealized losses on short-term investments and represents unrealized losses on available-for-sale marketable debt securities. For the nine months ended September 30, 2006, the unrealized loss totaled $51 thousand. During 2006, the US Treasury Note reached its maturity and the unrealized loss was recorded to offset the previously recorded unrealized gain.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows used in operating activities for the nine months ended September 30, 2007 were $1.0 million. Management fees and general and administrative and other expenses totaling $2.3 million and unfavorable working capital of $0.3 million were partially offset by interest income received of $1.5 million.

Cash flows used in operating activities for the nine months ended September 30, 2006 were $2.2 million, primarily related to management fees and general and administrative expenses totaling $2.9 million, partially offset by interest income received of $0.8 million.

Investing Cash Flows

Cash flows used in investing activities for the nine months ended September 30, 2007 were $1.4 million, related to investments in capital expenditures for oil and gas properties of $27.0 million, advances to operators of $1.4 million and the purchase of US Treasury Notes of $23.5 million, partially offset by proceeds from the maturity of US Treasury Notes of $50.6 million.

Cash flows provided by investing activities for the nine months ended September 30, 2006 were $32.7 million, related to proceeds from the maturity of US Treasury Notes of $89.1 million, partially offset by the purchase of US Treasury Notes of $48.1 million and $8.2 million for capital expenditures for oil and gas properties.

Financing Cash Flows

There were no cash flows related to financing activities for the nine months ended September 30, 2007.

Cash flows used in financing activities for the nine months ended September 30, 2006 were $2 thousand related to the payment of syndication costs.

Estimated Capital Expenditures

The Fund has entered into several participation and 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 September 30, 2007, such estimated capital expenditures totaled $21.2 million, all of which is expected to be paid out of unspent cash.

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

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Lease Block	Spent through September 30, 2007		To be spent less than 1 year		To be spent 1-2 years		Total to be spent
	(in thousands)
Eugene Island 354	$	4,641	$	119	$	—	$	119
Eugene Island 346/347		3,805		2,675		—		2,675
Mississippi Canyon 489/490		2,294		4,736		—		4,736
Walker Ridge 155		721		4,179		9,450		13,629
West Cameron 593		14,079		—		—		—
	$	25,540	$	11,709	$	9,450	$	21,159

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, had originally been equal to 2.5% of total capital contributed by shareholders. Effective January 1, 2007, the Manager has 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.

On a long-term basis, until one of the Fund’s projects begins producing, all or a portion of the management fee is paid generally from the interest or dividend income generated by the Fund’s development capital that has not been spent, although the management fee can be paid out of capital contributions. Such interest and/or dividend income is more than enough to cover Fund expenses, including the management fee. Generally, it can take anywhere from 18 to 24 months to bring a project to production, however deeper well projects, such as Walker Ridge 155, can take longer. Once a well is on production, the management fee and Fund expenses are paid from operating income. Over time as a well produces the Fund may recover some or the entire management fee that may have been paid out of capital contributions.

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 September 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, as well as the other working interest owners, the Operator will enter into various contractual commitments pertaining to exploration, development and production activities. Pursuant to the terms of the operating agreement, the Operator has the authority to enter into such contracts and the Fund does not execute or negotiate any such contracts. No contractual obligations exist at September 30, 2007 and December 31, 2006 pursuant to agreements executed directly by the Fund.

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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.

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, banker’s 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 September 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.

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Changes in Internal Controls over Financial Reporting

In the course of the Fund’s initial evaluation of disclosure controls and procedures, management considered certain internal control areas in which the Fund has made and are continuing to make changes to improve and enhance controls. Based upon that evaluation, the CEO and CFO concluded that 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 September 30, 2007 that have materially affected, or are reasonably likely to materially affect, the Fund’s internal control over financial reporting.

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.

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ITEM 6. EXHIBITS

EXHIBIT NUMBER	TITLE OF EXHIBIT
10.1	Participation Agreement between Chevron U.S.A., Inc. and Ridgewood Energy Corporation as Manager for South Timbalier 135/136. (previously filed)
10.2	Participation Agreement between Newfield Exploration Company and Ridgewood Energy Corporation as Manager for West Cameron 593. (previously filed)
10.3	Participation Agreement between Newfield Exploration Company and Ridgewood Energy Corporation as Manager for Eugene Island 346/347. (previously filed)
10.4	Participation Agreement between Devon Energy Production Company L.P. and Ridgewood Energy Corporation as Manager for Eugene Island Block 337. (previously filed)
10.5	Participation Agreement between Devon Energy Production Company L.P. and Ridgewood Energy Corporation as Manager for Eugene Island Block 354. (previously filed)
10.6	Participation Agreement between LLOG Exploration Offshore, Inc. and Ridgewood Energy Corporation as Manager for Mississippi Canyon 489/490
10.7	Participation Agreement between Kerr-McGee Oil & Gas Corporation and Ridgewood Energy Corporation as Manager for Walker Ridge 155
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.

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:	November 2, 2007			RIDGEWOOD ENERGY P FUND, LLC
		By:	/s/	ROBERT E. SWANSON
			Name:	Robert E. Swanson
			Title:	President and Chief Executive Officer
				(Principal Executive Officer)
Dated:	November 2, 2007
		By:	/s/	KATHLEEN P. MCSHERRY
			Name:	Kathleen P. McSherry
			Title:	Executive Vice President and Chief Financial Officer
				(Principal Financial and Accounting Officer)

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